For many Alberta and BC commercial and industrial accounts, the demand charge on your bill (measured in kW) costs more than the energy charge (measured in kWh). Peak shaving targets that charge directly.
This is what battery dispatch looks like across a typical day for a facility pairing solar with storage. The battery discharges to cover the morning and evening load spikes (when demand is high but solar production is still ramping up or winding down), lets solar carry the midday load directly, and recharges from the grid overnight during low-demand hours.
Conceptual illustration of a typical peak-shaving dispatch profile. Actual battery dispatch is tuned to each facility's specific load pattern and utility rate structure.
Most residential electricity bills are simple: you pay for how many kilowatt-hours (kWh) you used. Commercial and industrial accounts, especially anything above roughly 50 kW of peak load, usually pay a second charge on top of that: a demand charge, billed in dollars per kilowatt (kW), based on the single highest 15-minute interval of power draw during the billing period.
That means one short spike, a chiller, a compressor, or several pieces of equipment starting at once, can set your demand charge for the entire month, even if it lasts only a few minutes. Peak shaving is the practice of flattening those spikes, typically using a battery system, load-shifting software, or a combination of both, so your peak draw from the grid stays lower even though your total energy use doesn't change.
On a typical Alberta or BC commercial rate schedule, demand charges can represent 30–50% of a facility's total monthly bill. In the sample commercial cash-flow proformas we build for clients, demand-related charges alone often run into the thousands of dollars per month for a mid-size industrial account, separate from energy consumption entirely. That means peak shaving can produce meaningful savings even on a facility that has already installed solar, because solar addresses kWh consumption while peak shaving addresses the kW peak.
Using anonymized data from an actual commercial energy storage proposal, here's how a facility's annual electricity spend split between energy consumption and peak demand before any battery was installed:
Real annual bill breakdown from a commercial energy storage proposal: demand charges made up 43.7% of the total $75,389 annual bill, energy usage 55.6%, and fixed charges under 1%. This is the actual proportion peak shaving targets.
The chart below shows actual monthly demand-charge savings delivered by a 15 kW / 30 kWh battery system paired with an existing 150 kW solar array at a real commercial facility, targeting the site's highest-draw 15-minute interval each month.
$6,639 in total annual demand savings from this real system. Net ESS cost after the federal ITC and CCA depreciation was $3,770, meaning the battery's peak shaving value alone paid back its net cost in under a year, separate from the additional value of the solar generation it was paired with. Client details anonymized; results vary based on individual circumstances and are not guaranteed.
On most Alberta commercial and industrial rate schedules, the energy charge (the part that scales with total kWh consumed) is not where the largest chunk of your bill comes from. The System Usage Charge, billed against the single highest 15-minute interval your meter recorded all month, is frequently the bigger number. If your compressor, your block heaters, and your wash bay all happen to cycle on within the same 15-minute window, that one moment sets your demand charge for the entire billing period, regardless of how efficiently your facility ran every other minute of the month.
Many Alberta commercial rate schedules use a demand ratchet, meaning your minimum billed demand for the next 11 months is calculated as a percentage (commonly around 85%) of your trailing 12-month peak, not your current month's usage. A single unusually high peak in, say, February, can keep your demand charge elevated straight through the following winter, even if every other month runs well below that level. This is exactly why a peak shaving strategy that only reacts to today's load misses the point, the goal is holding your peak below a ceiling reliably, every month, not just occasionally.
The chart below illustrates the effect: a facility's actual monthly peak (orange) varies with the seasons, but the billed demand floor (navy dashed) stays elevated at roughly 85% of the trailing 12-month high, refusing to drop even in low-usage months.
Illustrative example. Ratchet percentages, rate minimums, and demand charge structures vary by Alberta distribution utility (ENMAX, EPCOR, ATCO Electric, FortisAlberta) and rate schedule, confirm your specific tariff before modeling savings.
Alberta distribution rate schedules typically use expected-peak-capacity tiers, and which tier your facility sits in determines your rate minimum and per-kW charge structure. Holding your metered peak reliably below a tier threshold, rather than just shaving it down within your current tier, can be the single largest lever on your bill, because it changes the rate structure itself, not just the number multiplied by it.
| Rate Tier (Illustrative Example) | Typical Rate Minimum | Structure |
|---|---|---|
| Small Commercial | ~3 kW | Lower per-kW-day charge, built for smaller sites |
| Standard / Mid-Tier Commercial | ~50 kW | Higher per-kW-day charge, ratchet on trailing 12-month peak |
| Large Industrial | ~2,000 kW | Billed on greater of metered peak or Contract Minimum Demand |
Illustrative tier structure based on common Alberta distribution rate patterns. Exact thresholds, rate minimums, and $/kW-day charges vary by utility and change over time, this is a conceptual example, not a quote against any specific tariff.
