Every federal development described in the first three alerts of this series – the PJM Interconnection (PJM) co-location orders, the Southwest Power Pool (SPP) High Impact Large Load (HILL) framework, the DOE Rulemaking Proposal’s proposed assertion of jurisdiction over large-load interconnections, and the new transmission service requirements and gross demand billing mandates – reinforces the same observation: the structural advantages of the Electric Reliability Council of Texas (ERCOT) for data center behind-the-meter generation and co-located load arrangements (collectively, BTM) have widened with each new federal regulatory action.
Texas is not a regulatory vacuum. Senate Bill 6, the ERCOT batch study transition, weatherization mandates, and multiple active rulemakings before the Public Utility Commission of Texas (PUCT) add genuine compliance complexity. But the starting position, complete avoidance of Federal Energy Regulatory Commission (FERC) jurisdiction over wholesale sales, transmission service, and interconnection, eliminates the entire federal regulatory overlay that defines the cost and timeline for BTM generation in every other organized market in the United States. For developers, sponsors, and lenders evaluating where to deploy capital for data center power infrastructure, that structural advantage deserves careful analysis.
This alert examines the Texas/ERCOT regulatory framework, the recent legislative and regulatory changes that add new requirements, and the practical considerations that determine whether the structural advantage translates into a project-level economic advantage for a given development.
The ERCOT Anomaly
Approximately 90% of Texas electricity load operates within ERCOT, which is intentionally isolated from the interstate grid through limited, asynchronous DC ties. ERCOT operates as an independent system operator but does not function as a regional transmission organization (RTO) under FERC oversight. Electricity generated, transmitted, and consumed entirely within ERCOT falls outside FERC’s jurisdiction over “the sale of electric energy at wholesale in interstate commerce” and “the transmission of electric energy in interstate commerce” under Section 201(b)(1) of the Federal Power Act (FPA).
The jurisdictional consequences are significant and pervasive. Electricity sales within ERCOT, including sales from a third-party generator to a data center operator, do not require FERC market-based rate (MBR) authorization. They do not trigger the co-location transmission service frameworks imposed in PJM, which administers the nation’s largest wholesale electricity market across 13 states, and SPP, which manages the wholesale market and transmission grid across portions of 14 states in the central United States. They are not subject to the DOE Rulemaking Proposal’s proposed standardized interconnection procedures for large loads. They are not subject to FERC-mandated gross demand billing for ancillary services. And they are not subject to the interconnection queue backlogs and multi-year study timelines that characterize FERC-jurisdictional markets.
The jurisdictional analysis that occupies substantial transactional attention in PJM territory (described in detail in Alert 3) is largely inapplicable in ERCOT. The sale-for-resale trigger under the FPA does not apply because the sale does not occur in interstate commerce. The transmission nexus does not apply because the electricity does not move on the interstate grid. The structuring questions about islanded versus synchronized configurations, about affiliate versus arm’s-length arrangements, about prophylactic MBR filings and declaratory orders, are questions that ERCOT developers generally do not need to answer.
For FERC practitioners and counsel accustomed to navigating the federal overlay, the simplicity of the ERCOT framework can be disorienting. The regulatory environment is not unregulated; it is differently regulated, with state-level oversight through the PUCT and ERCOT’s own protocols substituting for the federal framework. Understanding what those state-level requirements are, and how they have changed since 2025, is essential for developers who plan to capture the structural advantage rather than merely assume it.
Private Use Networks: The Established Pathway
ERCOT’s protocols establish Private Use Networks (PUNs) as the primary regulatory mechanism for BTM generation serving dedicated loads. A PUN is defined as an electric network connected to the ERCOT transmission system at a single point that serves only the owner’s load without third-party sales.
