Tex. UTIL Code § 38.001. GENERAL STANDARD.
An electric utility and an electric cooperative shall furnish service, instrumentalities, and facilities that are safe, adequate, efficient, and reasonable.
REGULATION OF ELECTRIC SERVICES
Tex. UTIL Code ch. 38
in effectTex. UTIL Code § 38.002. AUTHORITY OF REGULATORY AUTHORITY CONCERNING STANDARDS.
A regulatory authority, on its own motion or on complaint and after reasonable notice and hearing, may:
(1) adopt just and reasonable standards, classifications, rules, or practices an electric utility must follow in furnishing a service;
(2) adopt adequate and reasonable standards for measuring a condition, including quantity, quality, pressure, and initial voltage, relating to the furnishing of a service;
(3) adopt reasonable rules for examining, testing, and measuring a service; and
(4) adopt or approve reasonable rules, specifications, and standards to ensure the accuracy of equipment, including meters and instruments, used to measure a service.
Tex. UTIL Code § 38.003. RULE OR STANDARD.
(a) An electric utility may not impose a rule except as provided by this title.
(b) An electric utility may file with the regulatory authority a standard, classification, rule, or practice the utility follows.
(c) The standard, classification, rule, or practice continues in force until:
(1) amended by the utility; or
(2) changed by the regulatory authority as provided by this title.
Tex. UTIL Code § 38.004. MINIMUM CLEARANCE STANDARD.
(a) Notwithstanding any other law, a transmission or distribution line owned by an electric utility or an electric cooperative must be constructed, operated, and maintained, as to clearances, in the manner described by the National Electrical Safety Code Standard ANSI (c)(2), as adopted by the American National Safety Institute and in effect at the time of construction.
(b) An electric utility, municipally owned utility, or electric cooperative shall meet the minimum clearance requirements specified in Rule 232 of the National Electrical Safety Code Standard ANSI (c)(2) in the construction of any transmission or distribution line over the following lakes:
(1) Abilene;
(2) Alan Henry;
(3) Alvarado Park;
(4) Amistad;
(5) Amon G. Carter;
(6) Aquilla;
(7) Arlington;
(8) Arrowhead;
(9) Athens;
(10) Austin;
(11) Averhoff;
(12) B. A. Steinhagen;
(13) Bachman;
(14) Balmorhea;
(15) Bardwell;
(16) Bastrop;
(17) Baylor Creek;
(18) Belton;
(19) Benbrook;
(20) Big Creek;
(21) Bob Sandlin;
(22) Bonham;
(23) Bonham State Park;
(24) Brady Creek;
(25) Brandy Branch;
(26) Braunig;
(27) Brazos;
(28) Bridgeport;
(29) Brownwood;
(30) Bryan;
(31) Bryson;
(32) Buchanan;
(33) Buffalo Creek;
(34) Buffalo Springs;
(35) Caddo;
(36) Calaveras;
(37) Canyon;
(38) Casa Blanca;
(39) Cedar Creek;
(40) Champion Creek;
(41) Choke Canyon;
(42) Cisco;
(43) Cleburne State Park;
(44) Clyde;
(45) Coffee Mill;
(46) Coleman;
(47) Coleto Creek;
(48) Colorado City;
(49) Conroe;
(50) Cooper;
(51) Corpus Christi;
(52) Crook;
(53) Cypress Springs;
(54) Daniel;
(55) Davy Crockett;
(56) Diversion;
(57) Dunlap;
(58) Eagle Mountain;
(59) E. V. Spence;
(60) Fairfield;
(61) Falcon;
(62) Fayette County;
(63) Findley;
(64) Fork;
(65) Fort Parker State Park;
(66) Fort Phantom Hill;
(67) Fryer;
(68) Georgetown;
(69) Gibbons Creek;
(70) Gilmer;
(71) Gladewater;
(72) Gonzales;
(73) Graham;
(74) Granbury;
(75) Granger;
(76) Grapevine;
(77) Greenbelt;
(78) Halbert;
(79) Hawkins;
(80) Holbrook;
(81) Hords Creek;
(82) Houston;
(83) Houston County;
(84) Hubbard Creek;
(85) Inks;
(86) Jacksboro;
(87) Jacksonville;
(88) J. B. Thomas;
(89) Joe Pool;
(90) Kemp;
(91) Kickapoo;
(92) Kirby;
(93) Kurth;
(94) Lady Bird;
(95) Lake O' The Pines;
(96) Lavon;
(97) Leon;
(98) Lewisville;
(99) Limestone;
(100) Livingston;
(101) Lone Star;
(102) Lost Creek;
(103) Lyndon B. Johnson;
(104) Mackenzie;
(105) Marble Falls;
(106) Marine Creek;
(107) Martin Creek;
(108) McClellan;
(109) Medina;
(110) Meredith;
(111) Meridian State Park;
(112) Mexia;
(113) Mill Creek;
(114) Millers Creek;
(115) Mineral Wells;
(116) Monticello;
(117) Moss;
(118) Mountain Creek;
(119) Muenster;
(120) Murvaul;
(121) Nacogdoches;
(122) Naconiche;
(123) Nasworthy;
(124) Navarro Mills;
(125) New Ballinger;
(126) Nocona;
(127) Oak Creek;
(128) O. C. Fisher;
(129) O. H. Ivie;
(130) Palestine;
(131) Palo Duro;
(132) Palo Pinto;
(133) Pat Cleburne;
(134) Pat Mayse;
(135) Pinkston;
(136) Placid;
(137) Possum Kingdom;
(138) Proctor;
(139) Purtis Creek;
(140) Quitman;
(141) Raven;
(142) Ray Hubbard;
(143) Ray Roberts;
(144) Red Bluff;
(145) Richland-Chambers;
(146) Sam Rayburn;
(147) Sheldon;
(148) Somerville;
(149) Squaw Creek;
(150) Stamford;
(151) Stillhouse Hollow;
(152) Striker;
(153) Sulphur Springs;
(154) Sweetwater;
(155) Tawakoni;
(156) Texana;
(157) Texoma;
(158) Timpson;
(159) Toledo Bend;
(160) Tradinghouse Creek;
(161) Travis;
(162) Twin Buttes;
(163) Tyler;
(164) Waco;
(165) Walter E. Long;
(166) Waxahachie;
(167) Weatherford;
(168) Welsh;
(169) Wheeler Branch;
(170) White River;
(171) White Rock;
(172) Whitney;
(173) Wichita;
(174) Winnsboro;
(175) Winters-Elm Creek;
(176) Wood;
(177) Worth; and
(178) Wright Patman.
