We have been asked repeatedly how Battery Energy Storage Systems (BESS) (“storage”) will operate in Ontario’s wholesale energy market in the coming years, which led us to ask: what goes into a storage offer anyway? The answer, as it turns out, is complicated. With the independent Electricity System Operator (IESO) in the midst of procuring up to 2,500 MW of energy storage by 2027, understanding how BESS assets may offer into the wholesale energy market will inform many aspects of the Ontario electricity sector including the future cost of capacity payments to these assets; future capacity prices in the IESO’s Capacity Auction; IESO-Administered Market (IAM) design issues; and the potential direction of energy prices going forward.
Energy Storage in Today’s Market
Ontario’s market currently has a limited amount of transmission-connected energy storage – with the pumped hydro storage facility at the Beck Generating station being both the largest single asset.1 Output from the Beck pumped storage facility is rate-regulated and includes an additional incentive structure to incent the asset to charge and discharge during low and high value hours, respectively. The incentive structure is intended to price signals incent the asset to operate in an economically efficient manner, while avoiding contract-related must-offer conditions or an offer window.
In today’s market, energy storage is not scheduled or dispatched holistically in the IESO’s dispatch and scheduling software. Rather, storage is modelled distinctly as both a dispatchable load and dispatchable generator – meaning the market participant must manage the physical operation of the facility through separate energy bids (to charge) and offers (to discharge). The current dispatch software also does not include a State-of-Charge (SOC) calculation. With the Beck pumped storage facility – with a capacity of 175 MW out of around 200 MW of total installed transmission-connected energy storage capacity – accounting for a majority of storage in the current market, the risk of uneconomic or impractical scheduling and dispatch of energy storage is limited largely to one facility. The Beck pumped storage facility is also operates as part of a much broader generating complex (Beck) with around 2,000 MW of installed capacity.
The IESO does not currently have an ex-ante (“before the event”) market power mitigation framework. Instead, the IESO largely relies on ex-post (“after the event”) mitigation of Congestion Management Settlement Credits (CMSCs). CMSCs are out-of-market payments made to market participants to ensure they follow dispatch and are made financially whole.
Breaking Down the Marginal Cost of Storage and Energy Offers
Market participants are expected to offer into the market at their marginal cost – that is, the cost of producing an incremental unit of energy. For resources like solar and wind, the marginal cost is typically $0/MWh, as there is no incremental cost to producing another unit of energy (more sun and wind do not cost anything to use). For gas-fired generators, the marginal cost is the cost of purchasing gas and other variable costs. Hydro generators in Ontario largely calculate their marginal cost based on water rental fees and a Gross Revenue Charge (GRC) paid to the government – essentially taxes paid to the government based on water used to generate power. Nuclear and baseload hydro are considered to have negative marginal costs – i.e. it costs these assets money to shut down and will typically operate at any cost.
The marginal cost of storage is less straight forward and can be a combination of the cost of charging, fixed transmission and distribution costs, augmentation costs (i.e., the cost of replacing storage modules), and other operating costs. Opportunity costs – the cost of generating now rather than later when prices may be higher – can also be included in marginal costs. For simplicity, this analysis focuses only on the cost of charging and fixed transmission and distribution costs when calculating storage’s marginal cost.
Importantly, many distribution and transmission costs are either completely fixed – the monthly charge for example – or are based on the non-coincident peak load of the facility. Because the costs are largely fixed and do not change if a storage facility charges once or 30 times in a month, the usage of the asset will have a material impact on marginal costs. A higher utilization will spread monthly fixed operating costs over a greater number of units and result in lower marginal costs from an energy offer point of view.
In the following chart, marginal costs were based on a Hydro One customer operating a 100MW/400MWh storage asset. In this example, the charging costs average $15/MWh – a proxy for the marginal cost of hydro – for the entire month. All of the other costs related to transmission and distribution are based on Hydro One’s most recent rate order and applied equally to all output. The marginal cost changes significantly based on the operating profile. If the asset were to charge/discharge just one time in the month, its marginal cost would be more than $600/MWh. If it undertakes 20 cycles in the month, its marginal cost falls to around $48/MWh. Note that these are just marginal costs – i.e. these offers only recover the charge (including round trip efficiency) and other related costs and do not provide any operating profit to the storage asset.
