Battery Energy Storage Systems.Built Around Your Goals.

A battery energy storage system (BESS) is an integrated assembly of lithium-ion cells, power conversion electronics, thermal management and software that captures electricity when it’s cheap or surplus and delivers it when it’s expensive, scarce or critical, bridging variable renewables, volatile prices and the rising power demands of factories, data centers and grids.

Where BESS delivers the strongest return

Tariff structure, load profile and resilience requirements shape the business case. The industries below consistently produce the strongest BESS returns.

The figures below are reference information, not a project quote. Costs, savings, eligibility and payback depend on your configuration, location and current program rules.

How Ontario Global Adjustment changes BESS economics

Most BESS economics rest on demand charges or energy arbitrage. Ontario adds a third mechanism that is often larger than either, and it rewards a different operating pattern from the one a demand-charge model assumes.

Global Adjustment, Class A and Class B

Ontario commercial electricity has two components: the commodity, and the Global Adjustment, or GA. For large consumers the GA is frequently the bigger line.

How you are billed depends on your class. Class B customers generally pay GA against monthly consumption at the applicable Class B rate, so shifting load within the month does not change the allocation method by itself, although it may affect other energy and demand charges. Class A customers participating in the Industrial Conservation Initiative, or ICI, pay their share of GA according to their peak demand factor, and that factor is based on the facility’s contribution during Ontario’s five highest-demand hours in a 12-month base period.

The five hours that set the peak demand factor

The base period runs May 1 through April 30. The peak demand factor reflects the customer’s loss-adjusted withdrawal during the five highest Ontario demand hours, compared with the applicable system total for those hours, and it is then applied to the following July 1 to June 30 adjustment period. The IESO publishes both its Global Adjustment and Peak Demand Factor methodology and a Peak Tracker.

The consequence is unusual enough to state plainly: for an eligible Class A participant, reducing grid draw across five specific hours can reduce the GA allocation for an entire following year.

Eligibility

The IESO’s Class A eligibility page describes three demand bands, measured on average monthly maximum hourly demand. Facilities above 500 kW and below 1 MW in specified manufacturing, industrial and greenhouse sectors may opt in, subject to the required NAICS code and program rules. Facilities above 1 MW and up to 5 MW may opt in. Facilities above 5 MW qualify automatically and may opt out.

Eligibility rests on a 12-month calculation rather than one high bill, and ownership changes, facility aggregation and injections can affect the result. A site near a threshold should confirm its status with its local distribution company or the IESO.

The catch that changes your sizing

The five peak hours are only confirmed after the base period closes. Capturing the value means responding to forecast peaks, which is why operators commonly discharge on considerably more than five occasions a year, balancing forecast confidence, available state of charge, process constraints and battery throughput.

That changes the machine you need. A battery specified for five annual discharges is a different product, warranty and price from one specified for forty. If a quote never asks how often the battery will dispatch, it is quoting an enclosure rather than a system.

Check the market assumptions before modelling

Since the IESO’s 2025 Market Renewal Program the historical relationship between wholesale prices and Global Adjustment has changed, and Hydro One notes that wholesale prices rose while GA fell. A business case built from an older GA chart can materially overstate the opportunity, so the model needs current inputs rather than a figure carried forward from a previous project.

We cover the mechanism in depth on the Ontario peak shaving page, and the peak shaving calculator will give you a first estimate from one utility bill.

Does NFPA 855 apply to battery storage in Canada?

NFPA 855 is the Standard for the Installation of Stationary Energy Storage Systems. It is referenced constantly in the design and review of battery projects. It does not automatically become the governing law for an installation in Canada.

In Ontario the applicable requirements can come from the Ontario Building Code, the Ontario Electrical Safety Code, the Ontario Fire Code, municipal requirements, an insurer, the project specification and the authority having jurisdiction, or AHJ. The AHJ may be a building official, a fire service, an electrical authority or another body carrying approval responsibility. More than one can be involved on the same project.

