TITLE 16. ECONOMIC REGULATION

PART 2. PUBLIC UTILITY COMMISSION OF TEXAS

CHAPTER 25. SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS

SUBCHAPTER C. INFRASTRUCTURE AND RELIABILITY

The Public Utility Commission of Texas (commission) adopted new 16 Texas Administrative Code (TAC) §25.65, relating to Firming Program Requirements for Electric Generation Facilities in the ERCOT Region, with changes to the proposed text as published in the August 15, 2025 issue of the Texas Register (50 TexReg 5287). The new rule implements Public Utility Regulatory Act (PURA) §39.1592 as enacted by House Bill (HB) 1500 during the Texas 88th Regular Legislative Session. The new rule will establish performance requirements for electric generation facilities in the ERCOT region. The rule will also establish a framework for ERCOT to impose financial penalties on electric generation facilities that fail to comply with the requirements and provide financial incentives to electric generation facilities that exceed the requirements. This section is adopted under Project Number 58198. The rule will be republished.

The commission received written comments on the proposed section from Advanced Power Alliance and American Clean Power Association (APA and ACP); Electric Reliability Council of Texas, Inc. (ERCOT); Eolian, LP (Eolian); esVolta, LP (esVolta); Grid Resilience in Texas (GRIT); Hunt Energy Network, LLC (HEN); Lone Star Chapter of the Sierra Club (Sierra Club); Lone Star Energy Storage Alliance (LESA); Lower Colorado River Authority (LCRA); NextEra Energy Resources, LLC (NextEra); NRG Energy, Inc. (NRG); Octopus Energy LLC (Octopus Energy); Office of Public Utility Counsel (OPUC); Potomac Economics (Potomac); Solar Energy Industries Association (SEIA); Southern Power Company (Southern Power); Tesla, Inc. (Tesla); Texas Advanced Energy Business Alliance (TAEBA); Texas Competitive Power Advocates (TCPA); Texas Electric Cooperatives, Inc. (TEC); Texas Energy Buyers Alliance (TEBA); Texas Industrial Energy Consumers (TIEC); Texas Oil and Gas Association (TXOGA); Texas Public Policy Foundation (TPPF); Texas Public Power Association (TPPA); Texas Solar + Storage Association (TSSA); and Vistra Corporate Service Company (Vistra).

The commission invited interested persons to address two questions related to the proposed rule.

1. What level of Physical Responsive Capability (PRC) should be used to define a low operation reserve hour?

When PRC falls below 6,000 megawatts (MW)

TPPF recommended that the triggering threshold be when PRC falls below 6,000 MW. TPPF noted that hourly average PRC was below 3,000 MW for only seven total hours from 2020 to 2024, with no hours below 4,500 MW in 2024 or 2025. According to TPPF if this trend continues, compliance with the proposed rule will only be measured during emergency conditions that are unlikely to occur every year, and generators will likely opt to pay the penalty or procure short-duration energy storage rather than procure truly firm assets that will help protect the grid when emergencies arise. Differences in reliability and variations in performance, particularly between intermittent resources and dispatchable resources, do not present only during emergencies. Those differences are always present and must be accounted for even in years when emergency conditions are not reached. Moreover, a 3,000 MW threshold will make the firming program more of an incentive to improve resiliency--that is, performance during emergencies--rather than a program that improves the valuation of reliability and volatility every year.

Commission Response

The commission disagrees with TPPF that the triggering threshold to define a low operation reserve hour should be when PRC falls below 6,000 MW. The commission disagrees that the definition of a low operation reserve hour should be designed to ensure a low operation reserve hour is triggered each season just as the definition of a low operation reserve hour should not be designed to avoid a low operation reserve hour in any season.

When PRC falls below 3,000 MW (similar to criteria for declaration of a Watch)

APA and ACP, LCRA, NextEra, NRG, SEIA, TEBA, TIEC, TXOGA, TPPA, TSSA, TXOGA, and Vistra recommended that the proposed rule establishes an appropriate threshold of 3,000 MW. If the commission is inclined to take a conservative approach, then Southern Power recommended, as an alternative to its primary recommendation to set the triggering threshold at 2,500 MW, that the triggering threshold should be when PRC falls below 3,000 MW. Commenters were split on whether the triggering threshold should be when PRC falls below 3,000 MW for 15 minutes or 30 minutes. NextEra recommended that the triggering threshold should be when PRC falls below 3,000 MW for an entire 15-minute ERCOT settlement interval. NRG, TXOGA, and TPPA recommended that the triggering threshold should be when PRC falls below 3,000 MW for at least 15 minutes, consistent with the definition for low operation reserve hour in proposed §25.65(b)(4). On the other hand, APA and ACP, Southern Power, and TSSA recommended modifying the definition for low operation reserve hour to an hour when PRC falls below 3,000 MW for at least 30 minutes instead of 15 minutes. SEIA recommended modifying the definition for low operation reserve hour to an hour when PRC falls below 3,000 MW and is not expected to return to more than 3,000 MW within 30 minutes, consistent with the criteria ERCOT uses to declare a Watch. LCRA, NextEra, TEBA, TIEC, TXOGA, TPPA, TSSA, and Vistra were silent on the 15-minute duration that was included in the proposed definition for low operation reserve hour. However, TEBA and Vistra supported the definition for low operation reserve hour as stated in proposed §25.65(b)(4).

Commenters recommended that defining a low operation reserve hour as one in which PRC falls below 3,000 MW is consistent with ERCOT's conservative operational posture and ancillary service methodology, which seek to avoid entering a Watch. Moreover, because ERCOT is procuring sufficient ancillary services to avoid Watch conditions, it is reasonable that the metric for determining firming hours, which should reflect the hours of highest reliability risk, be set at the same level (or below) the Watch criteria to avoid interfering with pricing signals and ERCOT operations that encourage new investment. TEBA noted that, if the triggering threshold is set too low, then firming will never be triggered but if it is much higher, it could interfere with normal operations and commitment decisions in the ERCOT market. TXOGA recommended that this threshold should be an initial statewide trigger for 2026-2027 and that ERCOT should evaluate and recommend changes to this threshold in a biennial review of the program.

Commission Response

The commission agrees with commenters that the triggering threshold for defining a low operation reserve hour should be when PRC falls below 3,000 MW, which is consistent with when ERCOT declares a Watch. However, the commission declines to modify the triggering threshold to be longer than 15 minutes. The commission notes that a Watch is declared when the reserves fall below the 3,000 MW threshold and are expected to remain below that threshold for 30 minutes, not after reserves have been below that level for 30 minutes. A 30-minute triggering threshold would make it possible for ERCOT to declare a Watch without having the triggering threshold met.

When PRC falls below 2,500 MW (consistent with declaration of Energy Emergency Alert (EEA) Level 1)

APA and ACP recommended, as an alternative to their primary recommendation described above, that, if ERCOT's conservative operational posture were to change, then the metric to define a low operation reserve hour should be when PRC falls below 2,500 MW or an EEA Level 1. Eolian, OPUC, SEIA, Sierra Club, and TAEBA also recommended that the metric to define a low operation reserve hour should be when PRC falls below 2,500 MW. APA and ACP, Eolian, and OPUC noted that an EEA Level 1 coincides with ERCOT taking actions to stabilize the grid and minimizes impacts on the energy-only market thereby reflecting true emergency conditions. Similarly, Southern Power's primary recommendation was that the triggering threshold for defining a low operation reserve hour should be when PRC falls below 2,500 MW and is not expected to recover within 30 minutes.

Commission Response

The commission disagrees with commenters that a low operation reserve hour should be defined as an hour in which PRC falls below 2,500 MW because setting the threshold this low may interfere with pricing signals and ERCOT operations that encourage new investment.

When PRC falls below 2,000 MW (consistent with declaration of EEA Level 2)

Potomac recommended modifying the definition for low operation reserve hour to an hour when ERCOT issues an EEA Level 2 (i.e., when PRC falls below 2,000 MW) to align with actual system reliability risk when ERCOT requires additional powers to stabilize system frequency and manage system demand.

Commission Response

The commission disagrees with Potomac that a low operation reserve hour should be defined as an hour in which PRC falls below 2,000 MW because setting the threshold this low may interfere with pricing signals and ERCOT operations that encourage new investment.

1,000 MW

HEN recommended that the exact value used to define the low operation reserve hour should be developed as a parameter with the system and initially be set at 1,000 MW so that the impact to the market during the transition of real-time co-optimization plus batteries (RTC+B) is minimal and unobtrusive. If the commission and ERCOT determine that firming is a more critical issue post RTC+B familiarization, then HEN recommended that ERCOT could initiate a nodal protocol revision request to update the parameter, as necessary.

Commission Response

The commission disagrees with HEN that a low operation reserve hour should initially be defined as an hour in which PRC falls below 1,000 MW because setting the threshold this low may interfere with pricing signals and ERCOT operations that encourage new investment. Additionally, the performance requirements in this rule will impact electric generating facilities with a signed standard generation interconnection agreement (SGIA) SGIA after January 1, 2027 and that are in operation for at least a year at the start of the season. This means that the earliest potential low operation reserve hours where these performance requirements would apply is Spring 2028, which will give sufficient time for RTC+B implementation and familiarization, as that goes live on December 5, 2025.

Dynamic

TEC recommended that the level of PRC should not be set at a specific numerical level. Rather, the commission should analyze a set number of hours in each season with the lowest levels of PRC regardless of PRC levels reached.

Commission Response

The commission disagrees with TEC that the level of PRC should not be set at a specific numerical level. Analyzing a set number of hours in each season with the lowest level of PRC regardless of PRC levels reached introduces unnecessary administrative complexities and creates market uncertainty. Not every season, or even every year, will have hours of high reliability risk that are due to low operation reserves. Requiring a set number of hours in each season, regardless of whether the level of reserves is below the commission's threshold of a "low operation reserve hour," is not consistent with the language in statute.

1. Should the low operation reserve hour be tied to the deployment of or a shortage in aggregate real-time awards relative to the Ancillary Service Plan for ERCOT Contingency Reserve Service (ECRS)?

APA and ACP, Eolian, HEN, LCRA, NextEra, NRG, OPUC, Potomac, SEIA, Southern Power, TAEBA, TEBA, TEC, TIEC, TXOGA, TSSA, and Vistra answered no.

APA and ACP, Eolian, SEIA, and TSSA noted that once RTC+B is implemented, ERCOT will primarily deploy ECRS when it is economically efficient to convert ECRS capacity to energy based on real-time energy prices. Therefore, using ECRS deployments or shortage as the trigger risks applying performance requirements based on energy prices rather than on reliability needs.

HEN and Vistra noted that coupling the low operation reserve hour with ECRS would unnecessarily complicate the evaluation. LCRA recommended that decoupling these programs will mitigate impacts to price formation and protect the commission's flexibility in adjusting the firming policy in response to actual market outcomes.

NRG and TIEC explained that ECRS is deployed in situations other than just EEAs. ECRS is also deployed for frequency recovery and to manage net load ramps. As a result, a shortage of real-time awards of ECRS compared to the desired procurement amounts in the Ancillary Service Plan could occur temporarily in small amounts well before any period of low reserves.

TEC and TIEC recommended that the performance requirements should be tied to PRC without consideration of any other factors, such as the deployment of ancillary services. TIEC noted that this approach provides simplicity and predictability whereas using the deployment or shortage of ECRS relative to the Ancillary Service Plan introduces unnecessary uncertainty that will be difficult, if not impossible, to predict. The PRC level indicates when the ERCOT market is entering into emergency conditions, and as PRC declines, prices will inevitably increase to incentivize generation resources to provide energy to the grid. By relying on a PRC level for determining the low operation reserve hours, it will ensure resources can predict when the firming requirement will be triggered, and it will ensure the performance requirement is only triggered when there is an actual reliability risk. Moreover, NextEra noted that use of PRC as a trigger for an EEA is consistent with NERC standards, has been in practice for more than two decades in ERCOT, and is widely understood by stakeholders.

Commission Response

The commission agrees with commenters that the low operation reserve hour should not be tied to the deployment of or a shortage in aggregate real-time awards relative to the Ancillary Service Plan for ECRS. Additionally, the commission agrees with TIEC that the performance requirements set forth in the rule should be tied to PRC because the PRC level indicates when the ERCOT market is entering into emergency conditions.

General Comments

Counterfactual and forecasted analysis

TPPF recommended that before the rule is adopted, the commission use historical data to evaluate whether the proposed rule would have improved the reliability of the generation fleet at a reasonable cost had it already been in place for several years. TPPF also recommended that the commission create projections, based on its best estimate of the future resource mix, to ensure that the proposed rule will continue to encourage generators to meet the reliability standard well into the future.

Commission Response

The commission declines to adopt TPPF's recommendation to conduct a historical analysis evaluating whether the proposed rule would have improved the reliability of the generation fleet at a reasonable cost had it already been in place for several years. The commission also declines to adopt TPPF's recommendation that the commission create projections based on its best estimate of the future resource mix. Both types of analysis, counterfactual and forecasted, are inherently difficult and reliant upon assumptions about behavioral changes in response to differing conditions. A backwards looking analysis is beyond the scope of this project as the performance requirements are required by statute, regardless of the results of any such analysis. Moreover, a forward-looking analysis to estimate the impacts of the adopted rule in isolation is unnecessary given that ERCOT is already required to conduct a periodic, holistic assessment to determine whether the reliability standard is being met.

Portfolio-based compliance

Eolian, NextEra, TAEBA, TPPA, and Vistra recommended modifying the proposed rule to evaluate compliance, impose financial penalties, and provide financial incentives on a portfolio basis instead of at the resource level. Eolian noted that the framework in the proposed rule creates asymmetries by penalizing individual units even when the portfolio as a whole complies, while failing to provide corresponding credit for overperformance. Additionally, Eolian highlighted that PURA §39.1592(b) requires that owners or operators of electric generating facilities annually demonstrate that their overall portfolio can meet or exceed the seasonal average generation capability during periods of highest reliability risk. In support, Eolian provided a side-by-side comparison of the senate version of House Bill 1500, which uses the term "facility," and the enrolled version, which uses the term "owner or operator." TAEBA reasoned that pinning any reliability measurement to the individual resource is not necessarily reflective of system reliability, and allowing resource owners to account for generators not meeting performance expectations with other portfolio resources is more reflective of how the grid system functions.

Commission Response

The commission declines to adopt Eolian, NextEra, TAEBA, TPPA, and Vistra's recommendation to evaluate compliance, impose financial penalties, and provide financial incentives on a portfolio basis instead of at the resource level. The commission disagrees with Eolian that the reference in PURA §39.1592(b) to the owner or operator's portfolio means the owner or operator's overall portfolio. The statute does not use the term "overall" and electric generating facilities make up an owner or operator's portfolio. Therefore, it is appropriate to evaluate compliance of each electric generating facility in a portfolio and to impose financial penalties and provide financial incentives accordingly. However, the commission modifies the adopted rule to clarify that, for operational and settlement purposes, ERCOT will look to the Qualified Scheduling Entity (QSE) that represents the electric generating facility on behalf of the owner or operator. This approach complies with the statute and aligns with ERCOT's existing settlement system. Moreover, to comply with the statutory requirements to allow for other resources to satisfy the performance requirements, the commission modifies the adopted rule to make it explicit that an electric generating facility's performance requirements, either in part or in whole, can be satisfied through a trade arrangement with a firming resource. This can be done at any time prior to the final settlement of the season, and will ensure that the owner or operator of an electric generating facility can satisfy the performance requirements with other resources, either within their own portfolio or a portfolio managed by another owner or operator.

Firming requirement applicability

APA and ACP, Eolian, NextEra, Sierra Club, and TSSA recommended modifying the proposed rule to clarify that the performance requirement, and therefore the seasonal average generation capability (SAGC) calculation, applies only to an electric generating facility that is subject to PURA §39.1592 and the proposed rule. APA and ACP, Eolian, NextEra, and TSSA recommended that resources not subject to the performance requirements should not be held to a SAGC to determine the capacity that is available to firm other resources because PURA §39.1592 explicitly exempts existing electric generating facilities and energy storage resources from being subject to a SAGC for any purpose, including to determine the available capacity to supplement other resources subject to firming.

Commission Response

The commission adopts APA and ACP, Eolian, NextEra, Sierra Club, and TSSA's recommendation to clarify the applicability of the performance requirements. However, the commission disagrees with APA and ACP, Eolian, NextEra, and TSSA's interpretation of PURA §39.1592 to explicitly exempt existing resources and energy storage resources from being subject to a SAGC for any purpose. PURA §39.1592 explicitly requires an owner or operator of an electric generating facility to demonstrate the ability to operate or be available to operate when called on for dispatch at or above the SAGC. PURA §39.1592 is silent with respect to whether existing resources can provide firming and is also silent with respect to what capacity a resource, including an energy storage resource, may provide to firm an electric generating facility that is subject to the performance requirements.

Exempt energy storage resources from the application of the SAGC metric

APA and ACP, esVolta, LESA, NextEra, SEIA, Southern Power, TEBA, and Tesla recommended exempting energy storage resources from the application of the SAGC metric. According to commenters, doing otherwise is inconsistent with PURA §39.1592. Based on the statute's plain language, Southern Power recommended that the SAGC determination should not be applied to energy storage resources. The statute states that "an owner or operator of an electric generating facility, other than a battery energy storage resource, shall demonstrate to the commission the ability . . . to operate or be available to operate when called on for dispatch at or above the seasonal average generation capability" in times of high reliability risk. The requirement for resources to meet their SAGC is derived from this section only. The term seasonal average generation capability does not appear anywhere else in Chapter 39 of PURA. And, importantly, the sentence which includes this requirement expressly excludes energy storage resources.

esVolta, LESA, and SEIA recommended that overlaying a SAGC metric on energy storage resources reduces the effective capacity of storage available to the system. By defining an energy storage resource's ability to provide firming as its capacity in excess of its calculated SAGC, the proposed rule effectively prohibits energy storage resources from providing firming or otherwise incentivizes nonproductive uses of the assets. esVolta, LESA, and SEIA recommended that no metric should be used that would restrict an energy storage resource's ability to provide firming. As an alternative to the methodology in the proposed rule, esVolta, LESA, and SEIA recommended accounting for the availability of firming capacity similar to how an energy storage resource's capability to provide ancillary services into the ERCOT market for security constrained economic dispatch (SCED) dispatch is determined.

Southern Power recommended energy storage resources should be able to provide firming capacity, up to the energy storage resource's seasonal rated capacity, to supplement an owner or operator's portfolio or be sold to a third party via a contractual arrangement.

Commission Response

The commission agrees with APA and ACP, esVolta, LESA, NextEra, SEIA, Southern Power, TEBA, and Tesla that an energy storage resource, as long as it is operating or available to operate, should be able to provide its full capacity to firm an electric generating facility that is subject to the performance requirements set forth in the adopted rule. Therefore, the commission makes conforming changes to adopted §25.65(e)(2)(B). Additionally, because the commission makes this change, esVolta, LESA, and SEIA's alternative recommendation to account for the availability of an energy storage resource to provide firming is unnecessary.

Exempt existing resources from the application of the SAGC metric

APA and ACP, NextEra, and Southern Power recommended that existing electric generating facilities not required to meet the performance requirements should be able to provide firming capacity without regard to whether such electric generating facilities exceeded their SAGC. Southern Power reasoned that existing electric generating facilities are expressly excluded from the firming requirements by the first sentence of PURA §39.1592, which states "this section applies only to an electric generation facility in the ERCOT power region for which a standard generator interconnection agreement is signed on or after January 1, 2027." Southern Power recommended existing electric generating facilities should be able to provide firming capacity, up to the electric generating facility's seasonal rated capacity, to supplement an owner or operator's portfolio or be sold to a third party via a contractual arrangement.

Commission Response

The commission disagrees with APA and ACP, NextEra, and Southern Power that existing electric generating facilities that are not required to meet the performance requirements under PURA §39.1592 should be able to provide firming capacity without regard to whether those electric generating facilities exceeded their SAGC. The commission determines that existing electric generating facilities should be able to provide firming to satisfy the requirements of new electric generating facilities only if the existing electric generating facilities themselves would satisfy the performance requirement.

Formulas

TPPA recommended that the proposed rule include formulas for SAGC and effective value of lost load (VOLL) to clearly communicate how these variables will be calculated.

Commission Response

The commission agrees with TPPA and provides formulas in the adopted rule where appropriate, including the following:

Here, SAGC denotes Seasonal Average Generation Capability, HSL denotes High Sustained Limit, and SRC denotes Seasonal Rated Capacity. The first term in the minimum function calculates the ratio of real-time telemetered HSL and SRC across all intervals (i) that occurred during the prior five years of the same season ( denotes the total number of such intervals); if less than five years of operating data exist, all available data from the same season will be used. The minimum of this ratio and 0.75 is multiplied by the SRC at the start of the compliance season (j) to determine SAGC. The second term in the minimum function (0.75) effectively creates an upper bound on the resulting SAGC.

Expand the types of resources that can provide firming

APA and ACP, Eolian, Octopus Energy, SEIA, and TSSA recommended modifying proposed §25.65(d)(1) to allow demand response and aggregate distributed energy resources (ADERs) to provide firming. Eolian also recommended adding a definition for ADER. TEBA and TIEC recommended expanding proposed §25.65(d) to allow load resources to provide firming.

GRIT recommended the proposed rule expressly allow qualifying distribution generation resources (DGRs), distribution energy storage resources (DESRs) and settlement only distribution generators (SODGs) to provide firming to an electric generating facility subject to the performance requirements. GRIT reasoned that the smaller scale and geographic diversity of these resources enhance overall system resilience by reducing dependence on any single facility or location while their fast-start capability enables rapid response to ERCOT dispatch instructions. GRIT also noted that many of these resources already participate in programs with an established performance obligation, such as Emergency Response Service (ERS). Therefore, these resources have proven metering and verification pathways, making them well-suited for integration into the firming program without adding unnecessary administrative complexity. If the commission adopts this recommendation, then GRIT recommended that compliance could be demonstrated through net demand change energy. In the alternative, ERCOT could measure the resource's power quality or revenue meter data for compliance purposes.

Commission Response

The commission adopts TEBA and TIEC's recommendation to allow load resources to satisfy the performance requirements of electric generating facilities that are subject to the performance requirements. The commission modifies the adopted rule to include load resources and directs ERCOT, as part of its development of protocols to implement the adopted rule, to establish the necessary protocols to validate a load resource's performance.

The commission agrees with recommendations to include DGRs and DESRs, as these resources are dispatched by SCED and ERCOT has telemetry from these resources. The commission modifies the rule to include DGRs and DESRs and directs ERCOT, as part of the protocol development for this rule, to establish the necessary protocols to validate their performance.

The commission declines to include ADERs at this time. These terms are not currently in the ERCOT protocols.

The commission declines to include SODGs on the list of firming resources that can satisfy the performance requirements of electric generating facilities. Validation of the performance of these resources would be difficult or infeasible, as ERCOT does not have telemetry or resource statuses for these resources, and they are not dispatched by SCED.

Dynamic firming penalty and bilateral market

LCRA recommended the development of a dynamic firming penalty, which would require resource owners to be notified of their resource-specific firming penalty with sufficient time to contract with third parties to manage risk associated with high financial penalties. LCRA also recommended that commission staff and ERCOT develop protocols with stakeholder input to clarify the following:

(i) what new contract data must be provided to ERCOT from QSEs to support a bilateral market;

(ii) how much notice is required for resource owners to manage their seasonal firming risk through bilateral contracts with a third-party resource owner; and

(iii) the cutoff date (if any) for bilateral contracting.

Commission Response

The commission declines to implement the dynamic firming penalty recommended by LCRA. The owner or operator of an electric generating facility that signs a SGIA after January 1, 2027 is expected to be available for dispatch up to the facility's SAGC when system conditions are tight. A high performing electric generating facility that is expected to be available but is unavailable when system conditions are tight should be subject to a financial penalty. However, to ensure that high-performing electric generating facilities are not overly penalized, the commission modifies the SAGC formula to cap it at 75% of an electric generating facility's seasonal rated capacity. This avoids disincentivizing a high-performing electric generating facility to continue to perform at a high level during all available hours.

Periodic adjustments to financial penalty linked to the effective VOLL

LCRA recommend that under a VOLL-based penalty design, any change to the effective VOLL should trigger a review of the firming program to ensure that incentives are balanced appropriately. This will help to address the fact that as ERCOT updates its effective VOLL within the protocols, an electric generating facility's risk exposure will change accordingly.

Commission Response

The commission acknowledges LCRA's concern that the risk exposure of the owner or operator of an electric generating facility will change anytime there is a change to the effective VOLL and modifies the adopted rule so that the financial penalty amount is no longer based on the effective VOLL. Instead, the commission links the financial penalty amount to the system-wide offer cap, which will require a rulemaking to take place before the financial penalty amount may be changed.

Demonstration of ability to operate

Potomac noted that PURA §39.1592(b) requires that each year, post-2027, electric generating facilities must demonstrate their ability to operate at or above their SAGC during times of highest reliability risk due to low operation reserve hours. The proposed rule does not address how this demonstration will take place if no low operation reserve hours take place during a given year.

Similarly, APA and ACP and TSSA noted that the proposed rule does not address expectations in a season where there are more or less than 15 low operation reserve hours. For clarification, APA and ACP and TSSA recommended adding a sentence to proposed §25.65(b)(4), defining "low operation reserve hour," that states the low operation reserve hours are limited to a maximum of 15 hours per season and a sentence that states there is no performance requirement under the proposed rule in a season that does not experience any low operation reserve hours.

Commission Response

The commission adopts APA and ACP and TSSA's recommendation to substantively clarify that the low operation reserve hours are limited to a maximum of 15 hours per season and there is no performance requirement under the adopted rule in a season that does not experience any low operation reserve hours. However, the commission modifies adopted §25.65(d), relating to performance requirement, to include this substantive clarification instead of including the clarification in the definition for low operation reserve hour.

Reporting requirements related to the firming program

TXOGA recommended that ERCOT be required to develop a biennial assessment of the costs and benefits of this firming program and that the independent market monitor be required to include, in its annual state of the market report to the commission, the impacts of this firming program on all aspects of the ERCOT market and any concerns regarding market manipulation.

Potomac recommended requiring a report that measures the performance of the firming requirement on a regular basis and differentiates normal market behavior from the additional reliability benefits that the firming program introduces.

Commission Response

The commission declines to modify the rule to provide the specific reporting requirements requested by TXOGA and Potomac, as these reviews would be an inefficient use of resources since PURA §39.1592 requires the firming program. The commission notes that Potomac is free to include any observations regarding the ERCOT market and provide assessments and recommendations in its annual State of the Market Report.

Effective date of the proposed rule

TSSA recommended that the commission clarify the proposed rule by specifying that the rule is not effective until January 1, 2028 because this is the earliest firming could be used given the statutory requirement that the performance requirements and therefore firming apply to an electric generating resource with a signed SGIA after January 1, 2027 and after one year of operations.

Commission Response

The commission declines to adopt TSSA's recommendation to specify that the rule is not effective until January 1, 2028, because it is unnecessary.

Proposed §25.65(a) - Applicability

Proposed §25.65(a) specifies that battery energy storage resources, settlement only generators, and self generators are not required to comply with the performance requirements set forth in the proposed rule. Proposed §25.65(a) also specifies that an electric generating facility must comply with the performance requirements set forth in the proposed rule if the electric generating facility meets one of two conditions. The first is that the electric generating facility signs an SGIA on or after January 1, 2027 and has been in operation for at least one year. The second is that the electric generating facility completes upgrades resulting in an increase of 50% or more to the facility's nameplate capacity and requires a new SGIA after January 1, 2027.

Battery energy storage resource

TPPA recommended striking "battery" in front of "energy storage resource" to avoid ambiguity, as "energy storage resource" is already a defined term in the commission's rules. Including "battery" before the term could create ambiguity in the proposed rule's applicability and whether the term is intended to capture a different set of resources.

Commission Response

The commission declines to adopt TPPA's recommendation to remove the word "battery" before the term "energy storage resource" in adopted §25.65(a), because the commission modified the rule to relocate the exemptions to the performance requirements to §25.65(d). However, the commission makes the requested edit in that location, exempting energy storage resources from the performance requirements of this section. While there are other storage technologies currently participating in the ERCOT wholesale market, the capacity of these resources is de minimis, and applying the performance requirements of this section to these resources would place administrative burdens on the owners of these technologies, ERCOT, and the commission while providing little or no intrinsic value to the market. This approach is consistent with the public interest and consistent with statutory interpretation principles that a just and reasonable result, and a result feasible of implementation, is intended. The commission may revisit this interpretation, as required, in a future rulemaking.

Self-generators

TPPA recommended striking the reference to self-generators in proposed §25.65(a). TPPA reasoned that self-generators cannot legally sell power and therefore do not meet the definition of an electric generating facility, which is limited to entities that generate electricity for compensation.

Commission Response

The commission declines to adopt TPPA's recommendation to remove the reference to self-generators in proposed §25.65(a). The explicit exclusion of self-generators from the rule's applicability is consistent with PURA §39.1592 and avoids ambiguity. However, the commission modifies the adopted rule to specify in adopted §25.65(d) instead of adopted §25.65(a) that the performance requirements set forth in subsection (d) do not apply to a self-generator.

Overly broad

Potomac noted that it is unclear which provisions of the proposed rule apply to electric generating facilities placed in operation before January 1, 2027 versus those that begin operation after that date. Specifically, if "electric generating facility" applies to those facilities interconnecting after January 1, 2027, the language currently implies that: (1) pre-2027 electric generating facilities are ineligible to firm up electric generating facilities interconnecting after that date; and (2) pre-2027 electric generating facilities do not receive an SAGC from ERCOT or their SAGC is 0 MW.

Commission Response

The commission acknowledges the lack of clarity that Potomac raises relating to the rule's use of "electric generating facility" to describe pre-2027 and post-2027 resources and makes clarifying changes throughout the rule to distinguish between these two groups of electric generating facilities to more clearly articulate which facilities must comply with the performance requirements.

Co-located generation and private use networks (PUNs)

TIEC recommended modifying proposed §25.65(a) to state that the proposed rule applies to "the grid-dedicated capacity of an electric generating facility. . . ." TIEC highlighted that a third-party electric generating facility that enters into a purchase power agreement with a co-located customer(s) is required to register as a power generation company, creating asymmetry in the proposed rule's application to these types of electric generating facilities, settlement-only generators, and self-generators, the latter of which the proposed rule exempts. As a practical matter, these third-party electric generating facilities are similarly situated to self-generators and settlement-only generators in that the co-located customer(s) directly bears the physical and financial risks of the electric generating facility's performance. Rather than create exemptions to the proposed rule's applicability based on registration status, TIEC reasoned that only an electric generating facility's "excess" generation regularly made available to the grid should be subject to compliance with the performance requirements set forth in the proposed rule.

NRG, TCPA, and Vistra recommended modifying proposed §25.65(a) to exempt an electric generating facility co-located with a load in a PUN from complying with the performance requirements set forth in the proposed rule if the electric generating facility will provide more than 50% of its nameplate capacity to the load within the PUN and is therefore primarily dedicated to that load. NRG, TCPA, and Vistra cautioned that requiring an electric generating facility co-located with a load in a PUN to comply with the performance requirements could disincentivize co-located electric generating facilities to interconnect to the ERCOT system.

TEBA recommended broadening the self-generator exemption by modifying §25.65(a) to also exempt an electric generating facility that shares a point of interconnection with a load in the ERCOT region.

Commission Response

The commission agrees with TIEC, NRG, TCPA, Vistra, and TEBA that an exemption should be granted for an electric generating facility that is co-located with a load. The commission adopts NRG, TCPA, and Vistra's recommendation to exempt an electric generating facility co-located with a load in a PUN from the performance requirements if more than 50% of the electric generating facility's nameplate capacity is dedicated to serving the load within the PUN. This strikes the best balance of recognizing that the co-located load bears the risk of the electric generating facility's performance while ensuring electric generating facilities that intend to sell a majority of their output at wholesale do not co-locate with load simply to avoid being subject to the performance requirements. Accordingly, the commission declines to adopt TIEC's recommendation to apply the performance requirements to the "grid-dedicated capacity" of an electric generating facility. The commission also declines to adopt TEBA's recommendation to exempt the entire output of an electric generating facility that shares a point of interconnection with load.

Proposed §25.65(a)(1) - Signed SGIA on or after January 1, 2027 and in operation for at least one year

Proposed §25.65(a)(1) states that the performance requirements set forth in the proposed rule apply to an electric generating facility that: (A) has a SGIA that is signed on or after January 1, 2027, and (B) has been in operation for at least one year.

Eolian and TCPA recommended modifying proposed §25.65(a)(1) to specify that the performance requirements set forth in the proposed rule apply to an electric generating facility with "an original" SGIA signed on or after January 1, 2027. Eolian and TCPA reasoned that a SGIA that is executed before January 1, 2027 does not fall within the statutory scope of PURA §39.1592 even if the SGIA is later modified.

TCPA also recommended adding a new subsection that explicitly states that amendments to SGIAs that were signed before January 1, 2027 do not constitute an original SGIA for purposes of the performance requirements.

SEIA, TCPA, and TSSA recommended modifying §25.65(a)(1) to clarify that the performance requirements set forth in the rule apply to an electric generating facility that is operational for one year prior to the beginning of a season. Otherwise, an electric generating facility may not have sufficient operational data to calculate its SAGC for that full season.

Commission Response

The commission adopts Eolian and TCPA's recommendation to clarify adopted §25.65(a)(1) by adding "an original" in front of "standard generation interconnection agreement" to denote that the rule's applicability is based on the date that the SGIA is initially signed. The commission declines to adopt TCPA's recommendation to add a new subsection that explicitly states that amendments to SGIAs that were signed before January 1, 2027, do not constitute an original SGIA for purposes of the performance requirements because it is unnecessary since the commission removes the provision related to the adopted rule's applicability to upgrades. The commission adopts SEIA, TCPA, and TSSA's recommendation to include clarifying language in adopted §25.65(a)(1) that the rule applies to an electric generating facility that has been in operation for at least one year prior to the beginning of a season to ensure that there is at least one full season's worth of operational data for each season prior to the performance requirement applying to an electric generating facility.

Proposed §25.65(a)(2) - Upgrades increasing nameplate capacity

Proposed §25.65(a)(2) states that the performance requirements set forth in the proposed rule apply to an electric generating facility that completes upgrades resulting in an increase of the nameplate capacity by 50% or more and requires a new or amended SGIA.

Strike

APA and ACP, Eolian, NextEra, SEIA, TCPA, TEBA, TPPA, TSSA, and Vistra recommended striking proposed §25.65(a)(2), reasoning that PURA §39.1592 applies only to an electric generating facility with a SGIA signed on or after January 1, 2027. APA and ACP, Eolian, SEIA, TCPA, TEBA, TPPA, TSSA, and Vistra reasoned that proposed §25.65(a)(2) is inconsistent with the plain language of the statute and disincentivizes upgrades to facilities that may seek to increase efficiency or output, which are needed to meet increasing load growth.

Commission Response

The commission adopts APA and ACP, Eolian, NextEra, SEIA, TCPA, TEBA, TPPA, TSSA, and Vistra's recommendation to modify the adopted rule to remove proposed §25.65(a)(2), which states that the performance requirements apply to an electric generating facility that completes upgrades resulting in an increase of the nameplate capacity by 50% or more and requires a new or amended SGIA. However, the commission disagrees that proposed §25.65(a)(2) is inconsistent with the plain language of PURA §39.1592. PURA §39.1592 is silent as to whether the SGIA signed on or after January 1, 2027 must be an original SGIA, an amended SGIA, or an amended and restated SGIA. As demonstrated by the commenters that recommended clarifying the rule applies to an electric generating facility with an original SGIA, PURA §39.1592 is ambiguous. Therefore, it is appropriate for the commission to interpret this provision.

Limited application to upgraded facilities

TIEC recommended applying the performance requirements only to new, incremental capacity (i.e., the increased nameplate capacity above 50%). If NextEra and TCPA's primary recommendation to strike proposed §25.65(a)(2) is not adopted by the Commission, then NextEra and TCPA also recommended, in the alternative, that the performance requirements apply only to the increased nameplate capacity above 50%. TIEC reasoned that adding capacity at an existing site is a more cost-effective way to increase available generation than developing a greenfield site. However, subjecting a facility to the performance requirements because the facility updates or replaces existing units would deter these valuable investments from a reliability standpoint.

Commission Response

The Commission declines to adopt TIEC's recommendation and NextEra and TCPA's alternative recommendation to apply the performance requirements only to new, incremental capacity added by an electric generating facility (i.e., the increased nameplate capacity above 50%). Instead, the commission modifies the adopted rule to remove this provision.

