TITLE 16. ECONOMIC REGULATION

PART 1. RAILROAD COMMISSION OF TEXAS

CHAPTER 3. OIL AND GAS DIVISION

16 TAC §3.65, §3.107

The Railroad Commission of Texas (Commission) adopts new §3.65, relating to Critical Designation of Natural Gas Infrastructure, and amendments to §3.107, relating to Penalty Guidelines for Oil and Gas Violations, with changes to the proposed text as published in the October 1, 2021, issue of the Texas Register (46 TexReg 6458). The rules will be republished. The Commission also adopts Commission Forms CI-D and CI-X, which are related to the adopted new rule and amendments and were proposed on the Commission's website.

The new section and amendments implement changes made by House Bill 3648 and Senate Bill 3 from the 87th Texas Legislative Regular Session.

The Commission received comments on the proposed new rule and amendments from 11 associations, 18 companies or organizations, and 910 individuals. The comments are summarized below.

House Bill 3648 amends Texas Natural Resources Code, Chapter 81, to add new section 81.073, regarding critical natural gas facilities and entities. Section 81.073 requires the Commission to collaborate with the Public Utility Commission of Texas (PUCT) 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 rules adopted by the Commission under new section 81.073 must provide that those designated as critical natural gas facilities and entities provide critical customer information, as defined by the Commission, to their electric entities. House Bill 3648 requires that the Commission adopt the new rules not later than December 1, 2021.

Senate Bill 3 is the 87th Legislature's sweeping response to the February 2021 Winter Weather Event ("Winter Storm Uri") in Texas and generally creates new law related to preparing for, preventing, and responding to weather emergencies and power outages. Senate Bill 3 requires several state agencies and regulated industries to make significant changes in response to Winter Storm Uri. This proposed rulemaking is the Commission's first of many steps in implementing the requirements of Senate Bill 3.

Weatherization

Importantly, this rulemaking implements Section 4 of Senate Bill 3. It does not implement Sections 5 or 21 of Senate Bill 3, which added Natural Resources Code section 86.044 and Utilities Code section 121.2015 requiring the Commission to adopt rules requiring a gas supply chain facility operator and a gas pipeline facility operator, respectively, to implement measures to prepare to operate during a weather emergency (i.e., "weatherize"). Many comments focused on these weatherization requirements, and some suggested the Commission include weatherization requirements or guidelines in §3.65. The Commission will initiate a rulemaking at a later date to adopt weatherization rules. Because this rulemaking is limited to addressing critical designation for load shed purposes, adding weatherization requirements or guidelines at this stage of the rulemaking is inappropriate. And, as described more fully below, both the critical designation rulemaking and the publication of the electricity supply chain map are prerequisites to the weatherization rules. Therefore, the Commission views these comments as outside the scope of the current rulemaking.

However, the Commission recognizes that the critical designation process in this rulemaking is connected to the later weatherization rulemaking because, according to § 86.044, gas supply chain facilities subject to weatherization requirements are those that are: (1) designated critical in §3.65; and (2) included on the electricity supply chain map created by the Texas Electricity Supply Chain Security and Mapping Committee (Mapping Committee). The Commission notes that Section 21 of Senate Bill 3 provides different criteria to determine whether gas pipeline facilities are subject to weatherization requirements. A gas pipeline facility is subject to weatherization requirements if the pipeline: (1) directly serves a natural gas electric generation facility operating solely to provide power to the electric grid for the ERCOT power region or for the ERCOT power region and an adjacent power region; and (2) the pipeline is included on the electricity supply chain map. Therefore, while a pipeline's critical designation status in §3.65 does not impact whether it will be required to weatherize, a gas supply chain facility's critical designation status does. In any case, the specific requirements for weatherization will be proposed in a future rulemaking and will depend on the map created by the Mapping Committee.

Comments from the Texas Senate Committee on Business and Commerce (Senate B&C), Sierra Club, Texas Consumer Association (TCA), American Public Gas Association (APGA), City of Houston, Commission Shift, Lower Colorado River Authority (LCRA), Texas Public Power Association (TPPA), CPS Energy, Public Citizen, and 910 individuals expressed concerns regarding facilities either not designated critical in the proposal or designated critical but eligible for an exception. Commenters opposed language that would allow critical facilities to "opt out" of critical designation and subsequent weatherization requirements. These commenters asked that more facilities stay critical, so these facilities are subject to weatherization requirements adopted under § 86.044 and, ultimately, to ensure natural gas is available for electric generation in an energy emergency.

The Commission has addressed these comments with two changes to the rule. First, the Commission adopts § 3.65 with new subsection (e), which states certain facilities are not eligible for an exception. These facilities include facilities on the electricity supply chain map and other facilities that contribute significantly to the natural gas supply chain - namely gas wells or oil leases producing gas or casinghead gas in excess of 250 Mcf/day; gas processing plants; natural gas pipelines or pipeline facilities that directly serve local distribution companies or electric generation; local distribution company pipelines or pipeline facilities; underground natural gas storage facilities; natural gas liquids storage and transportation facilities; and saltwater disposal facilities that support the other listed facilities. Because these facilities are not eligible for an exception, they will remain critical for load shed purposes and they will be required to weatherize if they are included on the electricity supply chain map. The Commission notes that its deadline to adopt weatherization rules in Sections 5 and 21 of Senate Bill 3 is six months after the Mapping Committee publishes the electricity supply chain map. As stated above, Section 5 of Senate Bill 3 states that only gas supply chain facilities that are both designated critical and on the electricity supply chain map are required to weatherize. The Commission is prepared to timely adopt weatherization rules in accordance with the requirements of Senate Bill 3.

Second, the Commission adopts subsection (b) with changes to designate two classes of facilities as critical. The facilities designated "critical gas suppliers" are the key parts of the natural gas supply chain. These facilities may or may not need electricity to operate. However, because they are designated critical, they will later be required to comply with Commission weatherization rules if they are also included on the electricity supply chain map regardless of whether they require electricity from an electric entity to operate. This revision addresses concerns from the City of Houston, CPS Energy, Sierra Club, Commission Shift, LCRA, and individuals that §3.65 should apply to gas facilities that may potentially supply electric generators, regardless of whether a gas facility requires electricity. Subsection (b)(2) designates facilities as "critical customers." Only those critical facilities that need power to operate are "critical customers" and are required to provide information to their electric entities, which will limit the number of critical facilities that electric entities must prioritize as critical load. Both categories of facilities are designated critical and will be subject to weatherization requirements, once adopted, if the facility is a gas supply chain facility included on the electricity supply chain map.

Critical Designation for Load Shed Purposes

Though §3.65 relates to weatherization, the purpose of §3.65 is to implement Section 4 of Senate Bill 3 and Section 1 of House Bill 3648 by designating segments of the natural gas supply chain as critical for load shed purposes. The rule specifies the criteria and process by which entities associated with providing natural gas in Texas are designated as critical gas suppliers or critical customers during an energy emergency. Designation as a critical customer prompts a requirement for the facility's operator to directly provide the electric entities described in 16 Texas Administrative Code §25.52(h) (relating to Reliability and Continuity of Service) and section 38.074(b)(1) of the Texas Utilities Code (hereinafter "electric entities") with critical customer information. Providing the information positions a critical customer to receive power during an energy emergency so that it can continue to supply natural gas in the state for power generation and/or other important uses. The sections below summarize comments the Commission received on proposed §3.65.

Subsection (a) - Definitions

The Permian Basin Petroleum Association (PBPA), the Texas Oil and Gas Association (TXOGA), the Texas Alliance of Energy Producers (the Alliance), TPPA, and the Texas Pipeline Association (TPA) commented on the Commission's proposed definition of "energy emergency." The comments expressed concern that the definition was too broad. PBPA and TXOGA requested that the definition be tied to the Electric Reliability Council of Texas (ERCOT) Energy Emergency Alert Level 2. Comments filed in the PUCT's corresponding rulemaking to implement House Bill 3648 and Senate Bill 3 requested that the PUCT adopt a definition of energy emergency. The PUCT's adopted definition is "any event that results in or has the potential to result in firm load shed required by the reliability coordinator of a power region in Texas." The Commission adopts subsection (a)(1) with changes to incorporate the PUCT's definition because consistent definitions of "energy emergency" in the regulating agencies' rules will benefit those required to comply.

PBPA, the Alliance, TPPA and TPA also expressed concerns about the proposed definition of "weather emergency," requesting additional clarification, and some comments noted under the proposed definition affected facilities would not be able to determine whether they are prepared to operate in a weather emergency. The Commission notes that this concern relates to the proposed exception process, in which an operator was required to certify it was not prepared to operate in weather emergency. The exception process is revised in the adopted version of §3.65, and the rule no longer includes the term "weather emergency." Thus, the definition is removed.

Several comments concerned the definition of "critical customer information" in proposed subsection (a)(3) (adopted in subsection (a)(2)) and the related Table CCI proposed on the Commission's website. First, the Electric Reliability Council of Texas (ERCOT), comments jointly filed by the "Texas LDCs" (Atmos Energy Corporation's Mid-Tex and West Texas Divisions; CenterPoint Energy Resources d/b/a CenterPoint Energy Entex; and Texas Gas Service Company, a Division of ONE Gas, Inc.); and TPA asked that the Commission consider requiring the critical customer information to be filed with the Commission in addition to filing with electric entities. TPA suggested that forms be consolidated so that the same forms can be filed with the RRC, ERCOT, PUCT, and transmission and distribution utilities (TDUs). The Texas LDCs recommended amending the definition of "critical customer information" to omit the reference to Table CCI and replace it with a reference to the Form CI-D. The Commission agrees with these comments. The proposed Table CCI is removed and replaced with the Form CI-D and its attachment. The Commission revised the Form CI-D to include the information that was listed on the Table CCI. Additional information was also added to the Form CI-D in response to comments. The Form CI-D is still required to be filed by any facility designated critical in §3.65(b). However, only critical customers are required to provide the "critical customer information" (i.e., the Form CI-D and its attachments) to their electric entity. The Commission will also grant the PUCT secure access to the forms filed with the Commission, so that the Commission, the PUCT, and the TDUs will have the same information. The Form CI-D attachment is currently in Excel form, which is the format requested by the Joint TDUs and ERCOT in their comments. The Commission notes that in the future an operator may be required to file the Form CI-D and attachment electronically without the use of Excel.

Subsection (a) is also adopted with a change to add a definition in subsection (a)(3). New subsection (a)(3) states, "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." This language is added to ensure production volumes are calculated consistently and allow for better evaluation by electric entities receiving critical customer information.

Subsection (b) - Critical Designation Criteria

Most commenters expressed concern that the proposal designated too many facilities critical such that the rule does not provide information electric entities need to incorporate critical natural gas facilities into their respective load-shed plans. These commenters include the Atmos Cities Steering Committee, Commission Shift, CPS Energy, Joint TDUs, Office of Public Utility Counsel (OPUC), PBPA, Public Citizen, Senate B&C, Southwestern Electric Power Company (SWEPCO), South Texas Electric Cooperative, Inc. (STEC), TCA, Texas Competitive Power Advocates (TCPA), Texas Electric Cooperatives (TEC), Texas Independent Producers and Royalty Owners Association (TIPRO), TXOGA, TPPA, TPA, and many individuals. Specifically, the Joint TDUs, PBPA, TIPRO, and TXOGA requested that wells that produce non-reportable or marginal amounts of gas not be designated critical. The Commission understands these concerns and has made several changes to narrow the universe of critical facilities.

First, subsection (b) is adopted with changes to include two classes of critical facilities. Subsection (b)(1) lists "critical gas suppliers." The list of critical gas suppliers is similar to the list of critical facilities in proposed subsection (b). However, the list is narrowed in three important areas: (1) critical gas wells are limited to those wells producing gas in excess of 15 Mcf/day; (2) critical oil leases are limited to those leases producing casinghead gas in excess of 50 Mcf/day; and (3) the catchall provision in proposed (b)(8) is removed. These revisions remove thousands of facilities from the universe of critical facilities. The Commission notes that the Alliance requested the Commission refrain from making a blanket declaration that all wells below a certain production threshold are not critical. The Commission disagrees. Removing wells and leases not producing a certain threshold from critical designation removes thousands of facilities but only 1.2-1.4% of total gas production. However, the Commission notes the addition of an option for such wells to apply for critical designation in new subsection (c), which is discussed below.

The Commission further narrowed the universe of critical facilities by requiring that only "critical customers" --defined as the critical gas suppliers for whom electricity is essential to the ability of such gas supplier to operate--provide critical customer information to the electric entities. This change will limit the volume of information that electric entities must process in connection with their load shed planning. Electric entities need not incorporate in their load-shed plans facilities that do not need power. Subsection (b) and subsection (g) are adopted with a change to clarify which electric entities must be provided critical customer information. Electric entities are those described in 16 Texas Administrative Code §25.52(h) and those described in Texas Utilities Code §38.074(b)(1).

The Commission adopts subsection (b) with another change to add "control centers" to the description of pipeline facilities designated critical in subsection (b)(1)(D) and (b)(1)(E). This addition was requested by the Texas LDCs.

Many of the commenters listed above requested that the rule incorporate a "tiering" concept for purposes of prioritizing facilities for load shed. These commenters include CPS Energy, Joint TDUs, the Alliance, PBPA, SWEPCO, STEC, TCPA, TPA, TIPRO, and TXOGA. The Commission does not have any jurisdiction over electric utilities or their load shed planning and accordingly, §3.65 does not include tiers. However, recognizing that there are certain facilities that play a more significant role than others in the natural gas supply chain due to their volumetric contributions or their proximity and connectedness to electric power generation facilities and local distribution companies, the adopted rule identifies facilities in new subsection (e) that are not eligible to apply for an exception to critical designation.

The Alliance, the Joint TDUs, STEC, TPA, and TXOGA included in their comments proposed "tiers" for prioritization of critical natural gas facilities for load-shed purposes during an energy emergency. However, the above-referenced organizations, representing several portions of the natural gas and electricity supply chain, did not provide consistent suggestions regarding which critical natural gas facilities should fall into the first tier. While the Commission does not have jurisdiction over electric utilities or electricity load-shed events, the Commission sent a letter to the PUCT on November 23, 2021 to offer suggestions for the PUCT's guidance document implementing Tex. Util. Code § 38.074(b)(2) relating to load-shed during an energy emergency. The Commission recommended the following facilities be given highest priority for maintaining electric service and restoring electric service following an outage: pipelines that directly provide natural gas to electric generation or to local distribution company facilities; underground natural gas transportation and storage facilities; natural gas liquids transportation and storage facilities; gas processing plants with a capacity of 200 MMcf/day and greater; natural gas wells and oil leases producing natural gas in the amount of 5000 Mcf/day or greater, and saltwater disposal wells, compressor stations, and control centers supporting the listed facilities. The letter also indicated support for the types of facilities that should be given lower priority, as proposed by the industry groups in their comments.

As mentioned above, facilities with a significant role in the natural gas supply chain are listed in new subsection (e). These facilities may not obtain an exception and, therefore, remain critical. Critical facilities that are not included in subsection (e) may apply for an exception to critical designation. These facilities are listed on the revised form CI-X and include gas wells producing less than or equal to 250 Mcf/day; oil leases producing less than or equal to 250 Mcf/day in casinghead gas; natural gas pipelines and pipeline facilities that do not directly serve local distribution companies or electric generation; and saltwater disposal wells and pipelines that do not support a facility listed under §3.65(e)(1)-(7). The process to apply for an exception is discussed below.

New Subsection (c) - Request for Critical Designation

The Commission adopts § 3.65 with a change to add new language in subsection (c). New subsection (c) creates an option for facilities that are excluded from critical designation in subsection (b) to apply for critical designation. The option to apply for critical designation is limited to two types of facilities: (1) facilities that are not designated in subsection (b) but are required to operate in order for another critical facility to operate; and (2) facilities that are not designated in subsection (b) but are included on the electricity supply chain map.

Subsection (c)(1) incorporates the catch-all provision from proposed subsection (b)(8). To limit the universe of facilities designated critical, the catch-all provision was removed from subsection (b). In subsection (c) as adopted, facilities that must operate in order for a critical facility to operate may apply for critical designation if they provide objective evidence that their operation is necessary for a critical facility to operate. Facilities that are included on the electricity supply chain map are required to apply for critical designation. Adopted changes in subsection (c) address comments from STEC, TCPA, TEC, and TPPA suggesting that the Commission require an application for critical designation rather than presume facilities are critical. The Commission agrees that for certain types of facilities, an application process is appropriate. The application process involves writing the Commission a letter requesting critical designation. If and when a facility's application is approved, the facility's operator will be required to file the Form CI-D.

Subsection (d) - Acknowledgment of Critical Status

The Commission received few comments on proposed subsection (d), which requires a critical facility to acknowledge its critical status on Commission Form CI-D. Comments from Commission Shift suggested that connectivity information be collected on the Form CI-D. Similarly, ERCOT, the Texas LDCs, TPA, TPPA, and TEC asked that the Commission consider requiring the critical customer information to be filed with the RRC in addition to electric entities. TPA suggested that forms be consolidated so that the same forms can be filed with the RRC, ERCOT, PUCT, and TDUs. The Texas LDCs recommended amending the definition of "critical customer information" to omit the reference to Table CCI and replace it with a reference to the Form CI-D. TPPA and TEC requested a requirement that critical customer information be provided to electric utilities at the same time the Form CI-D is filed with the Commission.

The Commission agrees and adopts subsections (a) and (d) with changes to address these comments. As mentioned above, the Table CCI is removed, and the information previously included on that Table CCI is now included on the Form CI-D attachment. The definition of "critical customer information" is revised in subsection (a) to reference the Form CI-D rather than the Table CCI. Section 3.65 now requires that all facilities designated critical in subsection (b) (both critical gas suppliers and critical customers) file the Form CI-D and any attachments with the Commission. Only critical customers are then required to file the same information with their electric entity. The certification on the Form CI-D is revised to reflect a requirement that a critical customer provide the critical customer information (i.e., the Form CI-D) to its electric entity before or at the same time the information is filed with the Commission. To address comments by TEC, the Commission has added the following statement to the Form CI-D: "Designation as a critical customer does not guarantee the uninterrupted delivery of electric service to your facilities."

Relatedly, some comments requested a certification on the Form CI-D that the facilities listed on the attachment are prepared to operate in a weather emergency. The Commission disagrees. It is not appropriate to require certification that a facility is prepared to operate until the Commission adopts weatherization rules to define what an operator must do to prepare to operate. PBPA and TPA requested language that filing the Form CI-D is not a guarantee that a facility will operate. The Commission agrees with PBPA and TPA but does not adopt this change in the rule or forms.

Subsection (d) as adopted removes references to an electronic acknowledgment or electronic system because the Commission's "RRC Online" filing system will be available to operators for filing Forms CI-D and CI-X by the time §3.65 is effective. A more comprehensive online system filing system for Forms CI-D and CI-X may be developed in the future and operators will be notified of such a new system.

Subsection (d) is adopted with a change to the biannual filing deadlines in 2022. A facility included on the electricity supply chain map will no longer be eligible for an exception and must file Form CI-D. The map will not be available by the first Form CI-D filing deadline of January 15, 2022. The second filing deadline in 2022 was proposed as September 1, 2022. However, that is the same deadline included in Senate Bill 3 for when the map must be produced. Therefore, in order to give facilities included on the map time to learn whether they are included on the map prior to filing the Form CI-D or Form CI-X, the Commission has altered the second filing deadline to September 1, 2022, or 30 days after the electricity supply chain map is published, whichever is later. Thus, if the map is published March 1, 2022, the second deadline for filing Form CI-D would be September 1, 2022, but if the map is not published until September 1, 2022, then the deadline for filing would be October 1, 2022 (30 days after the map is published).

The Commission notes STEC and TCPA suggested the rules make clear that the Form CI-D must be submitted for each facility, rather than permitting operators to submit a single form purporting to cover all of an operator's facilities. The Commission disagrees. The Form CI-D as proposed and adopted has a spreadsheet attachment that allows an operator to list of its critical facilities. The Commission and commenters who will use the form agree that a process that allows an operator to list all its facilities in one filing is most efficient. PBPA suggested that the Commission allow operators to supplement and amend forms as more information is available. The Commission agrees that forms it requires to be filed may be updated as appropriate.

