|
|
|
|
|
Group Of Texas REPs Seek Ability To Opt Into Demand-Based Transmission Charges
The following story is brought free of charge to readers by VertexOne, the exclusive EDI provider of EnergyChoiceMatters.com
A group of Texas retail electric providers, termed the Retail Electric Providers for Affordable, Innovative Rates (REPAIR), has asked the Texas PUC to allow REPs to opt into demand-based transmission charges for all customers, including residential and other small customers, rather than being subjected to non-demand-based transmission rates
REPAIR includes Base Power Company, Tesla Energy Ventures, LLC, Octopus Energy, and Rhythm Energy
REPAIR's comments came in a Texas PUC proceeding examining transmission cost recovery
REPAIR said that a REP making such an opt-in election would receive demand-based invoices from the DSP [distribution service provider] for its total coincident-peak load contribution across all customer classes served in that territory in a manner consistent with the manner in which DSPs bill their largest customers. The election would be portfolio-wide for the REP in that DSP territory. "The REP would manage its total demand exposure and price its retail products as it sees fit within applicable retail market rules, but would not be permitted a direct passthrough of demand charges to residential customers," REPAIR said
REPAIR said, "we believe it unlikely that any REP serving residential customers would subject end-use customers to a demand charge for transmission. However, in an abundance of caution, our proposal includes a requirement that any REP that opts for demand-based treatment affirmatively intermediate the transmission demand pricing, rather than passing it through directly to the REP’s residential customers; this practice has precedent in other retail markets in the United States".
REPAIR sought to illustrate the alleged inequity, between C&I and residential customers, in the current transmission cost recovery mechanism, with the following example: "if a C&I customer reduces one megawatt of demand across demand intervals today, that load will save $68,550. If a REP, on behalf of its residential customers, does the same -- through smart thermostats, batteries, or time-of-use pricing -- it will save only $94."
REPAIR said that there is a 727:1 disproportionate benefit to C&I customers undertaking the same action as residential customers.
REPAIR also highlighted the experience in non opt-in entities in ERCOT, which face demand-based transmission-cost exposure directly for all of their customers in aggregate, contrasting such with the uptake of demand response by residential REP customers
REPAIR said, "NOIEs have invested in demand response accordingly. CPS Energy’s SmartHours and Energy Saver programs have enrolled over 180,000 residential customers with approximately 184 MW of demand response capability. Austin Energy’s Power Partner program has enrolled more than 60,000 customers with approximately 45 MW in demand reductions. Together, these programs conservatively generate approximately $3.1 million per year in estimated transmission-cost savings."
REPAIR said, "Comparable programs in REP territory are relatively undersubscribed because REPs are not exposed to transmission retail rates that provide a financial incentive to build equivalent demand response capabilities. According to ERCOT data, among residential customers, in NOIE territory 44.6% are enrolled in demand response programs, whereas in REP territory only 10.1% are enrolled. This is not a difference in technology access, customer sophistication, or program design capability. It is a difference in incentives."
REPAIR said that potential cost recovery changes included in a PUC Staff report would not materially change the structural disparity in the ability to respond to demand-based price signals for C&I versus residential customers
REPAIR said, "In particular, REPAIR is motivated by the Staff Report’s conclusion that even a move to the farthest bookend considered in the Report, 12 Coincident Peak ('12CP'), would cause a meaningful but still relatively small reduction in the transmission costs paid by residential customers, versus commercial and industrial classes ('C&I'). We calculate the magnitude of this reduction, using the residential customer percentage cost allocation change results of the staff linear linear regression analysis along with 2025 TCOS rates, peak loads, and residential meter data, at $16.73 per residential customer in competitive territory annually, with lesser-reaching reforms, such as 6CP, increasing costs by $4.82. We believe that a change to the allocative factors from 4CP to 12CP can be an important step toward fairness for residential customers like those we serve, but it should be complemented by policies that allow residential customers to engage in the same kind of demand response that larger customers and Non-Opt-In Entities ('NOIEs') do. We estimate that such a reform, whether they were responding to 4CP or 12CP, would return more than $250 per residential customer annually".
