Since our update one year ago, energy storage continues to develop in both Alberta and Ontario while being further incentivized by recent draft federal legislation regarding clean energy income tax credits and a clean (net-zero) electricity future. Energy storage appears to be here to stay and has widely been accepted as one of the solutions for Canada’s energy transition; however, the conversation has shifted from its need to conversations around the (a) issues regarding how the technology can/should be adopted and its role in the “mix” of grid resources and (b) project and financing structures that may be necessary to fully utilize the benefit of the incoming legislation.
There have been a number of important federal developments impacting energy storage, since our Fall 2022 update titled Energy storage in Canada: energizing the transition1.
On August 4, 2023, the federal government released draft legislation regarding the Clean Technology Investment Tax Credit (ITC)2, which provides up to a 30% refundable investment tax credit for the capital cost of “clean technology property”, which includes electricity storage equipment systems that do not use fossil fuels in their operations. This definition captures batteries, flywheels, supercapacitors, magnetic energy storage, compressed air storage, pumped hydro storage, gravity energy storage and thermal energy storage.
Six days later, on August 10, 2023, the federal government released draft clean electricity regulations (Clean Electricity Regulations), structured to promote Canada’s drive toward a net-zero electricity grid by 2035, with the aim of helping Canada achieve its overall net-zero emissions target by 20503.
Federal incentives and regulations will place pressure on the electricity grid to decarbonize, which will increase the need for energy storage.
The draft legislation provides some clarity but also raises several questions and potential issues4. While the ITC will undoubtedly incentivize energy storage (along with other non-emitting) development in Canada, its effect on developers (and therefore lenders) has the potential to be somewhat diluted by the other constituencies that may request their share of the “pie”. For instance, we have seen proposed adjustments to power purchase agreement pricing (both public and private) if a counterparty receives an ITC and expect that similar asks from engineering, procurement and construction contractors and original equipment manufacturers could follow, especially since such contracts are also being adjusted to account for labour and related objectives embedded in the ITC.
Nevertheless, the ITC will impact the economics and financing of energy storage projects, and the Clean Electricity Regulations will place further pressure on the electricity grid to decarbonize, which, in our view, will increase the need for energy storage to assist with this transition, help maximize existing grid resources and grid flexibility, and provide some of the benefits we outlined in our update a year ago.
Alberta makes progress on projects
The slow trickle of storage projects has continued in Alberta, with four 20-megawatt (MW) transmission-connected battery projects going online in the past year. This brings the total to seven in the province, six of which (or a total of 210 MWh of storage capacity) are owned and operated by Enfinite, a Calgary-based company, who plans to energize a further three 20 MW projects, to bring its total storage capacity to 315 MWh.
There are also 19 transmission-connected storage projects in the Alberta Electric System Operator’s (AESO) active connection queue, two of which are under construction: the Jurassic Solar+ project (80 MW of storage) and TransCanada Energy’s Saddlebrook Solar+ Storage project (6.5 MW of storage).
11 of the 19 projects in the queue are combined generation and storage projects (Solar+ or Wind+) that have not yet received approval from the Alberta Utilities Commission (AUC) for construction and operation. These projects are therefore impacted by the Government of Alberta’s pause on renewable power plant approvals, which is in effect until February 2024.
Regulations for storage projects have also progressed in the past year. The market rules applicable to energy storage, the Energy Storage ISO Rule Amendments, were approved by the Alberta Utilities Commission on June 13, 2023, and will come into effect on April 1, 20245. Among the amendments are necessary clarifications to ensure energy storage can participate and bid into Alberta’s energy and ancillary services markets.
Battery storage proponents are also working with the AESO to make amendments to the ISO tariff, which currently treats energy storage like any other load on the system, failing to recognize that storage is different because, while it is a “load”, it does not consume power like most other end-users. The AESO has acknowledged that this may allow for different rates to be charged when energy storage resources are drawn from the grid. In Spring 2023, the AESO initiated the Energy Storage Tariff Working Group to consider such changes to its tariff and ensure that it is not a barrier to entry. Work is ongoing, with the goal of recommending modifications to the ISO tariff for approval from the AUC in the near future.
Ontario storage capacity update
In the past year, the Ontario Independent Electricity System Operator (IESO) concluded its expedited request for proposal (RFP) process for long-term contracted capacity and announced the procurement of 15 energy storage projects with a total storage capacity of 822 MW and 586 MW of additional natural gas capacity from planned expansions and upgrades to existing facilities.
The storage projects, which range in size from 5 to 300 MW, are scheduled to be in service no later than 2026, and 9 of the 15 projects have Indigenous community participation of at least 50%.