Commission Shift, PBPA, and TXOGA asked that the Commission clarify how its Form CI-D process works with the ERCOT Critical Load Designation Form. PBPA also asked the Commission to make changes to ensure §3.65 does not prevent participation in ERCOT's Load Resources Program. The Commission declines to adopt any changes in response to these comments. Based on ERCOT's comments, the Commission expects that ERCOT will use information provided on Form CI-D moving forward, but the Commission cannot speak for ERCOT on that matter. To ensure entities associated with providing natural gas in Texas are considered critical for Winter 2021-2022, the Commission sent Notices to Operators reminding operators within Commission jurisdiction to file ERCOT's Critical Load Designation Form.

New subsection (e) - Facilities Not Eligible for An Exception

As mentioned above, many commenters expressed concerns about the exception provision in proposed §3.65. These commenters include Senate B&C, the American Public Gas Association (APGA), City of Houston, Commission Shift, CPS Energy, LCRA, OPUC, Sierra Club, TCA, TPPA, and the comments submitted by individuals. The comments requested that the Commission limit the types of facilities that can obtain an exception. Several comments, such as those by STEC, TPPA, and TCPA, specifically suggested that facilities included on the electricity supply chain map be ineligible for an exception.

As mentioned above, the Commission adopts §3.65 with new language in subsection (e) to list facilities that are not eligible for an exception to critical designation. The facilities not eligible for an exception are those with a significant contribution to the natural gas supply chain, namely, facilities on the electricity supply chain map; gas wells or oil leases producing gas or casinghead gas in excess of 250 Mcf/day; gas processing plants; natural gas pipelines or pipeline facilities that directly serve local distribution companies or electric generation; local distribution company pipelines or pipeline facilities; underground natural gas storage facilities; natural gas liquids storage and transportation facilities; and saltwater disposal facilities that support the other listed facilities. Because these facilities are not eligible for an exception, they will remain critical for load shed purposes and they will be required to weatherize if they are included on the electricity supply chain map.

Subsection (f) - Critical Designation Exception

Other commenters opposed the process for a facility to obtain an exception. These commenters include APGA, Atmos Cities Steering Committee, Commission Shift, CPS Energy, Joint TDUs, LCRA, OPUC, Sierra Club, TCA, TPPA, and the comments submitted by individuals. The concern expressed in these comments is that an exception could be obtained too easily and the comments suggested including a more robust application and review process. The Commission agrees and clarifies its exception review process in subsection (f)(1).

New language added in (f)(1) requires that an application for exception to critical designation include objective evidence to demonstrate a reasonable basis and justification in support of the application. Some commenters, including the Alliance, requested examples of information an operator could provide to obtain an exception. Subsection (f)(1) includes an example of a reasonable basis and justification, which is that all of the gas produced at a critical facility is for on-site consumption or is otherwise not available for third-party use. The evidence demonstrating the reasonable basis must be included with the applicant's Form CI-X. Subsection (f) further states that the application will be approved or denied by the Director of the Critical Infrastructure Division, and if denied, the applicant will have an opportunity to request a hearing.

The Commission also adopts changes to the exception application language similar to the changes made in subsection (d) for the Form CI-D - references to an electronic acknowledgement are removed and filing deadlines for 2022 are altered to allow facilities included on the electricity supply chain map to learn of their map status prior to filing Form CI-D or Form CI-X as appropriate.

Commenters such as OPUC, Sierra Club, and individuals opposed the amount an operator is required to pay for an exception application. The Commission understands this concern but the Commission cannot charge a fee or penalty unless it has statutory authority. With regard to the $150 exception application fee, the Commission's authority comes from Natural Resources Code section 81.0521, which sets the fee amount at $150.

APGA and LCRA asked that the Commission require facilities granted an exception to disclose this information to their counterparties on the supply chain so the counterparties can prepare appropriately. The Commission understands this concern and notes that whether a facility obtains an exception is public information that will be available unless claimed confidential under the Public Information Act.

Subsection (g) - Providing Critical Customer Information

The Commission adopts proposed subsection (e) as subsection (g). Subsection (g) clarifies that only critical customers are required to provide critical customer information to their electric entities. Subsection (g) is adopted with a change to clarify which electric entities must be provided critical customer information. Electric entities are those described in 16 Texas Administrative Code §25.52(h) and those described in Texas Utilities Code §38.074(b)(1). Due to comments from TPPA, subsection (g) is adopted with a change to require that critical customers provide critical customer information (the Form CI-D) to their electric entity prior to or at the same time the critical customer files the Form CI-D with the Commission. As mentioned above, this statement was also added to the certification language on the Form CI-D.

TPPA and TEC commented that the Commission should also require critical customers to timely respond to an electric entity's reasonable request for additional information within five business days of receipt of the request. The Commission agrees that critical customers and their electric entities should work together to ensure the electric entity has the information it needs for load-shed purposes. However, the Commission does not agree this language should be included in the rule.

Subsection (h) - Confidentiality of Information Filed Pursuant to §3.65

The Commission adopts §3.65 with a change to add new subsection (h). CPS Energy, Texas LDCs, and TPA requested that if critical customer information is provided to the Commission in addition to electric entities, the Commission specify how the information will be kept confidential. Though no provision of law excludes the information collected under this rule from the Public Information Act and the Commission cannot determine whether information is confidential, the Commission adds subsection (h) to describe the process prescribed under the Public Information Act, Texas Government Code Chapter 552, for claiming information is confidential. The Commission has also added a section on both the Form CI-D and Form CI-X to allow filers to indicate that information included on the forms/attachments is confidential.

Subsection (i)

The Commission did not receive comments on proposed subsection (f), "Exceptions not transferable," adopted as subsection (i). Therefore, that provision is adopted with only minor changes to correct internal rule references.

§3.65(j) and §3.107

The Commission received comments from Atmos Cities Steering Committee, Commission Shift, CPS Energy, OPUC, and Sierra Club opposing the minimum penalties specified in the proposed amendments to §3.107, which is referenced in §3.65(j). Atmos Cities Steering Committee and CPS Energy suggested that the penalties align with those in the statute relating to weatherization requirements. That statute, Natural Resources Code §86.222, gives the Commission authority to issue a penalty up to $1,000,000 for each violation of a rule adopted under Natural Resources Code §86.044. However, §3.65 is not adopted under Natural Resources Code §86.044. The statute requiring adoption of a critical designation rule, Natural Resources Code §81.073, does not provide the Commission penalty authority. Therefore, the Commission relies on its general penalty authority in Natural Resources Code § 81.0531. The Commission notes that the penalties to which commenters are opposed are included in the Commission's penalty guidelines rule and are merely minimum penalties. The Commission has discretion to increase the penalties if circumstances warrant an increase. Therefore, the Commission adopts the penalty amounts as proposed, with the only adopted changes to §3.107 being updates to subsection references in §3.65.

TEC and TPPA asked that the Commission penalize critical facilities who fail to provide required information by removing those facilities' critical designation. The Commission disagrees because removing critical status as a penalty could incentivize non-compliance.

The Commission adopts the new rule 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. The amendments are adopted under Texas Natural Resources Code, §81.0531, which gives the Commission authority to assess a penalty if a person violates provisions of Texas Natural Resources Code, Title 3, that pertain to safety or the prevention or control of pollution or the provisions of a rule, order, license, permit, or certificate that pertain to safety or the prevention or control of pollution that are issued under Title 3.

Statutory authority: Natural Resources Code §§81.051, 81.052, 81.0531, 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 or has the potential to result in firm load shed required by the reliability coordinator of a power region in Texas.

(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.

(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 15 Mcf/day;

(B) oil leases producing casinghead gas in excess of 50 Mcf/day;

(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 for whom the delivery of electricity from an electric entity is essential to the ability of such gas supplier to operate. A critical customer is required to provide critical customer information pursuant to subsection (g) 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.

(1) 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. If approved, the facility shall submit Form CI-D.

(2) A facility that is not designated critical under subsection (b) of this section but that is included on the electricity supply chain map produced by the Texas Electricity Supply Chain Security and Mapping Committee shall write to the Commission to apply to be designated critical, and after approval, shall submit Form CI-D.

(d) Acknowledgment of critical status. Except as provided by subsection (f) of this section, an operator of a facility designated as critical under subsection (b) 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) Facilities not eligible for an exception. Because of their contribution to the natural gas supply chain, the following facilities designated critical under subsection (b) of this section are not eligible for an exception under subsection (f) of this section:

(1) a facility included on the electricity supply chain map produced by the Texas Electricity Supply Chain Security and Mapping Committee;

(2) gas wells or oil leases producing gas or casinghead gas in excess of 250 Mcf/day;

(3) gas processing plants;

(4) natural gas pipelines or pipeline facilities that directly serve local distribution companies or electric generation;

(5) local distribution company pipelines or pipeline facilities;

(6) underground natural gas storage facilities;

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

(8) a saltwater disposal facility, including a saltwater disposal pipeline, that supports a facility listed in paragraphs (1) through (7) of this subsection.

(f) Critical designation exception.

(1) A facility listed in subsection (b) of this section other than those identified in subsection (e) of this section may apply for an exception. An applicant shall demonstrate with objective evidence a reasonable basis and justification in support of the application, such as all of the gas produced at a facility is for on-site consumption, or the facility does not otherwise provide gas for third-party use. 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) 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.

(g) 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 (f) 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.

(h) 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.

(i) 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 (f) of this section. If the facility has an exception under subsection (f) 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 (f) of this section.

(j) 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).

§3.107.Penalty Guidelines for Oil and Gas Violations.

(a) Policy. Improved safety and environmental protection are the desired outcomes of any enforcement action. Encouraging operators to take appropriate voluntary corrective and future protective actions once a violation has occurred is an effective component of the enforcement process. Deterrence of violations through penalty assessments is also a necessary and effective component of the enforcement process. A rule-based enforcement penalty guideline to evaluate and rank oil- and natural gas-related violations is consistent with the central goal of the Commission's enforcement efforts to promote compliance. Penalty guidelines set forth in this section will provide a framework for more uniform and equitable assessment of penalties throughout the state, while also enhancing the integrity of the Commission's enforcement program.

(b) Only guidelines. This section complies with the requirements of Texas Natural Resources Code, §81.0531 and §91.101, which provides the Commission with the authority to adopt rules, enforce rules, and issue permits relating to the prevention of pollution. The penalty amounts shown in the tables in this section are provided solely as guidelines to be considered by the Commission in determining the amount of administrative penalties for violations of provisions of Texas Natural Resources Code, Title 3; Texas Water Code, Chapters 26, 27, and 29, that are administered and enforced by the Commission; or the provisions of a rule adopted or order, license, permit, or certificate issued under Texas Natural Resources Code, Title 3, or Texas Water Code, Chapters 26, 27, and 29. This rule does not contemplate automatic enforcement. Violations can be corrected by operators before being referred to legal enforcement.

(c) Commission authority. The establishment of these penalty guidelines shall in no way limit the Commission's authority and discretion to cite violations and assess administrative penalties. The guideline minimum penalties listed in this section are for the most common violations cited; however, this is neither an exclusive nor an exhaustive list of violations that the Commission may cite. The Commission retains full authority and discretion to cite violations of Texas Natural Resources Code, Title 3; including Nat. Res. Code §91.101, which provides the Commission with the authority to adopt rules, enforce rules, and issue permits relating to the prevention of pollution; the provisions of Texas Water Code, Chapters 26, 27, and 29, that are administered and enforced by the Commission; and the provisions of a rule adopted or an order, license, permit, or certificate issued under Texas Natural Resources Code, Title 3, or Texas Water Code, Chapters 26, 27, and 29, and to assess administrative penalties in any amount up to the statutory maximum when warranted by the facts in any case, regardless of inclusion in or omission from this section.

(d) Factors considered. The amount of any penalty requested, recommended, or finally assessed in an enforcement action will be determined on an individual case-by-case basis for each violation, taking into consideration the following factors:

(1) the person's history of previous violations;

(2) the seriousness of the violation;

(3) any hazard to the health or safety of the public; and

(4) the demonstrated good faith of the person charged.

(e) Typical penalties. Regardless of the method by which the guideline typical penalty amount is calculated, the total penalty amount will be within the statutory limit.

(1) A guideline of typical penalties for violations of Texas Natural Resources Code, Title 3; the provisions of Texas Water Code, Chapters 26, 27, and 29, that are administered and enforced by the Commission; and the provisions of a rule adopted or an order, license, permit, or certificate issued under Texas Natural Resources Code, Title 3, or Texas Water Code, Chapters 26, 27, and 29, are set forth in Table 1.

Figure: 16 TAC §3.107(e)(1) (.pdf)

(2) Guideline penalties for violations of §3.73 of this title, relating to Pipeline Connection; Cancellation of Certificate of Compliance; Severance, include additional penalty amounts that are based on four components. In combination, these four components yield the factor by which an additional penalty amount of $1,000 is multiplied. The various combinations of the components are set forth in Table 1A.

(A) The first component is the length of the violation. A low rating means the violation has been in existence less than three months. A medium rating means the violation has been outstanding for more than three months and up to one year. A high rating means the violation has been outstanding for more than one year.

(B) The second component is production value. A low rating means the value of the production is less than $5,000. A medium rating means the value of the production is more than $5,000 and up to $100,000. A high rating means the value of the production is more than $100,000.

(C) The third component is the number of unresolved severances. A low rating means there are fewer than two unresolved severances. A medium rating means there are more than two and up to six unresolved severances. A high rating means there are more than six unresolved severances.

(D) The fourth component is the basis of the severance. The letter "N" indicates that the severance is not pollution related. The letter "Y" indicates that the severance is pollution related.

Figure: 16 TAC §3.107(e)(2)(D) (No change.)

(f) Penalty enhancements for certain violations. For violations that involve threatened or actual pollution; result in threatened or actual safety hazards; or result from the reckless or intentional conduct of the person charged, the Commission may assess an enhancement of the guideline penalty amount. The enhancement may be in any amount in the range shown for each type of violation as shown in Table 2.

Figure: 16 TAC §3.107(f) (No change.)

(g) Penalty enhancements for certain violators. For violations in which the person charged has a history of prior violations within seven years of the current enforcement action, the Commission may assess an enhancement based on either the number of prior violations or the total amount of previous administrative penalties, but not both. The actual amount of any penalty enhancement will be determined on an individual case-by-case basis for each violation. The guidelines in Tables 3 and 4 are intended to be used separately. Either guideline may be used where applicable, but not both.

Figure 1: 16 TAC §3.107(g) (No change.)

Figure 2: 16 TAC §3.107(g) (No change.)

(h) Penalty reduction for accelerated settlement before hearing. The recommended monetary penalty for a violation may be reduced by up to 50% if the person charged agrees to an accelerated settlement before the Commission conducts an administrative hearing to prosecute a violation. Once the hearing is convened, the opportunity for the person charged to reduce the basic monetary penalty is no longer available. The reduction applies to the basic penalty amount requested and not to any requested enhancements.

(i) Demonstrated good faith. In determining the total amount of any monetary penalty requested, recommended, or finally assessed in an enforcement action, the Commission may consider, on an individual case-by-case basis for each violation, the demonstrated good faith of the person charged. Demonstrated good faith includes, but is not limited to, actions taken by the person charged before the filing of an enforcement action to remedy, in whole or in part, a violation or to mitigate the consequences of a violation.

(j) Penalty calculation worksheet. The penalty calculation worksheet shown in Table 5 lists the guideline minimum penalty amounts for certain violations; the circumstances justifying enhancements of a penalty and the amount of the enhancement; and the circumstances justifying a reduction in a penalty and the amount of the reduction.

Figure: 16 TAC §3.107(j) (.pdf)

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 30, 2021.

TRD-202104769

Haley Cochran

Rules Attorney, Office of General Counsel

Railroad Commission of Texas

Effective date: December 20, 2021

Proposal publication date: October 1, 2021

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


PART 2. PUBLIC UTILITY COMMISSION OF TEXAS

CHAPTER 24. SUBSTANTIVE RULES APPLICABLE TO WATER AND SEWER SERVICE PROVIDERS

SUBCHAPTER C. ALTERNATIVE RATE METHODS

The Public Utility Commission of Texas (commission) repeals existing 16 Texas Administrative Code (TAC) §24.75 and adopts new 16 TAC §24.75, relating to Alternative Ratemaking Methodologies. The commission also adopts new 16 TAC §24.76, relating to System Improvement Charge. Both rules are adopted with changes to the proposed text as published in the June 4, 2021, issue of the Texas Register (46 TexReg 3481). Repealed §24.75 will not be republished. New §24.75 and §24.76 will be republished. These rules implement Texas Water Code (TWC) §13.183(c) enacted by the 86th Texas Legislature by establishing alternative ratemaking methodologies for water and sewer utility rates and establishing the requirements for a system improvement charge (SIC).

No party requested a public hearing; therefore, a public hearing was not held.

The commission received comments and reply comments on the proposed amendments from CSWR Texas Utility Operating Company, LLC (CSWR), Texas Association of Water Companies, Inc., and National Association of Water Companies (jointly TAWC/NAWC), and Office of Public Utility Council (OPUC).

§24.75(c) - Cash needs method

Under proposed §24.75(c), a Class C or Class D utility is allowed to use the cash needs method, if necessary, to establish the utility's revenue requirement in a comprehensive rate proceeding for the utility to provide continuous and adequate service or if other good cause exists to support the use of the cash needs method.

TAWC/NAWC stated that Class A and Class B utilities should be allowed to use the cash needs method "as there appears to be no justification for [the] limitation" to Class C and Class D utilities.

OPUC supported the limitation to Class C and Class D utilities.

Commission Response

The commission declines to allow Class A and Class B utilities to use the cash needs method. The use of the cash needs method is generally more suitable for the operating and financial aspects of smaller companies such as Class C and Class D utilities. Class A and Class B utilities most commonly use the rate base rate of return method but can apply for a good cause exception to use the cash needs method if necessary.

§24.75(c)(3)(A) - Inclusion of an additional margin

Under proposed §24.75(c)(3)(A), a utility may request an operating margin in addition to operations and maintenance expenses if the utility's most recent annual report included net plant of less than 25 percent of its related original cost. The proposed rule provides that an operating margin of up to five percent of operating expenses will be considered reasonable and may be included in the utility's revenue requirement.

TAWC/NAWC recommended that the operating margin presumed reasonable should be raised to ten percent or eliminated entirely.

Commission Response

The commission declines to adopt TAWC/NAWC's recommendation. A utility is not limited to five percent of operating expenses. Rather, the five percent limit only applies to what will be presumed reasonable. A utility may request a coverage amount above five percent of its operating expenses with appropriate evidentiary support.

§24.75(d)(1) - Form of application

Under proposed §24.75(d), a utility may request the addition of a new customer class or classes without filing a base rate case. Proposed paragraph (d)(1) outlines the application requirements for requesting a new customer class.

Commission Action

The commission amends §24.75(d)(1)(A) to clarify that a cost-of-service and rate design study must be submitted for each new proposed customer class.

§24.75(d)(3)(A) - Rate case requirement

Under proposed §24.75(d)(3)(A), a utility that has received commission approval for the creation of a new customer class or classes must file a comprehensive rate case not later than 18 months from the date service begins unless the utility can demonstrate that each new customer class represents less than ten percent of the utility's total annual revenue.

TAWC/NAWC requested clarification that the exception from filing a new rate case under proposed §24.75(d)(3)(A) applies when each new customer class individually represents less than ten percent of the utility's total annual revenue.

Commission Response

The commission declines to modify the language of this section. The proposed language clearly articulates that "each new customer class" must represent less than ten percent of the utility's total annual revenue. The addition of "individually" would be superfluous.

§24.75(d)(3)(B) and (C) - Exception to filing and required filing

Under proposed §24.75(d)(3)(B), if the utility fails to show in its annual report that each new customer class remains less than ten percent of the utility's total annual revenue, a utility is not required to submit a comprehensive rate case until a maximum of five years after the date service begins if it demonstrates to the commission that each new customer class represents less than ten percent of the utility's total annual revenue requirement. The utility is required to report the amount of revenues each customer class represents in its annual report. Under proposed §24.75(d)(3)(C), a utility is required to file a comprehensive rate case within the earlier of six months from the date its annual report is due under §24.129(a) or five years from the date service to the new customer class or classes began.