So the question worth asking is not whether a system is NFPA 855 compliant. It is which edition, if any, this AHJ intends to use, what product certifications they expect, what fire-test data must be submitted and who owns the site-specific analysis. Settle that before the equipment and the site layout are fixed, because both are expensive to revisit.

“Designed to NFPA 855” is not the same as approved to build.

What the 2026 edition changes for a C&I or utility buyer

Most buyers do not need to read the standard clause by clause. They do need to know which changes touch land, layout, engineering scope, documentation and schedule.

The direction of the 2026 edition is more weight on how an installation behaves under severe fire conditions. UL Solutions’ current explanation of NFPA 855 and UL 9540A points to the increased importance of installation-level, large-scale fire testing, together with separation, vent-gas ignition, enclosure behaviour and suppression performance.

That does not put every project on one identical test path. It does mean a buyer should stop treating “9540A tested” as a finished answer.

Set the hazard mitigation analysis scope early

A hazard mitigation analysis, or HMA, examines credible failure conditions and the safeguards used to control what follows from them. Depending on the installation that can include thermal runaway, fire propagation, flammable-gas accumulation, deflagration, ventilation, detection, suppression and emergency response.

It is site-specific. Certificates and laboratory reports feed it and do not replace it. Before ordering, establish who prepares the HMA, what data the supplier will provide and when the AHJ expects to review the approach.

Read the fire-test scope, not the cover page

ANSI/CAN/UL 9540A is a staged test method. A report may address the cell, module, unit or installation level depending on the edition, the test program and the results.

Older unit-level results stay useful. They are not the installation-level, large-scale fire test described in the newer framework, and the two should not be quoted as if they were interchangeable. The edition, the test level, the sample, the target arrangement and the results all matter. If the quoted system changes the cell, the module count, the enclosure, the fire system or the spacing, the project team needs a documented basis for carrying the earlier evidence across.

Put emergency planning in the contract

Emergency operations, response planning and training belong in the project scope, not in a folder assembled after energization. The owner, integrator, engineer and emergency services need one shared understanding of alarms, shutdowns, access, gas hazards, response and recovery. Assign ownership and delivery dates while there is still commercial leverage to do it.

Bring fire-protection input in while the layout can still move

Fire-protection advice is worth most while access, spacing, water supply, ventilation and responder approach are all still flexible. For larger or unusual installations the AHJ may expect interpretation by a qualified fire-protection professional. Identify that person during design rather than at permit stage.

What UL 9540, UL 9540A and the IEC standards actually prove

UL describes UL 9540 as the product-safety basis for an ESS and UL 9540A as the standardized fire-test method. A serious procurement review asks four things: what model was listed, what was tested, which edition was used, and how that scope maps onto the system being quoted.

A certificate proves that something specific was evaluated. It does not prove that your site was.

What to ask for before you issue a purchase order

Ask for a project document index naming the responsible party and the delivery date against each item.

• Product certificates and listing scope tied to the quoted battery, enclosure and ratings, and to the power-conversion equipment where it is included
• Complete fire-test reports identifying the standard edition, test level, sample configuration and laboratory
• A model and bill-of-materials cross-reference showing why that evidence applies to the configuration you are buying
• Installation manuals, environmental limits, spacing and access, plus the applicable detection, gas-management, ventilation, venting and suppression information
• Electrical single-line diagram, grounding, protection, interfaces, alarms and shutdown sequence
• Inputs for the site-specific HMA and the emergency plans
• Commissioning, training, service and warranty requirements
• Current transport documentation for the product actually being shipped

A folder of certificates drawn from several products is not an answer to this. What helps a reviewer is a traceable package connecting the marked equipment, the tested construction, the drawings and the installation being submitted.

The Canadian detail behind all of this, including how the evidence maps onto specific BX cabinet and container configurations, is handled per project. Send us the quoted configuration and we will tell you what evidence exists for it and what still has to be produced.