Texas commercial electricity: ERCOT and choice

Step 1: find out whether your address can choose at all

Retail choice does not cover every Texas address. Municipal utilities such as Austin Energy and CPS Energy in San Antonio, most electric cooperatives, and a number of smaller city systems sit outside the competitive market entirely. City names are a poor guide because territory boundaries run through them, and one city can hold both competitive and non-competitive service areas. The reliable test is the delivery utility behind the meter: if the transmission-and-distribution utility is Oncor, CenterPoint, AEP Texas, TNMP or Lubbock Power & Light, the address is generally shoppable; if it is a municipal system or a cooperative, it usually is not. Confirm the answer from the meter and the service identifier, not from the mailing address.

• Get the ESI ID or meter number from a recent bill — the fastest way to confirm your territory.
• Power to Choose publishes the state's guidance on where choice applies and where it does not.
• A facility that cannot choose is still worth reviewing for demand-charge and load-factor reduction.

Step 2: the delivery utility sets the floor your quote must clear

The utility that owns the wires is not the utility you buy from, and in Texas it usually does not bill you either: it charges the retail electric provider, which passes the same PUC-approved delivery charges through on your invoice. Five principal investor-owned transmission-and-distribution utilities cover most of competitive Texas — AEP Texas Central, AEP Texas North, CenterPoint Energy Houston Electric, Oncor Electric Delivery and Texas-New Mexico Power — alongside Lubbock Power & Light, a municipal system that moved its load into ERCOT. Delivery rates differ enough between them that a Dallas-area site and a Houston-area site with identical consumption clear different totals before any supply is priced, which is why a quote is only meaningful beside the territory it was built for. Some delivery charges are also non-bypassable: the transmission cost recovery factor and approved system-restoration or securitisation riders stay attached to the meter whatever provider you choose.

• Oncor — Dallas–Fort Worth, Waco, Tyler, Midland–Odessa and much of North and West Texas.
• CenterPoint Energy Houston Electric — Houston, Galveston and the Gulf Coast corridor.
• AEP Texas Central — Corpus Christi, Laredo, Victoria and the Rio Grande Valley.
• AEP Texas North — Abilene, San Angelo, Del Rio and the northern split of AEP.
• TNMP and Lubbock Power & Light — smaller and newer territories, Lubbock having moved its system into ERCOT.
• Delivery is billed to the provider and passed through; the wires, the meter and the riders are not negotiable with a supplier.

Why the same load prices differently across Texas: zones and congestion

Texas is not one market for price. ERCOT's settlement design divides the state into load zones — LZ_NORTH, LZ_HOUSTON, LZ_SOUTH, LZ_WEST, LZ_CPS, LZ_AEN and LZ_LCRA — and although the wholesale market now settles nodally, the zone framework still appears in market reports and in some contract language. Two forces move prices between them. Congestion is locational: when a transmission interface cannot carry all the power the market would schedule across it, ERCOT redispatches generation, so the constrained importing area pays more and the constrained exporting area can pay less. Scarcity is system-wide: ERCOT's Operating Reserve Demand Curve adds a price adder to real-time energy as available operating reserves thin, compensating the generation that is present during tight conditions. West Texas illustrates the first, where strong wind and solar output, low short-run generation costs and limited export capacity can drive the local price to zero or below while another zone is simultaneously higher. A fixed retail price absorbs both risks; an indexed product hands them back to the buyer, which is why the structure of a contract matters more than the headline.

• ERCOT's seven load zones remain the vocabulary for locational price differences.
• Congestion is locational; the Operating Reserve Demand Curve is system-wide scarcity.
• West Texas renewable oversupply and constrained exports can push the local price to zero or below.
• A fixed price absorbs congestion and scarcity risk; an indexed price returns it to the buyer.

What actually drives a commercial bill

A commercial invoice is not one number. It is energy, delivery and demand, and demand is the line most businesses have never inspected. Utilities bill demand as the highest sustained kilowatt draw in a billing window, so a single spike can set the charge for the whole month — and because the delivery tariff defines that quantity, sometimes averaging weekly peaks and sometimes carrying a floor from an earlier month, the figure on the invoice is not simply the largest number the meter recorded. For many commercial profiles demand and delivery together outweigh the supply charge being shopped, which is what stops a low headline unit price from becoming a cheaper contract.

• Energy charge — the price per unit of consumption, and the only part a supplier competes on.
• TDU delivery — fixed customer and metering charges plus per-unit delivery, set by the utility.
• Demand charge — billed per kilowatt of peak draw, and frequently the largest controllable component.
• Taxes, fees and provider adders — small lines that quietly change a comparison.

