Batch Zero: what it takes to keep your Texas power allocation

Find your project’s position

Batch Zero is the Electric Reliability Council of Texas’s (ERCOT) transition to studying qualifying large loads together across the system. It covers an existing cohort of requests, generally at least 75 megawatts (MW). Its ordinary entry deadlines have passed. A new application and a security posting do not buy entry now.

The distinction that matters for a customer buying capacity:

Ask the developer for the ERCOT serial number, its Planning Guide category, the status of eligibility verification, and the MW schedule supporting the delivery promise. “In Batch Zero” alone does not establish how much power a facility can receive or when it can receive it. Planning Guide, sections 9.2–9.3 (opens in a new tab)

Why the process changed

ERCOT described a rolling process in which new requests and withdrawals changed the study assumptions and required repeated restudies. Studying a group together gives the analysis a common set of projects.

Senate Bill 6 addressed project credibility through site control, financial requirements, and disclosure of competing Texas requests. ERCOT established the batch framework through its protocol and Planning Guide changes. Those are related reforms with different jobs. ERCOT’s February 2026 report, page 5 (opens in a new tab); enrolled Senate Bill 6 (opens in a new tab)

The dates that can change your schedule

Sources: September 21 ERCOT filing, cover letter (opens in a new tab), rule effective date (opens in a new tab), impact request (opens in a new tab), September 21 governor’s letter (opens in a new tab), and Planning Guide (opens in a new tab).

Complete both information requests

The eligibility request for information (RFI) tests whether a project belongs in its claimed Batch Zero category. The normal response period is ten business days, with up to five additional business days available by request. Failure to submit a timely, complete response can exclude the project.

The transmission service provider submits the completed eligibility response. Developers and the transmission and distribution providers remain responsible for their respective data, exhibits, and sworn attestations. Previously submitted documents still have to be uploaded where the request requires them.

A September 21 portal change matters to that coordination: utilities can no longer see developer responses and uploads. Developers can see the utility’s eligibility responses. Assign responsibility for each attachment and confirm the submission record with the transmission provider. Eligibility notice (opens in a new tab); portal change (opens in a new tab); studied-project question reference (opens in a new tab)

The State and Community Impact RFI asks about financial assistance, water, cooling, power arrangements, ownership, and community effects such as noise, light, and traffic. Its scope also reaches certain medium loads between 25 and 75 MW. The water section is issued on behalf of the Texas Water Development Board following the governor’s September 14 directive.

ERCOT’s September 24 notice created a voluntary impact-response route for newly substantiated medium loads not originally subject to the request. Requests to use that route run through October 5, with responses due October 12. That route does not reopen Batch Zero. Impact RFI (opens in a new tab); water directive (opens in a new tab); September 24 notice (opens in a new tab)

Budget for the agreement that follows the allocation

The adopted rule requires a standard large-load interconnection agreement within 60 days after the allocation report, including for Batch Zero projects. The agreement converts the allocation into contracted peak demand and a schedule the customer must support.

At that signing, security is the greater of $50,000 per contracted MW or the system-upgrade costs allocated to the project. A 300 MW allocation therefore means a $15 million floor. Allocated upgrade costs may make the required amount higher. Direct interconnection construction is a separate, nonrefundable cash obligation. Minimum-billing requirements may create additional security needs.

Existing Batch Zero cash and security can receive credit under the transition provisions. Do not assume October 8 requires a second, duplicate posting. Confirm with the utility what is already credited, what remains due, and which instruments it will accept. Adopted rule, subsections (f) and (h) (opens in a new tab)

A new request has an earlier funding step

For a covered new request, execute and fund the intermediate agreement before the study. Security is $50,000 per requested MW, plus a separate flat $100,000 study fee. Within 60 days after execution and funding, the utility must ask ERCOT to initiate the study. That is a deadline for the request, not a promise that the study starts immediately.

The rule generally applies to covered customers not energized by October 8, including qualifying new loads, expansions, and co-located loads. The threshold uses expected non-coincident peak at a site, at either transmission or distribution voltage. An expansion that first crosses 75 MW, or adds at least 75 MW to a site already above it, is covered for the added demand. Municipal utilities and cooperatives can impose additional service terms. Adopted rule, subsections (b), (d), and (e) (opens in a new tab)

Arrange the security instrument before the deadline

Cash, a qualifying guaranty, or a qualifying letter of credit are accepted forms. Intermediate cash can be returned or credited toward the standard security; the customer’s written election is due within 30 days of the allocation notice, with credit as the default. An intermediate guaranty or letter of credit is returned within 30 days after ERCOT’s allocation notice to the utility. Arrange the replacement instrument for the standard agreement.