TAWC/NAWC commented that language should be added to clarify that after the comprehensive rate case is filed, the amount of revenues each class represents is no longer required in its annual report.

Commission Response

The commission declines to adopt TAWC/NAWC's recommendation. The act of filing a rate case is insufficient to relieve a utility of its obligation to continue to provide demonstrations that the new customer class remains less than ten percent of the utility's total annual revenue. Merely filing a rate case does not guarantee that new rates will be approved by the commission. This would create a compliance loophole that would allow a utility to defer initiating a rate case for longer than intended. Accordingly, the utility must continue to provide demonstrations as a part of its annual report until a final order is issued in the utility's next comprehensive base rate case or upon the triggering of one of the conditions in the rule that requires the utility to file a comprehensive base rate case under (B) and (C). For example, if the revenues from a new customer class increase above ten percent of the utility's total annual revenues or five years have passed since service to the new customer class has begun, the utility is no longer required to provide demonstrations as part of its annual report, because one of the requirements to initiate a rate case has already been triggered.

§24.76 - System improvement charge

Under proposed §24.76, the requirements for a SIC are established.

TAWC/NAWC stated that the SIC should be part of the commission's minor tariff change procedures found in §24.25(b)(2) (relating to Form and Filing of Tariffs), and that the applications should not be referred to the State Office of Administrative Hearings (SOAH) for hearing, as the goal is for the process to be streamlined. TAWC/NAWC further commented that allowing parties to intervene and allowing for referrals to SOAH makes the SIC process expensive, complicated, and may lead to more rate case expenses.

Commission Response

The commission declines to adopt TAWC/NAWC's recommendations. The minor tariff change provisions of §24.25 are outside of the scope of this proceeding. Moreover, a request for a SIC is a rate proceeding, not a minor tariff change.

The commission finds that allowing the proceeding to be sent to SOAH is necessary to provide ratepayers an opportunity to participate in the SIC proceeding. Further, allowing this participation is consistent with similar substantive rules regarding electric rate proceedings such as §25.193 (relating to Distribution Service Provider Transmission Cost Recovery Factors (TCRF)) and §25.243 (relating to Distribution Cost Recovery Factor (DCRF)). Both rules are intended to provide for administratively streamlined proceedings that result in expedited implementation of updated rates, but which may contain certain circumstances that require referral to SOAH.

TAWC/NAWC and CSWR stated that §24.76 should explicitly include a provision for rate case expense recovery. CSWR commented that recovery of rate case expenses should be allowed because related costs may be relatively high, which could result in some smaller utilities incurring litigation expenses that are greater than the amount of additional revenues provided by implementation of the SIC. CSWR further opined that a cost recovery proceeding is necessary because significant litigation expenses incurred pursuant to a SIC may disincentivize the use of the proceeding by utilities if such costs are not reimbursable. Alternatively, CSWR recommended the initiation of a new rulemaking to address the recovery of expenses associated with filing and litigating rate proceedings

OPUC agreed with TAWC/NAWC and CSWR on modifying §24.76 to provide for SIC rate case expense recovery but stated that such recovery should be addressed in the utility's next comprehensive base rate case proceeding to allow for thorough review of the expenses while keeping the SIC proceeding streamlined. OPUC also argued that inclusion of SIC rate case expense recovery in a base rate proceeding allows for the examination of the prudence of expenses.

Commission Response

The commission agrees that the rule should explicitly state that a utility may request recovery of rate case. The commission agrees with OPUC that rate case expenses should be reviewed in the utility's next comprehensive base rate case to allow for an examination of the prudence of expenses without further delaying the SIC proceeding. The commission adds the following language: "Recovery of rate case expenses may be requested and must be reviewed in the utility's next comprehensive base rate case and in accordance with §24.44 of this chapter."

§24.76(b)(1) - Eligible plant

Under proposed §24.76(b)(1), "eligible plant" is defined as, "[p]lant properly recorded in the National Association of Regulatory Utility Commissioners System of Accounts, accounts 304 through 339 for water utility service or accounts 354 through 389 for sewer utility service."

OPUC noted that "eligible plant," as proposed, is not limited to one discrete water or sewer facility. OPUC argued that the definition of "eligible plant" should be limited to preclude utilities from using the SIC as a catch-all mechanism for all interim plant investment between comprehensive rate cases. OPUC recommended including "a single plant" at the beginning of the definition. OPUC referenced the Generation Cost Recovery Rider (GCRR), codified as 16 TAC §25.248 (relating to Generation Cost Recovery Rider), as an example where the commission specifically limited the application to a single discrete power generation facility.

TAWC/NAWC and CSWR opposed OPUC's proposed definition for "eligible plant." TAWC/NAWC and CSWR argued that, unlike electric generation plants, water and sewer systems are not composed of a single discrete facility, and it is impractical to require a separate SIC application for each component of the water or sewer system. CSWR argued that, because only one SIC can be in effect at one time, utilities that operate multiple systems would be precluded from using the mechanism to recover investments made in all but one of its systems.

TAWC/NAWC argued that TWC §13.183(a) and (c) do not confine the definition of "eligible plant" to a single plant and that all of a utility's invested capital used and useful without restriction should be included in a utility's rates. Therefore, in TAWC/NAWC's view, the SIC should allow for inclusion of a utility's capital improvements recordable in the listed accounts within the proposed rule. TAWC/NAWC also stated that "eligible plant" should be broadly defined to maximize a utility's ability to use a SIC for invested capital recovery.

Commission Response

The commission declines to change the definition of eligible plant to "a single plant" as water and wastewater systems are not discrete facilities. The commission also clarifies, in response to CSWR's reply comment, that under (c)(1), a utility must have only one SIC in effect for each of its rate schedules at any time. Because each system would have its own rate schedules, a utility with multiple systems is not prohibited from having a SIC in effect for each system.

§24.76(c)(4) -Timing of application with final rate case

Under proposed §24.76(c)(4), a utility cannot apply to establish or amend a SIC until 12 months after a commission order establishing rates is final and appealable.

TAWC/NAWC and CSWR asserted that the 12-month restriction creates a maximum waiting period of 45 months to file a SIC case, citing a 12-month test year period prior to filing, plus the time it takes to assemble a rate filing package, plus "up to a year or two after an application is filed and accepted to [be] complete," plus the 12-month waiting period, plus up to nine additional months depending on the "[Certificate of Convenience and Necessity]-specific time periods to file in proposed §24.76(c)(6)." TAWC/NAWC also stated that the SIC rules should reflect the timelines and processes of the generation cost recovery rider under §25.248, and interim Transmission Cost of Service (TCOS) proceedings under §25.192(h) (relating to Transmission Service Requirements).

Commission Response

The commission does not agree with the commenters that the proposed rule creates a 45-month waiting period. However, the commission does agree that the 12-month waiting period creates an unnecessary delay in implementing a SIC and removes this requirement from the adopted rule.

§24.76(c)(6) -Timing of application to calendar quarter

Under proposed §24.76(c)(6), a utility may apply to establish or amend a SIC, limited to filing in a specific quarter of the calendar year based on the last two digits of a utility's certificate of convenience and necessity CCN number, unless good cause is shown for filing in a different quarter. For a utility holding multiple CCNs, the utility can file in any quarter for which any of its CCNs is eligible.

TAWC/NAWC opposed the requirement in §24.76(c)(6) limiting SIC filings to certain months based on the utility's CCN number as in practice this could increase the waiting period for filing a SIC application to 21 months after a comprehensive rate case is finalized. TAWC/NAWC stated that they do not expect that adding a SIC process would create the type of workload that would necessitate CCN-specific filing time windows, particularly if the SIC process is streamlined as intended. TAWC/NAWC also stated that, in its view, there will not be many utilities filing and SIC cases do not need to be spread out. Lastly, TAWC/NAWC stated that the GCRR proceedings under §25.248 and interim TCOS proceedings under §25.192(h) do not have a similar CCN-based time-to-file limitation as §24.76(c)(6) imposes and therefore the limitation should be removed.

Commission Response

Because establishment of a SIC is a new process, it is difficult to predict how many requests will be filed. Without a schedule, the number of requests could potentially create an administrative burden on the commission and delay the processing of requests, contrary to the streamlined method intended by the rule. In addition, there are significantly more water utilities eligible for SIC than there are electric utilities eligible for GCRR and interim TCOS. Therefore, the commission declines to remove the schedule.

§24.76(c)(7) - Multi-step implementation

Under proposed §24.76(c)(7), the commission, either on its own motion, at the request of the utility seeking the SIC, or at the request of any other interested party, may approve a SIC charge as a multi-step rate increase if such a rate increase is already in effect or to limit the utility's annual total revenue increase to no more than ten percent. This mirrors the parties that are eligible to request a multi-step rate increase as part of a base rate case under §24.75(b)(2).

TAWC/NAWC stated that the language "any other interested party" would complicate what should be a streamlined process. TAWC/NAWC further requested that the commission eliminate the wording "or if necessary to limit the utility's annual total revenue increase to no more than 10 percent," or at least add the wording "unless there is good cause to exceed that limit." TAWC/NAWC argued that the revenue increase limitation should be determined on a case-by-case basis and that the described limit may be too restrictive.

Commission Response

The commission agrees with TAWC/NAWC that allowing any interested party to request a multi-step implementation of a SIC could complicate what is intended to be a streamlined process. Further, the commission may approve the multi-step implementation at its discretion, without explicit language in the rule. Therefore, the commission deletes proposed §24.76(c)(7).

§24.76(d)(4) - Annual report

Under proposed §24.76(d)(4), an application for a SIC must include the utility's most recent annual report filed with the commission, which must be the annual report most recently due for filing.

TAWC/NAWC proposed eliminating this requirement, stating that a utility filing a SIC application should be allowed to refer to a publicly available report that it has already filed with the commission pursuant to a utility's obligation under §24.129, and that it should not have to re-file the report as part of the SIC application.

Commission Response

The commission declines to remove the requirement to include the annual report in a SIC application. Submitting the annual report with the SIC application ensures that all relevant information to the SIC determination is readily available in the SIC docket. The commission has recently switched to e-filing and, therefore, attaching the annual report to the SIC application is not burdensome.

§24.76(e)(10)(B) - After-tax rate of return

Proposed §24.76(e)(9), adopted as §24.76(e)(10)(B), determines the after-tax rate of return used in calculating a utility's SIC. Under subparagraph (B), if the final order for a utility's last comprehensive base rate case was issued three or more years before the date the SIC application is filed, the after-tax rate of return is computed by using the average rate of return for settled and fully litigated approved rates of return for water and sewer utilities over the three years immediately preceding the filing of the SIC application.

OPUC agreed with the after-tax rate of return limitations of the proposed rule and further recommended limiting the increase in rate of return, over the utility's last commission-approved rate of return, to ten percent. OPUC stated that in the same way a utility's annual revenues are limited to a ten percent increase in §24.27(c)(7) (relating to Notice of Intent and Application to Change Rates Pursuant to TWC §13.187 or §13.1871), the authorized return should also be limited to a ten percent increase.

TAWC/NAWC opposed OPUC's proposed limitation, arguing that revenue growth resulting from a SIC does not equate to return. TAWC/NAWC requested clarification on whether the term "return" used in §24.76(e)(9) adopted as §24.76(e)(10), refers to the return on equity or the overall return.

CSWR argued that the commission should remove §24.76(e)(9)(B), adopted as §24.76(e)(10)(B), and instead use the utility's approved rate of return in lieu of the after-tax rate of return as the rule currently states. CSWR argued that each utility has its own capital structure and financing needs and, therefore, may have a different overall rate of return than the average of the commission's recently approved rates of return. CSWR opined that a case-by-case approach utilizing an individual utility's approved rate of return is more favorable to smaller utilities from a financing and cost-recovery risk perspective than the average rate of return provided in the proposed rule. CSWR argued that imputing an average rate of return based on rate cases filed by other utilities would entirely decouple a utility's commission-approved reasonable and necessary rate of return from its actual capital structure, cost of debt, risk profile, and financing needs. CSWR stated that if the commission finds that a utility's return that was approved three years prior is too high, it can require the utility to file a comprehensive rate case at any time where utility-specific evidence can be presented to justify any modification to the rate of return. CSWR argued that the commission should remove §24.76(e)(9)(B), adopted as §24.76(e)(10)(B), entirely, but that if the commission keeps the provision, OPUC's proposed changes to §24.76(e)(9)(B), adopted as §24.76(e)(10), should be denied. CSWR commented that, if §24.76(e)(9)(B), adopted as §24.76(e)(10), is not deleted and the commission does not reject OPUC's proposed limitation, the commission should apply the ten percent limitation to both increases and decreases to the rate of return.

Commission Response

The commission declines to remove §24.76(e)(9)(B), adopted as §24.76(e)(10)(B), as requested by CSWR. If a utility decides to use a company-specific return, it may file a rate case on its own motion, or it can use the average of the most recent three years of commission-approved rates. While a rate of return for water and sewer utilities that was approved three or more years ago may not cause a utility to over-earn, it is not current, and should not be applied to a SIC, because a SIC consists of plant financed under current market conditions.

The commission also declines to limit a company's rate of return to a ten percent increase over the rate approved by the commission in the utility's last comprehensive rate case, as proposed by OPUC. Applying a ten percent increase limitation to a rate of return approved more than three years prior may not appropriately reflect current market conditions.

The commission does, however, clarify which return is being referenced, as requested by TAWC/NAWC. The commission adds the language "weighed average cost of capital" or "overall" as appropriate.

§24.76(f) - Notice

Under §24.76(f), the intervention deadline in SIC proceedings is 25 days from the date service of notice is complete.

CSWR argued that if the commission accepts its proposal to reduce the deadline for the commission to issue a final order in SIC proceedings from 120 to 60 days, as discussed in heading §24.76(g) below, the commission should also reduce the intervention deadline from 25 to 21 days.

Commission Response

As previously discussed, the commission has declined to implement CSWR's recommendation to reduce the deadline for the commission to issue a final order in SIC proceedings from 120 to 60 days. Accordingly, the CSWR's comments regarding the intervention deadline are moot.

§24.76(g) - Processing of application

Under proposed §24.76(g), the presiding officer must set a procedural schedule that will enable the commission to issue a final order within 120 days after the application is determined to be sufficient.

CSWR stated that the SIC should be streamlined similar to proceedings for interim TCOS proceedings under §25.192(h) and GCRR applications under §25.248, both of which are mechanisms for expedited cost recovery for electric companies with significantly shorter timelines. CSWR contended that there is no reason a SIC would be more complex or take longer to review than an interim TCOS proceeding or GCRR application. CSWR recommended a timeline of 60 days after a materially sufficient application is filed similar to an interim TCOS proceeding under §25.192, or 60 days after an application is deemed sufficient consistent with the GCRR application under §25.248.

Commission Response

The commission declines to change the schedule as proposed by CSWR. The commission anticipates that, for some utilities, SIC application reviews may be complex and require significant review of detailed company-specific information. The commission also notes that a distribution cost recovery factor (DCRF) proceeding under §25.243--a similar cost-recovery mechanism for electric companies that has well-established administrative procedures--is processed on a 150-day schedule.

§24.76(g)(2) - Requests for information

Under proposed §24.76(g)(2), after an application is deemed sufficient, the applicant must respond to requests for information within ten days. An applicant's failure to timely respond to requests for information constitutes good cause for extending the deadline for final action one day for each day that a response exceeds ten days.

TAWC/NAWC and CSWR opposed linking the deadline for final approval to the timeliness of discovery responses. CSWR recommended removing this provision. CSWR stated that tying the deadline for final approval to the timing of the applicant's discovery responses is unnecessary and potentially confusing. CSWR additionally commented that parties that fail to comply with discovery deadlines are already subject to sanctions under the commission's rules, and parties can request a hearing if they believe there are controversial issues that cannot be resolved through the discovery process that necessitate further delay of the proceeding. CSWR also opined that this requirement means the deadline for final action is in constant flux.

In the alternative, CSWR recommended that the ten-day discovery deadline be changed to ten working days and should only affect the deadline if requested by a party through a motion filed pursuant to §22.77 (relating to Motions).

If neither of its prior proposals for §24.76(g)(2) are adopted, CSWR alternatively recommended adding language to clarify that the extension does not apply in situations where a timely filed discovery response is updated or supplemented, or where a discovery request is subject to an objection that extends the deadline for filing the response.

Commission Response

The commission declines to remove or otherwise modify paragraph (g)(2) as requested by TAWC/NAWC and CSWR. Late responses must undergo the same review as timely responses, with identical deadlines, and commission staff must be able to request an extension of time if necessary, to properly evaluate an application. Moreover, an extension of the deadline serves as an incentive for utilities to timely response to requests for information. The commission disagrees with CSWR's contention that the risk of sanctions for untimely responses to requests for information or the ability of a party to request a hearing to extend the discovery process mitigates the need for this provision. Asking the commission to impose sanctions is an extreme remedy and requesting a hearing to extend the discovery process is significantly less efficient than merely extending the deadline for final action by a few days.

The commission agrees with CSWR that a party must file a motion for a final deadline to be extended for late discovery responses. Under paragraph (g)(2), failure to respond to a discovery request does not automatically extend the deadline for final action. Rather, it "constitutes good cause" for extending the deadline. The commission intends this remedy to be used only when necessary to properly evaluate an application. Therefore, the commission does not believe that the additional language requested by CSWR is required to effectuate the intent of §24.76(g)(2).

§24.76(g)(3) - Request for hearing by intervenor

Under proposed §24.76(g)(3), a request by an intervenor for hearing must be filed within 25 days after the application is determined to be sufficient. A request for hearing must state with specificity the issues to be addressed.

TAWC/NAWC opposed §24.76(g)(3) as too restrictive but made no specific recommendation for the rule.

CSWR argued that if the commission accepts its proposal for §24.76(g) to reduce the 120-day deadline for final order to 60 days, then proposed §24.76(g)(3) should also be amended by reducing the intervention deadline from 25 days to 21 days.

Commission Response

As stated above, the commission has declined to adopt CSWR's proposal to reduce the deadline for final action from 120 days to 60 days under heading. Accordingly, CSWR's comments regarding §24.76(g)(3) are moot.

§24.76(g)(4) - Processing of application

Under proposed §24.76(g)(4), unless an intervenor requests a hearing, commission staff must submit a recommendation on the application or request a hearing not later than 45 days after the application is determined to be sufficient unless commission staff requests additional time.

CSWR argued that if the commission accepts its proposal to reduce the 120-day deadline for final order under §24.76(g) to 60 days, proposed §24.76(g)(3) should also be amended by reducing the deadline for commission staff to file its final recommendation from 45 days to 30 days.

Commission Response

The commission has declined to accept CSWR's proposal to reduce the deadline for final action from 120 days to 60 days under heading §24.76(g). Accordingly, CSWR's comments regarding the deadline for commission staff to issue its final recommendation are moot.

§24.76(g)(5) - Evidentiary hearing and schedule

Under proposed §24.76(g)(5), if a hearing on the application is requested, the application will be referred to SOAH for an evidentiary hearing. The presiding officer must set a procedural schedule that will enable the commission to issue a final order within 120 days after the application is referred to SOAH.

TAWC/NAWC and CSWR both argued that SICs should be eligible for informal disposition under §22.35(b)(1) (relating to Informal Disposition). CSWR requested that, if the requirements for informal disposition are met, the presiding officer be required to issue a notice of approval within 60 days of the date a materially sufficient application is filed.

CSWR further requested that the commission direct commission staff to work with utilities to "develop a standardized set of schedules to be used in these filings." CSWR argued that a standard set of schedules will streamline the submission and review of rate filing packages, "giving all utilities more clarity as to what should be included in the filing package and how it is presented," and facilitate commission staff review within a 60-day procedural schedule.

Commission Response

The commission declines to add language clarifying that SIC proceedings are eligible for informal disposition under §22.35(b)(1). The commission at this time does not have experience with SIC proceedings, the frequency with which they will be filed, or the range of issues that processing them will present. Accordingly, the commission is not prepared to fully delegate authority to resolve these decisions to an administrative law judge. However, the commission may revisit this decision at a future date and provide the necessary delegation by commission order to resolve SIC proceedings via notice of approval.

