TITLE 16. ECONOMIC REGULATION

PART 1. RAILROAD COMMISSION OF TEXAS

CHAPTER 3. OIL AND GAS DIVISION

16 TAC §3.65

The Railroad Commission of Texas (the "Commission") adopts amendments to §3.65, relating to Critical Designation of Natural Gas Infrastructure, with changes to the proposed text as published in the September 16, 2022, issue of the Texas Register (47 TexReg 5560). The amendments are adopted to simplify the rule language and the process for designating certain natural gas facilities and entities critical during energy emergencies.

Section 3.65 went into effect December 20, 2021. It implemented requirements from House Bill 3648 and Senate Bill 3 (87th Legislature, Regular Session) directing the Commission to collaborate with the Public Utility Commission of Texas (the "PUC") to adopt rules to establish a process to designate certain natural gas facilities and entities associated with providing natural gas in this state as critical customers or critical gas suppliers during energy emergencies. The Commission's process for designating certain facilities critical has been in place for approximately ten months. During that time, the Commission became aware of points of confusion in current §3.65. Additionally, during the recent comment period for proposed 16 Texas Administrative Code §3.66 (relating to Weather Emergency Preparedness Standards), the Commission received several comments requesting changes to §3.65. The Commission addresses some of those concerns with these adopted amendments.

The Commission received 35 comments on the proposal: 7 from associations, 18 from companies/organizations, and 10 from individuals.

Comments on proposed amendments to §3.65(a) - Definitions

CrownQuest Operating (CrownQuest), Office of Public Utility Counsel (OPUC), Permian Regulatory Solutions (PRS), and the Texas Oil and Gas Association (TXOGA) support the Commission's proposed amendments to the definition of "energy emergency." The Commission appreciates these comments.

TXOGA and the Texas Independent Producers and Royalty Owners Association (TIPRO) requested that the Commission notify operators with facilities subject to the requirements of §3.65 when the Electricity Reliability Council of Texas (ERCOT) issues an Energy Emergency Alert (EEA) 1, EEA 2, or EEA 3.

The Commission will notify operators of a weather emergency as defined in §3.66. Thus, the Commission will notify operators when weather conditions result in an energy emergency, as that term is modified in these amendments.

The Texas Competitive Power Advocates (TCPA) and Texas Electric Cooperatives (TEC) suggested the Commission align the definition of "energy emergency" with the definition of "weather emergency" adopted by the PUC. TCPA and TEC expressed concern that the Commission's definition of "energy emergency," which focuses on ERCOT-issued EEAs, places the threshold for targeted action at a point in an emergency where there could be insufficient time to implement meaningful steps to stave off further situational deterioration. TCPA and TEC noted that gas facilities should address the risk of losing production long before the onset of an EEA. Thus, TCPA suggested the Commission define "energy emergency" more broadly to include an Operating Condition Notice, Advisory, Watch, or some other threshold prior to an EEA and TEC suggested the Commission define "energy emergency" to include an Emergency Notice.

The Commission declines to change the definition in response to these comments. The requirement in the Commission's weatherization rule, §3.66, is for facilities subject to that rule to "implement measures to prepare to operate during a weather emergency." Weather emergency is defined in §3.66 as "weather conditions such as freezing temperatures, freezing precipitation, or extreme heat in the facility's county or counties that result in an energy emergency as defined by §3.65 of this title." Because an energy emergency is now defined as when the reliability coordinator issues an Energy Emergency Alert (EEA) 1, 2, or 3, facilities subject to §3.66 are required to implement measures to prepare to operate in weather conditions that result in the issuance of an EEA 1, 2, or 3. The Commission finds that if a facility has implemented measures to prepare to operate in weather conditions that cause an EEA 1 or higher, then consequently, the facility is prepared to operate in less serious conditions, such as those that prompt a advisory, watch, or emergency notice. Thus, the facility will be prepared to operate in the period leading up to the emergency - the period about which TCPA and TEC expressed concern.

Henry Resources, LLC (Henry) asked that the Commission include clarifying definitions of "electricity supply chain map" and "Director."

The Commission agrees that adding definitions to clarify these terms is helpful and adopts subsection (a) with changes to add the definitions in paragraphs (4) and (5).

Comments on proposed amendments to §3.65(b) - Critical Designation Criteria

Bluefin Resources, Citation Oil and Gas Corp. (Citation), Creek Energy, Inc., CrownQuest, Henry, OPUC, Diamondback, PRS, Southwest Gas Systems, Stephens Engineering, Permian Basin Petroleum Association (PBPA), the Texas Alliance of Energy Producers (Alliance), TXOGA, TIPRO, and four individuals expressed support for the Commission's proposed amendments in subsections (b)(1)(A) and (b)(1)(B), which increase the average amount of gas a gas well or oil lease must produce for it to be designated critical. The Commission appreciates the support of these commenters.

Diamondback requested the Commission raise the threshold to 1500 Mcf/day for oil leases. The Atmos Cities Steering Committee (ACSC) and TEC also asked that the Commission further limit the list of critical facilities. Conversely, Commission Shift expressed concern that too many facilities are excluded and the remaining facilities designated critical will not produce enough gas to meet peak demand experienced during Winter Storm Uri.

These four comments highlight the difficulty in striking the appropriate balance in determining the amount of critical facilities - designating too many facilities critical places a burden on electric utilities when prioritizing critical loads during an energy emergency and designating too few facilities critical risks losing natural gas supply to meet demand during the emergency. As the Commission noted in the preamble for the proposed amendments, raising the threshold in §3.65(b)(1) to 250 Mcf/day for gas wells and 500 Mcf/day for oil leases producing casinghead gas leaves 78.4% of the total natural gas produced per day, or approximately 24.5 Bcf/day of natural gas, designated as critical while removing the low-producing gas wells and oil leases, which aggregated together statewide only represent a small portion of the natural gas production. However, they account for a large number of the facilities. Thus, removing these facilities from the list reduces the burden on electric utilities and helps ensure other electric customers receive power in an emergency. Additionally, gas-fired generation nameplate capacity in Texas is 15 Bcf/day according to TCPA. During Winter Storm Uri, peak day demand for gas-fired generation was approximately 9 Bcf/day based on American Gas Association's estimates.

The Commission also notes that raising the volume thresholds in subsection (b)(1)(A) and (b)(1)(B) does not preclude facilities producing under the thresholds from producing gas during an energy emergency. Removing those wells and leases from the critical gas supplier list merely prevents their power from being prioritized by electric utilities during a load-shed event. However, the facilities may be located on the same meter as another critical facility such that their power remains on and they continue to produce, or they may otherwise maintain power, allowing more than 24.5 Bcf of production to be available. Therefore, the Commission declines to make changes to subsection (b)(1)(A) or subsection (b)(1)(B) in response to these comments.

ACSC also commented that the Commission has not provided enough guidance to electric utilities regarding how the facilities should be prioritized. The Commission should establish a hierarchy to provide direction during load shed events.

The Commission declines to make any changes in response to this comment. The PUC has the authority to regulate electric utilities and has published guidance on how critical natural gas facilities should be prioritized for load-shed purposes. The guidance is available on the PUC's website.

Regarding the list of facilities in subsection (b)(1), the Alliance and TXOGA requested that the facilities only be designated critical if they are also included on the electricity supply chain map developed by the Electricity Supply Chain Security and Mapping Committee pursuant to Senate Bill 3 (87th Legislature, Regular Session).

The Commission disagrees. The facilities on the electricity supply chain map are included on the map because they are located in the natural gas supply chain for electric generation. Thus, they are designated critical to ensure electric utilities prioritize their power during an energy emergency and they continue to operate to provide gas for electric generation. However, facilities that are not included on the map provide natural gas to other end users, notably, local distribution companies (LDCs) that serve city gates. Therefore, these facilities should also remain critical.

Relatedly, TEC asked that the Commission further limit the list of critical facilities to only those that directly support the delivery of gas to gas-fired electric generation or to end users.

The Commission notes that facilities that help provide gas to gas-fired electric generation and other end users are those designated critical in §3.65(b)(1). Other facilities designated critical in subsection (b)(1), such as saltwater disposal facilities, are included because if they lose power and are unable to operate, facilities that more directly contribute to the supply chain may be unable to operate. The Commission also notes that it adopts changes to the list of critical facilities in subsection (b) due to other comments.

AVAD Operating LLC, Slant Operating, PBPA, the Alliance, and one individual asked the Commission to find a solution for large waterflood/enhanced oil recovery (EOR) projects. These operations cover large areas of land (often thousands of acres) and are particularly vulnerable to cold weather but produce negligible volumes of casinghead gas from each unit, especially considering the likelihood of high energy intensive electricity equipment required to operate a single lease.

The Commission understands this concern and adopts subsections (a) and (b) with changes to address EOR projects. Subsection (a) is adopted with a change to define "EOR project" for the purposes of §3.65 as "an enhanced oil recovery project as defined in §3.50(c)(6) of this title (relating to Enhanced Oil Recovery Projects-Approval and Certification for Tax Incentive) with at least one injection well permitted under §3.46 of this title (relating to Fluid Injection into Productive Reservoirs) whether or not the project has received Commission approval or certification under §3.50." Changes adopted in subsection (b)(1)(B) exclude EOR projects from oil leases designated critical provided the EOR project consumes more energy than it produces calculated by comparing the amount of electricity used to the amount of gas produced both in Million British Thermal Units (MMBTU).

Henry, TXOGA, the Alliance, WaterBridge Operating LLC, and Stephens Engineering commented about the Commission's critical designation of saltwater disposal facilities and saltwater disposal pipelines in §3.65(b)(1)(H). Henry and TXOGA requested that the Commission limit the saltwater disposal facilities designated as critical to those that support the other facilities designated critical in subsection (b)(1). The Alliance and WaterBridge raised concerns that the designation of all saltwater disposal facilities in subsection (b)(1)(H) does not allow flexibility for saltwater disposal well networks connected through pipelines. These networks allow operators to shift disposal volumes to different areas if constraints arise in one part of their system. The Alliance and WaterBridge requested the rule allow operators of interconnected systems to only designate as critical the portions of the network necessary to ensure sufficient disposal capacity is maintained. Stephens asked for clarification on which types of saltwater disposal facilities are included in subsection (b)(1)(H) and asked that critical designation be limited to commercial saltwater disposal facilities.

The Commission declines to make changes in response to these comments. The Commission prefers that operators of saltwater disposal facilities who do not want their facilities to be critical seek an exception to critical designation through the process in subsection (e). If a saltwater disposal facility is not on the electricity supply chain map and can provide objective evidence that it does not support a critical facility listed in subsection (b)(1)(A)-(G), then it is eligible for an exception to critical designation, as discussed in the section regarding comments on subsection (e) below.

Similarly, the Commission disagrees with the Alliance and WaterBridge that saltwater disposal connected system operators should be able to determine which facilities on their system are critical. The Commission notes that all saltwater disposal facilities that are not included on the electricity supply chain map are now eligible to request an exception to critical designation. The Commission prefers saltwater disposal facilities to go through the exception process rather than removing these facilities from the list of critical facilities.

The Commission disagrees with Stephens that critical saltwater disposal facilities should be limited to commercial facilities. The Commission defines commercial saltwater disposal facilities as those whose owner or operator receives compensation from others for the storage, reclamation, treatment, or disposal of oil field fluids or oil and gas wastes that are wholly or partially trucked or hauled to the facility and whose primary business purpose is to provide these services for compensation. This definition excludes saltwater disposal facilities that receive waste through a pipeline and the Commission determines facilities that receive waste through a pipeline should be designated critical.

TCPA asked the Commission to provide clarity as to whether gas infrastructure facilities used to export natural gas from Texas via intrastate gas pipelines to Mexico or by way of liquefied natural gas (LNG) liquefaction and export terminals into the international LNG market are or should be designated as critical infrastructure.

LNG facilities are not currently designated critical under §3.65(b)(1) and the Commission declines to make changes to subsection (b) to include LNG facilities or LNG export terminals. Senate Bill 3 specified that the Commission's critical designation rule should designate certain facilities that are associated with providing natural gas in this state. LNG being exported for the international market is outside the intended scope of Senate Bill 3. Additionally, the Commission has no jurisdiction over LNG export facilities. A natural gas pipeline subject to the jurisdiction of the Commission that delivers natural gas to an LNG liquefaction plant may be designated critical under subsection (b)(1)(D) ("natural gas pipelines and pipeline facilities including associated compressor stations and control centers"); however, if the pipeline is not on the electricity supply chain map and all of the natural gas delivered by the pipeline facility is consumed outside of this state, the pipeline is eligible to apply for an exception to critical designation pursuant to §3.65(e).

TXOGA requested additional clarity regarding natural gas liquids transportation and storage facilities, which are designated critical in §3.65(b)(1)(G). TXOGA suggested that natural gas liquids that originate at crude oil wells be exempted from critical designation.

The Commission disagrees. Section 3.65(b)(1) designates as critical natural gas liquids transportation and storage facilities to ensure facilities that store or carry off natural gas liquids retain power. If these facilities lose power and a gas processing facility or an oil lease operator has no transport or storage for natural gas liquids, then the liquids may back up and slow or stop production or processing of natural gas.

Henry requested that the Commission clarify the term "critical customer," in subsection (b)(2) by changing the description to "a critical customer is a critical gas supplier that requires electricity to operate."

The Commission agrees to clarify the term "critical customer," but does not adopt Henry's proposed language, which would inadvertently include facilities that have their own power source or otherwise do not receive power from an electric entity. The Commission adopts §3.65(b)(2) with the following description: "A critical customer is a critical gas supplier that requires electricity delivered by an electric entity to operate." This change ensures that only customers of electric entities are deemed "critical customers" such that only true customers are required to be prioritized by the electric entities for load shed purposes.

