Understanding Demand Charges & Peak Management

For Commercial & Industrial (C&I) customers, demand charges – fees based on the highest rate of electricity usage (peak demand, measured in kilowatts or kW) rather than total consumption (kWh) – are often a critical and costly part of the electricity bill.

Measuring Peak Demand

  • Utilities measure demand over specific time intervals, typically 15 minutes or 30 minutes (e.g., ConEd uses 30 min).
  • The Monthly Peak Demand is the highest average kW usage recorded during any single interval within the billing month.
  • Billing formula: Demand Charge = (Monthly Peak kW) × ($/kW rate from tariff).
  • Tariffs may have seasonal demand charges (higher $/kW in summer) or time-of-use (TOU) demand windows (peak only counts if set during specific hours, e.g., 8am-6pm weekdays).
  • Some tariffs include a demand ratchet, where the billing demand is the higher of the current month's peak or a percentage (e.g., 50%) of the highest peak from the past 12 months. This ensures recovery of fixed costs even if demand drops temporarily.

Non-Coincident vs. Coincident Peak Demand

It's crucial to distinguish between these two types of peak demand, as they drive different cost components:

  • Non-Coincident Peak (NCP) Demand: This is the customer's own maximum demand during the billing period, regardless of when it occurs (unless limited by TOU windows).
    • Most utility delivery demand charges are based on NCP.
    • Recovers the cost of local distribution infrastructure sized for that customer's peak load.
    • Managed by reducing the facility's absolute highest usage interval in the month.
  • Coincident Peak (CP) Demand: This is the customer's demand at the specific time of a broader system peak (e.g., the single hour when the entire ISO/RTO system hits its annual maximum load, or the top 5 system peak hours).
    • Used to allocate system-wide costs like generation capacity and high-voltage transmission.
    • Determines tags like Peak Load Contribution (PLC) in PJM (based on 5CP demand) or Installed Capacity (ICAP) Tag in NYISO (based on 1CP demand).
    • Also used for Network Service Peak Load (NSPL) tags in PJM/ISO-NE for transmission cost allocation.
    • Managed by specifically reducing load during the few hours each year when the overall grid is expected to peak.

Key Distinction: Managing NCP demand lowers your monthly utility delivery bill's demand charge. Managing CP demand (often just a few critical hours per year) lowers your future capacity and transmission charges (often passed through by suppliers in capacity markets).

Peak Load Management & Demand Response

Since demand charges can be substantial (often >30% of a C&I bill), managing peak load is essential:

  • Peak Shaving Techniques:
    • Operational changes: Staggering equipment start-ups, shifting flexible processes off-peak.
    • Building controls: Pre-cooling/heating, adjusting HVAC setpoints during peaks.
    • On-site resources: Using backup generators (subject to permits), batteries, or solar PV during peak hours.
    • Technology: Installing demand controllers or energy storage systems (batteries, thermal storage).
  • Demand Response (DR) Programs:
    • ISO/RTO Programs: Allow C&I customers to earn payments or bill credits for reducing load during grid emergencies or high price periods (e.g., PJM Emergency/Economic DR, NYISO SCR program, ISO-NE Active Demand Resources, ERCOT ERS). Participation often requires meeting minimum size (e.g., 100 kW) and performance criteria.
    • Utility DR Programs: Local utility programs may offer incentives for peak reduction within specific distribution networks (e.g., ConEd CSRP/DLRP).

    See also: Demand Response & DSM Knowledge Base for more details on specific programs.

  • Coincident Peak Management Services: Many third parties offer services to predict system peak days/hours ("peak alerts") allowing customers to target curtailment efforts effectively to reduce PLC/ICAP tags.

Effectively managing both non-coincident and coincident peaks through operational changes, technology investments, and program participation can significantly reduce overall electricity costs for C&I customers. Combining smart procurement with active load management is a best practice in today's energy markets.