Texas Regulators Approved ERCOT's Rules for a 438 Gigawatt Large Load Queue. Commercial Rate Data Shows a Wide Spread by Contract Term.
Texas just rewrote the rules for connecting very large electricity users to the grid, and the queue behind those rules exceeds 438,000 MW. The rate data across 698 active Texas commercial plans shows a wide gap between what short and long contract terms cost right now.
ERCOT Is Tracking 438 GW of Large Load Requests
The Public Utility Commission of Texas approved ERCOT's Batch Zero interconnection process on June 18, 2026. In announcing the decision, the grid operator said it is tracking more than 438,000 MW of large load requests, nearly 89 percent from data centers alone. The batch framework replaces a project-by-project evaluation that ERCOT describes as having become lengthy and repetitive as large electricity users rushed to connect to the grid.
Under the framework described in that announcement, ERCOT groups qualified large projects of 75 MW and greater into a single study so it can assess the full picture of future electricity demand at once, allocate transmission capacity according to what the grid can reliably support, and identify the upgrades needed to serve the batch.
$3.65 Billion Generation Capacity Expansion
A parallel effort is under way on the supply side. Through the Texas Energy Fund In-ERCOT Generation Loan Program, the PUCT has closed eight loan agreements worth $3.65 billion to finance 4,994 MW of new dispatchable generation, the program total it lists as of June 24, 2026. Most of that capacity is not running yet. The PUCT project table shows operations dates spread from 2026 through 2029, with only two of the eight plants online ahead of this summer.
Those figures do not describe a supply shortfall. FERC's 2026 summer energy market assessment has ERCOT adding 25.6 GW of net summer capacity, more than any other region in the country and a 16 percent increase over its 2025 net summer capacity of 158 GW. What the picture describes is price pressure rather than scarcity, with load growing quickly while the largest fund-backed plants remain years from commercial operation.
Analysis of Current Market Rate Data
The average advertised rate across the 698 active commercial plans in this catalog, measured in mid-June 2026, is $0.109 per kilowatt-hour. That is a Texas Commercial Plans measurement of posted competitive offers, not a bundled, bill-based statewide average. For contrast, EIA puts the average price of electricity to Texas commercial customers at 8.26 cents per kWh for May 2026, a delivered figure covering every commercial account in the state, including territories closed to retail competition. The two numbers measure different things and should not be read against each other.
The more revealing data point is the divergence in pricing between contract length categories:
- Short-term contracts (under 12 months): median rate of $0.119/kWh
- Mid-term contracts (12-24 months): median rate of $0.088/kWh
- Long-term contracts (24-plus months): median rate of $0.080/kWh
Short-term contracts run 49% higher than long-term contracts at the median. For a business consuming 50,000 kWh per month, that difference amounts to approximately $1,950 per month.
This pricing gap reflects how forward markets estimate risk. When a grid signals rapid load growth and an uncertain demand trajectory, suppliers price short-term exposure higher and reward buyers willing to commit to longer terms.
Per-Utility Rates as of June 2026
Advertised rates vary meaningfully by delivery utility. Within the same catalog, Oncor and CenterPoint territories both sit at a median of $0.094/kWh. AEP Central comes in at $0.099/kWh, TNMP at $0.109/kWh, and AEP North carries the highest median at $0.125/kWh. These are medians of posted plan rates tracked here, not delivered bill totals, and a business does not select its delivery utility. Territory follows the service address.
What drives the AEP North spread is not something a catalog of posted offers can establish. Delivery tariffs, the number of suppliers quoting a territory, and the mix of plans on offer all move advertised rates, and separating them requires data this catalog does not carry. The figure above states the size of the gap and stops there.
The Decision Facing Texas Commercial Buyers This Summer
The new grid rules are built for a buildout measured in years, not months. ERCOT has said that while not all interconnection requests result in built projects, its data shows the majority of the queue expects to be operational by 2030. Two dynamics run at once for buyers signing contracts now.
In the near term, a growing load base looks likely to keep wholesale prices elevated. The same FERC assessment has ERCOT wholesale prices up 11 percent against summer 2025, one of only three regions projected to rise while the national benchmark average falls 5 percent. That increase is forecast even though ERCOT leads the country in new summer capacity, which is what makes it a demand story rather than a supply one.
Longer term, the generation backed by Texas Energy Fund loans reaches the grid on the operations dates the PUCT publishes, which run out to 2029 and may ease pressure as supply expands into the growing load.
Businesses renewing or signing contracts this summer are weighing both dynamics. The current rate spread between contract terms reflects market expectations: short-term buyers pay for optionality while long-term buyers trade flexibility for a lower locked-in rate.
Neither approach is universally correct. A business with uncertain space needs or limited capital may opt to pay the short-term premium to maintain flexibility. A business with stable, predictable demand and a long facility horizon has a stronger case for locking in a longer-term rate now.
Rate data for all active Texas commercial plans, broken down by utility territory and contract term, is available in the plan comparison tools on this site.