Tex. UTIL Code § 38.005. ELECTRIC SERVICE RELIABILITY MEASURES.
(a) The commission shall implement service quality and reliability standards relating to the delivery of electricity to retail customers by electric utilities and transmission and distribution utilities. The commission by rule shall develop reliability standards, including:
(1) the system-average interruption frequency index (SAIFI);
(2) the system-average interruption duration index (SAIDI);
(3) achievement of average response time for customer service requests or inquiries; or
(4) other standards that the commission finds reasonable and appropriate.
(b) The commission may take appropriate enforcement action under this section, including action against a utility, if any of the utility's feeders with 10 or more customers has had a SAIDI or SAIFI average that is more than 200 percent greater than the system average of all feeders during any two-year period. In determining the appropriate enforcement action, the commission shall consider:
(1) the feeder's operating and maintenance history;
(2) the cause of each interruption in the feeder's service;
(3) the duration of each interruption in the feeder's service;
(4) any action taken by a utility to address the feeder's performance;
(5) the estimated cost and benefit of remediating a feeder's performance; and
(6) any other relevant factor as determined by the commission.
(c) The standards implemented under Subsection (a) shall require each electric utility and transmission and distribution utility subject to this section to maintain adequately trained and experienced personnel throughout the utility's service area so that the utility is able to fully and adequately comply with the appropriate service quality and reliability standards.
(d) The standards shall ensure that electric utilities do not neglect any local neighborhood or geographic area, including rural areas, communities of less than 1,000 persons, and low-income areas, with regard to system reliability.
(e) The commission may require each electric utility and transmission and distribution utility to supply data to assist the commission in developing the reliability standards.
(f) Each electric utility, transmission and distribution utility, electric cooperative, municipally owned utility, and generation provider shall be obligated to comply with any operational criteria duly established by the independent organization as defined by Section 39.151 or adopted by the commission.
Added by Acts 1999, 76th Leg., ch. 405, Sec. 36, eff. Sept. 1, 1999.
Acts 2009, 81st Leg., R.S., Ch. 424 (H.B. 2052 ), Sec. 1, eff. June 19, 2009.
Tex. UTIL Code § 38.006. STRUCTURAL INTEGRITY STANDARDS FOR TRANSMISSION AND DISTRIBUTION POLES.
(a) This section applies only to an electric utility, municipally owned utility, or electric cooperative that operates transmission or distribution assets.
(b) The commission by rule shall adopt standards for the structural integrity of transmission and distribution poles.
(c) The standards adopted under this section must:
(1) require an electric utility to:
(A) inspect, maintain, remediate, and replace transmission and distribution poles as necessary on a timeline established by the commission; and
(B) maintain records of the actions described by Paragraph (A);
(2) account for geographic and weather characteristics of this state;
(3) consider national guidelines such as the National Electrical Safety Code and guidelines developed by the Rural Utilities Service of the United States Department of Agriculture;
(4) establish a classification system to assess the serviceability of transmission and distribution poles that accounts for pole maintenance and extending the service life of transmission and distribution poles; and
(5) consider the characteristics of electric utility, municipally owned utility, and electric cooperative transmission and distribution systems throughout this state.
(d) The governing body of a municipally owned utility or an electric cooperative shall adopt for the utility or cooperative, as applicable, the standards adopted by the commission under Subsection (b). If the commission revises the standards adopted under Subsection (b), the governing body of each municipally owned utility and electric cooperative shall adopt the revised standards not later than the 120th day after the effective date of the commission's revised standards.
(e) Not later than May 1 of each year, each electric utility, municipally owned utility, and electric cooperative shall submit to the commission a report on:
(1) the implementation of the utility's or cooperative's transmission and distribution pole maintenance schedule;
(2) the results of the utility's or cooperative's inspection of transmission and distribution poles, including the number of poles inspected and any remediation or replacement action taken; and
(3) any other information the commission requires.
(f) A municipally owned utility or electric cooperative shall include with the first report required under Subsection (e) after the utility or cooperative adopts initial or revised standards under Subsection (d) an attestation from the utility's or cooperative's highest-ranking representative, official, or officer with binding authority over the utility or cooperative stating that the utility or cooperative has adopted standards in compliance with this section.
(g) The commission may impose an administrative penalty under Section 15.023 against a municipally owned utility or electric cooperative for a violation of this section or a rule adopted under this section.
Added by Acts 2025, 89th Leg., R.S., Ch. 856 (S.B. 1789 ), Sec. 3, eff. September 1, 2025.
SUBCHAPTER B. PROHIBITIONS ON PREFERENCES AND DISCRIMINATION
Tex. UTIL Code § 38.021. UNREASONABLE PREFERENCE OR PREJUDICE CONCERNING SERVICE PROHIBITED.
In providing a service to persons in a classification, an electric utility may not:
(1) grant an unreasonable preference or advantage to a person in the classification; or
(2) subject a person in the classification to an unreasonable prejudice or disadvantage.
Tex. UTIL Code § 38.022. DISCRIMINATION AND RESTRICTION ON COMPETITION.
An electric utility may not:
(1) discriminate against a person or electric cooperative who sells or leases equipment or performs services in competition with the electric utility; or
(2) engage in a practice that tends to restrict or impair that competition.
SUBCHAPTER C. EXAMINATIONS, TESTS, AND INSPECTIONS
Tex. UTIL Code § 38.051. EXAMINATION AND TEST OF INSTRUMENT OR EQUIPMENT; INSPECTION.
