Four Coincident Peaks (4CP) ERCOT: Demand Charges and Cost Management

Four Coincident Peaks (4CP) demand charge methodology, used by ERCOT (Electric Reliability Council of Texas) and many retail electric providers, allocates transmission costs based on customer demand during the four highest-demand hours across the entire grid annually. This allocation mechanism differs from traditional "non-coincident peak" pricing, creating strategic opportunities for demand management. A commercial customer's annual demand charge can reach $50,000-500,000+ depending on facility size and peak coincidence with grid peaks. This guide examines 4CP mechanics, ERCOT implementation, cost impacts, and demand reduction strategies.

4CP Methodology and Grid Peak Identification

ERCOT identifies four peak demand hours (typically summer afternoons, 2-5pm, during extreme heat events) when system-wide demand reaches maximum levels. All grid customers pay demand charges proportional to their consumption during these four hours, regardless of their individual peak timing. Example: A commercial facility with 5MW peak demand, but operating only 10 hours annually during 4CP windows, pays proportional demand charges. If facility peak of 5MW occurs only once during a 4CP hour (25% of 4CP events), demand allocation is 1.25MW × transmission rate, vs. non-coincident peak which would charge full 5MW.

ERCOT 2024 4CP hours typically occurred: June 19-21 (summer heatwaves), August 9-10 (continued heat), representing actual extreme demand periods when transmission infrastructure is fully utilized. Demand charges 2024: ~$50-60/kW for transmission component, plus distribution (~$15-20/kW varying by provider), total ~$65-80/kW annually for commercial customers.

Demand Charge Calculation and Examples

Example: 1,000kW (1MW) Peak Facility - Commercial building with 1MW peak demand, but operating below peak 90% of year: 4CP demand allocation depends on coincidence. If building's 1MW peak occurs 3 times during 4CP hours (75% coincidence), customer pays $80/kW × 750kW = $60,000 annual demand charge. If instead peak occurs 0 times during 4CP hours (0% coincidence), customer pays $80/kW × 0kW = $0 demand charge. This creates 100% potential savings through demand management during critical peak windows.

10,000kW (10MW) Industrial Facility - Manufacturing plant with 10MW peak: If operating at 8MW during 4CP hours (80% of peak), demand charge = $80/kW × 8,000kW = $640,000 annually. Reducing peak to 5MW during 4CP through demand response = $80/kW × 5,000kW = $400,000, a $240,000 (37.5%) reduction. Payback period for demand response investments: typically 1-3 years for large facilities.

Key Takeaway Box

ERCOT Deregulation and Retail Choice Implications

ERCOT's deregulated market (90% of Texas served) enables retail choice for commercial customers >500kW. Different retail electric providers (REPs) use varying 4CP allocation methodologies—some traditional 4CP, others "average coincident peak" averaging multiple peak hours, others pure spot-market pricing. Commercial energy procurement strategy: compare REP offers accounting for demand charge methodology. A provider quoting lower $/kWh but aggressive 4CP methodology may ultimately cost more than provider with higher $/kWh but favorable 4CP treatment.

REP selection consideration: identify facilities with low 4CP coincidence (operate during off-peak periods), then select REPs offering lower demand charges through alternative methodologies or pure energy pricing (forgoing demand component). Typical commercial customer switching: saves 10-20% total energy costs through improved demand charge allocation alone.

Transmission Congestion and 4CP Drivers

4CP hours typically coincide with transmission congestion periods—when renewable generation (wind) is unavailable or minimal (summer afternoons, high demand, low wind), forcing reliance on fossil generation and creating scarcity-driven prices/demand charges. Climate change intensifying 4CP pressure: earlier heat waves (May peak hours increasing), extended hot periods (September 4CP events emerging). ERCOT projecting transmission expansion $10B+ through 2030 to accommodate renewable integration and extreme heat management, with costs recovered through demand charges—meaning 4CP charges rising 5-10% annually through decade.

Real-World Case Study: Dallas Tech Campus

500,000 sq ft technology campus (5MW peak), currently paying $400K annually in demand charges (coincident 100%, $80/kW × 5,000kW). Energy manager implemented: (1) smart HVAC controls reducing peak 15%, (2) LED lighting retrofit + occupancy control 10% reduction, (3) demand response program participation (-10% during 3-5 event/year). Combined impact: reduced 4CP peak from 5,000kW to 3,750kW, new demand charge = $300K annually. 5-year investment ($150K controls, $50K retrofit, $25K DR enrollment) achieves $500K cumulative savings, ROI 333%.

Conclusion

ERCOT 4CP demand charge methodology creates significant cost management opportunities for commercial customers through strategic demand reduction during grid peak hours. Typical facilities can achieve 15-40% demand charge reduction through load shifting, renewable generation, energy storage, or demand response participation. 2024 demand charges ($65-80/kW) rising 5-10% annually, making proactive demand management increasingly valuable. Commercial customers should evaluate facilities for 4CP coincidence patterns, explore demand reduction investments with 2-5 year paybacks, and engage demand response programs for additional revenue opportunities. Strategic energy procurement accounting for 4CP methodology selection among retail providers can provide incremental 5-15% cost savings beyond operational improvements.