PUNs offer several advantages for data center BTM projects. They avoid FERC jurisdiction entirely because the arrangement operates within a non-FERC-jurisdictional market. The primary power flow occurs within the private network, with the ERCOT grid interconnection used only for backup or supplemental service, which simplifies the interconnection process relative to a front-of-meter generator seeking full transmission access. PUN operators control the dispatch of generation to serve their load without ERCOT market participation requirements, though voluntary participation is permitted and may enhance project economics (discussed below). To qualify as a PUN, the arrangement must satisfy ERCOT’s single-entity ownership requirement: the generation, the load, and the interconnecting facilities must be owned or controlled by the same entity. Developers pursuing a third-party structure (in which GenCo and DataCo are separate entities) cannot use the PUN pathway without consolidating ownership, whether through a single-purpose entity that owns both the generation and the data center, a master lease structure in which one entity holds operational control of both, or another arrangement that satisfies the single-entity requirement. The structuring choice has implications for tax ownership, financing, and the REP certification analysis discussed below, and should be evaluated with tax counsel and the project’s financing parties before the ownership structure is finalized. Establishing a PUN also requires notification to ERCOT and verification of single-entity ownership, not PUCT certification or extensive regulatory proceedings.
The PUN structure directly addresses the cost allocation and reliability concerns that animated the Talen Order and the PJM Order (each described in Alert 1). Because the arrangement operates entirely within ERCOT, there is no federal transmission cost allocation to dispute, no capacity market impact to study, no interstate cost shift to litigate, and no intervenor standing to challenge the arrangement before FERC. The developer’s regulatory burden is limited to state-level requirements, which, while meaningful, are substantially less complex and less costly than the federal overlay applicable in PJM, SPP, and other organized markets.
For sponsors evaluating the ERCOT opportunity, the PUN structure has a particular advantage for project finance. The absence of federal regulatory risk simplifies the credit analysis: there is no FERC reclassification risk, no risk of unanticipated transmission charges from RTO tariff changes, and no regulatory change trigger tied to the DOE Rulemaking Proposal or PJM compliance proceedings. Lenders can underwrite the project against ERCOT market risk, Texas regulatory risk, and operational risk without layering federal regulatory uncertainty on top. That simplification may translate into more favorable financing terms, tighter spreads, and fewer regulatory representations and covenants in credit documentation relative to comparable projects in FERC-jurisdictional markets.
Senate Bill 6: The New Legislative Framework
The 89th Texas Legislature enacted Senate Bill 6 (SB 6), signed by Governor Greg Abbott on June 20, 2025, establishing a comprehensive regulatory framework for large-load interconnection within ERCOT. SB 6 represents the most significant legislative development for data center power in Texas since the deregulation of the retail market, and developers should understand its requirements in detail.
SB 6 imposes several requirements directly relevant to BTM data center generation. Entities interconnecting after December 31, 2025, must develop curtailment protocols and install equipment enabling remote disconnection by ERCOT during grid emergencies. Load forecasting requirements apply, obligating large-load customers to provide ERCOT with detailed demand projections that feed into ERCOT’s system planning. Ramp rate limitations may apply to large loads whose sudden changes in consumption could affect grid frequency and stability.
SB 6 also directs the PUCT to implement the legislation through multiple active rulemakings. The PUCT assigns each rulemaking a numbered “Project” docket, which functions similarly to a FERC docket number as the official proceeding identifier. Project 58481 addresses interconnection standards for large loads. Project 58479 addresses net-metering rules for co-located generation and load. Additional proceedings address large-load forecasting criteria, reliability contributions, and coordination between ERCOT and serving utilities. These rulemakings are ongoing, and the implementing rules will define the practical compliance requirements for BTM generation going forward. The final rules may differ from the statutory framework in ways that affect project design and economics.
For developers, SB 6 represents both a compliance burden and a political signal. The compliance burden is real: curtailment protocols, remote disconnect, load forecasting, and potential ramp rate limitations add operational requirements and equipment costs that did not exist before 2026. But the political signal may be equally important. SB 6 reflects the Texas legislature’s decision to accommodate data center load growth within ERCOT rather than restrict it. The legislature chose to impose operating conditions on large loads rather than to block or penalize them. That legislative posture, combined with ERCOT’s structural FERC avoidance, suggests that Texas intends to remain a preferred jurisdiction for data center development, subject to requirements designed to protect grid reliability and existing ratepayers.