(a) A regulatory authority may:
(1) examine and test equipment, including meters and instruments, used to measure service of an electric utility; and
(2) set up and use on the premises occupied by an electric utility an apparatus or appliance necessary for the examination or test.
(b) The electric utility is entitled to be represented at an examination, test, or inspection made under this section.
(c) The electric utility and its officers and employees shall facilitate the examination, test, or inspection by giving reasonable aid to the regulatory authority and to any person designated by the regulatory authority for the performance of those duties.
Tex. UTIL Code § 38.052. INSPECTION FOR CONSUMER.
(a) A consumer may have a meter or other measuring device tested by an electric utility:
(1) once without charge, after a reasonable period of presumed accuracy the regulatory authority establishes by rule; and
(2) at a shorter interval on payment of a reasonable fee established by the regulatory authority.
(b) The regulatory authority shall establish reasonable fees to be paid for other examining or testing of a measuring device on the request of a consumer.
(c) If the consumer requests the test under Subsection (a)(2) and the measuring device is found unreasonably defective or incorrect to the substantial disadvantage of the consumer, the fee the consumer paid at the time of the request shall be refunded.
SUBCHAPTER D. IMPROVEMENTS IN SERVICE
Tex. UTIL Code § 38.071. IMPROVEMENTS IN SERVICE; INTERCONNECTING SERVICE.
The commission, after notice and hearing, may:
(1) order an electric utility to provide specified improvements in its service in a specified area if:
(A) service in the area is inadequate or substantially inferior to service in a comparable area; and
(B) requiring the company to provide the improved service is reasonable; or
(2) order two or more electric utilities or electric cooperatives to establish specified facilities for interconnecting service.
Tex. UTIL Code § 38.072. PRIORITIES FOR POWER RESTORATION TO CERTAIN MEDICAL FACILITIES.
(a) In this section:
(1) "Assisted living facility" has the meaning assigned by Section 247.002 , Health and Safety Code.
(2) "End stage renal disease facility" has the meaning assigned by Section 251.001 , Health and Safety Code.
(3) "Extended power outage" has the meaning assigned by Section 13.1395 , Water Code.
(4) "Hospice services" has the meaning assigned by Section 142.001 , Health and Safety Code.
(5) "Nursing facility" has the meaning assigned by Section 242.301 , Health and Safety Code.
(b) The commission by rule shall require an electric utility to give to the following the same priority that it gives to a hospital in the utility's emergency operations plan for restoring power after an extended power outage:
(1) a nursing facility;
(2) an assisted living facility;
(3) an end stage renal disease facility; and
(4) a facility that provides hospice services.
(c) The rules adopted by the commission under Subsection (b) must allow an electric utility to exercise the electric utility's 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.
(d) A municipally owned utility shall report the emergency operations plan for restoring power to a facility listed in Subsection (b) to the municipality's governing body or the body vested with the power to manage and operate the municipally owned utility.
(e) An electric cooperative shall report the emergency operations plan for restoring power to a facility listed in Subsection (b) to the board of directors of the electric cooperative.
Added by Acts 2011, 82nd Leg., R.S., Ch. 640 (S.B. 937 ), Sec. 1, eff. September 1, 2011.
Tex. UTIL Code § 38.073. AUTHORITY OF COMMISSION DURING AN EMERGENCY.
(a) On a declaration of a natural disaster or other emergency by the governor, the commission may require an electric utility, municipally owned utility, electric cooperative, qualifying facility, power generation company, exempt wholesale generator, or power marketer to sell electricity to an electric utility, municipally owned utility, or electric cooperative that is unable to supply power to meet customer demand due to the natural disaster or other emergency. Any plant, property, equipment, or other items used to receive or deliver electricity under this subsection are used and useful in delivering service to the public, and the commission shall allow timely recovery for the costs of those items. The commission may order an electric utility, municipally owned utility, or electric cooperative to provide interconnection service to another electric utility, municipally owned utility, or electric cooperative to facilitate a sale of electricity under this section. If the commission does not order the sale of electricity during a declared emergency as described by this subsection, the commission shall promptly submit to the legislature a report describing the reasons why the commission did not make that order.
(b) If an entity receives electricity under Subsection (a), the receiving entity shall reimburse the supplying entity for the actual cost of providing the electricity. The entity receiving the electricity is responsible for any transmission and distribution service charges specifically incurred in relation to providing the electricity.
(c) An entity that pays for electricity received under Subsection (b) and that is regulated by the commission may fully recover the cost of the electricity in a timely manner by:
(1) including the cost in the entity's fuel cost under Section 36.203 ; or
(2) notwithstanding Section 36.201 , imposing a different surcharge.
Added by Acts 2009, 81st Leg., R.S., Ch. 1226 (S.B. 1492 ), Sec. 2, eff. June 19, 2009.
Added by Acts 2009, 81st Leg., R.S., Ch. 1280 (H.B. 1831 ), Sec. 2.02, eff. September 1, 2009.
Tex. UTIL Code § 38.074. CRITICAL NATURAL GAS FACILITIES AND ENTITIES.
(a) 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.
(b) The rules must:
(1) ensure that the independent organization certified under Section 39.151 for the ERCOT power region and each electric utility, municipally owned utility, and electric cooperative providing service in the ERCOT power region is provided with the information required by Section 81.073 , Natural Resources Code;
(2) provide for prioritizing for load-shed purposes during an energy emergency the facilities and entities designated under Subsection (a); and
(3) provide discretion to an electric utility, municipally owned utility, or electric cooperative providing service in the ERCOT power region to prioritize power delivery and power restoration among the facilities and entities designated under Subsection (a) on the utility's or cooperative's systems, as circumstances require.
Added by Acts 2021, 87th Leg., R.S., Ch. 426 (S.B. 3 ), Sec. 16, eff. June 8, 2021.
Added by Acts 2021, 87th Leg., R.S., Ch. 931 (H.B. 3648 ), Sec. 2, eff. June 18, 2021.
