ComEd Business Rate Classes Explained: BES GS vs Hourly (2025)

ComEd General Service (GS) schedules serve most commercial and light industrial accounts under 100 kW to several megawatts, billed on monthly peak demand plus energy. Business Electric Service (BES) targets larger loads with higher utilization—often three-shift manufacturing, cold storage, or data halls—where delivery tariff designers assume more stable demand and offer different demand charge curves. Hourly pricing (HR) and real-time pricing (RTP) expose the account to ComEd's hourly energy delivery components, which can reward curtailment but punish facilities that cannot shift process loads.

Load Factor as the Primary Selector

Load factor—average kW divided by peak kW—signals whether GS or BES economics win. Illinois facilities above 0.55 load factor with sustained overnight baseload (refrigeration, servers, continuous process) frequently benefit from BES review. Facilities below 0.45 with sharp daytime peaks (offices, schools, batch production) often remain better served on GS unless hourly curtailment is operationalized. A Schaumburg flex warehouse running one shift weekdays may peak at 400 kW while averaging 120 kW (LF 0.30); a Bolingbrook food processor on three shifts might peak at 900 kW averaging 650 kW (LF 0.72)—same collar county, opposite rate-class math.

Operating hours matter as much as nameplate demand. ComEd's hourly classes tie delivery energy charges to system peak hours; a facility that can shed 15% of load during top 100 PJM hours may outperform fixed GS delivery. Conversely, a hospital or cold chain operator that cannot curtail without risk should not accept hourly delivery exposure for a modest supplier discount. Review ComEd published rate schedules alongside 12 months of interval data—not monthly kWh summaries.

• Pull 12–24 months Green Button or ComEd interval data before any class change study.
• Segment peaks by cause: HVAC, production, refrigeration, EV charging.
• Model GS vs BES on identical peak months including ratchet carryforward.
• Confirm voltage service level—secondary vs primary affects eligible schedules.

High-voltage customers (primary service above 69 kV or dedicated substations) access alternative delivery schedules with different demand determinants. Multi-site portfolios should not assume one rate class fits all locations; a demand charge primer helps finance teams translate kW into dollars by schedule. ComEd's 2025 rate design continues to separate customer charge, standard metering charge, and distribution demand—each line responds differently to class changes.

Facilities evaluating electrification—heat pumps, EV fleets, battery storage—should model future load factor before locking a schedule for five years. A GS office that becomes a 24/7 micro-fulfillment hub may cross BES thresholds within one lease cycle. Engage your energy advisor during CapEx planning, not after the utility assigns a default schedule based on historical peaks alone.

Chicago-area food processors evaluating BES often discover that blast-chiller startups at shift change—not production lines—set peaks. Interval forensics separating motor inrush from sustained kW helps engineers propose staggered chiller sequences that improve load factor without capital. ComEd account representatives can confirm which schedule IDs apply to secondary service above 400 kW; do not rely on billing summaries alone when comparing GS-versus-BES demand charge stacks line by line.

ComEd demand ratchets set a floor on billed kW for delivery charges even when actual monthly peaks drop. After a facility sets a new summer peak—often June through September—the tariff may require billing demand equal to 80%, 90%, or 100% of that peak for the next several months or until a new maximum is established. One heat-wave week when chillers and production overlapped can inflate delivery bills through the following spring.

How Ratchets Flow Through Your Bill

Billing demand drives the largest line item on many ComEd commercial invoices: delivery demand charge ($/kW-month) multiplied by ratcheted kW. Energy charges ($/kWh) scale with usage but rarely dominate for low load-factor buildings. Minimum billing provisions add another layer—some schedules bill a minimum kW or minimum monthly charge regardless of temporary curtailment. Facilities that tested demand response during one month may not see proportional savings if the ratchet month already locked a higher floor.

Minimum billing impacts appear quietly on reconciliations. Accounts with power factor penalties, customer charges, and municipal taxes still pay fixed components when production pauses. Seasonal manufacturers—outdoor equipment, packaging before holidays—should model off-season months explicitly. The ICC electricity rate database publishes tariff sheets where ratchet percentages and lookback windows are defined by schedule line item.

