TITLE 16. ECONOMIC REGULATION

PART 2. PUBLIC UTILITY COMMISSION OF TEXAS

CHAPTER 25. SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS

The Public Utility Commission of Texas (commission) proposes amendments to §25.5, relating to definitions; §25.130, relating to advanced metering; and §25.133, relating to non-standard metering service. The amendments to §25.130 and §25.133 conform the rules to Senate Bill 1145, 85th Legislature, Regular Session, which amended Public Utility Regulatory Act (PURA) §39.452, and to the following bills from the 86th Legislature, Regular Session: House Bill 853, which amended PURA §39.5521, House Bill 986, which amended PURA §39.402, and House Bill 1595, which amended PURA §39.5021. These bills encourage deployment of advanced metering and meter information networks by extending the applicability of PURA §39.107(h) and (k) to electric utilities providing service in areas outside the Electric Reliability Council of Texas (ERCOT).

The amendments also remove the requirement for an electric utility to offer the home area network (HAN) feature due to limited customer interest and set minimum capabilities for on-demand reads of a customer's advanced meter. In addition, the amendments clarify and define rule language; remove rule language relating to an electric utility's limitation of liability because these provisions are addressed in the electric utility's tariff; and remove obsolete and other unnecessary rule language.

Growth Impact Statement

The agency provides the following governmental growth impact statement for the proposed rules, as required by Texas Government Code §2001.0221. The agency has determined that for each year of the first five years that the proposed amendments are in effect, the following statements will apply:

(1) the proposed amendments will not create a government program and will not eliminate a government program;

(2) implementation of the proposed amendments will not require the creation of new employee positions and will not require the elimination of existing employee positions;

(3) implementation of the proposed amendments will not require an increase and will not require a decrease in future legislative appropriations to the agency;

(4) the proposed amendments will not require an increase and will not require a decrease in fees paid to the agency;

(5) the proposed amendments will not create a new regulation;

(6) the proposed amendments will expand §25.130 by setting a requirement for the minimum provision of on-demand reads an electric utility must be capable of providing;

(7) the proposed amendments will conform §25.130 and §25.133 to the legislation described in the first paragraph by expressly applying §25.130 and §25.133 to electric utilities outside the ERCOT power region; and

(8) the proposed rules will not affect this state's economy.

Fiscal Impact on Small and Micro-Businesses and Rural Communities

There is no adverse economic effect anticipated for small businesses, micro-businesses, or rural communities as a result of implementing the proposed amendments. Accordingly, no economic impact statement or regulatory flexibility analysis is required under Texas Government Code §2006.002(c).

Takings Impact Analysis

The commission has determined that the proposed amendments will not be a taking of private property as defined in chapter 2007 of the Texas Government Code.

Fiscal Impact on State and Local Government

Therese Harris, Director of Infrastructure Analysis and Mapping, has determined that for the first five-year period the proposed amendments are in effect, there will be no fiscal implications for the state or for units of local government under Texas Government Code §2001.024(a)(4) as a result of enforcing or administering the amendments.

Public Benefits

Therese Harris has also determined that for each year of the first five years the proposed amendments are in effect, the anticipated public benefits expected as a result of the adoption of the proposed amendments will be conforming §25.130 and §25.133 to the legislation described in the first paragraph, setting minimum capabilities for on-demand reads of a customer's advanced meter an electric utility must provide, and removing unnecessary language from the rules.

There will be no probable economic cost to persons required to comply with the proposed amendments.

Local Employment Impact Statement

For each year of the first five years the proposed amendments are in effect there should be no effect on a local economy; therefore, no local employment impact statement is required under Texas Government Code §2001.022.

Costs to Regulated Persons

Texas Government Code §2001.0045(b) does not apply to this rulemaking because the Public Utility Commission is expressly excluded under subsection §2001.0045(c)(7).

Public Hearing

The commission staff will conduct a public hearing on this rulemaking, if requested in accordance with Texas Government Code §2001.029, at the commission's offices located in the William B. Travis Building, 1701 North Congress Avenue, Austin, Texas 78701 on January 17, 2020 at 9:00 a.m. The request for a public hearing must be received by January 13, 2019. If no request for a public hearing is received and the commission staff cancels the hearing, it will make a filing in this project prior to the scheduled date for the hearing.

