Coincident Peak Pricing in PJM: How Demand Charges Work and How to Reduce Your Bills

PJM Interconnection (covering Pennsylvania, New Jersey, Maryland, Delaware, and parts of surrounding states) charges commercial and industrial customers based not just on total electricity consumed (kWh), but on peak instantaneous demand (kW) coinciding with system-wide peak hours. A manufacturing plant using 1,000 kW during 3 PM on a summer afternoon when PJM experiences maximum system load triggers "coincident peak" demand charges, while the same 1,000 kW used at 11 PM (off-peak) incurs no coincident peak charge. This distinction can add $15,000-$150,000+ to annual bills for large facilities. Unlike time-of-use rates that vary hourly, coincident peak charges only apply to the few hours (typically 5-10 per year) when PJM hits system maximum demand. A single unmanaged peak hour can cost more than an entire month of baseline usage. For facilities able to reduce demand during these critical windows, 10-25% bill reductions are realistic. This guide explains PJM's coincident peak methodology, calculates real cost impacts, and provides optimization strategies from simple load shifting to facility infrastructure upgrades.

How Coincident Peak Pricing Works in PJM

PJM operates a wholesale electricity market across 13 states where generators bid power and utilities/retailers bid load. Each hour, supply and demand equilibrate at a locational marginal price (LMP). System peak occurs when total PJM demand reaches its annual maximum—typically 2-5 summer afternoons in July/August during extreme heat, occasionally winter mornings during cold snaps. When system peak occurs, PJM charges each commercial customer a "coincident peak demand charge" equal to: Customer's peak demand during that hour × all-in PJM coincident peak rate ($50-150/kW typical for 2024-2025). A customer's "coincident peak demand" is their maximum instantaneous demand (in kW) measured during any system peak hour.

Real example: 500 kW manufacturing facility in Pittsburgh (PJM zone) Baseline load profile: Mon-Fri 7 AM-6 PM = 450 kW average, nights/weekends = 100 kW. July 23, 2024: System peak hour (3-4 PM) when outside temperature 98°F, PJM hits record 160 GW demand (annual max). Plant runs all equipment at full capacity = 520 kW at 3:15 PM during peak hour. Coincident peak rate = $85/kW (2024 PJM summer). Cost = 520 kW × $85 = $44,200 charge for that single hour. For the year, that $44,200 charge represents ~15% of the facility's total $290,000 electricity bill, despite the hour representing <0.1% of annual hours.

Key Takeaway: PJM coincident peak charges are assessed only during system peak hours (5-10 per year typically), but can comprise 10-30% of annual bills for large industrial/commercial facilities. Reducing demand by even 50 kW during the single peak hour saves $50 × 85 = $4,250/year. This creates strong incentive for load management during rare peak events. Many facilities can shift production, defer HVAC demand, or curtail non-critical loads for 1-2 hours at enormous savings.

PJM Peak Demand Charge History and Rate Trends

Cost impact over time: A facility with 500 kW coincident peak demand paid: 2020 = $14,000; 2024 = $52,500; 2025 projection = $57,500-$65,000. This 4.7x increase (2020-2024) far outpaces wage/inflation growth, pressuring facilities to invest in demand management.

Calculating Your Coincident Peak Demand Charge

Step 1: Identify your PJM coincident peak rate Check your utility bill or PJM rate schedule. For Pennsylvania utilities (PPL, PECO, Duquesne), rates are published quarterly. As of 2025: Most PJM zones range $95-$125/kW. Specific zone variation exists (Western PA generally $100-105/kW, Northern NJ $110-115/kW due to transmission constraints).

Step 2: Determine your facility's peak demand during system peak hours Review 12 months of demand history. PJM announces system peak dates retrospectively (typically 5-8 summer dates per year). Your meter should log 15-minute interval demand data. Find your maximum demand (kW) during any hour when PJM system was at peak. For example, if your maximum during all PJM peak hours was 580 kW (even if it occurred during only one hour), that 580 kW is your coincident peak demand.

Step 3: Calculate annual charge Annual coincident peak demand charge = Your peak kW × $/kW rate. Example: 580 kW × $105/kW = $60,900/year coincident peak charge (component of total electricity bill).

Real-World Facility Cost Examples

Semiconductor Manufacturing Plant, Northern New Jersey (1,200 kW average load) Peak demand during system peak hours: 1,450 kW (process equipment cannot be rapidly curtailed). Coincident peak rate 2025: $118/kW. Annual charge: 1,450 × $118 = $171,100. Total electricity bill: $850,000 (energy 65%, demand 20%, capacity charges 15%). Coincident peak = 20% of annual bill. Facility investigated load shifting (deferring cleaning processes, shifting production schedules); identified 200 kW reduction achievable during peak hours (production shifted to evening). Savings: 200 × $118 = $23,600/year. Investment: New scheduling software ($50K), staff training ($10K) = $60K total. Payback: 2.5 years.

Data Center, Eastern Pennsylvania (2,500 kW continuous baseline) Peak demand: 3,100 kW during summer peak hours. Coincident peak rate: $115/kW. Annual charge: 3,100 × $115 = $356,500. Facility identified opportunity: Battery energy storage system (1 MWh, 500 kW discharge capability) can discharge during peak 1-2 hours, reducing grid draw and peak demand. Cost: $1.2M installed. Benefit: Reduce peak from 3,100 to 2,600 kW = 500 kW × $115 = $57,500/year savings. Payback: 21 years (marginal given 10-year battery warranty). However, facility also qualifies for federal ITC (30% tax credit) = $360K reduction, improving payback to ~15 years. Facility proceeds with investment.