Comments on proposed amendments to §3.65(c) - Request for Critical Designation

Citation and PRS commented in support of the Commission's proposed amendments to subsection (c). The Commission appreciates the support of these commenters.

TCPA and TEC commented that facilities that qualify for an exception under the list of reasonable bases and justifications in §3.65(e)(2)(A)-(C) should not be eligible to request critical designation under §3.65(c).

The Commission agrees in part. A facility that does not contribute to the natural gas supply chain in Texas should not be designated critical unless the facility supports a facility designated critical in subsection (b)(1). To be designated critical through the process in §3.65(c), a facility's operator must show with objective evidence that the facility's operation is required for another facility designated critical in §3.65(b) to operate. The Commission retains this process in the adopted amendments to ensure facilities not listed in subsection (b)(1) may apply to retain power if their operation is required for a critical facility to operate.

ACSC requested clarification regarding the process for requesting critical designation under §3.65(c). Specifically, ACSC requested clarification regarding who makes the determination that a facility is critical and how that decision is made.

The Commission agrees to clarify the process for requesting critical designation and adopts subsection (c) to state that the Critical Infrastructure Division director reviews applications submitted under §3.65(c). The changes also clarify that if a request for critical designation is denied, the applicant may request a hearing. The Commission notes that the determination will be made based on the whether the requirements specified in subsection (c) are satisfied. Subsection (c) requires an applicant to submit objective evidence that the facility requesting critical designation must operate in order for a facility designated critical in subsection (b) to operate.

Comments on proposed amendments to §3.65(e) - Critical Designation Exception

Henry, Occidental (Oxy), PBPA, PRS, the Alliance, TXOGA, and TIPRO commented that every critical facility should be able to request an exception regardless of the facility's status on the electricity supply chain map.

The Commission declines to make any changes in response to these comments. It is the Commission's understanding that the legislature does not support allowing facilities on the electricity supply chain map to apply for an exception to critical designation. When §3.65 was proposed in 2021, the Senate Business and Commerce Committee submitted a comment letter on the proposed rule. The letter stated, "Under no circumstances should a component of the natural gas supply chain that is directly tied to electric power generation be allowed to opt out of the critical designation requirements and subsequent weatherization."

TIPRO also requested that critical facilities that are not included on the electricity supply chain map be allowed to request an exception.

The amendments as proposed allow critical facilities not included on the electricity supply chain map to request an exception if the operator's reasonable basis and justification for the exception aligns with the examples provided in §3.65(e)(2).

The Alliance suggested that disposal wells that are disposing relatively small volumes in their daily operations be allowed to apply for a critical designation exception, just as disposal wells not supporting critical wells are currently allowed to do.

The amendments as proposed allow saltwater disposal facilities and pipelines not included on the electricity supply chain map to request an exception. A reasonable basis and justification for saltwater disposal facilities is added in §3.65(e)(2)(D) in response to comments below.

Regarding the examples of a reasonable basis and justification that may be provided with an exception request, TCPA noted that there may be more than just natural gas production that is directed entirely out of state and the reasonable basis and justification in §3.65(e)(2)(B) should be amended to include other types of facilities.

PRS and an individual requested the Commission add more bases for exception into the rule to allow for more administrative exceptions and reduce the number of hearings. Henry and PBPA requested that the Commission include a reasonable basis and justification specific to saltwater disposal facilities in §3.65(e)(2).

The Commission adopts §3.65(e)(2) with changes in response to these comments. The Commission adds "processed" and "delivered" in subsection (e)(2)(B) to address processing facilities and pipeline facilities. The Commission also adopts new §3.65(e)(2)(D) to provide a reasonable basis and justification applicable to saltwater disposal facilities. A saltwater disposal facility or saltwater disposal pipeline may request an exception if it is not included on the electricity supply chain map and it provides objective evidence to show that the facility or pipeline does not support a facility designated critical in §3.65(b)(1)(A)-(G).

Stephens Engineering commented that it is impossible to provide objective evidence of where lease water comes from for a non-commercial saltwater disposal facility. Thus, Stephens suggests a statement from the operator should be sufficient evidence to support an exception application.

The Commission understands this concern but declines to remove the requirement for objective evidence. To grant administrative approval without a hearing, Commission Staff must be able to verify the reasonable basis and justification claimed by a facility seeking an exception to critical designation.

Citation asked that the Commission include in the list of reasonable bases and justifications the bases and justifications approved in a final order by the Commission after a hearing. Henry also requested that a reasonable basis and justification approved in a final order of the Commission be added in subsection (e)(2).

The Commission does not agree these should be added to the rule because the list would become incomplete if the Commission issues additional final orders after a hearing.

TXOGA commented that the examples of reasonable bases and justifications does not adequately address possible exceptions for natural gas liquids pipelines.

The Commission notes that the list of reasonable bases and justifications is not exhaustive. Under the proposed amendments, natural gas liquids facilities and pipelines are eligible to request an exception if the facility/pipeline is not included on the electricity supply chain map. The Commission makes no changes in response to this comment.

In addition to Henry's comments requesting provisions in §3.65(e)(2) for saltwater disposal facilities and a reasonable basis and justification approved after a hearing, Henry requested that the following reasonable bases and justifications be added to subsection (e)(2): (1) The facility does not produce gas that supports electric generation in the state; (2) Gas production reported on an oil lease basis is disproportionately high when compared to gas production attributable to the individual oil wells on the lease; (3) The Commission has not provided at least 30 days written notice to the operator prior to the March 1 or September 1 Form CID filing deadline that the facility is included on the map; and (4) Other good cause shown, including but not limited to, facilities are capable of reducing their demand in response to an instruction issued by the applicable power region's reliability coordinator during certain grid conditions.

The Commission declines to add these provisions to §3.65(e)(2). First, the Commission notes that the list of reasonable bases and justifications contains examples and is not an exhaustive list. Operators seeking an exception may provide objective evidence of a reasonable basis and justification not contained in the list and receive administrative review. If the exception request is administratively denied, the operator may request a hearing.

Regarding Henry's first suggestion, the Commission disagrees that a facility that does not produce gas for electric generation should be able to obtain an exception on that basis alone. Facilities that do not support electric generation help provide gas for other end users, such as local distribution companies (LDCs) that serve city gates. Regarding Henry's second item, the Commission partly addressed this concern with changes to subsection (b)(1)(B) regarding EOR projects. The Commission also declines to add Henry's third item. The Commission understands operators' concerns with receiving notice of their facilities on the electricity supply chain map because a facility's map status affects whether it is required to weatherize pursuant to §3.66. Although §3.65 and §3.66 are related, the purpose of §3.65 is not solely to identify facilities required to weatherize, but to designate facilities as critical customers so that critical customers' power is prioritized during a load-shed event. Thus, an operator's failure to receive notice from the Commission regarding a facility's map status is not a sufficient reason to be exempt from critical designation. Finally, the Commission declines to add Henry's fourth item. Section 3.65 already allows an operator to submit an exception application for other good cause shown, because the list included in subsection (e)(2) merely contains examples. Further, it is not appropriate for the Commission to make changes that impact demand response programs managed by reliability coordinators and outside the Commission's authority to regulate. Operators concerned with demand response program implications may contact their reliability coordinator regarding changes to these programs.

The Commission received several comments regarding amendments proposed in §3.65(e)(2)(D), which allow an operator to submit objective evidence of an electric utility's denial of a facility's critical designation application as a reasonable basis and justification in support of an exception application. The Commission notes that this provision proposed in subsection (e)(2)(D) is adopted as subsection (e)(2)(E) because of the new language related to saltwater disposal facilities adopted as subsection (e)(2)(D).

TCPA's comment stated that for the majority of Texas, the "electric entity" that will receive and review critical designation forms required under 16 TAC §25.52(h) (relating to Reliability and Continuity of Service) will be Transmission and Distribution Utilities (TDUs). TDUs deliver electricity, but in the ERCOT competitive market, the provision of electricity is a transaction between generators and retail electric providers for the benefit of providing service to the customer. Thus, TCPA suggested the word "providing" in proposed subsection (e)(2)(D) be changed to "delivering."

The Commission appreciates this insight from TCPA and adopts §3.65(e)(2)(E) with the requested change.

Commission Shift commented that a denial from an electric utility should not be a reason an operator is eligible for an exception under subsection (e)(2) because designating facilities critical is not the sole purpose of §3.65. PBPA expressed support for the proposed amendment allowing an exception if a facility's critical load request is denied by their utility.

The Commission understands that a facility that receives an exception from critical designation is no longer required to weatherize under the requirements of §3.66. The Commission considers an exception to critical designation and, consequently, weatherization requirements, appropriate when a facility's electric utility has communicated the facility's power will not be prioritized during a weather emergency. It would be unreasonable to require an operator to invest in weatherizing a facility that is a critical customer (i.e., a facility requiring electricity from an electric utility to operate) if the electric utility communicates the customer's electricity will not be prioritized.

ACSC requested a change to subsection (e)(2)(D) to specify electric utilities' authority to deny a request for critical status.

The Commission does not regulate electric utilities and, therefore, declines to make changes addressing electric utilities' authority for denials. However, the Commission notes that Utilities Code §38.074 directs electric utilities to be provided discretion to prioritize power delivery and power restoration among facilities and entities designated critical, as circumstances require.

Commission Shift commented generally on subsection (e)(2) expressing concern that the list contains examples of reasonable bases and justifications such that the Commission could routinely grant exceptions for other reasons not listed in the rule.

Commission Shift is correct that the Commission retains discretion to approve exceptions for additional reasons. However, the Commission included the examples because the Commission considers those reasons sufficient. A request for an exception that does not align with the examples in subsection (e)(2) would require a hearing before it could be approved.

Henry requested the Commission revise §3.65(e) to require the CID director to administratively approve a request for exception if the exception was previously approved for the same facility or facilities.

The Commission declines to add the requested language. An exception will be administratively approved if it meets the requirements of §3.65 at the time the exception request is filed.

Other Comments

Proposed amendments in subsection (e) reference the electricity supply chain map, and the Commission received several comments about the map. Atmos Pipeline Texas (APT), PBPA, TXOGA, and an individual asked that the Commission clarify the process operators should use for adding or removing assets from the map.

These comments are outside the scope of this rulemaking, but the Commission will consider these comments as it works to ensure the map continues to be viable and accurate.

An individual, WaterBridge, and Commission Shift expressed concerns about the confidentiality of the electricity supply chain map.

The Commission does not have authority to address these concerns. The information on the electricity supply chain map is deemed confidential by Texas Utilities Code §38.203.

ACSC and the Joint TDUs (AEP Texas Inc., Entergy Texas, Inc., Oncor Electric Delivery Company LLC, Southwestern Electric Power Company, Southwestern Public Service Company, and Texas-New Mexico Power Company) noted that §3.66 requires a facility to weatherize only if it is designated critical under §3.65 and on the electricity supply chain map. Thus, some facilities may be critical but not on the map and, therefore, are not required to weatherize. The comments stated it does not make sense for utilities to have to prioritize facilities as critical if they are not required to weatherize. The Joint TDUs stated the Commission should require all critical facilities to weatherize, not just those that are included on the map.

The Commission declines to make any changes in response to these comments. The Commission's authority in Natural Resources Code §86.044 to adopt rules requiring gas supply chain facilities to implement measures to prepare to operate during a weather emergency (i.e., "weatherize) is limited to gas supply chain facilities that are (1) included on the electricity supply chain map; and (2) designated critical by the Commission. The legislature included the two elements intentionally. If the legislature intended for all facilities designated critical to weatherize, it would not have included the first element, which limits the list of facilities required to weatherize to those on the electricity supply chain map. Requiring facilities that are not on the map to weatherize goes beyond what was authorized in §86.044.

Commission Shift requested that the Commission clearly explain how both gas production and storage can meet demand needs during the next weather event. The Commission should also disclose its plan for extra supply in the event the supply chain is not functioning in all geographies. The CID should develop systems and processes to regularly compare projected gas demand against the supply that can be generated from facilities designated as critical and subject to the weatherization rule.

The Commission will not "establish a plan for extra supply" because the Commission does not have authority to require facilities to operate during a weather emergency. Further, it is not appropriate to explain production and storage availability, demand needs, or CID systems and processes in §3.65; therefore, the Commission declines to make any changes to the rule in response to these comments.

Finally, the Commission received several comments that address issues outside the scope of the proposed amendments. Two individuals, PBPA, PRS, and Southwest Gas Systems commented about experiencing difficulty with the critical designation and exception request filing processes (the Form CI-D and CI-X filings, respectively).

The Commission is working to improve the filing process and resolve any technical issues that arise. The Commission has also increased its CID staff since the first filing deadline in January 2022, and more staff members are available to assist operators when filing deadlines occur.

Commission Shift expressed concern regarding when operators transfer their critical assets between the Form CI-D filing deadlines and asked how the new operator's contact information will be available if a weather emergency occurs during that timeframe.

The Commission understands this concern. For most critical facilities, the Commission requires a filing upon transfer of a facility to a new operator. The Commission can access this information during an emergency if necessary. The Commission is working to ensure it has accurate information for the remainder of the facilities. The Commission also notes that it coordinated with the PUC when §3.65 was adopted in 2021. The PUC and the electric utilities informed the Commission that the electric utilities create their critical load lists twice per year and cannot continually update the critical load information. Thus, to align with this process and lessen the administrative burden on the utilities, §3.65 requires critical customers to send their electric utility their critical customer information twice per year.

Commission Shift commented that the penalties for violations of §3.65 are too low to incentivize compliance.