What a supplier needs before it will quote you

Commercial pricing is not published because it is underwritten per account: a supplier prices your load shape, credit and term, so an incomplete request produces either no quote or a padded one. The identifier at the centre of the request is the ESI ID, the premise-based number for each delivery point that the utility assigns and that ERCOT's registration and settlement systems use. It is unique and permanent, and it is deliberately non-intelligent — it does not encode the ZIP code, the utility or the meter number, so it cannot be reconstructed from an address and must be read off a bill. One building can carry several ESI IDs where separately metered loads share a site, and a multi-site operator needs the list address by address. Gathering the following before asking for pricing is the largest single time-saver in the process.

• Twelve months of usage history: monthly consumption, and peak demand if the bill shows it.
• Your current contract end date, plus the notice period required to leave it.
• Service addresses, ESI ID or meter numbers, and the delivery utility for each site.
• Business entity name, credit details, and any tax-exemption or government status.
• Your priority: lowest achievable price, budget certainty, renewable content, or flexibility.

Fixed, indexed or time-of-use

The structure of the rate usually matters more than the fourth decimal place of the price. A fixed rate buys certainty and charges for it. An indexed rate tracks a market settlement point and can look cheaper in a soft market, then move against the buyer — and in Texas the rules matter here, because an indexed product may not be offered to a residential or small commercial customer at all, which makes it a large-load instrument rather than a default. Time-of-use pricing can be an advantage if operations genuinely shift load off peak and a trap if they do not. Term length is the other half of the decision: a longer term locks price and locks the buyer in, while a shorter term keeps optionality and is priced for it.

• Fixed: one price for the full term. Budgetable, and the standard choice for a single site.
• Indexed: tied to a market index, lower in weak markets and exposed in tight ones, and barred to small commercial accounts under the state's disclosure rule.
• Time-of-use: cheaper off-peak, expensive at peak. Only worth it if load can actually move.
• Term length: longer locks price and commitment; shorter buys optionality at a cost.

Renewal timing is where the money is won or lost

A Texas business already buying competitively is not shopping for a first contract; it is deciding what happens when the current one ends. The default outcome is set by the contract, not by the market: where an agreement provides for it, the account rolls onto a post-term holdover or month-to-month arrangement, and the fixed price is not guaranteed to survive the term. The Provider of Last Resort is not that fallback. PURA § 39.106 requires the Commission to designate providers of last resort in competitive areas, offering a standard service package at a fixed, non-discountable, Commission-approved rate; it exists for continuity when a provider fails to serve its customers or when a customer needs service and no other provider is serving them. Treating it as a renewal plan misreads what it is for. The practical work is a comparison run against your own numbers: pull the prospective provider's Electricity Facts Label, read it at the same usage levels as your last twelve months and the same term length, and keep the transmission and distribution charges separate from the supply line.

• Contract terms, not the market, decide what happens at the end of a fixed term.
• POLR is a statutory continuity service under PURA § 39.106, not a default renewal product.
• An EFL must state a total average price at specified usage levels — compare at your own level.
• Normalise term length, load factor and pass-through charges before comparing anything.

The rules behind the contract: disclosure, terms and switching

Texas's competitive retail rules sit in 16 TAC Chapter 25, and three of them govern the paperwork a commercial buyer actually signs. Section 25.475 requires an Electricity Facts Label in the Commission's prescribed format for each product, disclosing standardised pricing, term, renewable content and fees so two offers can be compared on one sheet. Section 25.480 governs the Terms of Service — the contract information, billing and payment provisions, deposits, termination and cancellation terms, and the notices that must accompany them. Section 25.483 sets the switching rules, including the authorisation and verification requirements and the remedies for an unauthorised change, which is why the authorisation record, account number, premises information and effective switch date are worth keeping. A provider must be certified under PURA §39.352, and §25.5 defines the roles: an aggregator may join two or more customers into a purchasing unit to negotiate, but may not sell electricity or take title to it, which is a different position from that of a provider.

• §25.475 — the Electricity Facts Label, standardised per product.
• §25.480 — the Terms of Service and the notices that must accompany the contract.
• §25.483 — switching, verification, and the remedy for an unauthorised change.
• §25.5 and §25.107 — the definitions, and provider certification under PURA §39.352.
• An aggregator negotiates as a group but may not sell or take title to electricity.

Where HighGround fits, and what we do not do

HighGround works as an advisor-assisted channel rather than a rate table. Supply options are sourced through the Broker Online Exchange supplier network, and adjacent categories — connectivity, communications, security, cloud and software — through the AppDirect ecosystem, so a multi-site business can cover energy and the services supporting the site in one conversation. What we will not do is print a figure we cannot stand behind: a published average is market context, not an offer for your account, and the only meaningful number is a written offer for your service address.

• You get a structured comparison of proposed scope, term and conditions before signing anything.
• Availability, eligibility and pricing always depend on the individual service address and account.
• HighGround may be compensated by a provider when a purchase completes; that is disclosed on every page.
• No order is placed and no supplier switched by sending an inquiry.

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