ComEd Time-of-Use & Real-Time Pricing for Illinois Businesses

Fixed supply contracts lock $/kWh (plus defined pass-throughs) for 12–36 months—simple budgeting, no hourly volatility. ComEd hourly pricing passes PJM day-ahead or real-time energy costs through delivery and/or supply components depending on enrollment. Savings emerge when your load concentrates in low-LMP hours and avoids system peaks.

Candidates for hourly pricing often include cold storage with thermal mass, wastewater plants with storage, EV fleet depots charging overnight, and campuses with EMS-controlled HVAC pre-cooling. Poor candidates: data centers with flat 24/7 critical load, surgery centers, and plants where production windows are inflexible.

Review ComEd tariff documents and rate information for current BES-H eligibility and riders.

PJM ComEd zone day-ahead LMP averaged volatile spreads in recent summers—office buildings without shift capability saw hourly pricing premiums versus fixed supply, while refrigerated warehouses saved when pre-cooling overnight captured negative or near-zero off-peak intervals. Your zonal location within ComEd territory matters less than your ability to move kWh temporally.

Retail suppliers may offer indexed supply mirroring hourly pricing while delivery remains standard—compare fully bundled utility hourly programs versus split structures. Split structures add complexity but sometimes improve supplier competition on margin.

ComEd published rate comparisons for business classes updated through 2025—download current tariff book sections for BES and BES-H before board presentations rather than citing outdated cents-per-kWh summaries from vendor decks.

Pass-through charges for transmission and ancillary services still apply under hourly pricing—model complete bill, not energy-only LMP differential.

Energy intensive users considering ComEd economic development rates should compare against hourly pricing separately—EDR discounts may not stack with BES-H benefits.

ComEd business customers evaluating RTP should download historical LMP for their zone from PJM Data Miner and join with Green Button interval data in Excel or advisor tools—summary statistics without hourly join misstate savings by double digits.

Tax-exempt entities may have different risk tolerance for budget variance—school districts often reject RTP despite technical savings potential because bond covenant budget certainty outweighs opportunistic energy cost reduction.

Industrial customers with power factor penalties should correct PF before RTP enrollment—reactive power charges obscure hourly energy savings in bill variance analysis.

PJM summer peak definitions expanded in recent planning—model RTP with updated peak hour calendars, not legacy four-hour assumptions alone.

Compare RTP against block-and-index supply using identical weather years— cross-product comparisons prevent selecting wrong risk profile.

Include summer and winter weeks separately in RTP stress tests—Illinois LMP tail risk differs seasonally and single-season models mislead year-round enrollments.

Peak shaving targets both kW demand charges and high-LMP energy hours. Manufacturing sites shift non-critical processes—batch mixing, curing, parts washing—to evenings when LMP historically dips. Warehouses delay battery charging, AS/RS staging, and compressors using EMS schedules tied to day-ahead prices.

Manufacturing Tactics

• Publish internal 'red hours' when LMP forecasts exceed threshold—pause discretionary loads.
• Pre-cool buildings 6–8 AM before commercial peak LMP windows.
• Align heavy startup sequences across lines to avoid simultaneous inrush.
• Enroll in ComEd demand response for capacity payments stacking with HP savings.

Warehouse & Logistics Tactics

Distribution centers with automated sortation draw high kW in short bursts. Stagger pick waves and charger schedules using WMS integration. Cold storage facilities pre-freeze product mass when overnight LMP is negative or near zero—a strategy that paid off in mild shoulder months on PJM.

Plastic injection molding and metal stamping facilities with short cycle equipment may have less shift flexibility than assembly lines—map machine-level schedules before promising production managers RTP enrollment won't affect throughput. Pilot one line or one shift before campus-wide automation rules deploy.

ComEd business demand response payments stack with hourly savings if curtailment events align with high LMP—verify program rules avoid double-counting forbidden load reductions.

Food processing plants with sanitation cycles requiring hot water at fixed times face harder shift flexibility—prioritize refrigeration and compressed air for curtailment instead of CIP processes.

Office buildings with pre-COVID peak profiles may misforecast RTP value if hybrid work reduced peak kW but concentrated remaining load in narrower hours.

Microgrids with island capability may still benefit from hourly pricing when grid-connected—model both interconnected and island modes if considering dual operational states.

Cold storage operators in Illinois logistics corridors pre-cool product mass when day-ahead LMP forecasts below $20/MWh—thermal inertia carries through high-price afternoon windows without product integrity loss when monitored continuously.

Metal fabricators with shift-based arc furnace schedules may have less flexibility than assumed—production planning systems need integration hooks before automating furnace delay based on LMP signals.

Plastics extrusion lines with thermal soak requirements may shift start times only within narrow process windows—pilot one line before portfolio-wide RTP automation rules.

Exporting facilities with solar should simulate hourly pricing with on-site generation hourly profiles—net grid draw differs from gross load curves.

O'Hare corridor logistics facilities with refrigeration should model RTP against diesel backup generator costs during curtailment events— total cost of curtail includes product integrity risk.

Reprice hourly savings annually against realized LMP rather than forward curves alone.

Share RTP performance results with your ComEd account team annually—they may flag tariff options or demand response programs that complement hourly pricing structures.