Public Comments

Initial comments on the proposed amendments may be submitted to the commission's filing clerk at 1701 North Congress Avenue, P.O. Box 13326, Austin, TX 78711-3326 by January 13, 2019. Reply comments may be submitted by January 23, 2020. Comments should be organized in a manner consistent with the organization of the proposed rules. The commission invites specific comments regarding the costs associated with, and benefits that will be gained by, implementation of the proposed rules. The commission will consider the costs and benefits in deciding whether to modify the proposed rules on adoption. All comments should refer to project number 48525. Sixteen copies of comments are required to be filed under §22.71(c) of 16 Texas Administrative Code.

SUBCHAPTER A. GENERAL PROVISIONS

16 TAC §25.5

Statutory Authority

These amendments are proposed under §14.001 of the Public Utility Regulatory Act, Tex. Util. Code Ann. (West 2016 and Supp. 2017) (PURA), which provides the commission with 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; PURA §14.002, which provides the commission with the authority to make and enforce rules reasonably required in the exercise of its powers and jurisdiction; PURA §36.003, which grants the commission the authority to ensure that each rate be just and reasonable and not unreasonably preferential, prejudicial, or discriminatory; PURA §39.107, which grants the commission the authority to approve electric utility surcharges for the deployment of advanced meters, adopt rules relating to the transfer of customer data, and approve non-discriminatory rates for metering service; and PURA §§39.402, 39.452, 39.5021 and 39.5521, which permit the electric utilities outside of the ERCOT region that elect to deploy advanced meters and meter information networks to recover reasonable and necessary deployment costs and subjects the deployment to commission rules adopted under PURA §39.107(h) and (k).

Cross reference to statutes: Public Utility Regulatory Act §§14.001, 14.002, 36.003, 39.107, 39.402, 39.452, 39.5021 and 39.5521.

§25.5.Definitions.

The following words and terms[,] when used in this chapter[, shall] have the following meanings, unless the context clearly indicates otherwise:

(1) - (114) (No change.)

(115) Retail electric provider (REP) of record--The REP assigned to the electric service identifier (ESI ID) in ERCOT's database. There can be no more than one REP of record assigned to an ESI ID at any specific point in time.

(116) [(115)] Retail stranded costs--That part of net stranded cost associated with the provision of retail service.

(117) [(116)] Retrofit--The installation of control technology on an electric generating facility to reduce the emissions of nitrogen oxide, sulfur dioxide, or both.

(118) [(117)] River authority--A conservation and reclamation district created pursuant to the Texas Constitution, Article 16, Section 59, including any nonprofit corporation created by such a district pursuant to the Texas Water Code, Chapter 152, that is an electric utility.

(119) [(118)] Rule--A statement of general applicability that implements, interprets, or prescribes law or policy, or describes the procedure or practice requirements of the commission. The term includes the amendment or repeal of a prior rule, but does not include statements concerning only the internal management or organization of the commission and not affecting private rights or procedures.

(120) [(119)] Separately metered--Metered by an individual meter that is used to measure electric energy consumption by a retail customer and for which the customer is directly billed by a utility, retail electric provider, electric cooperative, or municipally owned utility.

(121) [(120)] Service--Has its broadest and most inclusive meaning. The term includes any act performed, anything supplied, and any facilities used or supplied by an electric utility in the performance of its duties under the Public Utility Regulatory Act to its patrons, employees, other public utilities or electric utilities, an electric cooperative, and the public. The term also includes the interchange of facilities between two or more public utilities or electric utilities.

(122) [(121)] Spanish-speaking person--A person who speaks any dialect of the Spanish language exclusively or as their primary language.

(123) [(122)] Standard meter--The minimum metering device necessary to obtain the billing determinants required by the transmission and distribution utility's tariff schedule to determine an end-use customer's charges for transmission and distribution service.

(124) [(123)] Stranded cost--The positive excess of the net book value of generation assets over the market value of the assets, taking into account all of the electric utility's generation assets, any above-market purchased power costs, and any deferred debit related to a utility's discontinuance of the application of Statement of Financial Accounting Standards Number 71 ("Accounting for the Effect of Certain Types of Regulation") for generation-related assets if required by the provisions of the Public Utility Regulatory Act (PURA), Chapter 39. For purposes of PURA §39.262, book value shall be established as of December 31, 2001, or the date a market value is established through a market valuation method under PURA §39.262(h), whichever is earlier, and shall include stranded costs incurred under PURA §39.263.