Tex. UTIL Code § 38.075. WEATHER EMERGENCY PREPAREDNESS.
(a) The commission by rule shall require each electric cooperative, municipally owned utility, and transmission and distribution utility providing transmission service in the ERCOT power region to implement measures to prepare the cooperative's or utility's facilities to maintain service quality and reliability during a weather emergency according to standards adopted by the commission. In adopting the rules, the commission shall take into consideration weather predictions produced by the office of the state climatologist.
(b) The independent organization certified under Section 39.151 for the ERCOT power region shall:
(1) inspect the facilities of each electric cooperative, municipally owned utility, and transmission and distribution utility providing transmission service in the ERCOT power region for compliance with the reliability standards;
(2) provide the owner of a facility described by Subdivision (1) with a reasonable period of time in which to remedy any violation the independent organization discovers in an inspection; and
(3) report to the commission any violation that is not remedied in a reasonable period of time.
(c) The independent organization certified under Section 39.151 for the ERCOT power region shall prioritize inspections conducted under Subsection (b)(1) based on risk level, as determined by the organization.
(d) The commission shall impose an administrative penalty on an entity, including a municipally owned utility or an electric cooperative, that violates a rule adopted under this section and does not remedy that violation within a reasonable period of time.
(e) Notwithstanding any other provision of this subtitle, the commission shall allow a transmission and distribution utility to design and operate a load management program for nonresidential customers to be used where the independent organization certified under Section 39.151 for the ERCOT power region has declared a Level 2 Emergency or a higher level of emergency or has otherwise directed the transmission and distribution utility to shed load. A transmission and distribution utility implementing a load management program under this subsection shall be permitted to recover the reasonable and necessary costs of the load management program under Chapter 36 . A load management program operated under this subsection is not considered a competitive service.
Added by Acts 2021, 87th Leg., R.S., Ch. 426 (S.B. 3 ), Sec. 16, eff. June 8, 2021.
Tex. UTIL Code § 38.076. INVOLUNTARY AND VOLUNTARY LOAD SHEDDING.
(a) The commission by rule shall adopt a system to allocate load shedding among electric cooperatives, municipally owned utilities, and transmission and distribution utilities providing transmission service in the ERCOT power region during an involuntary load shedding event initiated by the independent organization certified under Section 39.151 for the region during an energy emergency.
(b) The system must provide for allocation of the load shedding obligation to each electric cooperative, municipally owned utility, and transmission and distribution utility in different seasons based on historical seasonal peak demand in the service territory of the electric cooperative, municipally owned utility, or transmission and distribution utility.
(c) The commission by rule shall:
(1) categorize types of critical load that may be given the highest priority for power restoration; and
(2) require electric cooperatives, municipally owned utilities, and transmission and distribution utilities providing transmission service in the ERCOT power region to submit to the commission and the independent organization certified under Section 39.151 for the region:
(A) customers or circuits the cooperative or utility has designated as critical load; and
(B) a plan for participating in load shedding in response to an involuntary load shedding event described by Subsection (a).
(d) The commission by rule shall require electric cooperatives and municipally owned utilities providing transmission service in the ERCOT power region to:
(1) maintain lists of customers willing to voluntarily participate in voluntary load reduction; and
(2) coordinate with municipalities, businesses, and customers that consume large amounts of electricity to encourage voluntary load reduction.
(e) This section does not abridge, enlarge, or modify the obligation of an electric cooperative, a municipally owned utility, or a transmission and distribution utility to comply with federal reliability standards.
(f) After each load shedding event, the commission may conduct an examination of the implementation of load shedding, including whether each electric cooperative, municipally owned utility, and transmission and distribution utility complied with its plan as filed with the commission under Subsection (c)(2).
Added by Acts 2021, 87th Leg., R.S., Ch. 426 (S.B. 3 ), Sec. 16, eff. June 8, 2021.
Tex. UTIL Code § 38.077. RELIABILITY EXERCISES.
(a) In this section, "critical facility" means a transmission substation and any associated control centers that, if rendered inoperable or damaged because of a physical attack, could cause widespread instability, uncontrolled separation, or cascading outages within an interconnection.
(b) The commission and the independent organization certified for the ERCOT power region under Section 39.151 shall conduct simulated or tabletop load shedding exercises with providers of electric generation service and transmission and distribution service in the ERCOT power region.
The commission shall ensure that each year at least one simulated or tabletop load shedding exercise is conducted during a summer month and one simulated or tabletop load shedding exercise is conducted during a winter month.
(c) The commission and the independent organization certified for the ERCOT power region under Section 39.151 shall conduct simulated or tabletop exercises with providers of electric generation service and transmission and distribution service in the ERCOT power region to mitigate and prepare for a threat of an attack or an actual physical attack on a critical facility. The exercises required by this subsection are in addition to the exercises required by Subsection (b) and any requirements of the North American Electric Reliability Corporation Critical Infrastructure Protection plan standards. The commission and the independent organization shall conduct the exercises under this subsection at least once every two years.
(d) A simulated or tabletop exercise conducted under Subsection (c) must identify the roles and responsibilities of the following in the event of a threat of an attack or an actual physical attack on a critical facility:
(1) transmission and distribution service providers;
(2) providers of electric generation service;
(3) law enforcement;
(4) the independent organization certified for the ERCOT power region under Section 39.151 ; and
(5) the commission.
(e) A transmission and distribution service provider is not required to disclose the specific location of the provider's critical substations to the commission or the independent organization certified for the ERCOT power region under Section 39.151 for the purposes of a simulated or tabletop exercise conducted under Subsection (c).
(f) Each provider of electric generation service and of transmission and distribution service that participates in a simulated or tabletop exercise conducted under Subsection (c) shall provide to the independent organization certified for the ERCOT power region under Section 39.151 a written attestation that the provider has coordinated with law enforcement when identifying roles and responsibilities under Subsection (d).
Added by Acts 2021, 87th Leg., R.S., Ch. 426 (S.B. 3 ), Sec. 16, eff. June 8, 2021.