Mitigation Before the Peak Season

Ratchet mitigation starts in April, not August. Stagger equipment startups, pre-cool thermal mass before 1 p.m., shed non-critical loads during ComEd system peaks, and verify capacitor banks for power factor. Battery peak shaving helps delivery peaks only if interconnection agreements and tariff rules credit storage dispatch correctly—many Illinois projects still face review delays. Pair operational tactics with a supply strategy that does not assume ratcheted kW will fall immediately after efficiency projects.

1. 1Identify ratchet lookback months in your active schedule (typically prior summer peak).
2. 2Calculate dollar impact of 50 kW ratchet reduction—often $9,600–$10,800/year delivery alone.
3. 3Schedule capital projects (VFDs, staging controls) before May peak season.
4. 4Re-run class comparison after one full year of post-project interval data.

Finance teams budgeting 2026 should carry forward 2025 ratchet floors unless engineering confirms structural peak reduction. See our manufacturing sector guidance for shift-staggering patterns that Illinois plants use successfully. Property managers with master-metered retail should note that tenant expansion during summer can set portfolio-level ratchets that affect CAM reconciliations for years.

ComEd's 2025–2026 rate case proceedings may adjust ratchet percentages on certain GS subclasses—monitor ICC dockets if your billing demand seems disconnected from operational reality. Document every peak event with interval CSV exports; disputes require evidence, not anecdotes.

School districts and community colleges on GS schedules face ratchet pain when August cooling overlaps fall semester startup. Illinois public entities should model September billing demand before approving portable cooling for events. Tax-exempt accounts still pay delivery ratchets; procurement exemptions do not waive tariff mechanics. Document ratchet percentages from the active tariff rider each July when ComEd files updates with the ICC.

Changing ComEd rate class is not a checkbox on a supplier portal—it requires eligibility analysis, often a load study, customer request to ComEd, and ICC tariff compliance. Utilities may require 12 months of operating data at proposed load levels, transformer capacity verification, and fees for metering changes when moving to primary service or hourly metering.

Steps and Timeline

Typical timelines run 60–120 days for schedule changes within the same voltage level; primary service upgrades can exceed 12 months. Engineering firms charge $5,000–$25,000 for load studies modeling GS vs BES vs hourly scenarios with ratchets. Internal labor—facilities, accounting, energy advisor—adds coordination cost. Payback should exceed soft costs within 18 months unless the switch accompanies a major service upgrade already budgeted.

Payback example: a 750 kW BES candidate on GS pays an extra $4/kW-month delivery differential (~$36,000/year). Switching costs of $15,000 all-in yields sub-six-month payback if ratchets do not offset gains. A marginal 200 kW office with $8,000/year theoretical savings and $12,000 study plus metering cost fails payback—stay on GS and focus on supply. Use bill analyzer outputs to quantify schedule differentials with your actual ratchet history.

Common Rejection Reasons

ComEd may deny moves that increase cost allocation unfairness, lack adequate load factor, or require infrastructure not installed. Hourly schedule requests without demonstrated curtailment capability sometimes face scrutiny. Document a curtailment playbook before applying—PJM emergency events alone do not prove daily peak management.

• Engage ComEd account management early with interval plots and proposed schedule ID.
• Align class change effective date with supply contract start to avoid split analytics.
• Preserve copies of approval letters for billing dispute defense.
• Reconcile first three bills post-switch against modeled expectations.

Multi-site operators should sequence switches—pilots on one facility before portfolio rollout. Compare notes with peers in the ComEd rate case commentary when tariff revisions shift BES advantages. Legal counsel occasionally reviews lease pass-through language when landlord CAM pools include demand charges tied to historical rate classes.

Illinois Energy Advisors recommends a written decision memo for any class change: baseline bills, modeled future state, implementation costs, and rollback triggers if first-year savings miss targets by more than 15%. That discipline protects CFO sign-off and prevents operational teams from absorbing blame for tariff experiments that lacked executive sponsorship.