The Commission disagrees and declines to make any changes because the penalty rule, §3.107 of this title (relating to Penalty Guidelines for Oil and Gas Violations), was not included in this rulemaking.

Commission Shift expressed concern that ERCOT is still using a redundant form and process to obtain information from operators on whether they represent a critical load. Commission Shift asked the Commission to coordinate with ERCOT to simplify the process for operators and reduce redundancies.

The Commission will communicate this concern to ERCOT but notes that it cannot require ERCOT to change its process.

TEC asked the Commission to provide another tool to electric utilities by allowing electric utilities to obtain assistance from the Commission in parsing critical load applications submitted to the utility.

The Commission is available to assist electric utilities with critical load applications. The Commission does not make any changes to the rule in response to this comment.

NGL Water Solutions requested an opportunity to engage with the Commission to discuss weatherization methods for saltwater disposal wells and systems.

This comment is outside the scope of §3.65 but the Commission notes it will engage with operators when it updates the Weatherization Practices Guidance Document on its website.

Finally, the Commission received a comment from an individual about hydrogen sulfide gas, which is not related to §3.65, and a comment from another individual regarding Commission trainings on §3.65. The Commission makes no changes in response to these comments.

The adopted rule language is summarized in the paragraphs below.

Amendments to subsection (a) provide more certainty regarding the definition of "energy emergency." The Commission adopts amendments to define an event with "potential to result in firm load shed" as when the reliability coordinator of a power region in Texas issues an Energy Emergency Alert Level 1 or 2. More clearly defining when there is a potential for firm load shed will provide operators with more certainty as to when an energy emergency is occurring.

Section 3.66, which was adopted concurrently when these amendments to §3.65 were proposed, contains a related definition. It defines weather emergency as "weather conditions such as freezing temperatures, freezing precipitation, or extreme heat in the facility's county or counties that result in an energy emergency as defined by §3.65 of this title." Comments received on §3.66 noted the lack of certainty in the definition due to its reference to "energy emergency" in §3.65. The adopted amendments to subsection (a) address these concerns.

As noted above, subsection (a) is also adopted with definitions of "Director," "electricity supply chain map," and "EOR project" in response to comments.

The Commission adopts amendments to the list of critical gas suppliers in subsection (b)(1). The Commission received multiple comments on the original proposal of §3.65 expressing concern that the list of critical gas suppliers encompassed too many facilities such that electric utilities may experience a burden in prioritizing the facilities for load-shed purposes. Similarly, comments on §3.66 requested reducing facilities on the list by excluding more gas wells and oil leases with marginal production. The amendments now adopted in §3.65(b)(1) exclude gas wells producing an average of 250 Mcf of natural gas per day or less and oil leases producing an average of 500 Mcf of natural gas per day or less.

The Commission also adopts subsection (b)(1)(B) with changes due to comments on EOR projects.

Third, adopted amendments in subsections (c), (e), and (f) revise requirements triggered by a critical gas supplier's inclusion on the electricity supply chain map produced by the Texas Electricity Supply Chain Security and Mapping Committee. Changes to subsection (c) allow a facility that is not designated a critical gas supplier in subsection (b) an exemption from filing Form CI-D. Additional amendments are adopted in subsection (c) in response to comments requesting clarification on the process to request critical designation.

Amendments to subsection (e) and (f) clarify that if a facility designated critical in subsection (b) is included on the electricity supply chain map, it is not eligible to request an exception from critical designation.

Adopted changes to subsection (e) and (f) restate the exception process to affirmatively state which facilities are eligible for an exception rather than stating the facilities that are not eligible for an exception. The amendments remove the current language in subsection (e) and make current subsection (f) new subsection (e).

Adopted subsection (e) states that a facility designated critical under subsection (b) may request an exception unless the facility is included on the electricity supply chain map. The amendments also clarify the acceptable reasons for requesting an exception. The reasons are examples which are intended to capture the Commission's goal that facilities contributing natural gas to the supply chain in Texas are not eligible for an exception. Subsection (e)(2)(A) and (e)(2)(C) were included in the original proposal of §3.65 when it was adopted effective December 20, 2021. In this rulemaking, the exceptions are moved from subsection (e)(1) to the list in subsection (e)(2). Adopted subsection (e)(2)(B) adds language consistent with Natural Resources Code §81.073, which states, "The commission shall collaborate with the Public Utility Commission of Texas to adopt rules to establish a process to designate certain natural gas facilities and entities associated with providing natural gas in this state as critical customers or critical gas suppliers during energy emergencies" (emphasis added).

The Commission adopts subsection (e)(2) with changes to include new subsection (e)(2)(D), which provides a reasonable basis and justification specific to saltwater disposal facilities in response to comments.

Regarding adopted subsection (e)(2)(E), proposed as subsection (e)(2)(D), it is the Commission's understanding that some facilities designated critical customers were denied as critical loads by their electric utilities. This decision is in the electric utility's discretion. However, if a critical facility is denied as a critical load, the amendments allow the facility to request an exception such that it is not required to comply with §3.65. The exception will not be approved if the utility's denial was not communicated in writing or was due to errors made by the critical facility in submitting its critical customer information. Similarly, the exception will not be approved if the denial was based on the utility's administrative reasons, such as the facility's power is already prioritized due to its location on a meter that is already a critical load.

Other adopted amendments merely update internal references due to the removal of subsection (e) and the renaming of subsection (f).

The Commission adopts the amendments under Texas Natural Resources Code §81.073, which requires the Commission to adopt rules to establish a process to designate natural gas facilities and entities associated with providing natural gas in this state as critical customers or critical gas suppliers during an energy emergency; and Texas Natural Resources Code, §81.051 and §81.052, which give the Commission jurisdiction over all persons owning or engaged in drilling or operating oil or gas wells in Texas and the authority to adopt all necessary rules for governing and regulating persons and their operations under the jurisdiction of the Commission.

Statutory authority: Natural Resources Code §§81.051, 81.052, and 81.073.

Cross reference to statute: Natural Resources Code Chapter 81.

§3.65.Critical Designation of Natural Gas Infrastructure.

(a) Definitions.

(1) In this section, the term "energy emergency" means any event that results in firm load shed or has the potential to result in firm load shed required by the reliability coordinator of a power region in Texas. An event that has the "potential to result in firm load shed" is when the reliability coordinator of a power region in Texas has issued an Energy Emergency Alert Level 1 or 2.

(2) In this section, the term "critical customer information" means the information required on Commission Form CI-D and any attachments.

(3) In this section, "any volume of gas indicated in Mcf/day" means the average daily production from the well's six most recently filed monthly production reports. Wells without six months of production reports shall average the production from the well's production reports on file with the Commission or use the production volume from the well's initial potential test or deliverability test if the well has not yet filed a production report.

(4) In this section, the term "electricity supply chain map" means the electricity supply chain map produced by the Texas Electricity Supply Chain Security and Mapping Committee.

(5) In this section, the term "Director" means the Director of the Critical Infrastructure Division or the director's delegate.

(6) In this section, the term "EOR project" means an enhanced oil recovery project as defined in §3.50(c)(6) of this title (relating to Enhanced Oil Recovery Projects-Approval and Certification for Tax Incentive) with at least one injection well permitted under §3.46 of this title (relating to Fluid Injection into Productive Reservoirs) whether or not the project has received Commission approval or certification under §3.50 of this title.

(b) Critical designation criteria. The following facilities are designated critical during an energy emergency:

(1) Critical Gas Supplier. The following facilities are designated a critical gas supplier:

(A) gas wells producing gas in excess of 250 Mcf/day;

(B) oil leases producing casinghead gas in excess of 500 Mcf/day, except for EOR projects provided the EOR project consumes more energy than it produces calculated by comparing the amount of electricity used to the amount of gas produced both in Million British Thermal Units (MMBTU);

(C) gas processing plants;

(D) natural gas pipelines and pipeline facilities including associated compressor stations and control centers;

(E) local distribution company pipelines and pipeline facilities including associated compressor stations and control centers;

(F) underground natural gas storage facilities;

(G) natural gas liquids transportation and storage facilities; and

(H) saltwater disposal facilities including saltwater disposal pipelines.

(2) Critical Customer. A critical customer is a critical gas supplier that requires electricity delivered by an electric entity to operate. A critical customer is required to provide critical customer information pursuant to subsection (f) of this section to the electric entities described in §25.52(h) of this title (relating to Reliability and Continuity of Service) and Texas Utilities Code §38.074(b)(1) so that those electric entities may prioritize the facilities in accordance with Texas Utilities Code §38.074(b)(2) and (b)(3). Priority for load shed purposes during an energy emergency is described by §25.52(h)(2) of this title and any guidance issued thereunder by the Public Utility Commission.

(c) Request for critical designation if not designated critical in subsection (b) of this section. A facility that is not designated critical under subsection (b) of this section may write to the Commission to apply to be designated critical if the facility's operation is required in order for another facility designated critical to operate. The applicant shall include objective evidence that the facility's operation is required for another facility designated critical in subsection (b) of this section to operate. The director will review the application and if the application is approved, the facility shall submit Form CI-D. If the request is denied, the applicant may request a hearing.

(d) Acknowledgment of critical status. Except as provided by subsection (e) of this section, an operator of a facility designated as critical under subsection (b) or (c) of this section shall acknowledge the facility's critical status by filing Form CI-D as provided in this subsection. In the year 2022, the Form CI-D acknowledgment shall be filed bi-annually by January 15, 2022, and either September 1, 2022, or 30 days from the date the map is produced by the Texas Electricity Supply Chain Security and Mapping Committee, whichever is later. Beginning in 2023, the Form CI-D acknowledgment shall be filed bi-annually by March 1 and September 1 of each year.

(e) Critical designation exception.

(1) A facility listed in subsection (b) of this section that is not included on the electricity supply chain map produced by the Texas Electricity Supply Chain Security and Mapping Committee may apply for an exception. An applicant shall demonstrate with objective evidence a reasonable basis and justification in support of the application. The Director of the Critical Infrastructure Division will administratively approve or deny a request for an exception. If the request is denied, the Division will notify the applicant and the applicant may request a hearing to challenge the denial. The party requesting the hearing shall have the burden of proof.

(2) Examples of a reasonable basis and justification for which an exception may be granted include, but are not limited to, the following:

(A) All of the natural gas produced at the facility is consumed on site;

(B) All of the natural gas produced, processed, or delivered by the facility is consumed outside of this state;

(C) The facility does not provide gas for third-party use;

(D) For saltwater disposal facilities and saltwater disposal pipelines, the facility or pipeline does not support a facility designated critical in subsection (b)(1)(A)-(G) of this section; or

(E) The electric entity delivering electricity to the facility has provided notice that the facility's request for critical designation status was rejected, denied, or otherwise disapproved by the electric utility; provided, however, that the electric utility communicated its determination in writing, and the decision was for reasons other than the lack of correct identifying information or other administrative reasons.

(3) An applicant for exception shall submit a Form CI-X exception application that identifies each facility for which an exception is requested. The Form CI-X shall be accompanied by an exception application fee. The amount of the fee is $150 as established in Chapter 81, Texas Natural Resources Code.

(A) In the year 2022, the Form CI-X exception application shall be filed bi-annually by January 15, 2022, and either September 1, 2022, or 30 days from the date the map is produced by the Texas Electricity Supply Chain Security and Mapping Committee, whichever is later. Beginning in 2023, the Form CI-X exception application shall be filed bi-annually by March 1 and September 1 of each year.

(B) Once an operator has an approved Form CI-X on file with the Commission, the operator is not required to pay the $150 exception application fee when the operator updates the facilities identified on its Form CI-X.

(f) Providing critical customer information. A critical customer shall provide the critical customer information to the electric entities described in §25.52 of this title and Texas Utilities Code §38.074(b)(1) unless the critical customer is granted an exception under subsection (e) of this section. The critical customer information shall be provided in accordance with §25.52 of this title. The operator shall certify on its Form CI-D that it has provided the critical customer information to its electric entity.

(g) Confidentiality of information filed pursuant to this section. A person filing information with the Commission that the person contends is confidential by law shall notify the Commission on the applicable form. If the Commission receives a request under the Texas Public Information Act (PIA), Texas Government Code, Chapter 552, for materials that have been designated confidential, the Commission will notify the filer of the request in accordance with the provisions of the PIA so that the filer can take action with the Office of the Attorney General to oppose release of the materials.

(h) Exceptions not transferable. Exceptions are not transferable upon a change of operatorship. When a facility is transferred, both the transferor operator and the transferee operator shall ensure the transfer is reflected on each operator's Form CI-D or Form CI-X when the applicable form update is submitted in accordance with the bi-annual filing timelines in subsections (d) and (e) of this section. If the facility has an exception under subsection (e) of this section, the exception shall remain in effect until the next bi-annual filing deadline. If the transferee operator seeks to continue the exception beyond that time period, the transferee operator shall indicate the transferred facility on the Form CI-X pursuant to subsection (e) of this section.

(i) Failure to file or provide required information. An operator who fails to comply with this section may be subject to penalties under §3.107 of this title (relating to Penalty Guidelines for Oil and Gas Violations).

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 November 1, 2022.

TRD-202204311

Haley Cochran

Assistant General Counsel, Office of General Counsel

Railroad Commission of Texas

Effective date: November 21, 2022

Proposal publication date: September 16, 2022

For further information, please call: (512) 475-1295


PART 2. PUBLIC UTILITY COMMISSION OF TEXAS

CHAPTER 25. SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS

SUBCHAPTER B. CUSTOMER SERVICE AND PROTECTION

16 TAC §25.43

The Public Utility Commission of Texas (commission) adopts amendments to 16 Texas Administrative Code (TAC) §25.43, relating to Provider of Last Resort (POLR). The commission adopts this rule with changes to the proposed text as published in the September 30, 2022, issue of the Texas Register (47 TexReg 6363). The amended rule updates the POLR formulas for residential, and small and medium non-residential customer classes to reduce the likelihood that the POLR rate is lower than market rates. The rule will be republished.