Apply the firming requirements after the facility has been in operation, following the upgrades, for at least one year

ERCOT recommended applying the performance requirements to an electric generating facility that increases its nameplate capacity by 50% or more only after the facility has been in operation for at least one year after the upgrades have been completed. ERCOT explained that at least some operating data would be helpful to calculate the SAGC for the facility's upgrades and one year of data is consistent with the requirement for other electric generating facilities subject to the firming requirements under the proposed rule.

Commission Response

The Commission declines to adopt ERCOT's recommendation to apply the performance requirements to an electric generating facility that increases its nameplate capacity by 50% or more after the facility has been in operation for at least one year from the date that the upgrades have been completed for consistency with how other electric generating facilities subject to the performance requirements are treated. This change is unnecessary because the commission modifies the adopted rule to remove this provision.

Expand to apply the firming requirements to all electric generating facilities that amend the SGIA after January 1, 2027

TPPF recommended expanding proposed §25.65(a)(2) to include any electric generating facility that requires a new or amended SGIA after January 1, 2027. TPPF explained that the proposed rule would enable electric generating facilities with an SGIA that was signed before January 1, 2027 to exempt themselves from the performance requirements indefinitely, effectively creating a permanent bifurcated market, which is counter to the legislative intent. TPPF noted that a permanent bifurcated market where pre-2027 electric generating facilities are not required to comply with the performance requirements could create market distortions and reliability problems.

Commission Response

The Commission declines to adopt TPPF's recommendation to expand the applicability of the rule to any electric generating facility that requires an amended SGIA after January 1, 2027 in order to avoid a bifurcated market. PURA §39.1592 clearly demarcates a future point in time by when the firming requirements inure to electric generating facilities to provide regulatory and market certainty for developers of future electric generating facilities. The commission implements the statute as required. Additionally, a bifurcated market is not permanent in so far as all electric generating facilities eventually retire.

Decrease the threshold from 50 percent to 20 percent

HEN recommended applying the performance requirements to an electric generating facility that increases its nameplate capacity by 20% rather than 50%. This would align the proposed rule with ERCOT Planning Guide 5.2.4(4). ERCOT Planning Guide 5.2.4(4) requires the interconnecting entity to submit a new interconnection request for the additional capacity or for the entire project if the interconnecting entity increases the requested amount of capacity by more than 20% of the amount requested in the initial application. Alignment of the rule and ERCOT protocols would reduce confusion and provide consistency.

Commission Response

The commission declines to adopt HEN's recommendation to apply the performance requirements to an electric generating facility that increases its nameplate capacity by 20% rather than 50%. Instead, the commission modifies the adopted rule to remove this provision.

Proposed §25.65(b) - Definitions

Proposed §25.65(b) sets forth definitions for (1) electric generating facility, (2) high-risk hour, (3) in operation, (4) low operation reserve hour, (5) owner or operator, (6) season, and (7) seasonal average generation capability.

Additional definitions- ancillary service or reliability service

TPPA recommended adding a definition for "ancillary service or reliability service." TPPA recommended defining "ancillary service or reliability service" as a service, not including energy, which can be procured by ERCOT in the day-ahead market (DAM) or real-time market.

Commission Response

The commission declines to adopt TPPA's recommendation to provide a specific definition for ancillary service or reliability service and to provide a specific list of these services. The commission determines it is more appropriate to address these recommendations in the ERCOT stakeholder process. This will allow flexibility in identifying all of the ancillary service and reliability service products and incorporating new ancillary service and reliability service products if and when new ones are added.

Additional definitions- covered entity

Eolian recommended adding a definition for "covered entity" to conform with its recommended changes to proposed §25.65(c) and (d). Eolian recommended defining "covered entity" as any natural person, partnership, municipal corporation, cooperative corporation, association, governmental subdivision, or public or private organization that owns or controls an electric generation facility and is registered with ERCOT as a resource entity as defined in the ERCOT protocols.

Commission Response

The commission declines to adopt Eolian's recommendation to add a definition for covered entity because it is unnecessary. The adopted rule defines an "owner or operator" and a "QSE" consistent with PURA §39.1592.

Additional definitions- energy storage resource

TPPA recommended adding a definition for "energy storage resource." TPPA recommended mirroring the definition for energy storage resource in §25.55(b)(1).

Commission Response

The commission declines to adopt TPPA's recommendation to add a definition for energy storage resource that mirrors the definition used in §25.55(b)(1) of this Title (relating to Weather Emergency Preparedness). The commission adds a definition for energy storage resource but aligns the definition with the definition used in the ERCOT protocols to better maintain consistency across commission rules and ERCOT protocols.

Additional definitions- force majeure event

Southern Power recommended adding a definition for "force majeure event" to conform with its recommended changes to proposed §25.65(e)(2)(A). Southern Power recommended defining a "force majeure event" as an event caused by an act of God, including, without limitation, fires, landslides, lightning strikes, earthquakes, hurricanes, tornadoes, storms, or floods, or any event beyond the reasonable control of the owner of an electric generating facility such as wars, riot, pandemics, insurrections, acts of public enemies, governmental orders, blockades, quarantines, or other similar acts. For avoidance of doubt, the inherent variable electric generation output of an electric generating facility caused by changes in typical weather patterns will not constitute a force majeure event.

Commission Response

The commission declines to adopt Southern Power's recommendation to add a definition for force majeure event because the commission declines to adopt Southern Power's recommended changes to proposed §25.65(e)(2)(A) to include reference to a force majeure event, making the additional definition unnecessary.

Additional definitions- grid-dedicated capacity

TIEC recommended adding a definition for "grid-dedicated capacity" to conform with its recommended changes to proposed §25.65(a). TIEC recommended defining "grid-dedicated capacity" as the SAGC of an electric generating facility minus the sum of the seasonal maximum non-coincident peak demands of any metered loads.

Commission Response

The commission declines to adopt TIEC's recommendation to add a definition for grid-dedicated capacity because the commission declines to adopt TIEC's recommended changes to adopted §25.65(a), making the additional definition unnecessary.

Additional definitions- interval

TPPA recommended adding a definition for "interval." TPPA recommended that the definition specify whether the measurement refers to a 15-minute interval, a five-minute interval, or each instance in which Security-Constrained Economic Dispatch (SCED) runs.

Commission Response

The commission adopts TPPA's recommendation to add a definition for interval, defining it as each instance in which SCED runs

Additional definitions- firming penalty- low, medium, and high performance threshold

LCRA recommended adding definitions for firming penalty- low, medium, and high performance threshold to conform with its suggested changes to proposed §25.65(e)(1). LCRA recommended defining "firming penalty - low performance threshold" to mean for each season, ERCOT must calculate the ratio of real-time telemetered HSL to the seasonal rated capacity for all electric generating facilities across all intervals during the prior three years. The low performance threshold is the X lowest percentage of availability as measured by the ratio of real-time telemetered HSL to the seasonal rated capacity across all resources. LCRA recommended defining "firming penalty - medium performance threshold" to mean for each season, ERCOT must calculate the ratio of real-time telemetered HSL to the seasonal rated capacity for all electric generating facilities across all intervals during the prior three years. The median performance threshold is the median availability as measured by the ratio of real-time telemetered HSL to the seasonal rated capacity across all resources. Finally, LCRA recommended defining "firming penalty - high performance threshold" to mean for each season, ERCOT must calculate the ratio of real-time telemetered HSL to the seasonal rated capacity for all electric generating facilities across all intervals during the prior three years. The high-performance threshold is the X highest percentage of availability as measured by the ratio of real-time telemetered HSL to the seasonal rated capacity across all resources.

Commission Response

The commission declines to add the definitions proposed by LCRA for firming penalty- low, medium, and high performance threshold because the commission declines to include LCRA's dynamic penalty structure in the adopted rule. Therefore, these definitions are unnecessary.

Additional definitions- morning ramp periods and evening ramp periods

NextEra recommended adding a definition for "morning ramp periods" and "evening ramp periods" based on the load ramp, which is reflective of when customers need the assurance of power and is the period that has the most operational risk to ERCOT.

Commission Response

The commission declines to adopt NextEra's recommendation to add a definition for morning ramp periods and evening ramp periods because it is appropriate for ERCOT to develop the standards for defining morning ramp periods and evening ramp periods. However, the commission notes that under PURA §39.151(g-6), new or revised protocols may not take effect until the commission approves a market impact statement describing the new or revised protocols. Accordingly, ERCOT's development of the standards remains subject to the commission's oversight.

Additional definitions- peak net load hour

TPPA recommended adding a definition for "peak net load hour" because the term has unique meaning and may not be commonly understood by a layperson. TPPA recommended defining "peak net load hour" as an hour in which, after the reduction of renewable resources from the generation supply, the highest load demand was recorded in a 15-minute settlement interval.

Commission Response

The commission declines to include TPPA's definition for peak net load hour in the adopted rule because the high-risk baseline hours will no longer be based off historic hours with the highest peak net load.

Additional definitions- seasonal rated capacity

TPPA recommended adding a definition for "seasonal rated capacity" because the term has unique meaning and may not be commonly understood by a layperson. TPPA recommended defining "seasonal rated capacity" as the maximum generating capability of an electric generating facility, expressed in MW, that the owner or operator of an electric generating facility declares it can sustain under expected ambient conditions for a given season and as determined at the start of that season and documented on ERCOT's Resource Asset Registration Form.

Commission Response

The commission adopts TPPA's recommendation to add a definition for seasonal rated capacity to add clarity. Moreover, the commission substantially adopts TPPA's recommendation to define seasonal rated capacity. The commission defines seasonal rated capacity as the maximum generating capability of an electric generating facility, expressed in MW, that the owner or operator of an electric generating facility declares it can sustain under expected ambient conditions for a given season, according to the value that the electric generating facility reported to ERCOT.

Additional definitions- self-generator

If the Commission declines to adopt TPPA's recommendation to strike self-generator, then TPPA recommended adding a definition for "self-generator."

Commission Response

The commission adopts TPPA's recommendation to define self-generator to add clarity to the proposed rule.

Additional definitions- settlement-only generator

TPPA recommended adding a definition for "settlement-only generator." TPPA recommended defining "settlement-only generator" as an electric generating facility that is settled for exported energy only but may not participate in the ancillary service market or be dispatched by ERCOT.

Commission Response

The commission adopts TPPA's recommendation to add a definition for a settlement-only generator. However, the commission adopts a definition that aligns with the definition used in the ERCOT protocols to better maintain consistency across commission rules and ERCOT protocols.

Proposed §25.65(b)(1) - Electric generating facility

Proposed §25.65(b)(1) defines an electric generating facility as a generation resource, as defined in ERCOT protocols.

Mirror statutory language

ERCOT recommended changing the term from "electric generating facility" to "electric generation facility" to mirror the term used in PURA §39.1592.

Commission Response

The commission adopts ERCOT's recommendation to change the defined term from "electric generating facility" to "electric generation facility" to mirror the term used in PURA §39.1592 and to make conforming changes throughout the adopted rule.

Must-run alternative (MRA) units, reliability must-run (RMR) units, contracts for capacity, and mobile generation units

ERCOT recommended modifying proposed §25.65(b)(1) to clarify that the following resources are excluded from the definition of an electric generating facility: (1) a resource that operates as a MRA unit, a resource that operates as a RMR unit, and (3) a resource that contracts with ERCOT under a "contract for capacity." In the alternative, ERCOT recommended that MRA units and RMR units provide "reliability services" with a performance obligation and therefore should be exempt from the firming requirements set forth in the proposed rule consistent with the exemption in proposed §25.65(e)(2)(D). Additionally, ERCOT recommended explicitly stating that the proposed rule does not apply to the Prime Power Solutions LLC d/b/a Life Cycle Power mobile generation units that are operating for reliability reasons pursuant to a contract with ERCOT.

Commission Response

The commission agrees with ERCOT's recommendation to clarify that the following resources are excluded from the definition of an electric generating facility for purposes of compliance with the performance requirements: (1) a resource that operates as a MRA unit; (2) a resource that operates as a RMR unit; and (3) a resource that contracts with ERCOT under a "contract for capacity." However, the commission modifies adopted §25.65(d) instead of modifying the definition for electric generating facility to reflect that the performance requirements set forth in the rule do not apply to these resources. The commission agrees with ERCOT's interpretation that the performance requirements set forth in the rule do not apply to the Prime Power Solutions LLC d/b/a Life Cycle Power mobile generation units that are operating for reliability reasons pursuant to a contract with ERCOT.

Clarify whether energy storage resource is included in or excluded from the definition

Potomac recommended modifying proposed §25.65(b)(1) to clarify whether an energy storage resource meets the definition.

Eolian recommended modifying proposed §25.65(b)(1) to explicitly state that energy storage resources are excluded from the definition of an electric generating facility, consistent with the referenced definition for generation resource in ERCOT protocols.

Commission Response

The commission declines to adopt Potomac's recommendation to clarify whether an energy storage resource meets the definition of an electric generating facility. The commission also declines to adopt Eolian's recommendation to explicitly exclude energy storage resources from the definition of an electric generating facility. Instead, the commission clarifies how the adopted rule applies to energy storage resources by modifying adopted §25.65(a) relating to applicability, §25.65(b)(13) defining seasonal average generation capability, and §25.65(d) relating to performance requirements.

Replace reference to ERCOT protocols in definition

TPPA recommended replacing the reference to ERCOT protocols with a definition. TPPA reasoned that the commission delegated authority to ERCOT to create the protocols, and the commission's rules govern ERCOT protocols. Therefore, the commission's rules should avoid referencing ERCOT protocols.

Commission Response

The commission declines to adopt TPPA's recommendation to replace the reference to ERCOT protocols with a definition. The commission has oversight and approval authority over ERCOT protocols and therefore any change to the relevant definitions in ERCOT protocols must still be reviewed and approved by the commission prior to implementation.

Proposed §25.65(b)(2) - High-risk hour

Proposed §25.65(b)(2) defines a high-risk hour as a daily hour encompassing all seasonal morning and evening ramp hours, as determined by ERCOT, and any hour where at least 5% of the highest decile of net load hours occurred during that season in the prior three years.

NextEra recommended adding an objective formula instead of leaving ERCOT to determine the parameters for a high-risk hour. NextEra also recommended limiting the definition to a daily hour encompassing all seasonal morning and evening ramp periods.

TAEBA recommended excluding the morning and evening ramp hours because morning and evening ramping hours are well understood and accounted for in the marketplace, rendering them unnecessary for inclusion in the definition. Additionally, inclusion of the morning and evening ramp hours is punitive to solar resources.

TCPA and Vistra recommended basing the high-risk hour on the North American Electric Reliability Corporation (NERC) Probabilistic Assessment that ERCOT must conduct. The NERC Probabilistic Assessment uses the same probabilistic reliability model (Strategic Energy Risk Valuation Model, or SERVM) that will be used for the Reliability Assessment required by the commission's reliability standard. Additionally, the NERC Probabilistic Assessment has the added benefit of being an existing risk assessment process used to determine high-risk hours and does not require additional calculations by commission staff or stakeholders to validate the results.

APA and ACP, SEIA, and TSSA recommended replacing "high-risk hour" with "baseline period" to better align with PURA §39.1592 and avoid confusion since the low operation reserve periods determine the periods of high reliability risk. Additionally, APA and ACP and SEIA recommended defining the baseline period as a daily hour. TSSA recommended defining the baseline period as all daily hours.

APA and ACP, SEIA, and TSSA noted that the Probabilistic Reserve Risk Model (PRRM) that ERCOT uses to generate the monthly Outlook for Resource Adequacy (MORA) report accounts for current system conditions that impact reliability and the ramp down of renewable output, which is simulated using more than 42 weather years of data. Therefore, APA and ACP, SEIA, and TSSA recommend that the hour(s) used for the baseline period should be determined by using ERCOT's Monthly Outlook for Resource Adequacy (MORA) report to identify when the probability is at least 5% that the Capacity Available for Operating Reserves (CAFOR) will be less than 3,000 MW. These changes would reflect the expected hourly resource availability of a generation resource and would not assign a targeted threshold for solar output generation at night.

If its primary recommendation is not adopted by the commission, then TSSA recommended, in the alternative, that the proposed rule define the baseline period as hours encompassing all seasonal morning and evening ramp hours and any daily hour identified by ERCOT using the MORA report to identify when the probability is at least 5% that the CAFOR falls below 3,000 MW.

LCRA noted that the definition of "high-risk hour" may be overbroad in including both morning and evening ramps and "any hour where at least 5% of the highest decile of net load hours occurred during that season in the prior three years." Analysis of historic peak net load data from July 2023 through June 2025 reveals moderate exposure for performance penalties for all resources. Even with ERCOT pre-announcing the qualifying hours, there is still a significant penalty risk each season for non-exempted resources seeking to perform during the top 15 hours.

Sierra Club raised concerns that the definition in proposed §25.65(b)(2) unnecessarily expands the baseline period (high-risk hours) to approximately half of all hours. In practice, the methodology in the proposed rule would extend into the evening and nighttime hours. If a firming hour were to occur during the night, then solar would be required to firm even though the statute requires that the calculation be based upon the "expected resource availability." Because the expected resource availability for a solar resource is zero at night, there should not be a firming obligation imposed on solar at night.

Commission Response

The commission agrees with APA and ACP, SEIA, and TSSA that "high-risk hour" should be replaced with "baseline period." The usage of baseline period aligns with the language in PURA §39.1592(d)(3), which establishes the hours when a financial penalty could be imposed.

The commission declines to adopt NextEra's recommendation to include a formula for morning and evening ramps periods in the adopted rule. ERCOT protocols allow for flexibility to adjust these periods as the resource mix, load profile, etc. change and the morning and evening ramp hours change.

The commission declines to adopt TAEBA's recommendation to exclude morning and evening ramp periods. PURA §39.1592 explicitly calls for the morning and evening ramp periods to be included in the baseline hours in which ERCOT may impose financial penalties.

The commission adopts TCPA and Vistra's recommendation to utilize the NERC Probabilistic Assessment, as ERCOT already conducts this analysis annually and this will provide the most holistic snapshot of the high-risk hours on a looking-forward basis. The commission modifies the adopted rule to require ERCOT to utilize this analysis to identify high-risk hours for inclusion in the baseline period.

The commission declines to adopt APA and ACP, SEIA, and TSSA's recommendation to utilize the MORA to identify the high-risk hours that are included in the baseline period with the morning and evening ramp periods. While the commission agrees this is an improvement over the methodology in the proposed rule, the commission moves forward with the NERC Probabilistic Assessment recommended by TCPA and Vistra. This will also provide owners and operators with more notice on which hours will be included within the baseline period in each season.

The commission acknowledges LCRA and Sierra Club's concern that the proposed definition includes overly broad hours. The adopted definition for baseline period, which will utilize a probabilistic assessment to identify high-risk hours beyond the morning and evening ramp periods, addresses this concern by better reflecting the expected hours of highest risk.

The commission disagrees with Sierra Club that there should not be a performance requirement imposed on solar at night. PURA §39.1592 requires a new electric generating facility to operate or be available to operate at or above its seasonal average capability, not its hourly capability within a season.

Proposed §25.65(b)(3) - In operation

Proposed §25.65(b)(3) defines in operation as the resource commissioning date, as defined in the ERCOT protocols.

To avoid misinterpretation, ERCOT recommended specifying that in operation is the timeframe beginning with the resource commissioning date.

NextEra recommended specifying the resource commissioning date is when the resource completes the interconnection process and is approved for participation in ERCOT market operations.

APA and ACP and TSSA recommended using the commercial operations date defined in ERCOT Protocols.

Commission Response

The commission clarifies that the definition of "in operation" means the date that ERCOT approves the electric generating facility for commercial operation.

Proposed §25.65(b)(5) - Owner or operator

Proposed §25.5(b)(5) defines an owner or operator as a resource entity that owns an electric generating facility represented by a QSE.

APA and ACP, HEN, SEIA, and TSSA recommended modifying proposed §25.65(b)(5) to include an operator. APA and ACP and TSSA recommended modifying the definition in alignment with ERCOT protocols, which require that each resource entity that owns a resource submit a declaration to ERCOT as to which Decision Making Entity has control of each of its resources. SEIA recommended modifying the definition to state a resource entity that owns or operates an electric generating facility. HEN recommended modifying the definition to state a resource entity that owns or controls an electric generating facility.

Commission Response

The commission declines to adopt HEN's recommendation to modify the definition to add "controls." Instead, the commission adopts APA and ACP, HEN, SEIA, and TSSA's recommendation to add "operates" to the definition because the term aligns better with the statute. The commission declines to adopt APA and ACP and TSSA's recommendation to have resource entities declare a Decision Making Entity within the context of the owner or operator definition. Settlements in ERCOT go through an associated QSE and therefore an electric generating facility must be represented by a QSE for portfolio settlement purposes.

Proposed §25.65(b)(6) - Season

Proposed §25.65(b)(6) defines season as winter (December 1 through February 29), Spring (March 1 through May 31), Summer (June 1 through September 30), and Fall (October 1 through November 30.

Categorization of September

Southern Power recommended modifying proposed §25.65(b)(6) to split September between the summer and fall months to more accurately reflect the transitional nature of weather and load shapes that occur in September.

Commission Response

The commission declines to adopt Southern Power's recommendation to split September between the summer and fall months. The weather and load shapes that occur in Texas throughout the month of September are most consistent with the weather and load shapes in the summer months. Additionally, including the entirety of September in the summer season best aligns with the seasonal definition ERCOT uses in other studies and programs.

Shoulder months

TEC recommended removing the shoulder months from proposed §25.65(b)(6). TEC reasoned that most maintenance outages occur during the shoulder months and compliance with the performance requirements during those months will place additional strain on an already strained electric generating facility that is seeking one of the limited outage slots available for maintenance needs during the shoulder months. Because the grid need is elevated in the summer and winter months, TEC recommended that the proposed rule focus on those months.

Commission Response

The commission declines to adopt TEC's recommendation to remove the shoulder months from adopted §25.65(b)(12). The adopted rule provides for exemptions from the performance requirement for electric generating facilities that are on planned maintenance outages. Additionally, while the summer and winter months might currently have an elevated need and there may be little to no risk during shoulder months, the performance requirement should account for the increasing potential for high-risk hours in the shoulder months due to changes in the generation fleet.

Proposed §25.65(b)(7) - Seasonal average generation capability

Proposed §25.65(b)(7) defines SAGC for each season as the average of the ratio of real-time telemetered HSL to the seasonal rated capacity of an electric generating facility across all intervals during the prior three years multiplied by the seasonal rated capacity of the electric generating facility at the beginning of the relevant season. For an electric generating facility that has been in operation for less than three years, ERCOT will use the operational data that is available for each season.

Calculation for energy storage resources

Potomac recommended clarifying whether and how energy storage resources should receive a calculated SAGC. During charging intervals, energy storage resources are incentivized to telemeter an HSL of 0 MW (or a negative HSL, if rules allow it) to minimize their future SAGC. Therefore, if energy storage resources are to receive an SAGC, then Potomac recommended that their SAGC's calculation exclude charging intervals.

Commission Response

The commission declines to adopt Potomac's recommendation to clarify whether and how energy storage resources should receive a calculated SAGC. Instead, the commission clarifies in adopted §25.65(e) that an energy storage resource may provide its full HSL in a given hour to firm an electric generating facility subject to the performance requirements under the adopted rule. Therefore, an SAGC does not need to be calculated for an energy storage resource and further clarification is unnecessary.

Potential for gaming

Potomac noted that because the definition for SAGC is a function of real-time HSL across all intervals in a given season, generators that telemeter a higher HSL will be held to a higher benchmark during compliance intervals while those telemetering a lower HSL will be held to a lower benchmark. By averaging all intervals in its definition for the SAGC, the proposed rule invites electric generating facilities to lower their telemetered HSL during intervals where they likely would not be awarded at their HSL. Potomac acknowledged that this constitutes a violation of ERCOT protocols and would be subject to enforcement action but wanted to note the incentive.

Commission Response

The commission acknowledges Potomac's concerns that the proposed rule invites electric generating facilities to lower their telemetered HSL during intervals where they likely would not be awarded at their HSL. However, as Potomac notes such actions would constitute a violation of ERCOT protocols and would be subject to enforcement action. Therefore, the commission declines to modify the adopted rule.

Calculation based on all available intervals

HEN recommended modifying proposed §25.65(b)(7) by inserting "available" before "intervals."

Commission Response

The commission declines to adopt HEN's recommendation to insert "available" before "intervals." This would substantively change the calculation by basing it only on intervals where the resource is available, which would artificially inflate the SAGC of an electric generating facility. The SAGC should factor in availability rather than be based solely on performance when the electric generating facility is available.

Hourly seasonal standard

APA and ACP, NextEra, SEIA, TEBA, TIEC, and TSSA recommended modifying proposed §25.65(b)(7) to use an hourly seasonal 1x24 standard to calculate each electric generating facility's SAGC. According to these commenters, the seasonal 1x24 standard aligns with the requirement in PURA §39.1592 that an electric generating facility "be available to operate when called on . . . at or above the seasonal average generation capability . . . based upon expected resource availability" for each hour in an operating day. Specifically, the 1x24 standard captures a zero percent capacity factor for solar during night hours and thus aligns with the statutory requirement to base the SAGC on expected resource capability.

Commission Response

The commission declines to adopt APA and ACP, NextEra, SEIA, TEBA, TIEC, and TSSA's recommendation to use an hourly seasonal 1x24 standard to calculate each electric generating facility's SAGC. PURA §39.1592 requires demonstration of the ability to dispatch at or above the SAGC, not the hourly capability within a season. Moreover, the commission disagrees that "expected resource availability" implies that the SAGC should include 24 individual, hourly capabilities. The SAGC accounts for expected resource availability for all hours within a season and uses that information to determine the average capability of an electric generating facility.

Five years of operating data

APA and ACP, SEIA, and TSSA recommended using five years of operating data, when available, to calculate the SAGC. This ensures a variety of weather year output profiles are considered for weather dependent resources.

Commission Response

The commission adopts APA and ACP, SEIA, and TSSA's recommendation to modify the definition of SAGC in adopted §25.65(b)(13) to base the SAGC on five years of operating data, when available, instead of three years of operating data.

Seasonal net max sustainability ratings

NRG, TCPA, and Vistra recommended modifying proposed §25.65(b)(7) to refer to the Capacity, Demand, and Reserve (CDR) "seasonal net max sustainability ratings," which relies on both the historical and upcoming seasonal values as the multiplier to set the SAGC. According to these commenters, the applicable seasonal net maximum rating reflects each electric generating facility's normal maximum operating output at a temperature that correlates to typical peak load for each season and accounts for uprates if they occur. NRG, TCPA, and Vistra also recommended multiplying 75% of the seasonal rated capacity of the electric generating facility to calculate the SAGC. TCPA noted that using 75% of the seasonal net max sustainable rating to set the benchmark specifically accounts for different ambient temperature conditions that impact output without relation to actual performance, and accounts for reasonably expected derates associated with normal operations. Vistra noted that this approach recognizes that renewables cannot realistically achieve 100% of the seasonal net max sustainable rating but also sends a signal that additional firming capabilities should be developed or acquired. Finally, Vistra noted that the approach in the proposed rule inherently holds less reliable electric generating facilities to a lower standard and punishes more reliable electric generating facilities, particularly thermal dispatchable resources that will have higher HSLs during more moderate temperatures and lower HSLs during higher temperatures.

Commission Response

The commission declines to adopt NRG, TCPA, and Vistra's recommendation to outright replace the SAGC formula with a flat rating of 75% of the seasonal net max sustainability for each electric generating facility. This would impose a requirement on certain electric generating facilities that exceeds their average capability in a season. However, the commission acknowledges that the performance requirements are not intended to impose an undue burden on electric generating facilities that are high performing. Therefore, the commission modifies the adopted rule to set a maximum value for the SAGC of an electric generating facility. The commission sets the maximum value to 75% of the electric generating facility's seasonal rated capacity.

Proposed §25.65(c) - Notice of seasonal average generation capability

Proposed §25.65(c) states that prior to each season, ERCOT will (1) notify an electric generating facility of its SAGC; and (2) release the high-risk hours for the upcoming season.

Convert to a mandatory provision

Eolian and NextEra recommended modifying proposed §25.65(c) to require ERCOT to take the actions specified in proposed §25.65(c) by replacing "will" with "shall."

Commission Response

The commission adopts Eolian and NextEra's recommendation to replace "will" with a mandatory term that imposes a requirement. However, the commission replaces "will" with "must" instead of "shall" to maintain consistency with the commission's rule drafting practices.

Notice to owner or operator

Eolian recommended modifying proposed §25.65(c) to specify that ERCOT must notify the covered entity because, by practice and by rule, ERCOT communicates with the Resource Entities or QSEs, not with facilities. Similarly, SEIA recommended modifying proposed §25.65(c) to specify that notice must be provided to the owner or operator of the electric generating facility that is subject to the firming requirements set forth in the proposed rule.

Commission Response

The commission agrees with Eolian that notice should be provided to the owner or operator that is responsible for firming an electric generating facility. However, the commission declines to adopt the proposed term "covered entity" and instead uses the term "owner or operator" to maintain consistency with the language used in PURA §39.1592. The commission adopts SEIA's recommendation to clarify that notice must be provided for the electric generating facility that is subject to the performance requirements.

Two to three year lead time

NextEra recommended adding a requirement for ERCOT to calculate the SAGC two to three years before the compliance period begins to allow future electric generating facilities enough lead time to prepare for meeting the performance requirements set forth in the proposed rule. This lead time would be used to identify expected incremental costs of firming, negotiate contracts for new electric generating facilities, and develop new supply, or execute a bilateral contract to meet the performance requirements.

Commission Response

The commission declines to adopt NextEra's recommendation to add a requirement for ERCOT to calculate the SAGC two to three years before the compliance period begins. Specific timelines should be addressed in ERCOT protocols, which are developed with input from stakeholders and ultimately approved by the commission. Moreover, PURA §39.1592 becomes binding on certain electric generating facilities as soon as 2028 rendering NextEra's recommendation difficult, if not impossible, to implement.

Timeline to notice ahead of season

To allow an owner or operator sufficient time to economically structure their firming arrangements, Southern Power, TXOGA, and TPPA recommended specifying the time period that ERCOT must provide information under proposed §25.65(c). Southern Power recommended at least 45 days prior to the start of each season. TXOGA recommended at least 30 days prior to the start of each season. TPPA recommended at least six months in advance.

Commission Response

The commission declines to adopt Southern Power, TXOGA, and TPPA's recommendation to specify the time period by which ERCOT must provide the information described in adopted §25.65(c). ERCOT is best situated to determine the appropriate timeline based on its processes and workflow. Therefore, the commission leaves the timeline to be addressed in ERCOT protocols, which are developed with input from stakeholders and ultimately approved by the commission.

Content of notice and publication

TXOGA recommended modifying proposed §25.65(c) to require ERCOT to publish the high-risk hours, the methodologies, data summaries, and supporting statistics used to determine the SAGC values and the seasonal high-risk hours (and any seasonal PRC threshold). TPPA recommended requiring ERCOT to publicly publish the notice of high-risk hours.

Commission Response

The commission declines to adopt TXOGA's recommendation to require ERCOT to publish the methodologies, data summaries, and supporting statistics used to determine the SAGC values and the seasonal high-risk hours (and any PRC threshold) because it is unnecessary. ERCOT is required to notify the owner and operator of the SAGC values of their electric generating facilities, and ERCOT can provide additional information to the owner or operator upon request.

The commission agrees with TXOGA and TPPA that the high-risk hours should be published publicly. Accordingly, the commission makes clarifying changes to adopted §25.65(c).

Exigent circumstances

TEC recommended modifying proposed §25.65(c) to account for exigent circumstances that may be unknown to ERCOT that directly impact the ability of an electric generating facility to perform up to its SAGC by authorizing ERCOT to use a deadband or sliding scale to assess penalties. In essence, this approach would give resources with consistent overperformance greater leeway to continue overperformance without the increased risk of incurring a financial penalty. In contrast, the approach in the proposed rule would penalize an electric generating facility that consistently overperforms by including its overperformance in the calculation of the facility's SAGC thus increasing the facility's SAGC over time.

Commission Response

The commission agrees with TEC that high-performing electric generating facilities should not be punished for continued high availability. However, rather than establish a deadband or sliding scale to assess penalties, as recommended by TEC, the commission modifies the SAGC formula to cap it at 75% of an electric generating facility's seasonal rated capacity. This avoids disincentivizing a high performing electric generating facility to continue its high performance during all available hours.

Proposed §25.65(d) - Reliability requirement

Proposed §25.65(d) requires an electric generating facility to operate or be available to operate when called on for dispatch at or above the SAGC during a low operation reserve hour that occurs within a high-risk hour.

Clarifications

TPPA recommended using the term "firming" in place of "reliability" to ensure clarity in future discussions and to avoid conflating concepts such as the reliability standard and firming requirements.

Commission Response

The commission adopts TPPA's recommendation to remove the term "reliability" to provide clarity and avoid conflating concepts such as the reliability standard and firming. Additionally, the commission makes clarifying changes throughout the adopted rule to distinguish between performance requirements, firming a portfolio, providing firming service, and assuming a firming obligation.

SAGC applicability

TPPA recommended clarifying that the SAGC is specific to each electric generating facility and is not a uniform value applied to all facilities.

Commission Response

The commission adopts TPPA's recommendation to clarify that the SAGC is specific to each electric generating facility and is not a uniform value applied to all facilities. However, the commission adds the clarification to adopted §25.65(c)(1).

Existing electric generating facility's capacity to firm

NextEra and TCPA recommended specifying that an existing electric generating facility can be used to meet a new electric generating facility's performance requirement.

Commission Response

The commission declines to adopt NextEra and TCPA's recommendation to specify that an existing electric generating facility can be used to meet a new electric generating facility's performance requirement because it is unnecessary. An existing electric generating facility meets the definition of an electric generating facility and adopted §25.65(e)(1) states that an owner or operator of an electric generating facility may meet the performance requirements by supplementing or contracting with another electric generating facility.

Ability to provide full capacity for firming

APA and ACP, Eolian, NextEra, and TSSA recommended that an electric generating facility that provides firming should be able to provide all of its capacity for firming and not be limited to providing only that capacity that exceeds the SAGC.

Similarly, Tesla recommended modifying proposed §25.65(d) to specifically recognize that all output specifically from an energy storage resource may be used to meet an electric generating facility's firming requirement regardless of the energy storage resource's SAGC.

Commission Response

The commission declines to adopt APA and ACP, Eolian, NextEra, and TSSA's recommendation to allow an electric generating facility that provides firming to provide all of its capacity for firming. All electric generating facilities with a SGIA signed after January 1, 2027 must meet the performance requirements. Additionally, while existing electric generating facilities are not subject to the performance requirements, the commission determines that existing electric generating facilities should be able to provide firming to satisfy the performance requirements of new electric generating facilities only if the existing electric generating facilities themselves would satisfy the performance requirement. The commission agrees with Tesla's recommendation to recognize that the full output from an energy storage resource may be used to satisfy the performance requirements of an electric generating facility. Accordingly, the commission modifies adopted §25.65(e)(2)(B) to clarify that an energy storage resource may provide its full capacity to firm an electric generating facility that is subject to the performance requirements.

Sustained operation

GRIT recommended specifying that an electric generating facility must be capable of sustained operation for three to four hours during high-risk periods. According to GRIT, this requirement would help address reliability needs during extended events and would ensure that electric generating facilities providing firming capacity can deliver consistent output for the duration of the risk period.

Commission Response

The commission declines to adopt GRIT's recommendation to specify that an electric generating facility must be capable of sustained operation for three to four hours during high-risk periods because it is unnecessary. The risk of failing to meet the performance requirements is borne by the owner or operator of an electric generating facility subject to the performance requirements. If there is an expectation of longer duration risk within a season, that will be captured within the baseline period that may be subject to a financial penalty. Moreover, if the owner or operator of an electric generating facility relies on a firming resource that is incapable of being dispatched for the baseline period, the owner or operator of the firming resource that undertook the firming obligation is subject to the financial penalty for the low operation reserve hours in which the firming resource was unavailable.

Physical performance limitations

TAEBA recommended adding language to make explicit that performance hour expectations apply only when resources can physically perform to avoid punishing electric generating facilities for their inherent operational characteristics.

Commission Response

The commission declines to add TAEBA's recommended language explicitly stating that performance hour expectations apply only when resources can physically perform. The expected availability of an electric generating facility is accounted for by using the historical average availability across all hours in the season to determine the SAGC of an electric generating facility. An electric generating facility is expected to be available to dispatch up to its SAGC, or firm to do so, during times of highest reliability risk due to low operation reserves.

Mechanism for trade arrangements

NextEra recommended modifying proposed §25.65(d) to require ERCOT to develop a market mechanism by which owners or operators are able to contractually arrange to meet their firming obligations by trading firming MW after an event occurs in which penalties could be triggered.

Commission Response

The commission agrees with NextEra's recommendation to add language to the adopted rule requiring ERCOT to create a mechanism in the ERCOT protocols to allow owners or operators to arrange to meet their performance requirements by trading. The commission modifies the adopted rule accordingly.