Tex. UTIL Code § 38.078. CIRCUIT SEGMENTATION STUDY AND COST RECOVERY.
(a) Not later than September 15, 2023, the commission shall direct each transmission and distribution utility to perform a circuit segmentation study.
(b) A circuit segmentation study must:
(1) use an engineering analysis to examine whether and how the transmission and distribution utility's transmission and distribution systems can be segmented and sectionalized to manage and rotate outages more evenly across all customers and circuits, while maintaining the protections offered to critical facilities;
(2) include an engineering analysis of the feasibility of using sectionalization, automated reclosers, and other technology to break up the circuits that host significant numbers of critical facilities into smaller segments for outage management purposes to enable more granular and flexible outage management;
(3) identify feeders with critical facilities that, if equipped with facility-specific backup power systems and segmentation, can enhance the utility's outage management flexibility; and
(4) include an estimate of the time, capital cost, and expected improvements to load-shed management associated with the circuit segmentation study.
(c) Each transmission and distribution utility shall submit a report of the conclusions of the utility's study to the commission not later than September 1, 2024.
(d) The commission shall review each circuit segmentation study not later than March 15, 2025.
Added by Acts 2023, 88th Leg., R.S., Ch. 410 (H.B. 1500 ), Sec. 13, eff. September 1, 2023.
Tex. UTIL Code § 38.079. TRANSMISSION AND DISTRIBUTION SYSTEM RESILIENCY PLAN AND COST RECOVERY.
(a) In this section, "plan" means a transmission and distribution system resiliency plan described by Subsection (b).
(b) An electric utility may file, in a manner authorized by commission rule, a plan to enhance the resiliency of the utility's transmission and distribution system through at least one of the following methods:
(1) hardening electrical transmission and distribution facilities;
(2) modernizing electrical transmission and distribution facilities;
(3) undergrounding certain electrical distribution lines;
(4) lightning mitigation measures;
(5) flood mitigation measures;
(6) information technology;
(7) cybersecurity measures;
(8) physical security measures;
(9) vegetation management; or
(10) wildfire mitigation and response.
(c) A plan must explain the systematic approach the electric utility will use to carry out the plan during at least a three-year period.
(d) In determining whether to approve a plan filed under this section, the commission shall consider:
(1) the extent to which the plan is expected to enhance system resiliency, including whether the plan prioritizes areas of lower performance; and
(2) the estimated costs of implementing the measures proposed in the plan.
(e) The commission shall issue an order to approve, modify, or deny a plan filed under Subsection (b) and any associated rider described by Subsection (i) not later than the 180th day after the plan is filed with the commission. The commission may approve a plan only if the commission determines that approving the plan is in the public interest.
(f) For a plan approved by the commission, with or without modification, an electric utility may request a good cause exception on implementing all or some of the measures in the plan if operational needs, business needs, financial conditions, or supply chain or labor conditions dictate the exception. The commission's denial of a plan is not considered to be a finding of the prudence or imprudence of a measure or cost in the plan for the purposes of Chapter 36 or this chapter.
(g) An electric utility for which the commission has approved a plan under this section may request that the commission review an updated plan submitted by the electric utility. The updated plan must comply with any applicable commission rules and take effect on a date that is not earlier than the third anniversary of the approval date of the utility's most recently approved plan. The commission shall review and approve, modify, or deny the updated plan in the manner provided by Subsections (d), (e), and (f).
(h) An electric utility's implementation of a plan approved under this section may be reviewed for the purposes of Chapter 36 or this chapter. If the commission determines that the costs to implement an approved plan were imprudently incurred or otherwise unreasonable, those costs are subject to disallowance.
(i) Notwithstanding any other law, an electric utility may file with a plan an application for a rider to recover the electric utility's distribution investment that is made to implement a plan and is used and useful to the electric utility in providing service to the public. The electric utility may file the application before the electric utility places into service the distribution investment to implement an approved plan. The commission may approve the rider application before the electric utility places into service the distribution investment to implement an approved plan. The commission may not approve a rider that would allow an electric utility to begin recovering the distribution investment before the utility begins to use the investment to provide service to the public. If the commission approves or modifies the plan, the commission shall determine the appropriate terms of the rider in the approval order. The commission shall adopt a procedure for reconciliation of an electric utility's distribution-related costs to implement an approved plan.
(j) As part of a review described by Subsection (g), the commission shall reconcile the rider authorized under Subsection (i) to determine the electric utility's reasonably and prudently incurred plan costs.
(k) If an electric utility that files a plan with the commission does not apply for a rider under Subsection (i), after commission review, the utility may defer all or a portion of the distribution-related costs relating to the implementation of the plan for future recovery as a regulatory asset, including depreciation expense and carrying costs at the utility's weighted average cost of capital established in the commission's final order in the utility's most recent base rate proceeding in a manner consistent with Chapter 36 , and use commission authorized cost recovery alternatives under Sections 36.209 and 36.210 or another general rate proceeding.
(l) Plan costs considered by the commission to be reasonable and prudent may include only incremental costs that are not already being recovered through the electric utility's base rates or any other rate rider and must be allocated to customer classes pursuant to the rate design most recently approved by the commission.
Added by Acts 2023, 88th Leg., R.S., Ch. 836 (H.B. 2555 ), Sec. 2, eff. June 13, 2023.
Redesignated from Utilities Code, Section 38.078 by Acts 2025, 89th Leg., R.S., Ch. 204 (H.B. 1620 ), Sec. 22.001(67), eff. September 1, 2025.
Tex. UTIL Code § 38.080. WILDFIRE MITIGATION PLAN.
(a) In this section:
(1) "Division" means the Texas Division of Emergency Management.
(2) "First responder" has the meaning assigned by Section 418.251 , Government Code.
(3) "Plan" means a wildfire mitigation plan described by Subsection (b).
(4) "Wildfire risk area" means an area determined by the division or an electric utility, municipally owned utility, or electric cooperative to be at an elevated risk for wildfire.