Maintaining a twelve-month rolling forecast of utility spend helps Illinois leadership teams spot contract expiration, rate class opportunities, and rebate deadlines before they become urgent crises requiring rushed decisions.

Manual peak calls fail when plant managers prioritize production over energy emails. Automation links ISO price feeds, ComEd alerts, and BAS/SCADA setpoint adjustments with guardrails—never shutting critical process loads without override.

1. 1Integrate day-ahead LMP API with BAS ( BACnet / Modbus ) for pre-cooling scripts.
2. 2Set two-tier thresholds: advisory (operator choice) and automatic (non-critical loads).
3. 3Log every curtailment event with kW and $ impact for continuous improvement.
4. 4Test failover so automation never violates food safety or cleanroom specs.

Third-party energy management software vendors serve Illinois manufacturing; vet cybersecurity on OT networks. ComEd demand response programs provide another automation layer with defined event payments.

Cybersecurity review is essential when connecting price feeds to BAS—NERC CIP doesn't apply to most commercial sites but ransomware targets OT bridges. Use read-only price APIs and one-way data diodes where security teams require them.

Maintain manual override protocols documented in operations binders—automation failures during heat waves should not leave facilities without cooling because price scripts error out.

Start pilots on non-production circuits—lighting and parking garage ventilation respond safely to price signals while production lines remain manual override.

Integrate ComEd day-ahead price emails with existing maintenance ticketing so facilities staff see price context alongside HVAC work orders.

Union agreements may restrict automated load shifts affecting production line staffing—review CBAs before deploying price-responsive controls on covered equipment.

Facilities teams should receive LMP forecast dashboards in same portals as work orders—context increases compliance with voluntary curtailment compared to email-only alerts ignored during busy shifts.

Backup generators used for demand response must comply with EPA non-emergency run hour limits—coordinate DR enrollment with environmental permits before counting standby gen as curtailable load.

Cloud-based BAS integrations with ComEd price feeds should include offline fallback schedules—internet outages during heat waves should not leave systems in undefined control states.

Union overtime rules may limit load shift windows— validate CBAs before automating production changes tied to LMP forecasts.

ComEd business account managers can confirm BES-H eligibility prerequisites— voltage and demand thresholds exclude some smaller accounts from hourly delivery options.

Document each curtailment event with kW, duration, and dollar impact for continuous improvement reviews with operations leadership.

Peer facilities in the same utility territory often share benchmarking data through industry associations—compare your normalized $/kWh or $/therm privately to validate whether procurement or efficiency should lead the next budget cycle.

The only acceptable RTP/Hourly pricing business case uses your 12-month interval kW and kWh data repriced against historical LMP at your ComEd zone. Aggregate statistics from other sites mislead—your load shape is the product.

Modeling Steps

1. 1Download 12 months interval data from ComEd MyAccount or Green Button.
2. 2Obtain historical LMP for ComEd zone (PJM data miner or advisor tools).
3. 3Apply proposed tariff delivery energy charges hour by hour.
4. 4Add retail supply margin if supply remains fixed separately.
5. 5Compare total $ to actual fixed contract or counterfactual fixed quote.
6. 6Stress-test July and January weeks separately—tail risk matters.

Our broker guide explains transparent fee models for advisors running these simulations. Pair results with block-and-index supply hybrids if full RTP exposure feels aggressive—lock 70% fixed, float 30% indexed.

Advisors should deliver RTP models with transparent hourly spreadsheets—not summary slides—so CFOs audit formulas linking interval kWh to LMP. Question models assuming perfect load shift; use 10%, 15%, and 20% shift scenarios as brackets.

Re-model annually; load shape changes from expansion or efficiency alter hourly suitability. A 2023 RTP winner may become a loser after adding 24/7 automation equipment in 2025.

Export interval reprice results to CSV for auditors—transparency builds internal trust when operations asks why loads shifted on specific dates.

Compare RTP savings to demand charge reduction projects separately—combined ROI may justify automation CapEx even when RTP alone shows marginal benefit.

Third-party verified savings reports strengthen internal RTP approval—consider independent engineering review for investments over $100k in controls automation tied to hourly pricing.

Sensitivity analysis should include ComEd delivery rate changes approved by ICC separately from LMP—delivery increases can offset RTP energy savings in outer years of multi-year comparisons.

Hybrid supply products fixing 70–80% of volume while indexing remainder offer middle ground—model hybrid against pure RTP and pure fixed using identical interval dataset for board-ready comparison.

Present RTP business cases with three-year rolling repricing—not single historical year—to capture weather and LMP regime diversity Illinois experienced 2022 through 2025.

ComEd real-time pricing notifications via SMS reach field staff faster than email during heat events— redundancy improves curtailment compliance.

Joliet and Aurora manufacturers on ComEd should compare RTP savings against real estate expansion plans—new lines may flatten load factor unfavorably for hourly tariffs.

Pilot RTP on one facility before portfolio rollout—Illinois multi-site operators learn operational constraints cheaply on a single ComEd account.

Illinois buyers who calendar contract notice dates, exemption renewals, and rebate deadlines in one place reduce last-minute renewals at unfavorable rates.