(125) [(124)] Submetering--Metering of electricity consumption on the customer side of the point at which the electric utility meters electricity consumption for billing purposes.

(126) [(125)] Summer net dependable capability--The net capability of a generating unit in megawatts (MW) for daily planning and operational purposes during the summer peak season, as determined in accordance with requirements of the reliability council or independent organization in which the unit operates.

(127) [(126)] Supply-side resource--A resource, including a storage device, that provides electricity from fuels or renewable resources.

(128) [(127)] System emergency--A condition on a utility's system that is likely to result in imminent significant disruption of service to customers or is imminently likely to endanger life or property.

(129) [(128)] Tariff--The schedule of a utility, municipally-owned utility, or electric cooperative containing all rates and charges stated separately by type of service, the rules and regulations of the utility, and any contracts that affect rates, charges, terms or conditions of service.

(130) [(129)] Termination of service--The cancellation or expiration of a sales agreement or contract by a retail electric provider by notification to the customer and the registration agent.

(131) [(130)] Tenant--A person who is entitled to occupy a dwelling unit to the exclusion of others and who is obligated to pay for the occupancy under a written or oral rental agreement.

(132) [(131)] Test year--The most recent 12 months for which operating data for an electric utility, electric cooperative, or municipally-owned utility are available and shall commence with a calendar quarter or a fiscal year quarter.

(133) [(132)] Texas jurisdictional installed generation capacity--The amount of an affiliated power generation company's installed generation capacity properly allocable to the Texas jurisdiction. Such allocation shall be calculated pursuant to an existing commission-approved allocation study, or other such commission-approved methodology, and may be adjusted as approved by the commission to reflect the effects of divestiture or the installation of new generation facilities.

(134) [(133)] Transition bonds--Bonds, debentures, notes, certificates, of participation or of beneficial interest, or other evidences of indebtedness or ownership that are issued by an electric utility, its successors, or an assignee under a financing order, that have a term not longer than 15 years, and that are secured or payable from transition property.

(135) [(134)] Transition charges--Non-bypassable amounts to be charged for the use or availability of electric services, approved by the commission under a financing order to recover qualified costs, that shall be collected by an electric utility, its successors, an assignee, or other collection agents as provided for in a financing order.

(136) [(135)] Transmission and distribution business unit (TDBU)--The business unit of a municipally owned utility/electric cooperative, whether structurally unbundled as a separate legal entity or functionally unbundled as a division, that owns or operates for compensation in this state equipment or facilities to transmit or distribute electricity at retail, except for facilities necessary to interconnect a generation facility with the transmission or distribution network, a facility not dedicated to public use, or a facility otherwise excluded from the definition of electric utility in a qualifying power region certified under the Public Utility Regulatory Act §39.152. Transmission and distribution business unit does not include a municipally owned utility/electric cooperative that owns, controls, or is an affiliate of the transmission and distribution business unit if the transmission and distribution business unit is organized as a separate corporation or other legally distinct entity. Except as specifically authorized by statute, a transmission and distribution business unit shall not provide competitive energy-related activities.

(137) [(136)] Transmission and distribution utility (TDU)--A person or river authority that owns, or operates for compensation in this state equipment or facilities to transmit or distribute electricity, except for facilities necessary to interconnect a generation facility with the transmission or distribution network, a facility not dedicated to public use, or a facility otherwise excluded from the definition of "electric utility", in a qualifying power region certified under the Public Utility Regulatory Act (PURA) §39.152, but does not include a municipally owned utility or an electric cooperative. The TDU may be a single utility or may be separate transmission and distribution utilities.

(138) [(137)] Transmission line--A power line that is operated at 60 kilovolts (kV) or above, when measured phase-to-phase.