The commission also declines to direct staff to develop a standardized set of schedules at this time, but may elect to do so after additional experience with SIC proceedings.

§24.76(h) - Scope of proceeding

Under proposed §24.76(h), whether a cost is "prudent" and "reasonable and necessary" will not be addressed in a SIC proceeding unless the presiding officer finds good cause exists to do so. This provision effectively defers consideration of these standards to the utility's next comprehensive rate proceeding.

TAWC/NAWC stated there is no reason to address "prudent" costs in the SIC, therefore the rule language "unless the presiding officer finds good cause exists to address those issues" should be removed. CSWR recommended that the proposed rule explicitly preclude the consideration of prudence, similar to §25.248(g)(1) of the GCRR rule. CSWR argued that the provision allowing the presiding officer to consider prudence is ambiguous and is not included in other interim rate adjustment proceedings. Finally, CSWR argued that discovery on prudence would self-generate "good cause," and that prudence review is best deferred to the utility's next base rate case.

Commission Response

The commission finds that circumstances may exist that warrant consideration of whether issues of prudence, reasonableness, and necessity of costs may be appropriate in a particular SIC proceeding and declines to remove the language. A similar provision exists under §25.243(e)(5) of the DCRF rule.

§24.76(i) - Reconciliation

Under proposed §24.76(i), costs recovered through a SIC are subject to reconciliation in a utility's next comprehensive rate case. Any amounts recovered through the SIC found not to be prudent, reasonable, or necessary are subject to refund.

TAWC/NAWC's proposed adding the following clarifying language: "[n]either system improvement charge revenues nor plant costs paid for with such revenues shall be considered contributions in aid of construction."

Commission Response

The commission declines to add the clarifying language suggested by TAWC/NAWC because it is unnecessary. There is no instance in which SIC revenues might be considered contributions in aid to construction.

TAWC/NAWC identified a typographical error in §24.76(i) that should read, "...approved in the utility's next comprehensive rate case are effective."

Commission Response

The commission agrees with TAWC/NAWC and amends the rule accordingly.

§24.76(j) - Requirement to file a rate case

Under proposed §24.76(k), adopted as §24.76(j), utility must file a comprehensive base rate case within certain timelines following the date the commission files an order approving a SIC. Class A utilities must file within four years, Class B utilities must file within six years, and Class C and Class D utilities must file within eight years.

§24.76(j) - Good cause exception

TAWC/NAWC argued that §24.76(k), adopted as §24.76(j), should include a good cause exception for a utility failing to file a comprehensive rate case according to the rule schedule. TAWC/NAWC contended that the annual report may show it is not timely for the utility to file a rate case based on its earning levels, or that a utility may have gained or lost enough connections while the SIC was in effect to change the utility's rate class. Therefore, the utility may not need to file for comprehensive rate proceeding within the timeframes prescribed by the rule.

CSWR stated that §24.76(k), adopted as §24.76(j), appears to be in response to language in TWC §13.183(c) that directs the commission to "establish a schedule that requires all utilities that have implemented a system improvement charge approved by the utility commission to make periodic filings with the utility commission to modify or review base rates charged by the utility." CSWR stated that TWC §13.183(c) does not require that utilities file a comprehensive rate case but only that the utility make periodic filings to modify or review base rates; CSWR further stated that review of a utility's rates can be accomplished through the commission's evaluation of a utility's mandatory annual reports to determine if a utility is over- or under-earning, and the commission can require a utility to file a comprehensive base rate case at any time, making this provision unnecessary. CSWR alternatively recommended that the commission should allow a good cause exception to §24.76(k), adopted as §24.76(j), the utility is earning less than 50 basis points above its approved rate of return, similar to §25.247 (relating to Rate Review Schedule).

Commission Response

The commission declines to include an explicit allowance for a good cause exception to §25.76(k), adopted as §25.75(j), because the utility can request a good cause exception on its own motion. Furthermore, earnings are not the only consideration in the requirement to file a rate case. The commission is also obligated to timely ensure that the costs included in a SIC meet "prudence" and "reasonable and necessary" standards. Regulated electric utilities in Texas are subject to schedules requiring periodic applications for comprehensive base rate cases. However, water and sewer utilities do not have a mandatory date by which they file a comprehensive base rate case and, absent specific commission action, are not required to file for a rate case. A comprehensive base rate case allows the commission to conduct a thorough and detailed review of a utility's current financial position and level of regulated earnings.

Finally, for utilities that have changed class because of a gain or loss in connections, the rule specifically states that the filing deadline for a comprehensive base rate case is based on the utility's class at the time of the SIC application filing.

§24.76(j) - Cost trigger

OPUC proposed that the commission use an invested capital cost trigger to require a comprehensive base rate case filing on a shorter timeframe when a water and sewer utility's invested capital costs exceed a certain amount, similar to the requirements of a GCRR application under §25.248. OPUC recommended that the invested capital cost trigger not be a flat or a specific amount but instead should be determined on a case-by-case basis. Such a determination might depend on the size of utility or be based on a SIC amount relative to a water and sewer utility's annual revenue. OPUC provided an example of a utility with SIC revenues that are greater than 30 percent of its total annual revenues and specified it would be required to file a comprehensive rate case within 18 months of the date the SIC takes effect.

TAWC/NAWC opposed OPUC's recommendation for an invested capital cost trigger to be included in §24.76(k), adopted as §24.76(j), as, in its view, such a change would not reduce the goal of the SIC rule to reduce the frequency of comprehensive rate case filings.

Commission Response

The commission declines to add an invested capital cost trigger, because the schedule for requiring the utility to file a comprehensive base rate case fulfills the same purpose as an invested capital cost trigger without overburdening utilities with frequent, required rate cases.

§24.76(j) - Time frames

OPUC agreed with the intent of proposed §24.76(k), adopted as §24.76(j), requiring a water and sewer utility that is granted a SIC to file a comprehensive base rate case within a specified timeframe based on utility class and further recommended that the timeframes in the proposed rule should be reduced, not increased. OPUC stated that the comprehensive base rate case filing requirements allowed in the rule are too long, especially for the large Class A and Class B water and sewer utilities that should have the expertise and resources to file a comprehensive base rate case. The inclusion of carrying costs in a SIC, which are not subject to a prudence review, could result in a water and sewer utility including carrying costs in a SIC for a minimum of four years, after which the SIC costs could be deemed imprudent in a comprehensive base rate case. OPUC stated that, therefore, the proposed required timelines for filing a comprehensive base rate case should be shortened to lessen the impact of potential over-recoveries and to mitigate against the recovery of imprudent costs in a SIC. If the commission declines to implement an invested capital cost trigger in §24.76(k), adopted as §24.76(j), OPUC recommended adjusting the schedule so that Class A utilities file in two years instead of four, Class B utilities file in four years instead of six, Class C utilities file in six years instead of eight, and Class D utilities file in eight years. OPUC stated this would lessen the impact of potential over recoveries and hedge against the recovery of imprudent costs in a SIC. In its reply to TAWC/NAWC and CSWR, OPUC opposed increasing the time to file deadlines and recommended that the time requirements of the rule remain as initially proposed if its own proposals, discussed above, were rejected.

TAWC/NAWC and CSWR opposed OPUC's recommendation to reduce the rate case filing deadlines in §24.76(j) and replied that the goal of a SIC is to decrease the number of comprehensive base rate cases. TAWC/NAWC and CSWR contended that OPUC's recommendation would in fact increase the number of such rate cases. CSWR explained TWC §13.183(c) does not require a utility to file a comprehensive rate case, and the commission can already order a utility to file a rate case via an audit of a utility's annual report to determine if a utility is over- or under-earning. thus making §24.76(k), adopted as §24.76(j), unnecessary. CSWR further argued that OPUC's suggestion would discourage the use of the SIC mechanism. Therefore, CSWR recommended removing §24.76(k), adopted as §24.76(j), entirely, or in the alternative, urged the commission to decline OPUC's recommendations to reduce the timeframes to file a comprehensive base rate case. Similarly, TAWC/NAWC recommend that the rate case deadlines described in §24.76(k), adopted as §24.76(j), be extended.

Commission Response

The commission declines to amend or eliminate the schedule as recommended by commenters. The schedule as proposed strikes an appropriate balance between a timely, thorough review of a utility's costs and minimizing litigation expenses.

16 TAC §24.75

Statutory Authority

This repeal is adopted under Texas Water Code §13.041(b), which provides the commission with the authority to make and enforce rules reasonably required in the exercise of its powers and jurisdiction, and specifically, § 13.183(c), which allows the commission to adopt rules related to specific alternative ratemaking methodologies for water and sewer rates.

Cross reference to statutes: Texas Water Code §§ 13.041(b) and 13.184(c).

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 30, 2021.

TRD-202104766

Andrea Gonzalez

Rules Coordinator

Public Utility Commission of Texas

Effective date: December 20, 2021

Proposal publication date: June 4, 2021

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


16 TAC §24.75

Statutory Authority

These new rules are adopted under Texas Water Code §13.041(b), which provides the commission with the authority to make and enforce rules reasonably required in the exercise of its powers and jurisdiction, and specifically, §13.183(c), which allows the commission to adopt rules related to specific alternative ratemaking methodologies for water and sewer rates.

Cross reference to statutes: Texas Water Code §§13.041(b) and 13.184(c).

§24.75.Alternative Ratemaking Methodologies.

(a) Purpose and application. This section establishes alternative ratemaking methodologies for utilities that provide water or sewer service. The commission may prescribe modified rate filing packages for these alternative ratemaking methodologies.

(b) Multi-step rates. Multi-step rates allow a utility to implement one or more rates over time without filing multiple rate applications. Multi-step rates must be established in accordance with this subsection.

(1) Multi-step rates must be established in a comprehensive rate proceeding under Texas Water Code (TWC) §§13.187, 13.1871, 13.18715, or 13.1872.

(2) The commission may establish multi-step rates on its own motion or at the request of a utility or any other interested party.

(3) Rates established in a comprehensive rate case under TWC §§13.187, 13.1871, 13.18715, or 13.1872 will replace any multi-step rates already in effect or previously approved by the commission to go into effect for that utility.

(4) Multi-step rates may be established when a utility transitions from use of flat rates for unmetered service to use of volumetric rates for metered service.

(A) Multi-step rates for a utility's transition to metered service must not be effective before the date that meters are installed and in operation for all of the utility's connections.

(B) If the utility is seeking multi-step rates to transition to the use of volumetric rates for metered service, the utility must state in its notice of intent to change rates that it is seeking permission to use multi-step rates to transition to metered service with volumetric usage rates.

(C) The utility must provide notice to its customers at least 30 days before the utility begins charging its volumetric usage rate for metered service and at least 30 days before implementation of each step of its commission-approved multi-step rate.

(5) Multi-step rates may be established when a utility transitions from multiple rate schedules for different systems or service areas to consolidated rate schedules for regional or system-wide rates.

(A) Different rates and a different timeline may be established for each step in the multi-step rates of each system or service area that is transitioning to a consolidated rate schedule provided that the final step for each system or service area is the same consolidated rate.

(B) If the utility is seeking multi-step rates to transition to consolidated rate schedules, the utility must state in its notice of intent to change rates that it is seeking permission to use multi-step rates to transition from multiple rate schedules for different systems or service areas to consolidated rate schedules for regional or system-wide rates.

(C) The utility must provide notice to its customers at least 30 days before implementation of each step of its commission-approved multi-step rate.

(6) Multi-step rates may be established to moderate the effects of a rate increase on customers or if other good cause exists.

(A) Different rates and a different timeline may be established for each step in the multi-step rates for each of a utility's systems or service areas provided that the final step for each system or service area is the same final rate.

(B) If the utility is seeking multi-step rates under this paragraph, the utility must state in its notice of intent to change rates that it is seeking permission to use multi-step rates.

(C) The utility must provide notice to its customers at least 30 days before implementation of each step of its commission-approved multi-step rate.

(7) The notice requirements in paragraphs (4) - (6) of this subsection do not replace the standard statement of intent notice requirements under TWC §§13.187, 13.1871, 13.18715. or 13.1872.

(8) The commission may place conditions on the implementation of a multi-step rate or on any step of a multi-step rate. For the purpose of ensuring just and reasonable rates, the commission may terminate a multi-step rate in a rate proceeding before completion of all steps of the multi-step rate.

(c) Cash needs method. The commission may approve use of the cash needs method to establish a utility's revenue requirement in a comprehensive rate proceeding for a Class C or Class D utility under TWC §13.18715 or §13.1872 if use of the method is necessary for the utility to provide continuous and adequate service or other good cause exists to support the use of the cash needs method. Under the cash needs method, the allowable components of cost of service are operating expenses, debt service costs, and an additional margin consisting of either an operating margin or an incremental revenue amount.

(1) Operating expenses. Only those operating expenses that are reasonable and necessary to provide service may be recovered, and these amounts must be based on the utility's test year expenses, adjusted for known and measurable changes.

(2) Debt-service costs. Debt service costs include principal and interest payments on the utility's debt.

(A) The debt must have reasonable terms and must finance facilities that will be used and useful in the provision of utility service.

(B) If required by the commission, Texas Water Development Board, other state or federal agency, or financial institution, debt-service costs may include amounts placed in a debt-service reserve account or an escrow account.

(C) Debt service costs may include owner-financed assets. Debt-service costs related to these assets must include debt repayments using a reasonable amortization schedule and must use the prime interest rate in effect at the time the application is filed.

(3) Additional margin. An additional margin consists of either an operating margin or an incremental revenue amount. A utility requesting an additional margin must provide an explanation for the magnitude of the additional margin it requests.

(A) If a utility requesting an additional margin in the form of an operating margin has filed its most recent required annual report and has a net plant (original cost of plant in service less accumulated depreciation) of less than 25 percent of the original cost of plant, an operating margin of up to five percent of operating expenses approved by the commission will be presumed reasonable and may be included in the utility's revenue requirement.

(B) An additional margin consisting of an incremental revenue amount is calculated by adding an incremental amount to the debt service costs described in paragraph (c)(2)(A) of this section to achieve a reasonable total debt service coverage level above 1.0.

(4) Restrictions. Rates established using the cash needs method under this subsection may not be subsequently set using cost of service calculated under §24.41 of this title (related to Cost of Service) for any comprehensive rate change application filed within five years after the date of the commission's order establishing rates using the cash needs method. If, after this five-year period, the utility has a comprehensive rate change proceeding based on a cost of service calculated under §24.41 of this title, the utility's rate base must exclude an amount equal to the principal paid on the debt service during the time that rates based on the cash needs method were in effect.

(5) Subsequent acquisition. If a utility with rates established using the cash needs method is acquired by another utility while such rates are in effect, the acquiring utility is not subject to the restriction in paragraph (4) of this subsection on calculating cost of service. If the acquiring utility files a comprehensive rate change application based on a cost of service calculated under §24.41 of this title, the acquiring utility must exclude from rate base an amount equal to the principal paid on the debt service that was related to the acquired utility during the time that rates based on the cash needs method were in effect.

(d) New customer classes. A utility may request the addition of a new customer class or classes as provided by this subsection.

(1) Application. An application for new customer classes under this section must include:

(A) a cost-of-service and rate design study for each new proposed customer class;

(B) a definition for each proposed new customer class;

(C) demonstration that the characteristics of each proposed new customer class are sufficiently different from the characteristics of all existing and other proposed new customer classes for different rate treatment;

(D) a request for service from a customer in each proposed new customer class; and

(E) if the utility wants to extend the 18-month deadline to file a comprehensive rate case under paragraph (3) of this subsection, documentation that the revenues to be recovered from each new customer class will be less than ten percent of the utility's total annual revenue.

(2) Rates for new customer classes.

(A) The rates for each new customer class must be based on cost-of-service and rate design studies.

(B) On the effective date of the rates for each new customer class, common costs assigned to and recovered from the new customer classes must be removed from the rates of existing customer classes.

(3) Rate case requirement.

(A) A utility that has received commission approval for the creation of a new customer class or classes under this subsection must file a comprehensive rate case by filing a statement of intent under TWC §§13.187, 13.1871, 13.18715, or 13.1872 not later than 18 months from the date service begins to the new customer class or classes unless the utility has submitted documentation under subparagraph (1)(E) of this subsection demonstrating that each new customer class represents less than ten percent of the utility's total annual revenue required.

(B) If the utility demonstrates to the commission that each new customer class represents less than ten percent of the utility's total annual revenue by submitting documentation under subparagraph (1)(E) of this subsection, a comprehensive rate case is not required until the earlier of six months following the date on which the revenues of any of the new the customer classes equals or exceeds ten percent of the utility's total annual revenue or five years following the date service to the new customer class or classes begins. The utility must, as an attachment to its annual report filed under §24.129 (relating to Water and Sewer Utilities Annual Reports), annually update its demonstration to show that the revenues of each new customer class remain less than ten percent of the utility's total annual revenue. A utility must continue to update its demonstration annually until the commission adopts a final order in a comprehensive rate case for that utility or the utility is no longer eligible to delay filing a comprehensive rate case under this paragraph.

(C) If a utility fails to provide an annual update that shows the annual revenue of each new customer class remains less than ten percent of the utility's total annual revenue, the utility must file a comprehensive rate case within the earlier of six months from the date its annual report was due under §24.129(a) or five years from the date service to the new customer class or classes began.

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 30, 2021.

TRD-202104767

Andrea Gonzalez

Rules Coordinator

Public Utility Commission of Texas

Effective date: December 20, 2021

Proposal publication date: June 4, 2021

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


16 TAC §24.76

Statutory Authority

These new rules are adopted under Texas Water Code §13.041(b), which provides the commission with the authority to make and enforce rules reasonably required in the exercise of its powers and jurisdiction, and specifically, §13.183(c), which allows the commission to adopt rules related to specific alternative ratemaking methodologies for water and sewer rates.

Cross reference to statutes: Texas Water Code §§13.041(b) and 13.184(c).

§24.76.System Improvement Charge.

(a) Purpose. This section establishes the requirements for a system improvement charge to ensure timely recovery of infrastructure investment.

(b) Definitions. In this section, the following words and terms have the following meanings unless the context indicates otherwise.

(1) Eligible plant -- Plant properly recorded in the National Association of Regulatory Utility Commissioners System of Accounts, accounts 304 through 339 for water utility service or accounts 354 through 389 for sewer utility service.

(2) System improvement charge -- A charge for recovery of the portion of the cost of a utility's eligible plant that is not already included in the utility's rates.

(c) System improvement charge.

(1) A utility must have only one system improvement charge in effect for water and one system improvement charge in effect for sewer for each of its rate schedules at any time.

(2) A utility may apply to establish or amend one or more system improvement charges in accordance with the requirements of this section. A utility must not adjust its rates under this section more than once each calendar year. A utility that is applying to establish or amend multiple system improvement charges in a calendar year must do so in a single application.

(3) A utility may not apply to establish or amend a system improvement charge while it has a comprehensive rate proceeding under TWC §§13.187, 13.1871, 13.18715, or 13.1872 pending before the commission.

(4) If a utility with a pending application to establish or amend a system improvement charge files an application to change rates under TWC §§13.187, 13.1871, 13.18715, or 13.1872, or the commission initiates a rate change review under TWC §13.186, the utility will be deemed to have withdrawn its application to establish or amend a system improvement charge and the presiding officer must dismiss the application.

(5) The filing of applications as allowed by this section is limited to a specific quarter of the calendar year, and is based on the last two digits of a utility's certificate of convenience and necessity (CCN) number as outlined below, unless good cause is shown for filing in a different quarter. For a utility holding multiple CCNs, the utility may file an application in any quarter for which any of its CCN numbers is eligible.

(A) Quarter 1 (January-March): CCNs ending in 00 through 27;

(B) Quarter 2 (April-June): CCNs ending in 28 through 54;

(C) Quarter 3 (July-September): CCNs ending in 55 through 81; and

(D) Quarter 4 (October-December): CCNs ending in 82 through 99.