The amended provisions include §25.43(j)(3) which would require the Electricity Facts Label (EFL) for the POLR rate to be filed by the large service provider (LSP) on a monthly basis by the 10th of each month; §25.43(m)(2)(A) and (B) which would revise the POLR rates applicable to residential, and small and medium non-residential customers; and §25.43(m)(4) which would authorize the commission to direct an LSP to adjust the POLR rate under §25.43(m)(2) upon a showing of good cause by an affected person.

The commission received comments on the proposed rule from the REP Coalition and the Office of Public Utility Counsel (OPUC).

General Comments in Support

OPUC and the REP Coalition provided general comments in support of this proposed rulemaking.

§25.43(m)(2)(A)(iii)

Proposed §25.43(m)(2)(A)(iii) prohibits the LSP energy charge from exceeding 140% of the preceding month's LSP energy charge multiplied by an adjustment factor and for that adjustment to be set to 1.0 every calendar year. Proposed §25.43(m)(2)(A)(iii) also authorizes commission staff to file a recommendation for the commission to set a different adjustment factor and requires an LSP offering POLR service to declare the adjustment factor on its EFL.

Residential Customer LSP Energy Charge Cap

The REP Coalition argued that the cap under §25.43(m)(2)(A)(iii) should be increased to 160%, rather than the proposed 140%, which would minimize the risk of market rates rising above the LSP POLR rate. The REP Coalition noted that a 140% ceiling would have been exceeded five times in 2022, while a 160% ceiling would have been exceeded only once. The REP Coalition asserted that a 140% cap on the LSP energy charge would also result in prepaid service being capped at a below-market price "approximately 40% of the year."

Commission Response

The commission agrees with the REP Coalition that the LSP POLR rate should be slightly above market rates to account for the additional risk that LSPs face in terms of potentially having to assume a large number of unexpected customers after a mass transition to POLR event. The commission also agrees that the LSP POLR rate being capped below market rates has the additional consequence of capping the rate for prepaid service below market rates. Accordingly, the commission modifies the rule to increase the cap on how much the residential LSP energy charge can increase each month from 140 percent to 160 percent. This will allow the monthly LSP POLR rate to adjust more quickly in response to actual market conditions while still providing customers with protection against the significant price spikes that a monthly formula could produce following events such as Winter Storm Uri.

Residential LSP Customer Energy Charge Adjustment Factor

The REP Coalition stated that language in the proposed rule regarding the adjustment factor is unnecessary given the other recommendations the REP Coalition made and should be deleted if the REP Coalition's recommendations are adopted.

Commission Response

The commission agrees with the REP Coalition's recommendation regarding deletion of the adjustment factor under §25.43(m)(2)(A)(iii) and adopts its proposed language. Increasing the cap to 160% will allow the LSP POLR rate to more frequently remain above market rates without an adjustment factor. Removing the adjustment factor will also reduce the complexity of administering the formula.

The REP Coalition expressed concern that, if the commission elects to implement the proposed adjustment factor, such a mechanism would be too time intensive and unwieldy to utilize when a cap adjustment becomes necessary. Specifically, a recommendation filing by commission staff, followed by commission consideration and approval during an open meeting may take too much time to properly address the circumstances during a mass transition. The REP Coalition instead recommended authority to adjust the cap be delegated to the executive director so that the adjustment can be made in a more expedient manner. The REP Coalition further recommended clarifying that, under §25.43(m)(2)(A)(iii), the default adjustment factor of 1.0 is a floor. The REP Coalition provided draft language consistent with its recommendation.

Commission Response

The adjustment factor for the residential customer POLR formula has been removed from the rule, rendering the REP Coalition's comments moot.

The REP Coalition recommended the phrase "LSP offering POLR service" under §25.43(m)(2)(A)(iii) be reworded to "LSP designated under subsection (j)" because POLR service is a "temporary, last resort service that is not meant to be proactively offered by LSPs." The REP Coalition stated that the provision specifically applies to the largest LSP for each customer class or POLR area designated under §25.43(j)(3) to supply the example EFL to commission staff and not all LSPs. The REP Coalition also indicated that the proposed language of §25.43(m)(2)(A)(iii) would require an LSP to declare the adjustment factor on the EFL, but if the adjustment factor was exercised either by the commission or reset every calendar year, the LSP would be "required to create a second EFL shortly after creating the month's initial EFL." The REP Coalition noted that the inclusion of the adjustment factor is of minimal use to customers as the average prices disclosed on the EFL are typically the most helpful information. The REP Coalition provided draft language consistent with its recommendation but noted that if the adjustment factor is not retained in the adopted rule, then the language relating to it under §25.43(m)(2)(A)(iii) may be omitted entirely.

Commission Response

The adjustment factor for the residential customer POLR formula has been removed from the rule, rendering the REP Coalition's comments moot.

§25.43(m)(2)(B)(ii) and (iii)

Proposed §25.43(m)(2)(B)(ii) provides that the LSP customer charge component of the small and medium non-residential customer POLR rate formula is $0.025 cents per kWh. Proposed §25.43(m)(2)(B)(iii) sets the LSP demand charge component of the small and medium non-residential customer POLR rate formula be $2.00 per kW, per month, for customers that have a demand meter, and $50.00 per month for customers that do not have a demand meter.

Small and Medium Non-Residential Customer - LSP Customer Charge

The REP Coalition noted that the proposed rule does not address any changes to the LSP customer charge for POLR service to small and medium non-residential customers under §25.43(m)(2)(B)(ii). The REP Coalition recommended the LSP customer charge under §25.43(m)(2)(B)(ii) be increased to $0.09 per kWh and the LSP demand charge under §25.43(m)(2)(B)(iii) be deleted. The REP Coalition stated that not all small and medium non-residential customers have a demand meter and that the "alternative $50 monthly fee for small and medium non-residential customers without a demand meter may not provide an equitable approximation." If the commission elects to retain the LSP demand charge, then the REP Coalition alternatively recommended increasing the customer charge by $0.03 to $0.055 to appropriately account for increased costs. Specifically, the REP Coalition indicated that the increased customer charge for small and medium non-residential customers is commensurate with the increase to the LSP customer charge for residential POLR service.

Commission Response

The commission agrees that it is appropriate to modify the small and medium non-residential LSP POLR formula consistent with the modification made to the residential formula. Both customer classes are subject to the same underlying wholesale market conditions. The commission modifies the rule consistent with the REP Coalition's primary proposal to increase the LSP customer charge from $0.025 to $0.09 under §25.43(m)(2)(B)(ii) and deletes the LSP demand charge under §25.43(m)(2)(B)(iii). Further, eliminating the demand charge reduces the complexity of administering the formula.

§25.43(m)(2)(B)(iv)

Proposed §25.43(m)(2)(B)(iv) prohibits the LSP energy charge from exceeding 140% of the preceding month's LSP energy charge multiplied by the adjustment factor and for the cap to be set to 1.0 every calendar year. Proposed §25.43(m)(2)(B)(iv) authorizes commission staff to file a recommendation for the commission to set a different adjustment factor and requires an LSP offering POLR service to declare the adjustment factor on its EFL.

Small and Medium Non-Residential Customer - Energy Charge Cap

The REP Coalition recommended the 140% cap under §25.43(m)(2)(B)(iv) be increased to 160% for the same reasons provided in its comments related to §25.43(m)(2)(A)(iii).

Commission Response

The commission agrees with the REP Coalition's proposal to increase the energy charge cap to 160% for the same reasons discussed in response to comments related to the Residential Customer LSP Energy Charge Cap.

Small and Medium Non-Residential Customer - LSP Energy Charge Adjustment Factor

If the commission declines to implement its primary recommendation to delete the adjustment factor, then the REP Coalition recommended that authority to adjust the cap be delegated to the executive director and clarify in §25.43(m)(2)(B)(iv) that the default adjustment factor of 1.0 is a floor. The REP Coalition also recommended the phrase "offering POLR service" be removed from §25.43(m)(2)(B)(iv) and that the provision be reworded to indicate it is relevant only to LSPs designated under subsection (j) by insertion of the phrase "An LSP designated under subsection (j)."REP Coalition also recommended §25.43(m)(2)(B)(iv) be revised to not require an LSP to issue a second EFL after the adjustment factor is exercised, either by the commission or every calendar year, and instead allowing the adjustment factor to be built into the prices on the EFL rather than include the adjustment factor as a separate variable on the EFL. The REP Coalition also noted that if the adjustment factor is not retained in the adopted rule, then the language relating to it under §25.43(m)(2)(B)(iv) may be omitted entirely. The REP Coalition offered alternative draft language if the commission elects to maintain the LSP demand charge for the small and medium non-residential customer POLR rate, rather than increasing the LSP customer charge.

Commission Response

The adjustment factor for the small and medium non-commercial customer POLR formula has been removed from the rule, rendering the REP Coalition's comments moot.

§25.43(m)(4) - Good Cause Exception

Proposed §25.43(m)(4) provides, upon a showing of good cause by an affected person, the commission may direct an LSP to adjust the rate under §25.43(m)(2), if necessary to ensure that the rate is sufficient to allow an LSP to recover its costs of providing service.

The REP Coalition expressed support for the authorization permitting any affected person to show good cause in support of an adjustment to the LSP POLR rates. However, the REP Coalition indicated that, because the LSP POLR rates serve as the cap on the price for prepaid products, §25.43(m)(4) should be amended to reflect it is not solely applicable to LSPs, but to other affected REPs who "may not have the information to prove an LSPs' costs." The REP Coalition also recommended inserting language in §25.43(m)(4) that would clarify that any REP with a product subject to the POLR calculations under §25.43(m) is permitted recover costs associated with the provision of service to customers served under such products. The REP Coalition provided draft language consistent with its recommendations.

Commission Response

The commission declines to modify the standard for adjusting the LSP POLR rate to ensuring that the rate is sufficient to allow "any REP with products subject to the calculation(s) under subsection (m) to recover its costs of providing service" as requested by the REP Coalition. REPs are not guaranteed cost recovery for any competitively-offered products, including prepaid products, and it would be inappropriate for the commission to consider an individual provider's costs of providing a competitive product when setting the LSP POLR rate. However, the commission agrees with the REP Coalition that providers of prepaid service are subject to the LSP POLR rate cap but may not have access to the information required to support a good cause motion based on the proposed standard of "if necessary to ensure that the rate is sufficient to allow an LSP to recover its costs of providing service." Accordingly, the commission modifies the rule to provide that the commission may direct an LSP to adjust the LSP POLR rate if necessary to ensure the rate is consistent with prevailing market conditions. This modification will allow LSP POLR providers and providers of prepaid products to support claims that the LSP POLR rate needs to be adjusted.

The commission also agrees with the REP Coalition's recommendation to revise §25.43(m)(4) to indicate the good cause rate adjustment is related to cost recovery associated with products subject to the POLR formula. This revision is consistent with the PURA §39.107(g) provision that prepaid electric service sold to residential customers may not be sold at a price higher than the price charged by the provider of last resort.

The REP Coalition also expressed concern that the existing good cause mechanism, which requires commission action, may be inefficient to address the severe circumstances such as those immediately preceding a mass transition as such action would have to be taken up at an open meeting." The REP Coalition accordingly recommended that the authority to determine a good cause exception be delegated to the commission's executive director with additional authority to shorten the notice window if circumstances require it.

Commission Response

The commission declines to delegate authority to the executive director at this time. The commission may, at a future time, delegate authority to the executive director on its own initiative.

This amendment is adopted under the following provisions of Public Utility Regulatory Act (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 and enforce rules reasonably required in the exercise of its powers and jurisdiction; §17.003, which requires electric utilities and retail electric providers to provide clear and uniform information about rates, terms, services, involuntary load shed procedures, critical designations, and procedures for applying for critical designations; §17.102, which directs the commission to adopt and enforce rules requiring that charges on an electric service provider's bill be clearly and easily identified, §39.101, which requires the commission to ensure that retail customer protections are established that entitle a customer to safe, reliable, and reasonably priced electricity, and other protections; and §39.106, which requires that the commission designate providers of last resort.

Cross reference to statutes: Public Utility Regulatory Act §§14.001, 14.002, 17.003, 17.102, 39.101, 39.106

§25.43.Provider of Last Resort (POLR).

(a) Purpose. This section establishes the requirements for Provider of Last Resort (POLR) service and ensures that it is available to any requesting retail customer and any retail customer who is transferred to another retail electric provider (REP) by the Electric Reliability Council of Texas (ERCOT) because the customer's REP failed to provide service to the customer or failed to meet its obligations to the independent organization.

(b) Application. The provisions of this section relating to the selection of REPs providing POLR service apply to all REPs that are serving retail customers in transmission and distribution utility (TDU) service areas. This section does not apply when an electric cooperative or a municipally owned utility (MOU) designates a POLR provider for its certificated service area. However, this section is applicable when an electric cooperative delegates its authority to the commission in accordance with subsection (r) of this section to select a POLR provider for the electric cooperative's service area. All filings made with the commission pursuant to this section, including filings subject to a claim of confidentiality, must be filed with the commission's Filing Clerk in accordance with the commission's Procedural Rules, Chapter 22, Subchapter E, of this title (relating to Pleadings and other Documents).

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

(1) Affiliate--As defined in §25.107 of this title (relating to Certification of Retail Electric Providers (REPs).

