Power

ERCOT Data Center Interconnection for Sub-5MW Projects: What SB 6 Changes and What It Doesn't

Published ·15 min read

If you're planning a 2–5 MW data center in Texas, you've probably spent the last year reading about Senate Bill 6, ERCOT's large-load rules, study fees, and per-megawatt security, and wondering how much of it lands on your project. The short answer surprises many owners. The headline rules for ERCOT data center interconnection are written for loads of 75 MW and up. A sub-5MW facility is far below that line.

That doesn't make power easy at your scale. Your critical conversations are with different parties (your utility and, in much of the state, a retail electric provider), under different rules, with different risks. This guide covers what the law says, what's settled and what's pending as of October 21, 2026, how interconnection really works for a small facility, and what to ask before committing to a site.

The 75 MW Line: What Texas SB 6 Actually Says

SB 6 was signed by the Governor and took effect immediately on June 20, 2025.[^2] For Texas SB 6 data centers coverage, the provision that matters most is new Utilities Code §37.0561. It directs the Public Utility Commission of Texas (PUCT) to set interconnection standards for "large load customers" in the ERCOT power region.[^1]

The statute is explicit about who those standards cover. They "must apply only to customers requesting a new or expanded interconnection where the total load at a single site would exceed a demand threshold." It also says the commission "shall establish a demand threshold of 75 megawatts unless the commission determines that a lower threshold is necessary."[^1] The disclosures, the study fee of at least $100,000, the site-control proof, and the transmission financial commitments that follow all apply to customers above that threshold.[^1]

The PUCT kept the 75 MW number. Its adopted rule, 16 TAC §25.194, defines a large load customer as one whose expected non-coincident peak demand at a single site "is equal to or exceeds 75 MW, whether at transmission voltage or distribution voltage."[^5] The line is drawn by size, not by voltage.

Two nuances about "single site" from the PUCT's adoption order:

  • Separate sites aren't added together. The commission clarified that the rule doesn't reach one entity's separate interconnection requests at separate sites that together total 75 MW or more.[^6]
  • A campus is one site, however it's metered. The commission refused to measure by ESI ID because "large loads are able to establish campuses with multiple ESI IDs."[^6]

The second point matters to sub-5MW owners in one specific case. If your 3 MW hall or first phase sits on a campus whose total expected load reaches 75 MW, that site can fall under the rule even though your own piece is small.

ERCOT Large Load Interconnection Requirements, and Why a 5 MW Site Sits Outside Them

ERCOT's process uses the same threshold. Its Protocols define a "Large Load" as one or more facilities at a single site with aggregate peak demand of 75 MW or more. ERCOT's question-and-answer guide on the process states that the formalized process in Planning Guide Section 9 "does not apply to loads under 75 MW." Under the earlier interim process, loads co-located with generation were captured starting at 20 MW. The formalized process no longer draws that distinction.[^3]

For loads that do qualify, the ERCOT large load interconnection requirements are substantial:[^3]

  • reliability studies by the transmission service provider, reviewed by ERCOT
  • a Load Commissioning Plan
  • milestone deadlines that can remove a project from the process
  • conditions that must be met before ERCOT approves energization

ERCOT's Large Load Integration page is now organized around "Batch Zero," a batch study process for loads of 75 MW or greater.[^4]

ERCOT's newest technical rule follows the same pattern. Ride-through requirements for "Large Computational Loads" took effect August 1, 2026.[^8] The definition reads in full: "A Large Load in which 50% or greater of the Demand at the site consists of power electronic based load, specifically computational load, such as data centers and cryptocurrency mining facilities."[^9] A 3 MW facility isn't a Large Load, so it isn't an LCL.

The co-location rules follow suit. SB 6's net-metering review for loads sharing a site with existing generation applies to a "new large load customer as described by Section 37.0561(c)."[^1]

So when a vendor pitch describes "the ERCOT interconnection process" as your critical path, ask which process they mean. For most sub-5MW owners, it isn't this one.

