Demand charges are billed on the highest fifteen-minute average kilowatt draw during the utility's billing period, measured against the demand schedule on your tariff. On most commercial electric bills in the Mid-Atlantic, demand charges represent forty to sixty percent of the total invoice. Despite their dominance of the bill, demand charges receive far less management attention than commodity rates or efficiency upgrades. This primer covers how demand charges actually work, why ratchet clauses quietly compound the exposure, and the strategies that produce real reduction without disrupting operations.
What is a demand charge?
Your electric bill has two main consumption-related components: energy, billed in kilowatt-hours (the total quantity of electricity you used during the billing period), and demand, billed in kilowatts (the highest rate at which you drew electricity during a specific peak measurement window).
An analogy that helps: energy is the total water you used this month, billed by the gallon. Demand is the maximum flow rate you ever asked for, billed by the pipe size required to deliver it. The utility provisions its distribution infrastructure for your peak demand even if you only hit that peak briefly. The demand charge recovers the cost of that provisioned capacity.
Demand charges appear on commercial schedules that include a demand-metered tariff. Small commercial accounts on general-service tariffs do not have explicit demand charges; their demand is implicitly bundled into the energy rate. Once your facility crosses into demand-metered territory (typically when peak demand exceeds a threshold like 50 or 100 kW depending on the utility), demand becomes its own line item.
A typical demand charge in BGE, PEPCO, or Delmarva commercial general service territory ranges from eight to twenty-five dollars per kilowatt of peak demand per month. That means a single peak of one hundred kilowatts can add eight hundred to twenty-five hundred dollars to a single bill. The same peak repeated across a year produces nine to thirty thousand dollars in annual demand cost.
How peak demand is measured
Utilities measure peak demand by integrating instantaneous power draw over fixed time intervals, almost always fifteen minutes. Your demand for a given fifteen-minute window is the average kilowatts drawn during that window. The utility records this every fifteen minutes throughout the month and reports the highest interval as your billed demand.
Two important implications follow from this measurement methodology:
The peak is a moment, not a sustained level
A facility running at twenty kilowatts average but spiking to one hundred kilowatts for one fifteen-minute window pays for that one hundred kilowatt peak across the entire month. The peak does not need to be sustained. A single bad fifteen-minute interval drives the billed demand.
Time-of-use tariffs make timing matter
Some tariffs measure peak demand only during specified peak hours (for example, weekday afternoons in summer). On those tariffs, demand outside the peak window does not count, no matter how high it goes. Shifting peak operations outside the demand window becomes a powerful cost-reduction lever. On flat-window tariffs that measure demand any time, this lever is unavailable.
What is a demand ratchet clause?
A demand ratchet clauselocks in a minimum billed demand for the eleven months following a peak event, regardless of whether you ever approach that level again. Ratchet clauses appear on most large commercial schedules in BGE, PEPCO, and Delmarva territory, usually buried in the tariff under a name like "Minimum Demand Charge" or "Demand Ratchet."
A common ratchet structure is fifty percent: if your tariff has a fifty-percent ratchet and you peak at two hundred kilowatts in July, your minimum billed demand is one hundred kilowatts for the next eleven months even if your actual peak in those months drops to forty kilowatts. The utility bills the greater of (a) your actual peak that month or (b) the ratchet floor set by your prior twelve months' peak.
Why ratchet clauses matter so much
The ratchet structure dramatically increases the cost of a single operational mistake. Consider a facility that normally peaks at one hundred kilowatts, on a tariff with a fifteen dollar per kilowatt demand rate and a fifty-percent ratchet:
- Normal billed demand: 100 kW × $15 = $1,500/month
- One bad event drives the peak to 250 kW in July
- July billed demand: $3,750 (a $2,250 single-bill impact)
- Ratchet floor set at 125 kW (50% of 250) for the next eleven months
- Each of August through next June: minimum demand = 125 kW (vs. actual peak of 100 kW) = $1,875/month
- Eleven-month ratchet impact: $4,125 in excess demand charges
Total cost of the single bad event: $6,375, of which only one-third hit the immediate bill. The remaining two-thirds appear as quiet, persistent demand inflation across the following year. Most facility managers never realize this is happening.
How to spot ratchet exposure on your bill
Ratchet exposure is rarely labeled as such on the invoice. Instead, the bill shows a single demand line item with the billed demand quantity. To check whether you are paying a ratchet floor rather than your actual peak:
- Pull your twelve most recent invoices. List the billed demand quantity for each month.