(2) Basic firm service--Electric service that is not subject to interruption for economic reasons and that does not include value-added options offered in the competitive market. Basic firm service excludes, among other competitively offered options, emergency or back-up service, and stand-by service. For purposes of this definition, the phrase "interruption for economic reasons" does not mean disconnection for non-payment.

(3) Billing cycle--A period bounded by a start date and stop date that REPs and TDUs use to determine when a customer used electric service.

(4) Billing month--Generally a calendar accounting period (approximately 30 days) for recording revenue, which may or may not coincide with the period a customer's consumption is recorded through the customer's meter.

(5) Business day--As defined by the ERCOT Protocols.

(6) Large non-residential customer--A non-residential customer who had a peak demand in the previous 12-month period at or above one megawatt (MW).

(7) Large service provider (LSP)--A REP that is designated to provide POLR service pursuant to subsection (j) of this section.

(8) Market-based product - A month-to-month product that is either offered to or matches the rate of a product offered to non-POLR customers of the REP for the same TDU territory and customer class. A month-to-month contract may not contain a termination fee or penalty. For purposes of this section, a rate for residential customers that is derived by applying a positive or negative multiplier to the rate described in subsection (m)(2) of this section is not a market-based product.

(9) Mass transition--The transfer of customers as represented by ESI IDs from a REP to one or more POLR providers pursuant to a transaction initiated by the independent organization that carries the mass transition (TS) code or other code designated by the independent organization.

(10) Medium non-residential customer--A non-residential retail customer who had a peak demand in the previous 12-month period of 50 kilowatt (kW) or greater, but less than 1,000 kW.

(11) POLR area--The service area of a TDU in an area where customer choice is in effect.

(12) POLR provider--A volunteer retail electric provider (VREP) or LSP that may be required to provide POLR service pursuant to this section.

(13) Residential customer--A retail customer classified as residential by the applicable TDU tariff or, in the absence of classification under a tariff, a retail customer who purchases electricity for personal, family, or household purposes.

(14) Transitioned customer--A customer as represented by ESI IDs that is served by a POLR provider as a result of a mass transition under this section.

(15) Small non-residential customer--A non-residential retail customer who had a peak demand in the previous 12-month period of less than 50 kW.

(16) Voluntary retail electric provider (VREP)--A REP that has volunteered to provide POLR service pursuant to subsection (i) of this section.

(d) POLR service.

(1) There are two types of POLR providers: VREPs and LSPs.

(2) For the purpose of POLR service, there are four classes of customers: residential, small non-residential, medium non-residential, and large non-residential.

(3) A VREP or LSP may be designated to serve any or all of the four customer classes in a POLR area.

(4) A POLR provider must offer a basic, standard retail service package to customers it is designated to serve, which is limited to:

(A) Basic firm service; and

(B) Call center facilities available for customer inquiries.

(5) A POLR provider must, in accordance with §25.108 of this title (relating to Financial Standards for Retail Electric Providers Regarding the Billing and Collection of Transition Charges), fulfill billing and collection duties for REPs that have defaulted on payments to the servicer of transition bonds or to TDUs.

(6) Each LSP's customer billing for residential customers taking POLR service under a rate prescribed by subsection (m)(2) of this section must contain notice to the customer that other competitive products or services may be available from the LSP or another REP. The notice must also include contact information for the LSP, and the Power to Choose website, and must include a notice from the commission in the form of a bill insert or a bill message with the header "An Important Message from the Public Utility Commission Regarding Your Electric Service" addressing why the customer has been transitioned to an LSP, a description of the purpose and nature of POLR service, and explaining that more information on competitive markets can be found at www.powertochoose.org, or toll-free at 1-866-PWR-4-TEX (1-866-797-4839).

(e) Standards of service.

(1) An LSP designated to serve a class in a given POLR area must serve any eligible customer requesting POLR service or assigned to the LSP pursuant to a mass transition in accordance with the Standard Terms of Service in subsection (f)(1) of this section for the provider customer's class. However, in lieu of providing terms of service to a transitioned customer under subsection (f) of this section and under a rate prescribed by subsection (m)(2) of this section an LSP may at its discretion serve the customer pursuant to a market-based month-to-month product, provided it serves all transitioned customers in the same class and POLR area pursuant to the product.

(2) A POLR provider must abide by the applicable customer protection rules as provided for under Subchapter R of this chapter (relating to Customer Protection Rules for Retail Electric Service), except that if there is an inconsistency or conflict between this section and Subchapter R of this chapter, the provisions of this section apply. However, for the medium non-residential customer class, the customer protection rules as provided for under Subchapter R of this chapter do not apply, except for §25.481 of this title (relating to Unauthorized Charges), §25.485(a) - (b) of this title (relating to Customer Access and Complaint Handling), and §25.495 of this title (relating to Unauthorized Change of Retail Electric Provider).

(3) An LSP that has received commission approval to designate one of its affiliates to provide POLR service on behalf of the LSP pursuant to subsection (k) of this section must retain responsibility for the provision of POLR service by the LSP affiliate and remains liable for violations of applicable laws and commission rules and all financial obligations of the LSP affiliate associated with the provisioning of POLR service on its behalf by the LSP affiliate.

(f) Customer information.

(1) The Standard Terms of Service prescribed in subparagraphs (A) - (D) of this paragraph apply to POLR service provided by an LSP under a rate prescribed by subsection (m)(2) of this section.

(A) Standard Terms of Service, POLR Provider Residential Service:

Figure: 16 TAC §25.43(f)(1)(A) (No change.)

(B) Standard Terms of Service, POLR Provider Small Non-Residential Service:

Figure: 16 TAC §25.43(f)(1)(B) (No change.)

(C) Standard Terms of Service, POLR Provider Medium Non-Residential Service:

Figure: 16 TAC §25.43(f)(1)(C) (No change.)

(D) Standard Terms of Service, POLR Provider Large Non-Residential Service:

Figure: 16 TAC §25.43(f)(1)(D) (No change.)

(2) An LSP providing service under a rate prescribed by subsection (m)(2) of this section must provide each new customer the applicable Standard Terms of Service. Such Standard Terms of Service must be updated as required under §25.475(f) of this title (relating to General Retail Electric Provider Requirements and Information Disclosures to Residential and Small Commercial Customers).

(g) General description of POLR service provider selection process.

(1) Each REP must provide information to the commission in accordance with subsection (h)(1) of this section. Based on this information, the commission's designated representative will designate REPs that are eligible to serve as POLR providers in areas of the state in which customer choice is in effect, except that the commission will not designate POLR providers in the service areas of MOUs or electric cooperatives unless an electric cooperative has delegated to the commission its authority to designate the POLR provider, in accordance with subsection (r) of this section.

(2) POLR providers must serve two-year terms. The initial term for POLR service in areas of the state where retail choice is not in effect as of the effective date of the rule must be set at the time POLR providers are initially selected in such areas.

(h) REP eligibility to serve as a POLR provider. In each even-numbered year, the commission will determine the eligibility of certified REPs to serve as POLR providers for a term scheduled to commence in January of the next year.

(1) Each REP must provide information to the commission necessary to establish its eligibility to serve as a POLR provider for the next term. A REP must file, by July 10th of each even-numbered year, by service area, information on the classes of customers it provides service to, and for each customer class, the number of ESI IDs the REP serves and the retail sales in megawatt-hours for the annual period ending March 31 of the current year. As part of that filing, a REP may request that the commission designate one of its affiliates to provide POLR service on its behalf pursuant to subsection (k) of this section in the event that the REP is designated as an LSP. The independent organization must provide to the commission the total number of ESI ID and total MWh data for each class. Each REP must also provide information on its technical capability and financial ability to provide service to additional customers in a mass transition. The commission's determination regarding eligibility of a REP to serve as POLR provider under the provisions of this section will not be considered confidential information.

(2) Eligibility to be designated as a POLR provider is specific to each POLR area and customer class. A REP is eligible to be designated a POLR provider for a particular customer class in a POLR area, unless:

(A) A proceeding to revoke or suspend the REP's certificate is pending at the commission, the REP's certificate has been suspended or revoked by the commission, or the REP's certificate is deemed suspended pursuant to §25.107 of this title (relating to Certification of Retail Electric Providers (REPs));

(B) The sum of the numeric portion of the REP's percentage of ESI IDs served and percentage of retail sales by MWhs in the POLR area, for the particular class, is less than 1.0;

(C) The commission does not reasonably expect the REP to be able to meet the criteria set forth in subparagraph (B) of this paragraph during the entirety of the term;

(D) On the date of the commencement of the term, the REP or its predecessor will not have served customers in Texas for at least 18 months;

(E) The REP does not serve the applicable customer class, or does not have an executed delivery service agreement with the service area TDU;

(F) The REP is certificated as an Option 2 REP under §25.107 of this title;

(G) The REP's customers are limited to its own affiliates;

(H) A REP files an affidavit stating that it does not serve small or medium non-residential customers, except for the low-usage sites of the REP's large non-residential customers, or commonly owned or franchised affiliates of the REP's large non-residential customers and opts out of eligibility for either, or both of the small or medium non-residential customer classes; or

(I) The REP does not meet minimum financial, technical and managerial qualifications established by the commission under §25.107 of this title.

(3) For each term, the commission will publish the names of all REPs eligible to serve as a POLR provider under this section for each customer class in each POLR area and will provide notice to REPs determined to be eligible to serve as a POLR provider. A REP may challenge its eligibility determination within five business days of the notice of eligibility by filing with the commission additional documentation that includes the specific data, the specific calculation, and a specific explanation that clearly illustrate and prove the REP's assertion. Commission staff will verify the additional documentation and, if accurate, reassess the REP's eligibility. Commission staff will notify the REP of any change in eligibility status within 10 business days of the receipt of the additional documentation. A REP may then appeal to the commission through a contested case if the REP does not agree with the staff determination of eligibility. The contested status will not delay the designation of POLR providers.

(4) A standard form may be created by the commission for REPs to use in filing information concerning their eligibility to serve as a POLR provider.

(5) If ERCOT or a TDU has reason to believe that a REP is no longer capable of performing POLR responsibilities, ERCOT or the TDU must make a filing with the commission detailing the basis for its concerns and must provide a copy of the filing to the REP that is the subject of the filing. If the filing contains confidential information, ERCOT or the TDU must file the confidential information in accordance with §22.71 of this title (relating to Filing of Pleadings, Documents, and Other Materials). Commission staff will review the filing, and will request that the REP demonstrate that it still meets the qualifications to provide the service. The commission staff may initiate a proceeding with the commission to disqualify the REP from providing POLR service. No ESI IDs will be assigned to a POLR provider after the commission staff initiates a proceeding to disqualify the POLR provider, unless the commission by order confirms the POLR provider's designation.

(i) VREP list. Based on the information provided in accordance with this subsection and subsection (h) of this section, the commission will post the names of VREPs on its webpage, including the aggregate customer count offered by VREPs. A REP may submit a request to be a VREP no earlier than June 1, and no later than July 31, of each even-numbered year unless otherwise determined by the executive director. This filing must include a description of the REP's capabilities to serve additional customers as well as the REP's current financial condition in enough detail to demonstrate that the REP is capable of absorbing a mass transition of customers without technically or financially distressing the REP and the specific information set out in this subsection. The commission's determination regarding eligibility of a REP to serve as a VREP, under the provisions of this section, will not be considered confidential information.

(1) A VREP must provide to the commission the name of the REP, the appropriate contact person with current contact information, which customer classes the REP is willing to serve within each POLR area, and the number of ESI IDs the REP is willing to serve by customer class and POLR area in each transition event.

(2) A REP that has met the eligibility requirements of subsection (h) of this section and provided the additional information set out in this subsection is eligible for designation as a VREP.

(3) Commission staff will make an initial determination of the REPs that are to serve as a VREP for each customer class in each POLR area and publish their names. A REP may challenge its eligibility determination within five business days of the notice of eligibility by submitting to commission staff additional evidence of its capability to serve as a VREP. Commission staff will reassess the REP's eligibility and notify the REP of any change in eligibility status within 10 business days of the receipt of the additional documentation. A REP may then appeal to the commission through a contested case if the REP does not agree with the staff determination of eligibility. The contested status will not delay the designation of VREPs.

(4) A VREP may file a request at any time to be removed from the VREP list or to modify the number of ESI IDs that it is willing to serve as a VREP. If the request is to increase the number of ESI IDs, it must provide information to demonstrate that it is capable of serving the additional ESI IDs, and the commission staff will make an initial determination, which is subject to an appeal to the commission, in accordance with the timelines specified in paragraph (3) of this subsection. If the request is to decrease the number of ESI IDs, the request must be effective five calendar days after the request is filed with the commission; however, after the request becomes effective the VREP must continue to serve ESI IDs previously acquired through a mass transition event as well as ESI IDs the VREP acquires from a mass transition event that occurs during the five-day notice period. If in a mass transition a VREP is able to acquire more customers than it originally volunteered to serve, the VREP may work with commission staff and ERCOT to increase its designation. Changes approved by commission staff will be communicated to ERCOT and must be implemented for the current allocation if possible.

(5) ERCOT or a TDU may challenge a VREP's eligibility. If ERCOT or a TDU has reason to believe that a REP is no longer capable of performing VREP responsibilities, ERCOT or the TDU must make a filing with the commission detailing the basis for its concerns and must provide a copy of the filing to the REP that is the subject of the filing. If the filing contains confidential information, ERCOT or the TDU must file it in accordance with §25.71 of this title (relating to General Procedures, Requirements and Penalties). Commission staff will review the filing of ERCOT and if commission staff concludes that the REP should no longer provide VREP service, it will request that the REP demonstrate that it still meets the qualifications to provide the service. The commission staff may initiate a proceeding with the commission to disqualify the REP from providing VREP service. No ESI IDs will be assigned to a VREP after the commission staff initiates a proceeding to disqualify the VREP, unless the commission by order confirms the VREP's designation.