Proposed §25.65(d)(1) - Firming

Proposed §25.65(d)(1) specifies that an owner or operator of an electric generating facility may meet the firming requirements set forth in the proposed rule by supplementing the owner or operator's portfolio or contracting with: (A) another electric generating facility that is either on-site or off-site; or (B) an on-site or off-site battery energy storage resource.

Full capacity can be provided for firming purposes

APA and ACP, SEIA, and TSSA recommended modifying proposed §25.65(d)(1) to specify that resources that are not subject to the performance requirements set forth in the proposed rule can offer their entire capacity, either by physical co-location or financial contracting, to firm an electric generating facility that is subject to the performance requirements set forth in the proposed rule.

Commission Response

The commission declines to adopt APA and ACP, SEIA, and TSSA's recommendation to specify that resources that are not subject to the performance requirements can offer their entire capacity. While existing electric generating facilities are not subject to the performance requirements, the commission determines that existing electric generating facilities should only be able to provide firming to satisfy the performance requirements of new electric generating facilities if the existing electric generating facilities themselves would satisfy the performance requirements.

Capacity in excess of SAGC

APA and ACP and TSSA recommended modifying proposed §25.65(d)(1) to specify that if an electric generating facility subject to the performance requirements has capacity in excess of its SAGC, the facility may provide that excess capacity to firm other electric generating facilities.

Commission Response

The commission adopts APA and ACP and TSSA's recommendation to specify that if an electric generating facility subject to the firming requirements has capacity in excess of its SAGC, the facility may provide that excess capacity to firm other electric generating facilities. Accordingly, the commission makes this clarification to adopted §25.65(e)(2)(A).

Proposed §25.65(d)(2) - Disclosure to ERCOT

Proposed §25.65(d)(2) requires an owner or operator that supplements from its portfolio or contracts with another electric generating facility or battery energy storage resource to meet its firming requirements to disclose the arrangement to ERCOT and provide ERCOT with any additional information reasonably required for ERCOT to perform its duties under the proposed rule.

Timeline for disclosure

APA and ACP, Eolian, SEIA, and TSSA recommended modifying proposed §25.65(d)(2) to specify that the disclosure must be made no later than two weeks following the end of each season.

Commission Response

The commission declines to adopt APA and ACP, Eolian, SEIA, and TSSA's recommendation to specify that the disclosure must be made no later than two weeks following the end of each season. This timeline is better addressed in ERCOT protocols, which are developed with input from stakeholders and must ultimately be approved by the commission.

Required disclosure should apply only for contractual arrangements outside of the owner or operator's portfolio

NextEra recommended modifying proposed §25.65(d)(2) to clarify that the disclosure requirements apply if an owner or operator contracts with another electric generating facility or energy storage resource "outside of its portfolio."

Commission Response

The commission declines to adopt NextEra's recommendation to state that the disclosure requirements apply if an owner or operator contracts with another electric generating facility or energy storage resource "outside of its portfolio" because ERCOT must be made aware of all arrangements, whether within the same portfolio or across portfolios, for settlement purposes.

Limiting the disclosed information

Because these arrangements are likely to include sensitive commercial information that is not necessary for ERCOT to perform its duties under the proposed rule, Southern Power recommended modifying proposed §25.65(d)(2) to limit the information provided to ERCOT to information that is strictly necessary, such as confirmation from the contracting parties of the trading arrangement and the MW capability transacted over the relevant season. For avoidance of doubt, Southern Power also recommended including a sentence that states parties to a trade will not be required to disclose copies of any contractual arrangements to such trade.

TPPA recommended modifying proposed §25.65(d)(2) to specifically identify the information that ERCOT requires to verify trade arrangements by clarifying that only the executed trade agreement is necessary.

Commission Response

The commission declines to adopt Southern Power and TPPA's recommendations to limit the information provided to ERCOT to specific information identified in the rule. The adopted rule already limits the information to that which is reasonably required by ERCOT to perform its duties under the rule. Any further specification is appropriately addressed in ERCOT protocols, which are developed with input from stakeholders and are ultimately approved by the commission.

ERCOT processes and procedures

TXOGA recommended requiring ERCOT to develop and document new procedures to prevent double-counting and to ensure verifiability of contracted firming resources. Similarly, TPPA recommended making ERCOT responsible for confirming that any trade arrangements established to meet the firming requirements set forth in the proposed rule are unique and that multiple electric generating facilities are not relying on the same contracted capacity to satisfy their obligation. Additionally, TPPA recommended requiring ERCOT to notify the parties to a trade arrangement if ERCOT is unable to confirm the trade arrangement or the trade arrangement relies on the same capacity that is already provide in another trade arrangement.

Commission Response

The commission agrees with TXOGA and TPPA's recommendations to require ERCOT to verify trade arrangements between an electric generating facility subject to the performance requirements and a firming resource that assumes a firming obligation. Accordingly, the commission modifies the rule to require ERCOT to develop new processes for confirming arrangements related to firming and notifying parties in a firming arrangement if ERCOT is unable to confirm the arrangement.

Load resource

TIEC recommended modifying proposed §25.65(d)(2) to include reference to a load resource to conform with TIEC's recommended modification to proposed §25.65(d)(1).

Commission Response

The commission declines to adopt TIEC's recommendation to explicitly include reference to a load resource in adopted §25.65(e)(4) to conform with its recommended modification to proposed §25.65(d)(1) because it is unnecessary. The commission restructures the adopted rule and identifies that a load resource may provide firming in adopted §25.65(e)(1).

Proposed §25.65(e)(1) - Financial penalty

Proposed §25.65(e)(1) requires ERCOT to impose a financial penalty on an electric generating facility if the electric generating facility fails to operate or is unavailable to operate when called on for dispatch at or above the SAGC during a low operation reserve hour that occurs within a high-risk hour and did not supplement effectively from its portfolio or by contractual arrangement disclosed to ERCOT for any shortages. Proposed §25.65(e)(1) also states that a financial penalty imposed must be 20% of the effective value of lost load used to determine the ancillary service demand curves (ASDCs) for the DAM and real-time market and applied to the shortage megawatt hours (MWh). Moreover, in seasons where more than 15 low operation reserve hours occur during the seasonal high-risk hours, only the 15 low operation reserve hours with the lowest level of PRC will be subject to the financial penalty.

SAGC should account for actual dispatchability in compliance interval

Potomac recommended that application of the language "an electric generating facility must operate or be available to operate when called on for dispatch at or above the SAGC during a low operation reserve hour that occurs within a high-risk hour" should take into consideration actual dispatchability in the compliance interval and not rely on telemetered availability status. For example, a firming resource with a two-hour start time cannot firm another resource in an hour where the firming resource is not currently operating at its low sustained limit (LSL) or higher even if its status is "available" with a high telemetered HSL. The actual ability of a resource to provide energy or ancillary services to support the firming capacity should be accounted for in both the calculation of the SAGC and the accounting to determine if financial penalties are appropriate in any compliance intervals.

Commission Response

The commission declines to modify the adopted rule to accommodate Potomac's concern because it is unnecessary. The statute requires the owner or operator of an electric generating facility to demonstrate that their portfolio can operate or be available to operate when called on, and the adopted rule captures this language and requirement. This approach is also consistent with how the commission accounted for availability in the Texas Energy Fund Loan Program.

Resource-specific financial penalty relative to an average market resource

LCRA recommended modifying proposed §25.65(e)(1) to make the firming penalty resource-specific and reflective of the historic availability of each resource relative to an average market resource. In essence, LCRA recommended replacing the flat VOLL used to assess financial penalties across all resources, with a penalty that is based upon individual historic availability, and scaled or discounted based on the resource's historic contribution to system reliability. To effectuate this recommendation, LCRA also recommended modifying proposed §25.65(e)(1) to require ERCOT to calculate and publish a low, medium, and high performance threshold ahead of each season, along with each resource's calculated penalty.

Commission Response

The commission declines to adopt the scaled penalty structure proposed by LCRA. However, to mitigate concerns that financial penalties may have an oversized impact on high-performing electric generating facilities, the commission modifies the definition for SAGC to incorporate a cap set at 75% of an electric generating facility's seasonal rated capacity.

Specify the penalty amount instead of linking to VOLL

APA and ACP, Eolian, SEIA, TCPA and TSSA recommended modifying proposed §25.65(e)(1) to provide regulatory certainty by specifying that the penalty is $1,000 per MWh. APA and ACP and TSSA also recommended clarifying that if the peaker net margin threshold is reached and the system-wide offer cap is set to the low system-wide offer cap, then the penalty is $400 per MWh. SEIA recommended clarifying that a financial penalty may be assessed on fewer than 15 low operation reserve hours in a season, with the potential that there may be no low operation hours in a season.

Commission Response

The commission declines to adopt APA and ACP, Eolian, SEIA, TCPA and TSSA's recommendation to set the financial penalty to a specific dollar per MWh value in the adopted rule. However, to provide regulatory certainty that the value of the financial penalties will not change without a commission rulemaking taking place, the commission modifies the adopted rule to reference the system-wide offer cap that is in effect.

Equate the penalty to 20% of the system-wide offer cap and implement a tolerance band

NextEra recommended modifying proposed §25.65(e)(1) to equate the penalty to 20% of the system-wide offer cap for a maximum of 15 hours per season. NextEra also recommended for purposes of calculating financial penalties, implementing a tolerance band for shortages that is equal to the higher of 10 MW or 10% of the seasonal rated capacity.

Commission Response

The commission adopts NextEra's recommendation to modify the adopted rule to equate the penalty to 20% of the system-wide offer cap that is in effect. However, the commission declines to implement a tolerance band for shortages, as the statute requires financial penalties for failing to comply with the performance requirements, even at a de minimis level.

Base the penalty on the real-time system lambda or 20% of the effective VOLL

TXOGA recommended modifying proposed §25.65(e)(1) to base the financial penalty on the lower of the real-time system lambda or 20% of the effective VOLL.

Commission Response

The commission declines to adopt TXOGA's recommendation to tie the financial penalty value to the real-time system lambda. Instead, the commission modifies the adopted rule to set the financial penalty at 20% of the system-wide offer cap that is in effect. Having a clearly defined financial penalty provides certainty on the potential exposure to financial penalties in each season.

Gaming opportunities

Potomac recommended that during compliance hours, eligible electric generating facilities are considered to commit their SAGC into the market under the same rules imposed by the DAM. An electric generating facility that operates below its SAGC during compliance intervals would be required to pay an imbalance payment in the real-time market. During extremely tight conditions, the resulting firming penalty would be valued closer to VOLL while less tight conditions result in a lower penalty. This would eliminate gaming opportunities and scale the penalty to the reliability risk that the grid experiences.

Commission Response

The commission declines to adopt Potomac's recommendation to scale the financial penalties. Financial penalties for failure to meet the performance requirements under the adopted rule would only be imposed during low operation reserve hours, which are the times when ERCOT is facing tight conditions. Therefore, scaling the financial penalties based on how tight the tight conditions are is unnecessary.

Goal of the firming program

TPPF recommended that the financial penalty be based on the cost of new entry (CONE) multiplied by the unit's average annual firming requirement. TPPF cautioned that by basing the financial penalty amount on VOLL, the proposed rule advances the notion that the firming program is designed to incentivize greater resiliency--namely, performance during emergency conditions--rather than to improve the valuation of generator reliability on a consistent annual basis. TPPF recommended that the firming program should be set with two key points in mind (1) the financial penalty sets the maximum amount that generators will pay for firming resources (if firming costs more than the financial penalty, then generators will prefer to pay the financial penalty); and (2) the true value of "full firming" is the CONE for a dispatchable generator--such as a gas combustion turbine and not a duration limited resource such as energy storage--that is equal in size to the variable generator's performance requirement. At a broad level, the goal of the firming program should be to ensure that new units entering the ERCOT market each year are meeting the reliability standard, either individually or at least in the aggregate. If that goal is achieved, then ERCOT can be assured of meeting the reliability standard in the future; conversely, not achieving that goal means that at some point the resource mix will not be able to meet the reliability standard. Therefore, the commission should assess whether the financial penalty necessary to achieve that goal is equal to the full firming cost or less than that.

Commission Response

The commission disagrees with TPPF that the purpose of the firming program is to ensure that new units entering the ERCOT market each year are meeting the reliability standard, either individually or in the aggregate. The purpose of the performance requirements established by PURA §39.1592 is to incentivize owners or operators of electric generating facilities to ensure that their electric generating facilities are available at their average capability in a given season during hours with tight conditions due to low operation reserves that occur within that season. The adopted rule satisfies this objective by requiring the owner or operator of an electric generating facility subject to the performance requirements to demonstrate that they can perform during these hours with low operation reserves, supplement or contract with firming resources that can perform during those hours, or risk being penalized for failing to do so.

The commission also disagrees with TPPF's recommendation to base the financial penalty on the cost of new entry of a firming resource, specifically a new combustion turbine. The statute specifically states that the owner or operator of an electric generating facility is allowed to supplement or contract with an energy storage resource to satisfy these performance requirements, indicating that the cost of new entry for any specific dispatchable technology would not be the appropriate threshold to set the financial penalties for failing to meet the performance requirements.

Base the penalty on 10% of ancillary service pricing

TAEBA recommended modifying proposed §25.65(e)(1) to base the penalty on 10% of ancillary service pricing that is required to cover any shortfalls of expected generation.

Commission Response

The commission declines to adopt TAEBA's recommendation to base the penalty on 10% of ancillary service pricing that is required to cover any shortfalls of expected generation. The financial penalty in the adopted rule strikes the balance of providing a deterrence for non-compliance and providing the owner or operator of an electric generating facility with certainty as to the potential financial penalty they could face if their portfolio fails to satisfy the performance requirements.

Decrease the number of hours that generators must firm

TAEBA recommended decreasing the number of hours that generators must firm on an annual basis from 60 to 40. TAEBA reasoned that 60 hours seems excessive when EEAs are so rare.

Commission Response

The commission disagrees with TAEBA and declines to decrease the number of hours in which a financial penalty could potentially be imposed on the owner or operator of an electric generating facility that fails to satisfy the performance requirements. While it is possible that there could be 60 low operation reserve hours in a year, financial penalties would only be assessed for a maximum of 15 hours in any given season. If there are 60 low operation reserves hours with an associated financial penalty throughout the year, that would mean that ERCOT is experiencing tight conditions in all seasons, and the proposed number of penalty hours would be warranted.

Set the penalty at a level that does not result in market distortions

Vistra recommended modifying proposed §25.65(e)(1) by replacing the requirement that the financial penalty imposed be 20% of the effective VOLL used to determine the ASDCs with a requirement that the financial penalty be set at a level that does not result in distortions for the DAM and real-time market.

Commission Response

The commission declines to modify the rule to align with Vistra's recommendation to state generally that the financial penalty must be set at a level that does not result in distortions for the DAM and real-time market. The financial penalty in the adopted rule strikes the balance of providing a deterrence for non-compliance and providing the owner or operator of an electric generating facility with certainty as to the potential financial penalty they could face if their portfolio fails to satisfy the performance requirements.

Align with requirement to deposit penalties into state treasury

Eolian recommended modifying proposed §25.65(e)(1) to align with PURA §15.033 and Texas Government Code §404.094, which require that penalties collected under PURA be deposited into the state treasury and credited to the General Revenue Fund unless otherwise authorized by statute.

Commission Response

The commission disagrees with Eolian that the financial penalties contemplated in PURA §39.1592 are subject to the requirements of PURA §15.033 and Texas Government Code §404.094, which require that penalties collected under PURA be deposited into the state treasury and credited to the General Revenue Fund unless otherwise authorized by statute. PURA §39.1592 not only contemplates that ERCOT, not the commission, must impose financial penalties but also that ERCOT must provide financial incentives for the firming program. Importantly, PURA §39.1592 is silent with respect to how the financial incentives for the firming program should be funded.

A more careful reading of PURA in its entirety suggests that the commission must require ERCOT to impose financial penalties to underperformers and provide financial incentives to overperformers under PURA §39.1592 independent of PURA Chapter 15. Throughout Subchapter B of Chapter 15, the term "penalty" is used to more broadly describe "administrative penalty" and "civil penalty." PURA §15.027 requires an administrative penalty collected under Subchapter B, Enforcement and Penalties, of Chapter 15, Judicial Review, Enforcement, and Penalties, be sent to the comptroller. PURA §15.033 requires fines or penalties collected under another provision of PURA (i.e., not collected under Subchapter B of Chapter 15 and therefore not collected under PURA §15.027) be paid to the commission. Although PURA §15.033 uses the broader term "penalties," context from the rest of Subchapter B of Chapter 15 suggests that the term "penalties" is used to describe administrative penalties and civil penalties that are collected under a provision of PURA that falls outside of Subchapter B of Chapter 15. In essence, PURA §15.027 and PURA §15.033 both address the disposition of administrative penalties and civil penalties. Those administrative penalties and civil penalties that are collected under Chapter 15 must be sent to the comptroller and those administrative penalties and civil penalties that are collected under any other provision in PURA, must be paid to the commission. The financial penalties that are contemplated in PURA §39.1592 are neither an administrative penalty nor a civil penalty. As the more specific provision, PURA §39.1592 prevails over the more general Chapter 15 provisions, including PURA §15.033.

Moreover, in instances where a provision of Chapter 39 is to be administered in accordance with PURA Chapter 15, the Texas Legislature has explicitly stated so. See PURA § 39.101(e) (stating the commission may assess civil and administrative penalties under Section 15.023 and seek civil penalties under Section 15.028); PURA § 39.151(d-4)(5) (stating the commission may assess administrative penalties against ERCOT and the attorney general may apply for a court order to require ERCOT to comply with commission rules and orders in the manner provided by Chapter 15); PURA § 39.157(a) (stating the commission may seek civil penalties as necessary to eliminate or to remedy market power abuse or a violation as authorized by Chapter 15 or by imposing an administrative penalty as authorized by Chapter 15); PURA 39.357 (stating that the commission may impose an administrative penalty, as provided by Section 15.023 for violations described by Section 39.356); and PURA § 39.661 (stating that the commission may use any enforcement mechanism established by Chapter 15 against any entity that fails to remit excess receipts from the uplift balance financing under Section 39.653(e) or otherwise misappropriates or misuses amounts received from the uplift balance financing Subchapter N). In contrast, PURA § 39.1592 does not reference PURA Chapter 15.

Finally, Texas Government Code §311.021(3), (4), and (5) collectively state that in enacting a statute, it is presumed that a just and reasonable result is intended; a result feasible of execution is intended; and public interest is favored over any private interest. The Texas Legislature did not appropriate money to fund the firming program contemplated in PURA §39.1592. That leaves two remaining options to fund the required financial incentives: (1) load serving entities; or (2) the pool of financial penalties imposed and collected by ERCOT. Because the purpose of the firming program is to ensure that new electric generating facilities are operating or available to operate during tight conditions, electric generating facilities that are unable to do so should bear the cost for failing to meet the performance requirements, not load serving entities. Additionally, ERCOT routinely settles market payments based on electric generating facilities' availability and performance. Therefore, the commission determines that when reading PURA in its entirety, Chapter 15 is not applicable to the financial penalties imposed by ERCOT under PURA §39.1592. Additionally, the commission determines that it is reasonable to require that the financial incentives be provided from the pool of financial penalties that are imposed and collected by ERCOT.

Consequences of a bilateral trade

ERCOT recommended modifying proposed §25.65(e)(1) to state that if a QSE enters into a bilateral trade on behalf of an electric generating facility in its portfolio such that another QSE's electric generating facility assumes responsibility for providing the energy or ancillary service subject to the trade, ERCOT will look to that entity for performance and settlement purposes.

Commission Response

The commission agrees with ERCOT's recommendation and modifies the adopted rule to clarify that a firming resource that supplements the portfolio of, or contracts with, the owner or operator of an electric generating facility that is subject to the performance requirements assumes a firming obligation, including the financial penalties associated with the performance requirement. Additionally, the commission modifies the adopted rule to clarify that if a QSE enters into a bilateral trade on behalf of an electric generating facility in its portfolio such that another QSE's electric generating facility assumes responsibility for providing the energy or ancillary service subject to the trade, ERCOT must look to that entity for performance and settlement purposes.

Clarification

TPPA recommended clarifying that if the system does not face actual risk during the lowest reserve hours, then no penalty should be assessed. TPPA also recommended clarifying that an electric generating facility that fails to meet its performance requirement will not be subject to any penalties beyond the financial penalty outlined in proposed §25.65(e)(1).

Commission Response

The commission agrees with TPPA and adopts TPPA's recommendation to clarify that there will not be a financial penalty imposed in a season with no low operation reserve hours. However, the commission declines to adopt TPPA's recommendation to clarify that an electric generating facility that fails to meet its performance requirement will not be subject to any penalties beyond the financial penalty outlined in the adopted rule. The financial penalty outlined in adopted §25.65(f) is the only penalty created by this rule, but being assessed this financial penalty does not prevent additional penalties from being assessed for things unrelated to the performance requirements in the adopted rule.

Proposed §25.65(e)(2) - Financial penalty exemption

Proposed §25.65(e)(2) exempts an electric generating facility from a financial penalty if the electric generating facility is: (A) unavailable during the applicable hour due to a planned maintenance outage or derate that was approved by ERCOT, or a transmission outage; (B) a switchable generation resource committed to a neighboring independent system operator (ISO) or regional transmission operator (RTO); (C) awarded in the DAM; or (D) awarded ancillary service or reliability service that has an associated penalty for failure to perform.

Entities that assume a firming obligation

ERCOT recommended modifying proposed §25.65(e)(2) to state that an entity that accepts a contractual arrangement to provide firming to an electric generating facility is not exempt from financial penalties.

Commission Response

The commission agrees with ERCOT's recommendation to clarify that a firming resource that accepts a contractual arrangement to provide firming to an electric generating facility is not exempt from financial penalties and modifies the adopted rule accordingly. A QSE representing a firming resource that assumes a firming obligation could be subject to a financial penalty if their firming resource fails to satisfy that obligation.

Gaming

HEN raised a concern that because proposed §25.65(c)(2) requires ERCOT to publish the high-risk hours for the upcoming season, owners may conveniently request outages during those periods to avoid the potential for financial penalties under proposed §25.65(e).

Commission Response

The commission disagrees with HEN that publishing the high-risk hours for the upcoming season may incentivize owners of electric generating facilities to request outages during the baseline periods to avoid the potential for financial penalties. The published baseline periods are hours that occur every day within a season where an owner or operator of an electric generating facility could face a financial penalty if their electric generating facility is unable to satisfy the performance requirements in the adopted rule. This would mean that the owner or operator would need to request outages only during specific hours during the season, which is not consistent with the process that ERCOT uses to approve planned outage requests.

Opportunity outage

TCPA and Vistra recommended modifying proposed §25.65(e)(2)(A) to exempt an electric generating facility from financial penalties if the electric generating facility is unavailable due to an opportunity outage, which occurs at times when an electric generating facility is forced offline but has been previously approved for a planned outage within the next two days.

Commission Response

The commission adopts TCPA and Vistra's recommendation to exempt an electric generating facility from financial penalties if the electric generating facility is unavailable due to an opportunity outage. ERCOT protocols describe opportunity outages as a special category of Planned Outages, which are distinct from planned maintenance outages. The commission modifies the adopted rule accordingly.

Curtailment

APA and ACP, Eolian, NextEra, SEIA, and TSSA recommended modifying proposed §25.65(e)(2)(A) to exempt an electric generating facility from financial penalties if the electric generating facility is curtailed by ERCOT to manage transmission congestion or other reliability issues.

Commission Response

The commission declines to adopt APA and ACP, Eolian, NextEra, SEIA, and TSSA's recommendation to exempt an electric generating facility from financial penalties if the electric generating facility is curtailed by ERCOT. Electric generating facilities that receive curtailment instructions from ERCOT would not have their high sustained limit impacted by the curtailment. Therefore, the curtailment instruction would not impact the ability of the electric generating facility to satisfy the performance requirements, and no exemption is warranted.

Force majeure event

APA and ACP, LCRA, NRG, Southern Power, TEC, and TSSA recommended modifying proposed §25.65(e)(2)(A) to exempt an electric generating facility from financial penalties if the electric generating facility is unavailable due to a force majeure event.

Commission Response

The commission declines to adopt APA and ACP, LCRA, NRG, Southern Power, TEC, and TSSA's recommendation to include a specific exemption for unavailability during a force majeure event. An electric generating facility is expected to operate during extreme weather. However, as noted below, the commission modifies the adopted rule to exempt an electric generating facility that is unavailable due to a market suspension, which is defined in ERCOT protocols to include force majeure events that disable all, or a significant portion of, the necessary data and/or infrastructure for operations of ERCOT's systems and markets.

Forced outage or derate

LCRA recommended modifying proposed §25.65(e)(2)(A) to exempt an electric generating facility from financial penalties if the electric generating facility is unavailable due to a forced outage or derate having lasted longer than 60 days. LCRA noted that the addition of a $1,000/MWh financial penalty necessarily increases the cost of: (1) managing through a small maintenance issue, such as a tube leak, or (2) entering a forced outage for a small maintenance issue, such as a tube leak.

Commission Response

The commission declines to adopt LCRA's recommendation to add an exemption that accommodates extended forced outages. While the owner or operator of an electric generating facility experiencing an extended forced outage would face increased risk to a financial penalty for the duration of that electric generating facility's extended forced outage, the owner or operator could contract with a firming resource to satisfy the performance requirements while their electric generating facility is offline. Additionally, the performance of that electric generating facility would result in a decreased SAGC in future years, meaning that the owner or operator could earn additional incentives if the electric generating facility is able to perform in those future years.

Market suspension

ERCOT recommended modifying proposed §25.65(e)(2)(A) to exempt an electric generating facility from penalties if the electric generating facility is unavailable due to a market suspension, as that term is defined in the ERCOT protocols.

Commission Response

The commission adopts ERCOT's recommendation to add an exemption for unavailability due to a market suspension.

Environmental compliance requirements

LCRA and NRG recommended modifying proposed §25.65(e)(2)(A) to exempt an electric generating facility if the electric generating facility is unavailable due to environmental compliance requirements.

Commission Response

The commission agrees with LCRA and NRG's recommendation to exempt an electric generating facility if the electric generating facility is unavailable due to environmental compliance requirements. Electric generating facilities that are available to perform but restricted due to environmental compliance requirements should not be assessed a penalty for failure to satisfy the performance requirements. The commission modifies the adopted rule accordingly.

Contractual arrangement

OPUC recommended modifying proposed §25.65(e)(2)(A) to account for an instance where an owner or operator of an electric generating facility has a contractual arrangement to supplement its portfolio to meet the performance requirements.

Commission Response

The commission declines to adopt OPUC's recommendation to modify the rule to include an exemption for the owner or operator of an electric generating facility that has a contractual arrangement in place to meet its performance requirements. However, the commission does modify the adopted rule to make clear that a firming obligation (or partial firming obligation) is assumed by the owner or operator of a firming resource once the contract has been received and verified by ERCOT.

Switchable generation resource

ERCOT recommended modifying proposed §25.65(e)(2)(B) to apply to specific hours consistent with the rest of the proposed rule since a switchable generation resource may not be committed to the neighboring ISO or RTO for an entire season or the definition of the relevant season may differ.

Commission Response

The commission adopts ERCOT's recommendation to exempt a switchable generation resource that is committed to a neighboring ISO or RTO for the applicable hour rather than the applicable season. This aligns with the rest of the adopted rule. Moreover, this is consistent with the fact that a switchable generation resource may not be committed to the neighboring ISO or RTO for an entire season, or the definition of the relevant season may differ for the neighboring ISO or RTO.

Energy or ancillary service award

ERCOT, TCPA, and Vistra recommended modifying proposed §25.65(e)(2)(C) to clarify that the exemption applies if the electric generating facility is awarded energy or ancillary services in the DAM.

Commission response

The commission adopts ERCOT, TCPA, and Vistra's recommendation to clarify that the exemption applies if the electric generating facility is awarded energy or ancillary services in the DAM. The commission modifies the adopted rule accordingly.

Strike reference to "rules"

OPUC and Vistra recommended modifying proposed §25.65(e)(2)(C) by striking the reference to "rules" to provide clarity.

Commission Response

The commission adopts OPUC and Vistra's recommendation to remove the reference to "rules" in adopted §25.65(f)(2)(C) to provide clarity.

Strike exemption for award in DAM

HEN recommended striking proposed §25.65(e)(2)(C) because the firming requirements must be implemented December 1, 2026, one year after the implementation of real-time co-optimization. At that time, the DAM will be a purely financial market and only tangentially linked to a future real-time performance obligation.

Commission Response

The commission declines to adopt HEN's recommendation to remove the exemption for an award in the DAM. While only tangentially linked to a future real-time performance obligation, an electric generating facility that clears MW in the DAM but fails to perform in real-time would still bear the financial risk of non-performance.

Clarify exemption is for entire facility or portion of capacity

Southern Power recommended modifying proposed §25.65(e)(2)(C) to clarify whether the intent is to exempt an entire facility if any portion of its capacity is committed in the DAM or only to the extent of the capacity that cleared in the DAM.

Commission Response

The commission adopts Southern Power's recommendation to clarify that only the portion of an electric generating facility that is subject to a performance obligation for capacity that cleared in the DAM is exempt from the performance requirements under the adopted rule. The commission modifies the adopted rule accordingly.

Gaming

Potomac noted that there is an opportunity for gaming based on the structure of the proposed rule. Under certain conditions, an electric generating facility may face a lower cost by settling an imbalance in the real-time market than by paying the penalty imposed under the firming requirement set forth in the proposed rule. The MW a resource commits in the DAM or to ancillary services are exempt from firming obligations. In practice, firming penalties are typically triggered during hours when the ancillary services demand curves already produce high energy prices. In those cases, the firming penalty is usually less burdensome than an imbalance payment. However, the triggers differ. Compliance hours for the firming requirement are based on PRC, while high ASDC prices are driven by reserve levels. This means it is possible to have hours when PRC is low, but reserves remain sufficiently high to keep energy prices low. In such a case, an electric generating facility may be incentivized to commit its SAGC into DAM, avoid the firming penalty, and face only a relatively small imbalance cost.

Commission Response

The commission acknowledges Potomac's concern about the opportunity for gaming but declines to modify the adopted rule. ERCOT's latest biennial report on the operating reserve demand curve (ORDC) notes that when system conditions tighten and reserves become scarcer, the ORDC reserves and PRC tend to converge. The performance requirements will only trigger under tight system conditions, meaning that the risk of an extreme separation that causes a low PRC but a sufficiently high level of reserves that keeps energy prices low is minimal.

Exempt full capacity

APA and ACP recommended modifying proposed §25.65(e)(2)(C) and (D) to clarify that an electric generating facility is exempt from financial penalties if the electric generating facility is awarded any commitment or amount of capacity in the DAM, or for an ancillary service or reliability service that has an associated penalty for failure to perform.

Commission Response

The commission declines to adopt APA and ACP's recommendation to provide a full exemption for an electric generating facility that is awarded any amount of capacity in the DAM or for providing ancillary services or reliability services. Such an approach would enable an electric generating facility to circumvent the performance requirements by offering as little as one MW into the DAM or for an ancillary service or reliability service, which is not reasonable.

Exempt portion of capacity

TPPA recommended reorganizing proposed §25.65(e)(2)(C) and (D) to clarify that an electric generating facility is exempt from the performance requirements if it is awarded energy, an ancillary service, or a reliability service in the DAM. To prevent electric generating facility from bidding nominal amounts solely to qualify for an exemption, LCRA and TPPA recommended specifying that the exemption applies only to the number of MW awarded and only to the hours in which the award is received. Finally, TPPA recommended creating a process to allow an electric generating facility to request an exemption from penalties if ERCOT denies or modifies a planned outage request.

Commission Response

The commission agrees with TPPA and LCRA that the DAM exemption should only apply to the portion of an electric generating facility's capacity that is awarded in the DAM and should be limited to the hours in which the award is received. This approach ensures that the portion of the electric generating facility that is not awarded in the DAM is still subject to the performance requirements under the adopted rule and recognizes that for the portion awarded in the DAM, the electric generating facility is already incentivized to perform because of the risk of a financial penalty for failure to perform under its obligations in the DAM. The commission modifies the adopted rule accordingly.

The commission declines to modify the adopted rule to accommodate the recommendation from TPPA to create a process to allow an electric generating facility to request an exemption from financial penalties if ERCOT denies or modifies a planned outage request. Any changes around the approval of planned outages should be addressed in the ERCOT stakeholder process and incorporated into the ERCOT protocols, which are developed with input from stakeholders and ultimately approved by the commission.

Tighten the exemption

TCPA recommended modifying proposed §25.65(e)(2)(C) and (D) to tighten the exemption afforded DAM awardees to avoid incentivizing an electric generating facility from taking on a performance obligation that it cannot satisfy simply to avoid a financial penalty for failing to perform or firm under the proposed rule.

Commission Response

The commission adopts TCPA's recommendation to tighten the exemption that is afforded DAM awardees to avoid incentivizing gaming behavior. The commission modifies the adopted rule to state that only the MW that are awarded in the DAM are exempt from the performance requirements, limiting the potential for gaming to avoid the financial penalty for failing to satisfy the performance requirements.

Claw back

ERCOT recommended modifying proposed §25.65(e)(2)(D) to exempt an electric generating facility from financial penalties if the electric generating facility is awarded an ancillary service or reliability service that has an associated claw back. This change captures electric generating facilities that are already performing during a low operation reserve hour but are providing energy in an ancillary service, such as firm fuel supply service, which is subject to a claw back.

Commission Response

The commission adopts ERCOT's recommendation to modify adopted §25.65(f)(2)(D) to exempt an electric generating facility from financial penalties if the electric generating facility is awarded an ancillary service or reliability service that has an associated claw back. The commission modifies the adopted rule accordingly.

Contractual arrangement to serve load

LCRA recommended modifying proposed §25.65(e)(2)(D) to include contractual arrangements to serve load, which creates a performance requirement not dissimilar from a DAM award for energy.

Commission Response

The commission declines to adopt LCRA's recommendation to include contractual arrangements to serve load in the list of exemptions from financial penalties. PURA §39.1592 does not provide an exemption for any specific load serving entity who may have an obligation to serve their load. Instead, the statute is focused on all new electric generating facilities that are participating in the ERCOT wholesale market and aims to supplement and improve performance of those electric generating facilities during tight conditions, regardless of the type of load serving entity that they are providing electricity for. Even the entities that have an obligation to serve their load are part of the wholesale market and rely on ERCOT to balance the grid in real-time.

Proposed §25.65(e)(3) - Financial incentive

Proposed §25.65(e)(3) requires ERCOT to provide a financial incentive to an electric generating facility if the electric generating facility operates or is available to operate when called on for dispatch above the SAGC during a low operation hour that occurs within a high-risk hour. Proposed §25.65(e)(3) also states: (A) the total financial incentives awarded must not exceed the total financial penalties imposed; (B) the financial incentives payable to an electric generating facility must be equal to the total financial penalties imposed divided by the total MW that exceeded the SAGC; (C) a financial incentive must be calculated based on the total financial penalties imposed divided by available MWh and allocated to an eligible electric generating facility based on the percentage of MWh that exceed the performance requirements; and (D) an electric generating facility that is not required to operate or be available to operate is not eligible to receive a financial incentive.

Eligibility to participate in incentive pool

Potomac recommended that a firming resource should not be eligible to participate in the financial incentive pool. Potomac noted that a firm resource is expected to have the incentive to operate during truly tight system conditions (high risk to reliability) at a level above their SAGC. In this case, and especially if a trigger for delivery period is set to reflect true risk to reliability, the firming resource will have a market incentive to deliver a high level of availability and will receive higher compensation as a result. During such intervals, a high system locational marginal price (LMP) and shortage price adders are expected, creating a stronger incentive compared to revenue from a firming contract or the incentive pool. Eligibility to participate in both is likely redundant and will result in excessive cost.

Commission Response

The commission agrees with Potomac that a firming resource should not be eligible to receive both compensation from firming and financial incentives. Financial incentives are solely reserved for new electric generating facilities that are overperforming both their SAGC and any additional firming obligation they take on from another electric generating facility during low operation reserve hours. If the performance of a new electric generating facility exceeds both the facility's SAGC and any additional firming obligation the facility takes on, the owner or operator of that facility will be eligible for an incentive for that additional performance. The commission modifies the adopted rule to provide clarity on this.

Clarification

ERCOT recommended modifying proposed §25.65(e)(3) to clarify that ERCOT is only required to provide a financial incentive if financial penalties were also assessed in the applicable season.

Commission Response

The commission adopts ERCOT's recommendation to clarify that financial incentives will be paid out only if financial penalties are collected and modifies the adopted rule accordingly.