(d) Application for a system improvement charge. An application to establish or amend a system improvement charge must include the following:

(1) a description of the eligible plant for which cost recovery is sought through the system improvement charge, including the project or projects included in the request and an explanation of how each project has improved or will improve service;

(2) a calculation of the system improvement charge in accordance with subsection (f) of this section and all supporting calculations and assumptions for each component of the system improvement charge;

(3) information that sufficiently supports the eligible cost, such as invoices, receipts, and direct testimony, and that sufficiently addresses the exclusion of costs for plant provided by explicit customer agreements or funded by customer contributions in aid of construction;

(4) a copy of the utility's most recent annual report filed with the commission, which must be the annual report most recently due for filing; and

(5) an affidavit confirming that the application meets the requirements of this section.

(e) Calculation of the system improvement charge. The revenue requirement for the system improvement charge must be calculated using the following formula: SIC RR = (Reconcilable Cost * ROR) + Federal Income Taxes + Depreciation + ad valorem taxes + other revenue related taxes.

(1) SIC = the system improvement charge.

(2) SIC RR = system improvement charge revenue requirement.

(3) Reconcilable Cost = the original costs of eligible plant installed after the later of the ending date of the 2019 reporting period reflected in the utility's annual report filed under §24.19 (relating to Water and Sewer Utilities Annual Report) or the end of the test year used in the utility's most recent base-rate proceeding, less:

(A) accumulated depreciation; and

(B) any costs for plant provided by explicit customer agreements or funded by customer contributions in aid of construction.

(4) Accumulated depreciation = depreciation accumulated for eligible plant after the date the eligible plant was placed in service.

(5) ROR = after-tax overall rate of return as defined in paragraph (10) of this subsection.

(6) Federal Income Taxes = current annual federal income tax, as related to eligible costs.

(7) Depreciation = current annual depreciation expense for the eligible plant.

(8) Ad Valorem Taxes = current annual amount of taxes based on the assessed value of the eligible cost.

(9) Other Revenue Related Taxes = current annual amount of any additional taxes resulting from the utility's increased revenues related to the SIC.

(10) The after-tax overall rate of return is one of the following:

(A) if the final order approving the utility's overall rate of return (i.e., the company's weighted-average cost of capital) was filed less than three years before the date that the utility files an application for a SIC, the after-tax rate overall of return is the one approved by the commission in the utility's last base-rate case; or

(B) if the final order approving the utility's overall rate of return (i.e., the company's weighted-average cost of capital) was filed three years or more before the date that the utility files an application for a SIC, the after-tax overall rate of return is the average of the commission's approved rates of return for water and sewer utilities in settled and fully litigated cases over the three years immediately preceding the filing of the SIC.

(11) The SIC must be calculated based on annualized meter equivalents, derived using the most recent month's total customer meter equivalents multiplied by 12. The base SIC must be calculated as the SIC RR divided by annual meter equivalents. The SIC for each meter size must be calculated as the base SIC multiplied by the multiplier for that meter size.

Figure: 16 TAC §24.76(e)(11) (.pdf)

(f) Notice. By the first business day after it files its application, the utility must send notice of its SIC application to all affected ratepayers by first class mail, e-mail (if the customer has agreed to receive communications electronically), bill insert, or hand delivery. The utility must include in the notice the docket number for the utility's SIC proceeding, the intervention deadline, and a brief explanation of how an affected ratepayer can intervene in the SIC proceeding and how intervention differs from protesting a rate increase. The intervention deadline is 25 days from the date service of notice is complete.

(g) Commission processing of application. Upon the filing of an application to establish a SIC, the presiding officer must set a procedural schedule that will enable the commission to issue a final order within 120 days after the application is determined to be sufficient if no hearing is requested.

(1) For good cause or by agreement of the parties, the presiding officer may set a schedule that will not enable issuance of a final order within 120 days after the application is determined to be sufficient. The deadlines established by the presiding officer will be extended as provided in this subsection.

(2) After an application is determined to be sufficient, the applicant must respond to requests for information within 10 days. An applicant's failure to timely respond to requests for information constitutes good cause for extending the deadline for final action one day for each day that a response exceeds 10 days.

(3) A request by an intervenor for hearing must be filed within 25 days after the application is determined to be sufficient. A request for hearing must state with specificity the issues to be addressed.

(4) Unless an intervenor requests a hearing, commission staff must submit a recommendation on the application or request a hearing not later than 45 days after the application is determined to be sufficient unless commission staff requests additional time, not to exceed another 15 days unless good cause exists for a later date. If commission staff is granted additional time, the deadline for final action is extended day for day for each day of additional time.

(5) If a hearing on the application is requested, the application will be referred to the State Office of Administrative Hearings (SOAH) for an evidentiary hearing. The presiding officer must set a procedural schedule that will enable the commission to issue a final order within 120 days after the application is referred to SOAH. For good cause, the presiding officer may set a procedural schedule that will not enable the commission to issue a final order within 120 days after the application is determined to be sufficient.

(h) Scope of proceeding. The issue of whether eligible costs included in an application for a SIC or an amendment to a SIC are prudent, reasonable, or necessary, will not be addressed in a proceeding under this section unless the presiding officer finds that good cause exists to address these issues.

(i) System improvement charge reconciliation. Costs recovered through a SIC are subject to reconciliation in the utility's next comprehensive rate case. Any amounts recovered through the SIC that are found to have been unreasonable, unnecessary, or imprudent, plus the corresponding return and taxes, must be refunded with carrying costs. The utility must pay to its customers carrying costs on these amounts calculated using the same rate of return that was applied to the recovered costs in establishing the SIC until the date the rates approved in the utility's next comprehensive rate case are effective. Thereafter, carrying costs must be calculated using the utility's rate of return authorized in the comprehensive rate case.

(j) Rate case expenses. Recovery of rate case expenses may be requested and must be reviewed in the utility's next comprehensive base rate case and in accordance with §24.44 of this chapter (relating to Rate-case Expenses Pursuant to Texas Water Code §13.187 and §13.1871).

(k) Requirement to file a rate case. A utility must file a comprehensive rate case under TWC §§13.187, 13.1871, 13.18715, or 13.1872 within the following times from the date the commission files an order approving the SIC.

(1) Four years for a utility that was a Class A utility at the time of the order.

(2) Six years for a utility that was a Class B utility at the time of the order.

(3) Eight years for a utility that was a Class C or Class D utility at the time of the order.

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 30, 2021.

TRD-202104768

Andrea Gonzalez

Rules Coordinator

Public Utility Commission of Texas

Effective date: December 20, 2021

Proposal publication date: June 4, 2021

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


CHAPTER 25. SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS

SUBCHAPTER C. INFRASTRUCTURE AND RELIABILITY

16 TAC §25.52

The Public Utility Commission of Texas (commission) adopts amendments to existing 16 Texas Administrative Code (TAC) §25.52, relating to Reliability and Continuity of Service, with changes to the proposed text as published in the October 1, 2021, issue of the Texas Register (46 TexReg 6462). The rule will be republished. These amendments implement changes to the Public Utility Regulatory Act (PURA) enacted by the 87th Texas Legislature. Specifically, these amendments implement revisions made by Senate Bill (SB) 1876 to PURA §38.072(a) and (b) by adding end stage renal disease facilities to the list of health facilities prioritized during system restoration following an extended power outage in section §25.52(f).

These amendments also implement new PURA §38.074, added by House Bill (HB) 3648 and SB 3, as part of a joint effort with the Railroad Commission of Texas (RRC) to increase the coordination between the electric and gas industries during energy emergencies. As part of this joint effort, the RRC has proposed new §3.65, relating to Critical Designation of Natural Gas Infrastructure, which will operate in conjunction with the amendments adopted in this project. Together, these rules will require a critical natural gas facility, or a "critical customer" as described under §3.65, to provide critical customer information to the utility from which it receives electric delivery service and require the utility to incorporate this information into its load-shed and power restoration planning.

The commission received comments on the proposed amendments from AEP Texas Inc., Oncor Electric Delivery Company LLC, CenterPoint Energy Houston Electric, LLC, and Texas-New Mexico Power Company (collectively, the "Joint TDUs"), Guadalupe Valley Electric Cooperative, Inc. (GVEC), the Lower Colorado River Authority and LCRA Transmission Services Corporation (collectively LCRA), Occidental Permian LTD (OPL), Office of the Public Utility Counsel (OPUC), Southwestern Electric Power Company (SWEPCO), the Steering Committee of Cities Served by Oncor and the Texas Coalition for Affordable Power (collectively Cities/TCAP), Texas Competitive Power Advocates (TCPA), Texas Electric Cooperatives, Inc. (TEC), Texas Oil & Gas Association (TXOGA), Texas Pipeline Association (TPA), Southwestern Public Service Company (SPS), Texas Public Power Association (TPPA), and Vistra Corp. (Vistra). No party requested a hearing.

General Comments

TPPA and OPUC commented that the interconnection between proposed commission rule §25.52 and the RRC proposed rule §3.65 may cause uncertainty and ambiguity for stakeholders. Specifically, the differing timelines for adoption as currently proposed for the two rules may result in inconsistencies in application.

Commission response

The Commission adjusted its adoption timeline to allow these rule amendments to be adopted on the same day that the RRC adopts §3.65.

TPPA and GVEC expressed concerns regarding the conflicting approach between the process of designating critical status by the commission and the RRC in each agency's proposed rule language. TCPA recommended that the commission should immediately pursue enhanced coordination efforts with the RRC to encourage an approach towards designating truly critical infrastructure, prevent entities from opting-out of "critical" designation until mapping and prioritization activities identify them as such, and also create a more meaningful threshold for the weatherization expectations of a critical natural gas facility to be "prepared to operate during a weather emergency." TPA argued that the exception portion of proposed RRC rule §3.65 is not an "opt-out" provision, rather it is a "prohibition on a facility's ability to be considered as critical, and thus barring it from being able to be prioritized above others in a load shed event."

Commission response

The commission has collaborated with the RRC throughout this rulemaking process, as required by PURA §38.074. However, comments addressing the RRC's rulemaking project or entities over which the commission has no direct jurisdiction are beyond the scope of this rulemaking project.

ERCOT's voluntary designation form

TCPA and LCRA requested clarification regarding the continued use of the Electric Reliability Council of Texas, Inc. (ERCOT) form, Application for Critical Load Serving Electric Generation and Cogeneration (Critical LSE Application), until the new RRC designation process is implemented. OPUC expressed reservations regarding the RRC's proposed Critical Customer Information (CCI) table and its similarity to the existing application used by ERCOT.

Commission response

The commission anticipates that the new rules adopted by the commission and the RRC will become effective on the same date, rendering most clarifications regarding the ERCOT Critical LSE Application and the RRC CCI table moot. However, the commission has clarified that under §25.53(h)(2)(B), a utility may continue to treat a natural gas facility that self-designated as critical using the Critical LSE Application as a critical natural gas facility, as circumstances require.

Intrastate vs. interstate natural gas pipelines transparency

TCPA commented on the significant differences between federal regulation of interstate pipelines and state regulation of intrastate gas pipelines in Texas, including transparency requirements of gas system conditions. TCPA recommended that the commission work with the RRC to bring about more transparency regarding intrastate natural gas pipelines as part of the Texas Electricity Supply Chain Security and Mapping Committee's (Mapping Committee) mapping process, so that information available for intrastate pipelines is similar to that available for interstate pipelines. Specifically, TCPA recommended that all pipelines should publicly post on a daily basis, the capacities of, and volumes flowing through receipt and delivery points (consistent with interstate practices) and mainline segments on electronic bulletin boards in order to make available necessary information for tracking flows of natural gas throughout Texas.

Commission response

The commission has collaborated with the RRC throughout this rulemaking process, as required by PURA §38.074. However, comments addressing the RRC's rulemaking project or entities over which the commission has no direct jurisdiction are beyond the scope of this rulemaking project. The specifics of the work being done by the Mapping Committee are also not properly addressed in this rulemaking project.

Enhanced coordination with RRC and the mapping initiative

TCPA recommended that the commission and RRC commence the mapping process as soon as possible with a goal of releasing the map and best practices far in advance of the September 1, 2022, deadline as possible. OPUC stated that formalizing rules around critical facilities is premature given the unknown result of the Mapping Committee's future effort to map out the state's critical infrastructure as well as the RRC's future weatherization rules that will serve as the basis of opting out as a critical natural gas facility under §3.65(d).

Commission response

The commission, in conjunction with the RRC, has already begun the mapping the Texas electricity supply chain, as recommended by TCPA, and will release the map as soon as practicable.

The commission disagrees with OPUC that formalizing rules concerning critical natural gas facilities is premature. HB 3648 requires the commission to adopt rules required by PURA §38.074 by December 1, 2021.

§25.52(a) - Application

Proposed §25.52(a) lists the entities to which §25.52 applies. Vistra recommended that this list also include "operators of critical natural gas facilities," citing the proposed requirement in subparagraph (h)(1)(A) that operators of critical natural gas facilities provide critical customer information to certain entities.

Commission response

The commission declines to add operators of critical natural gas facilities to the entities listed in subsection (a). The commission does not have direct jurisdiction over these entities. Instead, the commission modifies the language of subparagraph (h)(1)(A) to clarify that operators of critical natural gas facilities are required to provide this critical customer information in accordance with §3.65 of this title, as required by the RRC.

TPPA noted that proposed §25.52(a) states that the term "utility" when used in §25.52 means an electric utility and a transmission and distribution utility and the rule further clarifies that in subsection (h), the term also includes electric cooperative and MOUs. TPPA asserted that the same word carrying different meanings within the same rule makes the rule more difficult to understand. TPPA recommended that the commission create a separate rule for addressing MOUs and electric cooperatives.

Commission response

The commission declines to address MOUs and cooperatives in a separate rule, because this rule would have to be published separately in the Texas Register and this could not be accomplished in a timely fashion. The commission agrees with TPPA that the use of same term in different ways in a single rule could be confusing, however, the use of a single term for all applicable entities significantly increases the readability of subsection (h). To mitigate potential confusion and preserve this readability, the commission moves the clarification that "utility," when used in subsection (h), includes MOUs and electric cooperatives to subsection (h).

§25.52(a) - Utilities in non-ERCOT areas of Texas

SWEPCO and SPS both argued that PURA §38.074 should be limited to entities providing service in the ERCOT power region. Specifically, SWEPCO and SPP construed the use of the word "certain" in PURA §38.074(a) to limit the applicability of the statute, and therefore the rule, to facilities in the ERCOT power region. "The commission shall collaborate with the Railroad 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 during energy emergencies..." SWEPCO and SPS also indicated that contextually, HB 3648 was passed to address ERCOT-specific load shed during Winter Storm Uri and the statute and rule should therefore be limited in applicability.

SPS further argued that §38.074(b)(1)-(3) explicitly designates facilities in the ERCOT power region as the subject of the rule. SWEPCO similarly argued that the RRC's proposed rule §3.65(e) appropriately limits the provision of critical customer information to the entities described in PURA §38.074(b)(1), however the commission's proposed §25.52(h)(1)(A) does not. SWEPCO also recommended edits to the term "utility" in §25.52(h)(1) and §25.52(h)(2) limiting the term to facilities in the ERCOT power region. SWEPCO offered draft language for clauses §25.52(h)(1)(A)(i) and §25.52(h)(1)(A)(ii), in accordance with its desired definition of the term "utility":

(i) The transmission and distribution utility, electric cooperative, or MOU from which the critical natural gas facility receives electric delivery service in the ERCOT region: and

(ii) For critical natural gas facilities located in the ERCOT region, tThe independent organization certified under PURA §39.151.

Commission response

The commission declines to adopt the recommendation of SWEPCO and SPS to limit the applicability of the proposed rule to facilities in the ERCOT power region. PURA §38.074(a) states in relevant part: ""¦certain natural gas facilities and entities associated with providing natural gas in this state as critical during energy emergencies." The plain meaning of PURA §38.074(a) is a directive for the RRC and the commission to establish a designation process of "[critical] facilities and entities" within the State of Texas. The adjective "certain" applies to the nouns "natural gas facilities and entities" which in turn are further limited in scope by the descriptor "in this state", meaning the State of Texas and reflective of the intent of the designation process to be statewide and not limited to the ERCOT power region. The term "as critical" is only intended as a directive for both agencies to determine which facilities and entities providing natural gas within the State should be prioritized pursuant to the statute. PURA §38.074(b)(1) should be read as a specific directive for the ERCOT power region whereas PURA §38.074(a) is a section of general applicability. SPS' interpretation of PURA §38.074(b)(1)-(3) is erroneous because, if the subsections were intended to limit the scope of the statute, (b)(1)-(3) would be subsections of (a) and not its own section, and the phrase "in this State" would not be have been included in (a) by the Legislature and instead have stated "in the ERCOT power region" or nothing at all.

The commission also notes that the mapping of the Texas electric supply chain as directed by SB 3, codified as PURA §38.201, as further evidence the intention of the designation of critical nature gas to be a statewide initiative. Specifically, PURA §38.201(b)(1) directs the Mapping Committee to "map this state's electricity supply chain" and §38.201(b)(2) which requires the Mapping Committee to "identify critical infrastructure sources in the [statewide] electricity supply chain".

For these reasons, the commission also declines to adopt SWEPCO's recommendation and proposed language limiting the scope of the term "utility" in §25.52(h)(1)(A)(i) and §25.52(h)(1)(A)(ii).

S25.52(c) - Definition of "energy emergency"

SWEPCO, Vistra and Joint TDUs requested that the commission adopt a definition of "energy emergency, because the term is used in this section several times. The Joint TDUs suggested the commission adopt the definition proposed by the RRC.

Commission response

Commission agrees to define the term energy emergency but does not agree to adopt the RRC's proposed definition, as recommended by the Joint TDUs. The commission defines energy emergency, when used in §25.52, as "[a]ny event that results in or has the potential to result in firm load shed required by the reliability coordinator of a power region in Texas."

§25.52(c)(2) - Definition of "critical natural gas"

Proposed §25.52(c)(2) defines the term "critical natural gas" as a facility designated as a critical gas supplier by the RRC under §3.65(b) unless the critical gas supplier has obtained an exception from its critical status under the RRC's proposed rule. Under proposed §3.65, a critical gas supplier that is not prepared to operate during a weather emergency can obtain an exception from its critical status.

Vistra recommended that rule define the term "critical natural gas facility" rather than "critical natural gas." Further, the definition should expressly include gas supply chain facilities in the electricity supply chain map and clarify that an energy emergency is declared by ERCOT.

Commission response

The commission agrees that defining "critical natural gas facility" in lieu of "critical natural gas" improves the clarity of the rule and amends the define term accordingly. However, the supply chain map is addressed in §3.65, promulgated by the RRC. Therefore, the commission declines to adopt Vistra's proposed language regarding the electric supply chain map for §25.52(c)(2). Moving forward, this order will refer to "critical natural gas" when discussing proposed language and will use "critical natural gas facility" when referring to the adopted rule.

Finally, the commission has relocated the statement "Critical natural gas is a critical load during an energy emergency" to (h)(2) for clarity.

Cities/TCAP argued that the definition of "critical natural gas" in the commission's rule should not include an exception for a critical gas supplier that is not prepared to operate during a weather emergency. TCPA and TEC requested the commission adopt rule language to require an attestation by an authorized officer of the facility operator to certify that the facility complies with best practices and is prepared to maintain service in an extreme weather event established under PURA §38.203(a)(4). TCPA and TEC also recommended removing all reference to the RRC's proposed rule §3.65 and instead rely solely on the definitions and requirements of critical natural gas facilities finalized by the commission. Specifically, TEC recommended that the commission adopt a more stringent definition for "critical natural gas" to include the criteria that the facility has provided all required information in accordance with RRC rules and has provided additional information as requested by the electric utility in accordance with subsection (h)(1)(C)(i).

Commission response

The commission declines to remove all references to §3.65 from the definition of critical natural gas facilities. Natural gas facilities are subject to the primary jurisdiction of the RRC, making the reference to its rule appropriate. Comments addressing other aspects of the RRC's rulemaking project or entities over which the commission has no direct jurisdiction are beyond the scope of this rulemaking project.

TPPA recommended that the commission include language in proposed §25.52 excluding natural gas facilities from being declared critical if the facility failed to timely provide critical customer information to its MOU, electric cooperative, or investor-owned utility.

