The good news first. Texas commercial electricity has become significantly more competitive over the last three years. The share of peak-demand hours with at least one “pivotal supplier” — a generator with enough market power to set prices above competitive levels — fell from over 90% in 2022 to just 35% in 2025, according to Potomac Economics, the grid’s independent market monitor. That improvement in competitive conditions has kept commercial rates lower and given Texas businesses genuine leverage when shopping providers.
The bad news: that window may be closing faster than most commercial buyers realize.
Unprecedented load growth driven by data centers, artificial intelligence infrastructure, and cryptocurrency mining is about to test ERCOT’s competitive structure in ways not seen since before Winter Storm Uri. As reported in MAGNIFYI, energy industry professionals are already preparing for what comes next. If you are a Texas commercial electricity customer with a contract renewing in the next 6–24 months, this is information you need now — not after your next auto-renewal.
The Potomac Economics 2025 State of the Market Report for ERCOT is the definitive annual independent assessment of the grid’s competitive performance. Its central warning is direct and specific.
Even a 20 GW increase in new net load — a fraction of what is currently sitting in ERCOT’s interconnection queue — would significantly reduce the operating reserve margin and increase the frequency of hours with pivotal suppliers. Hours with pivotal suppliers are hours where individual generators have enough concentration of market power to influence prices above competitive levels. This is the same condition that contributed to extraordinary price events during Winter Storm Uri in February 2021, when the offer cap reached $9,000/MWh.
The scale of what is in the queue makes the 20 GW warning number feel conservative. As of mid-2026, ERCOT is tracking approximately 410 GW of large load interconnection requests. The state’s current peak demand is roughly 85–90 GW. ERCOT’s own December 2025 load forecast identified 19.5 GW of contracted new load arriving by summer 2030, plus an additional 28.2 GW in attestations from transmission company officers.
Modo Energy analyst Alejandro de Diego has forecast around-the-clock ERCOT prices climbing to $74/MWh by 2028 and to $133/MWh by 2033. For context, all-in ERCOT costs declined 52% from 2023 to 2024, falling from approximately $70/MWh to $34/MWh. For a medium commercial account using 100,000 kWh per month, the difference between today’s market rates and 2028’s projected rates could mean an additional $3,000–$4,000 per month in electricity costs before TDU delivery charges.
Most Texas commercial electricity customers understand supply and demand at the grid level: more load means upward pressure on prices. What is less understood is how geographic concentration of large new loads creates price risk for nearby businesses — even when statewide supply is adequate.
ERCOT operates as a nodal market. The price your retail electric provider pays for power is not determined solely by statewide supply and demand. It is influenced by what is happening at your specific location on the transmission grid and by the physical limits of the transmission lines connecting different areas of the state.
When a massive data center interconnects in a local area, it can create congestion on the transmission lines serving that part of the grid. During high-demand periods, that congestion causes nodal prices in the affected area to spike significantly above the hub price — the statewide average that most people reference when reading about Texas electricity markets.
“Congestion shows up before the transmission catches up,” said Michael Strickland, owner of EnergyBrokerTX. “A big data center in a local pocket could spike nodal prices while state-wide supply is fine. More sophisticated REPs will hedge at the congestion gap with ERCOT congestion revenue rights and not only at the hub.”
If your electricity provider does not hedge against nodal price exposure — if they manage risk only at the hub level — congestion events driven by nearby large loads can create cost surprises that get passed through to your bill. Congestion already accounted for approximately 77% of ERCOT’s real-time reliability unit commitments in 2025, with make-whole payments exceeding $21 million. This is not a hypothetical future risk.
When you evaluate competing bids through a reverse auction, asking providers how they manage nodal versus hub price exposure is now a material due diligence question — particularly for commercial accounts in North Texas, Houston, and West Texas zones where large load interconnection activity is most concentrated.
The Texas Legislature addressed the load growth challenge in the 2025 session. Governor Greg Abbott signed Senate Bill 6 into law on June 20, 2025, with new interconnection rules going into effect July 11, 2026.
SB 6 primarily governs “large loads” — electricity customers with peak demand of 75 megawatts or more at a single site. This threshold covers data centers, cryptocurrency mining operations, and major industrial facilities. It does not directly regulate the typical small-to-medium commercial electricity account. Understanding what SB 6 does and does not do helps calibrate how much protection it actually provides to the broader commercial market.
Key provisions relevant to the commercial electricity market:
“Programs that let big customers dial back usage during the tightest hours are the cleanest protection against price spikes,” Strickland said. “Paying a contracted amount to a large user to go offline is cheaper than buying scarce power. Using this flexibility for data center customers for at most 20 to 24 hours per year changes the outlook for the grid.”
What SB 6 does not do is directly change the electricity contract, rates, or obligations of a typical commercial buyer. Its impact is indirect: better grid management of large loads should reduce the frequency and severity of the worst congestion and scarcity events. Monitor the PUCT’s work under Project No. 58317 for updates on transmission cost reallocation that could affect commercial bills.