Financial incentive cap

NRG recommended modifying proposed §25.65(e)(3) by capping the financial incentive at $1,000 per MWh for each individual resource that overperforms. TXOGA recommended capping financial incentives so that a net-short resource cannot finish net positive after seasonal netting.

Commission Response

The commission adopts NRG and TXOGA's recommendation to cap the financial incentive at the penalty price for each MWh and modifies the adopted rule accordingly.

Distribution of excess financial incentives

OPUC recommended financial incentives should be distributed on a MWh of exceedance ratio share amongst the electric generating facilities that exceeded the performance requirements in a season, up to a maximum of 10% of the cost of new entry (CONE), spread out evenly across the hours of highest risk. OPUC also recommended that any financial incentives that exceed the incentive cap should be allocated to load, potentially via a reduction in transmission cost of service (TCOS).

TXOGA recommended modifying proposed §25.65(e)(3) to explicitly state that if no electric generating facility qualifies for financial incentives in a season, ERCOT should pay the financial incentives to load for that season on a pro-rata energy basis.

ERCOT and NRG recommended modifying proposed §25.65(e)(3) to account for any excess funds remaining after disbursement of financial incentives by allowing those excess funds to be allocated to load serving entities based on their average load ratio share for the season.

Commission Response

The commission agrees with OPUC that there should be a cap on the financial incentives that an electric generating facility could be paid but declines to base this cap on a percentage of the cost of new entry. Instead, the commission modifies the adopted rule to cap the financial incentive on a dollar per MWh basis consistent with the financial penalties cap, which is on a dollar per MWh basis.

The commission agrees with ERCOT, OPUC, NRG, and TXOGA that if no electric generating facilities qualify for financial incentives in a season, the collected financial penalty funds should be paid out to load. The commission adopts ERCOT and NRG's recommendation that, in the event excess revenues are collected from financial penalties, those excess funds should be allocated to load serving entities based on a seasonal load ratio share basis. The commission modifies the adopted rule accordingly.

Rolling pooled financial penalties into next season

TEC recommended rolling the pooled financial penalties into the next season to provide additional financial incentives. Allowing pooled financial penalties to roll over avoids any need to eventually seek additional support from load for proper financial incentives. TEC also recommended that electric generating facilities that are net short on their performance requirements for a season should not be eligible for a financial incentive payment. Allowing an electric generating facility to take advantage of financial incentives while remaining net short on its obligations defeats the intended purpose of the performance requirements, leaving the grid subject to underperformance from an electric generating facility while still rewarding it for inconsistent overperformance.

Commission Response

The commission disagrees with TEC that pooled financial penalties should roll into the next season. Within the firming program, the value from electric generating facilities overperforming is to firm up electric generating facilities that are not able to satisfy their performance requirements. If a season has more electric generating facilities that are overperforming than underperforming, the value added from that overperformance is diminished, and the compensation from financial incentives should reflect that.

The commission agrees with TEC that electric generating facilities that are net short on their performance requirements for a season should not receive a financial incentive payment. The commission modifies the adopted rule to cap the hourly financial incentive that an overperforming electric generating facility can receive to address this concern.

Financial incentives funded independently of penalty collection

Eolian recommended modifying proposed §25.65(e)(3)(A) by replacing it with language that conforms with its recommended changes to proposed §25.65(e)(1). Specifically, Eolian recommended replacing proposed §25.65(e)(3)(A) with a statement that financial incentives must be funded independently of penalty collection and may not be limited to, or sourced from, collected penalties, consistent with PURA §§39.1592(c) and 15.033, and Texas Government Code 404.094, which require penalties to be deposited to the state treasury and credited to the General Revenue Fund.

Commission Response

The commission declines to adopt Eolian's recommendation to require financial incentives be funded independently of financial penalty collection and may not be limited to, or sourced from, collected financial penalties based on the applicability of PURA §15.033 and Texas Government Code §404.094, which require administrative penalties to be deposited to the state treasury and credited to the General Revenue Fund. The commission disagrees with Eolian's interpretation for the reasons stated above in the commission's response to Eolian's comments on proposed §25.65(e)(1).

Strike duplicative subsection

ERCOT recommended striking proposed §25.65(e)(3)(B) because it appears to be duplicative of proposed §25.65(e)(3)(A).

Commission Response

The commission adopts ERCOT's recommendation to remove §25.65(e)(3)(B) because the proposed clause is unnecessary.

Portfolio calculation of financial incentive

Eolian recommended modifying proposed §25.65(e)(3)(B) by replacing it with a statement that the financial incentive payable to a qualifying covered entity equals an incentive rate (established by the commission by order or rule) multiplied by the covered entity's portfolio over-performance MWh, where portfolio over-performance MWh equals, for each qualifying hour, the positive difference between the covered entity's portfolio output (or availability to operate when called) and its portfolio SAGC, summed across all low operation reserve hours that occur within the baseline period. If the commission establishes a seasonal incentive budget ERCOT shall allocate payments pro rata to qualifying covered entities in proportion to their portfolio over-performance MWh.

Commission Response

The commission declines to modify the adopted rule as proposed by Eolian. The commission will utilize the financial penalties collected to fund the financial incentives for over-performance, and as such, the commission disagrees with the proposed methodology.

Formula

TPPA recommended streamlining proposed §25.65(e)(3)(B) and (C) by using a formula and more clearly describing how the financial incentive will be calculated.

Commission Response

The commission adopts TPPA's recommendation to include formulas in addition to the written description of the financial incentive calculation. The commission modifies the adopted rule accordingly.

Not relieved of other obligations or penalties

Eolian recommended modifying proposed §25.65(e)(3)(C) by replacing it with a statement that receipt of a financial incentive does not relieve any resource "owned or contracted" from obligations or penalties applicable under other ERCOT markets, services, or commission rules. Over-performance MWh used to calculate a portfolio incentive may not be double counted toward any other incentive program for the same MW and hour unless expressly authorized by the commission.

Commission Response

The commission agrees with Eolian that receipt of a financial incentive does not relieve a resource of any other obligation it has, but declines to modify the adopted rule, as doing so is unnecessary. The commission partially agrees with Eolian's recommendation around double-counting of a resource. Only electric generating facilities that the performance requirements apply to are eligible for financial incentives, and capacity from these facilities that is used to satisfy the performance requirements of another electric generating facility should not be eligible to also receive a financial incentive payment, as that capacity is being utilized to firm up an electric generating facility that is not satisfying the performance requirements. The commission declines to apply this cap to any other incentive programs.

No financial incentive for overperformance in hours that a resource is exempt

NRG recommended modifying proposed §25.65(e)(3)(D) to clarify that an electric generating facility with an exemption in certain hours should not also be able to receive financial incentives for overperforming in those same hours.

Commission Response

The commission declines to adopt NRG's recommendation to clarify that an electric generating facility with an exemption in certain hours should not also be able to receive financial incentives for overperforming in those same hours. The performance requirements are designed to encourage electric generating facilities to be available during the hours of highest risk due to low operation reserves. While these electric generating facilities would be partially or fully exempt from a penalty during these hours, these facilities would still provide value if they are capable of overperforming in real-time when conditions are tight.

Allow facilities that provide firming to receive financial incentives

TCPA recommended striking proposed §25.65(e)(3)(D) and providing financial incentives to entities that provide firming.

Commission Response

The commission declines to adopt TCPA's recommendation to remove adopted §25.65(f)(3)(C), stating that an electric generating facility that is required to meet the performance requirements is not eligible to receive a financial incentive. However, the commission makes clarifying changes. An owner or operator of an electric generating facility cannot receive compensation via a contractual arrangement to firm an electric generating facility and receive a financial incentive payment for the same MW, as this would be a double payment.

Proposed §25.65(f) - Settlement

Proposed §25.65(f) requires ERCOT, after each season, to: (1) notify each electric generating facility if it was long or short net of trade arrangements disclosed to ERCOT during the low operation reserve hours that occurred within the high-risk hours in the prior season; (2) impose financial penalties to those electric generating facilities that are net short; and (3) provide financial incentives to those electric generating facilities that are net long.

Potomac recommended that the proposed rule require ERCOT to calculate deficiencies and facilitate transfer and settlement of penalties.

Vistra recommended including a timeline for notification, such as 30 days following the end of the season, and detail the specific data set that ERCOT will rely upon to determine net trade arrangements.

Similarly, TPPA recommended modifying proposed §25.65(f) to require ERCOT to publicly report the number of electric generating facilities that failed to meet or exceeded their firming requirement, including the aggregate MW failed or exceeded and a breakdown of the number of resources by type. TPPA also recommended requiring that the report include the total penalties assessed, the maximum single penalty assessed, and the maximum single incentive warded. Finally, TPPA recommended clarifying what is meant by "long" or "short net trade" and requiring ERCOT to complete its responsibilities within 50 days after the end of the season.

ERCOT recommended modifying proposed §25.65(f) to clarify that financial incentives must be paid only so long as there are penalty funds from that season to apply to incentive payments.

TXOGA recommended requiring ERCOT to include this program in its evaluation of collateral requirements for market participants and inform the commission of any incremental impacts on credit risk.

Commission Response

The commission agrees with Potomac that ERCOT will need to calculate deficiencies and facilitate transfer and settlement of financial penalties. Accordingly, the commission adds a requirement in adopted §25.65(g) for ERCOT to develop a mechanism that allows the owner or operator of an electric generating facility subject to the performance requirements to contract with a firming resource.

The commission declines to make the modifications recommended by Vistra on the timeline for notification or the specific data set ERCOT will rely on to determine net trade arrangements. These items will be left for development in the ERCOT stakeholder process through the ERCOT protocols, which will need to be approved by the commission before these performance requirements become effective.

The commission partially agrees with TPPA's recommendations for additional reporting. Accordingly, the commission modifies the adopted rule to require a post-season reporting requirement for the firming program.

The commission declines to adopt ERCOT's recommendation to modify adopted §25.65(h) to state that no financial incentive may be paid if there are no penalty funds from that season to apply to incentive payments because it is unnecessary. This clarification is made in adopted §25.65(f)(3)(A).

The commission agrees with TXOGA's recommendation that ERCOT should include the firming program in its evaluation of collateral requirements and to identify any incremental impacts on credit risk. However, the commission declines to modify the adopted rule because these impacts should be considered for any new program or requirement, not just for the performance requirements laid out in this rule. In addition, there is already an existing process for the ERCOT Credit Finance Sub Group (CFSG) to evaluate the credit impacts of each new revision request.

Proposed §25.65(g) - Protocols

Proposed §25.65(g) requires ERCOT to develop protocols to implement the proposed rule by December 1, 2026.

ERCOT and TEBA recommended striking proposed §25.65(g) because it is unnecessary. ERCOT must develop protocols to implement the proposed rule even if the commission does not require it by rule.

TXOGA recommended requiring a post-season report that summarizes qualifying hours, total penalties and incentives, and leading reasons for exemptions.

TPPA cautioned against setting a firm deadline that may later require a good cause exemption to allow appropriate implementation.

Commission Response

The commission disagrees with ERCOT and TEBA's recommendation to strike this subsection requiring ERCOT to develop protocols to implement the adopted rule by December 1, 2026. However, the commission acknowledges TPPA's concern around setting a firm deadline and modifies the rule to require ERCOT to complete the necessary protocols to implement this section before the statutory requirement for the performance requirements become effective.

The commission adopts TXOGA's recommendation to require a post-season report on any season where there were low operation reserve hours, and the performance requirements were triggered. The commission modifies the adopted rule accordingly.

In adopting this section, the commission makes other minor modifications for the purpose of clarifying its intent.

This section is adopted under the following provisions of Public Utility Regulatory Act (PURA): §14.001, which grants the commission the general power to do anything specifically designated or implied by this title that is necessary and convenient to the exercise of that power and jurisdiction; §14.002, which authorizes the commission to adopt and enforce rules reasonably required in the exercise of its powers and jurisdictions; §39.151, which authorizes the commission to oversee ERCOT and adopt rules relating to the reliability of the regional electrical network and accounting for the production and delivery of electricity among generators and all other market participants; and §39.1592, which requires the commission to make certain determinations and require ERCOT to impose financial penalties and provide financial incentives.

Cross Reference to Statutes: PURA §14.001; §14.002; §39.151; and §39.1592.

§25.65. Firming Program Requirements for Electric Generation Facilities in the ERCOT Region.

(a) Applicability. The performance requirements set forth in this section apply to an electric generation facility in the ERCOT region:

(1) for which an original standard generation interconnection agreement is signed on or after January 1, 2027; and

(2) that has been in operation for at least one year prior to the beginning of a season.

(b) Definitions. The following words and terms, when used in this section, have the following meanings unless the context indicates otherwise.

(1) Baseline period--A daily set of hours encompassing all seasonal morning and evening ramp hours, as determined by ERCOT, and any additional high-risk hours identified in each season as part of ERCOT's annual North American Electric Reliability Corporation (NERC) Probabilistic Assessment.

(2) Electric generation facility--A generation resource, as that term is defined in the ERCOT protocols.

(3) Distribution energy storage resource--A distribution energy storage resource, as that term is defined in the ERCOT protocols.

(4) Distribution generation resource--A distribution generation resource, as that term is defined in the ERCOT protocols.

(5) Energy storage resource--An energy storage resource, as that term is defined in the ERCOT protocols.

(6) In operation--The date when ERCOT approves the electric generation facility for commercial operation.

(7) Interval--Each instance in which security constrained economic dispatch (SCED) runs.

(8) Load resource--A load resource, as that term is defined in the ERCOT protocols.

(9) Low operation reserve hour--An hour within the baseline period when the physical responsive capability (PRC) falls below 3,000 MW for at least 15 minutes.

(10) Owner or operator--A resource entity that owns or operates an electric generation facility represented by a qualified scheduling entity.

(11) Qualified scheduling entity (QSE)--A qualified scheduling entity, as that term is defined in the ERCOT protocols, that represents an electric generation facility on behalf of an owner or operator for operational and settlement purposes.

(12) Season--Winter (December 1 through February 29), Spring (March 1 through May 31), Summer (June 1 through September 30), and Fall (October 1 through November 30).

(13) Seasonal average generation capability--The seasonal rated capacity of the electric generation facility at the beginning of the relevant season multiplied by the lesser of 0.75 and the average of the ratio of real-time telemetered high sustained limit (HSL) to the seasonal rated capacity of the electric generation facility across all intervals of the same season during the prior five years.

(14) Seasonal rated capacity--The maximum generating capability of an electric generation facility, expressed in MW, that an electric generation facility can sustain under expected ambient conditions for a given season, as determined by ERCOT at the start of that season, according to the value that the electric generation facility reported to ERCOT.

(15) Self-generator--An entity registered with the commission as a self-generator.

(16) Settlement-only generator--A settlement-only generator, as that term is defined in the ERCOT protocols.

(1) Seasonal average generation capability calculation.

(A) ERCOT must calculate the seasonal average generation capability for each electric generation facility subject to the performance requirements under this section using the following formula:

Figure: 16 TAC §25.65(c)(1)(A) (.pdf)

(i) Where:

(ii) SAGC = seasonal average generation capability.

(iii) HSL = high sustained limit.

(iv) SRC = seasonal rated capacity.

(v) The first term in the minimum function calculates the ratio of real-time telemetered HSL and SRC across all intervals (i) that occurred during the prior five years of the same season ( denotes the total number of such intervals); if less than five years of operating data exists, all available data from the same season must be used. The minimum of this ratio and 0.75 is multiplied by the SRC at the start of the compliance season (SRC_t) to determine SAGC. The second term in the minimum function (0.75) effectively creates an upper bound on the resulting SAGC.

(B) The seasonal average generation capability must be specific to each electric generation facility and not a uniform value applied to all electric generation facilities.

(2) Notice of seasonal average generation capability. Prior to each season, ERCOT must notify the QSE representing an electric generation facility of the facility's seasonal average generation capability for the upcoming season.

(3) Notice of baseline period. Prior to each season, ERCOT must provide public notice of the baseline period for the upcoming season.

(d) Performance requirement. Each season, an electric generation facility must operate or be available to operate at or above the facility's seasonal average generation capability when called on for dispatch during a low operation reserve hour that occurs within a baseline period. The low operation reserve hours are limited to a maximum of 15 hours per season. There is no performance requirement in a season that does not experience a low operation reserve hour. The performance requirements set forth in this subsection do not apply to:

(1) an energy storage resource;

(2) a resource that operates as a must-run alternative unit, as that term is defined in the ERCOT protocols;

(3) a resource that operates as a reliability must-run unit, as that term is defined in the ERCOT protocols;

(4) a resource that is contracted with ERCOT to provide capacity under ERCOT Protocol Section 6.5.1.1;

(5) a settlement-only generator;

(6) a self-generator; or

(7) an electric generation facility that is co-located with a load in a private use network provided that more than 50% of the electric generation facility's nameplate capacity is dedicated to serving the load within the private use network.

(e) Firming.

(1) Firming to meet performance requirement. The owner or operator of an electric generation facility may satisfy the facility's performance requirements under this section by entering into a trade arrangement with a firming resource. A trade arrangement may be for a firming resource represented by the same QSE that represents the electric generation facility that is subject to the performance requirements or for a firming resource represented by a QSE that is different from the QSE that represents the electric generation facility that is subject to the performance requirements. Firming resources may be located on-site at the electric generation facility or off-site. The following resource types are eligible to provide firming service:

(A) another electric generation facility;

(B) an energy storage resource;

(D) a distribution energy storage resource that is registered with ERCOT; or

(E) a load resource.

(2) Capacity available to provide firming service.

(A) An electric generation facility, including an existing electric generation facility that is not subject to the performance requirements under this section, may provide firming service equal to the facility's average high sustained limit in a given hour, across all intervals in which the facility was available (i.e., showing any status other than OUT), less the facility's own seasonal average generation capability.

(B) An energy storage resource, a distribution generation resource that is registered with ERCOT, and a distribution energy storage resource that is registered with ERCOT may provide firming service equal to the resource's average high sustained limit in a given hour, across all intervals in which the facility was available (i.e., showing any status other than OUT).

(C) A load resource may provide firming service equal to its average consumption in a low operation reserve hour, adjusted for any ERCOT deployments, less its low power consumption in that hour.

(3) Firming obligation. A QSE representing a firming resource that provides firming service for an electric generation facility that is subject to the performance requirements under this section assumes a firming obligation, including the financial penalties associated with the performance requirements for that obligation.

(4) Disclosure to ERCOT. A QSE that satisfies the performance requirements under this section by providing firming service to an electric generation facility through a trade arrangement must disclose the arrangement to ERCOT and provide ERCOT with any additional information reasonably required for ERCOT to perform its duties under this section, including confirmation by both parties to the arrangement.

(f) Financial penalty and financial incentive.

(1) Financial penalty. ERCOT must impose a financial penalty on a QSE representing an electric generation facility that fails to satisfy its performance requirements under this section. The QSE representing a firming resource that assumes a firming obligation is subject to a financial penalty if the firming resource fails to satisfy the performance requirements subject to the obligation.

(A) A financial penalty imposed by ERCOT must be 20% of the system-wide offer cap that is in effect for each MWh of deficiency.

(B) In seasons in which more than 15 low operation reserve hours occur during the seasonal baseline period, only the 15 low operation reserve hours with the lowest levels of PRC are subject to the financial penalty under this section.

(2) Financial penalty exemption.

(A) An electric generation facility is exempt from assignment of a financial penalty under this section if the facility is unavailable during the applicable hour due to:

(i) a planned maintenance outage, opportunity outage, or derate that was approved by ERCOT;

(ii) a transmission outage;

(iii) a market suspension, as that term is defined in the ERCOT protocols; or

(iv) a derate or outage to satisfy environmental compliance requirements.

(B) A switchable generation resource that is committed to a neighboring independent system operator or regional transmission operator for the applicable hour is exempt from assignment of a financial penalty under this section for that hour.

(C) The portion of capacity of an electric generation facility that is awarded energy or ancillary services in the day ahead market is exempt from assignment of a financial penalty during the applicable hour.

(D) An electric generation facility that is awarded an ancillary service or reliability service that has an associated penalty or claw back for failure to perform during the applicable hour is exempt from assignment of a financial penalty under this section for the portion of capacity that is awarded an ancillary service or reliability service.

(E) A firming obligation assumed by a firming resource through a trade arrangement with the owner or operator of an electric generation facility that is subject to the performance requirements under this section is not eligible for a financial penalty exemption for the hour that the resource has taken on that obligation.

(3) Financial incentive. ERCOT must provide a financial incentive to the QSE representing an electric generation facility that is subject to the performance requirements of this section if the electric generation facility operates or is available to operate above the seasonal average generation capability when called on for dispatch during a low operation reserve hour that occurs within a baseline period, as required under subsection (d) of this section.

(A) The total financial incentives provided under this subsection each season must not exceed the total financial penalties imposed each season for low operation reserve hours occurring within the baseline period. No financial incentives may be awarded in a season in which no financial penalties are imposed by ERCOT.

(B) A financial incentive provided to the QSE representing an eligible electric generation facility must be based on the total financial penalties imposed divided by the sum of all MWh exceeding the performance requirements of eligible electric generation facilities and allocated to the QSE representing an eligible electric generation facility based on the facility's share of the MWh that exceed the performance requirements. The financial incentive that is provided to the QSE representing an eligible electric generation facility must not exceed $1,000 per MWh that exceed the performance requirements. The financial incentive must be calculated using the following formula:

Figure: 16 TAC §25.65(f)(3)(B) (.pdf)

(i) Where:

(ii) FI_j= financial incentive provided to the QSE representing an eligible electric generation facility (j).

(iii) TFP (Total Financial Penalties) = the sum of all financial penalties imposed by ERCOT during a season.

(iv) &dgr_j= MWh exceeding the performance requirement by an eligible electric generation facility (j).

(v) ∆ = the sum of all &dgr_j for each eligible electric generation facility.

(C) An electric generation facility that is not subject to the performance requirements under this section is not eligible for assignment of a financial incentive for that facility's performance under this subsection.

(D) An electric generation facility that also serves as a firming resource to satisfy the performance requirements of another electric generation facility is not eligible for assignment of a financial incentive for any over-performance used to satisfy its firming obligation as a firming resource.

(E) If the amount of financial penalties collected from QSEs representing electric generation facilities under subsection (f)(1) of this section exceeds the amount paid out in financial incentives, any excess funds must be allocated to load serving entities based on each load serving entity's average load ratio share across the season.

(g) Tracking Mechanism. ERCOT must develop a tracking mechanism that allows a QSE representing an electric generation facility that is subject to the performance requirements under this section to meet those performance requirements with a firming resource that assumes a firming obligation for that electric generation facility.

(1) ERCOT must develop processes to confirm a trade arrangement by which a firming resource assumes a firming obligation.

(2) If ERCOT is unable to confirm a trade arrangement by which a firming resource assumes a firming obligation, ERCOT must notify the parties to the arrangement.

(3) The obligation to meet the performance requirements and the risk for financial penalty under this section remains with the original electric generation facility required to meet the performance requirements if ERCOT cannot confirm the trade arrangement by which the firming resource assumes a firming obligation for the electric generation facility subject to the performance requirements.

(h) Financial settlement. ERCOT must settle with the QSE that represents the electric generation facility that is subject to the performance requirements under this section or the QSE that represents the firming resource that assumes a firming obligation under this section. After each season, ERCOT must:

(1) notify the QSE representing an electric generating facility under this section if the electric generation facility was long or short, net of trade arrangements disclosed to ERCOT during the low operation reserve hours that occurred within the baseline period in the prior season;

(2) impose financial penalties on the QSEs representing electric generating facilities that are net short; and

(3) provide financial incentives to the QSEs representing electric generating facilities that are net long in a season in which financial penalties are imposed.

(i) Post-season report. Not later than 75 days after each season in which there were low operation reserve hours and the performance requirements were triggered, ERCOT must file a post-season report with the commission summarizing qualifying hours, settled financial penalties and financial incentives, and predominant causes for exemptions. ERCOT may file the post-season report with the quarterly reports that ERCOT is required to file under §25.362(i)(3) (relating to Electric Reliability Council of Texas (ERCOT) Governance).

(j) Protocols. ERCOT must develop protocols in consultation with commission staff to implement this rule before the effective date that the statute requires an electric generation facility to begin complying with the performance requirements set forth in this section. The protocols developed by ERCOT must identify how performance will be validated for a distribution generation resource, an energy storage resource, and a load resource that assumes a firming obligation.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on December 19, 2025.

TRD-202504756

Andrea Gonzalez

Rules Coordinator

Public Utility Commission of Texas

Effective date: January 8, 2026

Proposal publication date: August 15, 2025

For further information, please call: (512) 936-7244

SUBCHAPTER J. COSTS, RATES AND TARIFFS

DIVISION 1. RETAIL RATES

16 TAC §§25.235 - 25.237

The Public Utility Commission of Texas (commission) adopts amended 16 Texas Administrative Code (TAC) §25.235 relating to Fuel Costs, §25.236 relating to Recovery of Fuel Costs, and §25.237, relating to Fuel Factors. The commission adopts these rules with changes to the proposed text as published in the July 25, 2025 issue of the Texas Register (50 TexReg 4148). The amended rules collectively implement changes to Public Utility Regulatory Act (PURA) enacted pursuant to House Bill (HB) 2073 during the Texas 88th Regular Legislative Session. Specifically, the amended rules establish a new interim fuel adjustment proceeding under §25.236 which accounts for any refunds or surcharges of "material" balances accrued by the utility. The threshold for a "material" balance (i.e. the cumulative amount of over- or under-recovery, including interest of the utility' actual fuel cost figures on a rolling 12-month basis) is retained at 4.0% for both interim fuel adjustments and fuel factor proceedings. The rules will be republished.

Amended §25.235 establishes modified notice requirements for interim fuel adjustments and fuel factor proceedings based on the scope of those proceedings specified by HB 2073 and the written protest for eligible persons to participate in either an interim fuel adjustment or fuel factor proceeding. Amended §25.236 specifies the scope and timelines associated with interim fuel adjustments, including procedures for written protests by eligible persons, specific instances in which a hearing must be held for an interim fuel adjustment, and the scope of discovery. Amended §25.236 also reduces the periodicity of fuel reconciliations from three years to two years, as required by HB 2073, and makes conforming revisions for fuel reconciliation proceedings. Amended §25.237 specifies the scope and timelines associated with fuel factors, including procedures for written protests by eligible persons and the scope of discovery.

The commission received comments on the proposed rule from the Alliance of Xcel Municipalities (AXM) and Cities Advocating Reasonable Deregulation (CARD) (collectively "AXM/CARD"); the City of El Paso (CEP); El Paso Electric Company, Entergy Texas, Inc., Southwestern Electric Power Company, and Southwestern Public Service Company (collectively, "Joint Utilities"); the Office of Public Utility Counsel (OPUC); and Texas Industrial Energy Consumers (TIEC).

Questions for Comment

Question 1

Existing §25.236(a)(9) authorizes a utility to retain 10% of the margins from an off-system energy sales transaction if certain criteria are met. Should this percentage be adjusted? Why or why not?

CEP, Joint Utilities, and AXM and CARD recommended the 10% margin for off-system sales be maintained. CEP and Joint Utilities maintained that changing the 10% margin for off-system sales is not required or implied by HB 2073 and that its removal would introduce unnecessary complexity and increase litigation costs. In contrast OPUC recommended the 10% margin for off-system sales be categorically eliminated by reducing it to zero and deleting proposed §25.236(a)(9). TIEC recommended the 10% margin for off-system sales should largely be eliminated if those sales "are simply due to economic dispatch in a centralized wholesale market."

CEP indicated that the existing 10% margin for off-system sales has worked well for customers, reduces controversy, and has not presented an issue in El Paso Electric fuel reconciliation cases. CEP remarked that the sharing provisions, established through settlement agreements in its fuel reconciliation cases, provide for 100% of the margins to be provided to customers."

Joint Utilities commented that maintaining the 10% margin for off-system sales is sufficient and consistent with current commission practice. Joint Utilities indicated that the commission had previously declined to change this percentage in 2014 under Project 41905 where §25.236 was revised.

AXM and CARD commented that if the proposed §25.236(a)(9) were to be revised at all, it should preserve the 10% margin but add explicit requirements for utilities to provide verified and audited data regarding purchased-power costs and natural-gas costs. Specifically, AXM and CARD urged the commission to revise §25.236(a)(9) to ensure that "a utility's 10% share of OSS energy margins are to be based on margins from sales of the highest-cost energy (incremental sales) in each hour including the costs associated with the higher-cost energy assigned to [off-system sales]." AXM and CARD also recommended the rule should prohibit utilities from using "proprietary models" when calculating their off-system sales.

AXM and Card explained that the furnishing of data in the form and manner it recommends is necessary for a utility to "merit retention of any margins from [off-system sale] transactions" and is consistent with the original basis for margin sharing before the development of energy markets such as ERCOT, SPP, and MISO. AXM and CARD emphasized that a utility must provide that it assigned the lowest cost energy produced to its native retail customers and, conversely, its higher cost energy when calculating the margins for off-system sales.

AXM and CARD analogized its recommendations to the final commission action taken in past fuel dockets, Project 32766 and Project 53034. AXM and CARD indicated that in Project 32766, the commission "concluded that SPS' s off-system sales to El Paso Electric Company (EPE) should be assigned the higher incremental fuel costs incurred after supplying energy to SPS's native retail customers." Additionally, AXM and CARD commented that in Project 53034, the commission barred the utility from using proprietary models when calculating its off-system sales. According to AXM and CARD, this was because it frustrated efforts to ensure the utility assigned customers lower-cost energy to its customers and higher-cost energy to off-system sales.

OPUC commented that utilities have a statutory obligation to charge customers reasonable rates for electric service. OPUC asserted that this obligation "necessarily includes providing sufficient service at the lowest reasonable cost" by utilizing generating plant in the most economical manner, including the selling of energy off-system when cost-effective. OPUC emphasized that utility customers pay the costs of generating plant through base rates and that the utility has a reasonable opportunity to earn a return on such investments. OPUC concluded that utilities should not be entitled to make a profit from selling power generated by facilities that are fully paid for by their consumers. OPUC stated that any profit from off-system sales should accordingly be fully credited to the utility's consumers. OPUC referenced TIEC's comments in Project 41905 which stated that "allowing utilities to charge ratepayers 100% for their fuel costs while retaining 10% of the profits from re-selling power creates an arbitrage opportunity." OPUC provided draft redlines consistent with its recommendation.

TIEC commented that "[m]argin sharing was developed to incentivize utilities to pursue private, bilateral sales to external third parties" and is now an outdated practice. TIEC contended that most non-ERCOT utilities now bid generation into regions such as SPP or MISO which are centrally administered wholesale markets. TIEC explained that in those markets, off-system sales are "simply instances when the amount of energy economically dispatched from a utility' s generation resources exceeds the energy required to serve the utility's native load in a given hour." TIEC indicated that, in such an event, "[n]o work is done by the utility, and no additional profit incentive is needed to achieve this result." TIEC concluded that off-system sale margin sharing should be reviewed by the commission on an individual basis for utilities that do not participate in integrated marketplaces, or for certain "bilateral transactions that are not purely the result of economic dispatch" such as long term power purchase agreements with a third-party buyer.

Commission response

The commission preserves the 10% margin for off-system sales but eliminates §25.236(a)(9)(A)-(C) and imposes a requirement for commission review of the transaction to ensure the off-system sale is in the interests of the electric utility's retail customers and that margin sharing is in the public interest. Specifically, the commission revises §25.236(a)(9) to state: An electric utility may retain 10% of the margins from an off-system energy sale that is made between the utility and a third-party buyer if the commission finds that the transaction is in the interests of the electric utility's retail customers and that margin sharing is in the public interest." The commission eliminates the requirements of §25.236(a)(9)(A) and §25.236(a)(9)(B) as those criteria are unnecessary. All electric utilities currently participate in a transmission region governed by an independent system operator or equivalent and offer a generally applicable tariff for transmission service. Given the redundancy of these criteria, the only relevant inquiry is into the transaction itself. The commission also finds that a public interest standard is appropriate and consistent with other commission rules (e.g. §25.62, relating to Transmission and Distribution System Resiliency Plans). The commission agrees with TIEC that off-system sales should be reviewed by the commission on an individual basis for utilities that do not participate in integrated marketplaces or for "transactions that are not purely the result of economic dispatch" such as long-term power purchase agreements with a third-party buyer. The commission further agrees with TIEC that margin sharing was developed to incentivize utilities to pursue private, bilateral transactions with external third parties and that off-system sales should largely be eliminated if such sales are simply due to economic dispatch in a centralized wholesale market. Off-system sales are short-term, economic or emergency wholesale sales from a utility's generating resources when such resources are unnecessary to serve the utility's obligation-load customers (native load). However, given the widely varying positions on the issue, the commission will open a future rulemaking project to specifically address off-system sales by non-ERCOT utilities, including the scope, manner, and criteria for commission review of such transactions.

Question 2

Existing §25.236(a)(9) authorizes a utility to retain 10% of the margins from an off-system energy sales transaction if certain criteria are met. Should the provision be revised to distinguish separate margins (expressed as a percentage) that an electric utility may retain from off-system sales that are respectively applicable to electric utilities that are dispatched in a power market operated by an independent system operator (ISO) outside of ERCOT and those that are not? (I.E., An electric utility being dispatched by an outside-ERCOT ISO may retain X% of margins from off-system sales, an electric utility that is not dispatched by an outside-ERCOT ISO may retain Y% of margins from off-system sales.)

OPUC stated that distinguishing separate margins is unnecessary because utilities should not retain any margins from off-system sales. OPUC reiterated that proceeds from off-system sales are "derived from the mere fulfillment of utilities' statutory obligations to serve customers at just and reasonable rates" and that the creation and management of separate margin structures could introduce additional administrative burdens and regulatory complexity which may increase overall costs. However, OPUC hypothesized that if costs associated with off-system sales in a power region outside of ERCOT are lower, separate margins could theoretically result in lower electricity prices due to a greater share of profits being passed back to a utility's customers. OPUC stated that any profits from off-system sales should be fully credited to consumers because the power being sold is generated from facilities fully paid for by consumers. OPUC further stated that ERCOT utilities should not be impacted by any revisions to this provision and that the commission could evaluate the percentage, if any, of margins from off-system sales that ERCOT utilities may potentially retain.

CEP commented that because El Paso Electric (EPE) is not part of an ISO, no provisions that concern an ISO should be applicable to EPE or a similarly situated utility.

TIEC commented that proposed §25.236(a)(9) should be revised to distinguish separate margins a utility may retain from off-system sales inside or outside ERCOT. TIEC stated that "there is no reason to give utilities any portion of the profits from ‘off-system' sales that result from economic dispatch in a centrally administered wholesale market" such as SPP or MISO. TIEC indicated that a 10% profit-sharing incentive is unnecessary to facilitate sales to external third parties because the "off-system sale" concept predates the advent of integrated, centrally dispatched markets. TIEC explained that when the 10% profit sharing was introduced "utilities had to actively seek third-party buyers to market any surplus generation through a private, bilateral transaction." Since actual marketing and transactional resources were required, utilities were authorized to margin-share as an incentive to make off-system sales. TIEC indicated that the market landscape has significantly changed since the introduction of off-system sales. Specifically, utilities now submit bids for generation and RTOs/ISOs centrally dispatch resources in the most economically efficient fashion subject to transmission constraints. TIEC indicated that a utility purchases the energy needed to serve its native load using the lowest-cost resources in the market, including self-owned resources, and then each utility is paid "according to the amount of its generation that is needed to serve the market' s collective demand." TIEC explained that off-system sales are "simply instances in which the amount of energy economically dispatched from a utility's generation resources exceeds the energy required to serve the utility's native load in a given hour. No work is done by the utility, and no additional profit incentive is needed to achieve this result."

TIEC concluded that off-system sale margin sharing should be reviewed by the commission on an individual basis for utilities that do not participate in integrated marketplaces, or for certain "bilateral transactions that are not purely the result of economic dispatch" such as long-term power purchase agreements with a third-party buyer. [This is repeated from Q1] TIEC stated that customers could benefit from "incentivizing utilities to take on additional work and risk related to actual off-system sales, but it depends on the circumstances presented and what profits would have resulted from economic dispatch without a [power-purchase agreement] in place." TIEC recommended that utilities be required to both demonstrate the actual need for such an incentive as well as justify the magnitude of any incentive before the utility is authorized to retain any margins from off-system sales. TIEC provided draft language consistent with its recommendation.

Joint Utilities opposed distinguishing separate margins a utility may retain from off-system sales inside or outside ERCOT as it is not addressed or authorized by HB 2073. Joint Utilities stated that separate margin retention percentages for ISO and non-ISO utilities would introduce "unnecessary regulatory complexity and administrative burden without statutory support." Joint Utilities maintained that the existing 10% margin sharing percentage appropriately incentivizes a utility to maximize generation resource availability for dispatch such that it can perform off-system sales that mutually benefit the utility and its customers, either for reliability or economic reasons. Joint Utilities commented that regardless of whether a utility is receiving dispatch instructions from an ISO, the utility has discretion over several factors that can affect generation resource availability.