Commission response

The commission agrees that timely receipt of critical customer information is essential for proper emergency planning. For this reason, the commission adds language to clause (h)(1)(C)(i) that gives a utility some discretion as to whether to treat a natural gas facility that submits untimely information as critical.

TEC recommended that the commission qualify the definition of "critical natural gas" to indicate that the designation does not guarantee uninterrupted supply of energy or that load will not be shed.

Commission response

The commission agrees with TEC that a clarification of the effect of a critical designation on the certainty of electricity supply for a natural gas facility would be helpful and adds the following language to the definition of critical natural gas facility: "Designation as a critical natural gas facility does not guarantee the uninterrupted supply of electricity."

§25.52(f) - Power restoration for certain medical facilities

Under §25.52(f), a utility must give the same priority to certain medical facilities that it gives to a hospital in the utility's emergency operations plan for restoring power after an extended power outage.

Joint TDUs requested a new paragraph under this subsection adding "Nothing in this subsection (f) shall be deemed as altering the terms and conditions of a utility's tariff."

Commission response

The commission declines to add language requested by the Joint TDUs. The Joint TDUs did not provide any reasoning supporting this addition, and the commission finds it to be superfluous.

§25.52(h) - Critical natural gas

Proposed §25.52(h) specifies that critical natural gas standards, as defined under RRC rule §3.65, are applicable to gas suppliers in Texas that are designated as critical customers.

TPA recommended clarifying that load shed programs apply only to facilities served by electric distribution facilities, not transmission facilities and recommended changing the language to add the word distribution in this subsection.

Commission response

The commission declines to make the proposed changes suggested by TPA. The term "electric delivery service" encompasses both transmission and distribution service providers. Additionally, certain utilities in Texas are integrated and may provide both transmission and distribution services.

25.52(h) - Cross reference to RRC rule §3.65

TEC and TCPA commented that the cross reference to TRRC's rule §3.65 should be removed. and proposed that the commission rely on the definition and requirements of critical natural gas facilities finalized in its own rules.

Commission response

The commission declines to remove all references to §3.65 from subsection (h). Natural gas facilities are subject to the primary jurisdiction of the RRC, making the reference to its rule appropriate.

§25.52(h)(1)(A) - Critical customer information

Proposed §25.52(h)(1)(A) requires critical natural gas facilities to provide critical customer information in a format described under RRC rule §3.65(a)(3) to their respective electric delivery service providers and, for critical natural gas facilities within the ERCOT region, to the independent organization certified under PURA §39.151.

TPPA recommended that the subsection also clarify that, for any corrections or updates provided to a utility, critical natural gas facilities would be required to concurrently provide those same corrections or updates to ERCOT.

TPA also requested the Commission to provide clarity and continuity as to what is meant by "usable format" in §25.52(h)(1)(A) regarding providing Critical Customer Information, as defined by §3.65(a)(3) of the RRC rule.

Commission response

The commission replaces the reference to "usable format" with a requirement that the critical customer information must be provided using Form CI-D and any attachments, to align with a change made by the RRC in §3.65.

The commission agrees that providing updated information to ERCOT is appropriate, but finds that such a process can be addressed in implementation of the rule.

Joint TDUs proposed expanding the scope of RRC rule §3.65(a)(3) to include additional details for each critical natural gas facility. Specifically, information regarding which facilities directly support electric generation should be included so the TDUs can incorporate those facilities into their respective load-shed and emergency restoration plans.

TEC proposed changes to this subsection to require a gas operator that provides critical customer information under §3.65(a)(3) to also provide a "prepared to operate" certification from an authorized officer of the utility and, if applicable, to ERCOT, within the time frames set forth under §3.65(c).

Commission response

The commission has collaborated with the RRC throughout this rulemaking process, as required by PURA §38.074. However, comments addressing the RRC's rulemaking project or entities over which the commission has no direct jurisdiction are beyond the scope of this rulemaking project.

TPA proposed an alternate mechanism for identifying critical facilities in non-customer choice regions of Texas, where meters do not have ESI IDs. TPA made no specific recommendations beyond a special ID determined by the commission to be assigned to meters without ESI IDs and expressed general support for such an alternative protocol.

Commission response

The commission has collaborated with the RRC throughout this rulemaking process, as required by PURA §38.074. The specific critical customer information that critical natural gas facilities need to provide will be delineated in Form CI-D, as adopted by the RRC. This form will provide an alternate mechanism of identifying critical facilities in non-customer choice regions of Texas.

§25.52(h)(1)(B) - Updating utility email information

Under proposed subparagraph (h)(1)(B), the commission will maintain on its website, a list of utility email addresses to be used for the provision of critical customer information. This subparagraph also requires that utility to ensure that its' email address is accurate by requiring the utility to immediately provide the the commission with an updated email address if the email address is inaccurate or changes.

TPPA and TEC commented that the proposed rule's requirement to immediately update the contact information is burdensome and outside normal commission practice for emergency contact maintenance. TPPA referred to §25.53(e) and recommended that timeline for compliance be set to either "as soon as practicable" or "within 30 days." TEC proposed that email addresses be updated "as soon as reasonably practicable."

LCRA recommended that in the event the utility's email address changes or is inaccurate, the utility should be allowed five business days from the date the email address changes, or the utility is informed that the email address on file is inaccurate.

Commission response

The commission agrees with commenters that requiring a utility to update its email address immediately is inconsistent with other similar requirements in the commission's rules. The commission modifies the language to require a utility provide an updated email address within five business days of the email address changing or the utility becoming aware that the posted address is inaccurate, as recommended by LCRA.

§25.52(h)(1)(C) - Evaluation of critical customer information

Proposed new §25.52(h)(1)(C)establishes the timeline for evaluation of critical natural gas facility customer information by TDUs and notification to the gas facility of its critical status.

TPPA opposed the requirement imposed by §25.52(h)(1)(C) to notify gas facilities of their critical status and argued that the proposed rule paragraph exceeds the scope of PURA §38.074. TPPA opined on the purpose served by the notification when RRC has already designated a gas facility as critical and requested clarity on which entity grants critical status and the circumstances that could result in removal of critical status. TPPA also requested that the commission set the deadline for compliance with this subsection to either "as soon as practicable" or "within 30 days" so that TDUs can more meaningfully respond to critical information submissions by gas operators.

SWEPCO requested that the commission require critical customer information be received by utilities by September 15 of each year so it can incorporate this information during the annual review of its load shed plan. SWEPCO also requested that utilities be granted 21 days to review the information provided.

Joint TDUs asserted that five business days is too short of a timeframe for the utilities to process, evaluate, and respond to the volume of information that will be simultaneously submitted by the gas operators. Joint TDUs recommended that a timeframe of 15 business days be adopted to allow the utilities to analyze the critical customer information analyze the critical customer information more thoroughly. Joint TDUs argued that this timeframe would also allow for an opportunity for clarification and communication with the operators if needed and would be more consistent with the 30-day timeframe set forth in Texas Water Code §13.1396(g), which also addresses critical infrastructure.

TEC proposed clarifying the types of notices a utility may provide to gas operators depending on the circumstances, such as notices for submitting incomplete information. TEC also requested clarifying that a gas operator must respond within five business days to a utility's requests for additional information and if a gas operator fails to respond, the utility should not be required to further evaluate, classify, or designate the facility. TEC further recommended adding a new subsection providing details on timelines for providing different notices to gas operators.

Specifically, TEC offered language changes under §25.52(h) and recommended that a utility should not be required to prioritize or plan for those gas facilities in their load shed, power delivery and power restoration plan that do not meet the Commission's definition of critical natural gas supplier under §25.52(c)(2).

Commission response

The commission agrees with commenters that five business days is insufficient time for utilities to evaluate critical customer information and increases the deadline to 10 business days. The commission declines to make the changes proposed by TEC to add a new subsection on timelines for utilities to provide various notices to gas operators.

The commission does not require utilities to receive critical customer information from critical natural gas facilities by September 15, as requested by SWEPCO. The deadline for a critical natural gas facility to provide critical customer information to its utility is governed by §3.65.

The commission modifies §25.52(h)(1)(C)(i) to allow a utility to set a deadline of no shorter than five business days for a natural gas facility to provide additional, requested critical customer information. If the utility does not receive the additional information in a timely fashion, the utility may use its discretion to determine if it is possible to treat the natural gas facility as critical for load sed and power restoration purposes. However, the commission expects a utility to include as many critical natural gas facilities as practicable in its power restoration and load shed plans.

§25.52(h)(1)(C)(ii) - Utility notice to gas operator with complete information

Proposed new §25.52(h)(1)(C)(ii) details the required contents of a notice from a utility to a gas operator that has provided complete critical customer information under to §25.52(h)(1)(C).

TPPA requested the commission provide additional clarification on what is required of utilities when notifying gas operators of "any additional classifications assigned to the facility" under §25.52(h)(1)(C)(ii).

Commission response

Under §25.52(h)(2)(B), a utility retains discretion to implement load shed and power restoration as circumstances require. If a utility assigns any additional classifications, such as tier of criticality, using this discretion, that classification must be reported to the critical natural gas facility.

Subsection §25.52(h)(1)(D) - Confidentiality of critical customer information

This subsection establishes the requirement that neither investor-owned facilities, MOUs, electric cooperatives nor the independent system operator must not release any critical customer information to any person unless authorized by the commission or the critical natural gas facility operator.

LCRA proposed the list of gas facilities that have filed RRC's Form CI-X, Critical Customer/Critical Gas Supplier Designation Exception Application be provided to electric generators, so the generators can determine if gas facilities in their fuel supply chain are not prepared to operate in winter weather conditions. LCRA further proposed that either the generators have access to the RRC's list of gas facilities or that the confidentiality provisions of §25.52(h)(1)(D) be amended to include generators' access to this information. LCRA and Vistra proposed sharing of critical customer information between a retail electric service provider and its transmission operator.

Commission response

Providing supply chain information to electric generators, as recommended by LCRA, is beyond the scope of this rulemaking. Therefore, the commission declines to amend the rule as proposed. The commission disagrees with both LCRA's and Vistra's proposals to allow exchange of critical gas customer information with REPs. Customers can provide the information voluntarily and at their own discretion to their REP.

LCRA proposed amending the language of §25.52(h)(1)(D) to include a utility's transmission operator as an exception to the prohibition of sharing critical customer information.

Commission response

The commission agrees with LCRA and amends the rule accordingly.

Vistra proposed amending language in §25.52(h)(1)(D) to include the word "delivery" between "electric" and "service."

Commission response

The commission agrees with Vistra and amends the rule accordingly.

TEC proposed changes to §25.52(h)(1)(D) to clarify that confidentiality applies when both sending and receiving customer information regarding a critical natural gas facility.

Commission response

The commission agrees with TEC and amends the rule accordingly.

TEC's proposed new subparagraph (h)(1)(E)

TEC recommended adding a new subparagraph that specifies the dates by which a utility must provide notice of the status of evaluation or designation to the critical natural gas facility operator. TEC proposed a 30-day deadline in 2022 and a 60-day deadline beginning in 2023.

Commission response

The commission agrees with TCPA and amends the rule to allow utilities to treat utilities that voluntarily self-designated as critical using the Critical LSE Application as critical natural gas facilities as circumstances require.

Vistra requested the commission clarify §25.52(h)(2)(A) as, in its view, multiple interpretations are possible of the sentence portion ""¦prioritize critical natural gas facilities for load-shed purposes"¦" in the rule. Specifically, Vistra requested the commission clarify whether the rule intended to prioritize "critical natural gas facilities as a class for continued power delivery during a load-shed event, relative to other classes of loads." Vistra opined that this is the intended meaning of the rule due to the term "among" used in §25.52(h)(2)(B)-(C) to specify "relative prioritization the broader critical load segment and within the more narrow critical natural gas facility segment". However, Vistra indicated that an opposing interpretation is possible, specifically that "critical natural gas facilities should be prioritized for having their load shed." Vistra proposed language to resolve this perceived ambiguity:

(A) A utility must prioritize include critical natural gas facilities as a category of facilities considered for prioritization of continued power delivery during for load-shed purposes during in an energy emergency.

Commission response

The commission agrees with Vistra that current rule language is ambiguous and modifies §25.52(h)(2)(A) to "A utility must prioritize critical natural gas facilities for continued power delivery during an energy emergency."

SPS proposed rule language in line with its general comments under heading §25.52(h) where it argued the applicable scope of the rule is limited to the ERCOT power region.

(h)(2)(A) A utility in the ERCOT power region must prioritize critical natural gas facilities for load-shed purposes during an energy emergency.

Commission response

The commission declines to adopt SPS's proposed rule language for the reasons stated in response to SPS's comments on the application of the rule, §25.52(a).

SWEPCO, Cities/TCAP, and Joint TDUs expressed concern over the ambiguity of certain provisions in §25.52(h)(2) regarding prioritization by the commission and RRC, utility discretion for prioritization, and industry guidance. SWEPCO, Cities/TCAP, and Joint TDUs recommended the commission clarify proposed new §25.52(h)(2) in order to prioritize specific facilities or entities within the umbrella term "critical natural gas facilities". SWEPCO proposed various criteria for the commission to consider for prioritization. Cities/TCAP recommended the commission or ERCOT publish guidance on the same. Joint TDUs recommended a specific three-tiered system based on criticality for §25.52(h)(2)(A) and making §25.52(h)(2)(C) more permissive, only obligating utilities "to consider" additional guidance or prioritization criteria, provided by a limited, identifiable group within the commission, ERCOT, and RRC.

SWEPCO argued that critical natural gas facilities should be categorized to enable utilities to incorporate them into load shed and restoration plans in the most "meaningful manner" possible.

Cities/TCAP expressed concern that identifying all gas supply chain facilities as critical without any attention to "role or ranking" may introduce risks and result in utilities unable to effectively manage prioritization of critical facilities during an emergency.

Joint TDUs asserted that neither the RRC's nor commission's proposed rules distinguish among natural gas facilities, nor do they provide a methodology by which critical natural gas facilities should be prioritized for load shedding, power delivery, and restoration purposes. According to Joint TDUs, the Legislature's mandate to the commission and the RRC in both SB 3 and HB 3648, as reflected in PURA §38.074(a) and Tex. Nat. Res. Code §8 1.073(a), was to "collaborate with [each other] 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 during energy emergencies;". Joint TDUs concluded that it is unclear how this evaluation would occur under either rule as proposed. To overcome this deficiency Joint TDUs proposed Tiers 1, 2, and 3 of (high-medium-low) prioritization based on criticality. Joint TDUs provided language as proposed clauses (i), (ii), and (iii) to be added to §25.52(h)(2) to that effect. TPA argued that the commission and the RRC must recognize that not every part of a critical gas facility may be needed during a weather emergency, and not all facilities are the same. TPA emphasized the need to consider all pressure maintenance facilities "critical."

Commission response

The commission declines to adopt the proposals of SWEPCO, Cities/TCAP, Joint TDUs, TPPA, and TPA as such recommendations are premature without consideration of the passed RRC rule in conjunction with the map of the state power grid published by the Mapping Committee. The commission anticipates providing agency guidance on prioritization of natural gas to the industry or a further rulemaking project in the future. As previously stated, the commission has collaborated with the RRC throughout this rulemaking process, as required by PURA §38.074. However, comments addressing the RRC's rulemaking project or entities over which the commission has no direct jurisdiction are beyond the scope of this rulemaking project.

§25.52(h)(2)(B) - Discretion regarding load shed and restoration

SWEPCO requested the commission delete the word "critical" from the phrase "other critical loads" in subparagraph (h)(2)(B). According to SWEPCO the phrase "among critical natural gas facilities and other critical loads" could be read to limit a utility' s discretion further than intended. SWEPCO provided as an example where an instance could foreseeably arise in which, to maintain the stability of the distribution system, the utility has no choice but to de-energize a circuit containing a critical natural gas facility while a circuit with no critical loads remains energized. SWEPCO further argued that such a situation may become more likely if the natural gas facilities deemed critical are numerous and widespread. Therefore, SWEPCO concluded removing the word critical would allow utilities retain the discretion to manage all load in the most effective manner possible during an emergency

Commission response

PURA §38.074(b)(3) requires the commission to adopt rules that provide discretion to a utility to prioritize power delivery and power restoration "among the facilities and entities designated under Subsection (a)." Subsection (a) merely refers to natural gas facilities and entities designated as critical during energy emergencies. The commission acknowledges that it has expanded this to include discretion to prioritize power delivery and power restoration among all critical loads, but this was done to harmonize PURA §38.074(b)(3) with other provisions of PURA that relate to critical loads, such as PURA §38.072(c), which requires the commission to allow an electric utility to exercise discretion to prioritize power restoration for certain medical facilities.

Joint TDUs recommended commission add the phrase to the end of subparagraph (h)(2)(B) "as circumstances require."

Commission response

The commission agrees with Joint TDUs that the recommended language provides appropriate discretion and aligns with statutory language. The commission amends the rule accordingly.

SPS proposed adding a sentence that would clarify that "Compliance with the procedures and directives of a regional transmission organization having authority over a utility outside of the ERCOT power region shall be deemed compliance for that utility."

Commission response

The commission agrees with SPS that a utility outside of the ERCOT power region must follow the directives of a regional transmission organization with authority over that utility. The commission adopts similar language as proposed by SPS as subparagraph (D) of this paragraph.

Cities/TCAP cautioned that allowing every utility to create its own load shed and power restoration priority list will lead to ineffective execution of the proposed rule and undermines the intention of the Legislature and the commission to designate critical load for the purpose of increasing electric reliability in a weather emergency. According to Cities/TCAP, entity-by-entity discretion may not lead to the optimization of all utilities. Therefore, Cities/TCAP urged the commission to provide specific guidance on the industry-wide prioritization of natural gas facilities, considering that without natural gas supply, other critical loads cannot receive service.

Commission response

PURA §38.074(b)(3) requires the commission to "provide discretion to an electric utility...to prioritize power delivery and power restoration [for facilities and entities designated as critical under PURA §38.074(a)] and the commission is therefore prohibited from limiting such discretion, as proposed by Cities/TCAP." However, the commission may issue additional guidance on prioritization for power delivery and power restoration purposes under §25.52(h)(2)(C).

§25.52(h)(2)(C) - Additional guidance for prioritization during a load shed event

Proposed new §25.52(h)(2)(C) requires a utility to consider any additional guidance or prioritization criteria provided by the commission, RRC, or ERCOT or governing RTO for its power region in prioritizing critical loads.

Joint TDUs argued that proposed §25.52(h)(2)(C) is vague and overly broad and may lead to confusion. Therefore, Joint TDUs recommended §25.52(h)(2)(C) should be narrowed so that utilities are only obligated to consider additional guidance or prioritization criteria provided by only certain authorized personnel from the commission, the RRC, and ERCOT. SWEPCO recommended the commission to remove §25.52(h)(2)(C) entirely because it is superfluous and vague, and it would leave open to subjective interpretation what constitutes "any additional guidance or prioritization criteria".

TPPA argued that any such guidance or prioritization criteria must be provided by regulatory bodies in advance of load shed events, rather than during such an event. According to TPPA, load shed and power restoration planning are detailed and complex processes, and any delay in a regulatory body providing its necessary expectations for either process can result in unnecessary confusion.

Cities/TCAP stated that the RRC "passed on the option to establish prioritization of critical natural gas facilities, stating it lacks the jurisdiction." Therefore, Cities/TCAP encouraged the commission to implement additional guidance or prioritization criteria to ensure uniformity and effective execution of the proposed rule amendments. In the alternative, Cities/TCAP requested that the commission direct ERCOT to do so through the creation of new Nodal Protocols or Operating Guides necessary to implement the Commission's rule amendments.

Commission response

The commission declines to delete or narrow §25.52(h)(2)(C), or to set a deadline for providing additional guidance. By its very nature, an energy emergency is rapidly changing situation that calls for implementation or documentation of best practices as they are determined. The commission intends to make available guidance reflecting those best practices as appropriate, and expects that the Railroad Commission and reliability coordinators will take a similar approach. The commission further notes that the requirement in subparagraph (C) is for the utility to consider this additional guidance. The utility retains its discretion under under §25.52(h)(2)(B). No changes to the rule language are necessary.