For sponsors and lenders, SB 6’s requirements should be modeled into project economics from the outset. Curtailment obligations affect revenue projections: if the facility is required to reduce load during grid emergencies, the data center’s availability (and therefore its revenue) may be reduced during the highest-value periods. Remote disconnect equipment adds capital cost. Load forecasting compliance requires dedicated personnel or systems. These costs are modest relative to the federal regulatory burden in PJM or SPP, but they are not zero, and they should not be ignored.
The curtailment obligation also has implications for the offtake or service level agreement between the generation provider and the data center customer. If ERCOT orders load curtailment during a grid emergency, the resulting reduction in data center availability may constitute an event under the service level agreement (SLA) unless the agreement expressly carves out grid-emergency curtailment as an excused event. Developers and their counsel should ensure that the offtake agreement, the SLA, and the force majeure provisions are drafted to allocate curtailment risk consistently, and that the data center customer understands the frequency and duration of curtailment events that SB 6 may produce.
Congressional staff monitoring data center energy policy should note SB 6 as a potential model for federal approaches. The legislation’s framework of accommodating large loads while imposing reliability and cost-sharing conditions reflects a policy balance that may inform the DOE Rulemaking Proposal and future federal legislation. To the extent that the DATA Act (described in Alert 2) proposes a complete exemption from federal regulation for off-grid facilities, SB 6 represents an alternative approach: regulation that is calibrated to the risks rather than eliminated entirely.
The ERCOT Batch Study Transition
ERCOT’s large-load interconnection process is undergoing fundamental reform. The historical process was serial: interconnection requests were studied individually in the order received. That process functioned adequately when ERCOT received fewer than 20 requests per quarter. It cannot function at current volumes, which have reached close to 100 requests per quarter, driven overwhelmingly by data center and industrial load growth.
ERCOT is transitioning to a batch study process in which interconnection requests are grouped and studied together, analogous (though not identical) to the cluster study process that FERC Order 2023 imposed on FERC-jurisdictional transmission providers. A “Batch Zero” mechanism addresses the backlog of existing requests submitted under the serial process. ERCOT has indicated a target effective date of August 1, 2026, following anticipated ERCOT Board approval.
The transition creates near-term scheduling uncertainty for developers with projects in the queue. Projects submitted under the serial process may be rolled into Batch Zero or studied under transitional procedures that differ from both the old serial process and the new batch process. Developers should confirm the status of their interconnection requests and understand how the transition affects their study timeline, cost obligations, and queue position.
For developers who have not yet submitted interconnection requests, the batch study framework may offer advantages over the serial process: studies conducted in clusters can identify shared infrastructure needs and allocate costs more efficiently, and the batch process may ultimately produce faster study completion for projects that enter the queue together. But the transition period itself may be slower than either the old or new steady-state process, because ERCOT is simultaneously processing legacy serial requests, Batch Zero transitional requests, and early batches under the new framework.
REP Certification and Third-Party Arrangements
Texas’s deregulated retail electricity market allows customers in competitive service areas to choose their electricity provider. However, entities providing retail electric service must obtain Retail Electric Provider (REP) certification from the PUCT. The certification requirement applies to entities that sell electricity at retail to end-use customers, with certain exemptions.
The critical question for third-party BTM generation in Texas is whether GenCo providing power to DataCo constitutes retail electric service requiring REP certification. If GenCo and DataCo are the same entity (single-entity self-supply through a PUN), the question does not arise, because no retail sale occurs. If GenCo and DataCo are separate entities with arm’s-length contracts, the PUCT could potentially characterize the arrangement as a retail sale requiring REP certification.
The PUCT has not required REP certification for certain single-customer or integrated arrangements. Texas law provides a streamlined certification path for providers serving large individual customers, and the PUCT has generally taken a permissive approach to industrial arrangements that do not involve service to the general public. However, the regulatory analysis is fact-specific, and the PUCT’s approach may evolve as data center power arrangements become more common and more closely scrutinized.
