ComEd Demand Charges and Battery Payback: The Worked Guide for Illinois Businesses (2026)

PJM capacity prices have cleared at the FERC-approved cap in each of the last two auctions, and that cost reaches Illinois commercial bills through a charge most facility teams have never itemized. A battery sized against that reality either attacks real money or it quietly loses it, and the difference is the facility's own load shape. This guide works through the actual math.

Fast Facts

• The three charges that matter: Energy ($/kWh), the Distribution Facilities Charge or DFC ($/kW of billing demand), and PJM capacity, the charge tied to five hours ComEd and PJM will not tell you about in advance.
• Current PJM capacity price, ComEd zone: $329.17 per MW-day for the 2026/27 Delivery Year, in effect now, rising to $333.44 per MW-day for 2027/28. Both cleared at the FERC-approved price cap.
• The storage rebate: ComEd's Rider DG Rebate pays $250 per kWh of paired battery storage for large commercial and industrial customers, on top of the demand-charge and capacity savings a battery can produce, and Public Act 104-0477 extends eligibility to standalone storage effective June 1, 2026.
• The one-sentence verdict: A battery's payback is decided by the facility's load shape, not by the sales pitch. A peaky, multi-shift load with a real gap between average and maximum demand can capture real money. A flat, continuous load mostly cannot.
• Primary sources: ComEd's nonresidential rate summary (comed.com), PJM's 2027/2028 Base Residual Auction report (pjm.com), the Illinois Commerce Commission's Plug In Illinois page, ComEd's Rider DG Rebate terms, and NREL's 2024 Annual Technology Baseline.

Read your ComEd bill before you size anything

ComEd separates every nonresidential bill into Delivery Services, the wires and infrastructure charges ComEd itself controls, and Electricity Supply Services, the energy and PJM-related charges tied to whatever supply arrangement the customer has chosen. Delivery includes the Distribution Facilities Charge, the customer charge, and the metering charge. Supply includes the energy rate and, for most commercial accounts, a capacity charge that rides on top of it. ComEd-supplied accounts with at least 100 kW of load generally receive hourly-varying supply prices under Rate BESH, while a competitive supply contract or an eligible fixed-price tariff can set different terms, which is the detail that determines whether energy arbitrage is even available. (comed.com, nonresidential line item summary)

• Energy ($/kWh): The price per kilowatt-hour actually consumed. ComEd's own summer 2026 Price to Compare, the default supply benchmark, is 10.399 cents per kWh (8.677 cents supply plus 1.722 cents transmission), effective June 1 through September 30, 2026. That figure is the fixed-price comparison benchmark, not the assumed supply rate for a large interval-billed account. (Plug In Illinois, ICC)
• Billing demand ($/kW), the DFC: A charge on the highest 30-minute demand recorded in the monthly billing period, at a rate that varies by delivery class and voltage level. For the main commercial classes it runs roughly $11 to $13 per kW at secondary voltage and $5.75 to $10.25 per kW at primary voltage. This is the charge a battery targets first.
• Capacity ($/kW-month or $/MW-day): A separate charge tied to the customer's share of PJM's five annual system peak hours, priced off the ComEd zone's cleared capacity price for the delivery year. It rides on the supply side of the bill: hourly-pricing customers see it as its own capacity line, while fixed-price and many competitive-supply customers pay it inside the supply charge. It is also climbing: the ComEd zone cleared at the FERC-approved price cap in each of the last two capacity auctions.

How your demand charge is actually set

ComEd measures billing demand as the Maximum Kilowatts Delivered, or MKD: the single highest 30-minute demand interval recorded anywhere in the monthly billing period, with many delivery classes measured within a weekday daytime window, a detail GEC confirms from the account's own tariff terms. One bad half hour sets the whole month's DFC charge, which is exactly what makes a battery's job simple in concept: shave that one interval and the charge drops for the entire month. Billing demand resets each period per the tariff's measured-demand definition. GEC confirms the specifics for your delivery class during the engineering screen, since some utilities apply a ratchet that carries a prior peak forward and ComEd's own published materials are the source of record for whether and how that applies to your account.

High Voltage delivery (69 kV and above) uses a different charge structure, with separate high-voltage facilities and transformer charges, so it is not shown in this table.

This is the DFC table read directly from ComEd's own delivery-charge guide, the latest version ComEd publishes as of this writing. These are the resultant billed charges beginning with the January 2026 bill. Delivery rates move through Illinois Commerce Commission proceedings, so GEC pulls the facility's current class rate from the live tariff during every engineering screen. The table is also the reason a single flat number is always wrong. A facility in the Large Load class, 400 to 1,000 kW of demand, the class most commercial and light-industrial accounts fall into, pays $10.10 per kW at primary voltage service or $12.84 per kW at secondary voltage, a real spread depending on how the facility is served. A representative Large Load facility at 500 kW of billing demand, served at secondary voltage and doing nothing to manage its peak, pays roughly 500 kW times $12.84, or about $6,420 in DFC charges that month, before demand response of any kind. (comed.com, delivery-charge guide, January 2026)