Commission response

The commission declines to establish separate ISO-based margins for off-system sales. The revision to §25.236(a)(9) that authorizes commission review of each individual off-system sales transaction to ensure the transaction is in the interests of the utility's retail customers and that margin sharing is in the public interest is sufficient to ensure that such transactions are appropriate. Commission review of such transactions will provide additional information as to whether separate margins for off-system sales inside or outside ERCOT are necessary. In response to Joint Utilities comment that HB 2073 does not address or authorize off-system sale margin sharing, the commission is not solely limited to the implementation of HB 2073 in this rulemaking. Texas Government Code § 2001.033(a)(1)(B) (the APA) provides that: "[a] state agency order finally adopting a rule must include… a summary of the factual basis for the rule as adopted which demonstrates a rational connection between the factual basis for the rule and the rule as adopted." The margin-sharing and off-system sales issue was properly noticed in a question for comment and is therefore within the scope of this rulemaking. Moreover, PURA §14.001 states that "[t]he commission has the general power to regulate and supervise the business of each public utility within its jurisdiction and to do anything specifically designated or implied by this title that is necessary and convenient to the exercise of that power and jurisdiction." (emphasis added). Therefore, it is appropriate that the commission addresses all issues within the scope of the proposed rulemaking, including those presented by the issued questions for comment that do not involve the implementation of HB 2073. As stated previously, the commission will open a future rulemaking project to specifically address off-system sales.

Question 3

PURA §36.203(b)(3)(A) requires commission rules to ensure any material balance of amounts under-collected or over-collected for eligible electric fuel and purchased power costs is refunded or surcharged to customers through an interim fuel adjustment not later than the 90th day after the date the balance is accrued unless an exception applies. What is the proper threshold for determining a "material balance" for purposes of an interim fuel adjustment? (The proposed rule contains a 4.0% materiality threshold identical to the threshold used in §25.237 for fuel factors.)

OPUC recommended lowering the materiality threshold that would require a utility to apply for an interim fuel adjustment from 4.0% to 2.0%. OPUC stated that lowering the materiality threshold would help reduce financial burdens on residential and small commercial customers by ensuring that utilities file interim adjustment applications more frequently and therefore customers would receive refunds. Moreover, in the event of a surcharge, the total amount of interest paid would also be less if interim adjustment applications occurred more frequently. OPUC indicated that lowering the threshold would be consistent with language in existing §25.235(a) that states "it is in the interests of both electric utilities and their ratepayers to adjust charges in a timely manner to account for changes in certain fuel and purchased-power costs." OPUC further stated that lowering the materiality threshold would "reduce the risk of intergenerational inequity" by decreasing the likelihood a ratepayer may move or stop service before a refund occurs. OPUC provided draft redlines consistent with its recommendation.

TIEC expressed openness to lowering the materiality threshold from 4.0% to 2.0% or 1.0% on the basis that it would benefit utilities and ratepayers.

CEP, AXM and CARD, and Joint Utilities recommended maintaining the materiality threshold at 4.0%. CEP remarked that, given the reduced timeframes for processing interim fuel adjustments, lowering the threshold is likely to result in increased administrative burdens and issues with customer billing due to more interim adjustment filings that may overlap. AXM and CARD indicated that the 4.0% threshold is sufficient and provides certainty as both the utilities and ratepayers are accustomed to the threshold from past experience.

Joint Utilities commented that "there is no clearly appropriate level at which to set the [materiality] threshold that would [enable §25.236(b) to] achieve conformity with HB 2073" and therefore did not provide a different recommendation for the threshold. Joint Utilities remarked that, absent frequent interim fuel adjustments, there is no optimal percentage for when a material balance is deemed to have accrued. Joint Utilities indicated that a low threshold would increase the frequency of fuel proceedings and therefore increase the burdens of compliance in contravention of HB 2073. Similarly, a high threshold would permit "greater deviations between costs and collections despite the legislative direction to achieve contemporaneous collection of costs." Joint Utilities remarked that, given the "impossibility of selecting a materiality threshold that [both reduces regulatory burdens and promotes more timely cost recovery]" its alternative proposal more effectively and accurately implements the plain language and legislative intent of HB 2073.

Joint Utilities stated that the existing threshold appropriately ensures that material balances are promptly addressed while preserving a utilities' discretion for filing for an interim fuel adjustment. Joint Utilities indicated that threshold "functions as a trigger for mandatory action, not a cap on voluntary filings" and that a utility is authorized to make monthly or even more frequent filings to ensure contemporaneous recovery and consistent customer billing even when an under-recovery or over-recovery balance is under 4.0%. Joint Utilities noted that frequent adjustments help reduce the likelihood that large surcharges or refunds are retained, which stabilizes customer rates. Additionally, regular adjustments facilitate HB 2073's directive to ensure utility's collect costs "as contemporaneously as reasonably possible." Joint Utilities stated that if the commission does not adopt such an approach, that any alternative continue to permit utilities "to defer adjustments when balances are projected to self-correct within the threshold" and preserve a utility's ability to make voluntary filings at any time.

Commission response

The commission preserves the materiality threshold of 4.0% in the definitions of "materially or material" in §25.236(b)(1) and §25.237(a)(3)(C). Reducing the materiality threshold would correspondingly increase the number of interim fuel adjustment proceedings and therefore increase the time, cost, and resources necessary to resolve these proceedings. PURA §36.203(b)(1) requires commission rules to ensure that a utility collects eligible fuel costs as contemporaneously as reasonably possible. The commission maintains the reduced timeline of interim fuel adjustment proceedings provided by statute, among other statutory changes, address this statutory requirement.

Question 4

PURA §36.203(b)(3)(A) requires commission rules to ensure any material balance of amounts under-collected or over-collected for eligible electric fuel and purchased power costs is refunded or surcharged to customers through an interim fuel adjustment not later than the 90th day after the date the balance is accrued unless an exception applies. Given the 90-day deadline for recovery under §36.203(b)(3)(A), what time period is appropriate to reasonably expect an electric utility to be capable of filing an interim fuel adjustment application? (I.E., Taking into account the time necessary for a utility to close their books and make a true-up determination regarding whether the deferred fuel balance places the utility in a state of material over- or under-recovery.)

OPUC commented that a 30-day period is a reasonable period to expect a utility to be capable of filing an interim fuel adjustment application. OPUC stated that 30 days is appropriate as §25.72, which requires utilities to maintain a uniform system of business accounting and reporting, and §25.82, which requires utilities to file monthly fuel reports with the commission, already requires utilities to retain information necessary for such adjustments. OPUC indicated that the monthly filing of fuel reports aligns with its recommendation for a 30-day filing of interim fuel adjustments. OPUC stated that a longer period would cause issues with meeting the 90-day statutory deadline for interim fuel adjustments. OPUC noted that if a utility fails to file a complete interim fuel adjustment application, it may therefore be impractical for the utility to either issue or refund a surcharge before the 90-day deadline. OPUC recommended that the proposed rules should explicitly state the requirement of HB 2073 for "any material balance of amounts under- collected or over-collected for eligible electric fuel and purchased power costs [be] collected from or refunded to customers through an interim fuel adjustment not later than the 90th day after the date the balance is accrued." OPUC further recommended that if a utility either fails to file a complete interim fuel adjustment application or the commission is unable to issue an order within the 90-day deadline, then interest should not accrue on any under-collected amount between the date that such balance accrues and the date that a complete application is filed. Inversely, OPUC recommended that utilities be required to pay interest for any over-collected amounts from the date the over-collection accrues until a commission order is issued. OPUC stated these changes would help incentivize prompt and complete filings by utilities and therefore reduce any negative impacts on ratepayers.

CEP commented that the timing for filing an interim fuel adjustment after the close of the month should be as minimal given that such adjustments are interim in nature and the fact that utilities monitor fuel costs on an ongoing basis.

AXM and CARD recommended the commission require utilities to provide a detailed explanation regarding any constraints on their ability to comply with the 90-day deadline prescribed by PURA §36.203(b)(3)(A) "within the procedural safeguards afforded ratepayers under HB 2073."

TIEC commented that the 90-day statutory timeline requires the filing interim fuel adjustment applications as contemporaneously as possible.

Joint Utilities recommended a monthly adjustment framework be adopted and commented that the five working day timeline in proposed §25.236(i)(2)(A) is not feasible. Joint Utilities remarked that the proposed timelines conflict with HB 2073 by retaining the commission's current fuel cost recovery paradigm. Joint Utilities emphasized that a significantly longer period than five days is required for the fuel accounting and reconciliation necessary to "compile, validate, and submit accurate interim fuel refund and surcharge filings" particularly when coupled with notice requirements. Joint Utilities indicated that currently under commission rules, utilities file monthly fuel cost reports 45 days after the end of the reporting month with interim fuel adjustment filings following 30 days or more after that after balances are verified and supporting documentation is prepared. Joint Utilities indicated that, given those internal timelines and workload, the proposed five-day timeline is incompatible with timely and accurate recovery within the 90-day statutory deadline. Joint Utilities advanced an alternative proposal for an end-of-month filing period where filings are generally based off historical data from two months prior. Joint Utilities also recommended an additional requirement that the interim fuel adjustment be filed five calendar days prior to the adjustment becoming effective.

Commission response

This question is comprehensively addressed under the header for Question 5.

Question 5

PURA §36.203(b)(3)(A) requires commission rules to ensure any material balance of amounts under-collected or over-collected for eligible electric fuel and purchased power costs is refunded or surcharged to customers through an interim fuel adjustment not later than the 90th day after the date the balance is accrued unless an exception applies. At what point does a utility determine that it incurs ("accrues") a fuel balance for purposes of an interim fuel adjustment? (I.E., Given the lag time in providing monthly fuel reports to the commission and based on a utility's accounting practices, what is the method for determining when a material under-recovery or over-recovery has accrued?)

OPUC and TIEC commented that the time period for accruing a fuel balance for purposes of an interim fuel adjustment is utility specific. CEP noted that utilities monitor fuel balances on an ongoing basis.

OPUC qualified its statement by saying that utilities should have discretion "as long as the materiality determination is made when the utility knows or should have known that it will incur more or less in fuel expenses based on (1) fuel contracts, (2) market fluctuation of fuel prices, (3) actual amount spent on procurement, and (4) contemporaneous review of its invoices, receipts, and other relevant fuel expenses." OPUC stated that the utility is best positioned to make such a determination due to its stewardship of all necessary information and records. OPUC further stated that this determination can be made by the utility prior to filing its monthly fuel report with the commission.

AXM and CARD stated that a utility accrues its fuel balance that meets the materiality threshold on the date its monthly report is due. AXM and CARD commented that, at the time of filing, a utility is aware of whether it has accrued a fuel balance, the fuel balance amount, and whether the balance meets the materiality threshold.

Joint Utilities recommended that the balance used for interim fuel adjustments should be the final balance available approximately 45 days after the end of the month. Joint Utilities further recommended that, for purposes of the interim fuel adjustment contemplated by statute, the term "accrual" should be defined as "the point at which actual fuel costs are finalized at the close of the monthly accounting period." Joint Utilities also recommended the commission adopt its definition of "current month" the most recent month for which costs and kilowatt-hour sales data are available. Joint Utilities noted that this approach is consistent with standard accounting practices used by all non-ERCOT utilities and ensures that adjustments "are based on verified historical data rather than preliminary estimates or projections."

Joint Utilities stated its definition of "current month" appropriately links accrual with monthly balancing. Joint Utilities explained that, for all non-ERCOT utilities, final fuel balances are typically unavailable until "the middle of the second month after month-end close." Joint Utilities indicated that estimates, while available earlier, are subject to adjustment in the utility's next month fuel report and is reflective of the time required to close accounting books and reconcile fuel costs. Joint Utilities commented that this approximate 45-day period complies with the 90-day deadline from the date of accrual to collect or surcharge a balance, preserves the integrity of the adjustment process, and avoids using incomplete data for filings- therefore mitigating customer billing inaccuracies.

Commission response

The commission determines that a fuel balance accrues 75 days from month end close or when the utility has verified, actual data. The commission accordingly revises the timeline for a utility to file an interim fuel adjustment under §25.236(h)(2) to accommodate the 75-day accrual period.

The commission revises §25.236(h)(2)(B) (formerly proposed §25.236(h)(2)(A)) to state that "[a] utility seeking an interim fuel adjustment to surcharge or refund a fuel under- or over-recovery balance must file its interim fuel adjustment petition and issue notice within five working days from the date the material fuel under- or over-recovery balance accrues, which is either (i) 75 days from the last day of the month for which the utility seeks recovery (month end close) or (ii) when the utility has verified, actual data for that month." The commission also specifies in new §25.236(h)(2)(C) that "[e]ach month for which a utility seeks recovery must correspond with the utilities monthly fuel cost and use report filed with the commission in accordance §25.82 of this title (relating to Fuel Cost and Use Information)." These changes align with the 45-day period referenced by Joint Utilities for when a final balance for fuel costs becomes available and the utility files its fuel cost report for the relevant reporting month in accordance with §25.82, relating to Fuel Cost and Use Information and the approximate 30-day period needed by utilities to verify the balances and prepare supporting documentation. Given the timing variance of this second-step verification and the comments from OPUC and TIEC indicating that the time period for accrual is utility-specific, the addition of "or when the utility has verified, actual data for that month" is appropriate. The provision is also revised to give flexibility to the presiding officer to set a procedural schedule that will enable the utility to issue a refund or collect a surcharge within the applicable time period. These changes eliminate the compliance issues associated with the proposed five working day period to file from the date a material balance accrues as discussed under the heading for Question 4 and provide the flexibility sought by Joint Utilities.

The provision also revises the exceptions to the final order deadline for interim fuel adjustments under §25.236(h)(2)(E) (previously §25.236(h)(2)(C)) to be the instances in which a hearing is required for an interim fuel adjustment. (i.e., if the presiding officer determines that the interim fuel adjustment sought would either (1) result in a total bill increase of 10 percent or more for an average customer in any rate class or (2) the utility has a material under-collected balance that is the result of extraordinary electric fuel and purchased power costs.)

Question 6

PURA §36.203(b)(3)(A) requires commission rules to ensure any material balance of amounts under-collected or over-collected for eligible electric fuel and purchased power costs is refunded or surcharged to customers through an interim fuel adjustment not later than the 90th day after the date the balance is accrued unless an exception applies. Given the introduction of the interim fuel adjustment by HB 2073 (88R), should §25.237(f), which concerns emergency revisions to a fuel factor, be deleted or revised? (i.e., Does an interim fuel adjustment eliminate the need for emergency revisions to the fuel factor?)

OPUC and TIEC recommended that proposed §25.237(f) be retained because the provision serves a different purpose than the interim fuel adjustments specified by HB 2073. OPUC and TIEC stated that an emergency interim fuel factor revision under proposed §25.237(f) authorizes a utility to adjust its fuel factor on an expedited timeline if it experiences "fuel curtailments, equipment failure, strikes, embargoes, sanctions, or other reasonably unforeseeable circumstances." Therefore, the utility would significantly and foreseeably under-recover fuel costs unless the utility's fuel factor is quickly revised.

OPUC noted that the 90-day or longer timeframe specified by PURA §36.203(c) if an under-collection is the result of extraordinary costs that are unlikely to continue may not be a sufficient timeframe for the utility to recover fuel costs. In contrast, OPUC commented that proposed §25.237(f) provides that the 30-day deadline for an interim order to be issued. OPUC further recommended the 120-day review period for the commission to ensure the approved emergency amount is not excessive be reduced to 90 days. OPUC also recommended that the penalty for an emergency revision if the commission determines no emergency condition existed be increased from 10% to 20% to ensure there is a sufficient deterrent from abusing this provision.

TIEC indicated that, if the emergency is severe enough, it may be financially difficult for a utility to carry any resulting under-recovery balance until it could recover those costs through an interim fuel adjustment surcharge. TIEC stated it would accordingly be prudent to retain the option to adjust a utility's fuel factor for highly specific and extreme emergency situations.

AXM and CARD and Joint Utilities recommended that proposed §25.237(f) be deleted because HB 2073 renders ad hoc emergency fuel factor revisions unnecessary. Joint Utilities remarked that HB 2073 sufficiently accounts for emergency situations through interim fuel adjustments in a standardized process. Specifically, Joint Utilities stated that PURA §36.203 addresses extraordinarily fuel cost events through the more structured and regular interim fuel adjustment process such that the provision is now unnecessary. Joint Utilities contended that retaining proposed §25.237(f) "would introduce unnecessary complexity and could create confusion about when and how utilities should respond to fuel cost volatility." Joint Utilities also remarked that retaining the provision would only serve to "perpetuate inefficiencies" and would contravene the legislative intent of HB 2073 to make fuel cost recovery more efficient.

CEP indicated that the only purpose of proposed §25.237(f) would be to "extend recovery time in the event of a cost spike such as was experienced during winter storm Uri." CEP remarked that is unlikely that severe weather or other such events would create a substantial reduction in fuel costs that would be considered an emergency. CEP indicated that the only point of comparison are the conditions surrounding Winter Storm Uri in 2021. CEP noted that even during Winter Storm Uri, gas distribution utilities were able to secure short-term financing to pay fuel costs.

Commission response

The commission elects to preserve §25.237(f) for emergency fuel factor revisions. The commission agrees with OPUC and TIEC that it is prudent to retain that provision in the event of an emergency and that the provision serves a separate purpose than interim fuel adjustments. Moreover, retaining the option to revise a fuel factor on an expedited timeline due to an emergency may obviate the need for an interim fuel adjustment if drastic changes to fuel costs are foreseeable. The commission declines to implement OPUC's recommended revisions to §25.237(f) as the existing timelines in the provision are sufficient. The commission disagrees with AXM and CARD and Joint Utilities that preserving §25.237(f) would introduce complexity and confusion into non-ERCOT fuel proceedings. If a utility determines it would prefer to have extreme fuel cost discrepancies resolved through an interim fuel adjustment rather than through an emergency fuel factor revision it may elect to do so at its discretion.

Question 7

Procedurally, how should a "protest" of a fuel factor or interim fuel adjustment be treated at the commission given the foregoing statutory limitations? Under HB 2073, a person that files a "protest" in the context of a fuel factor or interim fuel adjustment could be classified as a more constrained form of "intervenor" in the proceeding under commission rules. Specifically, an "intervenor" as defined in 16 TAC §22.2(25), relating to Definitions is a party to the proceeding and may accordingly, per 16 TAC §22.102(b), relating to Classification of Parties, "have the right to present a direct case, cross-examine all witnesses, conduct discovery, make oral or written legal arguments, and otherwise fully participate in any proceeding." This contrasts with the far more limited "protestor" defined in 16 TAC §22.2(37) that is not a party to the case and may only submit oral or written comments if allowed by the presiding officer per 16 TAC §22.102(c)). However, given the foregoing statutory boundaries on protests of fuel factors and interim fuel adjustments and the requirement that, for interim fuel adjustments, a material balance be collected from or refunded to customers no later than the 90th day after the date the balance accrues. In the context of these proceedings, consider the following questions.

Question 7a

Is a protest in fuel factor proceeding or of an interim fuel adjustment meant to equate to a motion to intervene? Or should filing a protest mean that the person is automatically a party to the (assuming that person is a customer of the electric utility, a municipality with original jurisdiction over the utility, or OPUC)?

OPUC, AXM and CARD, and TIEC recommended that a term "protest" as used in PURA §36.203 for non-ERCOT fuel proceedings be interpreted as a motion to intervene granting automatic party status. CEP generally recommended the statutory term "protest" not be construed too narrowly and that protestors of fuel proceedings be treated as parties. Conversely, Joint Utilities recommended that protests of fuel proceedings not be treated as a motion to intervene and protestors should not be granted automatic party status.

OPUC stated that it must be afforded the opportunity to substantively participate in fuel proceedings to fulfill its statutory role in representing the interests of residential and small commercial customers. OPUC noted that it generally files motions to intervene in certain electric utility proceedings, including fuel proceedings for non-ERCOT utilities in accordance with its statutory right to do so under PURA §13.003(a)(3). OPUC stated that PURA §36.203(e) does not diminish OPUC's statutory right to intervene. OPUC remarked that party status is accompanied by attendant rights such as conducting discovery, filing testimony, presenting a direct case, cross-examining witnesses, making oral or written legal arguments, and fully participating in the proceeding. OPUC further commented that party status residential and small commercial customers of the non-ERCOT utility should be construed liberally due to the unfamiliarity such customers may have with PURA and commission or State Office of Administrative Hearing rules and procedures.

CEP remarked that municipalities and other parties frequently intervene in fuel proceedings without opposing the outcome. CEP emphasized the importance of the participation of those parties as they provide meaningful contributions to the case and oversight. CEP explained that it does not matter whether party status is "automatic" given that, under the commission's procedural rules, the presiding officer should have an opportunity to rule on intervention by an entity that is not a municipality with original jurisdiction over the utility, OPUC, or a customer of the utility.

AXM and CARD stated that the expedited timeframes of HB 2073 and the definition and hearing requirements for contested cases under §2001.003 and §2001.056 of the Texas Administrative Procedure Act (APA). Specifically, AXM and CARD stated that once a protest is filed in either a fuel factor proceeding or interim fuel adjustment, the proceeding becomes a contested case. AXM and CARD emphasized that a fuel factor or interim fuel adjustment is a "ratemaking proceeding in which the Commission is determining a party's legal rights, duties, or privileges" that becomes a contested case if a protest is submitted by an eligible party. AXM and CARD stated that HB 2073 does not abrogate the APA requirements for contested cases and the procedural rights parties are afforded by the APA in contested cases. AXM and CARD referenced holdings from case law stating that "when the legislature adopts a new law, it is presumed to have been enacted with complete knowledge of existing law and with reference to it, and unless expressly amended, the other laws remain in effect" and that the Legislature is "presumed to be aware of an agency' s relevant rules and prior decisions."

TIEC stated that it would be sensible to automatically admit a protestor as a party to the proceeding assuming the protest is properly filed without a motion to intervene. TIEC indicated that PURA §36.203(e) provides that only a customer of the utility, a municipality with original jurisdiction over the utility, or OPUC may file a protest and would therefore have standing to intervene under §22.103(b)(2). Therefore, submitting a motion to intervene would be unnecessary and merely a formality. TIEC noted that if a protest is improperly filed by a party without standing, the utility or other parties to the fuel proceeding should be authorized to challenge the invalid protestor's party status in the same manner as motions to intervene.

Joint Utilities commented that a protest in a fuel proceeding is not equivalent to full intervention. Joint Utilities maintained that a protest is a procedural mechanism distinct from intervention that is limited only to a utility's customers, municipalities with original jurisdiction over the utility, and OPUC. Joint Utilities stated that treating a protest as an intervention would contravene "the legislative intent of HB 2073 to streamline fuel adjustment proceedings for timely recovery of fuel costs." Joint Utilities remarked that PURA §36.203 specifically limits the scope of a protest to whether the proposed adjustment reasonably reflects the costs a utility has incurred or will incur. Joint Utilities further stated the statute prohibits the prudence of cost from being raised as an issue by a protestor and limits the opportunity for a protestor to request a hearing outside of specific circumstances. Joint Utilities indicated that a protest should be treated as a more limited form of participation as an intervention to ensure the reduced 90-day deadline for implementing an interim fuel adjustment is achievable and other statutory boundaries are maintained. Joint Utilities stated that treating protests in a more limited fashion, as its proposal does, ensures the commission can "consider valid concerns without triggering a fully contested case unless the statutory thresholds are met."

Commission response

The commission determines that an eligible person that files a written protest in response to an interim fuel adjustment or fuel factor proceeding be afforded the rights of a party under the APA. The APA defines a "contested case" as "a proceeding, including a ratemaking or licensing proceeding, in which the legal rights, duties, or privileges of a party are to be determined by a state agency after an opportunity for adjudicative hearing." (emphasis added) While PURA §36.203(i) states "[a] proceeding under this section is not a rate case under Subchapter C [of Chapter 36]," that provision appears to only exempt non-ERCOT fuel proceedings under PURA §36.203 from the requirements of §§36.101-36.112. Accordingly, a non-ERCOT fuel proceeding would still be a contested case under the APA as it is an interim rate proceeding.

PURA §36.203(g) requires a hearing for interim fuel adjustments if the adjustment would result in a total bill increase of 10 percent or more or if the adjustment results from extraordinary electric fuel and purchased power cost. There is also no prohibition on the commission holding a hearing for an interim fuel adjustment on its own motion. If a hearing is held or other issues arise in an interim fuel adjustment proceeding that render meeting the 90-day refund or surcharge deadline for material balances infeasible, then a party may file a petition for interim relief or the presiding officer may otherwise order interim relief under §25.236(f)(4).

For fuel factor proceedings, PURA §36.203(d) states that the commission is not required to hold a hearing on the adjustment of a utility's fuel factor, the following sentence states "[i]f the commission holds a hearing, the commission may consider at the hearing any evidence that is appropriate and in the public interest." By implication, this authorizes the commission to hold a hearing in a fuel factor or fuel factor formula revision proceeding if it elects to do so.

Question 7b

What rights should a person that files a "protest" in a fuel factor proceeding or an interim fuel adjustment have? (i.e., right to present a direct case, cross-examine witnesses, conduct discovery, etc.)

OPUC, CEP, AXM and CARD, and TIEC commented that protestors in fuel proceedings should have the same rights a party to a contested case is afforded under the APA such as the ability to conduct discovery, file testimony, present a direct case, cross-examine witnesses, and make oral or written legal arguments. AXM and CARD highlighted that under Texas Government Code § 2001.051 of the APA, a protestor is "is entitled to an opportunity for a hearing after reasonable notice of not less than 10 days and to respond and to present evidence and argument on each issue involved in the case." AXM and CARD also remarked that a protestor is entitled to conduct discovery in non-ERCOT fuel proceedings in accordance with §22.1. Purpose and Scope; §22.141. Forms and Scope of Discovery; §22.143. Depositions; and §22.144. Requests for Information and Requests for Admission of Facts. TIEC stated that, to ensure due process rights are preserved, participants in non-ERCOT fuel proceedings should be afforded the opportunity to present evidence and cross-examine witnesses if a hearing is held.

Joint Utilities stated that the procedural rights of a protestor should be limited to the submission of written comments or objections, the presentation of evidence relevant to whether "the proposed factor ‘reasonably reflects' fuel and purchased power costs," request a hearing if the statutory criteria provided by PURA § 36.203(g) are met. Joint Utilities stated that a protestor "should not automatically gain the full rights of an intervenor" under §22.102(b) and instead, intervenor rights should only be granted if the protestor separately files a motion to intervene that is approved in accordance with commission rules. Joint Utilities maintained its interpretation and proposal appropriately preserve due process rights while maintaining the streamlined process enumerated by HB 2073 which limits the scope of review to whether the fuel factor or interim adjustment "reasonably reflects costs the electric utility has incurred or will incur."

Commission response

The commission generally agrees with OPUC, CEP, AXM and CARD, and TIEC that eligible persons that file a written protest in fuel proceedings should have the same rights a party to a contested case is afforded under the APA. However, under PURA §14.052(b), the commission may adopt rules that authorize an administrative law judge to limit certain procedural rights afforded to parties in a contested case. Accordingly, the commission revises §25.236(h)(3) to mirror the procedural steps of §25.237(g) regarding protests of interim fuel adjustments. The revised provision establishes that discovery in an interim fuel adjustment or fuel factor proceeding will be conducted in accordance with the commission's rules, except as modified by the presiding officer.

Question 7c

Given the time constraints surrounding refunds or collections, should the rights afforded to a person that files a "protest" in an interim fuel adjustment be different than those afforded to a person that files a "protest" in a fuel factor proceeding?

OPUC, CEP, and AXM and CARD commented that there is no difference in rights that should be afforded between a protestor in an interim fuel adjustment and a protestor in a fuel factor proceeding. AXM and CARD indicated that the more limited timeframe for an interim fuel adjustment may cause practical issues, there is no functional difference in rights a protestor has in either proceeding.

TIEC and Joint Utilities commented that the rights of a protestor in a fuel factor proceeding should be more expansive than in an interim fuel adjustment. TIEC and Joint Utilities explained that a protestor should have a greater opportunity to participate in a fuel factor proceeding due to its wider scope and lengthier timeframe than an interim fuel adjustment. TIEC maintained that the commission should afford protestors the greatest opportunity to participate as possible while "also respecting the timeframes for litigating those proceedings set by the legislature."

Joint Utilities stated that a protestor in an interim fuel adjustment should have the right to file a protest and request a hearing, as well as the right to a hearing "only if the adjustment exceeds the 10% threshold or involves extraordinary costs" in accordance with PURA § 36.203(g), and limited discovery or procedural rights unless the protestor's request for a hearing is granted. For fuel factor proceedings, Joint Utilities referred to its proposal and stated that protestors may be entitled to slightly more flexibility but still within the limited statutory scope.

Commission response

The commission generally agrees with OPUC, CEP, and AXM and CARD and declines to vary the procedural rights afforded to a person that files a written protest in an interim fuel adjustment proceeding or fuel factor proceeding except as modified by the presiding officer on a case-by-case basis.

Question 7d

Should an interim fuel adjustment be eligible for administrative approval under 16 TAC §22.32, relating to Administrative Review, regardless of whether a protest is filed? (Assuming no hearing is required under PURA §36.203(g) and the commission does not otherwise deem a hearing to be necessary).

OPUC and CEP recommended that interim fuel adjustments not be eligible for administrative approval regardless of whether a protest is filed. AXM and CARD stated the interim fuel adjustments could be eligible for administrative approval provided that the requirements of §22.32 are met- more specifically §22.32(a)(3).

TIEC stated that whether an interim fuel adjustment is eligible for administrative approval is dependent on whether non-utility participants in such proceedings are considered "protestors" or "intervenors" under the commission's rules. If participants are considered intervenors and therefore parties, then the interim fuel adjustment would not qualify for administrative approval due to §22.32(a)(3) stating that administrative review is not available unless "there are no issues of fact or law disputed by any party." Alternatively, if participants are considered "protestors" then "administrative review would be available notwithstanding those participants disputing issues of fact or law." TIEC reiterated its recommendation that protestors under PURA §36.203 be granted party status if the protest is properly filed.

Joint Utilities stated that an interim fuel adjustment should be eligible for administrative approval provided that a hearing is not required under PURA §36.203(g) and the commission does not otherwise consider a hearing to be necessary. Joint Utilities maintained this interpretation is consistent with HB 2073 and that "[a] protest alone should not automatically trigger a contested case or preclude administrative approval." Joint Utilities expressed that administrative approval ensures the efficient implementation of interim fuel adjustments by avoiding unnecessary delays and therefore preserving both the 90-day recovery timeline and the commission's authority to hold a hearing if necessary. Joint Utilities recommended the commission adopt the language in its proposal and explicitly state in the rule that interim fuel adjustments are eligible for administrative review subject to the limitations previously specified.

Commission response

The commission declines to implement specific language concerning administrative approvals for interim fuel adjustments in §25.236. A proceeding is eligible for administrative approval if the criteria under §22.32, relating to Administrative Review, are met.

Question 8

Please provide any additional feedback regarding the statutory deadlines and commission procedures surrounding fuel factor proceedings and interim fuel adjustments.

Commission response

The commission has organized the additional feedback received by commenters in response to Question 8 under the relevant headers.

TIEC's Transmission-Voltage Customer Proposal

TIEC recommended that provisions be added to the rule to require utilities "to bill individual transmission-voltage customers based on their actual fuel costs, but on a two-month lag." TIEC commented that this change for transmission-voltage customers would ensure fuel costs are properly allocated to the customers that cause them while also ensuring full recovery of fuel cost occurs within the 90-day period required by PURA §36.203. TIEC remarked that billing transmission-voltage customers in this manner would increase customer bill transparency while also rendering surcharge and refund proceedings unnecessary. TIEC provided draft redlines consistent with its recommendation.

Commission response

The commission declines to implement the recommended change because it is out of scope. TIEC's proposal would create two tiers of interim fuel adjustments and fuel factors, a tier for transmission voltage customers and a tier for all other customers receiving service at distribution voltage. HB 2073 neither requires nor prohibits a specific treatment of transmission voltage customers in fuel proceedings. PURA §36.201(b)(2) only requires commission rules to "ensure that…the total of the utility's eligible electric fuel and purchased power costs, including any under-collected or over-collected amounts to be recovered through an interim fuel adjustment, is allocated among customer classes based on actual

historical calendar month usage." The commission acknowledges the potential benefit of diminishing the magnitude of under-recoveries for distribution voltage customers if transmission customers are billed more directly, provided that the prohibition on automatic adjustment and pass-through of fuel costs under PURA §36.201 is observed. Accordingly, the commission defers this issue for a later rulemaking.

TIEC recommended an alternative proposal for implementation of the statutory requirement for significant bill increases of 10 percent or more to be deferred over a period greater than 90 days. Specifically, TIEC recommended that utilities be required, for transmission-voltage customers,

to monitor whether changes in fuel costs resulted in fuel factor increases that "would increase [the customer's] total bill by 10% or more compared to the increase that would have occurred under the prior month' s fuel factor." In that event, the utility would be required to "limit the increase to 10% of the total bill, with the overage to be deferred and recovered over a period that is greater than 90 days."

Commission response

The commission declines to implement the recommended change because it is out of scope. TIEC's recommendation would impose an additional obligation on utilities to monitor fuel costs of transmission voltage customers that were not noticed and to which other commenters have not had an opportunity to reply to. The proposed rule language implementing deferred recovery for a period greater than 90 days in the event of a bill increase of 10% or more is sufficient to address the requirement of HB 2073.

Joint Utilities Alternative Proposal for Implementation of HB 2073

Joint Utilities commented that its alternative proposal correctly implements and meets the requirements of HB 2073. Joint Utilities noted that PURA §36.203(b), as amended by HB 2073, imposes four criteria for commission rules: (1) that fuel recovery occurs as contemporaneously as reasonably possible; (2) that eligible costs are allocated among customer classes based on actual historical calendar month usage; (3) that material balances are recovered or refunded through an interim fuel adjustment; and (4) notice is provided to affected parties.

(1) Contemporaneity and "automatic" adjustments

Joint Utilities contended that monthly adjustments are what is meant by the text of PURA §36.203(b)(1) which requires commission rules to ensure that a non-ERCOT utility collects eligible fuel costs "as contemporaneously as reasonably possible." Joint Utilities asserted that a process that precludes monthly adjustments and instead requires a less frequent adjustment period does not comply with this statutory requirement.

Joint Utilities further commented that monthly adjustments are not precluded by PURA §36.201 which prohibits the commission from approving a rate or tariff that authorizes a utility to "automatically adjust and pass through to the utility's customers a change in the utility's fuel or other costs" except as permitted by PURA §36.204. Joint Utilities stated that interpreting PURA §36.201 as applying to PURA §36.203 improperly conflates an automatic adjustment with a monthly interim adjustment and does not properly effectuate PURA §36.203(a). Moreover, Joint Utilities stated that PURA §36.201 neither explicitly prohibits monthly adjustments nor does the term "monthly" appear in PURA §36.201. Joint Utilities remarked that the mere fact an adjustment is "monthly" does not inherently render it "automatic" or vice versa. Accordingly, Joint Utilities concluded that PURA §36.201 does not prohibit monthly interim adjustments.

Joint Utilities also noted that PURA §36.203(a) states "36.201 does not prohibit the commission from reviewing and providing for adjustments of an electric utility's fuel factor." Joint Utilities pointed out that PURA §36.203(a) does not require the commission to issue an order for each interim fuel adjustment, only that the provision allows for the commission to "provide for adjustments."

Joint Utilities explained that its proposal for monthly interim adjustments is not "automatic" and therefore not prohibited by PURA §36.201 for four reasons. First, the monthly adjustment in its proposal is only an "interim" adjustment that is a temporary rate that is subject to review and correction in a later fuel reconciliation proceeding. Joint Utilities emphasized the significance of HB 2073 increasing the frequency of fuel reconciliations from at least every three years to at least every two years. Joint Utilities commented that the two-year timeframe will ensure that monthly interim fuel adjustments will be more thoroughly reviewed and approved than under the existing rules. Second, Joint Utilities pointed out that interim fuel adjustments under its framework would be subject to protest and a potential hearing under PURA §36.203(e) and therefore a monthly adjustment would not be automatic. Third, Joint Utilities contended that because its proposal requires staff compliance reviews of monthly interim adjustments, therefore a monthly adjustment could not be "automatically" implemented by the utility. Fourth, Joint Utilities commented that the consumer protections imposed by PURA §36.203(c) which permit the commission to defer recovery of extraordinary costs that are unlikely to continue prevent the monthly interim adjustment from being automatic. Specifically, Joint Utilities stated that PURA §36.203(c) is an assurance that there will not be an "automatic" adjustment that could cause rate shock.