Developers pursuing third-party BTM generation in ERCOT should evaluate whether REP certification is required for their specific arrangement, whether an existing exemption applies, or whether obtaining a streamlined certification as a precautionary measure may be advisable. The REP certification process is not particularly burdensome (compared to, for example, obtaining MBR authorization from FERC), and the compliance obligations are manageable for a sophisticated operator. The risk of operating without certification when it is required, which could result in enforcement action and potential unwinding of the arrangement, is likely not worth the cost savings of avoiding the certification process.
Weatherization and Resilience Requirements
The February 2021 winter storm that caused widespread blackouts in Texas, known as Winter Storm Uri, prompted significant regulatory reforms that apply to BTM generation as well as grid-connected facilities.
Generation facilities and associated fuel supply infrastructure must implement weatherization measures to operate during extreme weather. Requirements include cold weather preparedness (insulation, freeze protection equipment, windbreaks, auxiliary fuels), freeze protection for natural gas production and delivery infrastructure serving electric generation in ERCOT, heat preparedness for summer peak conditions, and annual weatherization inspections, declarations of preparedness, and certifications. ERCOT is tasked with inspecting for compliance and reporting violations to the PUCT.
BTM natural gas generation must demonstrate reliable fuel access through firm supply contracts, on-site storage, or both. Fuel assurance has become a critical regulatory and operational requirement since Uri, and developers should expect scrutiny of their fuel supply arrangements during the interconnection and registration process.
These requirements add cost and operational complexity. Cold and heat weatherization, fuel assurance, annual compliance certifications, and ERCOT inspections represent ongoing obligations that must be budgeted and managed. For lenders, weatherization compliance is a diligence item: the financing documents should include representations regarding compliance with applicable weatherization standards, covenants requiring ongoing compliance, and notice requirements if the facility is found noncompliant or faces enforcement action.
For data centers requiring high reliability (which is effectively all of them), the investment in weatherization is prudent regardless of the regulatory mandate. Winter Storm Uri demonstrated that Texas weather can produce extreme conditions that overwhelm unprepared facilities. A data center that loses power during a winter storm faces not only the direct cost of the outage but also the reputational and contractual consequences of failing to meet uptime commitments. Weatherization should be designed into the facility from the outset, not treated as a compliance afterthought.
Resource Adequacy: The Energy-Only Market
ERCOT operates an energy-only market without a capacity market, a structural distinction from PJM, ISO New England (ISO-NE), and other organized markets where capacity obligations play a significant role in the economics and regulation of generation.
In an energy-only market, generators are compensated only for the energy and ancillary services they actually provide, not for maintaining available capacity. There are no must-offer obligations requiring generators to bid into a capacity auction, no capacity performance penalties for failing to deliver during peak conditions, and no obligation to commit BTM generation resources to a capacity market. ERCOT relies instead on scarcity pricing, allowing energy prices to reach $5,000/MWh during tight supply conditions, to incentivize adequate generation investment and availability.
For BTM generation in ERCOT, the energy-only structure has several implications. There are no capacity market obligations to navigate, which eliminates a significant source of regulatory complexity and cost that applies in PJM and other organized markets with mandatory capacity obligations, including ISO-NE and the New York Independent System Operator (NYISO). BTM generators can participate voluntarily in ERCOT’s real-time energy market to monetize surplus generation, and can provide ancillary services (regulation, responsive reserves, non-spinning reserves) for additional revenue, but participation is entirely optional. During tight supply conditions, PUN operators capable of exporting surplus generation to the grid can capture substantial scarcity pricing revenue, though this opportunity is intermittent and should not be the primary basis for project economics.
The energy-only structure is itself evolving. The Texas legislature has authorized the PUCT to establish reliability mechanisms under Texas Utilities Code § 39.1594, and the Performance Credit Mechanism (PCM) or similar constructs may introduce capacity-like obligations that could affect BTM generation economics. The PCM, as currently contemplated, would credit generators for providing capacity during critical periods, potentially creating a revenue stream for BTM generators willing to offer excess capacity to the market. It could also create an obligation or incentive structure that reduces the operational flexibility that PUN operators currently enjoy. Developers with long-dated investments in ERCOT should monitor the PUCT’s implementation of these reliability mechanisms and consider how potential changes to the energy-only structure could affect project economics over the facility’s operating life.