What's Settled and What's Still Pending (as of October 21, 2026)

Based on the primary sources we reviewed on October 21, 2026:

Settled:

  • SB 6 is law. It has been in effect since June 20, 2025.[^2]
  • The PUCT's large-load interconnection rule is final. 16 TAC §25.194 was adopted September 18, 2026 under Project No. 58481, with an effective date of October 8, 2026.[^5][^6][^7] For loads of 75 MW and up, it requires an intermediate agreement, a $100,000 study fee, and financial security of $50,000 per MW.[^5]
  • The PUCT has said, in writing, that small loads are outside this rule. The adoption order states: "The interconnection path for loads below 75 MW is outside the scope of the adopted rule."[^6]
  • Two related SB 6 rulemakings are done. The net-metering rule (Project 58479) and the large-load forecasting rule (Project 58480) are both adopted.[^7]

Pending:

  • A standard large load interconnection agreement. A proposal was expected in October 2026, with adoption by March 2027.[^7] It covers large load customers only.
  • The demand management service (Project 58482). This project was restyled for possible implementation of PURA §39.170(a), with a recommended order expected in January 2027.[^7] Section 39.170(a) requires curtailment protocols for transmission-voltage customers interconnected after December 31, 2025, and it has no MW floor.[^1] See the note on transmission voltage below.
  • Transmission cost allocation (Project 58000). SB 6 directed the PUCT to re-examine how transmission costs are assigned, including the four-coincident-peak (4CP) method, and to amend its rules by December 31, 2026.[^1] The rulemaking, titled "Wholesale and IOU Retail Transmission Cost Recovery in the ERCOT Region," expects a recommended order in December 2026.[^7] This one reaches sub-5MW sites directly. On Oncor's secondary and primary schedules, any premise that has set a demand of 700 kW or more is billed transmission cost recovery on 4CP kW.[^17] CenterPoint applies 4CP-based transmission charges to premises above 700 kVA.[^18] Every 2–5 MW site crosses that line. Your transmission charges are 4CP-based today, and the method is being rewritten. We aren't predicting the outcome.

The statute also lets the PUCT lower the 75 MW threshold if it finds that necessary.[^1] That isn't a live issue today, but it's a reason to re-check before you lock a power strategy.

How Texas Data Center Interconnection Actually Works Below 75 MW

For most sub-5MW owners, Texas data center interconnection is a utility service extension under that utility's tariff. In competitive areas it runs alongside a separate retail supply contract.

Step 1: Confirm the grid, the provider, and whether you have retail choice

  • Confirm the parcel is in ERCOT. ERCOT serves about 90 percent of the state's electric load, not all of it.[^12] SB 6's large-load provisions apply only to the ERCOT power region.[^1] The PUCT also notes that retail competition is delayed in Entergy Gulf States, Southwestern Public Service, El Paso Electric, and AEP SWEPCO territories.[^15]
  • Competitive areas. Investor-owned transmission and distribution utilities deliver the power under the PUCT's statewide pro forma tariff (16 TAC §25.214).[^10] You buy the power itself from a retail electric provider (REP), also called a competitive retailer.[^13]
  • Municipal utilities and cooperatives that haven't opted in. These areas offer no choice of retail provider. ERCOT names Austin and San Antonio among them.[^13] By statute, a municipal utility's governing body decides "when or if" to offer customer choice.[^14] Co-ops set their own retail rates. The PUCT has only appellate jurisdiction over municipal retail rates and regulates non-competing co-ops only for limited purposes.[^15] The pro forma tariff won't govern your extension here. The provider's own line-extension policy will.

The muni policies can differ sharply from the TDU tariffs. Austin Energy "collects 100% of the costs for line extensions and new infrastructure associated with requests for new electric service," with an exemption only for certain affordable housing.[^11] CPS Energy in San Antonio charges customers for new infrastructure under its own Line Extension Policy.[^16] Confirm the provider before you fall in love with a parcel.