Tenant finish-out in multi-tenant industrial parks sometimes triggers service upgrades that reset metering—verify CT ratios after landlord work. A mis-sized transformer can produce billing peaks unrelated to tenant load until corrected. ComEd may allow schedule changes effective at meter upgrade dates; coordinate with landlords on pass-through lease language for demand charge increases tied to rate class moves initiated by anchor tenants.

Attorneys reviewing energy LOAs should confirm whether advisors model rate class changes as part of scope or only supply swaps. Scope gaps leave six-figure delivery savings unclaimed while suppliers compete on fractional cent differences.

Illinois market buyers in the 2025–2026 cycle should archive interval CSV exports, supplier LOAs, and utility tariff pages supporting Switching Rate Classes: Process Costs & decisions. Regulatory updates from the ICC and Comed filings can shift delivery determinants between budget seasons—schedule semiannual reviews with your energy advisor.

Retail supply contracts and ComEd delivery schedules interact but are procured separately. A brilliant fixed-price supply deal built on inflated peak kW overpays capacity pass-throughs; optimizing delivery ratchets first lowers the kW anchor suppliers use in RFP pricing. Illinois licensed suppliers receive aggregate load data; providing corrected forward peaks after rate-class change improves bid competitiveness.

Sequencing the Work

Best practice: (1) analyze interval data and ratchets, (2) implement operational peak reduction, (3) finalize rate class or hourly strategy, (4) issue supply RFP with updated load shape, (5) align contract start with new billing determinants. Reversing steps—signing 36-month fixed supply before a planned BES switch—locks capacity charges on obsolete peaks unless pass-through clauses allow true-up.

Block-and-index supply structures pair with partial hourly exposure for sophisticated loads. Fixed all-in suits low load-factor sites needing budget certainty. Cultivation, cold storage, and data centers each warrant different pairings—reference warehousing and industry-specific guides when stress-testing options.

Monitor PJM market operations for capacity auction results affecting 2025–2026 supply adders. Pair results with ComEd tariff effective dates from the ICC. Transparent advisors document margin separately from pass-throughs—see broker guide before signing LOA.

1. 1Complete delivery optimization and wait one billing cycle for ratchet confirmation.
2. 2Issue supply RFP with updated peak, LF, and schedule ID.
3. 3Compare offers on total $/year including known pass-throughs.
4. 4Set contract start date after rate-class effective billing month.
5. 5Schedule annual revalidation—automation projects change LF quickly.

Portfolio owners with both ComEd and Ameren sites should not assume identical sequencing—downstate tariffs differ—but the principle holds: delivery determinants first, supply second. Cross-reference our rate class explainer when briefing boards that conflate supplier switching with tariff optimization.

Creditworthiness and deposit requirements on supply contracts sometimes rise when interval data shows volatile peaks—even after rate class optimization. Suppliers interpret peak volatility as risk. Present post-optimization interval files and ratchet-adjusted billing demand forecasts in RFP cover letters to avoid unnecessary deposits.

Illinois manufacturers exporting to weak-currency markets need budget certainty; pairing BES delivery with 24–36 month fixed supply remains popular despite index market dips. Revisit annually—automation and EV loads change the optimal pairing faster than contract lengths.

Illinois market buyers in the 2025–2026 cycle should archive interval CSV exports, supplier LOAs, and utility tariff pages supporting Pairing Rate Optimization with Supply Co decisions. Regulatory updates from the ICC and Comed filings can shift delivery determinants between budget seasons—schedule semiannual reviews with your energy advisor.

Illinois market buyers in the 2025–2026 cycle should archive interval CSV exports, supplier LOAs, and utility tariff pages supporting Pairing Rate Optimization with Supply Co decisions. Regulatory updates from the ICC and Comed filings can shift delivery determinants between budget seasons—schedule semiannual reviews with your energy advisor.

Illinois market buyers in the 2025–2026 cycle should archive interval CSV exports, supplier LOAs, and utility tariff pages supporting Pairing Rate Optimization with Supply Co decisions. Regulatory updates from the ICC and Comed filings can shift delivery determinants between budget seasons—schedule semiannual reviews with your energy advisor.