(j) LSPs. This subsection governs the selection and service of REPs as LSPs.

(1) The REPs eligible to serve as LSPs must be determined based on the information provided by REPs in accordance with subsection (h) of this section. However, for new TDU service areas that are transitioned to competition, the transition to competition plan approved by the commission may govern the selection of LSPs to serve as POLR providers.

(2) In each POLR area, for each customer class, the commission will designate up to 15 LSPs. The eligible REPs that have the greatest market share based upon retail sales in megawatt-hours, by customer class and POLR area must be designated as LSPs. Commission staff will designate the LSPs by October 15th of each even-numbered year, based upon the data submitted to the commission under subsection (h) of this section. Designation as a VREP does not affect a REP's eligibility to also serve as an LSP.

(3) For the purpose of calculating the POLR rate for each customer class in each POLR area, an EFL must be completed by the LSP that has the greatest market share in accordance with paragraph (2) of this subsection. The Electricity Facts Label (EFL) must be supplied to commission staff electronically for placement on the commission webpage by the 10th of each month. Where REP-specific information is required to be inserted in the EFL, the LSP supplying the EFL must note that such information is REP-specific.

(4) An LSP serving transitioned residential and small non-residential customers under a rate prescribed by subsection (m)(2) of this section must move such customers to a market-based month-to-month product, with pricing for such product to be effective no later than either the 61st day of service by the LSP or beginning with the customer's next billing cycle date following the 60th day of service by the LSP. For each transition event, all such transitioned customers in the same class and POLR area must be served pursuant to the same product terms, except for those customers specified in subparagraph (B) of this paragraph.

(A) The notice required by §25.475(d) of this title to inform the customers of the change to a market-based month-to-month product may be included with the notice required by subsection (t)(3) of this section or may be provided 14 days in advance of the change. If the §25.475(d) notice is included with the notice required by subsection (t)(3) of this section, the LSP may state that either or both the terms of service document and EFL for the market-based month-to-month product will be provided at a later time, but no later than 14 days before their effective date.

(B) The LSP is not required to transfer to a market-based product any transitioned customer who is delinquent in payment of any charges for POLR service to such LSP as of the 60th day of service. If such a customer becomes current in payments to the LSP, the LSP must move the customer to a market-based month-to-month product as described in this paragraph on the next billing cycle that occurs five business days after the customer becomes current. If the LSP does not plan to move customers who are delinquent in payment of any charges for POLR service as of the 60th day of service to a market-based month-to-month product, the LSP must inform the customer of that potential outcome in the notice provided to comply with §25.475(d) of this title.

(5) Upon a request from an LSP and a showing that the LSP will be unable to maintain its financial integrity if additional customers are transferred to it under this section, the commission may relieve an LSP from a transfer of additional customers. The LSP must continue providing continuous service until the commission issues an order relieving it of this responsibility. In the event the requesting LSP is relieved of its responsibility, the commission staff designee will, with 90 days' notice, designate the next eligible REP, if any, as an LSP, based upon the criteria in this subsection.

(k) Designation of an LSP affiliate to provide POLR service on behalf of an LSP.

(1) An LSP may request the commission designate an LSP affiliate to provide POLR service on behalf of the LSP either with the LSP's filing under subsection (h) of this section or as a separate filing in the current term project. The filing must be made at least 30 days prior to the date when the LSP affiliate is to begin providing POLR service on behalf of the LSP. To be eligible to provide POLR service on behalf of an LSP, the LSP affiliate must be certificated to provide retail electric service; have an executed delivery service agreement with the service area TDU; and meet the requirements of subsection (h)(2) of this section, with the exception of subsection (h)(2)(B), (C), (D), and (E) of this section as related to serving customers in the applicable customer class.

(2) The request must include the name and certificate number of the LSP affiliate, information demonstrating the affiliation between the LSP and the LSP affiliate, and a certified agreement from an officer of the LSP affiliate stating that the LSP affiliate agrees to provide POLR service on behalf of the LSP. The request must also include an affidavit from an officer of the LSP stating that the LSP will be responsible and indemnify any affected parties for all financial obligations of the LSP affiliate associated with the provisioning of POLR service on behalf of the LSP in the event that the LSP affiliate defaults or otherwise does not fulfill such financial obligations.

(3) Commission staff will make an initial determination of the eligibility of the LSP affiliate to provide POLR service on behalf of an LSP and publish their names. The LSP or LSP affiliate may challenge commission staff's eligibility determination within five business days of the notice of eligibility by submitting to commission staff additional evidence of its capability to provide POLR service on behalf of the LSP. Commission staff will reassess the LSP affiliate's eligibility and notify the LSP and LSP affiliate of any change in eligibility status within 10 business days of the receipt of the additional documentation. If the LSP or LSP affiliate does not agree with staff's determination of eligibility, either or both may then appeal the determination to the commission through a contested case. The LSP must provide POLR service during the pendency of the contested case.

(4) ERCOT or a TDU may challenge an LSP affiliate's eligibility to provide POLR service on behalf of an LSP. If ERCOT or a TDU has reason to believe that an LSP affiliate is not eligible or is not performing POLR responsibilities on behalf of an LSP, ERCOT or the TDU must make a filing with the commission detailing the basis for its concerns and must provide a copy of the filing to the LSP and the LSP affiliate that are the subject of the filing. If the filing contains confidential information, ERCOT or the TDU must file it in accordance with §25.71 of this title (relating to General Procedures, Requirements and Penalties). Commission staff will review the filing and if commission staff concludes that the LSP affiliate should not be allowed to provide POLR service on behalf of the LSP, it will request that the LSP affiliate demonstrate that it has the capability. The commission staff will review the LSP affiliate's filing and may initiate a proceeding with the commission to disqualify the LSP affiliate from providing POLR service. The LSP affiliate may continue providing POLR service to ESI IDs currently receiving the service during the pendency of the proceeding; however, the LSP must immediately assume responsibility to provide service under this section to customers who request POLR service, or are transferred to POLR service through a mass transition, during the pendency of the proceeding.

(5) Designation of an affiliate to provide POLR service on behalf of an LSP must not change the number of ESI IDs served or the retail sales in megawatt-hours for the LSP for the reporting period nor does such designation relieve the LSP of its POLR service obligations in the event that the LSP affiliate fails to provide POLR service in accordance with the commission rules.

(6) The designated LSP affiliate must provide POLR service and all reports as required by the commission's rules on behalf of the LSP.

(7) The methodology used by a designated LSP affiliate to calculate POLR rates must be consistent with the methodology used to calculate LSP POLR rates in subsection (m) of this section.

(8) If an LSP affiliate designated to provide POLR service on behalf of an LSP cannot meet or fails to meet the POLR service requirements in applicable laws and Commission rules, the LSP must provide POLR service to any ESI IDs currently receiving the service from the LSP affiliate and to ESI IDs in a future mass transition or upon customer request.

(9) An LSP may elect to reassume provisioning of POLR service from the LSP affiliate by filing a reversion notice with the commission and notifying ERCOT at least 30 days in advance.

(l) Mass transition of customers to POLR providers. The transfer of customers to POLR providers must be consistent with this subsection.

(1) ERCOT must first transfer customers to VREPs, up to the number of ESI IDs that each VREP has offered to serve for each customer class in the POLR area. ERCOT must use the VREP list to assign ESI IDs to the VREPs in a non-discriminatory manner, before assigning customers to the LSPs. A VREP must not be assigned more ESI IDs than it has indicated it is willing to serve pursuant to subsection (i) of this section. To ensure non-discriminatory assignment of ESI IDs to the VREPs, ERCOT must:

(A) Sort ESI IDs by POLR area;

(B) Sort ESI IDs by customer class;

(C) Sort ESI IDs numerically;

(D) Sort VREPs numerically by randomly generated number; and

(E) Assign ESI IDs in numerical order to VREPs, in the order determined in subparagraph (D) of this paragraph, in accordance with the number of ESI IDs each VREP indicated a willingness to serve pursuant to subsection (i) of this section. If the number of ESI IDs is less than the total that the VREPs indicated that they are willing to serve, each VREP must be assigned an equal number of ESI IDs, up to the number that each VREP indicated it was willing to serve for a given class and POLR area.

(2) If the number of ESI IDs exceeds the amount the VREPs are designated to serve, ERCOT must assign remaining ESI IDs to LSPs in a non-discriminatory fashion, in accordance with their percentage of market share based upon retail sales in megawatt-hours, on a random basis within a class and POLR area, except that a VREP that is also an LSP that volunteers to serve at least 1% of its market share for a class of customers in a POLR area must be exempt from the LSP allocation up to 1% of the class and POLR area. To ensure non-discriminatory assignment of ESI IDs to the LSPs, ERCOT must:

(A) Sort the ESI IDs in excess of the allocation to VREPs, by POLR area;

(B) Sort ESI IDs in excess of the allocation to VREPs, by customer class;

(C) Sort ESI IDs in excess of the allocation to VREPs, numerically;

(D) Sort LSPs, except LSPs that volunteered to serve 1% of their market share as a VREP, numerically by MWhs served;

(E) Assign ESI IDs that represent no more than 1% of the total market for that POLR area and customer class less the ESI IDs assigned to VREPs that volunteered to serve at least 1% of their market share for each POLR area and customer class in numerical order to LSPs designated in subparagraph (D) of this paragraph, in proportion to the percentage of MWhs served by each LSP to the total MWhs served by all LSPs;

(F) Sort LSPs, including any LSPs previously excluded under subparagraph (D) of this paragraph; and

(G) Assign all remaining ESI IDs in numerical order to LSPs in proportion to the percentage of MWhs served by each LSP to the total MWhs served by all LSPs.

(3) Each mass transition must be treated as a separate event.

(m) Rates applicable to POLR service.

(1) A VREP must provide service to customers using a market-based, month-to-month product. The VREP must use the same market-based, month-to-month product for all customers in a mass transition that are in the same class and POLR area.

(2) Subparagraphs (A) - (C) of this paragraph establish the maximum rate for POLR service charged by an LSP. An LSP may charge a rate less than the maximum rate if it charges the lower rate to all customers in a mass transition that are in the same class and POLR area.

(A) Residential customers. The LSP rate for the residential customer class must be determined by the following formula: LSP rate (in $ per kWh) = (Non-bypassable charges + LSP customer charge + LSP energy charge) / kWh used, where:

(i) Non-bypassable charges must be all TDU charges and credits for the appropriate customer class in the applicable service territory and other charges including ERCOT administrative charges, nodal fees or surcharges, reliability unit commitment (RUC) capacity short charges attributable to LSP load, and applicable taxes from various taxing or regulatory authorities, multiplied by the level of kWh and kW used, where appropriate.

(ii) LSP customer charge must be $0.09 per kWh.

(iii) Beginning on the 10th of each month, an LSP energy charge must be the average of the actual Real-Time Settlement Point Prices (RTSPPs) for the applicable load zone for the preceding calendar month (the historical average RTSPP) multiplied by the number of kWhs the customer used during that billing period and further multiplied by 120%. The LSP energy charge must not exceed 160%of the preceding calendar month's LSP energy charge. The applicable load zone will be the load zone located partially or wholly in the customer's TDU service territory with the highest average under the historical average RTSPP calculation.

(iv) "Number of kWhs the customer used" is based on usage data provided to the POLR by the TDU.

(B) Small and medium non-residential customers. The LSP rate for the small and medium non-residential customer classes must be determined by the following formula: LSP rate (in $ per kWh) = (Non-bypassable charges + LSP customer charge + LSP energy charge) / kWh used, where:

(i) Non-bypassable charges must be all TDU charges and credits for the appropriate customer class in the applicable service territory, and other charges including ERCOT administrative charges, nodal fees or surcharges, RUC capacity short charges attributable to LSP load, and applicable taxes from various taxing or regulatory authorities, multiplied by the level of kWh and kW used, where appropriate.

(ii) LSP customer charge must be $0.09 per kWh.

(iii) Beginning on the 10th of each month, LSP energy charge must be the average of the actual RTSPPs for the applicable load zone for the preceding calendar month multiplied by the number of kWhs the customer used during that billing period and further multiplied by 125%. The LSP energy charge must not exceed 160% of the preceding calendar month's LSP energy charge. The applicable load zone will be the load zone located partially or wholly in the customer's TDU service territory with the highest average under the historical average RTSPP calculation.

(iv) "Number of kWhs the customer used" is based on usage data provided to the POLR by the TDU.

(C) Large non-residential customers. The LSP rate for the large non-residential customer class must be determined by the following formula: LSP rate (in $ per kWh) = (Non-bypassable charges + LSP customer charge + LSP demand charge + LSP energy charge) / kWh used, where:

(i) Non-bypassable charges must be all TDU charges and credits for the appropriate customer class in the applicable service territory, and other charges including ERCOT administrative charges, nodal fees or surcharges, RUC capacity short charges attributable to LSP load, and applicable taxes from various taxing or regulatory authorities, multiplied by the level of kWh and KW used, where appropriate.

(ii) LSP customer charge must be $2,897.00 per month.

(iii) LSP demand charge must be $6.00 per kW, per month.

(iv) LSP energy charge must be the appropriate RTSPP, determined on the basis of 15-minute intervals, for the customer multiplied by 125%, multiplied by the level of kilowatt-hours used. The energy charge must have a floor of $7.25 per MWh.

(3) If in response to a complaint or upon its own investigation, the commission determines that an LSP failed to charge the appropriate rate prescribed by paragraph (2) of this subsection, and as a result overcharged its customers, the LSP must issue refunds to the specific customers who were overcharged.