(2) Cost allocation based on actual historical calendar month usage

Joint Utilities commented that its proposed version of §25.237(c)(1) implements the statutory requirement that "the total of the utility's eligible electric fuel and purchased power costs, including any under-collected or over-collected amounts to be recovered through an interim fuel adjustment, is allocated among customer classes based on actual historical calendar month usage."

(3) Material balances must be recovered or refunded through an interim fuel adjustment

Joint Utilities commented that its proposed rules implement the criteria for material balance recovery or refunds specified by PURA §36.203(b). Joint Utilities remarked that the implementation of monthly interim adjustments ensure that "balances are not accrued and then carried for more than 90 days" while still accounting for adjustment protests and their outcomes as well as extraordinary fuel costs by deferring recovery for a period of longer than 90 days.

(4) Notice to affected parties

Joint Utilities commented that is proposal requires notice to all parties that participated in the non-ERCOT utility's most recent fuel reconciliation proceeding. Joint Utilities indicated that this is consistent with rider proceeding such as the District Cost Recovery Factor (DCRF) rider for ERCOT utilities under §25.243(e)(2) which requires notice to "all parties in the electric utility's last comprehensive base-rate proceeding and, if applicable, last DCRF proceeding."

Joint Utilities further commented that its proposal also accurately implements the other requirements of HB 2073, such as the explicit authorization for the commission to defer recovery of extraordinary fuel costs that are unlikely to continue, the protest of interim fuel adjustments and fuel factors, and the more frequent two-year fuel reconciliation period.

Commission response

This question is comprehensively addressed under the header for Implementation of HB 2073.

Implementation of HB 2073

Joint Utilities stated that the commission's proposed rules do "not undertake the substantial revision of the Fuel Rules that HB 2073 requires." Joint Utilities categorically opposed the proposed rule changes on the basis that implementation is infeasible and contrary to the directives of PURA §36.203, as amended by HB 2073. Joint Utilities emphasized changing the existing fuel cost recovery rule framework is necessary to correctly implement HB 2073. Accordingly, Joint Utilities recommended the commission adopt its alternative proposal for §§25.235-25.237.

Joint Utilities commented that the existing fuel recovery rules "inevitably misalign costs and payments, are inherently burdensome on all stakeholders, and do not achieve accurate, contemporaneous collection of fuel costs." Joint Utilities noted that the existing fuel cost recovery process for non-ERCOT utilities involves "fuel formula change cases, fuel factor adjustment cases, fuel refund cases, and fuel surcharge cases" and would continue to exist under the proposed rules. Joint Utilities indicated there have been more than 25 such fuel cost recovery proceedings since 2022, including ten fuel refund proceedings and six surcharge proceedings. Joint Utilities stated that each refund proceeding represents an instance where customers have paid for fuel costs that exceed the fuel expenses for that period which is solely attributable to the "to the inevitable misalignment of formulas, factors, and actual costs." Similarly, each surcharge proceeding represents the inverse where customer bills have been insufficient to cover fuel costs. Joint Utilities remarked that the subsequent proceeding to issue the refund or surcharge only serves to perpetuate the misalignment between customer bills and fuel costs.

Joint Utilities commented that the proposed rules would only continue the current paradigm of fuel cost recovery for non-ERCOT utilities and in many instances, increase the associated regulatory burden of compliance. Joint Utilities emphasized that the intent of HB 2073 was to "reform the fuel recovery process to make it more efficient and timely by moving away from the existing suite of fuel recovery processes" and referred to the Bill Analysis issued by the Texas House of Representatives State Affairs Committee.

Joint Utilities explained that non-ERCOT utilities must purchase fuels such as natural gas and coal, to operate their generators and that the cost recovery process for such fuel purchases is unnecessarily complex and litigious. As a result, utilities have accumulated and carried significant uncollected balances that must be addressed through surcharges on customer bills. Joint Utilities indicated that these large balances accumulate due to the impossibility associated with predicting future fuel prices when establishing a fuel charge on customer bills. Joint Utilities noted that the surcharge approval process does not actually correct the underlying fuel charge on a customer bill, which is instead undertaken in a separate contested case proceeding. Joint Utilities emphasized that HB 2073 was intended to create a "more efficient fuel cost validation process that will allow for more timely, incremental corrections to fuel charges while avoiding the need for surcharges or refunds except in extreme circumstances"

Joint Utilities asserted that HB 2073 was intended to reform the currently burdensome fuel recovery framework by requiring the recovery of fuel costs "as frequently as possible" and prohibiting fuel balances to be carried for more than 90 days to ensure costs are tracked on an ongoing basis. Joint Utilities also stated HB 2073 promotes customer protection by authorizing protests of fuel adjustments and requiring interim fuel adjustments to be reviewed and reconciled every two years, instead of three years under the status quo.

Commission response

The commission rejects Joint Utility's proposal as inconsistent with HB 2073 and as violative of PURA §36.201. HB 2073 revised PURA §36.203 to require that commission rules ensure that a utility collects, as contemporaneously as reasonably possible, certain fuel costs the commission determines are eligible and that such eligible costs be allocated among customer classes based on actual historical calendar month usage. HB 2073 also requires that "material" balances be collected from or refunded to customers through an interim fuel adjustment no later than 90 days from the date the balance accrues unless certain criteria are met. The statutory changes require a hearing in two very specific circumstances for interim fuel adjustments and generally authorize a hearing for fuel factor proceedings, if the commission determines a hearing is necessary. HB 2073 also establishes a limited right for certain eligible persons to file a "protest" in response to an interim fuel adjustment petition or a fuel factor proceeding, with the narrow scope of a single issue identified for both. HB 2073 categorically prohibits the consideration of prudence of costs during an interim fuel adjustment and fuel factor proceeding. Lastly, HB 2073 establishes the time period for fuel reconciliations to be biannual and authorizes the incorporation of under-collected or over-collected balances resulting from a fuel reconciliation to be incorporated into an interim fuel adjustment, as directed by the commission.

When compared to existing §§25.235-237, HB 2073 is essentially consistent with current commission practice in non-ERCOT fuel proceedings. Existing rule concepts, such "material" balances under existing §25.237 for refunds and surcharges, are contemplated by HB 2073. Moreover, the changes to PURA §36.203 made by HB 2073 amount to primarily procedural changes, such as the establishment of specific timelines and the identification of the specific scope of certain proceedings. The only other substantive change is the creation of the interim fuel adjustment proceeding, which under existing commission rules is a procedural action either independently triggered (for refunds) or sought (for surcharges) by meeting or exceeding the materiality threshold under existing §25.237(a)(3)(B) or is an attendant procedural action subsequent to a fuel factor proceeding or fuel reconciliation. The statutory revisions only necessitated the clear establishment of refunds and surcharges, now collectively called an "interim fuel adjustment" by HB 2073, as a standalone commission proceeding with specific timelines under §25.236.

Joint Utilities proposal, in contrast, contemplates a complete overhaul of non-ERCOT fuel proceedings with the commission. The commission rejects this proposal as inconsistent with HB 2073. For example, Joint Utilities' proposal contemplates the use of a "fuel factor adjustment balancing account" which is identified as "difference between the fuel and purchased power expenses and the fuel factor billed revenue" and may include "additional amounts or interim fuel adjustments granted by the commission." Elsewhere, the purpose of the balancing account is established as a mechanism to ensure "that only the appropriate revenue is recovered through the application of the [fuel] factor rate and interim fuel adjustments and that the utility does not accumulate a material balance of over-or under-recovery." (emphasis added) The Joint Utilities proposed definition of "material balance" is much the same as the commission-proposed definition of "materially" or "material."

A balancing account is forward-looking accounting mechanism employed by a utility to ensure that differences between actual and estimated costs and revenues are appropriately reflected in future rates. Balancing accounts are not utilized in commission non-ERCOT fuel proceedings. Instead, the commission requires the usage of "deferred fuel accounts" which are treated as a regulatory asset. The usage of a balancing account would be a departure from current practice and is not contemplated by HB 2073.

Moreover, Joint Utilities' language concerning the purpose of the balancing account to prevent a material balance from ever occurring appears to contemplate the total elimination of refunds or surcharges from being issued or collected. Joint Utilities proposal appears to interpret an interim fuel adjustment not as a standalone commission proceeding, but as an adjustment to the balancing account to which eligible persons may protest and the commission would hold a hearing on if the statutory criteria are met. It is unclear how eligible persons or the commission would be notified of the occurrence of a "balancing account adjustment" or how the statutory criteria for a hearing on such an adjustment would ever be triggered. Joint Utilities proposal also appears to reduce a fuel factor proceeding into a perfunctory administrative action where all a utility must demonstrate is that "updated fuel factor rates are reasonably anticipated to collect from or refund to customers any accrued material balance in the fuel factor balancing account within 90 days of the accrual of that material balance." (emphasis added)

Additionally, Joint Utilities defines the term "fuel factor rate" as "the monthly per kWh charge to be applied to customers' bills that is estimated to reflect the electric utility's fuel and purchased power costs [with any appropriate adjustments]" and later provides that a utility's fuel costs "will be recovered from the utility's customers by the use of a fuel factor rate and interim fuel adjustments, which the utility may combine as a single charge on customers' bills." Read together with the stated purpose of the balancing account to eliminate the potentially material balances from occurring, the Joint Utilities proposal appears to contemplate the establishment of a rate that authorizes the automatic adjustment and pass-through of a utility's fuel costs to customers, which is expressly prohibited by PURA §36.201. The commission interprets "automatic" adjustments and pass-throughs under PURA §36.201 to be the direct imposition of fuel or other costs upon customers as they occur, without the opportunity for commission review. The usage of a balancing account in the manner Joint Utilities contemplates, in conjunction with the proposed application and definition of a "fuel factor rate," would effectively authorize a utility to charge customers for any fuel costs that exceed the utility's revenues as they occur (I.E. monthly), with little to no commission review of such charges other than a routine monthly filing of a customer-class rate schedule by the utility.

Feasibility of the Proposed Rule Changes

Joint Utilities commented that incorporation of HB 2073 into the existing fuel recovery framework in the commission's proposal is "ultimately not possible." Specifically, Joint Utilities remarked that the commission's proposal does not ensure contemporaneous fuel cost recovery or even move in that direction. Instead, the commission proposal would maintain the existing cycle of fuel formula and fuel factor cases that "inevitably fail to achieve consistent, contemporaneous recovery" and subsequently necessitate fuel refund and fuel surcharges and the associated proceedings. Joint Utilities asserted that HB 2073 intended to eliminate fuel refunds and fuel surcharges "absent extraordinary circumstances."

Joint Utilities emphasized that the historical amount of fuel refund and fuel surcharge dockets is an indication that the current fuel recovery framework fails to provide for contemporaneous recovery. Joint Utilities noted that, under the current system, fuel cost recovery is not appropriately balanced with the incurring of fuel costs and the fact a refund or surcharge is not triggered does not mean contemporaneous recovery is occurring.

Joint Utilities concluded that preserving the existing fuel formula and fuel factor framework while also implementing HB 2073 is impracticable. Joint Utilities noted that, even if fuel formula and fuel factor proceedings were retained, those proceedings would need to be more frequent to more towards contemporaneous cost recovery. Joint Utilities commented that such an approach is incompatible with the commission proposal, which limits the frequency for which utilities can file for adjustments and the timing of their filings within the calendar year. Joint Utilities remarked such a timing restriction directly conflicts with a more timely alignment between the time fuel costs are incurred and the time those fuel costs are recovered. Moreover, Joint Utilities contended that more frequent fuel formula and fuel factor proceedings would be undesirable and impractical due to the volume and associated administrative burden of litigating those proceedings. Joint Utilities emphasized that changing the current fuel recovery framework is necessary to implement HB 2073.

Joint Utilities commented that, even if the timelines in the commission's proposal were revised to be feasible, implementation would be extraordinarily burdensome for utilities, the commission, and all stakeholders. Joint Utilities emphasized that there would be a substantial risk that deadlines will be missed or that "issues arise within the process that lead to violations of the statutory requirements." Joint Utilities noted that it is unreasonable to think that the Legislature "intended to increase the Commission's workload and the regulatory burden and regulatory risk on all stakeholders" and concluded that the fuel recovery framework must be "fundamentally reformed."

Joint Utilities indicated that its comments on individual rule provisions "should not be construed as an endorsement" of the commission's proposal. Joint Utilities maintained that the commission's proposal is inconsistent with the requirements of PURA §36.203, as amended by HB 2073.

Commission response

The commission acknowledges the increased administrative burdens associated with complying with the 90-day statutory deadline specified under PURA §36.203(b)(3)(A) for interim fuel adjustments. The revisions made to the procedural timelines in §25.236 for interim fuel adjustments referenced under the commission response to Question 5 presents a feasible solution to the concerns raised by Joint Utilities and other commenters regarding the practicability of meeting the statutory deadlines and complying with any associated rule deadlines. Under the revised timeline, the accrual of a material balance coincides with the date a utility must file its interim fuel adjustment petition and issue notice, with discretion afforded to the utility on when to file once it determines when the utility has verified, actual data for that month. Moreover, the presiding officer will set a procedural schedule that will enable the utility to issue a refund or collect a surcharge within the applicable time period specified in §25.236(f)(2)(A) or (B) (i.e., within 90 days from the date the balance accrues unless one of the statutory exceptions apply). . This sequencing of the proceeding and subsequent action by the utility satisfies the requirement of PURA §36.203(b)(3)(A) for material balances to be refunded or surcharged 90 days from the date of accrual. In the event a hearing is held, an interim fuel adjustment is eligible for interim relief that would enable the 90-day deadline to be met. The revised proposal also complies with the requirements of the APA in that it treats eligible persons that file a written protest in both interim fuel adjustments and fuel factor proceedings as parties and affords them certain statutory procedural rights, with appropriate limitations given the narrow scope of such proceedings.

Proposed §25.235 - Fuel Costs

Proposed §§25.235(b), 25.235(b)(1), and 25.235(b)(1)(A)(i) and (ii)- Notice of Fuel Proceedings

Proposed §25.235(b) requires an electric utility to give notice of a fuel proceeding at the time the petition is filed. Proposed §25.235(b)(1) requires notice in fuel proceedings to be posted to the utility's website and provided to OPUC by electronic mail. Proposed §25.235(b)(1)(A) requires notice in interim fuel adjustments or a proposal to change the fuel factor under §25.237 must be by either by one-time publication in a newspaper having general circulation in each county of the service area of the electric utility under §25.235(b)(1)(A)(i) or by individual notice to each customer or by individual notice to all parties in the electric utility's prior fuel reconciliation proceeding under §25.235(b)(1)(A)(ii).

OPUC recommended proposed §§25.235(b)(1), 25.235(b)(1)(A), and 25.235(b)(1)(A)(i) be revised to require both notice by newspaper publication and notice by individual issuance to each customer and all parties in the electric utility's prior fuel reconciliation proceeding. In contrast, Joint Utilities opposed the inclusion of newspaper notice or individual notice in §25.235(b)(1)(A)(i) and (ii) for interim fuel adjustments and recommended it be replaced with a uniform requirement for notice by electronic mail to all parties in the utility's most recent fuel reconciliation proceeding. OPUC commented that, by presenting an option between the two forms of notice, the proposed language diminishes the effectiveness of notice. OPUC remarked that newspaper notice, by itself, is insufficient as most customers rely primarily on the internet and social media. Therefore, newspaper notice is unlikely to actually reach a utility's customers. In contrast, OPUC stated that individual notice is preferable due to its reliability. Joint Utilities indicated that requiring newspaper notice or individual notice would, at a minimum, take approximately 30 to 45 days. Joint Utilities commented that this delay is incompatible with HB 2073's 90-day deadline to complete bill adjustments and the 75-day application processing timeline under proposed §25.235(i)(2)(B).

Commission response

The commission generally agrees with Joint Utilities that newspaper notice is incompatible with the reduced timeline imposed by HB 2073. The commission accordingly eliminates newspaper notice as a requirement, deletes §25.235(b)(1)(A)(i), and merges §25.235(b)(1)(A)(ii) into §25.235(b)(1)(A). While PURA §36.103 under Chapter 36, Subchapter C. requires notice of proposed rate changes to be issued by newspaper, PURA §36.203(i) states "[a] proceeding under this section is not a rate case under Subchapter C." Therefore, non-ERCOT fuel proceedings are exempt from the newspaper notice requirement under PURA §36.103. The commission declines to replace the individual notice requirement with a uniform requirement for notice by electronic mail, as certain customers may not have an e-mail address or may have not provided an e-mail address to the utility. In this event, the option to provide notice by other means, such as first-class mail, should be available to the utility.

The commission also adds new §25.235(b)(2)(C)(ii), (iii) and (iv) which require notices to explain the notice recipient's right to file a protest in a fuel factor or interim fuel adjustment proceeding, including a requirement for the protest to identify whether the person that submits the protest is a customer of the utility; specify the appropriate scope of a protest in an interim fuel adjustment or fuel factor proceeding, as applicable; include an admonition that a request for a hearing should be included in the protest if one is sought; and the specific grounds for which a hearing may be held in each type of proceeding.

Proposed §25.236 - Recovery of Fuel Costs

Proposed §25.236(a) - Eligible fuel expenses

Proposed §25.236(a) establishes that eligible fuel expenses include expenses properly recorded in Federal Energy Regulatory Commission (FERC) Uniform Systems of Accounts 501, 502, 503, 509, 518, 536, 547, and 555, as modified by the provision, as of April 1, 2025. The provision expressly excludes any later amendments to the System of Accounts from being incorporated into the subsection.

Joint Utilities recommended FERC Account 559.3 be added to the list of FERC Uniform System of Accounts that describe fuel expenses eligible for recovery in proposed §25.236(a). Joint Utilities noted that this account includes "the cost delivered at the station" of renewable fuel costs such as hydrogen or renewable natural gas. Joint Utilities commented that the addition of this account to the list of eligible fuel costs would be consistent with FERC Order 898.

Commission response

The commission agrees with Joint Utilities and implements the recommended change.

Proposed §25.236(a)(8) - Revenue offsets for eligible fuel expenses

Proposed §25.236(a)(8) prohibits eligible fuel expenses from being offset by revenues by affiliated companies for the purpose of equalizing or balancing the financial responsibility of differing levels of investment and operation costs associated with transmission assets. The provision also authorizes eligible fuel expenses to be offset by revenues specified under §25.237(A)-(C).

CEP commented that mandatory language should be preserved in proposed §25.236(a)(8) for eligible fuel offsets. Specifically, CEP commented that existing §25.236(a)(8) states that "eligible fuel expenses shall be offset by [the revenues subparagraphs (A) through (C)]." However, in proposed §25.236(a)(8), the "shall" is replaced with "may": "eligible fuel expenses may be offset by [the revenues subparagraphs (A) through (C)]. Accordingly, CEP recommended that "may" be replaced with "must" to ensure that eligible fuel expenses are appropriately "offset by corresponding revenues that are directly related to those expenses" and therefore promote "contemporaneous matching of fuel revenues and expenses" which in turn would mitigate unnecessary surcharge or refunds by a utility in future fuel reconciliation proceedings.

Commission response

The commission agrees with CEP and implements the recommended change. The provision is revised to state that eligible fuel expenses must be offset by the revenues specified under §25.236(8)(A)-(C).

Proposed §25.236(e) - Fuel reconciliation proceedings

Proposed §25.236(e) establishes the burden or proof and scope of a fuel reconciliation proceeding.

Proposed §25.237(e)(2) - Scope of fuel reconciliation proceeding

Proposed §25.237(e)(2) specifies that the scope of a fuel reconciliation proceeding and establishes that a utility has the burden of proof in a fuel reconciliation proceeding to establish the reasonableness of its fuel expenses and the materiality of any over- or under-recovery.

OPUC recommended proposed §25.236(e)(2) be revised to state that "[A]n electric utility has the burden of proof in a fuel reconciliation proceeding to establish the reasonableness and necessity of its fuel expenses and the materiality of any over- or under-recovery." OPUC remarked that, because a utility bears both the burden of showing that its eligible fuel expenses are both "reasonable" and "necessary" when providing electric service, the rule should be revised accordingly.

Commission response

The commission agrees with OPUC and implements the recommended change with revisions. A cost that is reasonable does not always necessarily mean the cost is necessary (i.e. fuel volume, fuel type, etc.). The commission revises the first sentence of §25.236(e)(2) to state: "The scope of a fuel reconciliation proceeding includes any issue related to determining the reasonableness and necessity of the electric utility's fuel expenses…." The commission also deletes the second sentence regarding the electric utility's burden of proof under §25.236(e)(2) as it is redundant of §25.236(e)(1)(A). The commission merges the portion of §25.236(e)(2) regarding the electric utility's burden of proof regarding the materiality of any over- or under-recovery into §25.236(e)(1)(A).

Proposed §25.236(f) - Interim fuel adjustments

Proposed §25.236(f) requires a utility to apply for an interim fuel adjustment in the time frame specified by §25.236(h)(2)(A) if the utility is in a state of material under-collection or over-collection of the utility's reasonably stated eligible fuel and purchased power costs.

Proposed §25.236(f)(1) - Adjustment factor

Proposed §25.237(f)(1) states that if it is determined in the interim fuel adjustment that the utility is in a state of material under-collection or over-collection, except as provided for under §25.237(g)(3), each rate class must be credited or assessed a refund or surcharge, as applicable, using an adjustment factor. The provision further states that the adjustment factor will be applied to the kilowatt-hour usage of each rate class for the duration of the refund or surcharge period.

Proposed §25.236(f)(1)(B) - Adjustment factor for transmission voltage customers

Proposed §25.236(f)(1)(B) provides that, notwithstanding the requirements of §25.236(f)(1)(A), each retail customer who receives service at transmission voltage levels, each wholesale customer, and any groups of seasonal agricultural customers as identified by the electric utility must be given a one-time credit or assessed a surcharge made on a monthly basis over a period not to exceed 12 months through a bill charge, based on the actual refund or surcharge balance for the individual customers.

Joint Utilities recommended proposed §25.236(f)(1)(B) be revised to replace the phrase "based on the actual refund or surcharge balance for the individual customers" with language from existing §25.236(e)(4) "based on their individual actual historical usage recorded during each month of the period in which the cumulative under- or over-recovery occurred, adjusted for line losses if necessary." Joint Utilities recommended generally that proposed §25.236(f) not be adopted, but in the event it is adopted, that proposed §25.236(f)(1)(B) be reverted to existing language as "there is no reason for it to deviate from current practice."

Commission response

The commission agrees with Joint Utilities that changing current practice is unnecessary in this instance and implements the recommended change. The commission also makes conforming revisions to §25.236(f)(1).

Joint Utilities commented that calculation of customer-specific refunds under §25.236(f)(1)(B) for customers taking service at transmission voltage is infeasible given the 5-day period for utilities to prepare interim fuel adjustments under proposed §25.236(i)(2)(A). Joint Utilities also generally remarked the 5-day period under proposed §25.236(i)(2)(A) is unworkable for utilities.

Commission response

The commission declines to revise the provision based on Joint Utilities comments because the issue is moot. The revisions to the procedural timeline for interim fuel adjustments under §25.236(h)(2), as detailed under the heading for Question 5, substantively address Joint Utilities concerns.

Proposed §§25.236(f)(2), 25.236(f)(2)(B), 25.236(f)(2)(B)(i), and §25.236(h)(2)(C)- Refunds and surcharges

Proposed §25.236(f)(2) requires refunds and surcharges to be issued and recovered by the electric utility, as applicable, no later than 90 days from the date the balance is accrued in the form and manner specified by §25.236(f)(2)(A) and (B) for each rate class. Proposed §25.236(f)(2)(B) requires all surcharges to be assessed on a monthly basis and paid by customers no later than 90 days from the date the surcharge balance is accrued except in the circumstances prescribed by §25.236(f)(2)(B)(i) and (ii). Proposed §25.236(f)(2)(B)(i) states that a surcharge must be collected over a time period greater than 90 days, as ordered by the commission, if an interim fuel adjustment would or is anticipated to result in a total bill increase of 10 percent or more for an average customer in any rate class compared to the total bill in the month before implementation. Proposed §25.236(h)(2)(C) authorizes the issuance of a final order later than 75 days from the date a surcharge balance is accrued if the presiding officer determines that the interim fuel adjustment sought would result in a total bill increase of 10 percent or more for an average customer in any rate class

Joint Utilities recommended that the 10% customer bill change that triggers a longer recovery period under proposed §25.236(f)(2)(B)(i) and a hearing under §25.236(h)(2)(C)(i) should be revised to "be benchmarked to total retail billed revenue on a jurisdictional basis rather than individual rate class changes." Joint Utilities explained that categorical application of the 10% bill change to individual customer classes could result in "frequent and unnecessary hearings," particularly for small customer classes that have volatile energy usage such as seasonal businesses. Joint Utilities emphasized that, if customer class agnostic methodology is not implemented, even minor adjustments could trigger a hearing which would be contrary to the intent of HB 2073 and lead to an inconsistent application of the rule. Joint Utilities remarked that the proposed customer-class based threshold would be administratively burdensome for the commission as it would require a hearing "every time a single rate class experiences a 10% change" and therefore result in "a near constant state of hearings."

Commission response

The commission declines to implement the recommended change and maintains a rate class distinction for surcharges and refunds. HB 2073 refers to "a total bill increase" and is clearly focused on mitigating the potential for significant bill increases for customers as a result of interim fuel adjustments by allowing a longer recovery period to avoid excessive total bill increases. The Texas retail jurisdiction does not receive an electric bill, and thus the concept of applying a total bill increase analysis to the entire Texas jurisdiction as a whole is not appropriate. A rate class is a group of customers that pay the same set of rates, and the rates and total bill amounts faced by customers in different rate classes can and do vary significantly, with the typical proportion of a customer's total bill that reflects fuel costs varying widely between rate classes. Interim fuel adjustments could also lead to situations in which the jurisdictional-level impact may be small, but some rate classes may face significantly large surcharges, even while other rate classes face fuel refunds. Ignoring the typical total bill impact for individual rate classes could lead to situations where a minor overall interim fuel adjustment results in a total bill impact for typical customers in certain rate classes far in excess of 10% without triggering the associated requirement of the statute. It therefore logically follows that a total customer bill impact analysis would necessarily be by rate class. While the current language would result in more hearings, PURA §36.203(b)(2) requires that "the total of the utility's eligible electric fuel and purchased power costs, including any under-collected or over-collected amounts to be recovered through an interim fuel adjustment [be] allocated among customer classes based on actual historical calendar month usage." (emphasis added) Interim relief is available for interim fuel adjustments in the event there are issues meeting the 90-day statutory accrual deadline for refunds and surcharges due to a hearing being required under §25.236(h)(2) for a specific customer class. In that event, the customer classes that received an increase that did not trigger a hearing would proceed as normal.

Proposed §25.236(g) and §25.236(g)(1)- Interest calculations for fuel proceedings

Proposed §25.236(g) and §25.236(g)(1) require that interest for fuel reconciliation proceedings and interim fuel adjustments be calculated for each rate class on the cumulative monthly ending under- or over-recovery balance for that rate class using the commission-prescribed annual rate established in accordance with §25.28, relating to Bill Payment and Adjustments. The provision also requires interest to be calculated for each rate class based on the principles established under §25.236(g)(1)(A)-(E).

Joint Utilities recommended that proposed §25.236(g) should be revised to state that interest on balances resulting from deferrals under §36.203(c) should be calculated at the non-ERCOT utility's Weighted Average Cost of Capital (WACC). Joint Utilities commented that in such instances, the non-ERCOT utility is ordered by the commission to "undertake financing of costs to defer them over an extended recovery period." Joint Utilities further commented that WACC is reflective of the utility's commission-determined cost of capital and is therefore the "appropriate interest rate to apply."

Commission response

The commission declines to implement the recommended change. WACC should only be applied to long-term balances. Any interim fuel adjustment balances should be addressed within one year. Moreover, per PURA §36.203(h), fuel reconciliations now occur on a two-year cadence rather than three and may result in an interim fuel adjustment. Therefore, usage of the commission-prescribed interest rate under Project 45319 is appropriate.

Proposed §25.236(g)(2) and §25.236(g)(3)- Interest calculations for fuel proceedings

Proposed §25.236(g)(2) governs the calculation of rate class fuel balances for purposes of refunds and surcharges. Proposed §25.236(g)(3) establishes that intraclass allocations of refunds and surcharges depend on the voltage level at which the customer receives service and indicates the specific methodology of such allocations for retail customers and all other customers.

The commission moves §25.236(g)(2) and (3) to §25.236(f)(2) relating to refunds and surcharges as the provisions are not interest related. Specifically, §25.236(g)(2) is transitioned as new §25.236(f)(2)(C) and §25.236(f)(2)(D). The commission also renumbers §25.236(g) and its sub-provisions accordingly.

Proposed §§25.236(h), 25.236(h)(1), and 25.236(h)(2)- Procedural schedule for interim fuel adjustment

Proposed §25.236(h) establishes the procedural schedule for fuel proceedings. Proposed §25.236(h)(1) establishes the procedural schedule for fuel reconciliation proceedings. Proposed §25.236(h)(2) establishes the procedural schedule for interim fuel adjustments.

Joint Utilities commented that proposed §25.236(h) should be revised to reflect existing §25.237(a)(3)(B) which connects the projection of whether a utility is anticipated to remain in a state of material over-recovery or under-recovery to the determination of whether a refund or surcharge is required. Joint Utilities remarked that the state of a utility's material under-recovery or over-recovery should be retained and applied to interim fuel adjustment proceedings. Joint Utilities explained that it is reasonable for a utility to not propose a refund or surcharge if it projects that future fuel revenue and costs will bring the utility's recovery amount below the materiality threshold without additional action. Joint Utilities alternatively recommended that, if existing §25.237(a)(3)(B) is not retained in proposed §25.236(h), then the materiality threshold of 4.0% should be significantly increased to account for the reduced flexibility in calculating material fuel balances and to minimize unnecessary commission proceedings.

Commission response

The commission agrees with Joint Utilities and implements the recommended change. The commission revises §25.236(h)(2) and adds new §25.236(h)(2)(A) to incorporate the existing language in §25.237(a)(3)(B) with minor changes. The commission also revises §25.236(h)(1) for clarity. Specifically, the commission revises the provision to replace the phase "materially complete petition" with "administratively complete" petition as determined by the presiding officer as the term "materially" is a specific definition unrelated to fuel reconciliations. The commission also makes minor and conforming changes to §25.236(h)(1).

Joint Utilities recommended that the procedural schedule requirements for interim fuel adjustments under proposed §25.236(h)(2) be deleted as they do not conform with the directives of HB 2073. Joint Utilities commented that interim fuel adjustments should be a streamlined process that facilitates the frequent updating of a utility's fuel factor using recent historical costs that should become effective promptly unless protested.

Commission response

Proposed §25.236(h)(2)(B) - Procedural schedule for interim fuel adjustments established by presiding officer

Proposed §25.236(h)(2)(B) requires, upon the filing of a petition for an interim fuel adjustment to surcharge or refund a material fuel under- or over-recovery balance, the presiding officer to set a procedural schedule that will enable the commission to issue a final order in the proceeding no later than 75 days from the date the surcharge or refund balance is accrued.

Joint Utilities recommended proposed §25.236(h)(2)(B) be revised to require a final order for an interim fuel adjustment be issued by the commission within 30 days from the date a material balance has accrued. Joint Utilities stated that the proposed 75-day timeline does not provide a sufficient period for a utility to execute the refund or surcharge within 90 days of the balance being accrued. Joint Utilities explained that a utility needs time between the date the final order is issued to account for the refund or surcharge into its billing systems and an additional full month billing cycle to implement the refund or surcharge.

Commission response

Proposed §25.236(h)(2)(C) and §25.236(h)(2)(C)(i)- Deferral of final order for 10 percent or more bill increase

Proposed §25.236(h)(2)(C) authorizes a final order for an interim fuel adjustment to be issued later than 75 days from the date a surcharge balance is accrued if the criteria under either §25.236(h)(2)(C)(i) or (ii) are met. Proposed §25.236(h)(2)(C)(i) states that if the presiding officer determines that the interim fuel adjustment sought by the utility would result in a total bill increase of 10 percent or more for an average customer in any rate class as described under §25.236(f)(2)(B)(i), or if the utility has a material under-collected balance that is the result of extraordinary electric fuel and purchased power costs as described under §25.236 (f)(2)(B)(ii) of

this section, then the presiding officer may issue the final order later from the date a surcharge balance accrues.

Joint Utilities commented that the procedural schedule timeline in proposed §25.236(h)(2)(C)(ii) directly conflicts with the requirement of PURA §36.203 which requires refunds to be completed within 90 days unless the adjustment would result in a total bill increase greater than or equal to 10%. Similarly, Joint Utilities remarked that a protest of an interim fuel adjustment should not qualify as an exception to the 90-day deadline for a final order to be issued as it is not provided for by PURA §36.203(b). Joint Utilities emphasized that any commission proceedings concerning an interim fuel adjustment protest must be completed in a time period sufficient to permit a surcharge to be collected within 90 days of accrual.

Commission response

The commission disagrees with Joint Utilities. The argument presented does not account for PURA §36.203(b)(3)(B) which states that if an interim fuel adjustment "would result in a total bill increase of 10 percent or more compared to the total bill in the month before implementation, not later than a date ordered by the commission which must be after the 90th day after the date the balance is accrued." This criteria for deferred recovery is identical to the requirement for the commission to hold a hearing under PURA §36.203(g) which states "[t]he commission shall hold a hearing on a protest of an interim fuel adjustment under Subsection (e) if the adjustment would result in a total bill increase of 10 percent or more as described by Subsection (b)(3) or if the adjustment results from extraordinary electric fuel and purchased power costs as described by Subsection (c)." (emphasis added) Moreover, PURA §36.203(c) authorizes deferred recovery (I.E. greater than 90 days from the date a balance accrues) for extraordinary electric fuel and purchased power costs: "Notwithstanding Subsection (b)(3), on a finding that an electric utility has an under-collected balance that is the result of extraordinary electric fuel and purchased power costs that are unlikely to continue, the commission may approve an interim fuel adjustment that would defer recovery to take place over a period longer than 90 days." (emphasis added) Therefore, there is nothing in the cited rule provisions that are inconsistent with HB 2073. In the event of a protest or a hearing occurring where the statutory requirements for deferred recovery are not triggered, the utility may petition for, or the commission may order, interim relief.

AXM and CARD recommended that proposed §25.236(h)(3) be revised to explicitly require interim fuel adjustment proceedings conform to the contested case requirements prescribed by the Texas Administrative Procedure Act.

Commission response

The commission declines to implement the recommended change because it is unnecessary. The Texas APA applies uniformly to all state agency contested cases, rulemakings, and other applicable proceedings unless exempted, in whole or in part, by the relevant statute authorizing or requiring the agency action. Per §2001.001(1) of the Texas APA: "[i]t is the public policy of the state through this chapter to provide minimum standards of uniform practice and procedure for state agencies."

Proposed §25.236(h)(3) - Procedural schedule for protest of interim fuel adjustment

Proposed §25.236(h)(3) establishes that a protest of an interim fuel adjustment may be processed and reviewed in a manner deemed administratively efficient by the presiding officer to ensure that any refunds or surcharges are refunded or collected in accordance with the deadline established under §25.236(f), as applicable.

Joint Utilities recommended that proposed §25.236(h)(3) be omitted and replaced with a general statement that the commission will determine whether a utility accurately calculated the under-collected or over-collected balance and associated interest. Joint Utilities remarked that the provision as proposed is contrary to HB 2073. Joint Utilities provided draft language consistent with its recommendation.

Commission response

The commission partially agrees with Joint Utilities and implements the recommended change as new §25.236(h)(3)(C). The commission further notes that the revisions to the procedural timeline for protests of interim fuel adjustments under §25.236(h)(3), as detailed under the headings for Questions 7a and 7b, are made to reflect the similar provisions for protests of a fuel factor under §25.237(g).

Proposed §25.237 - Fuel Factors

Proposed §25.237(a) - Use and calculation of fuel factors

Proposed §25.237(a) establishes that an electric utility's fuel costs will be recovered from the electric utility's customers by the use of a fuel factor that will be charged for each kilowatt-hour (kWh) consumed by the customer.

Proposed §25.237(a)(1) - General requirements for fuel factors

Proposed §25.237(a)(1) provides that an electric utility may determine its fuel factor in dollars per kilowatt-hour and requires that fuel factors account for system losses and for the difference in line losses corresponding to the voltage at which the electric service is provided. The provision further authorizes an electric utility to have different fuel factors for different times of the year to account for seasonal variations and for a different method of calculation to be used upon a showing of good cause by the electric utility.

