Request for Comments on Texas PUCT Draft Report Regarding Transmission Cost Recovery in the ERCOT Region

Legislative Background 

On 1 August 2025, Public Utility Commission of Texas (PUCT or the Commission) staff (Commission Staff) opened Project No. 58484, Evaluation of Transmission Cost Recovery, pursuant to Senate Bill 6 (SB 6), which requires the Commission to evaluate whether the existing methodology under Public Utility Regulatory Act (PURA) § 35.004(d) used to charge wholesale transmission costs to distribution service providers (DSPs) continues to appropriately assign costs for transmission investments and whether the Commission’s retail ratemaking practices ensure that transmission cost recovery appropriately charges system costs to each customer class. SB 6 requires the Commission to amend its rules no later than 31 December 2026, to ensure that wholesale transmission charges appropriately assign costs for transmission investment. We have previously reported on the impacts of SB 6 on large load development in the Electric Reliability Council of Texas (ERCOT).

On 16 March 2026, following a workshop and two rounds of public comments, the Commission issued a draft report (the Draft Report) providing six draft recommendations. Commission Staff invites comments on the draft recommendations, due by 13 April 2026, prior to the issuance of a final report. 

The Draft Report’s Request for Comments on Recommendations

The Draft Report identifies draft recommendations and requests the public to provide comments on the following draft recommendations: 

1. Changing the methodology for assessing wholesale transmission costs on DSPs from a four coincident peak (4CP) to a methodology utilizing a greater number of coincident peaks.
2. Lengthening the interval over which each coincident peak is measured.
3. Eliminating interconnection cost allowances for large load customers.
4. Requiring large load customers to pay a portion of system upgrade costs.
5. Requiring annual updates to the class allocation factor values used in proceedings, such as a transmission cost recovery factor (TCRF).
6. Requiring large load customers to pay a minimum demand charge based on their contracted peak demand for a period of 10 to 15 years.

Wholesale Transmission Cost Recovery

The current 4CP methodology bills DSPs based on load during four summer coincident peak intervals (June, July, August, and September). Commission Staff found that this framework does not capture winter scarcity events, that the 15-minute measurement interval likely provides too narrow a price signal, and that some types of sophisticated large industrial customers can quickly make consumption reductions in ways that reduce their transmission cost obligations (commonly known as 4CP avoidance) without a commensurate reduction in the system costs they cause. The report also raises the concern that the increasing addition of more flexible large loads (such as crypto mines and certain types of data centers) will make clear transmission cost assignment increasingly difficult utilizing the 4CP methodology. This concern arises because while these flexible large loads require significant transmission system investment and consume electricity on an order of magnitude higher than most other consumers, their flexible operating procedures allow them to quickly reduce consumption without significantly disrupting their core business functions. 

Commission Staff pointed out that in ERCOT’s wholesale energy market, demand reductions are typically expected to occur as a response to high energy prices, which signal real-time generation scarcity. However, the 4CP methodology introduces an additional and significant form of price-responsive behavior, where customers decrease demand to reduce wholesale transmission charges and not to avoid high real-time energy prices. This was a lesser issue when ERCOT summer system peaks coincided with periods of high energy prices. However, because of the increasing market penetration of renewable generation resources, this relationship has shifted and now higher prices tend to have a stronger relationship with peak net load (defined as gross load minus wind and solar generation), which typically occurs during the evening solar ramp down. Commission Staff therefore is considering changing the methodology for assessing wholesale transmission costs on DSPs to a coincident peak methodology with a greater number of coincident peaks and lengthening the interval over which each coincident peak is measured.

Retail Rate Design

The Draft Report stated that the magnitude of load in a small geographic area associated with large load customers raises important issues associated with the existing transmission cost recovery methodology. The Draft Report found that large loads are likely to need significant and extensive transmission upgrades to adequately serve them. Even a large load customer that can eliminate consumption entirely during peak intervals (4CP or otherwise) is likely to require substantial transmission system upgrade investment. Commission Staff opined that a distinct but temporary cost recovery treatment for such customers could be utilized—requiring large load customers to pay a minimum demand charge based on their contracted peak demand for a period of 10 to 15 years. After the applicable period, organic load growth would presumably develop to utilize some or all of the associated transmission buildout, and large load customers would revert to the standard rate design based on actual metered load. 

