AEC Market Education Module #13
Demand Charge Management
The kW side of a Texas commercial electric bill — how demand charges work, where they live on the bill, and what actually moves them.
Most discussion of electricity pricing focuses on the energy charge: cents per kWh, twelve or twenty-four months fixed, the headline number on the contract. The other half of the bill is measured in kilowatts. It moves on different rules, reacts to different choices, and at most commercial sites it accounts for between a fifth and a third of the total spend.
Quantity-based. You pay for every unit of energy you consume across the month. A kWh is a unit of energy: one kilowatt drawn for one hour, or two kilowatts drawn for a half hour, or any other equivalent combination.
Capacity-based. You pay for the high water mark — the single highest fifteen-minute slice of the month — regardless of how often that level was reached. Bringing the high water mark down by 50 kW saves the same amount whether it stood for one hour or one quarter-hour.
The two charges measure different things. Energy is what came through the meter. Demand is how big the pipe had to be to deliver it. The utility built the pipe — substations, transformers, conductors, transmission lines — for the worst case, and the demand charge is how that fixed cost gets recovered from each customer in proportion to the load they imposed at the worst moment.
For a flat load running close to its average all month, the demand charge spreads thinly across thousands of kWh. For a peaky load that briefly spikes well above its average, the same demand charge concentrates on a much smaller energy base. That is the mathematical link to load factor, and it is why the same TDU tariff produces wildly different per-kWh outcomes for two facilities that consume the same total energy. The load factor module works through that math directly.
On a Texas commercial bill, the kW-driven charges sit on the regulated delivery side, billed by your TDU and passed through by your retail provider. The line items vary by utility and rate class, but they roll up into three buckets: a flat monthly amount (customer plus metering), a per-kWh component that bundles a few small energy-based items, and the per-kW demand charges that drive most of the conversation in this module.
Current TDU charges across the major Texas territories, commercial > 10 kW class:
| TDU | Per month | Per kWh | Per kW |
|---|---|---|---|
| Oncor | $32.43 | 0.055¢ | $11.27 |
| CenterPoint Energy | $13.41 | 0.093¢ | $10.10 |
| AEP Texas Central | $22.00 | 0.074¢ | $12.79 |
| AEP Texas North | $22.00 | 0.074¢ | $12.38 |
| Texas-New Mexico Power | $24.56 | 0.156¢ | $14.98 |
| Lubbock Power & Light | — | 1.631¢ | $11.32 |
Total kW exposure across the major TDUs runs $10 to $15 per kW per month. A site holding a 500 kW high water mark therefore carries roughly $5,000 to $7,500 per month in demand charges before any energy is metered. Bring that mark down by 10 percent and the saving is permanent and recurring — it shows up every month for as long as the new mark holds.
One additional effect to flag here: power factor. If your facility's power factor falls below 0.95, the TDU adjusts your billed kW upward to recover the cost of carrying reactive power your equipment draws but does not convert into useful work. The math means a metered 500 kW load running at 0.85 PF gets billed closer to 558 kW. Capacitor banks and variable-frequency drives are the standard remediation. We will cover the specifics — measurement, threshold variations by TDU, and the economics of correction — on a forthcoming power factor module.
The TDU meter integrates power continuously. Once every fifteen minutes it logs the average kW drawn during that window and resets. Each month produces 2,880 such intervals (give or take, depending on month length). Your billing demand is the single highest one.
Interval data — the underlying record of every fifteen-minute reading the meter produced — is available for any IDR-metered site through Smart Meter Texas. The interval data module covers how to pull and read it. For demand-charge work, that file is the diagnostic. It tells you which day, which hour, and which equipment cycle is setting your bill.
Some TDU rate classes carry a provision called a demand ratchet. Under a ratchet, your billing demand for any given month cannot fall below a stated percentage of your high water mark across the prior eleven months. A typical ratchet sets the floor at 80 percent of that rolling mark.
The mechanism exists because the utility sized your service drop, transformer, and feeder capacity for your worst-case demand. Ratchets ensure they recover that fixed investment year-round, even during months when actual load runs well below the design point. From a customer's perspective, the ratchet means a single bad summer afternoon can keep your billing floor elevated through the following winter, spring, and into the next summer.
A facility runs a steady 350 kW most of the year. On July 14, an unusual confluence — late afternoon production push, full chiller load, an unscheduled compressor cycle — drives a single fifteen-minute window to 600 kW. That month bills at 600.
From August through the following June, even months where actual peak comes in at 320 or 360 kW will be billed at 480. At an all-in demand rate of $11 per kW, that floor adds up:
The single July incident extends well beyond the July bill. The high water mark is set, and it refuses to recede for eleven more months.
Not every TDU rate schedule includes a ratchet, and where they exist the percentage and the lookback window vary. Oncor's primary-service rate classes carry one form; CenterPoint's industrial schedules carry another; some secondary-service tariffs do not ratchet at all. The first place to look is your tariff schedule on file with the PUC, or the demand-charge calculation footnote on a recent bill. If the bill shows a "billed demand" that is higher than your actual metered peak for the month, a ratchet is the most common explanation.
Run the math on your own high water mark. Enter your current billing demand, your blended demand rate (the typical Texas commercial range is $10 to $15 per kW depending on TDU), and a target reduction. The calculator returns the direct monthly and annual savings, plus the carryover effect if you are on a ratcheted tariff.
Demand reduction breaks into three buckets: operational discipline (free), controls and automation (low capital), and physical infrastructure (capital projects with payback math). The right starting point depends on what is driving your current peak. Interval data tells you which lever to pull first.
Bringing your own high water mark down saves money on your own bill. Demand response flips the model: the utility pays you for the right to call on your load reduction during specific events. Same operational capability, different counterparty, different cash flow.
These programs are structured under PUCT energy efficiency rules and run during defined seasonal windows — winter for the cold-weather peak risk that surfaced after Storm Uri, and summer for the traditional heat-driven afternoon peaks. The basic structure is consistent: enroll a curtailable load, accept short-notice call events from the utility, deliver the contracted reduction during each event, and collect a per-kW incentive payment based on verified performance.
Designed as a load-shedding resource that helps Oncor avoid rolling outages during winter grid emergencies. Events are called when ERCOT anticipates or enters an Energy Emergency Alert Level 2 — the stage immediately preceding the rotating blackouts of an EEA-3.
Verification runs through Oncor's AMI / IDR meter data — actual fifteen-minute usage compared against an established baseline, calculated using the lowest-performing event of the season. Realized performance below 90 percent of the contracted amount steps the multiplier down; below 50 percent and the contract pays at half rate.
Several categories of load are excluded by program rules: REPs whose contracts prohibit curtailment, customers taking transmission-voltage service for-profit, manufacturing customers who have opted out of the EECRF, and critical-load customers. The fit test happens during enrollment.
For a site already managing its own high water mark for billing reasons, CLM enrollment is usually additive. The same operational capability that flattens your demand curve is what the program is paying for. The decision comes down to event tolerance — whether your operation can accept a thirty-minute notification and the curtailment commitment without disrupting production or service.