The Permian Basin is at risk of rolling blackouts. That much is on the record from the Electric Reliability Council of Texas, repeated through a chain of hearings, wire stories and legislative fights since July. What has not been reported is the assumption underneath the number.
ERCOT’s binding figure for the Far West assumes every battery in the region is sitting at zero state of charge. That is a modeling convention, not a finding. It is currently helping justify a transmission program with a capital cost between $17.2 billion and $33 billion, and no party in the certificate proceedings has been required to test it.
The document nobody is citing
Dan Woodfin, ERCOT’s vice president of system operations, presented Far West Load Growth and Transmission Timing Issues to the ERCOT board on February 9 and 10, 2026. It is the technical spine under every statement that followed, and it is specific in ways the hearing testimony is not.
ERCOT monitors two Far West import constraints whose limits are treated as Interconnection Reliability Operating Limits, requiring operator action up to pre-contingency loadshed to prevent widespread uncontrolled outages. Under critical conditions with no outages, maximum reliable load-serving capability in the Far West was calculated at 9,500 MW. Local thermal generation totals 2,827 MW across five plants, the largest being Odessa Ector at 1,280 MW.
Woodfin also draws the distinction that matters. Far West import constraints overload when the local area cannot serve local load even if there is sufficient capacity elsewhere on the system. This is a thermal-overload import problem inside a load pocket at the end of a radial system. It is not ERCOT-wide resource adequacy, and describing it that way gets the policy question wrong.
The gap nothing closes
Delaware Basin Stage 2 came online in June 2026 with an estimated incremental benefit of about 1,000 MW. Stages 3 and 4, arriving December 2026 and December 2027, are not import projects. The next transmission with significant impact is Stage 5 at the end of 2029, then the Permian Basin 765-kV buildout. On the resource side, a single 224 MW unit in the second quarter of 2027 meaningfully raises capability under critical conditions.
That is roughly 1,200 MW of relief between now and late 2029, against a load line ERCOT charts heading well past it. The 765-kV segments the Public Utility Commission approved on August 28 energize in 2030 and 2031. The Texas Public Policy Foundation and Energy Ventures Analysis make the same timing point from the opposite direction: West Texas demand grows from 2026, the lines arrive in 2031, so something else has to cover the interval regardless.
Both sides’ evidence agrees the lines cannot prevent a 2027 or 2028 event. “Approve the certificates or the Permian goes dark next summer” is not a coherent argument. It is the argument being made.
Storage counts for zero, by assumption
The 9,500 MW figure is calculated with energy storage resources fully discharged, providing voltage support only. The West load zone holds 4.0 GW of operational battery capacity as of the second quarter of 2026, one of the largest zone fleets in ERCOT behind North and South. None of it counts toward the number that determines whether the Far West sheds load.
That is not ERCOT being unfair to batteries. The binding condition is an extended low-wind stretch overnight, and ERCOT’s fleet averaged 1.65 hours of duration entering 2026. In the 2026 planning case of ERCOT’s 2024 ELCC study, 97 percent of modeled storage is one- and two-hour systems, and three hours or longer is required to reach 91 percent effective load carrying capability on a summer afternoon. An overnight event is harder than an afternoon peak. There is no solar arriving to recharge, and a multi-day low-wind period exhausts a two-hour asset on the first evening.
So adding more storage of the kind Texas currently builds changes nothing about this constraint. That conclusion is correct. It is also load-bearing, and it has never been stress-tested in a proceeding.
Local storage is worth more than its capacity credit
Because this is a thermal import constraint rather than a system adequacy problem, every megawatt discharged inside the pocket is a megawatt that does not have to cross the constrained lines. Storage sited in the Far West substitutes for import capability at roughly one to one while it is discharging. A battery in the North zone contributes to ERCOT reserve margin. A battery in Reeves County raises the operating limit. The effective load carrying capability framework prices the first and undersells the second.
The charging economics favor the location. West Texas is the most curtailed region on the system, and midday surplus is exactly what a long-duration asset wants to absorb. The reason six-hour storage is not being built there is revenue design. Merchant battery revenue fell from $192/kW in 2023 to roughly $43/kW averaged across 2024 and 2025, new interconnection applications dropped 50 percent in the second half of 2025, and developers have moved toward load centers with better pricing. A battery behind a binding constraint cannot reliably reach real-time prices, which is a direct disincentive to siting inside the problem.
Scoping the requirement, and this arithmetic is mine rather than ERCOT’s: closing the gap would take somewhere between 2,000 and 4,000 MW of firm local capability by 2028 or 2029. At six to eight hours, that is 12 to 32 GWh concentrated in one weather zone. Total operational storage energy across all of ERCOT was 28.8 GWh at the end of the second quarter of 2026. Not impossible. Not incremental either.
What the record does not contain
Oncor and LCRA Transmission Services testified in Docket 59182 that they conducted no separate alternatives analysis, because the Commission had already approved the 765-kV option and directed certificate filings consistent with that decision. The Permian Basin Reliability Plan study itself compared 345-kV, 500-kV and 765-kV import paths. Voltage levels, not resource strategies.
Nobody has been required to model a storage-heavy Far West against the import buildout. More than 40 legislators filed a brief arguing that 4 to 5 GW of gas generation in West Texas could reduce or eliminate the need for the lines, which is structurally the same argument with a different resource. The transmission providers’ own June 24 joint filing partly concedes the mechanism: negative pricing helps explain why no new dispatchable generation has been built in the Permian in a decade, and state incentives have produced plans for only 2.5 GW of new dispatchable capacity in the Far West.
Meanwhile the demand half of the case is being relitigated. The plan rests on a 2022 oil-and-gas study projecting 11,964 MW of Permian peak by 2030, plus roughly 11,695 MW of additional non-oil-and-gas load, nearly as much again. That second half is data centers and crypto, and ERCOT chief executive Pablo Vegas told House State Affairs on August 19 that auditing the roughly 200 GW of proposals will take several months. The supply-side fix is being approved while the demand forecast is under audit.
Unverified
Three things I could not confirm. Whether ERCOT has recorded an exceedance on the Far West import constraints specifically, as opposed to the system-wide exceedances reported through its operations updates. Whether the capacity procurement Woodfin floated for the first half of 2026 was ever issued. And whether ERCOT has run any Far West case with storage at nonzero state of charge, or whether the zero-charge assumption is a Planning Guide convention rather than a study result.
The third is the one worth chasing. If it is a convention, then the convention is deciding a $33 billion question.
edited and authored by Dave with close collaboration by Claude