The Draft Report found this approach would ensure that large load customers’ transmission charges better reflect the uniquely disproportionate costs they cause to be imposed on the system. Under this proposal, DSPs serving large load customers would pay wholesale transmission charges as if its large load customers were on the system at the time of the 4CP or successor intervals. Investor-owned utility DSPs would then allocate their transmission costs to the transmission rate class as if the large load customers were at maximum load at the peak intervals, thereby avoiding allocating those costs to other rate classes. The Draft Report stated that requiring such treatment would ensure that large load customers pay a significant portion of the system upgrade costs they cause to be incurred, as well as for their use of the existing transmission system.

Retail Interconnection Costs

The Commission found that the current patchwork approach electric utilities in ERCOT have taken for determining the financial commitments and the direct interconnection costs that large load customers must pay has resulted in certain service areas being viewed as more favorable for siting and has contributed to difficulties in accurately forecasting load in the ERCOT transmission planning process. Additionally, to the extent that not all direct interconnection costs are treated the same, ratepayers across the ERCOT region are bearing more of the direct interconnection costs for transmission infrastructure than they should be. Commission Staff has noted that Project 58481, Rulemaking to Implement Large Load Interconnection Standards Under PURA § 37.0561, will be evaluating if the Commission should eliminate interconnection cost allowances for large load customers. 

Commission Staff is considering requiring large load customers to pay a portion of system upgrade (highway) costs, in addition to the direct interconnection (driveway) costs they currently bear through contribution in aid of construction (CIAC). Commission Staff stated, on its face, that expanding the interconnection costs to include system upgrades is an appealing approach that seems consistent with cost causation and equitable ratemaking principles. However, such an approach would be complex to administer, because, for example, it would be challenging to assign costs based on cost causation principles. For instance, it may be difficult to determine if a system upgrade that is identified in a batch study process should only be attributed to a single large load customer when the system upgrade will serve other loads on the system.

Retail Cost Allocation

The Commission found that under the current framework under which TCRF rates are calculated, the use of fixed allocation factor values, updated only in base rate proceedings, combined with the disproportionate load growth of the transmission-voltage customer class, has resulted in inequitable cost-shifting between customer classes. Commission Staff notes that the widespread deployment of Advanced Metering Systems now makes annual updates administratively feasible.

Accordingly, Commission Staff is considering requiring annual updates to the class allocation factor values used in TCRF proceedings. The Draft Report flagged Docket No. 58923, Commission Staff’s Petition to Require Annual Updates to Class Allocation Factor Values Under 16 TAC § 25.193(c), as a related pending proceeding. In that proceeding, Commission Staff has petitioned the Commission to require annual updates to TCRF class allocation factor values under the existing rule; the outcome of that docket may parallel or inform the rulemaking approach taken in this project. Commission Staff notes in the Draft Report that an additional option for resolving this issue is updating 16 TAC § 25.193 to require annual updates to class allocation factor values. 

Implications and Next Steps

The draft recommendations, if adopted, would significantly impact large load customers by requiring minimum demand charges based on contracted peak demand for up to 15 years, eliminating interconnection cost allowances, and potentially expanding CIAC to include system upgrade costs. If the Commission moves away from the 4CP methodology for transmission cost allocation, 4CP avoidance will be more difficult, impacting large commercial customers (including large loads). Utilities would face new metering and administrative obligations, including providing ERCOT with large load customer metering data and updating class allocation factor values annually.

Commission Staff invites comments on the draft recommendations, due by 13 April 2026, prior to the issuance of a final report. The Commission must amend its rules no later than 31 December 2026. Our Power practice group lawyers are available to answer any questions you may have when considering how to participate in the PUCT proceeding or understanding how these changes may impact your business.