The standard Texas commercial procurement approach over the last three years has been defensible: shop competitively, get bids from multiple providers, select the best rate, and choose between 12 and 24 month terms. Prices fell consistently and short contract terms allowed businesses to benefit from the declining market. The load growth outlook changes that calculus in three specific ways.
Locking in a longer term now makes more sense than it did 24 months ago. Forward electricity prices are currently at relatively favorable levels. ERCOT’s VP of Commercial Operations told the ERCOT board in June 2026 that forward prices were trending lower than one year prior. A 24 or 36-month fixed contract signed now locks in competitive pricing against a forward market that independent analysts project will increase materially by 2028.
“Today’s market is calmer and competitive, so buying power for future years now is likely cheaper than waiting,” Strickland said. “You should be solving for those one-off periods where the megawatt jumps to $9,000, and hedge to lock in your cost to serve. Those that are not hedging are laddering out of business because they cannot afford the next megawatt hour.”
Variable and index-priced contracts carry more risk in a tightening market. Index-priced contracts expose your business to real-time market prices. During ordinary conditions this can produce savings relative to fixed rates. During grid stress events — exactly the condition that load growth makes more likely — index contracts pass price spikes directly to your bill. The businesses that faced extraordinary electricity costs during Winter Storm Uri were predominantly on variable or indexed rate structures.
The auto-renewal trap becomes more expensive in a rising market. Commercial electricity contracts typically auto-renew at holdover rates — often 20–40% above the contracted fixed rate — if you miss the termination window. In a falling market, auto-renewal is costly but manageable. In a rising market where forward prices are climbing and congestion pressure is increasing, auto-renewing into a holdover rate is a compounding problem. Initiating your procurement 90–120 days before expiration is now more critical than ever.
For commercial accounts above approximately 20 kW — which includes most businesses beyond small retail — demand charges can represent 30–50% of the total electricity bill. These charges are based on your single highest 15-minute power draw in a billing period, not your total energy consumption. They are set by your TDU and are not negotiable through retail provider switching.
Load growth affects demand charges through two mechanisms. First, increased system-wide load over time elevates the rate environment used to calculate TDU charges across rate case proceedings. Second, for commercial accounts subject to four-coincident peak (4CP) assessment — where certain TDU transmission charges are calculated based on your demand during ERCOT’s four highest peak hours of the year — more load growth means more high-peak system hours and greater 4CP exposure for accounts not actively managing their peak load profile.
Manufacturing facilities, cold storage operations, large retail locations, and other high-demand commercial accounts should evaluate demand charge and 4CP exposure as part of their electricity procurement strategy. For more detail see our guides on manufacturing demand charge calculation in ERCOT and the demand charge profile of EV charging station operations.
1. Run a competitive auction now — not 30 days before your renewal deadline.
The most common and most costly commercial electricity procurement mistake is waiting until 30–60 days before contract expiration to begin the process. Starting 90–120 days out gives you time to evaluate multiple bids, negotiate contract terms, and avoid auto-renewal. A reverse auction with 25 or more licensed Texas providers creates genuine head-to-head competition for your account. The gap between a competitively shopped rate and a passively auto-renewed rate has historically been 15–30%. In a market where forward prices are climbing, that gap widens.
2. Compare 24 and 36-month term options alongside your standard 12-month quote.
Request quotes for multiple contract lengths simultaneously when you run your next auction. The forward curve currently does not demand a significant premium for longer-term fixed contracts relative to where independent analysts project prices will be by 2028. Seeing 12, 24, and 36-month pricing from multiple competing providers gives you the data to make an informed term decision rather than defaulting to the shortest available option.
3. Ask every bidding provider how they manage nodal versus hub pricing exposure.
Not all fixed-rate contracts are structured to manage the same risks. A provider that manages their energy cost only at the ERCOT hub level leaves your account exposed to congestion events in your local transmission area. Ask bidding providers directly how they hedge congestion risk in your TDU service territory. The sophistication of the answer tells you something important about how your rate will perform during the kinds of market events the independent market monitor says are coming.
Texas commercial electricity has been a genuine buyer’s market since 2022. The all-in cost of ERCOT electricity fell 52% from 2023 to 2024. Competition among retail providers increased as market conditions improved. Businesses that shopped competitively locked in rates well below national averages.
The Potomac Economics 2025 State of the Market Report and the load growth data now in ERCOT’s interconnection queue tell a consistent story: the conditions that produced three years of falling commercial electricity prices are under structural pressure from a volume of new large load that, even partially materialized, is sufficient to reverse competitive conditions and drive prices meaningfully higher.
The businesses that act on today’s competitive market before load growth tightens it will be better positioned — on rate, on contract structure, on demand charge exposure — than those that wait for the situation to become obvious in their monthly bill. At that point, the forward market will already have priced in the risk.
If you are a Texas commercial electricity customer with a contract expiring in the next 6–24 months, now is the right time to see what 25+ licensed Texas providers would bid for your account — and to lock in the best of those bids while the competitive market that produced them is still in your favor.
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