Office Building, Pittsburgh (400 kW peak demand during normal days; 520 kW during system peak hours) Peak demand (highest during system peaks): 520 kW. Coincident peak rate: $102/kW. Annual charge: 520 × $102 = $53,040. Facility implemented demand management: (1) Precooling building to 68°F before peak hours, then allowing temperature to drift to 76°F during peak = 60 kW HVAC demand reduction; (2) Deferring non-critical lighting loads during peak hours = 20 kW reduction; (3) Postponing elevator maintenance during peak = 10 kW. Total reduction: 90 kW during peak hours. Savings: 90 × $102 = $9,180/year. Cost: HVAC programming $5K, LED retrofit (unrelated to peak, but accomplished concurrently) $30K. Demand management portion ROI: 1.8-year payback (if $5K, the non-LED cost).

Demand Management Strategies: Ranked by ROI

Strategy 1: Operational Load Shifting (Best ROI, 1-3 year payback) Defer or shift non-critical processes to non-peak hours. Manufacturing: Schedule maintenance windows, CNC machine runtimes, paint/cleaning operations to evening/night. Office: Postpone equipment maintenance, stagger elevator repairs, defer EV charging until after peak hours. Cost: Minimal (staff schedule changes, software scheduling tool $5-15K). Reduction potential: 50-200 kW depending on facility. Annual savings: $5K-$25K+ for $5-15K investment.

Strategy 2: Precooling/Preheating (Moderate ROI, 2-4 year payback) Cool/heat building before peak hours, allow drift during peak to reduce HVAC demand. Requires: BMS (Building Management System) programming, no capital equipment. Cost: $3-10K for controls upgrade. Reduction potential: 30-80 kW (HVAC compressor demand reduction). Annual savings: $3-10K. Example payback: $6K investment, $5K savings = 1.2-year payback.

Strategy 3: Battery Energy Storage (Moderate ROI with tax incentives, 12-20 year payback) Install 1-2 MWh battery system, charge during off-peak, discharge during system peak. Reduces peak demand by system duration × power output. Cost: $800K-$2M (includes installation, controls, interconnection). Reduction potential: 200-500 kW depending on size. Annual savings: $23K-$60K. Payback: 15-25 years (improves to 10-15 years with 30% federal ITC, state rebates). Best for facilities with: (1) High demand charges relative to bill, (2) Multiple peak events annually, (3) Access to incentives.

Strategy 4: On-Site Solar + Battery (Long-term ROI, 7-12 year payback) 100 kW solar system generates power during peak hours (typically 2-5 PM summer), discharges battery during extended peak hours. Cost: $200K-$400K (solar $1.50-2.00/W + battery $200-300/kWh). Reduction potential: 50-100 kW peak demand reduction. Annual savings: $5-15K demand charge reduction + $8-12K energy cost reduction = $13-27K total. Payback: 10-15 years. Strong incentive if facility also qualifies for federal ITC (30%), accelerates payback to 7-10 years.

Worst-Case Scenario: Unmanaged Peak Hour

Pharmaceutical Facility, New Jersey (Aug 5, 2024 - Extreme Heat Event) Facility's normal summer peak: 900 kW. Aug 5: Temperature reached 98°F by 2 PM, all cooling loads maximized, production continued without load management. 3:47 PM: Facility hit 1,200 kW demand during PJM system peak (highest all year). Coincident peak charge: 1,200 kW × $118/kW = $141,600 for that single hour (part of annual demand charge calculation). Facility had no demand response contract, no load curtailment plan. Later analysis showed: Reducing non-essential cooling by 10°F setpoint during peak 2 hours would've reduced demand to 1,050 kW = savings of 150 kW × $118 = $17,700 from that single event. Facility invested $15K in demand response automation software post-facto to prevent recurrence.

Next Steps

Step 1: Obtain 12 months of interval meter data. Contact your utility's commercial customer service. Request 15-minute interval load profile data (not just hourly summary). Costs: $0-$50 usually free to commercial customers. This data is essential to identify your demand patterns and peak hour behavior.

Step 2: Identify PJM system peak dates for current/previous year. Visit PJM.com → Reports → System Peak Hours (published after year-end). Note the dates/times of your facility's maximum demand coinciding with system peaks. Benchmark against national/regional demand trends.

Step 3: Conduct demand reduction audit. Identify 3-5 operational or equipment changes that reduce demand during peak hours with minimal/no capital cost. Examples: Defer maintenance, shift schedules, adjust thermostat setpoint, postpone equipment startup. Estimate kW reduction × PJM rate = potential annual savings. Target: 50-150 kW reduction for $5-20K investment if pursuing quick-payback strategies.

Step 4: For significant investments (batteries, solar), obtain quotes and incentive estimates. Contact 2-3 EPC (engineering, procurement, construction) firms for battery/solar turnkey quotes. Check federal ITC eligibility (seia.org), state rebate programs (utility website). Model 15+ year NPV with declining equipment costs, rising electricity rates, and incentives to justify capital deployment.

Related articles: Time-of-Use Rates, Capacity Auctions, Energy Storage Systems