The capacity tag: the charge you set in five afternoons

PJM identifies the five highest non-holiday weekday hourly system peaks between June 1 and September 30 each year, the '5 Coincident Peaks' or 5CP. A customer's average demand across those five specific hours becomes its Peak Load Contribution, or PLC, the 'capacity tag' that sets that customer's share of PJM capacity cost for the delivery year beginning the following June 1. PJM identifies the five hours after the summer ends, generally publishing them in the fall, months after the fact, which means no one dispatches a battery against a known schedule. They dispatch against a forecast, and a wrong forecast forfeits that hour's contribution entirely. (PJM, PLC and NSPL education presentation)

One layer of precision matters here. For a ComEd account the final capacity obligation is computed under the governing tariff attachment, which uses the customer's load across the five PJM system peaks plus ComEd's own five zone peaks, applies loss adjustments, and scales the result across the zone. A battery's reduction during the five PJM hours is the main input, not automatically a one-for-one cut in the final tag. GEC models the full calculation during the engineering screen.

The price behind that tag is at the ceiling. PJM's capacity clearing price for the ComEd zone (part of 'Rest of RTO,' with no locational adder) is $329.17 per MW-day for the 2026/27 Delivery Year, in effect now through May 2027, cleared at the FERC-approved price cap. The 2027/28 Delivery Year cleared at $333.44 per MW-day, again at the cap, in an auction PJM's own no-cap simulation suggests would have cleared closer to $529.80 per MW-day without the collar. Illinois is also about to add real supply behind that number: the Illinois Power Agency's first-ever utility-scale storage procurement, targeting 1,038 MW total including 588 MW in the PJM ComEd Area, is scheduled for August 26, 2026, under a 20-year Indexed Storage Credit contract structure. (PJM, 2027/2028 Base Residual Auction report and Illinois Power Agency, energy storage procurement)

That table is arithmetic on the published clearing price (kW reduced, converted to MW, times the daily price, times 365 days), not a modeled estimate. It is also why the capacity tag is the highest-dollar-per-kW stream a battery can chase, and the least predictable. Get the five hours right and the value in that table is the gross ceiling. Miss one, and in this simplified arithmetic the average across the remaining four hours falls short of it.

What a battery can and cannot do about each charge

Four separate value streams exist for a C&I battery in ComEd territory, and they should never be blended into one number. Each has its own mechanism, its own predictability, and its own honest constraint.

The worked example: a 500 kW manufacturer

This is a representative example built to show the mechanics, not a documented facility. No primary source gives a single 'typical' Illinois manufacturing load profile, so every number below is illustrative, clearly labeled, and built from the rates and prices sourced above rather than invented savings claims.

The facility: a 500 kW peak, Large Load delivery class, secondary voltage service. The battery: 350 kW of power and 700 kWh of energy, a 2-hour duration system sized to sustain a meaningful shave through a full 30-minute billing interval or a full PJM coincident-peak hour with room to spare. At 85 percent, the representative round-trip efficiency in NREL's 2024 Annual Technology Baseline, replenishing a full 700 kWh discharge requires drawing roughly 824 kWh from the grid (700 divided by 0.85), the loss every dispatch carries. (NREL, 2024 Annual Technology Baseline)

One summer dispatch day: on a July weekday, the facility's demand climbs toward its 500 kW peak in the early afternoon. The battery, already charged overnight during low-price hours, discharges at 250 kW for the 30-minute interval most likely to set the month's MKD, holding the metered peak to 250 kW. If that same afternoon happens to fall inside one of PJM's five coincident-peak hours (only knowable for certain months later), the same 250 kW of held-back demand also reduces the facility's contribution to next year's capacity tag. One dispatch, two value streams, if the timing lines up.

• Base case, DFC reduction: A 250 kW monthly shave at the Large Load class rate runs $2,525.00 per month at primary voltage ($10.10/kW) to $3,210.00 per month at secondary voltage ($12.84/kW), or roughly $30,300 to $38,520 per year if sustained across all 12 billing periods.
• Base case, capacity-tag reduction: A 250 kW PLC reduction, if the battery discharges through all five PJM coincident-peak hours, is worth $30,037 per year at the 2026/27 clearing price of $329.17 per MW-day (rising toward $30,426 at the 2027/28 price of $333.44 per MW-day).
• Downside case, missed one 5CP afternoon: In the simplified five-hour arithmetic, if the battery misses one of the five hours (a wrong forecast, a prior discharge that left it empty), the average reduction across the remaining four hours falls to 200 kW, and the capacity-tag value drops to roughly $24,029 per year at the 2026/27 price, a difference of about $6,000 for missing a single afternoon.
• Energy arbitrage: Not modeled with a single figure here. PJM caps the real-time hourly energy price at $3.70 per kWh, the outer bound on any single spread, not a typical one. Realized arbitrage value depends on the facility's actual daily price volatility under Rate BESH or Rider PPO and the roughly 15 percent round-trip loss on every cycle. GEC models this stream against the facility's real interval and hourly-price data, not a representative number.
• Rider DG Rebate, one-time: A 700 kWh battery earns $250 per kWh, or $175,000, paid once after approval. A facility whose meter sits in the statute's pre-2025 net-metering cohort can qualify at $300 per kWh, or $210,000, through December 31, 2029. Which rate applies is a cohort question GEC settles during the screen, and this example carries the conservative $175,000.
• Upside case: All five 5CP hours captured and the DFC shave held every month at the secondary-voltage rate: roughly $38,520 a year in DFC savings, $30,037 a year in capacity-tag value, and a separate $175,000 one-time rebate check in year one, tracked as three distinct lines, not a combined figure. Arbitrage and any demand-response enrollment sit outside this tally entirely.