(4) On a showing of good cause by an affected person, the commission may direct an LSP to adjust the rate prescribed by paragraph (2) of this subsection, if necessary to ensure that the rate is consistent with prevailing market conditions. Notwithstanding any other commission rule to the contrary, such rates may be adjusted on an interim basis for good cause shown and after at least 10 business days' notice and an opportunity for hearing on the request for interim relief. Any adjusted rate must be applicable to all LSPs charging the rate prescribed by paragraph (2) of this subsection to the specific customer class, within the POLR area that is subject to the adjustment.

(5) For transitioned customers, the customer and demand charges associated with the rate prescribed by paragraph (3) of this subsection must be pro-rated for partial month usage if a large non-residential customer switches from the LSP to a REP of choice.

(n) Challenges to customer assignments. A POLR provider is not obligated to serve a customer within a customer class or a POLR area for which the REP is not designated as a POLR provider, after a successful challenge of the customer assignment. A POLR provider must use the ERCOT market variance resolution tool to challenge a customer class assignment with the TDU. The TDU must make the final determination based upon historical usage data and not premise type. If the customer class assignment is changed and a different POLR provider for the customer is determined appropriate, the customer must then be served by the appropriate POLR provider. Back dated transactions may be used to correct the POLR assignment.

(o) Limitation on liability. A POLR provider must make reasonable provisions to provide service under this section to any ESI IDs currently receiving the service and to ESI IDs obtained in a future mass transition or served upon customer request; however, liabilities not excused by reason of force majeure or otherwise must be limited to direct, actual damages.

(1) Neither the customer nor the POLR provider must be liable to the other for consequential, incidental, punitive, exemplary, or indirect damages. These limitations apply without regard to the cause of any liability or damage.

(2) In no event will ERCOT or a POLR provider be liable for damages to any REP, whether under tort, contract or any other theory of legal liability, for transitioning or attempting to transition a customer from such REP to the POLR provider to carry out this section, or for marketing, offering or providing competitive retail electric service to a customer taking service under this section from the POLR provider.

(p) REP obligations in a transition of customers to POLR service.

(1) A customer may initiate service with an LSP by requesting such service at the rate prescribed by subsection (m)(2) of this section with any LSP that is designated to serve the requesting customer's customer class within the requesting customer's service area. An LSP cannot refuse a customer's request to make arrangements for POLR service, except as otherwise permitted under this title.

(2) The POLR provider is responsible for obtaining resources and services needed to serve a customer once it has been notified that it is serving that customer. The customer is responsible for charges for service under this section at the rate in effect at that time.

(3) If a REP terminates service to a customer, or transitions a customer to a POLR provider, the REP is financially responsible for the resources and services used to serve the customer until it notifies the independent organization of the termination or transition of the service and the transfer to the POLR provider is complete.

(4) The POLR provider is financially responsible for all costs of providing electricity to customers from the time the transfer or initiation of service is complete until such time as the customer ceases taking service under this section.

(5) A defaulting REP whose customers are subject to a mass transition event must return the customers' deposits within seven calendar days of the initiation of the transition.

(6) ERCOT must create a single standard file format and a standard set of customer billing contact data elements that, in the event of a mass transition, must be used by the exiting REP and the POLRs to send and receive customer billing contact information. The process, as developed by ERCOT must be tested on a periodic basis. Each REP must submit timely, accurate, and complete files, as required by ERCOT in a mass transition event, as well as for periodic testing. The commission will establish a procedure for the verification of customer information submitted by REPs to ERCOT. ERCOT must notify the commission if any REP fails to comply with the reporting requirements in this subsection.

(7) When customers are to be transitioned or assigned to a POLR provider, the POLR provider may request usage and demand data, and customer contact information including email, telephone number, and address from the appropriate TDU and from ERCOT, once the transition to the POLR provider has been initiated. Customer proprietary information provided to a POLR provider in accordance with this section must be treated as confidential and must only be used for mass transition related purposes.

(8) Information from the TDU and ERCOT to the POLR providers must be provided in Texas SET format when Texas SET transactions are available. However, the TDU or ERCOT may supplement the information to the POLR providers in other formats to expedite the transition. The transfer of information in accordance with this section must not constitute a violation of the customer protection rules that address confidentiality.

(9) A POLR provider may require a deposit from a customer that has been transitioned to the POLR provider to continue to serve the customer. Despite the lack of a deposit, the POLR provider is obligated to serve the customer transitioned or assigned to it, beginning on the service initiation date of the transition or assignment, and continuing until such time as any disconnection request is effectuated by the TDU. A POLR provider may make the request for deposit before it begins serving the customer, but the POLR provider must begin providing service to the customer even if the service initiation date is before it receives the deposit - if any deposit is required. A POLR provider must not disconnect the customer until the appropriate time period to submit the deposit has elapsed. For the large non-residential customer class, a POLR provider may require a deposit to be provided in three calendar days. For the residential customer class, the POLR provider may require a deposit to be provided after 15 calendar days of service if the customer received 10 days' notice that a deposit was required. For all other customer classes, the POLR provider may require a deposit to be provided in 10 calendar days. The POLR provider may waive the deposit requirement at the customer's request if deposits are waived in a non-discriminatory fashion. If the POLR provider obtains sufficient data, it must determine whether a residential customer has satisfactory credit based on the criteria the POLR provider routinely applies to its other residential customers. If the customer has satisfactory credit, the POLR provider must not request a deposit from the residential customer.

(A) At the time of a mass transition, the executive director or staff designated by the executive director will distribute available proceeds from an irrevocable stand-by letter of credit in accordance with the priorities established in §25.107(f)(6) of this title. For a REP that has obtained a current list from the Low Income List Administrator (LILA) that identifies low-income customers, these funds must first be used to provide deposit payment assistance for that REP's transitioned low-income customers. The Executive Director or staff designee will, at the time of a transition event, determine the reasonable deposit amount up to $400 per customer ESI ID, unless good cause exists to increase the level of the reasonable deposit amount above $400. Such reasonable deposit amount may take into account factors such as typical residential usage and current retail residential prices, and, if fully funded, must satisfy in full the customers' initial deposit obligation to the VREP or LSP.

(B) For a REP that has obtained a current list from the LILA that identifies low-income customers, the Executive Director or the staff designee will distribute available proceeds pursuant to §25.107(f)(6) of this title to the VREPs proportionate to the number of customers they received in the mass transition, who at the time of the mass transition were identified as low-income customers by the current LILA list, up to the reasonable deposit amount set by the Executive Director or staff designee. If funds remain available after distribution to the VREPs, the remaining funds must be distributed to the appropriate LSPs by dividing the amount remaining by the number of low income customers as identified in the LILA list that are allocated to LSPs, up to the reasonable deposit amount set by the Executive Director or staff designee.

(C) If the funds distributed in accordance with §25.107(f)(6) of this title do not equal the reasonable deposit amount determined, the VREP and LSP may request from the customer payment of the difference between the reasonable deposit amount and the amount distributed. Such difference must be collected in accordance with §25.478(e)(3) of this title (relating to Credit Requirements and Deposits).

(D) Notwithstanding §25.478(d) of this title, 90 days after the transition date, the VREP or LSP may request payment of an amount that results in the total deposit held being equal to what the VREP or LSP would otherwise have charged a customer in the same customer class and service area in accordance with §25.478(e) of this title, at the time of the transition.

(10) On the occurrence of one or more of the following events, ERCOT must initiate a mass transition to POLR providers, of all of the customers served by a REP:

(A) Termination of the Load Serving Entity (LSE) or Qualified Scheduling Entity (QSE) Agreement for a REP with ERCOT;

(B) Issuance of a commission order recognizing that a REP is in default under the TDU Tariff for Retail Delivery Service;

(C) Issuance of a commission order de-certifying a REP;

(D) Issuance of a commission order requiring a mass transition to POLR providers;

(E) Issuance of a judicial order requiring a mass transition to POLR providers; and

(F) At the request of a REP, for the mass transition of all of that REP's customers.

(11) A REP must not use the mass transition process in this section as a means to cease providing service to some customers, while retaining other customers. A REP's improper use of the mass transition process may lead to de-certification of the REP.

(12) ERCOT may provide procedures for the mass transition process, consistent with this section.

(13) A mass transition under this section must not override or supersede a switch request made by a customer to switch an ESI ID to a new REP of choice, if the request was made before a mass transition is initiated. If a switch request has been made but is scheduled for any date after the next available switch date, the switch must be made on the next available switch date.

(14) ERCOT must identify customers who are mass transitioned for a period of 60 calendar days. The identification must terminate at the first completed switch or at the end of the 60-day period, whichever is first. If necessary, ERCOT system changes or new transactions must be implemented no later than 14 months from the effective date of this section to communicate that a customer was acquired in a mass transition and is not charged the out-of-cycle meter read pursuant to paragraph (16) of this subsection.

(15) In the event of a transition to a POLR provider or away from a POLR provider to a REP of choice, the switch notification notice detailed in §25.474(l) of this title (relating to Selection of Retail Electric Provider) is not required.

(16) In a mass transition event, the ERCOT initiated transactions must request an out-of-cycle meter read for the associated ESI IDs for a date two calendar days after the calendar date ERCOT initiates such transactions to the TDU. If an ESI ID does not have the capability to be read in a fashion other than a physical meter read, the out-of-cycle meter read may be estimated. An estimated meter read for the purpose of a mass transition to a POLR provider must not be considered a break in a series of consecutive months of estimates, but must not be considered a month in a series of consecutive estimates performed by the TDU. A TDU must create a regulatory asset for the TDU fees associated with a mass transition of customers to a POLR provider pursuant to this subsection. Upon review of reasonableness and necessity, a reasonable level of amortization of such regulatory asset must be included as a recoverable cost in the TDU's rates in its next rate case or such other rate recovery proceeding as deemed necessary. The TDU must not bill as a discretionary charge, the costs included in this regulatory asset, which must consist of the following:

(A) fees for out-of-cycle meter reads associated with the mass transition of customers to a POLR provider; and

(B) fees for the first out-of-cycle meter read provided to a customer who transfers away from a POLR provider, when the out-of-cycle meter read is performed within 60 calendar days of the date of the mass transition and the customer is identified as a transitioned customer.

(17) In the event the TDU estimates a meter read for the purpose of a mass transition, the TDU must perform a true-up evaluation of each ESI ID after an actual meter reading is obtained. Within 10 days after the actual meter reading is obtained, the TDU must calculate the actual average kWh usage per day for the time period from the most previous actual meter reading occurring prior to the estimate for the purpose of a mass transition to the most current actual meter reading occurring after the estimate for the purpose of mass transition. If the average daily estimated usage sent to the exiting REP is more than 50% greater than or less than the average actual kWh usage per day, the TDU must promptly cancel and re-bill both the exiting REP and the POLR using the average actually daily usage.

(q) Termination of POLR service provider status.

(1) The commission may revoke a REP's POLR status after notice and opportunity for hearing:

(A) If the POLR provider fails to maintain REP certification;

(B) If the POLR provider fails to provide service in a manner consistent with this section;

(C) The POLR provider fails to maintain appropriate financial qualifications; or

(D) For other good cause.

(2) If an LSP defaults or has its status revoked before the end of its term, after a review of the eligibility criteria, the commission staff designee will, as soon as practicable, designate the next eligible REP, if any, as an LSP, based on the criteria in subsection (j) of this section.

(3) At the end of the POLR service term, the outgoing LSP must continue to serve customers who have not selected another REP.

(r) Electric cooperative delegation of authority. An electric cooperative that has adopted customer choice may select to delegate to the commission its authority to select POLR providers under PURA §41.053(c) in its certificated service area in accordance with this section. After notice and opportunity for comment, the commission will, at its option, accept or reject such delegation of authority. If the commission accepts the delegation of authority, the following conditions apply:

(1) The board of directors must provide the commission with a copy of a board resolution authorizing such delegation of authority;

(2) The delegation of authority must be made at least 30 calendar days prior to the time the commission issues a publication of notice of eligibility;

(3) The delegation of authority must be for a minimum period corresponding to the period for which the solicitation must be made;

(4) The electric cooperative wishing to delegate its authority to designate a continuous provider must also provide the commission with the authority to apply the selection criteria and procedures described in this section in selecting the POLR providers within the electric cooperative's certificated service area; and

(5) If there are no competitive REPs offering service in the electric cooperative certificated area, the commission must automatically reject the delegation of authority.

(s) Reporting requirements. Each LSP that serves customers under a rate prescribed by subsection (m)(2) of this section must file the following information with the commission on a quarterly basis beginning January of each year in a project established by the commission for the receipt of such information. Each quarterly report must be filed within 30 calendar days of the end of the quarter.

(1) For each month of the reporting quarter, each LSP must report the total number of new customers acquired by the LSP under this section and the following information regarding these customers:

(A) The number of customers from whom a deposit was requested pursuant to the provisions of §25.478 of this title, and the average amount of deposit requested;

(B) The number of customers from whom a deposit was received, including those who entered into deferred payment plans for the deposit, and the average amount of the deposit;

(C) The number of customers whose service was physically disconnected pursuant to the provisions of §25.483 of this title (relating to Disconnection of Service) for failure to pay a required deposit; and

(D) Any explanatory data or narrative necessary to account for customers that were not included in either subparagraph (B) or (C) of this paragraph.

(2) For each month of the reporting quarter each LSP must report the total number of customers to whom a disconnection notice was issued pursuant to the provisions of §25.483 of this title and the following information regarding those customers:

(A) The number of customers who entered into a deferred payment plan, as defined by §25.480(j) of this title (relating to Bill Payment and Adjustments) with the LSP;

(B) The number of customers whose service was physically disconnected pursuant to §25.483 of this title;

(C) The average amount owed to the LSP by each disconnected customer at the time of disconnection; and

(D) Any explanatory data or narrative necessary to account for customers that are not included in either subparagraph (A) or (B) of this paragraph.

