No. The ~440,000 MW figure is total interconnection requests — essentially site inquiries seeking studies. It is not a forecast and the vast majority will never energize; connecting that much load to ERCOT would be physically impossible on any near-term horizon. The meaningful number is study-backed reality: roughly 30,000 MW has progressed to firm status (observed taking service, approved to energize, or with planning studies approved by the TSP and ERCOT) through 2030, and only about 6,000 MW of large load has actually been observed taking service so far.

The queue is now roughly 95% data center, having evolved from West Texas oil-and-gas electrification, through a crypto-mining wave, to today's hyperscale data centers (crypto is near 3.3%, industrial ~1%, hydrogen below 1% and falling). Size matters because the mix has shifted toward very large campuses — more than 180 projects above 1,000 MW, totaling nearly 300,000 MW of requests. A 1,000 MW campus is a distinct stability challenge: an instantaneous trip of that magnitude can stress grid frequency and voltage. That is why ERCOT is imposing ride-through requirements, developing synchronous-oscillation requirements, and applying consequential-load-loss limits — a trip causing 1,000 MW or more of consequential loss violates reliability criteria.

Forecast inclusion matters because the official load forecast drives transmission planning and resource-adequacy assessments (e.g., the CDR). For 2026, a project must (1) disclose duplicative sites to avoid double-counting, (2) demonstrate site control via an executed lease or deed, and (3) satisfy one of three financial commitments: $100,000/MW of financial security based on contracted peak demand; 100% payment of long-lead-time equipment (transformers, large breakers); or 100% of the contribution in aid of construction (CIAC) for interconnection facilities. Beginning in 2027, the bar rises sharply: a project will need a signed interconnection agreement — meaning completed studies, an accepted allocation and study results, posted financial security, paid interconnection costs, and reported development progress.

In our assessment, the queue overstates reality by design — like the generation queue, it captures inquiries, not commitments, and many study results will steer developers away from given sites. The 2026 load forecast is, in our view, currently too high, because the criteria that gate forecast entry this year were not stringent enough to fully discipline speculative volume. We expect the stricter 2027 standard (a signed interconnection agreement) to materially improve forecast accuracy. That said, the underlying growth is real and historic; the task is engineering and policy that separate credible projects from speculative ones.

ERCOT is replacing one-at-a-time large-load studies with a batched process. Batch Zero is the first cycle and carries unique rules because its purpose is to clear a two-to-three-year backlog of loads that have already energized or advanced far through the process. Only after that backlog is cleared can durable long-term policy be set in Batch One and beyond. Batch Zero is also where controllable-load-resource (CLR) and bring-your-own-generation (BYOG) rules were filed.

BYOG gives preferential treatment to large loads that co-locate with new generation. A qualifying campus can energize on a timeline tied to the commissioning of its generation — without waiting for new transmission. We expect roughly 40,000–60,000 MW of Batch Zero load to qualify as "baseload," receiving 100% of its interconnection allowance; other loads receive a reduced allocation and must wait for upgrades such as the 765 kV strategic expansion and the Permian Basin Reliability Plan. Where the transmission system is oversubscribed (likely in Batch Zero), a large load can wait for the next batch, accept a lower allocation until transmission is built, or pursue BYOG — serving the full campus on-site generation subject to a withdrawal limit capping grid imports.

Senate Bill 6 provides the statutory framework for managing large-load growth. Completed rulemakings include the load-forecast criteria and net-metering-with-existing-generation rules. In progress are the large-load interconnection standards (entry/exit criteria and financial terms for the batch process) and a proposed reliability service for large loads — a demand-response-style product compensating data centers that voluntarily drop off the grid up to 24 hours ahead of an anticipated emergency. The net-metering rule is notable: adding a data center behind a generator that was standalone and ERCOT-connected as of September 1, 2025 triggers load interconnection studies plus a separate 120-day ERCOT review of transmission security and resource adequacy.