(b) An electric utility, municipally owned utility, or electric cooperative that owns a transmission or distribution facility in a wildfire risk area shall file with the commission a wildfire mitigation plan that includes the following:
(1) a description of each area to which the utility or cooperative provides transmission or distribution service that is in a wildfire risk area and the utility's or cooperative's process for periodically inspecting the utility's or cooperative's transmission and distribution facilities in those areas;
(2) a detailed plan for vegetation management in the wildfire risk area;
(3) a detailed operations plan for reducing the likelihood of wildfire ignition from the utility's or cooperative's facilities and for responding to a wildfire;
(4) a description of the procedures the utility or cooperative intends to use to restore the utility's or cooperative's system during and after a wildfire event, including contact information for the utility or cooperative that may be used for coordination with the division and first responders;
(5) the utility's or cooperative's community outreach and public awareness plan regarding wildfire risks and actual wildfires affecting the utility's or cooperative's service territory or system, including a specific communications plan for responding to a wildfire event;
(6) any infrastructure report, maintenance report, or transmission or distribution pole maintenance plan required by the commission;
(7) an analysis of the wildfire mitigation plan prepared by an independent expert in fire risk mitigation;
(8) a description of procedures for de-energizing power lines and disabling reclosers to mitigate potential wildfires or implement a public safety power shut-off plan;
(9) a description of the procedures and standards that the utility or cooperative will use to inspect and operate the utility's or cooperative's infrastructure to mitigate the risk of wildfires;
(10) a description of how the utility or cooperative will monitor compliance with the wildfire mitigation plan; and
(11) any other information the commission may require.
(c) The commission shall issue an order not later than the 180th day after a plan is filed with the commission that:
(1) approves the plan if the commission finds that approval is in the public interest; or
(2) modifies or rejects the plan as necessary to be consistent with the public interest.
(d) An electric utility, municipally owned utility, or electric cooperative that does not implement a plan approved under this section is subject to an administrative penalty as provided by Chapter 15 .
(e) The commission may accept in place of the information required under Subsection (b) any information required under other law that is substantially similar to the information required under that subsection.
Added by Acts 2025, 89th Leg., R.S., Ch. 1072 (H.B. 145 ), Sec. 2, eff. June 20, 2025.
Tex. UTIL Code § 38.081. EVIDENCE IN ACTIONS FOR DAMAGES CAUSED BY WILDFIRE.
(a) An electric utility, municipally owned utility, or electric cooperative that submits and obtains commission approval for a wildfire mitigation plan under Section 38.080 may use the plan as evidence in an action brought against the utility or cooperative for damages resulting from a wildfire ignited or propagated by the utility's or cooperative's facility.
(b) Subject to any applicable tariff provision, in an action for damages resulting from a wildfire ignited or propagated by an electric utility's, municipally owned utility's, or electric cooperative's facility, the utility or cooperative is not liable for damages resulting from the wildfire if the trier of fact in the action finds that the utility or cooperative:
(1) submitted, obtained commission approval for, and implemented a wildfire mitigation plan under Section 38.080 ;
(2) was in compliance with relevant measures of the utility's or cooperative's wildfire mitigation plan with respect to the specific equipment found to have ignited or propagated the wildfire; and
(3) did not cause the wildfire intentionally, recklessly, or with negligence.
(c) Subsections (a) and (b) do not apply to an electric utility, municipally owned utility, or electric cooperative that:
(1) does not file a wildfire mitigation plan under Section 38.080 ; or
(2) files a plan that is rejected by the commission.
(d) Notwithstanding any other provision of this section, this section does not affect an express contractual right of a person or entity involving a communications facility or the shared use of an electric facility or pole attachment.
Added by Acts 2025, 89th Leg., R.S., Ch. 1072 (H.B. 145 ), Sec. 2, eff. June 20, 2025.
SUBCHAPTER E. INFRASTRUCTURE IMPROVEMENT AND MAINTENANCE
Tex. UTIL Code § 38.101. REPORT ON INFRASTRUCTURE IMPROVEMENT AND MAINTENANCE.
(a) Not later than May 1 of each year, each electric utility shall submit to the commission a report describing the utility's activities related to:
(1) identifying areas that are susceptible to damage during severe weather and hardening transmission and distribution facilities in those areas; and
(2) vegetation management.
(b) Each electric utility shall include in a report required under Subsection (a) a summary of the utility's activities related to preparing for emergency operations.
Added by Acts 2009, 81st Leg., R.S., Ch. 1280 (H.B. 1831 ), Sec. 2.03, eff. September 1, 2009.
Tex. UTIL Code § 38.102. REPORTS ON SAFETY PROCESSES AND INSPECTIONS.
(a) Each electric utility, municipally owned utility, and electric cooperative that owns or operates overhead transmission or distribution assets shall submit to the commission a report that includes:
(1) a summary description of hazard recognition training documents provided by the utility or electric cooperative to its employees related to overhead transmission and distribution facilities; and
(2) a summary description of training programs provided to employees by the utility or electric cooperative related to the National Electrical Safety Code for the construction of electric transmission and distribution lines.
(b) An electric utility, municipally owned utility, or electric cooperative shall submit an updated report not later than the 30th day after the date the utility or electric cooperative finalizes a material change to a document or program included in a report submitted under Subsection (a).
(c) Not later than May 1 every five years, each electric utility, municipally owned utility, and electric cooperative that owns or operates overhead transmission facilities greater than 60 kilovolts shall submit to the commission a report for the preceding five-year period ending on December 31 of the preceding calendar year that includes:
(1) the percentage of overhead transmission facilities greater than 60 kilovolts inspected for compliance with the National Electrical Safety Code relating to vertical clearance in the reporting period; and
(2) the percentage of the overhead transmission facilities greater than 60 kilovolts anticipated to be inspected for compliance with the National Electrical Safety Code relating to vertical clearance during the five-year period beginning on January 1 of the year in which the report is submitted.