(3) For the entirety of the reporting quarter, each LSP must report, for each customer that received POLR service, the TDU and customer class associated with the customer's ESI ID, the number of days the customer received POLR service, and whether the customer is currently the LSP's customer.

(t) Notice of transition to POLR service to customers. When a customer is moved to POLR service, the customer must be provided notice of the transition by ERCOT, the REP transitioning the customer, and the POLR provider. The ERCOT notice must be provided within two days of the time ERCOT and the transitioning REP know that the customer must be transitioned and customer contact information is available. If ERCOT cannot provide notice to customers within two days, it must provide notice as soon as practicable. The POLR provider must provide the notice required by paragraph (3) of this subsection to commission staff at least 48 hours before it is provided to customers, and must provide the notice to transitioning customers as soon as practicable. The POLR provider must email the notice to the commission staff members designated for receipt of the notice.

(1) ERCOT notice methods must include a post-card, containing the official commission seal with language and format approved by the commission. ERCOT must notify transitioned customers with an automated phone-call and email to the extent the information to contact the customer is available pursuant to subsection (p)(6) of this section. ERCOT must study the effectiveness of the notice methods used and report the results to the commission.

(2) Notice by the REP from which the customer is transferred must include:

(A) The reason for the transition;

(B) A contact number for the REP;

(C) A statement that the customer will receive a separate notice from the POLR provider that must disclose the date the POLR provider must begin serving the customer;

(D) Either the customer's deposit plus accrued interest, or a statement that the deposit must be returned within seven days of the transition;

(E) A statement that the customer can leave the assigned service by choosing a competitive product or service offered by the POLR provider, or another competitive REP, as well as the following statement: "If you would like to see offers from different retail electric providers, please access www.powertochoose.org, or call toll-free 1-866-PWR-4-TEX (1-866-797-4839) for a list of providers in your area;"

(F) For residential customers, notice from the commission in the form of a bill insert or a bill message with the header "An Important Message from the Public Utility Commission Regarding Your Electric Service" addressing why the customer has been transitioned to another REP, the continuity of service purpose, the option to choose a different competitive provider, and information on competitive markets to be found at www.powertochoose.org, or toll-free at 1-866-PWR-4-TEX (1-866-797-4839);

(G) If applicable, a description of the activities that the REP will use to collect any outstanding payments, including the use of consumer reporting agencies, debt collection agencies, small claims court, and other remedies allowed by law, if the customer does not pay or make acceptable payment arrangements with the REP; and

(H) Notice to the customer that after being transitioned to POLR service, the customer may accelerate a switch to another REP by requesting a special or out-of-cycle meter read.

(3) Notice by the POLR provider must include:

(A) The date the POLR provider began or will begin serving the customer and a contact number for the POLR provider;

(B) A description of the POLR provider's rate for service. In the case of a notice from an LSP that applies the pricing of subsection (m)(2) of this section, a statement that the price is generally higher than available competitive prices;

(C) The deposit requirements of the POLR provider and any applicable deposit waiver provisions and a statement that, if the customer chooses a different competitive product or service offered by the POLR provider, a REP affiliated with the POLR provider, or another competitive REP, a deposit may be required;

(D) A statement that the additional competitive products or services may be available through the POLR provider, a REP affiliated with the POLR provider, or another competitive REP, as well as the following statement: "If you would like to choose a different retail electric provider, please access www.powertochoose.org, or call toll-free 1-866-PWR-4-TEX (1-866-797-4839) for a list of providers in your area;"

(E) The applicable Terms of Service and Electricity Facts Label (EFL); and

(F) For residential customers that are served by an LSP under a rate prescribed by subsection (m)(2) of this section, a notice to the customer that after being transitioned to service from a POLR provider, the customer may accelerate a switch to another REP by requesting a special or out-of-cycle meter read.

(u) Market notice of transition to POLR service. ERCOT must notify all affected Market Participants and the Retail Market Subcommittee (RMS) email listserv of a mass transition event within the same day of an initial mass-transition call after the call has taken place. The notification must include the exiting REP's name, total number of ESI IDs, and estimated load.

(v) Disconnection by a POLR provider. The POLR provider must comply with the applicable customer protection rules as provided for under Subchapter R of this chapter, except as otherwise stated in this section. To ensure continuity of service, service under this section must begin when the customer's transition to the POLR provider is complete. A customer deposit is not a prerequisite for the initiation of service under this section. Once service has been initiated, a customer deposit may be required to prevent disconnection. Disconnection for failure to pay a deposit may not occur until after the proper notice and after that appropriate payment period detailed in §25.478 of this title has elapsed, except where otherwise noted in this section.

(w) Deposit payment assistance.

(1) The commission staff designee will distribute the deposit payment assistance monies to the appropriate POLRs on behalf of customers as soon as practicable.

(2) The executive director or staff designee will use best efforts to provide written notice to the appropriate POLRs of the following on or before the second calendar day after the transition:

(A) a list of the ESI IDs identified by the LILA that have been or will be transitioned to the applicable POLR (if available); and

(B) the amount of deposit payment assistance that will be provided on behalf of a POLR customer identified by the LILA (if available).

(3) Amounts credited as deposit payment assistance pursuant to this section must be refunded to the customer in accordance with §25.478(j) of this title.

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 November 3, 2022.

TRD-202204366

Adriana Gonzales

Rules Coordinator

Public Utility Commission of Texas

Effective date: November 23, 2022

Proposal publication date: September 30, 2022

For further information, please call: (512) 936-7322


PART 4. TEXAS DEPARTMENT OF LICENSING AND REGULATION

CHAPTER 73. ELECTRICIANS

16 TAC §73.100

The Texas Commission of Licensing and Regulation (Commission) adopts amendments to an existing rule at 16 Texas Administrative Code (TAC), Chapter 73, §73.100, regarding the Electricians program, without changes to the proposed text as published in the June 17, 2022, issue of the Texas Register (47 TexReg 3522). The rule will not be republished.

EXPLANATION OF AND JUSTIFICATION FOR THE RULES

The rules under 16 TAC Chapter 73 implement Texas Occupations Code, Chapter 1305, Electricians.

Pursuant to Occupations Code, Chapter 1305, §1305.101(a)(2), the Commission is required to adopt the National Electrical Code (NEC) every three years "as the electrical code for the state." The Commission has adopted the 2020 NEC in its entirety by rule at 16 TAC, Chapter 73, §73.100, Technical Requirements. Section 90.4 of the 2020 NEC authorizes the Department to waive specific code requirements when doing so will not have a negative impact on safety.

Section 210.8(F) of the NEC requires certain outdoor outlets to have ground-fault circuit-interrupter (GFCI) protection. An incompatibility between most GFCI products on the market and common air-conditioning and heating equipment has resulted in that equipment failing by persistently tripping circuit breakers. Recent rulemaking by the Department has delayed the implementation of Section 210.8(F) until January 1, 2023, in order to allow equipment manufacturers to correct this incompatibility. See 16 TAC §73.100(b). However, because this incompatibility will not be resolved by January 1, 2023, the adopted rule will exclude Section 210.8(F) from the Department's implementation of the 2020 NEC altogether.

The summer heat and winter cold pose a serious threat to Texas residents whose air conditioning or heating systems have failed or are malfunctioning. Adopting the proposed rule would help keep Texas residents safe by ensuring installed air conditioning and heating systems are not subject to failure due to equipment incompatibility. Additionally, the Department's technical experts have confirmed that adopting the proposed rule would not have a negative impact on safety.

SECTION-BY-SECTION SUMMARY

The adopted rule amends §73.100(b) to state that compliance with Section 210.8(F) of the 2020 NEC is not required.

PUBLIC COMMENTS

The Department drafted and distributed the proposed rules to persons internal and external to the agency. The proposed rules were published in the June 17, 2022, issue of the Texas Register (47 TexReg 3522). The public comment period closed on July 18, 2022. The Department received comments from four interested parties on the proposed rules. The public comments are summarized below.

Comment: Two commenters expressed their support for the proposed rule as published.

Department Response: The Department appreciates these comments.

Comment: One commenter stated that the Department was "moving in the right direction" by adopting the proposed rules. The commenter stated that requiring GFCI protection for air conditioning equipment is a bad requirement that is not practical and that imposes extreme costs.

Department Response: The Department appreciates the comment.

Comment: One commenter stated simply, "Keep the rule in place."

Department Response: The Department was unable to determine whether the commenter was in favor of or against adopting the proposed rule. The Department appreciates the comment.

ADVISORY BOARD RECOMMENDATIONS AND COMMISSION ACTION

The Electrical Safety and Licensing Advisory Board met on August 25, 2022, to discuss the proposed rules and the public comments received. The Advisory Board recommended that the Commission adopt the proposed rules as published in the Texas Register. At its meeting on October 18, 2022, the Commission adopted the proposed rules as recommended by the Advisory Board.

STATUTORY AUTHORITY

The adopted rule is adopted under Texas Occupations Code, Chapters 51 and 1305, which authorize the Texas Commission of Licensing and Regulation, the Department's governing body, to adopt rules as necessary to implement these chapters and any other law establishing a program regulated by the Department.

The statutory provisions affected by the adopted rule are those set forth in Texas Occupations Code, Chapters 51 and 1305. No other statutes, articles, or codes are affected by the adopted rule.

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 November 4, 2022.

TRD-202204397

Brad Bowman

General Counsel

Texas Department of Licensing and Regulation

Effective date: December 31, 2022

Proposal publication date: June 17, 2022

For further information, please call: (512) 475-4879


CHAPTER 75. AIR CONDITIONING AND REFRIGERATION

16 TAC §75.100

The Texas Commission of Licensing and Regulation (Commission) adopts amendments to an existing rule at 16 Texas Administrative Code (TAC), Chapter 75, §75.100, regarding the Air Conditioning and Refrigeration Contractors program, without changes to the proposed text as published in the July 8, 2022, issue of the Texas Register (47 TexReg 3864). The rule will not be republished.

EXPLANATION OF AND JUSTIFICATION FOR THE RULES

The rules under 16 TAC Chapter 75 implement Texas Occupations Code, Chapter 1302, Air Conditioning and Refrigeration Contractors.

Pursuant to 16 TAC, Chapter 75, §75.100(a)(4), electrical work performed by air conditioning and refrigeration contractors must be performed in accordance with the 2020 National Electrical Code (NEC). Section 90.4 of the 2020 NEC authorizes the Department to waive specific code requirements when doing so will not have a negative impact on safety.

Section 210.8(F) of the NEC requires certain outdoor outlets to have ground-fault circuit-interrupter (GFCI) protection. An incompatibility between most GFCI products on the market and common air-conditioning and heating equipment has resulted in that equipment failing by persistently tripping circuit breakers. Recent rulemaking by the Department has delayed the implementation of Section 210.8(F) until January 1, 2023, in order to allow equipment manufacturers to correct this incompatibility. See 16 TAC §75.100(a)(5). However, because this incompatibility will not be resolved by January 1, 2023, the proposed rule will exclude Section 210.8(F) from the Department's implementation of the 2020 NEC altogether.

The summer heat and winter cold pose a serious threat to Texas residents whose air conditioning or systems have failed or are malfunctioning. Adopting the proposed rule would help keep Texas residents safe by ensuring installed air conditioning and heating systems are not subject to failure due to equipment incompatibility. Additionally, the Department's technical experts have confirmed that adopting the proposed rule would not have a negative impact on safety.

SECTION-BY-SECTION SUMMARY

The adopted rule amends §75.100(a)(5) to state that compliance with Section 210.8(F) of the 2020 NEC is not required.

PUBLIC COMMENTS

The Department drafted and distributed the proposed rules to persons internal and external to the agency. The proposed rules were published in the July 8, 2022, issue of the Texas Register (47 TexReg 3864). The public comment period closed on August 8, 2022. The Department received comments from twelve interested parties on the proposed rules. The public comments are summarized below.

Comment: Ten commenters expressed their support for the proposed rule as published.

Department Response: The Department appreciates these comments.

Comment: One commenter stated that Texas should have a law requiring all residences and businesses to have working air conditioning.

Department Response: The Department appreciates the comment, but is not empowered to make such a change. Only the Texas Legislature could impose such a requirement.

Comment: One commenter stated that GFCI protection makes installation of air conditioning equipment more costly, and should not be required if the equipment is installed correctly.

Department Response: The Department appreciates the comment.

ADVISORY BOARD RECOMMENDATIONS AND COMMISSION ACTION

The Air Conditioning and Refrigeration Contractors Advisory Board met on August 24, 2022, to discuss the proposed rules and the public comments received. The Advisory Board recommended that the Commission adopt the proposed rules as published in the Texas Register. At its meeting on October 18, 2022, the Commission adopted the proposed rules as recommended by the Advisory Board.

STATUTORY AUTHORITY

The adopted rule is adopted under Texas Occupations Code, Chapters 51 and 1302, which authorize the Texas Commission of Licensing and Regulation, the Department's governing body, to adopt rules as necessary to implement these chapters and any other law establishing a program regulated by the Department.

The statutory provisions affected by the adopted rule are those set forth in Texas Occupations Code, Chapters 51 and 1302. No other statutes, articles, or codes are affected by the adopted rule.

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 November 4, 2022.

TRD-202204396

Brad Bowman

General Counsel

Texas Department of Licensing and Regulation

Effective date: December 31, 2022

Proposal publication date: July 8, 2022

For further information, please call: (512) 475-4879