A facility sitting just above a tier threshold pays the higher tier's rate minimum and structure on its entire demand charge, every month, even though the actual usage difference between "just above" and "just below" the line might be a handful of kilowatts. Reliably holding peak demand under a threshold, with a battery system sized and controlled well enough to guarantee it, can move a facility into a fundamentally cheaper rate structure, not just a smaller bill within the same structure.
These two terms get used interchangeably, but they're different battery strategies that want opposite things from your battery's state of charge, and most commercial installations only run one of them.
Captures excess solar production during the day and discharges it in the evening to reduce the volume of grid electricity purchased. Targets the energy charge (kWh). Wants the battery as empty as possible by sundown, to leave room to absorb tomorrow's solar.
Holds charge in reserve so the battery can discharge against a demand ceiling whenever the site's load looks like it will exceed it. Targets the demand charge (kW). Wants the battery as full as possible at all times, ready to defend the threshold.
The chart below shows how a battery's state of charge looks across a typical day under each strategy in isolation. A load-displacement-only battery drains to empty by evening; a peak-shaving-only battery stays topped up all day, ready to defend against a spike at any moment. A system programmed for only one strategy leaves the other type of savings on the table.
Conceptual illustration. Well-designed commercial systems use dynamic dispatch logic that blends both strategies hour by hour, rather than committing fully to one, rather than a fixed setting that can only optimize for one at a time.
A common but costly mistake is sizing a battery by taking a facility's worst-ever 15-minute peak, subtracting a target ceiling, and quoting a battery large enough to cover that gap for fifteen minutes. The math looks clean on paper, but it often oversizes the battery unnecessarily. A more precise approach identifies which specific pieces of equipment are actually driving the peak, a compressor's startup cycle, a wash bay pump, block heaters staging on together, and sizes the battery against that combination, not the facility's total connected load.
This is also why interval-data analysis matters more than a single peak-demand number on your bill. Understanding the shape and cause of your peak, not just its size, is what lets a system be sized correctly instead of oversized "to be safe."
A battery with a fixed, manually-set discharge threshold is a blunt instrument. The threshold has to be set conservatively enough to protect against the worst month of the year, which means it's leaving savings on the table during every other month. And when a facility adds new equipment that shifts its load profile, a fixed threshold doesn't adapt, someone has to notice and manually retune it, which in practice rarely happens.
The systems that actually deliver on both load displacement and peak shaving simultaneously use dynamic dispatch controllers: software that forecasts production and consumption on a rolling basis and continuously adjusts how much of the battery's capacity to allocate toward defending tomorrow's demand ceiling versus absorbing today's surplus solar. This is a meaningfully different (and more valuable) capability than a battery that simply executes a fixed inverter setting programmed once at installation. When evaluating a commercial battery proposal, it's worth asking directly whether the dispatch logic adapts automatically to seasonal and equipment changes, or whether it requires manual retuning, and whether the installer can show you, in dollars, what the system actually saved versus a baseline.
There are three main levers, usually deployed together:
An on-site battery system, sized to your facility's peak profile, discharges automatically during the highest-draw intervals of the day, covering part of the spike so less power is pulled from the grid at that moment. The battery recharges during lower-cost or lower-demand periods, often from solar generation.
Shifting flexible loads, like batch processes, EV charging, or non-time-sensitive equipment, away from your facility's typical peak window. This requires understanding your interval data closely enough to know when your peaks actually occur.
Software that tracks your facility's demand in near real time and can trigger automated responses, like battery discharge or non-critical equipment shutdown, before a new monthly peak gets set.
Before recommending a system, we pull your facility's interval data (typically 15-minute kW readings) for a full year if available, the same way a formal energy-use profile is built for any commercial solar or storage proposal. This reveals your facility's actual peak pattern: whether it's a predictable daily spike, a seasonal pattern, or driven by a specific piece of equipment. That pattern determines whether a battery, load scheduling, or a combination makes the strongest financial case, and it determines exactly how large a battery needs to be, since oversizing wastes capital and undersizing leaves savings on the table.
| Charge Type | What Addresses It |
|---|---|
| Energy consumption (kWh) | Solar generation offsets grid draw directly |
| Peak demand (kW) | Battery dispatch and load scheduling (peak shaving) |
| Outage risk | Battery storage sized for backup duration |
| Rate volatility exposure | Solar + storage combined, reducing reliance on floating market rates |
Most commercial energy proposals we build combine at least two of these, since a battery sized for peak shaving is also the battery that stores solar production and provides backup power, and the incremental cost of adding that capability to an existing solar project is usually far lower than building a standalone system later.
A metal manufacturing facility in Alberta was paying demand charges that made up nearly 40% of its monthly utility bill, driven by short compressor start-up spikes each morning.
An interval-data review identified the exact 15-minute window responsible for the facility's monthly peak. A battery system was sized specifically to cover that window, paired with a soft-start schedule for the compressor bank.
The facility's monthly demand charge dropped by roughly 35% within the first billing cycle after commissioning, with no change to production output.
Client name changed. Results vary based on individual circumstances. Prior results do not guarantee similar outcomes.
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