ERCOT Market Participation: The Revenue Opportunity
While PUNs can operate independently of ERCOT’s markets, voluntary market participation may meaningfully enhance project economics for facilities with surplus generation capacity or operational flexibility.
Energy market sales provide a straightforward revenue stream when the data center’s load is below the generation facility’s output. For a facility sized with a 15 to 30 percent reserve margin (as described in Alert 3 for islanded configurations), the surplus capacity during normal operations represents potential energy market revenue. ERCOT’s real-time market clears at marginal cost, with prices that can be highly volatile, ranging from near-zero during low-demand periods to $5,000/MWh during scarcity events.
Ancillary services represent a potentially higher-value revenue stream for generation capable of rapid response. Responsive reserves, regulation services, and non-spinning reserves are procured by ERCOT through competitive markets. BTM generation that can modulate output or redirect generation between the data center and the grid may be well-positioned to provide these services, though doing so requires operational coordination between the generation facility and the data center’s power management systems.
During grid emergencies, ERCOT’s Reliability Deployment Price Adder (RDPA) can produce scarcity pricing that makes emergency exports extremely valuable. A PUN capable of reducing its grid draw or exporting surplus generation during these events can capture significant revenue in a short period.
Market participation requires registration as a Qualified Scheduling Entity (QSE) and compliance with ERCOT protocols. For sophisticated operators with the systems and personnel to manage the complexity, the revenue opportunity may be meaningful. For operators whose primary focus is data center uptime rather than power market optimization, the complexity may not be justified. The decision should be evaluated as part of the project’s overall financial model, with realistic assumptions about market price frequency, dispatch flexibility, and the operational burden of QSE compliance.
For sponsors and lenders, ERCOT market revenue adds an upside component to the project’s cash flow projections but introduces commodity price exposure that complicates the credit analysis. Lenders may wish to structure market revenue as an equity upside rather than a base-case debt service assumption, or may require hedging arrangements or revenue reserves to mitigate the volatility.
The Cost Differential: Quantifying the Structural Advantage
For sponsors and lenders evaluating the ERCOT opportunity relative to FERC-jurisdictional markets, the cost differential is the central analytical question. The structural advantage described throughout this alert translates into project-level economics through several channels.
In PJM, a 500 MW data center with dedicated co-located generation would face mandatory transmission service charges under one of the four service options established by the PJM Order (described in Alert 1), gross demand billing for ancillary services regardless of the transmission service election, interconnection study costs and potential network upgrade obligations (which can reach into the hundreds of millions of dollars for large projects in constrained areas), and the administrative and legal costs of navigating the co-location tariff framework, the compliance filings, and potential intervenor challenges. The aggregate annual cost of these federal regulatory obligations could amount to tens of millions of dollars for a facility of this scale.
In ERCOT, the same facility would face PUCT registration (straightforward), ERCOT interconnection (under the batch study process), SB 6 compliance (curtailment protocols, remote disconnect, load forecasting), weatherization, and standby/backup utility tariffs. These costs are real but materially lower than the PJM regulatory burden. A reasonable estimate of the annual cost differential, accounting for transmission charges, ancillary service billing, and regulatory compliance, could range from $20 million to $50 million or more, depending on the specific PJM zone, the transmission service election, and the extent of network upgrade obligations.
That differential compounds over a 20-year project life. At a 500 MW scale, the present value of the regulatory cost savings from ERCOT versus PJM could represent hundreds of millions of dollars. This is a significant factor in the current capital migration to Texas, and the structural advantage is likely to persist even as SB 6 and the batch study transition add new compliance requirements.
The cost differential is not the only factor in siting decisions. Fiber connectivity, water availability, labor markets, tax incentives, land costs, community receptivity, and the developer’s existing infrastructure and relationships all play a role. But for developers whose siting analysis can accommodate Texas, the regulatory cost advantage is large enough to be dispositive for many projects.