Step 2: Run two tracks in competitive areas, wires and supply

In TDU territory, the utility bills your chosen REP for delivery charges, and the REP passes them through. Construction charges are the exception: the utility bills those directly to whoever requested the work, and they stay your responsibility even if you change REPs.[^10] Plan for two parallel workstreams:

  • the TDU extension (design, a facility extension agreement, and any contribution in aid of construction, or CIAC)
  • the REP supply contract (energy, plus passed-through delivery and transmission charges)

You'll need a REP in place to take service. Don't leave it for the last month.

Step 3: Make a detailed request, early, with real service-voltage assumptions

Under the pro forma tariff, the utility must give an estimated completion date and estimated cost within ten business days of receiving a detailed request, unless both sides agree otherwise.[^10] That's an estimate, not a commitment. The tariff also tells requesters to get "the phase and voltage of the service available before committing to the purchase of motors or other equipment."[^10] Take that literally. Don't release switchgear orders until the utility has confirmed service voltage.

Step 4: Understand who pays for what

This is where data center owners get surprised most often. Under the pro forma tariff, the utility may require a Facility Extension Agreement and keeps title to the facilities it installs.[^10] You get an allowance, and costs above it may require a CIAC.[^10] The allowance amounts and rules sit in each utility's own tariff chapter, so the details vary.[^10]

The allowance depends on service class and voltage, and the differences are large. Current tariff figures, which change in rate cases:

  • Oncor: $291/kW for secondary service, $177/kW for primary distribution-line service, $5/kW for primary substation service, and $3/kW for transmission service. The transmission factor covers only metering and capacitors.[^17] Oncor applies the factor to its own estimate of your maximum 15-minute demand.[^17]
  • TNMP: $356/kW for secondary loads over 9 kW and $225/kW for primary service.[^19]
  • AEP Texas: $552/kW for general service over 10 kW, $379/kW for primary line, and $249/kW for primary substation. AEP also weighs other "Facilities Extension Factors."[^20]
  • CenterPoint: the standard allowance is based on distance, not dollars per kW: up to 1,000 feet of three-phase overhead extension from the nearest suitable existing facility.[^18]

As an illustration only, using Oncor's factors at 3 MW before any tax or franchise-fee adjustments: roughly $873,000 of allowance at secondary, $531,000 at primary distribution-line, and $15,000 at primary substation.[^17] The service class your utility assigns can move your CIAC by hundreds of thousands of dollars.

Redundancy is generally paid in full by the owner. The pro forma tariff lists two-way feeds, transfer switches, multiple points of delivery, and redundant facilities as examples of non-standard facilities.[^10] In practice the two largest TDUs don't let the allowance help:

  • Oncor: unused allowance can't be "used to reduce the cost for installation of non-standard Delivery System facilities." You pay "the total estimated cost of all non-standard facilities less the cost of standard facilities."[^17]
  • CenterPoint: the standard allowance is unavailable for "Premium Service," which covers back-up, stand-by, and redundant service. Premium Service requires a non-refundable, up-front pre-construction study at your expense. It also adds a Monthly Fixed Charge, set case by case, for "reservation of distribution capacity on alternate circuits."[^18] A second feed there is a recurring operating cost, not just a one-time CIAC.

Transmission-voltage service at 2–5 MW is the exception, not an option on a menu. CenterPoint requires transmission service only when a load "cannot otherwise be economically served from Company's Distribution Voltage system." In that case the customer pays all extension costs and builds, owns, and maintains its own substation to CenterPoint's specifications.[^18] If transmission voltage does come up, the pending §39.170(a) curtailment-protocol work applies too.[^1][^7]

Step 5: Get written agreements for anything that can parallel the grid

Under the pro forma tariff, you may not connect a power source that "may permit Electric Power and Energy to flow into the Delivery System" without a written agreement with the utility.[^10] Raise closed-transition transfer, generator soft-loading, and battery storage early. CenterPoint also makes the allowance unavailable for extensions "solely for the interconnection of distributed generation."[^18]

Where Schedule Risk Really Lives at 2–5 MW

Escaping a 75 MW study process doesn't remove timeline risk. It moves it. The following is general planning guidance from our side of the table, not data from any specific project:

  • The utility's date is an estimate. For non-residential extensions, the tariff says work "should be completed within the time estimated by Company."[^10] Get whatever written commitment the utility will give, and treat verbal dates as nonexistent.
  • Transformation can be long-lead. A Congressional Research Service report cites a 2024 national laboratory finding that distribution transformer orders were taking two years, a fourfold increase over pre-2022. It also cites an industry consultancy's estimate that waits had fallen to 30 weeks by the second quarter of 2025.[^21] Ask who furnishes the transformation at your point of delivery and what its current lead time is. Oncor's direct cost for standard extensions includes the utility's transformers.[^17] At transmission voltage in CenterPoint territory, the substation is yours.[^18]
  • Phasing is honest, and over-forecasting has a bill attached. A request that steps from 2 MW to 5 MW is a different conversation than 5 MW on day one. Don't inflate the number to "reserve capacity." The tariffs claw it back:
    • Oncor: if your estimated load "has not materialized" within four years, Oncor may recalculate CIAC and charge a "non-utilization charge." It asks for a load profile or load ramp document.[^17]
    • TNMP: the facility extension agreement can run up to 36 months. TNMP may require a letter of credit or surety equal to the standard allowance, and charges an under-utilization fee if the maximum kW isn't realized.[^19]
    • AEP Texas: if estimated loads "may not be realized, the Standard Allowance will be adjusted accordingly."[^20]
  • Easements and permits are schedule items. CenterPoint puts easement, right-of-way, and FAA marker costs on the customer.[^18] AEP Texas may bill permit costs such as railroad, Corps of Engineers, and highway permits.[^20]
  • Late changes reset the clock. Changing service voltage, load, or the point of delivery after the estimate invites a new one.
  • "Power available" needs paper behind it. A broker's listing isn't a utility cost estimate or an executed extension agreement.

We covered the broader version of this in why the interconnection queue is your critical path. The principle holds at sub-5MW scale, even when the formal process is a utility extension rather than an ERCOT study. Power Is the New Real Estate covers power-first site strategy more generally. Scale Matters explains why sub-5MW projects shouldn't be planned like small hyperscale builds.

Questions to Ask Before You Commit to a Site

Put these in writing and keep the answers in your site file:

  1. Is this parcel in ERCOT? Who serves it? Is it competitive, or a muni/co-op that hasn't opted in? If competitive, when do we need a REP in place to energize?
  2. What service class and voltage will you serve us at (secondary, primary line, primary substation, transmission), and what's your standard allowance for it? Ask for the tariff section in writing.
  3. What load ramp are you basing the allowance and CIAC on? What non-utilization terms, surety, or agreement term apply if we ramp slower?
  4. How do you price a second feed? Is there a pre-construction study fee, and is there a recurring monthly charge?
  5. Who furnishes and owns the transformation at our point of delivery, and what's the current lead time?
  6. What written agreement do you require for closed-transition transfer, generator paralleling, or battery storage?
  7. What easements, rights-of-way, permits, or site improvements are on us, and on what schedule?
  8. Does our site share a campus or point of delivery with other load, and what's the total expected peak at that site?
  9. Beyond the ten-business-day estimate, what written commitment on cost and completion will you give?
  10. For the REP: how will 4CP transmission charges be passed through, and how would a Project 58000 outcome flow into our contract?

Asking these before site control, rather than after, is what separates a credible energization date from a hopeful one.

Where an Independent Owner's Rep Fits

At this scale, nobody else at the table has the job of reconciling the utility's estimate, the REP contract, your design team's one-line, and your schedule. The utility has its tariff. The REP has its contract. The designer has a scope. The contractor has a contract. Nobody is paid only to ask whether all of them agree.

That's the role we play. NextGen Mission Critical is an owner's representative only. We don't design, we don't build, and we don't take construction margins. On power, we start at site selection. We help owners confirm who serves a site, frame the utility request, and test "power available" claims before capital is committed. Our power-first site selection work produces a power feasibility summary for each candidate site. Our owner's representative service carries that thread through design, procurement, construction, and commissioning, so the energization date in your schedule stays tied to what the utility has actually committed.