(d) Subject to Subsection (f), not later than May 1 of each year, each electric utility, municipally owned utility, or electric cooperative that owns or operates overhead transmission facilities greater than 60 kilovolts shall submit to the commission a report on the overhead transmission facilities for the preceding calendar year that includes information regarding:
(1) the number of identified occurrences of noncompliance with Section 38.004 regarding the vertical clearance requirements of the National Electrical Safety Code for overhead transmission facilities;
(2) whether the utility or electric cooperative has actual knowledge that any portion of the utility's or electric cooperative's transmission system is not in compliance with Section 38.004 regarding the vertical clearance requirements of the National Electrical Safety Code; and
(3) whether the utility or electric cooperative has actual knowledge of any violations of easement agreements with the United States Army Corps of Engineers relating to Section 38.004 regarding the vertical clearance requirements of the National Electrical Safety Code for overhead transmission facilities.
(e) Subject to Subsection (f), not later than May 1 of each year, each electric utility, municipally owned utility, or electric cooperative that owns or operates overhead transmission facilities greater than 60 kilovolts or distribution facilities greater than 1 kilovolt shall submit to the commission a report for the preceding calendar year that includes:
(1) the number of fatalities or injuries of individuals other than employees, contractors, or other persons qualified to work in proximity to overhead high voltage lines involving transmission or distribution assets related to noncompliance with the requirements of Section 38.004 ; and
(2) a description of corrective actions taken or planned to prevent the reoccurrence of fatalities or injuries described by Subdivision (1).
(f) Violations resulting from, and incidents, fatalities, or injuries attributable to a violation resulting from, a natural disaster, weather event, or man-made act or force outside of a utility's or electric cooperative's control are not required to be included in the portions of the reports required under Subsections (d) and (e).
(g) Not later than September 1, each year the commission shall make the reports publicly available on the commission's Internet website.
(h) A report, and any required information contained in a report, made on an incident or violation under this section is not admissible in a civil or criminal proceeding against the electric utility, municipally owned utility, or electric cooperative, or the utility's or electric cooperative's employees, directors, or officers. The commission may otherwise take enforcement actions under the commission's authority.
Added by Acts 2019, 86th Leg., R.S., Ch. 1320 (H.B. 4150 ), Sec. 5, eff. September 1, 2019.
Tex. UTIL Code § 38.103. DISTRIBUTION POLE PLAN.
(a) Each electric cooperative, electric utility, and municipally owned utility that distributes electric energy to the public shall submit to the commission a plan for the management and inspection of distribution poles the cooperative or utility owns in the cooperative's or utility's distribution system.
(b) Each plan submitted under Subsection (a) must include:
(1) a statement of the plan's scope and objectives for ensuring public safety through the effective management, inspection, maintenance, and repair of distribution poles;
(2) the roles and responsibilities of individuals responsible for overseeing and executing the plan;
(3) processes for training and certifying personnel, including third-party vendors, who inspect distribution poles;
(4) an estimated timeline for completing inspections and remedial action required for any pole identified as unreliable, unsafe, or needing repair;
(5) processes for documenting and responding to a report or complaint made by a landowner regarding the condition or repair of a distribution pole;
(6) for a plan submitted by an electric utility, the estimated cost of implementing the plan; and
(7) a description of the cooperative's or utility's methods to monitor compliance with the plan.
(c) Not later than May 1 of each year, an entity to which this section applies shall submit an update to the commission detailing the entity's compliance with the plan's objectives, the costs of implementing the plan to date, and the results of the entity's inspection of distribution poles, including the number of poles inspected and any remediation or replacement action taken. An electric utility may submit the update in a report required under Section 38.101 .
(d) The commission shall review each plan and update submitted under this section to determine whether the entity that submitted the plan or update is in compliance with the plan's objectives described by Subsection (b)(1) and notify the entity whether or not the entity is in compliance with those objectives.
(e) The commission may accept in place of the information required under this section any information required under other law that is substantially similar to the information required under this section.
Added by Acts 2025, 89th Leg., R.S., Ch. 919 (H.B. 144 ), Sec. 2, eff. June 20, 2025.
SUBCHAPTER F. TEXAS ELECTRICITY SUPPLY CHAIN SECURITY AND MAPPING COMMITTEE
Tex. UTIL Code § 38.201. TEXAS ELECTRICITY SUPPLY CHAIN SECURITY AND MAPPING COMMITTEE.
(a) In this subchapter, "electricity supply chain" means:
(1) facilities and methods used for producing, treating, processing, pressurizing, storing, or transporting natural gas for delivery to electric generation facilities;
(2) critical infrastructure necessary to maintain electricity service; and
(3) roads necessary to access facilities in the electricity supply chain.
(a-1) A reference in this subchapter to the "electricity supply chain" includes water and wastewater treatment plants.
(b) The Texas Electricity Supply Chain Security and Mapping Committee is established to:
(1) map this state's electricity supply chain;
(2) identify critical infrastructure sources in the electricity supply chain;
(3) establish best practices to prepare facilities in the electricity supply chain to maintain service in an extreme weather event and recommend oversight and compliance standards for those facilities; and
(4) designate priority service needs to prepare for, respond to, and recover from an extreme weather event.
(c) The committee is composed of:
(1) the executive director of the commission;
(2) the executive director of the Railroad Commission of Texas;
(3) the president and the chief executive officer of the independent organization certified under Section 39.151 for the ERCOT power region;
(4) the chief of the Texas Division of Emergency Management; and
(5) the executive director of the Texas Department of Transportation.
(d) Each member of the committee may designate a personal representative from the member's organization to represent the member on the committee. A member is responsible for the acts and omissions of the designee related to the designee's representation on the committee.
(e) The executive director of the commission serves as the chair of the committee. The executive director of the Railroad Commission of Texas serves as vice chair of the committee.
Added by Acts 2021, 87th Leg., R.S., Ch. 426 (S.B. 3 ), Sec. 17, eff. June 8, 2021.
Tex. UTIL Code § 38.202. ADMINISTRATION.