The tax analysis reinforces rather than offsets the structural advantage. Credits under Section 45Y and Section 48E of the Inflation Reduction Act of 2022 (IRA) are technology-based, not geography-based, and are equally available for qualifying generation in ERCOT as in FERC-jurisdictional markets. Texas locations may also qualify for the energy community bonus credit, a 10% adder available for projects sited in qualifying census tracts, many of which are concentrated in the Permian Basin, along the Gulf Coast, and in former coal communities. Sponsors evaluating ERCOT against other jurisdictions should incorporate the energy community designation into their siting analysis, as the bonus credit can materially affect project economics for qualifying locations.
The tax analysis summarized in this section is intended to identify structural considerations relevant to siting decisions, not to provide tax advice. The specific application of IRA credits, the energy community bonus, and any state-level incentives to a particular project should be confirmed by tax counsel and the sponsor’s accountants. The availability and value of these credits depend on the specific technology, ownership structure, and tax position of the sponsor, and should not be incorporated into project economics or financing assumptions without that confirmation.
Standby and Backup Service: The Utility Variable
Data centers operating PUNs typically maintain a backup connection to the local distribution utility for supplemental power, maintenance outages, and emergencies. This backup service implicates utility tariffs that vary significantly among ERCOT utilities.
Standby and backup tariffs typically include demand charges based on maximum coincident peak usage from the grid, energy charges for actual kWh consumed, backup reservation charges for maintaining capacity availability, and non-bypassable delivery charges for transmission and distribution infrastructure. The specific rate levels and structures differ materially among Texas utilities. For a large data center, the difference in annual standby costs between the most favorable and least favorable utility territory in ERCOT can amount to millions of dollars.
Texas law provides an important protection: utilities cannot prevent self-generation through prohibitive standby rates. All utility rates, including standby charges for backup service to self-generators, must be just and reasonable, and the PUCT reviews standby tariffs for cost-basis and non-discrimination. Developers who believe that a utility’s standby rates are unreasonably high or discriminatory can challenge them before the PUCT.
Utility territory selection should be a component of the siting analysis, not an afterthought. Developers should obtain and compare standby tariff schedules from the utilities serving their candidate sites, model the standby cost over the project life, and factor the result into the siting decision alongside land cost, interconnection timeline, fiber availability, and other variables.
Practical Considerations
ERCOT offers what appears to be the fastest and most cost-effective path to operational BTM generation at scale in the United States. The structural FERC avoidance, the established PUN framework, the competitive energy markets, the resource diversity (wind, solar, and natural gas), and the state’s scale and growth trajectory create a combination of advantages that no other jurisdiction currently matches.
But the advantage is structural, not absolute. SB 6 adds real compliance requirements. The batch study transition creates near-term interconnection uncertainty. Weatherization is a capital and operational cost. Standby rate differentials among utility territories can materially affect economics. The PUCT’s ongoing rulemakings will define compliance requirements that are not yet finalized. And the political environment, while currently favorable, is subject to change: the Ratepayer Protection Pledge’s “national policy” language (discussed in Alert 2) and the growing public attention to data center energy consumption create political pressures that could produce additional requirements over time.
The developers who are most likely to capture the ERCOT advantage are those who approach Texas with the same diligence they would apply to any complex regulatory environment: engaging the active PUCT proceedings, modeling SB 6 compliance costs, evaluating utility territory as a siting variable, designing weatherization into the facility, and building the project for long-term regulatory resilience rather than optimizing for the current moment.
This is the fourth in a series of seven alerts examining the regulatory frameworks applicable to data center power across multiple jurisdictions. The next alert examines Colorado’s large-load tariff and the clean energy overlay that makes Colorado the most complex jurisdiction in this series and the one most different from Texas.
This alert is intended to provide a general overview of the regulatory framework for data center power in Texas and ERCOT. It does not constitute legal advice, and the appropriate approach will depend on the specific facts, jurisdiction, and circumstances applicable to each project.
RJ Colwell is a Senior Associate at Davis Graham & Stubbs LLP in the Energy & Mining Group. His practice focuses on the regulatory, transactional, and structuring dimensions of data center power, advising data center developers, power generation companies, and their investors and lenders on FERC regulatory matters, behind-the-meter generation, co-located load arrangements, and energy infrastructure transactions. RJ can be reached at rj.colwell@davisgraham.com.