Adding the Recovery of Capital Costs in Storage Energy Offers
If a storage owner only offers and is paid for its marginal costs, it will never recover any of the so-called “missing money” required to pay for the fixed operating and capital costs required to build and maintain the asset. While the missing money problem is often at least partially solved by the dispatch of higher marginal cost resources – which then set a market price higher than the marginal cost for most assets – storage resources, as shown above and described in more detail later in this paper, are likely to be some of the higher marginal cost resources. This means that they may often set the market clearing price and not recover the missing money required to build and maintain an asset without pushing their offer price higher (beyond marginal cost).
What if storage assets were allowed by the Market Rules to offer energy at their fixed costs? The following chart shows the magnitude of increase in energy offers required to recover fixed costs. Again, the asset is a 100MW/400MWh storage facility, with a capacity cost of $1,258/MW-day.2 A storage asset that charges/discharges 20 times a month – or nearly every business day – the fixed cost offer would need to be $328/MWh. When combined with a marginal cost offer, the total energy offer would be $376/MWh – or nearly eight times the average HOEP in 2022. Storage assets that are operated more infrequently will require much higher energy offers – in some cases, higher than the ceiling price in Ontario’s wholesale energy market.
Market Power Mitigation and Storage in the Market Renewal Program (MRP)
The IESO is currently undertaking the most significant overhaul of the wholesale market design since it was introduced in 2003. One notable feature of MRP is the introduction of a new Market Power Mitigation (MPM) framework. In particular, MPM will introduce an ex-ante mitigation of energy offers and bids, among other changes. As part of the MPM, offers from market participants can be mitigated back to pre-determined reference levels based on marginal costs for different resources.
Reference levels for storage resources may include an opportunity cost component. The current MPM design includes different opportunity cost calculations for storage and hydroelectric resources. For storage resources, in particular, the opportunity cost reference level will be no higher than highest Day-Ahead Market (DAM) price. Hydroelectric resources are offered a broader opportunity cost time horizon.
What this means is that when a storage asset is deemed to be in a “constrained” zone – with the IESO proposing various levels of constraints, each with a different threshold for mitigation – its energy offers can be mitigated back to its reference level. If, for example, offers from storage are the price-setting offer and it is located within a constrained zone, those offers could be mitigated back to the next highest price on that day. Recognizing this is a very simplified presentation of MPM, it highlights the risk that price-setting units like storage face when submitting energy offers in the post-MRP wholesale market, as they may often face the risk of mitigated energy offers compared to other resource types.
Storage’s Place in Ontario’s Supply Stack
Ontario has a unique supply stack when compared to other wholesale markets. Ontario has a very large amount of baseload nuclear and hydro, along with a significant level of installed wind capacity. Over the past decade, thermal units – almost exclusively gas-fired generators – have operated as peaking and reserve assets, operating during both during high demand hours and often providing Operating Reserve (OR). As a result of this supply mix, the supply stack – or economic merit order – often sets price at a lower level than more thermal-dominated wholesale markets across the United States and Alberta. When gas-fired units are price-setting in Ontario, a majority of the gas-fired generators have similar efficiency and will set prices before inefficient or oil-fired generation is dispatched.
This is important for storage, as Ontario’s supply stack under the current policy environment will continue to prevent wholesale energy prices from coming anywhere close to the fixed cost energy offers described in the previous section. Even on a marginal cost basis, energy storage may not be commonly dispatched. The following chart compares the marginal cost of energy storage described previously with the marginal cost of different resources in Ontario. Importantly, with the $170/tonne carbon price and the current Emissions Performance Standard (EPS) of 0.310 tonnes of emissions per MWh, the marginal cost of energy storage is in many cases higher than even the highest marginal cost gas-fired generators when gas prices are $3.50/MMBtu. If storage is operated less frequently – 5 charge/discharge cycles per month, for example – than it is likely one of the highest marginal cost resources in Ontario, even with the full impact of a $170/tonne carbon price (i.e. the EPS goes to 0).