CEP recommended proposed §25.237(a)(1) be revised to require fuel factors be established for no less than four-month periods, unless an emergency arises, in the same manner as existing §25.237(a). CEP explained that fuel factors adjusted on a more frequent basis than four months make customer bills more unpredictable and therefore should not be allowed by the rule. Moreover, requiring more frequent fuel factor adjustment proceedings would impose unnecessary costs and litigation burdens. CEP provided draft language consistent with its recommendation.

Commission response

The commission declines to implement the recommended change because it is unnecessary. Under §25.237(a)(2)(A) and (B), a utility is limited to a four-month cadence for adjusting its fuel factor regardless of whether it elects to elect to use the standard methodology under §25.237(a)(1)(A) or a commission-approved, utility specific formula under §25.237(a)(1)(B).

Proposed §25.237(a)(2) and §25.237(a)(2)(A) and (B) - Scheduling for initiation of change to fuel factor

Proposed §25.237(a)(2) establishes the timing requirements a utility must comply with when initiating a change to its fuel factor. Proposed §25.237(a)(2)(A) limits an electric utility that uses the standard methodology under §25.237(a)(1)(A) to petition to adjust its fuel factor as often as once every four months in accordance with the schedule established by §25.237(d). Proposed §25.237(a)(2)(B) limits an electric utility that uses a commission-approved, utility specific formula under §25.237(a)(1)(B) to adjust its fuel factor in accordance with its formula no sooner than four months after the filing of its most recent fuel factor adjustment petition.

Joint Utilities commented that the four-month timeline for fuel factor rate adjustments under proposed §25.237(a)(2)(A) and (B) is too lengthy and should be reduced. Joint Utilities stated the proposed timeline is contrary to the legislative intent of HB 2073 for the commission fuel recovery rules to ensure that a utility collects eligible costs "as contemporaneously as reasonably possible." Joint Utilities commented that fuel factor rate adjustments should be authorized on a more frequent basis than four months to ensure that fuel costs are synchronized with customer billing in a timely fashion. Joint Utilities further commented than any restriction in the proposed rules that retains over-recovery or under-recovery balances rather than eliminating them is contrary to PURA §36.203(b)(1). Joint Utilities provided draft language consistent with its recommendation.

Commission response

The commission disagrees with Joint Utilities and declines to implement the recommended change. HB 2073 neither provides for nor requires the commission to establish specific timelines for fuel factor proceedings, it only requires commission rules to "ensure that…a utility collects as contemporaneously as reasonably possible the electric fuel and purchased power costs that the utility incurs and that the commission determines are eligible" under §36.203(b)(1)." Accordingly, HB 2073 does not necessitate the elimination of the possibility for a utility to retain over-recovery or under-recovery balances. If a utility is not carrying a balance month to month, conceptually that would mean a utility's revenues appropriately match a utility's costs. If such an outcome is achieved by the contrivance of removing the timing restrictions on applying fuel factor rate adjustments, rather than a utility filing timely and accurate information in its fuel factor petition on a routine schedule, that is tantamount to the establishment of a rate authorizing the automatic adjustment and pass-through of changes in fuel costs to customers. Automatic adjustments are expressly prohibited by PURA §36.201 except for the recovery of "reasonable costs of conservation, load management, and purchased power" under §36.204.

Proposed §25.237(a)(3) - Fuel factor adjustments

Proposed §25.237(a)(3) establishes that fuel factors are temporary rates and that a utility's collection of revenues by fuel factors is subject to the adjustments specified under §25.237(a)(3)(A)-(B).

Joint Utilities commented that separate refunds and surcharges, as contemplated under proposed §25.237(a)(3), would be unnecessary if Joint Utilities proposal to "to instead account for refund or surcharge balances in the calculation of the utility's fixed fuel factor" were implemented. Joint Utilities remarked that PURA §36.203 was adopted to both ensure that a utility's fuel factor was timely adjusted and that eligible costs are recovered by the utility as contemporaneously as possible. Joint Utilities accordingly recommended that, to properly implement HB 2073, the balance of a utility's under-recovery or over-recovery should be rolled into the calculation of the fixed fuel factor and be adjusted on a monthly basis.

Commission response

The commission declines to implement the recommended change. HB 2073 does not require the elimination of refund or surcharge proceedings. Instead, HB 2073 establishes interim fuel adjustments as a standalone proceeding with specific requirements and a timeline for the issuance of a refund or collection of a surcharge under §25.236. Accounting for "for refund or surcharge balances in the calculation of the utility's fixed fuel factor" and adjusting the fuel factor on a monthly basis rather than through an interim fuel adjustment is effectively an automatic adjustment and pass through of fuel costs to customers that is prohibited under PURA §36.201.

Proposed §25.237(b) and proposed §25.237(b)(1) and (2) - Petitions to revise fuel factors

Proposed §25.237(b) establishes the specific timing and requirements for filing petitions to revise fuel factors. Proposed §25.237(b)(1) requires a utility that uses the standard methodology under §25.237(a)(1)(A) in accordance with the cadence specified by §25.237(a)(2)(A) to file a petition during the first five working days of the months specified under §25.237(d). The provision further requires the complete fuel factor filing package to include the fuel factor application, a tariff sheet reflecting the proposed fuel factors, and supporting testimony. The provision requires that supporting testimony include, for each month of the period in which the fuel-factor has been in effect and has not been reconciled up to the most recent month for which information is available, specific information concerning costs and revenues by customer class and the differences between such costs and revenues. Proposed §25.237(b)(2) requires a utility that uses a commission-approved, utility specific formula in accordance with the cadence specified by §25.237(a)(1)(B) in accordance with the cadence specified by §25.237(a)(2)(B) to file a petition at least 15 days prior to the first billing cycle in the billing month in which the proposed fuel factors are requested to become effective. The provision further requires the complete fuel factor filing package to include a tariff sheet reflecting the proposed fuel factors, workpapers in Excel format with intact formulas with appropriate proof and verification of natural gas prices that support the calculation of the revised fuel factors, as well as other information such as calculations accounting for differences in line losses corresponding with the voltage of the provided electric service.

Joint Utilities recommended proposed §25.237(b) be revised to require less information to be provided by the utility when filing a fuel factor petition and have less restrictive timelines to better align with the intent of HB 2073. Joint Utilities commented that interim rates (I.E. the fuel factor) are "intended to timely match fuel costs with customer billing to avoid large over- and under-recoveries." Joint Utilities noted that, in contrast, proposed §25.237(b) would continue to require substantial proceedings to adjust fuel factor rates which are burdensome and time-consuming for both stakeholders and the commission to undertake. Joint Utilities stated that proposed §25.237(b) contravenes the legislative intent to align costs with customer bills "as contemporaneously as reasonably possible." Joint Utilities also highlighted that a more comprehensive proceeding for fuel factors is unnecessary because a fuel factor is an interim rate that will ultimately be reconciled and reviewed for prudence by the commission in a later proceeding.

Commission response

The commission declines to implement the recommended change. As stated previously, HB 2073 neither provides for nor requires the commission to establish specific timelines for fuel factor proceedings. The limitations on fuel factor petition timing under §25.237(b)(1) for utilities that use the standard methodology under §25.237(a)(1)(A) and the fuel factor petition timing under §25.237(b)(2) for utilities that use a commission-approved, utility-specific methodology under §25.237(a)(1)(B) are appropriate.

Proposed §§25.237(c), 25.237(c)(1), and 25.237(c)(2)- Fuel factor revision proceeding

Proposed §25.237(c) establishes the burden of proof and the scope of a fuel factor revision proceeding. Proposed §25.237(c)(1) establishes a utility's burden of proof for a utility that uses either the standard methodology for fuel factor calculation under §25.237(a)(1)(A) or uses a commission-approved, utility-specific formula under §25.237(a)(1)(B). Proposed §25.237(c)(2) establishes the scope of a fuel factor revision proceeding for a utility that uses the standard methodology for fuel factor calculation under §25.237(a)(1)(A) and a utility that uses a commission-approved, utility-specific formula under §25.237(a)(1)(B), respectively.

Joint Utilities commented that proposed §25.237(c)(1) and (2) are contrary to PURA §36.203 and do not fulfill the legislative intent of HB 2073. Specifically, Joint Utilities noted that the rule provisions do not sufficiently reflect the limitations of PURA §36.203(f) which explicitly restrict the scope of a fuel factor protest and also prohibit prudence from being reviewed in a fuel factor proceeding or interim fuel adjustment. Joint Utilities remarked that proposed §25.237(c)(1) and (2) inadequately distinguish between the more limited "protest" articulated under HB 2073 and the "broader procedural rights associated with contested cases."

Commission response

The commission disagrees with Joint Utilities and declines to implement the recommended change. The scope of a fuel factor protest established by PURA §36.203(f) is implemented under §25.237(g)(1)(B). PURA §36.203(f) states "The sole issue that may be considered on a protest of a fuel factor… is whether the factor reasonably reflects costs the electric utility will incur so that the utility will not substantially under-collect or over-collect the utility's reasonably stated fuel and purchased power costs on an ongoing basis. Subparagraph 25.237(g)(1)(B) implements the statute almost verbatim: "[t]he commission will review a protest of a fuel factor solely to determine whether the utility's fuel factor reasonably reflects costs the utility will incur such that that the utility will not substantially under-collect or over-collect the utility's reasonably stated fuel and purchased power costs on an ongoing basis." Moreover, §25.237(g)(1)(C) codifies the prohibition on review of prudence of costs in a protest of a fuel factor established by PURA §36.203(e).

Proposed §§25.237(d), 25.237(d)(1), and 25.237(d)(2)- Schedule for filing petitions to revise fuel factors

Proposed §25.237(d) authorizes a petition to revise fuel factors or to initiate or revise a fuel factor formula to be filed with any general rate proceeding. Proposed §25.237(d)(1) establishes a four-month schedule for each specific non-ERCOT utility that utilizes the standard methodology for fuel factor calculations under §25.237(a)(1)(A) to file a fuel factor revision petition. The provision also authorizes alternative timing for emergency fuel factor petitions under §25.237(f). Proposed §25.237(d)(2) authorizes a utility that uses a commission-approved, utility-specific formula under §25.237(a)(1)(B) to file a fuel factor petition in any month except December.

Joint Utilities recommended proposed §25.237(d) be deleted as it is contrary to the legislative intent of HB 2073. Specifically, Joint Utilities noted that the provision "constitutes a restriction on efforts to collect costs contemporaneously" and therefore is contrary to the revised statute.

Commission response

The commission disagrees with Joint Utilities and declines to implement the recommended change. Deleting the schedule under §25.237(d)(1) for utilities that elect to use the standard methodology for fuel factor calculations under §25.237(a)(1)(A) could risk several utilities filing a fuel factor revision petition or fuel factor formula revision petition close together which would be extremely burdensome for commission staff. The general authorization under §25.237(d)(2) for a utility that uses a utility-specific formula under §25.237(a)(1)(B) is already sufficiently flexible as it only prohibits the filing of petitions in December. This scheduling difference is due to the significantly lengthier amount of time associated with reviewing fuel factor revision or fuel factor formula revision petitions for utilities that elect to use the standard methodology under §25.237(a)(1)(A) rather than a commission-approved, utility specific formula under §25.237(a)(1)(B). Moreover, HB 2073 does not impose a requirement for costs to be collected contemporaneously. PURA §36.203(b)(1) requires commission rules to "ensure that…a utility collects as contemporaneously as reasonably possible the electric fuel and purchased power costs that the utility incurs and that the commission determines are eligible." This general requirement is primarily effectuated by the separation of refunds and surcharges from fuel factor proceedings into a separate interim fuel adjustment proceeding under §25.236 where material over-collections or under-collections will be refunded or recovered, respectively. This paradigm is reflected in §25.237(a)(3)(B) which establishes that "[t]o the extent that there are variations between the fuel costs incurred and the revenues collected, it may be necessary to refund material over-collections or surcharge material under-collections through an interim fuel adjustment under §25.236 of this title in the time and manner required by that section." Importantly, the following sentence states "[r]efunds or surcharges may be made without changing an electric utility's fuel factor." More contemporaneous recovery can be achieved by a utility filing timely and accurate information with the commission regarding its fuel factor or fuel factor formula revision and electing to use a commission-approved, utility specific methodology under §25.237(a)(1)(B).

Proposed §25.237(e) - Procedural schedules

Proposed §25.237(e) provides for the procedural schedules for revising fuel factors if a utility selects the standard fuel factor methodology under §25.237(a)(1)(A) or otherwise employs a utility-specific fuel factor methodology under §25.237(a)(1)(B).

Joint Utilities generally recommended the deadlines in proposed §25.237(e) be reduced to the furthest extent possible to ensure the fuel factor is adjusted faster. Joint Utilities emphasized that "more routine and frequent fuel factor updates would better align customer bills with actual costs" and therefore be reflective of the legislative intent for fuel cost recovery to be contemporaneous. Joint Utilities also recommended preserving language, such as under existing §25.237(e)(2)(B), which allows fuel factors to be approved if no hearing is requested within 30 days of the date the petition is filed. Joint Utilities explained that such language is a current example under existing rules of where an "interim rate change may take effect without undue procedural burden." Joint Utilities maintained that fuel factors occurring on a more routine and frequent basis would help better align customer bills with actual costs and "fulfill HB 2073's contemporaneity requirement."

Commission response

The commission declines to reduce the deadlines specified under §25.237(e). More contemporaneous recovery is better effectuated through explicitly authorizing interim relief for interim fuel adjustments in a manner appropriate for those proceedings as opposed to reducing the deadlines for fuel factor proceedings. As stated previously, the commission adds new §25.236(f)(4) which authorizes the presiding officer to order interim relief for interim fuel adjustments without a hearing for good cause, either on the presiding officer's own motion, in response to a petition filed by a party, or in response to a written protest filed by an eligible person. New §25.236(f)(4) also provides additional flexibility for the presiding officer to determine whether good cause exists to grant interim relief. As noted previously, HB 2073 does not impose a requirement for costs to be collected contemporaneously; it only requires commission rules to "ensure that…a utility collects as contemporaneously as reasonably possible the electric fuel and purchased power costs that the utility incurs and that the commission determines are eligible" under PURA §36.203(b)(1). Interim relief ensures that, for interim fuel adjustments, material balances are collected or refunded no later than the 90th day from the date the balance accrues in the event of a hearing. In the event interim relief is necessary for a fuel factor proceeding, §22.125, relating to Interim Relief will govern.

Proposed §25.237(g) and §25.237(g)(5) - Protest of fuel factor

Proposed §25.237(g) specifies the form, manner, and scope of a protest of a utility's fuel factor. Proposed §25.237(g)(5) authorizes the presiding officer to hold a hearing on a protest of a fuel factor at his or her discretion and to consider any evidence that is appropriate and in the public interest.

OPUC recommended proposed §25.237(g)(5) be revised to omit language that would enable the presiding officer to use discretion when holding a hearing on a fuel factor protest. OPUC noted that holding a hearing in these instances "should not be left solely to the discretion of the presiding officer."

Commission response

The commission declines to implement the recommended change because it is contrary to statute. PURA §36.203(d) authorizes total commission discretion in requiring a hearing for fuel factors, including fuel factor protests. Specifically, PURA §36.203(d) states "[t]he commission is not required to hold a hearing on the adjustment of an electric utility's fuel factor under this section. If the commission holds a hearing, the commission may consider at the hearing any evidence that is appropriate and in the public interest." (emphasis added). There is no equivalent provision requiring a hearing to be held for a protest on a fuel factor in PURA §36.203 as there is for an interim fuel adjustment under PURA §36.203(g). The commission also merges the prohibition on prudence of costs into the protest requirements under §25.237(g)(1) and eliminates proposed §25.237(g)(2) and (3) as redundant. The commission renumbers §25.237(g)(1)-(5) accordingly.

Fuel Reconciliation Filing Package

The proposed edits to the fuel reconciliation filing package require copies of each monthly fuel cost report that the utility filed in the past 24-month period covered by the fuel reconciliation, including any corrected fuel cost reports.

Joint Utilities recommended that the Fuel Reconciliation Filing Package (FRFP) not require the inclusion of copies of the previous 24-months of a utility's fuel reports because it is duplicative and unnecessary. Joint Utilities explained that these reports have already been filed with the commission and are available on the commission Interchange in projects specifically designated for this purpose and therefore should not be required to be submitted again with the FRFP.

Commission Response

The commission declines to implement the recommended changes. Requiring the prior 24-months of fuel costs reports to be included with the FRFP facilities efficient work by the commission. In some instances, utilities may have corrected fuel cost reports that they have not re-filed since the original fuel report was filed. Moreover, requiring the utility to file all of the fuel cost reports at once for purposes of a fuel reconciliation places the burden on the utility, rather than staff to compile and organize the reports. This requirement is no different than what is required in interim rate proceedings where a utility must provide their baseline rate schedules and the associated commission orders approving those rate schedules. The commission adds language to §25.236(d)(7) to reflect the requirement in the FRFP to file monthly fuel cost reports, including the requirement to file corrected reports.

The amended rules are adopted under the following provisions of PURA: §14.001, which provides the commission the general power to regulate and supervise the business of each public utility within its jurisdiction and to do anything specifically designated or implied by PURA that is necessary and convenient to the exercise of that power and jurisdiction; §14.002, which provides the commission with the authority to make adopt and enforce rules reasonably required in the exercise of its powers and jurisdiction; §36.203 which requires the commission to, by rule, implement procedures that provide for the timely adjustment of an electric utility's fuel factor and ensure that a utility collects as contemporaneously as reasonably possible the utility's eligible electric fuel and purchased power costs, that those costs are allocated among customer classes based on actual historical calendar month usage, and any material balances are collected from or refunded to customers.

Cross reference to statutes: Public Utility Regulatory Act §§14.001, 14.002, 36.203.

§25.235. Fuel Costs.

(a) Purpose. The commission will set an electric utility's rates at a level that will permit the electric utility a reasonable opportunity to earn a reasonable return on its invested capital and to recover its reasonable and necessary expenses, including the cost of fuel and purchased power. The commission recognizes that it is in the interests of both electric utilities and their ratepayers to adjust charges in a timely manner to account for changes in certain fuel and purchased-power costs. In accordance with Public Utility Regulatory Act (PURA) §36.203 this section establishes a procedure for setting and revising fuel factors and a procedure for regularly reviewing the reasonableness of the fuel expenses recovered through fuel factors.

(b) Notice of fuel proceedings. In addition to the notice required by the Administrative Procedure Act (APA) to be given by the commission, the electric utility is required to give notice of a fuel proceeding at the time the petition is filed. The term "rate class" as used in this subsection means all customers taking service under the same tariffed rate or schedule, or a group of seasonal agricultural customers as identified by the electric utility.

(1) Method of notice. Notice of fuel proceedings must be posted to the utility's website and provided to OPUC by electronic mail. Notice must also be provided by the electric utility as follows, as applicable:

(A) Notice in all proceedings involving refunds or surcharges (an interim fuel adjustment) under §25.236 of this title (relating to Recovery of Fuel Costs), or a proposal to change the fuel factor under §25.237 of this title (relating to Fuel Factor), must be by individual notice to each customer and by individual notice to all parties in the electric utility's most recent fuel reconciliation proceeding.

(B) Notice in all fuel reconciliation proceedings must be by:

(i) publication once each week for two consecutive weeks in a newspaper having general circulation in each county of the service area of the electric utility; and

(ii) by individual notice to each customer and to all parties in the electric utility's most recent fuel reconciliation proceeding.

(2) Contents of notice.

(A) All notices required by this section must provide the following information:

(i) the date the petition was filed;

(ii) a general description of the customers, customer classes (for fuel factors) or rate classes (for interim fuel adjustments), and territories affected by the petition;

(iii) the relief requested;

(iv) a statement substantially similar to the following: "Persons with questions or who want more information on this petition may contact (utility name) at (utility address) or call (utility toll-free telephone number) during normal business hours. A complete copy of this petition is available for inspection at the address listed above or at the following website [direct link to notice on the utility's website]"; and

(v) a statement substantially similar to the following: "Persons who wish to formally participate in this proceeding, or who wish to express their comments concerning this petition should contact the Public Utility Commission of Texas, Consumer Protection Division, P.O. Box 13326, Austin, Texas 78711-3326, or call (512) 936-7120 or toll-free at (888) 782-8477. Hearing and speech-impaired individuals may contact the commission through Relay Texas (toll-free) at 1-800-735-2989."

(B) Notices to revise fuel factors must also state the proposed fuel factors by type of voltage and the period for which the proposed fuel factors are expected to be in effect.

(i) a statement substantially similar to the following: "these changes will be subject to final review by the commission in the electric utility's next fuel reconciliation proceeding," unless the change is a result of a reconciliation proceeding;

(ii) an explanation of the notice recipient's right to file a protest in a fuel factor or interim fuel adjustment proceeding; and

(iii) for interim fuel adjustments under §25.236 of this title:

(I) a statement substantially similar to the following detailing the appropriate scope of the protest: "A protest must identify whether the person submitting the protest is a customer of the utility. Except for prudence of costs, a protest may address any aspects of the interim fuel adjustment petition, including the adequacy of notice or whether the refund or surcharge is appropriate. As required by Public Utility Regulatory Act §36.203, in response to a protest of an interim fuel adjustment, if the commission finds that the electric utility is in a state of material under-collection or over-collection of the utility's reasonably stated eligible fuel and purchased power costs and is projected to remain in that state on an ongoing basis, the commission will order the utility to establish or modify an interim fuel adjustment to address the under-collection or over-collection."

(II) a statement substantially similar to the following detailing the recipient's right to request a hearing: "If a hearing is sought, a protest of an interim fuel adjustment must include a request for a hearing. If a hearing is not requested in the protest, it will be presumed that a hearing is not sought. Requesting a hearing does not guarantee that a hearing will be held. A hearing is only required to be held if the commission determines that an interim fuel adjustment (1) would or is anticipated to result in a total bill increase of 10 percent or more for an average customer in any rate class compared to the total bill in the month before implementation; or (2) a utility has a material under-collected balance that is the result of extraordinary electric fuel and purchased power costs that are unlikely to continue."

(iv) for fuel factor revisions under §25.237 of this title

(I) a statement substantially similar to the following detailing the appropriate scope of the protest: "A protest must identify whether the person submitting the protest is a customer of the utility. As required by Public Utility Regulatory Act §36.203, the scope of a protest on a fuel factor is whether the factor reasonably reflects costs the electric utility will incur so that the utility will not substantially under-collect or over-collect the utility's reasonably stated fuel and purchased power costs on an ongoing basis. The commission may adjust the utility's fuel factor based on its determination on that issue. A protest of a fuel factor is prohibited from raising the prudence of costs as an issue."

(II) a statement substantially similar to the following detailing the recipient's right to request a hearing: "If a hearing is sought, a protest of a fuel factor must include a request for a hearing. If a hearing is not requested in the protest, it will be presumed that a hearing is not sought. Requesting a hearing does not guarantee that a hearing will be held. The commission has total discretion to hold or not hold a hearing in a fuel factor proceeding."

(D) Notices for fuel reconciliation proceedings must also state the period for which final reconciliation is sought.

(E) Notices for an interim fuel adjustment must indicate, for each rate class:

(i) whether the adjustment is for a refund or surcharge;

(ii) the amount of the proposed refund or surcharge;

(iii) the period for which the proposed refund or surcharge is applicable (i.e., January to March);

(iv) if the adjustment is for a surcharge, whether the surcharge would or is anticipated to result in a total bill increase of 10 percent or more for an average customer in any rate class compared to the total bill in the month before implementation; and

(v) the time period and manner in which the surcharge or refund will be implemented.

(c) Reports; confidentiality of information. Matters related to submitting reports and confidential information will be handled as follows:

(1) The commission will monitor each electric utility's actual and projected fuel-related costs and revenues on a monthly basis. Each electric utility must maintain and provide to the commission, in a format specified by the commission, monthly reports containing all information required to monitor monthly fuel-related costs and revenues, including generation mix, fuel consumption, fuel costs, purchased power quantities and costs, and system and off-system sales revenues.

(2) Contracts for the purchase of fuel, fuel storage, fuel transportation, fuel processing, or power are discoverable in fuel proceedings, subject to appropriate confidentiality agreements or protective orders.

(3) The electric utility must prepare a confidentiality disclosure agreement to be included as part of the fuel reconciliation petition. The format for the agreement must be the same as that contained in the commission-approved rate filing package. In addition to the agreement itself, Attachment 1 of the agreement must present a complete listing of the information required to be filed which the electric utility alleges is confidential. Upon request and execution of the confidentiality agreement, the electric utility must provide any information which it alleges is confidential. If the electric utility fails to file a confidentiality agreement, the deadline for a commission final order in the case is tolled until a protective order is entered or a confidentiality agreement is filed. Use of the confidentiality disclosure agreement does not constitute a finding that any information is proprietary or confidential under law, or alter the burden of proof on that issue. The form of agreement contained in the commission approved rate filing package does not bind the examiner or the commission to accept the language of the agreement in the consideration of any subsequent protective order that may be entered.

(4) A party that cannot view a confidential document without receiving advantage as a competitor or bidder may hire outside counsel and consultants to view the document subject to a protective order.

§25.236. Recovery of Fuel Costs.

(a) Eligible fuel expenses. Eligible fuel expenses include expenses properly recorded in the Federal Energy Regulatory Commission Uniform System of Accounts, numbers 501, 502, 503, 509, 518, 536, 547, 555, and 559.3 as modified in this subsection, as of April 1, 2025, and the items specified in paragraph (8) of this subsection. Any later amendments to the System of Accounts are not incorporated into this subsection. Subject to the commission finding special circumstances under paragraph (7) of this subsection, eligible fuel expenses are limited to:

(1) For any account, the electric utility may not recover, as part of eligible fuel expense, costs incurred after fuel is delivered to the generating plant site, for example, but not limited to, operation and maintenance expenses at generating plants, costs of maintaining and storing inventories of fuel at the generating plant site, unloading and fuel handling costs at the generating plant, and expenses associated with the disposal of fuel combustion residuals. Further, the electric utility may not recover maintenance expenses and taxes on rail cars owned or leased by the electric utility, regardless of whether the expenses and taxes are incurred or charged before or after the fuel is delivered to the generating plant site. The electric utility may not recover an equity return or profit for an affiliate of the electric utility, regardless of whether the affiliate incurs or charges the equity return or profit before or after the fuel is delivered to the generating plant site. In addition, all affiliate payments must satisfy the Public Utility Regulatory Act (PURA) §36.058.

(2) For Accounts 501 and 547, the only eligible fuel expenses are the delivered cost of fuel to the generating plant site excluding fuel brokerage fees. For Account 501, revenues associated with the disposal of fuel combustion residuals will also be excluded.

(3) For Account 502, the only eligible fuel expenses are environmental consumables that are: properly recorded in the Account as chemicals; required to comply with applicable state or federal emission reduction statutes, orders, and regulations; and whose use is directly proportional to the fuel consumed to generate electricity.

(4) For Account 509, the only eligible fuel expenses are allowances expensed concurrent with the monthly emissions of sulfur dioxide and nitrogen oxides.

(5) For Accounts 518 and 536, the only eligible fuel expenses are the expenses properly recorded in the Account excluding brokerage fees. For Account 503, the only eligible fuel expenses are the expenses properly recorded in the Account, excluding brokerage fees, return, non-fuel operation and maintenance expenses, depreciation costs and taxes.

(6) For Account 555, the electric utility may not recover demand or capacity costs.

(7) Upon demonstration that such treatment is justified by special circumstances, an electric utility may recover as eligible fuel expenses fuel or fuel related expenses otherwise excluded in paragraphs (1) - (6) of this subsection. In determining whether special circumstances exist, the commission will consider, in addition to other factors developed in the record of the reconciliation proceeding, whether the fuel expense or transaction giving rise to the ineligible fuel expense resulted in, or is reasonably expected to result in, increased reliability of supply or lower fuel expenses than would otherwise be the case, and that such benefits received or expected to be received by ratepayers exceed the costs that ratepayers otherwise would have paid or otherwise would reasonably expect to pay.

(8) Eligible fuel expenses are prohibited from being offset by revenues by affiliated companies for the purpose of equalizing or balancing the financial responsibility of differing levels of investment and operation costs associated with transmission assets. In addition to the expenses designated in paragraphs (1) - (7) of this subsection, unless otherwise specified by the commission, eligible fuel expenses must be offset by:

(A) revenues from steam sales included in Accounts 504 and 456 to the extent expenses incurred to produce that steam are included in Account 503;

(B) revenues from off-system sales in their entirety, except as permitted in paragraph (9) of this subsection; and

(9) Shared margins from off-system sales. An electric utility may retain 10 percent of the margins from an off-system energy sale that is made between the utility and a third-party buyer if the commission finds that the transaction is in the interests of the electric utility's retail customers and that margin sharing is in the public interest.

(b) Definitions. The following terms, when used in this section, have the following meanings unless the context indicates otherwise.

(1) Materially or material -- the cumulative amount of over- or under-recovery, including interest, is greater than or equal to 4.0 percent of the annual actual fuel cost figures on a rolling 12-month basis, as reflected in the utility's monthly fuel cost reports as filed by the utility with the commission.

(2) Rate class -- all customers taking service under the same tariffed rate or schedule, or a group of seasonal agricultural customers as identified by the electric utility.

(1) Each electric utility must file a petition for reconciliations on a periodic basis such that the petition:

(A) contains at least one year and no more than two years of reconcilable data; and

(B) is filed no later than 180 days after the end of the period to be reconciled.

(2) To the extent a reconciliation results in a material change to the electric utility's under-collected or over-collected fuel balance, that change may be incorporated into an interim fuel adjustment under subsection (f) of this section as directed by the commission through the issuance of a written order.

(d) Fuel reconciliation petitions. In addition to the commission-prescribed reconciliation application, a fuel reconciliation petition filed by an electric utility must be accompanied by a summary and supporting evidence that includes the following information:

(1) a summary of significant, atypical events that occurred during the reconciliation period that affected the economic dispatch of the electric utility's generating units, including but not limited to transmission line constraints, fuel use or deliverability constraints, unit operational constraints, and system reliability constraints;

(2) a general description of typical constraints that limit the economic dispatch of the electric utility's generating units, including but not limited to transmission line constraints, fuel use or deliverability constraints, unit operational constraints, and system reliability constraints;

(3) the reasonableness and necessity of the electric utility's eligible fuel expenses and its mix of fuel used during the reconciliation period;

(4) a summary table that lists all the fuel cost elements which are covered in the electric utility's fuel cost recovery request, the dollars associated with each item, and where to find the item in the prefiled testimony;

(5) tables and graphs which show generation (MWh), capacity factor, fuel cost (cents per kWh and cents per MMBtu), variable cost and heat rate by plant and fuel type, on a monthly basis; and

(6) a summary and narrative of the next-day and intra-day surveys of the electricity markets and a comparison of those surveys to the electric utility's marginal generating costs.

(7) copies of each monthly fuel cost report required under §25.235(c)(1) of this title (relating to Fuel Costs) that the utility filed in the past 24-month period covered by the fuel reconciliation organized in chronological order.

(A) A utility is required to file corrected reports with its fuel reconciliation petition if information in previously filed reports becomes erroneous based on actual verified data.

(B) If the utility submits corrected fuel cost reports as part of its fuel reconciliation, the utility must also file the same corrected fuel cost reports in the relevant commission project assigned for such reports.

(e) Fuel reconciliation proceedings. The burden of proof and scope of a fuel reconciliation proceeding are as follows:

(1) In a proceeding to reconcile fuel factor revenues and expenses, an electric utility has the burden of proving that:

(A) its eligible fuel expenses during the reconciliation period were reasonable and necessary expenses incurred to provide reliable electric service to retail customers and the materiality of any over- or under-recovery;

(B) if its eligible fuel expenses for the reconciliation period included an item or class of items supplied by an affiliate of the electric utility, the prices charged by the supplying affiliate to the electric utility were reasonable and necessary and no higher than the prices charged by the supplying affiliate to its other affiliates or divisions or to unaffiliated persons or corporations for the same item or class of items; and

(C) it has properly accounted for the amount of fuel-related revenues collected in accordance with the fuel factor during the reconciliation period.

(2) The scope of a fuel reconciliation proceeding includes any issue related to determining the reasonableness and necessity of the electric utility's fuel expenses during the reconciliation period and reviewing whether the electric utility has materially over- or under-recovered its reasonable fuel expenses through interim fuel adjustments under subsection (f) of this section.

(f) Interim fuel adjustments. An electric utility must apply for an interim fuel adjustment in the time frame specified by subsection (h)(2)(B) of this section if the utility is in a state of material under-collection or over-collection of the utility's reasonably stated eligible fuel and purchased power costs.

(1) Adjustment factor. If the commission determines in the interim fuel adjustment proceeding that the utility is in a state of material under-collection or over-collection, except as provided for under subsection (g)(3) of this section, each rate class must be credited or assessed a refund or surcharge, as applicable, using an adjustment factor. The adjustment factor will be applied to the kilowatt-hour usage of each rate class until the total amount has been collected or refunded.

(A) The adjustment factor will be determined by dividing the amount of refund or surcharge properly allocated to each rate class by projected kilowatt-hour usage for the applicable rate class during the period in which the refund or surcharge will be made.

(B) Notwithstanding subparagraph (A) of this paragraph, each retail customer who receives service at transmission voltage levels, each wholesale customer, and any groups of seasonal agricultural customers as identified by the electric utility must be given a one-time credit or assessed a surcharge made on a monthly basis over a period not to exceed 12 months through a bill charge, based on their individual actual historical usage recorded during each month of the period in which the cumulative under- or over-recovery occurred, adjusted for line losses if necessary.

(2) Refunds and surcharges. Refunds and surcharges must be issued and recovered by the electric utility, as applicable, in the following manner for each rate class:

(A) All refunds must be made through a bill credit and be issued no later than 90 days after the refund balance is accrued. A refund may be made by check to a municipally-owned utility if requested by that utility.

(B) All surcharges must be assessed on a monthly basis and paid by customers no later than 90 days from the date the surcharge balance is accrued except in the following circumstances:

(i) If the commission determines that an interim fuel adjustment would or is anticipated to result in a total bill increase of 10 percent or more for an average customer in any rate class compared to the total bill in the month before implementation, the surcharge must be collected over a time period ending not later than a date ordered by the commission. Such a time period must be at least 90 days after the date the balance is accrued.

(ii) If the commission determines that a utility has a material under-collected balance that is the result of extraordinary electric fuel and purchased power costs that are unlikely to continue, the commission may approve a surcharge in an interim fuel adjustment proceeding that would defer recovery to occur over a period exceeding 90 days from the date the surcharge balance is accrued.

(C) Unless otherwise ordered by the commission in an electric utility's fuel reconciliation proceeding, in calculating rate class fuel balances for purposes of a refund or surcharge, the total of the utility's eligible electric fuel and purchased power costs for a calendar month must be allocated among jurisdictions based on the actual historical calendar month kilowatt-hour usage, adjusted for line losses using the same commission-approved loss factors that were used in the electric utility's applicable fixed or interim fuel factor. The resulting monthly Texas retail jurisdiction costs must be allocated among rate classes based on the actual historical calendar month kilowatt-hour usage, adjusted for line losses using the same commission-approved loss factors that were used in the electric utility's applicable fixed or interim fuel factor.

(D) Intraclass allocations of refunds and surcharges depend on the voltage level at which the customer receives service from the electric utility. Retail customers who receive service at transmission voltage levels, all wholesale customers, and any groups of seasonal agricultural customers as identified by the electric utility must be given refunds or assessed surcharges based on their individual actual historical kilowatt-hour usage recorded during each month of the period in which the cumulative under- or over-recovery occurred, adjusted for line losses where necessary. All other customers must be given refunds or assessed surcharges based on the historical kilowatt-hour usage of their rate class.

(3) Prudence review prohibited. The prudence of costs will not be considered in an interim fuel adjustment. The prudence of costs may only be reviewed in a fuel reconciliation proceeding under subsection (e) of this section or another appropriate proceeding.

(4) Interim relief.

(A) An interim fuel adjustment is eligible for interim relief under §22.125 of this title (relating to Interim Relief) to ensure refunds and surcharges are issued or recovered in accordance with the timelines specified under paragraphs (2)(A) and (B) of this section.

(B) A party to an interim fuel adjustment proceeding may file a motion for interim relief in accordance with the procedural schedule established by the presiding officer.

(C) Notwithstanding the requirements of §22.125 of this title, the presiding officer may order interim relief without a hearing on a finding of good cause:

(i) on their own motion;

(ii) in response to a motion filed under subparagraph (B) of this paragraph; or

(iii) in response to a written protest filed by an eligible person in accordance with subsection (h)(3)(B) of this section.

(D) In determining whether good cause exists for interim relief under this subparagraph, the presiding officer may consider one or more of the factors prescribed by §22.125 of this title, but the primary consideration is whether the interim relief is consistent with the substantive requirements of this section and will ensure compliance with applicable deadlines. A showing of good cause may be supported by affidavit and without testimony or hearing.