- Identify the highest demand month. Multiply by your ratchet percentage (check your tariff document; typically 50, 75, or 80 percent).
- For each subsequent month, compare the billed demand quantity to the ratchet floor you calculated. If the billed demand equals the ratchet floor and not your actual peak, you are paying ratchet rather than actual demand.
If you do not have access to interval data showing your actual peak for each month, contact your utility and request the interval read records for the past twelve months. They are obligated to provide this. The interval data will show your true peak, which you can then compare against the billed demand.
Five strategies that actually reduce demand charges
1. Identify the equipment driving peak demand
Interval data reveals the time-of-day pattern of your peaks. Cross- reference against operational schedules to identify what is running when peaks happen. Common culprits in commercial facilities: chiller startup sequences, simultaneous HVAC equipment cycles, EV charging, compressor startup, and unit-substation transfer events.
2. Stagger equipment startup
Equipment that draws large startup current should not start simultaneously. Sequencing two pieces of equipment thirty seconds apart instead of in unison can shave significant demand without operational impact. Building automation systems can typically be configured for staged startup.
3. Pre-cool or pre-heat to shift demand
Buildings with thermal mass can be pre-cooled in off-peak hours to reduce mid-day HVAC demand. The same principle applies to refrigeration and other thermal loads. Pre-cool strategies are particularly effective on time-of-use tariffs where peak windows are defined.
4. Power factor correction
Many large commercial loads (motors, transformers, rectifiers) draw reactive power that does not register on the kilowatt meter but increases the total current the utility must supply. Most tariffs include a power factor adjustment that effectively penalizes you for poor power factor. Installing capacitor banks at the service entrance or near specific large loads corrects the power factor and avoids the penalty. We cover this in detail below.
5. Enroll in demand response
Programs like PJM Capacity Performance pay you to reduce demand on command during grid stress events. The capacity payment is recurring revenue, and the operational impact during events is bounded. We cover this in the next section.
Demand response: getting paid to manage demand
Demand response is a class of grid services that pays you to reduce electrical load during specified events. In the PJM Interconnection region (which covers all of our service territory), the largest programs are Capacity Performance and Synchronized Reserve.
Capacity Performance pays a fixed monthly capacity payment plus an event-based payment when called. Events typically occur five to fifteen times per year, for two to four hours each. Participating facilities commit to reducing load by a defined amount on notice. A facility that can reliably shed five hundred kilowatts on notice earns fifteen to forty thousand dollars per year in pure revenue, separate from any operational savings.
Synchronized Reserve is a faster-response service that requires load reduction within ten minutes of notice. Payments are higher per megawatt, but operational requirements are stricter. Most commercial facilities participate in Capacity Performance; only a subset qualify for Synchronized Reserve.
Enrollment is administered through curtailment service providers (CSPs) who handle the PJM interface, baseline measurement, and event coordination. The CSP retains a portion of the capacity payment as compensation; net payments to the facility typically run twenty-five to seventy-five dollars per kilowatt-month of registered capacity.
Power factor and demand interaction
Power factor is the ratio of real power (kilowatts, what does work) to apparent power (kilovolt-amperes, what the utility must supply). Inductive loads (motors, transformers, rectifiers, fluorescent ballasts) cause current and voltage to fall out of phase, producing reactive power that the utility delivers but cannot bill at the energy rate.
Utilities recover the cost of reactive power through a power factor adjustment that penalizes you when your power factor drops below a threshold (typically 0.90 or 0.95). The penalty can manifest as either a kVAR (reactive power) line item charge or an adjusted billed demand figure that scales your real demand by the power factor deficit.
Power factor correction involves installing capacitor banks at the service entrance or near specific large loads. The capacitors offset the inductive reactive power, raising the facility's overall power factor and avoiding the penalty. Equipment cost runs twenty to two hundred thousand dollars depending on facility size; payback periods from penalty avoidance alone are typically eighteen to thirty-six months.
Summary
Demand charges are the largest under-managed cost in most commercial electric bills in the Mid-Atlantic. The combination of fifteen-minute peak measurement, eleven-month ratchet exposure, and power factor penalties creates a structural cost that operational discipline alone cannot fully reduce. The strategies above (peak identification, startup staggering, thermal pre-cool, power factor correction, demand response enrollment) typically combine to reduce demand-related costs by twelve to thirty percent on the commercial accounts we audit.
For a deeper read on the specific finding patterns we surface during demand-related audits, see the Demand Management service page for full detail on engagement structure, typical outcomes, and the specific equipment-and-tariff patterns we look for.