Every figure above is a representative example built on sourced rates, not a projection for any real facility. GEC runs this same math against a facility's actual 12 months of ComEd bills and interval data during the engineering screen, which is the only way to know whether a specific load shape produces this kind of result.

Solar-only, battery-only, or both

The right combination follows the facility's load shape, not a default. Solar offsets energy consumption during daylight hours and does nothing for a demand charge unless the facility's peak happens to land when the sun is producing, or unless it is paired with storage. A battery targets the DFC and the capacity tag directly, on its own schedule, regardless of what the sun is doing.

• Single-shift, daytime-only operation: Peak demand tends to land during production hours, which is also when solar is producing. Solar alone captures real energy savings here, and a battery adds demand-charge and capacity-tag value on top.
• Two-shift operation: Peaks extend into the evening, past solar's production window. A battery becomes the primary lever for the DFC and capacity charges, charged from solar or the grid during the cheaper hours and discharged against the facility's actual peak.
• Continuous, 24-7 operation: A flat, high-load-factor profile has a smaller gap between average and maximum demand, which means less peak for a battery to shave in the first place. This is exactly the profile covered in the honest-limits section below.

When a battery will not pay back

This section exists because the honest answer sometimes is no. A battery's economics depend entirely on the gap between a facility's average demand and its maximum demand, and on how reliably that gap can be captured.

• Flat, low-variability load profiles: A facility that runs close to the same demand around the clock has little peak to shave. If the highest 30-minute interval is barely above the average, a battery has almost nothing to cut against the DFC.
• Low load factor claims cut both ways: A low load factor (a big gap between average and peak demand) is actually the profile that favors a battery, since there is real peak to shave. A high load factor, close to continuous full-load operation, is the profile where the math gets hard.
• Missed dispatch on the 5CP hours: Because PJM's five coincident-peak hours are unknown in advance and only published after the summer ends, generally in the fall, a battery dispatched on the wrong hours captures none of the capacity-tag value for that year, no matter how well it performed on every other hour.
• Round-trip losses are real, every cycle: 85 percent is the representative round-trip efficiency in NREL's 2024 Annual Technology Baseline. Every kWh discharged costs roughly 1.18 kWh charged. That loss has to be smaller than the value captured, or the stream is a net cost.
• The rebate now reaches standalone storage, with strings attached: Public Act 104-0477, effective June 1, 2026, extends the storage rebate to standalone batteries. It also adds statutory caps and requires post-Act recipients to participate in a qualifying utility program, and ComEd's implementing tariff is still pending. A project counting on the rebate needs its cohort, cap, and program obligations confirmed first.

None of this is a reason to skip the analysis. It is a reason to run the actual numbers before committing capital, which is what the engineering screen at the end of this guide is for.

The incentive layer

A battery's payback does not rest on demand-charge and capacity math alone. ComEd's Rider DG Rebate pays $250 per kWh of paired storage for large commercial and industrial customers, currently unchanged, and it combines with the federal Investment Tax Credit at 30 percent, a rate that assumes the prevailing-wage and apprenticeship requirements GEC manages on every project, rising to 40 percent where the facility's address qualifies as an Energy Community, which the current IRS lists make true for most of Illinois and which is always verified at the specific address. Each layer is captured and disclosed on its own line, never rolled into a single stacked percentage. The full rebate mechanics live in the ComEd Battery Storage and DG Rebate guide, and the federal credit math lives in the Energy Community bonus guide. The full Illinois picture, incentive by incentive, is on the Incentives and Safe Harbor pillar.

Three regulatory developments from July 2026 are worth knowing, without over-reading any of them. A trailer bill to the Clean and Reliable Grid Affordability Act became Public Act 104-0477 on June 26, 2026, with a stated effective date of June 1, 2026, and it reshapes the distributed-storage rebate: standalone storage becomes eligible at $250 per kWh, systems behind pre-2025 net-metering-cohort meters qualify at $300 per kWh through 2029, new statutory caps apply, and post-Act recipients must enroll in a qualifying utility program. ComEd's conforming tariff filing implements the details. (Public Act 104-0477) ComEd's Scheduled Dispatch Virtual Power Plant, Rider SDVPP, was filed June 1, 2026 with tariff sheets dated effective July 16, 2026, and program service begins no later than March 1, 2027. The filed incentive is $10 per kW-season, subject to the tariff's dispatch terms. (ComEd Rider SDVPP filing, ICC) And the Illinois Power Agency's first utility-scale storage procurement, covering 588 MW in the PJM ComEd Area, is scheduled for August 26, 2026. None of these change the math worked through above. They are the direction the market is moving, and GEC tracks the final terms as each one is published.