The total 1,325 MW of long-term capacity (storage and natural gas procurements), combined with the 250 MW of storage from the Oneida Energy Storage Project expected to be in service by 2025 (which we discussed in our update last year), the 1,400 MW of summer capacity secured in the IESO’s annual capacity auction, and a new agreement for the Brighton Beach Generating Station to continue operations, have provided the IESO comfort that it will satisfy the province’s electricity needs through to 20286.
The IESO’s long-term RFP launched this fall (bids are due in the second week of December), with the goal of procuring an additional 2,500 MW of storage to be in service toward the end of the decade.
Back to the future
One year ago, we spoke of the merits and uses of energy storage and how it could serve a critical role in Canada’s energy transition, including the decarbonization of the electricity grid. Since then, the ITC and Clean Electricity Regulations have cemented the critical role that energy storage can play. The developments in Alberta and Ontario are also evidence that energy storage is here to stay.
The conversation has now shifted to the adoption of energy storage (including what roles it should play)7 and some of the difficulties that can arise, including the implementation of this new technology on an existing (“old”) grid, transmission constraints, interconnection queue backlog and supply chain issues.
For the expedited RFP, the IESO concluded that natural gas procurements were necessary “as a transitional resource to help maintain reliability as Ontario grows its storage fleet”8. On the same basis, the IESO plans to continue to procure natural gas resources in the long-term RFP. In particular, the IESO noted that, while batteries provide a quick ramp up and down for changes in demand, they only provide energy for about four hours9 before they need to recharge, whereas natural gas generators can run for 12 hours or longer if necessary. Additionally, the IESO noted that natural gas can provide voltage and frequency stabilization services to the transmission grid (although these are services that can, to a certain extent, also be provided by energy storage)10.
This is just one example of the “growing pains” that are to be expected with the implementation of new technology on a grid that has been established for decades and whose roots reach back to the 19th century. It also shows the need for further development of long-term and greater-capacity energy storage to overcome some of the concerns that grids and utilities have, as well as further energy policymaker education in respect of the “Swiss Army knife” nature of energy storage (where the same storage asset can provide many different services—in some cases, effectively contemporaneously).
The conversation has now shifted to energy storage adoption and the difficulties that can arise implementing this new technology on an existing (“old”) grid.
Transmission constraints were also a factor in the IESO’s selection process in the expedited RFP. The IESO uses what it calls a “Deliverability Test” to test transmission capacity for a proposed project, and a number of proposals received a “Deliverable but Competing”11 assessment. Effectively, this meant that such energy storage projects had to beat out all other proposed connections in their transmission area, notwithstanding how good their proposal was in respect of the RFP overall. As a result, many energy storage projects that had compelling economics were ultimately not selected, especially when competing against gas generation resources (for the reasons mentioned above). This is a cruel irony given that energy storage is a technology that can act as transmission deferment or replacement. It presumably does not help that energy storage is both a load (to charge) and a supply (to discharge), and therefore, theoretically12 uses twice the transmission of a typical generator (which only supplies power) or an end-user load (which only draws power).
More troubling, not just for energy storage but all energy transition projects, are the delays resulting from interconnection queues (the AESO Connection queue, now impacted by the Alberta Government’s pause on project approvals, is one example). Similar connectivity issues exist throughout the G-7, most proximately in the United States where there are reportedly 430GW of projects queued up13.
Finally, battery energy storage continues to struggle with supply chain issues related to component rare earth metals, such as lithium (most of the supply comes from Australia, Chile and China), and demand competition from other end-users of lithium-ion batteries, such as EVs.
In short, while the future is bright and exciting for energy storage in the long term, near-term issues arising from the adoption challenges, transmission constraints, interconnection backlogs and supply chain constraints will need to be overcome in order to successfully implement storage into our existing grids and reap the benefits it can provide to help accelerate us through Canada’s energy transition.
For example: (i) the available ITC is reduced on a dollar-for-dollar basis if other government support has been granted to a project—borrowers that have obtained Canada Infrastructure Bank (CIB) financing for more than 30% of their project costs may find that they are ineligible for ITC and (ii) the ITC “recapture” regime and the proposed rules in respect of partnership structures (partners are only eligible to claim ITC up to their “at-risk amount”, which can be relatively small in a highly leveraged project and will require modification of existing transaction and financing structures in order to maintain “finance-ability” of projects and maximization of the ITC.
The long-term RFP also includes a category for 8-hour storage providers.
IESO Resource Adequacy Update, June 27, 2023.
The transmission constraints in Ontario are increasingly reflecting the bottleneck nature of grids everywhere—most proponents in the current long-term RFP received “Deliverable but Competing” assessments, and some proponents who received such an assessment in the expedited long-term RFP were assessed as “Non-Deliverable” less than a year later.
Only theoretically because virtually all energy storage systems will typically charge at off-peak times (to minimize cost), during which the transmission system is significantly under-utilized.
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