Analysis: the constraint moved from the module to the connection, and then to the rulebook
Queiroz frames the shift as attention moving from equipment to infrastructure. The Texas record suggests a further step. Module cost and tracker design are engineering problems with published prices and competitive suppliers. Interconnection in ERCOT is now partly a regulatory timing problem, and the PUCT firming rule makes that explicit: the same project, with the same equipment and the same site, carries a different obligation depending on whether its interconnection agreement is signed before or after January 1, 2027. No amount of module procurement skill changes that.
The subsidy structure points the same way. The Texas Energy Fund pays $120,000 per MW for dispatchable capacity interconnected before June 1, 2026 and $80,000 per MW after, with 10,000 MW caps. Solar is not dispatchable and does not qualify, so a solar developer is competing for interconnection studies, transmission capacity and equipment against projects that carry a state payment for connecting sooner. That is a competitive fact about the queue rather than about modules.
Against all of this, the capacity numbers show the constraint is binding on individual projects rather than on the aggregate. Texas utility-scale solar grew from 26,172.5 MW to 32,998.8 MW in a year while wind added roughly 1,000 MW. If interconnection were closing the market, that gap would not open. What the evidence supports is a narrower claim: that the variance in project timelines now sits on the grid side, so two otherwise identical projects can diverge by years for reasons that have nothing to do with their equipment.
The new ERCOT transmission interconnection cost report is the thing to watch, because it is the first systematic public data on what connecting actually costs in this market. A year of those monthly filings will show whether interconnection cost per MW is rising, and that is the number that would turn a scheduling constraint into a measurable change in project economics.
What the documents say
Fernando Queiroz, chief executive of the utility-scale developer Levona Renewables, wrote in pv magazine on August 18, 2026 that while developing a recent project in the ERCOT interconnection zone in Texas his team spent more time on transmission infrastructure, interconnection requirements, equipment availability and utility procurement than on solar modules. The commentary is behind a paywall beyond its opening, so what follows sets that claim against the public record rather than against the rest of his argument.
The record supports the direction of the commentary and adds something it does not state: the grid-side constraint in Texas is now written into state rules, not only into queue times.
What Texas actually built
Utility-scale solar capacity in Texas is still rising quickly. The Energy Information Administration’s Electric Power Monthly reports net summer capacity at utility-scale solar photovoltaic facilities in Texas of 32,998.8 MW in June 2026, against 26,172.5 MW a year earlier. Small-scale solar added an estimated 3,369.1 MW, up from 3,154.1 MW, taking estimated total solar in the state to 36,367.9 MW from 29,326.6 MW.
Wind, by comparison, barely moved: 43,987.4 MW in June 2026 against 42,920.0 MW. Total renewable capacity in Texas reached 78,030.5 MW from 70,141.5 MW. Almost the entire year-on-year increase in Texas renewable capacity was solar, and the state added more solar in twelve months than most countries have installed in total.
That is the number the commentary has to be read against. Interconnection is slow enough to dominate a project team’s calendar and fast enough, in aggregate, to add roughly 6,800 MW of utility-scale solar in a year.
Where the queue actually binds
ERCOT publishes a monthly generator interconnection status report covering planned generation in its region, and since March 2026 that series has included a transmission interconnection costs report, a requirement added under Section 5.2.8.4 of the ERCOT Planning Guide. Those costs are reported by transmission service providers for transmission-level generators that received an initial energisation date in the previous month. The grid operator also publishes resource capacity trends by fuel type that fold in projects still being studied in the interconnection process.
The existence of that cost report is itself the point Queiroz is making. Until March 2026 a developer had no systematic public record of what transmission-level interconnection had cost other projects. Equipment prices have been published and benchmarked for years; interconnection costs have not.
The rules that changed what interconnection means
The regulatory picture in ERCOT is described in detail in the annual report of NRG Energy, Inc. (NYSE: NRG), one of the market’s largest participants. Two changes matter for a solar developer.
First, firming. The Public Utility Commission of Texas adopted a final rule in December 2025 requiring new generation resources with signed interconnection agreements on or after January 1, 2027 to acquire additional capacity to meet a minimum requirement during low reserve hours on the ERCOT system. An interconnection agreement signed after that date therefore carries an obligation that one signed before it does not, which turns queue position into a cost variable rather than only a schedule variable.
Second, large loads. Senate Bill 6, signed on June 20, 2025, governs how ERCOT, transmission and distribution utilities and generators plan for loads of 75 MW and above. It requires financial commitments from large load customers when they request interconnection studies, sets out processes for curtailing those loads, and creates a PUCT procedure addressing co-location of large loads with generators that were interconnected and operating as stand-alone generators as of September 1, 2025. It also directs the PUCT to investigate revising cost allocation and rate design for the ERCOT transmission system, a rulemaking still in progress.
Underlying both is demand. ERCOT’s long-term load forecast, as cited in the NRG filing, shows peak demand rising from 86 GW in 2024 to 139 GW in 2030. NRG also records that, according to ERCOT, 46% of 2025 energy consumption in the market came from carbon emission-free resources, with wind contributing 24%.
Texas is also spending public money on the other side of the ledger. The Texas Energy Fund offers grants and low-interest loans at 3% for dispatchable generation, with completion bonus grants of $120,000 per MW for dispatchable projects interconnected before June 1, 2026 and $80,000 per MW for those interconnected on or after that date but before June 1, 2029, under separate 10,000 MW caps for the loan and grant programmes.