If you're weighing a Texas site in the 2–5 MW range, we're glad to talk through what you're hearing from the utility and what to ask next.

Frequently Asked Questions

Does Texas SB 6 apply to a 5 MW data center?

Generally, no. SB 6's large-load interconnection standards apply only above a demand threshold, which the statute sets at 75 MW unless the PUCT determines a lower threshold is necessary.[^1] The PUCT's rule applies at 75 MW or more at a single site, at any voltage.[^5] One exception: if your 5 MW sits on a campus whose total load reaches 75 MW, the site can be covered.[^6] Also, §39.170(a) applies to transmission-voltage customers without a MW floor, and its implementation is pending.[^1][^7]

Does ERCOT's Large Load Interconnection Process apply to sub-5MW data centers?

No. ERCOT defines a Large Load as 75 MW or more at a single site and states that its formalized process does not apply to loads under 75 MW.[^3]

Who do I work with to interconnect a 2–5 MW data center in Texas?

In competitive ERCOT areas, you work with the transmission and distribution utility for the wires and a retail electric provider for supply.[^10][^13] In municipal or co-op areas that haven't opted in to competition, such as Austin and San Antonio, you work with that utility alone, under its own policies.[^13][^15]

Who pays for utility upgrades for a small data center in Texas?

You receive an allowance that depends on your utility and service class, and you pay a contribution in aid of construction for costs above it.[^10][^17] Redundant service such as a second feed is generally paid in full by the owner. Oncor won't apply the allowance to non-standard facilities, and CenterPoint makes it unavailable for Premium Service, which also carries a monthly charge.[^17][^18] Austin Energy collects 100% of line-extension costs.[^11]

Is the PUCT's SB 6 large-load rule final?

Yes. 16 TAC §25.194 was adopted September 18, 2026, effective October 8, 2026. The standard interconnection agreement, the demand management service, and the transmission cost allocation rulemakings were still pending as of October 21, 2026.[^5][^6][^7]

Sources

[^1]: Texas Legislature, S.B. 6, 89th Legislature (R), Enrolled version (Utilities Code §37.0561, §39.169, §39.170; Section 6). https://www.capitol.texas.gov/tlodocs/89R/billtext/html/SB00006F.htm

[^2]: Texas Legislature Online, 89(R) History for SB 6 (signed by the Governor and effective immediately, 06/20/2025). https://capitol.texas.gov/BillLookup/History.aspx?LegSess=89R&Bill=SB6

[^3]: ERCOT, Questions and Answers About the Large Load Interconnection Process, Rev. 12.15.25 (PDF). The same document notes separate ERCOT modeling standards for loads of 25 MW or greater (NPRR1234), which is also well above the sub-5MW range. https://www.ercot.com/files/docs/2025/12/24/Large-Load-Interconnection-Process-Q-A.pdf

[^4]: ERCOT, Large Load Integration (accessed Oct 21, 2026). https://www.ercot.com/services/rq/large-load-integration/

[^5]: PUCT, 16 TAC §25.194, Large Load Interconnection Standards, effective 10/08/2026 (P-58481) (PDF). https://ftp.puc.texas.gov/public/puct-info/agency/rulesnlaws/subrules/electric/25.194/25.194.pdf

[^6]: PUCT, Project No. 58481, Order Adopting New 16 TAC §25.194 (PDF; loads below 75 MW at pp. 4–5; separate sites at p. 45; multiple ESI IDs at pp. 71–72). https://ftp.puc.texas.gov/public/puct-info/agency/rulesnlaws/subrules/electric/25.194/58481adt.pdf

[^7]: PUCT, Project No. 58317, SB 6 Implementation Roadmap, Updated September 2026 (filed Sept 22, 2026; Item 69) (PDF). https://interchange.puc.texas.gov/Documents/58317_69_1685516.PDF

[^8]: ERCOT, NOGRR282, Large Computational Load Ride-Through Requirements (approved by PUCT 07/09/2026; effective 08/01/2026). https://www.ercot.com/mktrules/issues/NOGRR282