Vistra recommended adding language to the rule to specify that "energy emergency prioritization should seek to maximize delivered natural gas for human needs and safety. including fuel supply to power generation facilities." Vistra further recommended that the commission add language clarifying that the paragraph applies to an energy emergency declared by ERCOT.

Commission response

The commission declines to adopt Vistra's recommendation. Utilities have discretion under PURA §38.074(b)(3) to prioritize load shed and power restoration, which encompasses the concept recommended by Vistra. Further, this subparagraph applies to an energy emergency declared by any reliability coordinator not just those declared by ERCOT. Therefore, Vistra's recommended change is not appropriate. No changes to the rule are necessary.

TEC recommended language to clarify that the guidance referenced may relate not just to prioritization among critical natural gas facilities but also how the prioritization of those facilities relates to other critical loads.

Commission response

The commission agrees with TEC and modifies the rule accordingly.

SPS commented that §25.52(h) should not be applied to SPS as it is a non-ERCOT utility in Texas subject to Federal Energy Regulatory Commission regulated Regional Transmission Organizations.

Commission response

The commission addressed this issue thoroughly in it's analysis of comments to §25.52(a) above. Furthermore, the commission has added §25.52(h)(2)(D), which states that "[c]ompliance with directives of a regional transmission organization having authority over a utility outside of the ERCOT power region will be deemed compliance for that utility.":

Classification criteria for critical natural gas facilities

TEC argued that the commission should explicitly allow a utility to create classifications of critical natural gas facilities for purposes of prioritizing power delivery and restoration. TEC further argued that the commission should provide the following non-exclusive list of factors to consider when creating these classifications: availability and type of backup power supply; duration of that supply; fuel source for that supply; type of facility; role of the facility in the natural gas supply chain; size of the electric load; gas production rate; location of the facility on the utility's system; and whether new or upgraded electric energy equipment or facilities are necessary to serve the facility during an energy emergency and the cost of such equipment or facilities.

Commission response

The commission declines to add a new subparagraph explicitly authorizing a utility to create classifications of critical natural gas facilities as requested by TEC. A utility already has the discretion to develop its own classification system under subparagraph (h)(2)(B). Moreover, the commission disagrees with TEC that the non-exclusive list recommended would provide meaningful guidance to utilities in how to create such classifications. By TEC's own admission, the factors "must be non-exclusive given the variety of distribution systems, geography, and weather across the state." Given this wide variance, the commission opts to not include specific guidance in the language of the rule. The commission may, at its discretion under §25.52(h)(2)(C) as discussed previously, issue additional guidance to utilities on how to classify critical natural gas facilities at future time.

Joint TDUs' proposed new §25.52(h)(2)(D)

Joint TDUs recommended that the commission adopt a new subparagraph to (h)(2) stating that "[n]othing in this Subsection (h) shall be deemed as altering the terms and conditions of a utility's tariff."

Commission response

The commission declines to add language requested by the Joint TDUs. The Joint TDUs did not provide any reasoning supporting this addition, and the commission finds it to be superfluous.

TEC's proposed new §25.52(h)(2)(E)

TEC argued that "under [proposed rule §25.52], utilities will bear the burden of the state's effort to evaluate and determine the priority of a potentially massive amount of critical natural gas load and other critical loads in this state." TEC proposes a limitation on liability for implementing this regulatory process.

Commission response

The commission declines to add a new subparagraph providing a limitation on liability as requested by TEC. PURA §38.074 directs the commission to adopt rules that provide discretion to utilities regarding how to prioritize power delivery and power restoration during energy emergencies. The Texas Legislature did not opt to include liability protection as part of this statutory framework.

OPL's proposed new §25.52(h)(3) Limitation on critical status proposed by OPL

OPL argued that, absent weather conditions that pose a risk of supply chain disruptions, the commission should only consider natural gas facilities that are directly related to gas storage and transport as critical. OPL stated that it would be inefficient and potentially detrimental to grid reliability for the commission to require utilities to treat all types of natural gas facilities as critical electric loads throughout the year, as maintaining adequate gas supply is exclusive to extreme cold weather conditions. OPL further argued that many natural gas facilities currently provide demand response services that contribute to grid reliability, and such facilities could continue to provide those valuable services in most weather conditions without any risk of creating gas supply issues in the ERCOT power region. However, OPL contended that being unnecessarily designated as "critical electric load" under all conditions could unintentionally interfere with a natural gas facility's ability to participate in demand response.

OPL provided recommended language requiring the ERCOT to define conditions under which certain types of natural gas facilities will be treated at critical for purposes of load obligations and being restricted from participating in ancillary services or other demand response programs in ERCOT. OPL's recommended language also indicated that until these conditions were defined by ERCOT, certain natural gas facilities designated as critical gas suppliers by the RRC shall only be treated as critical during the months of December, January, and February, or during other periods declared an extreme cold weather event by the commission.

Commission response

Commission declines to make changes in response to the comments of OPL. Under PURA §38.074, the critical status of natural gas facilities is tied to "energy emergencies" and not seasonality or weather conditions as proposed by OPL. Moreover, how ERCOT defines the conditions under which certain types of natural gas facilities are restricted from participating in ancillary services or other demand response programs is beyond the scope of this rulemaking project.

Statutory Authority

This amended rule is adopted under the following provisions of PURA: §14.001, which provides the commission the general power to regulate and supervise the business of each public utility within its jurisdiction and to do anything specifically designated or implied by PURA that is necessary and convenient to the exercise of that power and jurisdiction; §14.002, which provides the commission with the authority to make and enforce rules reasonably required in the exercise of its powers and jurisdiction; §38.072, which requires the commission to adopt a rule requiring an electric utility to give end stage renal disease facilities the same priority it gives to hospitals in the utility's emergency operations plan for restoring power after an extended power outage; and §38.074, which requires the commission to, in collaboration with the Railroad Commission of Texas, rules to establish a process to designate certain natural gas facilities and entities as critical natural gas customers during energy emergencies and to require utilities to prioritize these facilities for load-shed and power restoration purposes during an energy emergency.

Cross reference to statutes: PURA §§14.001, 14.002, 38.072, and 38.074.

§25.52.Reliability and Continuity of Service.

(a) Application. This section applies to all electric utilities as defined by §25.5(41) of this title (relating to Definitions) and all transmission and distribution utilities as defined by §25.5(137) of this title. When specifically stated, this section also applies to electric cooperatives and municipally-owned utilities (MOUs). The term "utility" as used in this section means an electric utility and a transmission and distribution utility.

(b) General.

(1) Every utility must make all reasonable efforts to prevent interruptions of service. When interruptions occur, the utility must reestablish service within the shortest possible time.

(2) Each utility must make reasonable provisions to manage emergencies resulting from failure of service, and each utility must issue instructions to its employees covering procedures to be followed in the event of emergency in order to prevent or mitigate interruption or impairment of service.

(3) In the event of national emergency or local disaster resulting in disruption of normal service, the utility may, in the public interest, interrupt service to other customers to provide necessary service to civil defense or other emergency service entities on a temporary basis until normal service to these agencies can be restored.

(4) Each utility must maintain adequately trained and experienced personnel throughout its service area so that the utility is able to fully and adequately comply with the service quality and reliability standards.

(5) With regard to system reliability, a utility must not neglect any local neighborhood or geographic area, including rural areas, communities of less than 1,000 persons, and low-income areas.

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

(1) Critical loads--Loads for which electric service is considered crucial for the protection or maintenance of public safety; including but not limited to hospitals, police stations, fire stations, critical water and wastewater facilities, and customers with special in-house life-sustaining equipment.

(2) Critical natural gas facility--A facility designated as a critical customer by the Railroad Commission of Texas under §3.65(b) of this title (relating to Critical Designation of Natural Gas Infrastructure) unless the facility has obtained an exception from its critical status. Designation as a critical natural gas facility does not guarantee the uninterrupted supply of electricity.

(3) Energy emergency--Any event that results in or has the potential to result in firm load shed required by the reliability coordinator of a power region in Texas.

(4) Interruption classifications:

(A) Forced--Interruptions, exclusive of major events, that result from conditions directly associated with a component requiring that it be taken out of service immediately, either automatically or manually, or an interruption caused by improper operation of equipment or human error.

(B) Scheduled--Interruptions, exclusive of major events, that result when a component is deliberately taken out of service at a selected time for purposes of construction, preventative maintenance, or repair. If it is possible to defer an interruption, the interruption is considered a scheduled interruption.

(C) Outside causes--Interruptions, exclusive of major events, that are caused by influences arising outside of the distribution system, such as generation, transmission, or substation outages.

(D) Major events--Interruptions that result from a catastrophic event that exceeds the design limits of the electric power system, such as an earthquake or an extreme storm. These events shall include situations where there is a loss of power to 10% or more of the customers in a region over a 24-hour period and with all customers not restored within 24 hours.

(5) Interruption, momentary--Single operation of an interrupting device which results in a voltage zero and the immediate restoration of voltage.

(6) Interruption, sustained--All interruptions not classified as momentary.

(7) Interruption, significant--An interruption of any classification lasting one hour or more and affecting the entire system, a major division of the system, a community, a critical load, or service to interruptible customers; and a scheduled interruption lasting more than four hours that affects customers that are not notified in advance. A significant interruption includes a loss of service to 20% or more of the system's customers, or 20,000 customers for utilities serving more than 200,000 customers. A significant interruption also includes interruptions adversely affecting a community such as interruptions of governmental agencies, military bases, universities and schools, major retail centers, and major employers.

(8) Reliability indices:

(A) System Average Interruption Frequency Index (SAIFI)--The average number of times that a customer's service is interrupted. SAIFI is calculated by summing the number of customers interrupted for each event and dividing by the total number of customers on the system being indexed. A lower SAIFI value represents a higher level of service reliability.

(B) System Average Interruption Duration Index (SAIDI)--The average amount of time a customer's service is interrupted during the reporting period. SAIDI is calculated by summing the restoration time for each interruption event times the number of customers interrupted for each event and dividing by the total number of customers. SAIDI is expressed in minutes or hours. A lower SAIDI value represents a higher level of service reliability.

(d) Record of interruption. Each utility must keep complete records of sustained interruptions of all classifications. Where possible, each utility must keep a complete record of all momentary interruptions. These records must show the type of interruption, the cause for the interruption, the date and time of the interruption, the duration of the interruption, the number of customers interrupted, the substation identifier, and the transmission line or distribution feeder identifier. In cases of emergency interruptions, the remedy and steps taken to prevent recurrence must be recorded. Each utility must retain records of interruptions for five years.

(e) Notice of significant interruptions.

(1) Initial notice. A utility must notify the commission, in a method prescribed by the commission, as soon as reasonably possible after it has determined that a significant interruption has occurred. The initial notice must include the general location of the significant interruption, the approximate number of customers affected, the cause if known, the time of the event, and the estimated time of full restoration. The initial notice must also include the name and telephone number of the utility contact person and must indicate whether local authorities and media are aware of the event. If the duration of the significant interruption is greater than 24 hours, the utility must update this information daily and file a summary report.

(2) Summary report. Within five working days after the end of a significant interruption lasting more than 24 hours, the utility must submit a summary report to the commission. The summary report must include the date and time of the significant interruption; the date and time of full restoration; the cause of the interruption, the location, substation and feeder identifiers of all affected facilities; the total number of customers affected; the dates, times, and numbers of customers affected by partial or step restoration; and the total number of customer-minutes of the significant interruption (sum of the interruption durations times the number of customers affected).

(f) Priorities for power restoration to certain medical facilities.

(1) A utility must give the same priority that it gives to a hospital in the utility's emergency operations plan for restoring power after an extended power outage, as defined by Texas Water Code, §13.1395, to the following:

(A) An assisted living facility, as defined by Texas Health and Safety Code, §247.002;

(B) A facility that provides hospice services, as defined by Texas Health and Safety Code, §142.001;

(C) A nursing facility, as defined by Texas Health and Safety Code, §242.301; and

(D) An end stage renal disease facility, as defined by Texas Health and Safety Code, §251.001.

(2) The utility may use its discretion to prioritize power restoration for a facility after an extended power outage in accordance with the facility's needs and with the characteristics of the geographic area in which power must be restored.

(g) System reliability. Reliability standards apply to each utility and are limited to the Texas jurisdiction. A "reporting year" is the 12-month period beginning January 1 and ending December 31 of each year.

(1) System-wide standards. The standards must be unique to each utility based on the utility's performance and may be adjusted by the commission if appropriate for weather or improvements in data acquisition systems. The standards will be the average of the utility's performance from the later of reporting years 1998, 1999, and 2000, or the first three reporting years the utility is in operation.

(A) SAIFI. Each utility must maintain and operate its electric distribution system so that its SAIFI value does not exceed its system-wide SAIFI standard by more than 5.0%.

(B) SAIDI. Each utility must maintain and operate its electric distribution system so that its SAIDI value does not exceed its system-wide SAIDI standard by more than 5.0%.

(2) Distribution feeder performance. The commission will evaluate the performance of distribution feeders with ten or more customers after each reporting year. Each utility must maintain and operate its distribution system so that no distribution feeder with ten or more customers sustains a SAIDI or SAIFI value for a reporting year that is more than 300% greater than the system average of all feeders during any two consecutive reporting years.

(3) Enforcement. The commission may take appropriate enforcement action, including action against a utility, if the system and feeder performance is not operated and maintained in accordance with this subsection. In determining the appropriate enforcement action, the commission will consider:

(A) the feeder's operation and maintenance history;

(B) the cause of each interruption in the feeder's service;

(C) any action taken by a utility to address the feeder's performance;

(D) the estimated cost and benefit of remediating a feeder's performance; and

(E) any other relevant factor as determined by the commission.

(h) Critical natural gas facilities. In accordance with §3.65 of this title, critical natural gas standards apply to each facility in this state designated as a critical customer under §3.65 of this title. In this subsection, the term "utility" includes MOUs, electric cooperatives, and entities considered utilities under subsection (a) of this section.

(1) Critical customer information.

(A) In accordance with §3.65 of this title, the operator of a critical natural gas facility must provide critical customer information to the entities listed in clauses (i) and (ii) of this subparagraph. The critical customer information must be provided by email using Form CI-D and any attachments, as prescribed by the Railroad Commission of Texas.

(i) The utility from which the critical natural gas facility receives electric delivery service; and

(ii) For critical natural gas facilities located in the ERCOT region, the independent organization certified under PURA §39.151.

(B) The commission will maintain on its website a list of utility email addresses to be used for the provision of critical customer information under subparagraph (A) of this paragraph. Each utility must ensure that the email address listed on the commission's website is accurate. If the utility's email address changes or is inaccurate, the utility must provide the commission with an updated email address within five business days of the change or of becoming aware of the inaccuracy.

(C) Within ten business days of receipt, the utility must evaluate the critical customer information for completeness and provide written notice to the operator of the critical natural gas facility regarding the status of its critical natural gas designation.

(i) If the information submitted is incomplete, the utility's notice must specify what additional information is required and provide a deadline for response that is no sooner than five business days from when the critical natural gas facility receives the written notice. If the utility does not receive the additional information in a timely fashion, the utility may use its discretion to determine if it is possible to treat the natural gas facility as critical for load shed and power restoration purposes.

(ii) If the information submitted is complete, the utility's notice must notify the operator of the facility's critical natural gas status, the date of its designation, any additional classifications assigned to the facility by the utility, and notice that its critical status does not constitute a guarantee of an uninterrupted supply of energy.

(iii) A utility must provide an additional notice to the operator of the critical natural gas facility regarding any changes to the information provided in the notice required under clause (i) of this subparagraph. Notice must be provided within ten business days of the effective date of the change.

(D) A utility or an independent system operator receiving or sending critical customer information regarding a critical natural gas facility under this subsection must not release critical customer information to any person unless authorized by the commission or the operator of the critical natural gas facility. This prohibition does not apply to the release of such information to the commission, the Railroad Commission of Texas, the utility from which the critical natural gas facility receives electric delivery service, the designated transmission operator, or the independent system operator or reliability coordinator for the power region in which the critical natural gas facility is located. This prohibition also does not apply if the critical customer information is redacted, aggregated, or organized in such a way as to make it impossible to identify the critical natural gas facility to which the information applies.

(2) Prioritization of critical natural gas facilities. A critical natural gas facility is a critical load during an energy emergency. A utility must incorporate critical natural gas facilities into its load-shed and restoration planning. For purposes of this paragraph, a utility may also treat a natural gas facility that self-designated as critical using the Application for Critical Load Serving Electric Generation and Cogeneration form as a critical natural gas facility, as circumstances require.

(A) A utility must prioritize critical natural gas facilities for continued power delivery during an energy emergency.

(B) A utility may use its discretion to prioritize power delivery and power restoration among critical natural gas facilities and other critical loads on its system, as circumstances require.

(C) A utility must consider any additional guidance or prioritization criteria provided by the commission, the Railroad Commission of Texas, or the reliability coordinator for its power region to prioritize among critical natural gas facilities and other critical loads during an energy emergency.

(D) Compliance with directives of a regional transmission organization having authority over a utility outside of the ERCOT power region will be deemed compliance for that utility.

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 30, 2021.

TRD-202104770

Andrea Gonzalez

Rules Coordinator

Public Utility Commission of Texas

Effective date: December 20, 2021

Proposal publication date: October 1, 2021

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


SUBCHAPTER S. WHOLESALE MARKETS

16 TAC §25.505

The Public Utility Commission of Texas (commission) adopts amendments to 16 Texas Administrative Code (TAC) §25.505, relating to reporting requirements and the scarcity pricing mechanism in the Electric Reliability Council of Texas power region, with changes to the proposed rule as published in the October 22, 2021, issue of the Texas Register (46 TexReg 7130). The rule will be republished. These amendments modify the value of the high system-wide offer cap (HCAP) by lowering it from the current $9,000 per megawatt-hour (MWh) and $9,000 per megawatt (MW) per hour to $5,000 per MWh and $5,000 per MW per hour. In this adoption, citations to Public Utility Regulatory Act (PURA) §39.160 refer to that section of the Texas Utilities Code added by Senate Bill 3 §18, 87th Regular Session.

The commission received comments on the proposed amendment from Austin Energy, Hunt Energy Network, LLC (HEN), the City of Houston (Houston), Intersect Power, East Texas Electric Cooperatives, Inc. (ETEC), Jupiter Power LLC (Jupiter Power), Lower Colorado River Authority (LCRA), NextEra Energy Resources (NextEra), the Office of Public Utility Counsel (OPUC), South Texas Electric Cooperative, Inc. (STEC), Steering Committee of Cities Served by Oncor (OCSC), the Texas Advanced Energy Business Alliance (TAEBA), Texas Competitive Power Advocates (TCPA), Texas Electric Cooperatives, Inc. (TEC), Texas Industrial Energy Consumers (TIEC), Texas Public Power Association (TPPA), the Texas Solar Power Association (TSPA), Vistra Corp. (Vistra). No party requested a hearing.

Recommendations for the Value of HCAP

Currently, the value of the HCAP is set at $9,000 per MWh. The proposed amendment would lower this value to $4,500 per MWh.

HEN, OCSC, OPUC, NextEra, ETEC, and Houston generally supported reducing the value of the HCAP to $4,500 per MWh. NextEra stated that a $4,500 per MWh HCAP strikes an adequate balance between creating incentives for generation and load to perform and limiting the financial risk to those purchasing energy at the HCAP. ETEC stated that lowering the value of the HCAP ensures energy prices remain affordable during the upcoming winter season. Houston commented that reducing the HCAP to $4,500 per MWh would lessen the financial impact to customers during scarcity events.

TEC supported the commission's proposal to lower the HCAP, provided that the change is part of a broader initiative to move away from a crisis-based market model toward supply stability and an environment characterized by regulatory certainty. TEC also emphasized the importance of being mindful of how adjustments to the HCAP and the Value of Lost Load (VOLL) will interact with price-responsive demand. TPPA supported adjusting the HCAP downward to a value between $4,500 per MWh and $9,000 per MWh. Jupiter Power could support an HCAP value of $4,500 per MWh or $6,000 per MWh, depending on the outcome of the Brattle scenario analysis discussed at the October 21, 2021 Open Meeting and other wholesale market design changes made by the commission.