(g) Interest calculations for fuel proceedings. For a fuel proceeding under subsection (e) or (f) of this section, interest must be calculated for each rate class on the cumulative monthly ending under- or over-recovery balance for that rate class at the rate established annually by the commission for overbilling and underbilling in §25.28 of this title (relating to Bill Payment and Adjustments). Interest must be calculated for each rate class based on principles set out in paragraphs (1) - (5) of this subsection:

(1) Interest must be compounded by using an effective monthly interest factor.

(2) The effective monthly interest factor must be determined by using the algebraic calculation x = (1 + i)^(1/12) - 1; where i = commission-approved annual interest rate, and x = effective monthly interest factor.

(3) Interest accrues on a monthly basis. The monthly interest amount is calculated by applying the effective monthly interest factor to the previous month's ending cumulative under- or over-recovery balance.

(4) The monthly interest amount must be added to the cumulative principal and interest under- or over-recovery balance.

(5) In calculating the amounts to be refunded or surcharged, interest must be calculated through the end of the month of the refund or surcharge.

(h) Procedural schedule.

(1) Procedural schedule for fuel reconciliation proceedings. Upon the filing of a petition to reconcile fuel expenses, the presiding officer will set a procedural schedule that will enable the commission to issue a final order in the proceeding within one year after the presiding officer determines that the petition is administratively complete. However, if two or more electric utilities file petitions to reconcile fuel expenses within 45 days of each other, the presiding officers will schedule the cases in a manner to allow the commission to accommodate the workload of the cases irrespective of whether the procedural schedule enables the commission to issue a final order in each of the cases within one year after the presiding officer determines that the petition is administratively complete

(2) Procedural schedule for interim fuel adjustments. To the extent that there are variations between the fuel costs incurred and the revenues collected, it may be necessary to refund over-collections or surcharge under-collections.

(A) Refunds or surcharges may be made without changing an electric utility's fuel factor.

(i) an electric utility may file a petition for an interim fuel adjustment to issue a surcharge any time it has materially under-collected its fuel costs and projects that it will continue to be in a state of material under-collection.

(ii) an electric utility must file a petition for an interim fuel adjustment to make a refund any time it has materially over-collected its fuel costs and projects that it will continue to be in a state of material over-collection.

(B) A utility seeking an interim fuel adjustment to surcharge or refund a fuel under- or over-recovery balance must file its interim fuel adjustment petition and issue notice within five working days from the date the material fuel under- or over-recovery balance accrues, which is either:

(i) 75 days from the last day of the month for which the utility seeks recovery (month end close); or

(ii) when the utility has verified, actual data for that month.

(C) Each month for which a utility seeks recovery must correspond with the utility's monthly fuel cost and use report filed with the commission in accordance §25.82 of this title (relating to Fuel Cost and Use Information)..

(D) Upon a utility filing its petition, the presiding officer will set a procedural schedule that will enable the utility to issue a refund or collect a surcharge within the applicable time period specified in subsection (f)(2)(A) or (B) of this section;

(E) A hearing is required for an interim fuel adjustment if the presiding officer determines that :

(i) the interim fuel adjustment sought would result in a total bill increase of 10 percent or more for an average customer in any rate class as described under subsection (f)(2)(B)(i) of this section; or

(ii) the utility has a materially under-collected balance that is the result of extraordinary electric fuel and purchased power costs as described under subsection (f)(2)(B)(ii) of this section.

(3) Protest of interim fuel adjustment.

(A) Only a customer of the utility, a municipality with original jurisdiction over the utility, or OPUC is eligible to protest an interim fuel adjustment under this paragraph.

(i) A protest of an interim fuel adjustment must identify the eligibility of the person to submit the protest.

(ii) The commission will review a protest of an interim fuel adjustment to determine whether the utility is in a state of material under-collection or over-collection of the utility's reasonably stated eligible fuel and purchased power costs and is projected to remain in that state on an ongoing basis.

(iii) The commission will not consider issues related to the prudence of costs raised in a protest.

(iv) If a hearing is sought, a protest must include a request for a hearing and the basis for the request.

(B) In response to a protest filed under this paragraph, the presiding officer may order interim relief, as deemed appropriate.

(C) If it is determined that the utility is in a state of material under-collection or over-collection and is projected to remain as such on an ongoing basis, the utility will be ordered to establish or modify an interim fuel adjustment to address the under-collection or over-collection.

(D) Unless a hearing is otherwise required under this section, the determination to hold a hearing on a protest is at the presiding officer's discretion. In a hearing on a protest, any evidence found by the presiding officer to be appropriate and in the public interest may be considered.

(E) A protest of an interim fuel adjustment may be processed and reviewed in a manner deemed administratively efficient by the presiding officer.

(F) Discovery in an interim fuel adjustment proceeding will be conducted in accordance with the commission's rules, except as modified by the presiding officer.

§25.237. Fuel Factors.

(a) Use and calculation of fuel factors. An electric utility's fuel costs will be recovered from the electric utility's customers by the use of a fuel factor that will be charged for each kilowatt-hour (kWh) consumed by the customer.

(1) An electric utility may determine its fuel factor in dollars per kilowatt-hour in accordance with either subparagraph (A) or (B) of this paragraph. Fuel factors must account for system losses and for the difference in line losses corresponding to the voltage at which the electric service is provided. An electric utility may have different fuel factors for different times of the year to account for seasonal variations. A different method of calculation may be allowed upon a showing of good cause by the electric utility.

(A) Fuel factors may be determined by dividing the electric utility's projected net eligible fuel expenses, as defined in §25.236(a) of this title (relating to Recovery of Fuel Costs), by the corresponding projected kilowatt-hour sales for the period in which the fuel factors are expected to be in effect.

(B) Fuel factors may be determined using a commission-approved, utility-specific fuel factor formula. Fuel factor formulas may be approved or revised only in a general rate change proceeding or a proceeding to consider an application to establish a fuel factor formula with notice and an opportunity for a hearing.

(2) An electric utility may initiate a change to its fuel factor as follows:

(A) In accordance with subsection (a)(1)(A) of this section, an electric utility may petition to adjust its fuel factor as often as once every four months according to the schedule set out in subsection (d) of this section.

(B) In accordance with subsection (a)(1)(B) of this section, an electric utility may petition to adjust its fuel factor in accordance with its approved fuel factor formula no sooner than four months after the filing of its most recent fuel factor adjustment petition.

(C) Notwithstanding subsection (a)(2)(A) of this section, an electric utility may petition to change its fuel factor at times other than provided in the schedule if an emergency exists as described in subsection (f) of this section.

(D) An electric utility's fuel factor may be changed in any general rate proceeding.

(3) Fuel factors are temporary rates, and the electric utility's collection of revenues by fuel factors is subject to the following adjustments:

(A) The reasonableness of the fuel costs that an electric utility has incurred will be periodically reviewed in a reconciliation proceeding, as described in §25.236 of this title, and any disallowed costs resulting from a reconciliation proceeding will be reflected in the calculation of the utility's recoverable fuel and over- or under- collections.

(B) To the extent that there are variations between the fuel costs incurred and the revenues collected, it may be necessary to refund material over-collections or surcharge material under-collections through an interim fuel adjustment under §25.236 of this title in the time and manner required by that section. Refunds or surcharges may be made without changing an electric utility's fuel factor.

(C) The terms "materially" or "material," as used in this section, mean that the cumulative amount of over- or under-recovery, including interest, is greater than or equal to 4.0 percent of the annual actual fuel cost figures on a rolling 12-month basis, as reflected in the utility's monthly fuel cost reports as filed by the utility with the commission.

(b) Petitions to revise fuel factors.

(1) An electric utility using the fuel factor methodology established in accordance with subsection (a)(1)(A) of this section may file a petition requesting revised fuel factors in accordance with subsection (a)(2)(A) of this section during the first five working days of the months specified in subsection (d) of this section. A copy of the complete petition package must be served on each party in the utility's most recent fuel reconciliation and on OPUC. Service must be accomplished in accordance with §22.74 of this title (relating to Service of Pleadings and Documents). Each complete fuel factor filing package must include the petition, a tariff sheet reflecting the proposed fuel factors, and supporting testimony that includes the following information:

(A) For each month of the period in which the fuel-factor has been in effect and has not been reconciled up to the most recent month for which information is available,

(i) the revenues collected in accordance with fuel factors by customer class;

(ii) any other items that to the knowledge of the electric utility have affected fuel factor revenues and eligible fuel expenses; and

(iii) the difference, by customer class, between the revenues collected in accordance with fuel factors and the eligible fuel expenses incurred.

(B) To the extent that there are variations between the fuel costs incurred and the revenues collected, it may be necessary or convenient to refund overcollections or surcharge undercollections. Refunds or surcharges may be made without changing an electric utility's fuel factor. Nothwithstanding §25.236(e)(6) of this title, an electric utility may petition for a surcharge any time it has materially undercollected its fuel costs and projects that it will continue to be in a state of material undercollection. Notwithstanding §25.236(e)(6) of this title, an electric utility shall petition to make a refund any time it has materially overcollected its fuel costs and projects that it will continue to be in a state of material overcollection. "Materially" or "material," as used in this section, shall mean that the cumulative amount of over- or under-recovery, including interest, is greater than or equal to 4.0% of the annual actual fuel cost figures on a rolling 12-month basis, as reflected in the utility's monthly fuel cost reports as filed by the utility with the commission.

(2) An electric utility using the fuel factor formula methodology established in accordance with subsection (a)(1)(B) of this section may file a petition requesting revised fuel factors in accordance with subsection (a)(2)(B) of this section at least 15 days prior to the first billing cycle in the billing month in which the proposed fuel factors are requested to become effective. A copy of the complete petition package must be served on each party in the utility's most recent fuel reconciliation and on OPUC. Service must be accomplished in accordance with §22.74 of this title (relating to Service of Pleadings and Documents). Each complete fuel factor filing package must include:

(A) a tariff sheet reflecting the proposed fuel factors;

(B) workpapers (in native Excel format with formulas intact; and proof and verification of natural gas prices, including copies of data used to calculate the natural gas prices) supporting the calculation of the revised fuel factors;

(C) calculations underlying any differentiation of fuel factors to account for differences in line losses corresponding to the voltage at which the electric service is provided; and

(D) any computer generated documents must be provided in their native electronic format with all cells and internal formulas disclosed.

(c) Fuel factor revision proceeding. The burden of proof and the scope of a fuel factor revision proceeding are as follows:

(1) In a proceeding to revise fuel factors in accordance with subsection (a)(1)(A) of this section, an electric utility has the burden of proving that:

(A) the expenses proposed to be recovered through the fuel factors are reasonable estimates of the electric utility's eligible fuel expenses during the period that the fuel factors are expected to be in effect;

(B) the electric utility's estimated monthly kilowatt-hour system sales and off-system sales are reasonable estimates for the period that the fuel factors are expected to be in effect; and

(C) the proposed fuel factors are reasonably differentiated to account for line losses corresponding to the voltage at which the electric service is provided.

(2) The scope of a fuel factor revision proceeding under subsection (a)(1)(B) of this section is limited to the issue of whether the petitioning electric utility has appropriately calculated its proposed fuel factors. In a proceeding to revise fuel factors in accordance with subsection (a)(1)(B) of this section, an electric utility has the burden of proving that:

(A) the electric utility has calculated its proposed fuel factors in compliance with the commission-approved fuel factor formula; and

(B) the proposed fuel factors utilize a commission-approved adjustment to account for line losses corresponding to the voltage at which the electric service is provided.

(3) The prudence of costs will not be considered in a fuel factor proceeding. The prudence of costs may only be reviewed in a fuel reconciliation proceeding under §25.236 of this title or another appropriate proceeding.

(d) Schedule for filing petitions to revise fuel factors. A petition to revise fuel factors or to initiate or revise a fuel factor formula may be filed with any general rate proceeding or in accordance with paragraph (1) of this subsection.

(1) Except as provided by subsection (f) of this section which addresses emergencies, petitions by an electric utility to revise fuel factors in accordance with subsection (a)(1)(A) of this section may only be filed in accordance with the following schedule:

(A) February, June, and October: El Paso Electric Company;

(B) March, July, and November: Entergy Texas, Inc.;

(D) May, September, and January: Southwestern Electric Power Company; and

(E) March, July, and November: any other electric utility not named in this subsection that uses one or more fuel factors.

(2) Petitions by an electric utility to revise fuel factors in accordance with subsection (a)(1)(B) of this section may be filed in any month except December.

(e) Procedural schedules.

(1) Upon the filing of a petition to revise fuel factors in accordance with subsection (a)(1)(A) of this section, the presiding officer will set a procedural schedule that will enable the commission to issue a final order in the proceeding as follows:

(A) within 60 days after the petition was filed, if no hearing is requested within 30 days of the petition; and

(B) within 90 days after the filing of an administratively complete petition, if a hearing is requested within 30 days of the petition. If a hearing is requested, the hearing will be held no earlier than the first working day after the 45th day after the petition was filed.

(2) Upon the filing of a petition to revise fuel factors in accordance with subsection (a)(1)(B) of this section, the presiding officer will set a procedural schedule as follows:

(A) the presiding officer will issue an order approving the proposed fuel factors on an interim basis no later than 12 days after the date the petition was filed, if no objection to interim approval is filed within 10 days after the date the petition was filed;

(B) if no hearing is requested within 30 days after the petition was filed, the presiding officer will, after submission of proof of notice by the electric utility, issue an order approving the fuel factors without hearing or action by the commission; and

(C) if a hearing is requested within 30 days after the petition was filed, the hearing will be held no earlier than the first working day after the 45th day after the petition was filed and a final order will be issued within 90 days after the petition was filed, subject to submission of proof of notice by the electric utility.

(f) Emergency revisions to the fuel factor. If fuel curtailments, equipment failure, strikes, embargoes, sanctions, or other reasonably unforeseeable circumstances have caused a material under-recovery of eligible fuel costs, the electric utility may file a petition with the commission requesting an emergency interim fuel factor. Such emergency requests must state the nature of the emergency, the magnitude of change in fuel costs resulting from the emergency circumstances, and other information required to support the emergency interim fuel factor. The commission will issue an interim order within 30 days after such petition is filed to establish an interim emergency fuel factor. If within 120 days after implementation, the emergency interim factor is found by the commission to have been excessive, the electric utility must refund all excessive collections with interest calculated on the cumulative monthly ending material under- or over-recovery balance in the manner and at the rate established by the commission for overbilling and underbilling in §25.28(c) and (d) of this title (relating to Bill Payment and Adjustments Billing). If, after full investigation, the commission determines that no emergency condition existed, a penalty of up to 10 percent of such over-collections may also be imposed on investor-owned electric utilities.

(g) Protest of fuel factor.

(1) Only a customer of the utility, a municipality with original jurisdiction over the utility, or OPUC is eligible to protest a fuel factor under this subsection.

(A) A protest of a fuel factor must identify the eligibility of the person to submit the protest.

(B) The commission will review a protest of a fuel factor to determine whether the utility's fuel factor reasonably reflects costs the utility will incur such that the utility will not substantially under-collect or over-collect the utility's reasonably stated fuel and purchased power costs on an ongoing basis.

(D) If a hearing is sought, a protest must include a request for a hearing and the basis for the request.

(2) If it is determined that a fuel factor is anticipated to result in a substantial under- or over-collection of costs by the utility, the utility's fuel factor will be adjusted to address the under-collection or over-collection in a manner consistent with this section.

(3) The presiding officer may hold a hearing on a protest of a fuel factor and may consider any evidence that is appropriate and in the public interest.

(4) A protest of a fuel factor may be processed and reviewed in a manner deemed administratively efficient by the presiding officer.

(5) Discovery in a fuel factor or fuel factor formula revision proceeding will be conducted in accordance with the commission's rules, except as modified by the presiding officer.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on December 19, 2025.

TRD-202504758

Seaver Myers

Rules Coordinator

Public Utility Commission of Texas

Effective date: January 8, 2026

Proposal publication date: July 25, 2025

For further information, please call: (512) 936-7433

PART 4. TEXAS DEPARTMENT OF LICENSING AND REGULATION

CHAPTER 60. PROCEDURAL RULES OF THE COMMISSION AND THE DEPARTMENT

The Texas Commission of Licensing and Regulation (Commission) adopts amendments to existing rules at 16 Texas Administrative Code (TAC), Chapter 60, Subchapter B, §60.22, and a new rule at Subchapter C, §60.38, regarding the Procedural Rules of the Commission and the Department, §60.22 and §60.38 are adopted without changes to the proposed text as published in the October 10, 2025, issue of the Texas Register (50 TexReg 6589). These rules will not be republished.

The Commission also adopts amendments to existing rules at 16 TAC Chapter 60, Subchapter C, §60.34, regarding the Procedural Rules of the Commission and the Department, with changes to the proposed text as published in the October 10, 2025, issue of the Texas Register (50 TexReg 6589). This rule will be republished.

EXPLANATION OF AND JUSTIFICATION FOR THE RULES

The rules under 16 TAC, Chapter 60, Procedural Rules of the Commission and the Department, implement Texas Occupations Code, Chapter 51, Texas Department of Licensing and Regulation, and other laws applicable to state agencies.

The adopted rules implement House Bill (HB) 11, 89th Legislature, Regular Session (2025). The bill amends the Department's enabling act, Chapter 51, Occupations Code, to require the Department to maximize the creation of occupational license reciprocity agreements with licensing authorities in other states. Rulemaking is required to establish procedures to both compare the licensing requirements of other states to those of Texas, and to enter in to and implement reciprocity agreements with those states with substantially equivalent license requirements. The Department must consider the scope of practice for each license; required training, testing, and work experience; and the jurisdiction's procedures to resolve complaints and determine if a license holder is in good standing. HB 11 builds on existing authority in Ch. 51 to enter into reciprocity agreements and to waive prerequisites for licensure for applicants who hold a similar license issued by another jurisdiction that has a reciprocity agreement with Texas.

The adopted rules add the power to enter into reciprocity agreements to the basic powers of the Department and the Executive Director. The adopted rules provide a list of the specific criteria the Department will use to evaluate the licensing requirements of another jurisdiction to determine if they are substantially equivalent to those of Texas. Further, the adopted rules include a concise list of the minimum requirements a license applicant must satisfy to obtain a Texas license when a reciprocity agreement is in place. In addition to establishing that the reciprocity and license requirements in Chapter 60 are subject to any different or more stringent requirements in Ch. 60, TAC; Ch. 51, Occupations Code; or the program statutes and rules governing the particular license, the Department reserves sole discretion to determine if the licensing requirements of the other jurisdiction are substantially equivalent to those of Texas. These rules are necessary to aid the Department to affirmatively seek to create more reciprocity agreements by providing clear notice to other jurisdictions of the criteria and conditions the Department will examine and consider going forward.

SECTION-BY-SECTION SUMMARY

The adopted rules amend §60.22, General Powers and Duties of the Department and the Executive Director, to include the responsibility to enter into reciprocity agreements with licensing authorities in other jurisdictions.

The adopted rules amend §60.34, Substantially Equivalent License Requirements, to update and clarify the applicability of the section to persons holding a license in another jurisdiction, and to specify the requirements for that license that the Department will examine. These include requirements related to: scope of practice, experience, training, education, examination, accreditation by other entities, financial security or insurance, standards of conduct, criminal history, and procedures to resolve complaints and to determine good standing of license holders. The section includes several edits for conciseness and clarity. Two nonsubstantive corrections to the punctuation in (d)(5) and (8) of this section are made in the adopted text.

The adopted rules add new §60.38, Reciprocity Agreements, to lay out the Department's authority to enter into reciprocity agreements and to list the minimum requirements a license holder must satisfy to obtain a Texas license under a reciprocity agreement with another jurisdiction. The requirements relate to how the license was obtained, how long it has been held, if it is in good standing, whether the applicant has a disqualifying criminal history or has had a license revoked, whether any complaints or allegations are pending in the other jurisdiction, and whether the license holder satisfactorily met examination or other substantially equivalent requirements to obtain the other jurisdiction's license.

PUBLIC COMMENTS AND INFORMATION RELATED TO THE COST, BENEFIT, OR EFFECT OF THE PROPOSED RULES

The Department drafted and distributed the proposed rules to persons internal and external to the agency. The proposed rules were published in the October 10, 2025 issue of the Texas Register (50 TexReg 6589). The Department requested public comments on the proposed rules and information related to the cost, benefit, or effect of the proposed rules, including any applicable data, research, or analysis. The public comment period closed on November 10, 2025.

The Department received comments from four interested individuals in response to the required summary of the proposed rules, which was posted on the Department's website and distributed on September 29, 2025, the same day that the proposed rules were filed with the Texas Register, but before the official publication of the proposed rules and the official start of the public comment period. Subsequently, the Department received comments from one interested party on the published proposed rules during the official public comment period. This commenter is the Texas Association for Behavior Analysis Public Policy Group (TxABA PPG). The public comments are summarized below. In this response, the term "state" is interchangeable with "jurisdiction."

Comments in Response to the Posted Summary

Of the four individuals who submitted comments in support of the rules, three made remarks in addition to expressing general support, as follows.

Comment: One individual commented in support of the proposed rules, citing a desire to hold licenses in other states to practice an online job.

Department Response: The Department thanks the commenter for the expression of support for the rules and agrees that license reciprocity will reduce or remove barriers to multi-state practice. No changes were made to the proposed rules in response to this comment.

Comment: An individual commented supporting the rules and to propose a strategy to ease re-licensing for former Texas license holders and those with inactive Texas licenses. The commenter suggests that licensing revenue would return to Texas and could likewise be increased by adding the equivalent of two years of renewal fees for these applicants as well.

Department Response: The Department appreciates the support for the rules and the recommendations offered. The proposed rules implement HB 11 to increase reciprocal licensing for current license holders in Texas and other jurisdictions. The Department rules are regularly scrutinized to modify or remove barriers to licensing for all applicants. Changes such as those the commenter recommends must be considered in another rulemaking. These comments have been directed to staff for consideration for re-licensing for those with expired or inactive licenses. No changes have been made to the proposed rules in response to this comment.

Comment: An individual commented to support reciprocity and to point out that, because Texas has the hardest electrician exams and the National Electrical Code applies in all states, that all states should reciprocate and Texas licensed electricians should automatically qualify for other states' licenses.

Department Response: The Department appreciates the support for reciprocity but disagrees that the electrician examinations should be the only or even main factor to consider in making reciprocity decisions for electrician licenses. Not all states adopt or enforce the NEC equally. Several other licensing standards and applicant qualifications in addition to the examination must be evaluated to determine if two states' licenses are substantially equivalent. Requirements for qualifications such as training, education, or experience may be more or less stringent in other states, and it is important for both states considering reciprocity to have confidence that people who can become licensed substantially meet or exceed the state's standards before that state agrees to reciprocal licensing. Other factors such as the length of time the person has held a license, compliance history, and so on may affect whether a person can qualify for another state's license.

Texas license holders may avail themselves of regular or alternative licensing procedures in another state regardless of whether a reciprocity agreement is in place. Passing the Texas examination may well open the door to another state's license, but most states use additional criteria to make licensing decisions. The Department has made no changes to the proposed rules as a result of this comment.

Comments in Response to the Published Proposed Rules

Comment: The TxABA PPG expressed opposition to the proposed rules providing TDLR or the Texas Commission of Licensing and Regulation (TCLR) sole discretion to determine whether another state's licensing requirements are substantially equivalent to those of TDLR. Specifically, the TxABA PPG expressed concern that input from subject-matter experts including the relevant Department advisory boards would be excluded from the decision-making process for out-of-state license equivalence, undermining the integrity of the licensing system.

Department Response: The Department thanks the TxABA PPG for its thoughtful and detailed comments. The Department reserves sole discretion to decide whether the licensing requirements of another state are substantially equivalent to those of Texas to ensure that those states clearly understand that the Department's determinations on substantial equivalence are final and may not be challenged. All of the expertise residing in the Department is employed as needed to evaluate substantial equivalence, including that of staff, leadership, and advisory board members. Not all decisions require extensive or burdensome efforts to evaluate substantial equivalence, so the advisory boards are consulted as the need for obtaining their members' expertise arises.

The boards by law serve in an advisory role to the Department, the Executive Director, and to the Commission primarily through the rulemaking function, but for other purposes as well. Their input is highly valued and never disregarded. The Department's determinations on substantial equivalence are well-informed because they are the result of thorough and serious consideration, and advisory board expertise is a needed and welcome part of the evaluation process. If the requirements of a state desiring to establish reciprocity are not substantially equivalent to those of Texas, then either state may modify or waive its requirements, add new requirements, or simply not engage in reciprocity. The Department will not sacrifice the integrity of its licensing system to engage in reciprocity that is not supported by a careful analysis as provided in the proposed rules.

Comment: The TxABA PPG recommends that the Department define substantial equivalence for all the professions for which it issues licenses, include input from the advisory boards' review of other states' licensing requirements, and include the Department advisory boards in the process of rule development.

Department Response: The proposed rules in TAC Chapter 60 are the basic guidelines and criteria the Department will use to make decisions about reciprocity agreements and individual applicants when reciprocity agreements in any program are sought. The Department regulates over 160 license types and nearly one million license holders in over 40 programs, so the Department expects to conduct rulemaking only as necessary to expand on program- or license-specific requirements related to license reciprocity for which targeted rules would eliminate confusion or unnecessary additional evaluation. The Department expects to occasionally identify tailored program- or license-specific rules to add to the program rules for the relevant license types. Such rules might address commonly encountered differences in continuing education requirements, examination scoring, or other criteria for which a specific alternative, exemption, or clarification will address ongoing impediments to licensing or reciprocity in a particular program. The main and most important role of each advisory board is to advise the Department in developing rules for that program, so the advisory boards will be an indispensable part of program rulemaking to address substantial equivalence and reciprocity issues where such rules are needed.

If new or amended rules with wide applicability across programs are necessary, then those are usually added to Chapter 60. Because of the universal nature and application of Chapter 60 rules, they normally do not follow the same process as program rules in one main way: the rules are not presented to each Department advisory board for its recommendations to propose or adopt. Not only would this be very cumbersome and time-consuming, but the nature of Chapter 60 rules is that they are procedural rules for the operation of the Department and they often implement statutory requirements that are not subject to modification in the rules. Each division of the Department provides input to develop Chapter 60 rules, including reaching out to subject matter experts, including advisory board members, where needed. The Chapter 60 rules are either adjusted to accommodate conflicts with program rules, or staff slates program rules for amendment to resolve such conflicts. Of course, advisory board members may also participate in the rulemaking process for Chapter 60 rules by submitting comments and recommendations to raise any concerns relative to the effect of Chapter 60 rules on the relevant program.

The Department does not believe that adopting rules to define exactly what substantial equivalence means for every license type is reasonable, efficient, or necessary. The main reasons for this position include:

Identifying and defining every possible disparity among the requirements of multiple states for each of over 160 license types to define exactly what is or is not substantially equivalent to Texas requirements would demand an enormous commitment of time and resources to accomplish, with little discernable benefit. Further, license requirements in all states are fluid and change over time, so frequent redefinition and consequent rulemaking would be necessary.

Evaluating substantially equivalent licensing encompasses more than an item-by-item checklist of applicant qualifications. Instead, it is a comparison of the way licensing is administered by a state, for example, its procedures for resolving complaints against license holders. This makes the scope of the evaluation even more difficult and formidable to capture in great detail and specificity in rule (see §60.34(d)).

The "substantially equivalent" analysis does not by its nature demand identical qualifications and processes in a reciprocating state, and this underlines the need for discretion and flexibility in the comparison. For example, comparing licensing standards for which education or training requirements are very exacting and lengthy, such as years of academic courses with specific content for a particular curriculum, would impose a significant obstacle to defining substantial equivalence.

Less demanding requirements in one component of licensing may be balanced out by more stringent requirements in another, but retaining flexibility for that weighing process benefits both parties - who are equally competent to make those calculations. Differences in requirements may be minor and neither state may feel that those differences should prevent reciprocity. Even if substantial equivalence were defined in rule, flexibility and discretion would still be necessary to accomplish reciprocity in many cases because it is impossible to identify by rule every permutation of the way requirements and procedures could vary.

Establishing license reciprocity agreements that accept another state's licensing requirements as substantially equivalent to those of Texas does not alone open the door to every applicant. Reciprocity does not replace or waive any applicable Texas license requirements or an individualized evaluation of each applicant - for criminal history, compliance history, and so on, both at issuance and renewal, as spelled out in the proposed rules (see §60.38(c)). The reciprocity agreement establishes that each state will perform its usual evaluation of license applicants so that the other state can rely on the determination that the person did qualify for that license. The obligation for each license holder to comply with each state's law and rules is unaffected by the existence of a reciprocity agreement except for any requirements specifically waived by the agreement. Typically, only the examination requirement is waived in the reciprocating state, and all other license requirements remain applicable and enforceable.

Comment: The TxABA PPG comments that the dangers of leaving substantial equivalence undefined in the rules could include the failure of behavior analyst license holders to maintain certification as a Board Certified Behavior Analyst or Qualified Behavior Analyst, to complete continuing education requirements, to have the minimum comparable education or experience to meet Texas standards, or to undergo relevant background checks.

Department Response: As explained in this response, all license applicants must satisfy the license requirements of each state participating in the reciprocity agreement except for any that are specifically waived. Applicants will undergo a verification process to confirm qualifications that may have lapsed or changed, as is routinely done for all applicants for new or renewed licenses. The terms of reciprocity agreements contain safeguards that include an obligation for each state to update the other if its requirements change or if a license holder fails to meet that state's requirements to hold or renew a license.

Comment: The TxABA PPG requests revising the proposed rules to require consultation with each professions' advisory board when evaluating other states' licensing requirements for substantial equivalence.

Department Response: The Department agrees that each program's advisory board may need to assist the Department to evaluate another state's license requirements to determine if they are substantially equivalent to those of Texas. However, Department staffs' review and comparison usually results in a clear determination. The Department has relied on the advisory boards in the past to make recommendations about equivalence when disparities were uncovered so that the Department has appropriate guidance to make supportable decisions. That will not change. But a requirement to consult the program advisory board for each substantial equivalence decision would be burdensome to all involved and is simply not necessary in most cases. The Department has no reluctance to consult with the program advisory boards when their expertise is needed to make correct decisions and will continue to do so, both for state reciprocity decisions and for developing rules to ease, expand, or modify reciprocity requirements or processes.

The Department does not exclude the possibility that the proposed rules will need modification as the efforts to increase reciprocity expand. The need for license-specific reciprocity provisions in some programs' rules is also a likely possibility. The advice and input from the Department advisory boards will be an integral part of such rulemaking. The Department has made no changes to the proposed rules in response to the TxABA PPG's comments.

COMMISSION ACTION

At its meeting on December 16, 2025, the Commission adopted the proposed rules with changes to §60.34 as published in the Texas Register. These changes are explained in the Section-by-Section Summary.

SUBCHAPTER B. POWERS AND RESPONSIBILITIES

16 TAC §60.22

STATUTORY AUTHORITY

The adopted rule is adopted under Texas Occupations Code, Chapter 51, which authorizes the Texas Commission of Licensing and Regulation, the Department's governing body, to adopt rules as necessary to implement the chapter and any other law establishing a program regulated by the Department.

The statutory provisions affected by the adopted rules are those set forth in Texas Occupations Code, Chapter 51, and the program statutes for all of the Department programs in which a licensing reciprocity agreement could be created: Agriculture Code, Chapter 301 (Weather Modification and Control); Education Code, Chapter 1001 (Driver and Traffic Safety Education); Government Code, Chapters 171 (Court-Ordered Programs); and 469 (Elimination of Architectural Barriers); Health and Safety Code, Chapters 401, Subchapter M (Laser Hair Removal); 754 (Elevators, Escalators, and Related Equipment); and 755 (Boilers); Labor Code, Chapter 91 (Professional Employer Organizations); Occupations Code, Chapters 202 (Podiatrists); 203 (Midwives); 401 (Speech-Language Pathologists and Audiologists); 402 (Hearing Instrument Fitters and Dispensers); 403 (Dyslexia Practitioners and Therapists); 451 (Athletic Trainers); 455 (Massage Therapy); 506 (Behavior Analysts); 605 (Orthotists and Prosthetists); 701 (Dietitians); 802 (Dog or Cat Breeders); 1151 (Property Tax Professionals); 1152 (Property Tax Consultants); 1202 (Industrialized Housing and Buildings); 1302 (Air Conditioning and Refrigeration Contractors); 1304 (Service Contract Providers and Administrators); 1305 (Electricians); 1603 (Barbers and Cosmetologists); 1802 (Auctioneers); 1806 (Residential Solar Retailers); 1901 (Water Well Drillers); 1902 (Water Well Pump Installers): 1952 (Code Enforcement Officers); 1953 (Sanitarians); 1958 (Mold Assessors and Remediators); 2052 (Combative Sports); 2303 (Vehicle Storage Facilities); 2308 (Vehicle Towing and Booting); 2309 (Used Automotive Parts Recyclers); 2310 (Motor Fuel Metering and Quality); 2311 (Electric Vehicle Charging Stations); and 2402 (Transportation Network and Delivery Network Companies); and Transportation Code, Chapters 551A (Off-Highway Vehicle Training and Safety); and 662 (Motorcycle Operator Training and Safety).

The legislation that enacted the statutory authority under which the adopted rules are proposed to be adopted is House Bill 11, 89th Legislature, Regular Session (2025).

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on December 19, 2025.

TRD-202504743

Doug Jennings

General Counsel

Texas Department of Licensing and Regulation

Effective date: January 15, 2026

Proposal publication date: October 10, 2025

For further information, please call: (512) 475-4879

SUBCHAPTER C. LICENSE APPLICATIONS AND RENEWALS

16 TAC §60.34, §60.38

STATUTORY AUTHORITY

The adopted rules are adopted under Texas Occupations Code, Chapter 51, which authorizes the Texas Commission of Licensing and Regulation, the Department's governing body, to adopt rules as necessary to implement the chapter and any other law establishing a program regulated by the Department.

The legislation that enacted the statutory authority under which the adopted rules are proposed to be adopted is House Bill 11, 89th Legislature, Regular Session (2025).

§60.34. Substantially Equivalent License Requirements.

(a) This section is applicable to an applicant who holds a current license issued by another jurisdiction that is similar to a license issued by the department.

(b) For purposes of this section, "another jurisdiction" or "other jurisdiction" means a U.S. state, the District of Columbia, a municipality or local jurisdiction, or a U.S. territory.

(c) A person holding a license issued by another jurisdiction may be eligible for a Texas license if the other jurisdiction's licensing requirements are substantially equivalent to those of Texas.

(d) Unless provided otherwise in the statutes and rules governing a program or license type, the department will review and evaluate the following criteria to determine if another jurisdiction's licensing requirements are substantially equivalent to those of Texas:

(1) Scope of practice--the scope of work authorized to be performed under the license;

(2) Experience and training requirements--including the length of time or number of hours of on-the-job experience or training that the other jurisdiction requires applicants to possess to qualify for the particular license;

(3) Education requirements--including the amount of time (hours, months or years) or credits needed to complete any course, program, or curriculum that is a prerequisite for licensure;

(4) Examination requirements--including whether the other jurisdiction requires an applicant to pass any examinations to obtain the license; the type and content of any such examination(s); and the minimum score needed for an applicant to pass the examination(s);

(5) Accreditation requirements--including credentials or accreditation by federal agencies or national or other professional organizations or entities that a person must have to practice a profession;

(6) Financial security or insurance requirements--whether and to what extent the other jurisdiction requires license holders to hold certain insurance policies, secure a bond, or provide other forms of financial security;

(7) Standards of conduct--including requirements for honesty and fair dealing with the public when providing services or goods, in advertising, and in business dealings;

(8) Criminal history--including whether the jurisdiction takes an applicant's or license holder's criminal history into account when determining license eligibility or disqualification; and

(9) Procedures used in the other jurisdiction to receive and resolve complaints and to determine whether a license holder is in good standing.

(e) The department may require an applicant under this section to provide additional supporting documentation or information in order for the department to evaluate the criteria under subsection (d) as it relates to a specific license.

(1) Any foreign transcripts or foreign degrees must be translated and evaluated as prescribed under §60.30. Any other documents in a language other than English must be translated in accordance with the provisions under §60.30.

(2) The applicant shall bear all expenses incurred under this section during the evaluation process.

(f) The department has sole discretion in determining whether the licensing requirements for a license issued by another jurisdiction are substantially equivalent to those of Texas.

The agency certifies that legal counsel has reviewed the adoption and found it to be a valid exercise of the agency's legal authority.

Filed with the Office of the Secretary of State on December 19, 2025.

TRD-202504744

Doug Jennings

General Counsel

Texas Department of Licensing and Regulation

Effective date: January 15, 2026

Proposal publication date: October 10, 2025

For further information, please call: (512) 475-4879