(a) The committee shall meet at least once each calendar quarter at a time determined by the committee and at the call of the chair.
(b) A member who is an ex officio member from a state agency shall be reimbursed for actual and necessary expenses in carrying out committee responsibilities from money appropriated for that purpose in the agency's budget. Other members of the committee may receive reimbursement for actual and necessary expenses in carrying out committee responsibilities from money appropriated for that purpose.
(c) The commission, the Railroad Commission of Texas, the Texas Division of Emergency Management, and the Texas Department of Transportation shall provide staff as necessary to assist the committee in carrying out the committee's duties and responsibilities.
(d) The independent organization certified under Section 39.151 for the ERCOT power region shall provide staff as necessary to assist the committee in carrying out the committee's duties and responsibilities.
(e) Except as otherwise provided by this subchapter, the committee is not subject to Chapters 2001 , 551 , and 552 , Government Code.
(f) Information written, produced, collected, assembled, or maintained under law or in connection with the transaction of official business by the committee or an officer or employee of the committee is subject to Section 552.008 , Government Code. This subsection does not apply to the physical locations of critical facilities, maps created under this subchapter, or proprietary information created or gathered during the mapping process.
Added by Acts 2021, 87th Leg., R.S., Ch. 426 (S.B. 3 ), Sec. 17, eff. June 8, 2021.
Tex. UTIL Code § 38.203. POWERS AND DUTIES OF COMMITTEE.
(a) The committee shall:
(1) map the state's electricity supply chain in order to designate priority electricity service needs during extreme weather events;
(2) identify and designate the sources in the electricity supply chain necessary to operate critical infrastructure, as defined by Section 421.001 , Government Code;
(3) develop a communication system between critical infrastructure sources, the commission, and the independent organization certified under Section 39.151 for the ERCOT power region to ensure that electricity and natural gas supplies in the electricity supply chain are prioritized to those sources during an extreme weather event; and
(4) establish best practices to prepare facilities in the electricity supply chain to maintain service in an extreme weather event and recommend oversight and compliance standards for those facilities.
(b) The committee shall update the electricity supply chain map at least once each year.
(c) The commission shall:
(1) create and maintain a database identifying critical infrastructure sources with priority electricity needs to be used during an extreme weather event; and
(2) update the database at least once each year.
(d) The information maintained in the database is confidential under Section 418.181 , Government Code, and not subject to disclosure under Chapter 552 , Government Code.
(e) The committee shall provide the Texas Energy Reliability Council with access to the electricity supply chain map.
(f) On request, the committee shall provide view-only access to the electricity supply chain map to:
(1) an electric utility, a transmission and distribution utility, an electric cooperative, or a municipally owned utility;
(2) an operator of a gas supply chain facility, as defined by Section 86.044 , Natural Resources Code; or
(3) an operator of a gas pipeline facility described by Section 121.2015 .
(g) Access to the electricity supply chain map by an entity described by Subsection (f)(1) is limited to the critical natural gas facilities on the map that are located in the requesting entity's service area.
(h) The committee may not provide an entity described by Subsection (f)(1) with access to the electricity supply chain map unless the entity has complied with Section 37.157 .
(i) Access to the electricity supply chain map by an operator described by Subsections (f)(2) and (3) is limited to the critical natural gas facilities operated by the requesting operator.
Added by Acts 2021, 87th Leg., R.S., Ch. 426 (S.B. 3 ), Sec. 17, eff. June 8, 2021.
Tex. UTIL Code § 38.204. MAPPING REPORT.
(a) Not later than January 1, 2022, the committee shall submit a report to the governor, the lieutenant governor, the speaker of the house of representatives, the legislature, and the Texas Energy Reliability Council on the activities and findings of the committee. The report must:
(1) provide an overview of the committee's findings regarding mapping the electricity supply chain and identifying sources necessary to operate critical infrastructure;
(2) recommend a clear and thorough communication system for the commission, the Railroad Commission of Texas, the Texas Division of Emergency Management, and the independent organization certified under Section 39.151 for the ERCOT power region and critical infrastructure sources in this state to ensure that electricity supply is prioritized to those sources during extreme weather events; and
(3) include a list of the established best practices and recommended oversight and compliance standards adopted under Section 38.203 (a)(4).
(b) The report is public information except for portions considered confidential under Chapter 552 , Government Code, or other state or federal law.
Added by Acts 2021, 87th Leg., R.S., Ch. 426 (S.B. 3 ), Sec. 17, eff. June 8, 2021.
Tex. UTIL Code § 38.0725. LIST OF PRIORITY FACILITIES.
(a) In this section, "priority facility" means:
(1) a facility listed in Section 38.072 (b); or
(2) a facility for which electric service is considered crucial for the protection or maintenance of public safety, including:
(A) a hospital;
(B) a police station;
(C) a fire station;
(D) a critical water or wastewater facility; and
(E) a confinement facility operated by or under a contract with any division of the Texas Department of Criminal Justice.
(b) An electric utility shall maintain a list of priority facilities in the utility's retail service area that includes the following information:
(1) the name of each priority facility;
(2) the type of each priority facility; and
(3) the address of each priority facility.
(c) An electric utility shall provide on the utility's Internet website a mechanism for a facility to request that the utility add the facility to the priority facility list. The electric utility shall add the requested facility to the list only if the facility is a priority facility.
(d) On request from a facility, an electric utility shall disclose to the facility not later than the 14th day after the date the utility receives the request whether the facility is on the priority facility list.
(e) Notwithstanding any other law, on a declaration of a natural disaster or other emergency by the governor affecting the service area of the electric utility, the utility shall provide the list of priority facilities to the Texas Division of Emergency Management.
(f) A priority facility list submitted to the Texas Division of Emergency Management under this section is confidential and not subject to disclosure under Chapter 552 , Government Code. The commission may establish additional processes for protecting consumer information under this section as the commission determines necessary.
Added by Acts 2025, 89th Leg., R.S., Ch. 562 (H.B. 1584 ), Sec. 1, eff. September 1, 2025.