The impact of the chart above should be carefully considered. Under this scenario, storage in Ontario will make a limited amount of profit in the wholesale energy market. When it is dispatched, it will either be the price-setting unit or the difference between its marginal cost and the Market Clearing Price (MCP) will likely be limited if storage offers energy at its marginal cost (i.e. it will earn very little profit when dispatched). An increase in charging costs – higher than the $15/MWh assumed in this example – will make it even more difficult for storage to be economically dispatched on a marginal cost basis. Given Ontario is headed to a much tighter supply/demand balance in 2026 with the retirement of the Pickering Nuclear Generating Station (PNGS), the number of hours where hydro and other non-emitting generators are on the margin are likely to decrease materially from recent years – which is expected to push the number of hours where HOEP is greater than $15/MWh up significantly.
In this environment, storage earns very little operating profit that can be used to pay down its fixed operating and capital costs – meaning there is little opportunity to recover the so-called missing money from the wholesale energy market. As a result, storage will likely require higher capacity payments through long-term contracts or the Capacity Auction to be financially viable in Ontario.
What Does It All Mean?
First, on a pure marginal cost basis – which is how storage is expected, according to the Market Rules, to offer into both the current and future Ontario market – storage will likely be one of the highest marginal cost resources. As such, it will be dispatched minimally. If storage is used solely for peaking purposes, it will be dispatched even less and will be one of the highest marginal cost resources even if full carbon pricing is applied to offers from gas-fired generators.
Second, the opportunity for storage to recover anything beyond marginal costs from the energy market will be limited. Given the high fixed cost nature of storage assets, energy market revenues will play a marginal role in financing storage. While this analysis considered energy market revenues only, additional revenue will be earned through the ancillary services market – predominantly Operating Reserve (OR). While storage can provide OR through many hours of the day, there will be a limited market for OR if the IESO procures 2,500 MW of storage capacity by 2027 – as the hourly OR amounts procured are typically half that amount.
Third, the lack of earning significant wholesale market revenues will require high capacity payments, either through the IESO’s Capacity Auction or through fixed long-term contracts. Most future storage projects are now participating in the IESO’s various long-term procurements – a trend that is expected to continue. The IESO is currently increasing the reference price in the Capacity Auction to $644/MW-day and proposing a maximum clearing price of $966/MW-day. Both of these amounts are well below the cost of a storage asset, which is estimated to be between $1,200 to $1,800/MW-day (or higher). If storage were to participate more directly in the Capacity Auction, clearing prices would have to be allowed to move even higher than current thresholds. Given the lack of energy market revenues to recover fixed costs and the IESO’s need for new capacity from storage resources, these assets will need long-term contracts to be financially viable. While participants in the recent IESO procurements can reduce their capacity payment based on expected energy market revenues, the high marginal cost of storage compared to other resources will significantly limit this potential. As such, the contract structure for storage resources will include limited potential for energy market revenues.
Fourth, the proposed Market Power Mitigation (MPM) framework may severely limit the ability of storage to recover fixed costs through the energy market, which will impact all resources and cost allocation through the Class A/Class B mechanism currently in place. While higher wholesale energy prices will mitigate the need for high Global Adjustment (GA) charges, the MPM framework will explicitly mitigate resources to the marginal cost, resulting in lower wholesale prices and higher GA charges.
And finally, the IESO is introducing a number of significant changes through the redesign of the wholesale market as part of the MRP. Notably, this will include the introduction of a Day-Ahead Market (DAM) and a pre-dispatch Look-Ahead Period (LAP) of 27 hours. No other wholesale market includes anything close to a 27-hour LAP. Given the many uncertainties that will occur over 27 hours – ranging from forecast errors related to demand and variable supply – storage resources may face continuously changing pre-dispatch schedules. With storage being modelled separately as a load and generator, constantly changing schedules is likely to result in an increase in sub-optimal or uneconomic dispatch. As close to 2,000 MW of energy storage comes online, ensuring that they are optimally dispatched will become increasingly difficult.
1 There is an unknown quantity of behind-the-meter energy storage capacity. Neither the IESO, Local Distribution Companies or the Ontario Energy Board (OEB, the regulator) attempt to track the total installed capacity.
2 This is one simplified estimate and is included as an indicative cost with the caveat that the range of storage costs can quite large.