As proposed (and subject to change), an intermediate agreement serves as a preliminary gate to enter a batch study, with a study fee of about $100,000 for projects under 250 MW and $300,000 for larger projects. Developers may optionally pre-fund long-lead-time equipment to let the TSP begin procurement early. A financial-security requirement near $50,000/MW applies; as currently drafted most of it is non-refundable (a withdrawing project recovers about 20%, with 80% retained to offset rate base), though refundability is likely to evolve. After batch-study results, executing the interconnection agreement involves a non-refundable interconnection fee plus security for long-lead equipment and system upgrades.

Transmission cost has become a larger driver of total delivered cost than energy, and the Four Coincident Peak (4CP) method concentrates that cost recovery in just four summer peak intervals. The PUCT studied alternatives, and staff recommended moving to a 12CP approach with a 30-minute measurement interval, plus a minimum demand charge for large loads of 250 MW and above (based on non-coincident or contracted peak demand). The effect would shift more transmission cost onto the largest loads. This is a staff recommendation; the commission may modify it or seek further comment. Separately, the transmission "postage-stamp" delivery charge has risen to about 74 cents from 68, with further increases expected.

The latest CDR does show projected reserve margins turning negative across 2027–2029 — which on paper implies a 100% probability of firm load shed — but those projections use the elevated load forecast. We read the result as a forcing function rather than a fixed prediction: supply must scale with demand, and demand will be constrained by real transmission and economic limits. The focus is on adding supply: roughly 7,000–8,000 MW of new ERCOT-dedicated gas via the Texas Energy Fund, reforms to the Dispatchable Reliability Reserve Service (DRRS), continued solar and battery additions, and — critically — a major expansion of demand response across commercial, industrial, and residential customers.

Real-time co-optimization plus batteries (RTC+B) went live in December 2025. RTC dispatches energy and ancillary services together in real time, and batteries are now modeled as a single device with a state-of-charge constraint rather than separate load and generation. Security-constrained economic dispatch (SCED) selects the least-cost resource mix, cutting manual operator actions; ERCOT projected $2.5–$6.4 billion in annual efficiency savings. Early performance (through March 2026, including a winter stress event near 85 GW) has been stable, with scarcity largely absorbed in ancillary-service markets rather than broad energy-price blowouts. RTC+B is not inherently inflationary — it reallocates risk from averages toward the tails, so tight ancillary-service hours and real-time events matter more.

Several factors keep near-term futures soft despite significant upside risk. Reality is slowing large-load growth: a deep queue backlog, infrastructure delays (gas turbines, steel, microchips), labor shortages, and ongoing regulatory change all push out the timing of new load. ERCOT is also comparatively insulated from geopolitical volatility because Texas has abundant local gas supply and operates an energy-only market — import-dependent regions such as the Northeast have seen far larger impacts from overseas events. With mild weather earlier in the year and many participants in "wait-and-see" mode, much of the upside risk simply has not been realized yet. As loads energize, the forecast firms, and summer heat arrives, that risk is likely to surface in pricing.

The transmission runs through natural gas. Sustained high oil prices encourage additional drilling — notably in the Permian — and the associated gas produced alongside that oil increases domestic gas supply, which can ultimately ease gas (and therefore power) prices. Counterbalancing that, Texas Gulf Coast LNG export facilities already run near maximum capacity (about 16–18 Bcf/day, scaling toward 32.6 Bcf/day by 2030), and damage to overseas export infrastructure plus risk around the Strait of Hormuz (~20% of global oil and LNG transit) tighten global markets and pull on US exports, modestly supporting Henry Hub. The net near-term effect on ERCOT is muted by Texas's strong local supply.

A late-developing El Niño anchors the outlook, favoring a warm west and south and a more seasonable midwest and east. For ERCOT specifically, guidance points to a warm, seasonable June trending toward a hot, dry August, with 2018 and 2023 cited as analog years — both of which delivered extended stretches above 100°F and substantial real-time price volatility. The slower-moving El Niño tilts the hottest, most volatile risk toward earlier in the summer, though exact timing is uncertain. Fall guidance will firm up later in the season; the prudent stance is to plan for above-average August heat and embedded scarcity premiums in peak hours.