For Batch Zero interconnection agreements executed on or before June 1, 2025, the existing agreement governs direct interconnection costs; the other standard-agreement financial obligations still apply. Customers with a 2026 regional-plan agreement must withdraw or execute a compliant superseding agreement. Batch Zero provisions govern where both apply. Adopted rule, subsections (h) and (i) (opens in a new tab)

Make the land and customer commitments match

A land option can support the intermediate agreement and qualifying studied-project eligibility. By the standard agreement, the customer needs a deed, an executed purchase-and-sale agreement, or a qualifying lease. The lease must run at least five years from the expected date of contracted peak demand. An affiliate-held land interest needs a binding connection among the customer, affiliate, and site.

The competing-request disclosure reaches beyond the applicant. It includes affiliates, a contracted hosted end user, and developers acting for them. Disclose a substantially similar Texas request when success there would cause a delay of at least a year, a change of at least 20% in requested peak, or a different point of interconnection here. Competitively sensitive details may be anonymized as the rule permits.

An officer able to bind the customer attests that the agreement’s disclosures are complete and accurate. The file includes the development and energization schedules; water volume, source, supplier, and cooling; permit status; and backup-generation capabilities and limits. A change that ERCOT’s protocols treat as material requires a new interconnection request. That is a separate test from the competing-request disclosure thresholds. Adopted rule, subsections (d)–(f) (opens in a new tab)

For a customer contracting for space, diligence should reach the end user’s alternatives, the developer’s land interest, the power schedule, and the permit record together. A change in any one can affect the others.

Put the permit hold into the delivery schedule

On September 21, Governor Greg Abbott directed the Texas Commission on Environmental Quality to pause issuance of data-center permits until ERCOT completes its review. The letter also directed other state agencies to hold data-center approvals pending the information. The October 19 agency response date is a reporting deadline. ERCOT’s December 10 report date is also not a guaranteed permit restart.

The directive followed the August 3 instruction to the commission and ERCOT to scrutinize projects before advancing them, and the September 14 water-information directive. Developers now need a schedule that accounts for the eligibility review, financial commitments, and the availability of required agency approvals. An interconnection agreement does not issue an air or water permit. August 3 letter (opens in a new tab); September 14 letter (opens in a new tab); September 21 letter (opens in a new tab)

On-site generation has its own constraints

ERCOT’s framework recognizes controllable loads and projects with their own generation and a defined limit on grid withdrawals. Those are specific operating arrangements with eligibility requirements and earlier election deadlines. Buying generators now does not automatically change a project’s Batch Zero category.

A facility relying on its own generation cannot assume that a generator outage entitles it to withdraw the facility’s full demand from the grid. The agreed withdrawal limit still matters, as do the permits required to operate the generation. Confirm the elected category, controls, grid limit, and permit status before offering a customer a generation-backed delivery date. Planning Guide, section 9 (opens in a new tab)

Price an exit before the signing window closes

Batch Zero withdrawal costs depend on the project’s category and timing. The utility may process a written Batch Zero withdrawal notice only after ERCOT issues the allocation report and before the standard-agreement deadline. The category-specific retention provisions apply within that window.

After applicable outstanding costs, the rule treats these categories differently:

The percentages apply to security tied to allocated capacity, not automatically the entire original posting. Check the exact category, withdrawal date, and applicable costs before pricing an exit. Missing the standard-agreement deadline requires cancellation; the Batch Zero provision says the customer may be deemed to have forfeited security posted under an intermediate agreement. Adopted rule, subsection (h) (opens in a new tab)

After the standard agreement, withdrawing contracted MW requires payment of outstanding costs, including applicable minimum bills, before the 20% retention on security attributable to the withdrawn capacity. At energization, 20% of remaining security returns; later releases follow the agreement’s minimum-billing milestones.

A 24-month miss against the energization schedule as a whole can trigger loss of unused capacity. The utility collects outstanding costs, retains 20% of security attributable to unused capacity, and returns the balance. ERCOT can put released capacity into a later study. The utilities cannot reallocate it themselves. Direct interconnection contributions remain nonrefundable. Adopted rule, subsections (f), (g), and (k) (opens in a new tab)

Before you commit a customer to a delivery date

Get the project team and utility working from the same record:

• The ERCOT serial number, category, verification response, and MW-by-year schedule.
• The distinct eligibility and impact-response deadlines, including any confirmed extension.
• The standard-agreement funding plan, credited security, replacement instruments, and land rights.
• The permit path under the governor’s directives, including constraints on backup or on-site generation.
• The withdrawal terms and the consequences of changes to the customer’s other Texas requests.

JD Key helps developers and operators coordinate the state-agency, utility, and local-government work behind that record. Bring the category, MW schedule, and next deadline to the conversation.