The deliverable half of Texas: the Houston and Dallas-Fort Worth load pockets sit close to generation on a robust transmission network, so power actually reaches the site. It costs more than the wind-rich west, but it is where the large data-center corridors are and where a firm 24/7 load should look first.
See ERCOT (Texas) system conditions →Why: The same open, energy-only connect-and-manage framework as ERCOT statewide, applied where the transmission is robust and the load pockets are well served.
What would change the read: Restrictive new large-load interconnection rules following a major reliability event.
For new supply: The same fast energy-only build path, applied where transmission is robust and the load pockets are well served.
Beyond the grid: Water and community consent bind in Central Texas: the San Antonio to Austin corridor quadrupled data-centre development from 2023 to 2025 as Edwards Aquifer levels hit historic lows, Hays County advocates are protesting five proposed sites, and San Marcos City Council voted a data centre down outright. KUT TPR
Strong access: Houston and North (DFW) have low congestion, generation sited near demand, and more robust transmission than the west, plus ERCOT's fast connect-and-manage energization.
Availability is workable with cheap self-supply gas; the load pockets are gas-served and dense.
Higher cost than the west, but still low by national standards; deliverability is the reason to pay it.
Highest momentum in ERCOT: the DFW and Houston corridors anchor the Texas data-center build.
Carbon is the weak pillar (gas-heavy load pockets), immaterial in the default lens.
ERCOT-wide assessment applied to the Central sub-region: Winter Storm Uri (Feb 2021) forced about 20,000 MW of rolling blackouts, the largest manual load shed in US history; post-Uri winterization has improved winter performance but the tail risk remains. The Houston and DFW load pockets have robust local transmission, a deliverability strength captured in the access pillar.
What this means: A large new load faces occasional exposure here. Monitor conditions and keep a contingency plan.
event-based · FERC/NERC Feb 2021 cold weather final report
Average customer interruption (SAIDI) of 98.33 minutes per year in 2024, excluding major event days as filed.
The market figure above is an average across these territories. A project sits in one of them, not in the average. Each row is that operator’s own filed record; once a candidate site is matched to a territory, that row is the evidence that applies to it.
| Territory operator | SAIDI min/yr | Customers | Major-event method |
|---|---|---|---|
| Oncor Electric Delivery Company LLC (TX) | 67.28 | 4,013,062 | own method |
| CenterPoint Energy (TX) | 150.09 | 2,847,806 | IEEE 1366 |
| Denton County Elec Coop, Inc (TX) | 26.9 | 319,523 | IEEE 1366 |
Filed to EIA Form 861 for 2024, excluding major event days. Territory-wide averages: see the layer note above for what they do not establish.
NERC's 2024 Long-Term Reliability Assessment rates ERCOT elevated-risk grid-wide: about 20 GW of new large loads plus a more variable resource mix raise the risk of long-term shortfalls across the interconnection.
What this means: A large new load should expect genuine exposure to forced power cuts (curtailment), price spikes, and delays in getting connected, and should design in backup power or firm supply contracts.
assessed · NERC 2024 Long-Term Reliability Assessment
ERCOT-wide: fast access is conditioned on accepting curtailment at system peaks; the 4CP transmission mechanism further rewards curtailing at the four coincident annual peaks.
Utility feeds, UPS, storage, on-site generation, islanding, black start and the residual energy you still expect to lose are properties of a specific site design, not of a market. This layer only exists once there is a site, and we never assert it for you.
What this means: The supply picture looks likely to tighten; a new load should lock firm supply early and expect competition for capacity.
The average customer loses about 98.33 minutes of power per year (2024). This is the standard regulator outage measure (SAIDI); lower means a more reliable grid.
Averaged across 3 territories. No single customer experiences this figure. The per-territory table in the reliability overlay above gives each operator’s own filed record, which is what a site-specific read needs.
Low
This market's friction level, wait band and full story are free here. The precise typical wait in months, and every market ranked side by side, are the Analyst Desk.
ERCOT's energy-only, connect-and-manage framework is the fastest large-load path in the US, and the Central load pockets (Houston, DFW) pair it with robust transmission so a firm load can actually draw its power. A 75 MW readiness threshold and posted security now apply, but there is no capacity-market queue to clear.
Data-center share of demand pressure: Rising. Sources: ERCOT interconnection process · ERCOT large loads. The full cross-market connection dataset is available through the Connection Friction Feed.
$55 to $95 per MWh
Midpoint about $72 per MWh
The Central sub-region costs more than the west, but the power actually reaches the site; deliverability is what the premium buys.
This market's band is free here; the ranked cross-market table with every market's precise midpoint is the Analyst Desk. See the ranked view.
Basis: triangulated from public sources, in US dollars per MWh delivered to a large high-load-factor load, excluding refundable taxes. Sources: ERCOT 2024 load-zone prices (Modo Energy).
100 MW contracted demand, 95% load factor, HV servicecalculated
A load of this shape consumes 832,200 MWh a year. At the delivered band of $55 to $95/MWh that is $45,771,000 to $79,059,000 a year in recurring power.
Wholesale energy is 72% of the delivered rate here; the other $20/MWh is capacity, network, demand and levies. See the full build-up.
Connection route under review. Abbott directive and ERCOT notice M-A080326-01, 3 Aug 2026: a verification gate on large-load interconnection. Access and timing, not the cost stack. The recurring-cost build-up below is not part of that review and is published unchanged. Timing should be treated as unresolved until the review closes.
Recurring charges only. Customer-funded connection, substation and network-upgrade capital is quoted per project by the network operator and is not in this figure. A load factor materially below 95% raises the delivered rate per MWh, because demand and network charges are levied per MW; screen your own load to see whether the band still applies.
Moderate
1 of 3 data layers measured
Full
3 of 3 dimensions: reliability, connection, cost
June 2026
per-layer vintages below
| Layer | Method | Vintage | Freshness | Source |
|---|---|---|---|---|
| PGIQ Rating opinion | opinion | June 2026 | Current | PGIQ methodology |
| Reliability | measured | 2024 | Fresh | EIA Form 861, Schedules 3B and 3C (annual electric power industry report) (two major-event methods, IEEE; respondent-defined, customer-weighted blend of 3 of 3 territories, 100% of customers, regional context only) |
| Connection friction | proxy | 2025/26 | Fresh | ERCOT interconnection process |
| Realized cost | triangulated | 2026 | Fresh | ERCOT 2024 load-zone prices (Modo Energy) |
Freshness reflects each layer's refresh cadence: reliability annual to three-yearly, capacity-auction and queue yearly, tariffs every year or two. The full cross-market freshness dashboard is at /data-quality.
Territories in this market, each with its own filed record: Oncor Electric Delivery Company LLC, CenterPoint Energy, Denton County Elec Coop, Inc. Which one serves a given site depends on where that site is.
How the connection process is organised: the applicable service and connection entities depend on the candidate location and the power pathway. We have not compiled the structure for this market; that is a gap in our wayfinding, not a fact about the market.
How ERCOT Central (Houston & DFW)'s reliability-adjusted score and tier have moved, month by month. Part of your Analyst Desk.
Every field above carries its own source and freshness. Price, imports and exports are modelled in every market because no feed supplies them. Carbon intensity is derived from the fuel mix.
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