TIEC argued that the HCAP should be set at $6,000 per MWh. TIEC expressed concern that reducing the HCAP to $4,500 per MWh will dilute incentives for generator performance and demand response in the real-time market. TIEC explained that some of its members provide incremental demand response between $4,500 and $9,000 per MWh that will likely be lost if the HCAP is reduced to $4,500 per MWh. TAEBA echoed the concerns raised by TIEC, recommending that the commission exercise caution when adjusting the HCAP, as too large of a reduction could result in a decline in participation in economic demand response in the ERCOT power region.

TIEC also contended that the risk of high real-time prices encourages forward hedging by market participants to manage real-time price exposure. Reducing the financial penalty for a resource that fails on a forward obligation in real time, or for a load serving entity that is not properly hedged during emergency conditions, could have adverse impacts on the long-term reliability and health of the ERCOT market. TIEC further stated that the lower the HCAP is set, the more pressure there will be to increase generator revenues from other sources, such as changing the parameters of the Operating Reserve Demand Curve (ORDC) to have a "longer fatter tail." TIEC argued that such changes could shift additional revenues to intermittent resources and impose an unjustified energy tax for consumers during times of sufficient real-time reserves.

STEC recommended that the commission refrain from modifying the HCAP until after the "Brattle Group's study" is completed. STEC maintained that wholesale changes to the market are best done with a comprehensive, holistic approach with input from stakeholders. STEC stated that constantly modifying the offer caps and ORDC parameters will be detrimental to the market, as it introduces additional regulatory uncertainty. Additionally, STEC expressed concern that any reduction in the HCAP without a fuel cost recovery mechanism could exacerbate energy supply issues during scarcity events when natural gas prices are high. Under the right conditions, STEC continued, it may not be economically feasible for generators to offer capacity into the market as fuel costs would be unrecoverable. Rather than altering the HCAP in isolation, STEC recommended that the commission look to the customer protection rules to ensure consumers are protected from exposure to volatile electricity costs.

Intersect Power stated it is unwise to lower the HCAP to $4,500 per MWh. TSPA commented that it will be difficult to raise the offer cap after lowering it. TSPA stated that the offer cap must be high enough for generators to have financial risk for outages and to encourage economic demand response when conditions warrant.

Commission Response

The commission modifies the language of §25.505(g)(6)(B) to set the HCAP at $5,000 per MWh and $5,000 per MW per hour.

After the extreme weather events of February 2021, the price cap of $9,000 per MWh has proven to be a liability on market participants and customers of ERCOT. The commission agrees with HEN, OCSC, OPUC, NextEra, ETEC, and Houston that lowering the HCAP would help ensure prices remain affordable during the upcoming winter season and lessen the financial risk to customers during scarcity events. The commission also agrees with TIEC and TAEBA that lowering the HCAP too much would reduce the incentives for economic demand response.

Setting the HCAP at $5,000 per MWh and $5,000 per MW per hour strikes the best balance of ensuring appropriate generation is brought to the market using market-based mechanisms and incentivizing demand response during scarcity events while limiting extraordinary financial liability for all market participants and customers during such events. Additional changes to the wholesale market design are being considered in Project Number 52373.

Coordination Between Modifying the Value of HCAP and ORDC Changes

Nearly every commenter recognized the importance of aligning any changes to the value of the HCAP with any other changes made by the commission to the ERCOT wholesale market design.

OCSC and OPUC acknowledged that adjusting the HCAP is only one component of the needed comprehensive and holistic review of the ERCOT wholesale market design. TPPA acknowledged that the commission is simultaneously working on changes to ORDC in Project Number 52373, and TPPA encouraged the commission to carefully consider how modifications to the HCAP may affect the ORDC going forward. TEC supported lowering the HCAP with the understanding that this change will be done in concert with other market modifications, including changes to parameters of the ORDC, new ancillary service products, and other changes that support reliable fuel supply and system resilience. TSPA encouraged the commission to consider any changes to the HCAP in concert with modifications to the ORDC, as these matters are inextricably intertwined.

TCPA and Vistra supported a lower HCAP but stated that the HCAP reduction needs to be implemented in conjunction with the commensurate ORDC reforms needed to maintain existing revenues and provide investment signals to existing and new generation resource owners. TCPA and Vistra stated that the ORDC reforms need to incentivize economic commitment of the desired level of real-time operating reserves so that ERCOT does not have to rely on out-of-market commitment of resources to achieve the desired operating reserves. TCPA stated that this includes, at a minimum, increasing the probability of reserves falling below the minimum contingency level within the ORDC. TCPA recommended that the commission adopt all required ORDC changes prior to the end of 2021 so that such changes can become effective simultaneously with the lowered HCAP value. Vistra recommended modifications that include increasing the minimum contingency level and shifting the ORDC standard deviation parameter. Additionally, Vistra emphasized the importance that any ORDC changes need to be examined in light of the historical levels of offline reserves, which Vistra stated have been at about 33% of the online reserve levels.

STEC argued that reducing the HCAP in isolation would further degrade resource adequacy and reliability. LCRA agreed with STEC, commenting that a reduction in the HCAP should only be implemented in concert with corresponding ORDC changes to ensure the HCAP change will not harm the existing wholesale market. TAEBA averred that reducing the HCAP without simultaneously considering changes to other key components of the wholesale energy market and evaluating the financial impact of all changes together poses significant regulatory risk. Intersect Power specifically mentioned increasing the minimum contingency level and encouraged the commission to make this adjustment regardless of a decision to reduce the HCAP. Austin Energy suggested that the commission pause this rulemaking to allow for adequate time to analyze the impacts from changes to the HCAP. Austin Energy recommended that changes to the value of the HCAP be incorporated into the broader wholesale market design changes in Project Number 52373, because the appropriate HCAP level will be determined by other decisions regarding the market design construct.

HEN contended that the commission should take a holistic approach to reviewing the HCAP, VOLL, ORDC, Ancillary Service demand curves, and the power balance penalty curve. In the view of HEN, the current ORDC does not send the appropriate price signals, because the parameters have not been adjusted to reflect the recent discussion to procure 6,500 MW of reserves from generation resources. A lower value for VOLL could exacerbate this problem. HEN recommends, in conjunction with a $4,500 per MWh HCAP, setting VOLL at $9,000 per MWh, the minimum contingency level at 3,000 MW, and increasing the ORDC standard deviation parameter. NextEra strongly argued that any reduction in the HCAP needs to be offset by changes to the ORDC parameters that will shift the ORDC to the right so that the revised curve causes scarcity pricing to occur at higher reserve margins. NextEra recommended the following ORDC parameters to avoid a reduction in generation revenues: HCAP at $4,500 per MWh, VOLL at $15,000 per MWh, minimum contingency level at 2,300 MW, and shifting the ORDC to cause scarcity pricing to occur at higher reserve margins. Jupiter Power posited that a downward change in the HCAP necessitates changes to the ORDC curve, including lifting the minimum contingency level from 2,000 MW.

Commission Response

The commission declines to delay modifying the value of the HCAP. The system-wide offer cap begins each calendar year set to the HCAP. Then, if the peaker net margin exceeds three times the cost of new entry of a generation plant, as it did during Winter Storm Uri, the system-wide offer cap drops from the HCAP to the low system-wide offer cap (LCAP), which is substantially lower and serves as an important customer protection against high prices. The system-wide offer cap is set to the LCAP for the remainder of 2021, but it will revert to the HCAP on January 1, 2022. It is the intent of the commission that the lowered HCAP take effect before this date to maintain a degree of protection against high prices. However, the commission will consider additional market design changes in a future rulemaking project, informed by the requested analysis by Brattle.

Decoupling VOLL from the System-Wide Offer Cap in Effect

Several parties recommended that the commission consider decoupling VOLL from the system-wide offer cap in effect, as is currently required by §25.505(g)(6)(E). While not taking a position in its comments, Austin Energy recommended that the commission make a determinative decision as to whether the VOLL in the ORDC should be coupled to the system-wide offer cap or otherwise decoupled. HEN supported severing the link in §25.505(g)(6)(E) and keeping VOLL at $9,000 per MWh when the HCAP is in effect. Vistra recommended that the commission consider striking the provision in §25.505(g)(6)(E) that equates the value of VOLL to the system-wide offer cap that is in effect. Vistra stated that doing so will give the commission needed flexibility to study other proposals affecting VOLL that are already being discussed in Project Number 52373. NextEra encouraged the commission to evaluate decoupling the HCAP from VOLL to ensure that price-suppressing impacts of a reduced HCAP do not cause dispatchable generation revenues to decrease. Intersect Power stated that as the Texas economy and Texas residents' quality of life is increasingly dependent on electric and digital infrastructure, VOLL should be increasing, not decreasing. If the commission chooses to reduce the HCAP, Intersect Power requested that it decouple the HCAP from VOLL and increase VOLL to $20,000 per MWh as recommended by the Independent Market Monitor.

Commission Response

For purposes of this rulemaking, the commission retains the language in §25.505(g)(6)(E) that sets VOLL equal to the system-wide offer cap in effect. The commission will review alternative values of VOLL in Project Number 52373 and may reconsider this issue in a future rulemaking.

Emergency Pricing Program

Austin Energy, HEN, TIEC, ETEC and Houston all referenced either the emergency pricing program in PURA §39.160 or the need for an additional circuit breaker during extended periods of high prices, as experienced during Winter Storm Uri. Austin Energy encouraged the commission to consider the design of the emergency pricing program, given the dependence of this new pricing mechanism on the value of the HCAP. HEN and TIEC both commented that the commission should implement the emergency pricing programs in accordance with PURA §39.160 to protect the market from sustained scarcity prices over a long duration and limit the financial risk exposure of extended real-time price excursions during extreme weather events. ETEC argued that implementing the additional measures recently put in place by the legislature in PURA §39.160 will help prevent extreme pricing events, like the one experienced during Winter Storm Uri. Houston pointed out that the lack of an effective circuit breaker during Winter Storm Uri contributed to the impacts felt by customers in Texas as much as the absolute level of the HCAP. Houston recommended that the commission add in a circuit breaker that would cap prices at the LCAP when the HCAP price signal no longer provides any material benefit to real-time resource adequacy or reliability.

Commission Response

The commission makes no changes in response to these comments. The emergency pricing program is beyond the limited scope of this rulemaking. The commission will establish the emergency pricing program as required in PURA §39.160 in a future rulemaking.

Additional Comments

Jupiter Power commented that the commission should consider seasonal ORDC curves and seasonal values for the HCAP and VOLL. It also recommended that the commission evaluate any changes to the HCAP one year from now, with additional reviews on a periodic basis to ensure the wholesale energy market is signaling investment in resources ensuring resource adequacy.

Austin Energy recommended that the commission consider expanding the scope of the cost recovery provision in §25.505(g)(7), which allows a resource entity to be reimbursed for operating losses when the LCAP is in effect, to apply to periods when the HCAP is in effect.

Vistra recommended the approval of a mechanism, such as the Dispatchable Standby Reserve product they recommended in Project 52373, by which additional resources are retained and available to the market as insurance when needed. Vistra argued this new product is complementary to the ORDC improvements and encouraged the commission to work towards concurrent or near-concurrent approval of all of the associated market design elements.

Commission Response

The commission declines to make changes in response to these comments. These recommendations are beyond the scope of this rulemaking. However, the commission encourages commenters to participate in Project Number 52373, which is evaluating market design issues more broadly.

Statutory Authority

These amendments are adopted under §14.002 of the Public Utility Regulatory Act, (PURA), which provides the commission with the authority to make and enforce rules reasonably required in the exercise of its powers and jurisdiction; PURA §39.101, which establishes that customers are entitled to safe, reliable, and reasonably priced electricity and gives the commission the authority to adopt and enforce rules to carry out these provisions; and PURA §39.151, which grants the commission oversight and review authority over independent organizations such as ERCOT, directs the commission to adopt and enforce rules relating to the reliability of the regional electrical network and accounting for the production and delivery of electricity among generators and all other market participants, and authorizes the commission to delegate to an independent organization such as ERCOT responsibilities for establishing or enforcing such rules.

Cross reference to statutes: PURA §14.002, §39.101, and §39.151.

§25.505.Reporting Requirements and the Scarcity Pricing Mechanism in the Electricity Reliability Council of Texas Power Region.

(a) General. The purpose of this section is to prescribe reporting requirements for the Electric Reliability Council of Texas (ERCOT) and market participants, and to establish a scarcity pricing mechanism for the ERCOT market.

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

(1) Generation entity -- an entity that owns or controls a generation resource.

(2) Load entity -- an entity that owns or controls a load resource. A load resource is a load capable of providing ancillary service to the ERCOT system or energy in the form of demand response and is registered with ERCOT as a load resource.

(3) Resource entity -- an entity that is a generation entity or a load entity.

(c) Resource adequacy reports. ERCOT must publish a resource adequacy report by December 31 of each year that projects, for at least the next five years, the capability of existing and planned electric generation resources and load resources to reliably meet the projected system demand in the ERCOT power region. ERCOT may publish other resource adequacy reports or forecasts as it deems appropriate. ERCOT must prescribe requirements for generation entities and transmission service providers (TSPs) to report their plans for adding new facilities, upgrading existing facilities, and mothballing or retiring existing facilities. ERCOT also must prescribe requirements for load entities to report their plans for adding new load resources or retiring existing load resources.

(d) Daily assessment of system adequacy. Each day, ERCOT must publish a report that includes the following information for each hour for the seven days beginning with the day the report is published:

(1) System-wide load forecast; and

(2) Aggregated information on the availability of resources, by ERCOT load zone, including load resources.

(e) Filing of resource and transmission information with ERCOT. ERCOT must prescribe reporting requirements for resource entities and TSPs for the preparation of the assessment required by subsection (d) of this section. At a minimum, the following information must be reported to ERCOT:

(1) TSPs will provide ERCOT with information on planned and existing transmission outages.

(2) Generation entities will provide ERCOT with information on planned and existing generation outages.

(3) Load entities will provide ERCOT with information on planned and existing availability of load resources, specified by type of ancillary service.

(4) Generation entities will provide ERCOT with a complete list of generation resource availability and performance capabilities, including, but not limited to:

(A) the net dependable capability of generation resources;

(B) projected output of non-dispatchable resources such as wind turbines, run-of-the-river hydro, and solar power; and

(C) output limitations on generation resources that result from fuel or environmental restrictions.

(5) Load serving entities (LSEs) will provide ERCOT with complete information on load response capabilities that are self-arranged or pursuant to bilateral agreements between LSEs and their customers.

(f) Publication of resource and load information in ERCOT markets. To increase the transparency of the ERCOT-administered markets, ERCOT must post the information required in this subsection at a publicly accessible location on its website. In no event will ERCOT disclose competitively sensitive consumption data. The information released must be made available to all market participants.

(1) ERCOT will post the following information in aggregated form, for each settlement interval and for each area where available, two calendar days after the day for which the information is accumulated:

(A) Quantities and prices of offers for energy and each type of ancillary capacity service, in the form of supply curves;

(B) Self-arranged energy and ancillary capacity services, for each type of service;

(C) Actual resource output;

(D) Load and resource output for all entities that dynamically schedule their resources;

(E) Actual load; and

(F) Energy bid curves, cleared energy bids, and cleared load.

(2) ERCOT will post the following information in entity-specific form, for each settlement interval, 60 calendar days after the day for which the information is accumulated, except where inapplicable or otherwise prescribed. Resource-specific offer information must be linked to the name of the resource (or identified as a virtual offer), the name of the entity submitting the information, and the name of the entity controlling the resource. If there are multiple offers for the resource, ERCOT must post the specified information for each offer for the resource, including the name of the entity submitting the offer and the name of the entity controlling the resource. ERCOT will use §25.502(d) of this title (relating to Pricing Safeguards in Markets Operated by the Electric Reliability Council of Texas) to determine the control of a resource and must include this information in its market operations data system.

(A) Offer curves (prices and quantities) for each type of ancillary service and for energy in the real time market, except that, for the highest-priced offer selected or dispatched for each interval on an ERCOT-wide basis, ERCOT will post the offer price and the name of the entity submitting the offer three calendar days after the day for which the information is accumulated.

(B) If the clearing prices for energy or any ancillary service exceeds a calculated value that is equal to 50 times a natural gas price index selected by ERCOT for each operating day, expressed in dollars per megawatt-hour (MWh) or dollars per megawatt per hour, during any interval, the portion of every market participant's price-quantity offer pairs for balancing energy service and each other ancillary service that is at or above a calculated value that is equal to 50 times a natural gas price index selected by ERCOT for each operating day, expressed in dollars per megawatt-hour (MWh) or dollars per megawatt per hour, for that service and that interval must be posted seven calendar days after the day for which the offer is submitted.

(C) Other resource-specific information, as well as self-arranged energy and ancillary capacity services, and actual resource output, for each type of service and for each resource at each settlement point;

(D) The load and generation resource output, for each entity that dynamically schedules its resources; and

(E) For each hour, transmission flows, voltages, transformer flows, voltages and tap positions (i.e., State Estimator data). Notwithstanding the provisions of this subparagraph and the provisions of subparagraphs (A) through (D) of this paragraph, ERCOT must release relevant State Estimator data earlier than 60 days after the day for which the information is accumulated if, in its sole discretion, it determines the release is necessary to provide a complete and timely explanation and analysis of unexpected market operations and results or system events, including but not limited to pricing anomalies, recurring transmission congestion, and system disturbances. ERCOT's release of data in this event must be limited to intervals associated with the unexpected market or system event as determined by ERCOT. The data released must be made available simultaneously to all market participants

(g) Scarcity pricing mechanism (SPM). ERCOT will administer the SPM. The SPM will operate as follows:

(1) The SPM will operate on a calendar year basis.

(2) For each day, the peaking operating cost (POC) will be 10 times the natural gas price index value determined by ERCOT. The POC is calculated in dollars per megawatt-hour (MWh).

(3) For the purpose of this section, the real-time energy price (RTEP) will be measured as an average system-wide price as determined by ERCOT.

(4) Beginning January 1 of each calendar year, the peaker net margin will be calculated as: Ʃ((RTEP - POC) * (number of minutes in a settlement interval / 60 minutes per hour)) for each settlement interval when RTEP - POC >0.

(5) Each day, ERCOT will post at a publicly accessible location on its website the updated value of the peaker net margin, in dollars per megawatt (MW).

(6) System-wide offer caps.

(A) The low system-wide offer cap (LCAP) will be set at $2,000 per MWh and $2,000 per MW per hour.

(B) The high system-wide offer cap (HCAP) will be $5,000 per MWh and $5,000 per MW per hour.

(C) The system-wide offer cap will be set equal to the HCAP at the beginning of each calendar year and maintained at this level until the peaker net margin during a calendar year exceeds a threshold of three times the cost of new entry of new generation plants.

(D) If the peaker net margin exceeds the threshold established in subparagraph (C) of this paragraph during a calendar year, the system-wide offer cap will be set to the LCAP for the remainder of that calendar year. In this event, ERCOT will continue to apply the operating reserve demand curve and the reliability deployment price adder for the remainder of that calendar year. Energy prices, exclusive of congestion prices, will not exceed the LCAP plus $1 for the remainder of that calendar year.

(E) The value of the lost load will be equal to the value of the system-wide offer cap in effect.

(7) Reimbursement for operating losses when the LCAP is in Effect. When the system-wide offer cap is set to the LCAP, ERCOT must reimburse resource entities for any actual marginal costs in excess of the larger of the LCAP or the real-time energy price for the resource. ERCOT must utilize existing settlement processes to the extent possible to verify the resource entity's costs for reimbursement.

(h) Development and implementation. ERCOT must use a stakeholder process to develop and implement rules that comply with this section. Nothing in this section prevents the commission from taking actions necessary to protect the public interest, including actions that are otherwise inconsistent with the other provisions in this section.

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

Filed with the Office of the Secretary of State on December 2, 2021.

TRD-202104787

Melissa Ethridge

Assistant Rules Coordinator

Public Utility Commission of Texas

Effective date: December 22, 2021

Proposal publication date: October 22, 2021

For further information, please call: (512) 936-7299