[^9]: ERCOT, NPRR1308, PUCT Report (07/09/2026), §2.1 definition of Large Computational Load (DOCX). https://www.ercot.com/files/docs/2026/07/11/1308NPRR-18-PUCT-Report-070926.docx · Issue page: https://www.ercot.com/mktrules/issues/NPRR1308

[^10]: PUCT, 16 TAC §25.214 (PDF), and the §25.214(d)(1) Pro-forma Retail Delivery Tariff (PDF; §3.3 Description of Service; §5.6.2 Parallel Operation; §5.7 Facilities Extension Policy; §5.8 Billing). https://ftp.puc.texas.gov/public/puct-info/agency/rulesnlaws/subrules/electric/25.214/25.214.pdf · https://ftp.puc.texas.gov/public/puct-info/agency/rulesnlaws/subrules/electric/25.214/25.214fig(d)(1).pdf

[^11]: Austin Energy, Design Criteria Manual (effective Dec 12, 2023), §1 "AE Line Extension Policy" (PDF). https://austinenergy.com/-/media/project/websites/austinenergy/contractors/designcriteriamanual.pdf

[^12]: ERCOT, About ERCOT ("about 90 percent of the state's electric load"). https://www.ercot.com/about

[^13]: ERCOT, Grid Insights: Retail Market (Nov 2025) (PDF; NOIE areas include Austin and San Antonio; REPs and TDSPs). https://www.ercot.com/files/docs/2025/11/17/ERCOT-Grid-Insights-Retail-Market.pdf

[^14]: Texas Utilities Code (PURA) Chapter 40, §40.051. https://statutes.capitol.texas.gov/docs/UT/htm/UT.40.htm

[^15]: PUCT, Consumer FAQ: Munis and Co-ops. https://puc.texas.gov/consumer-help/faq/muni/

[^16]: CPS Energy, Customer Construction Cost: Contribution in Aid of Construction (CIAC). https://www.cpsenergy.com/en/construction-and-renovation/customer-construction-cost.html

[^17]: Oncor Electric Delivery, Tariff for Retail Delivery Service (PDF; §6.1.1.1.3, .5, .6 Rider TCRF billing demand; §6.1.2.2.6.1 standard allowance factors, effective June 1, 2026; §6.1.2.2.6.4; §6.1.2.2.7; §6.3 Facility Extension Agreement Article II). https://www.oncor.com/content/dam/oncorwww/documents/about-us/regulatory/tariff-and-rate-schedules/Tariff%20for%20Retail%20Delivery%20Service.pdf.coredownload.pdf

[^18]: CenterPoint Energy Houston Electric, Tariff for Retail Delivery Service (Rev. 32, eff. 05/18/26) (PDF; §6.1.1.1.3 transmission billing demand; Sheet 6.16 Subsections 2.1, 2.2, 2.3, 2.5; §6.1.2.3.3 Premium Service). https://assets.centerpointenergy.com/api/public/content/tariff-for-retail-delivery-service-9-1-2026.pdf

[^19]: Texas-New Mexico Power, Tariff for Retail Delivery Service (PDF; §6.1.2.2 facilities extension agreement and funding arrangements; §6.1.2.2.3 standard allowances, effective Sept 13, 2026). https://tnmp.com/sites/default/files/inline-images/TNMP%20Retail%20Tariff%20%2858964%29.pdf

[^20]: AEP Texas, Tariff for Electric Delivery Service (PDF; §6.1.2 Facilities Extension Allowances and Factors). https://www.aeptexas.com/lib/docs/ratesandtariffs/Texas/AEP_TEXAS_TARIFF_Eff_Sept_29_2026v1.pdf

[^21]: Congressional Research Service, Electricity Distribution Transformers: Supply, Tariffs, and Policy Options, R48933 (Apr 23, 2026) (PDF). https://www.everycrsreport.com/files/2026-04-23_R48933_7b9be639e3196e5282d3817519df9f1ed2778302.pdf

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