In separately filed comments, NRG Energy said that a "new paradigm" for allocating transmission system costs
should be implemented to reflect the changing nature of transmission infrastructure
development
As part of such, NRG suggested incorporating a minimum demand charge for large loads through a new rate class or
interconnection fee. NRG said that one possible rate design to better align cost causation would be to
create a separate rate class, or provide for separate rate treatment, for large load
customers, and design rates specifically for these customers (e.g., data centers)
separately from non-large load customers.
NRG suggested implementing a methodology to allocate transmission costs that, "ensures all consumers
contribute based on the utilization of the transmission system while eliminating the
ability to materially shift costs to other consumer classes." NRG said that this includes substantially
increasing the number of CPs, incorporating Non-Coincident Peaks (NCPs), and
implementing a multi-hour measurement interval duration
NRG alternatively suggested a cost allocation
ceiling for non-large load customers.
"Under such an approach, the ~$6
billion in transmission cost of service (TCOS) incurred prior to 2026 could set a baseline for non-large load contribution. The proposal would bifurcate between (i) transmission system costs
incurred prior to 2026, which reflected a 4CP methodology and gradual load growth for all
customer classes, and (ii) future years, which will certainly reflect disproportionate costs imposed
on the system by new large loads and potentially a new wholesale rate design," NRG said
NRG said, "NRG would not recommend a static
ceiling but one that would gradually increase based on organic load growth across all customer
classes over time. As broader benefits materialize, the ceiling could be adjusted further by the
Commission to maintain cost causation principles."
More specifically in terms of allocating transmission costs, NRG said that the Commission should further evaluate approaches with more CPs such as
52CP and 365CP, including multi-hour measurement intervals, and also incorporate NCPs into the
analysis to help inform the decision on a new methodology.
In separately filed comments, Vistra cited what it termed potential downsides to CP-only approaches to transmission cost allocation.
Vistra did not recommend a specific metric, CP-based or Non-CP-based, at this time
In separately filed comments, the Texas REP Coalition generally said that, "This proceeding should ensure that the overall cost allocation by class does not result in
residential and small commercial customers being allocated more of these new transmission costs [driven by large loads]
than is appropriate for their contribution to cost causation and utilization of the transmission system
-- in other words, it should be expected that the percentage allocated to smaller rate classes at the
wholesale level in the future will be lower than has historically been the case given drivers of the
current growth in transmission investment."
The Texas REP Coalition said that, "One proposal that merits further analysis would require that large loads pay a portion of the
requested interconnection demand rather than a look back on actual demand and a handful of CP
intervals over the year."
The Texas REP Coalition further said, "the Commission is correct in reviewing mechanisms that would potentially
bifurcate the cost allocation among classes at the wholesale level to include allocation of a portion
of the cost that is not based on a coincident peak methodology and includes some recognition of the
transmission costs driven by the projected presence of large loads that benefit from the grid during
off-peak conditions and that are driving investment decisions in transmission."
Project 58484
ADVERTISEMENT Copyright 2026 EnergyChoiceMatters.com. Unauthorized copying, retransmission, or republication
prohibited. You are not permitted to copy any work or text of EnergyChoiceMatters.com without the separate and express written consent of EnergyChoiceMatters.com
In Alternative Proposal, NRG Suggests Transmission Cost Ceiling For Non-Large-Load Customers
April 13, 2026
Email This Story
Copyright 2026 EnergyChoiceMatters.com
Reporting by Paul Ring • ring@energychoicematters.com
NEW Jobs on RetailEnergyJobs.com:
• NEW -- Channel Partner Manager -- Retail Energy
• NEW -- Manager of Sales, Commercial -- Retail Supplier
• NEW -- Commercial Sales Support Specialist -- Retail Supplier
• NEW -- Channel Partner Manager - TX -- Retail Supplier
• NEW / Refreshed 2/24/26 -- Manager, ISO Coordination (electricity), Retail Supplier
|
|
|
|
|