(139) [(138)] Transmission service--Service that allows a transmission service customer to use the transmission and distribution facilities of electric utilities, electric cooperatives and municipally owned utilities to efficiently and economically utilize generation resources to reliably serve its loads and to deliver power to another transmission service customer. Includes construction or enlargement of facilities, transmission over distribution facilities, control area services, scheduling resources, regulation services, reactive power support, voltage control, provision of operating reserves, and any other associated electrical service the commission determines appropriate, except that, on and after the implementation of customer choice in any portion of the Electric Reliability Council of Texas (ERCOT) region, control area services, scheduling resources, regulation services, provision of operating reserves, and reactive power support, voltage control and other services provided by generation resources are not "transmission service".

(140) [(139)] Transmission service customer--A transmission service provider, distribution service provider, river authority, municipally-owned utility, electric cooperative, power generation company, retail electric provider, federal power marketing agency, exempt wholesale generator, qualifying facility, power marketer, or other person whom the commission has determined to be eligible to be a transmission service customer. A retail customer, as defined in this section, may not be a transmission service customer.

(141) [(140)] Transmission service provider (TSP)--An electric utility, municipally-owned utility, or electric cooperative that owns or operates facilities used for the transmission of electricity.

(142) [(141)] Transmission system--The transmission facilities at or above 60 kilovolts (kV) owned, controlled, operated, or supported by a transmission service provider or transmission service customer that are used to provide transmission service.

The agency certifies that legal counsel has reviewed the proposal and found it to be within the state agency's legal authority to adopt.

Filed with the Office of the Secretary of State on November 15, 2019.

TRD-201904267

Andrea Gonzalez

Rules Coordinator

Public Utility Commission of Texas

Earliest possible date of adoption: December 29, 2019

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


SUBCHAPTER F. METERING

16 TAC §25.130, §25.133

Statutory Authority

These amendments are proposed under §14.001 of the Public Utility Regulatory Act, Tex. Util. Code Ann. (West 2016 and Supp. 2017) (PURA), which provides the commission with 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; PURA §14.002, which provides the commission with the authority to make and enforce rules reasonably required in the exercise of its powers and jurisdiction; PURA §36.003, which grants the commission the authority to ensure that each rate be just and reasonable and not unreasonably preferential, prejudicial, or discriminatory; PURA §39.107, which grants the commission the authority to approve electric utility surcharges for the deployment of advanced meters, adopt rules relating to the transfer of customer data, and approve non-discriminatory rates for metering service; and PURA §§39.402, 39.452, 39.5021 and 39.5521, which permit the electric utilities outside of the ERCOT region that elect to deploy advanced meters and meter information networks to recover reasonable and necessary deployment costs and subjects the deployment to commission rules adopted under PURA §39.107(h) and (k).

Cross reference to statutes: Public Utility Regulatory Act §§14.001, 14.002, 36.003, 39.107, 39.402, 39.452, 39.5021 and 39.5521.

§25.130.Advanced Metering.

(a) Purpose. This section addresses the deployment, operation, and cost recovery for advanced metering systems. [The purposes of this section are to authorize electric utilities to assess a nonbypassable surcharge to use to recover costs incurred for deploying advanced metering systems that are consistent with this section; increase the reliability of the regional electrical network; encourage dynamic pricing and demand response; improve the deployment and operation of generation, transmission and distribution assets, and provide more choices for electric customers.]

(b) Applicability. This section is applicable to all electric utilities, including transmission and distribution utilities. Any requirement applicable to an electric utility in this section that relates to retail electric providers (REPs) or REPs of record is applicable only to electric utilities operating in areas open to customer choice.[, other than an electric utility that, pursuant to Public Utility Regulatory Act (PURA) §39.452(d)(1), is not subject to PURA §39.107; and to the Electric Reliability Council of Texas (ERCOT).]

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

(1) Advanced meter--Any new or appropriately retrofitted meter that functions as part of an advanced metering system and that has the minimum system features specified in this section, except to the extent the electric utility has obtained a waiver of a minimum feature from the commission.

(2) - (3) (No change.)

[(4) Dynamic Pricing--Retail pricing for electricity consumed that varies during different times of the day.]

(4) [(5)] Enhanced [Non-standard] advanced meter--A meter that contains features and functions in addition to the AMS features in the deployment plan approved by the commission.

(5) Web portal--The website made available on the internet in compliance with this section by an electric utility or a group of electric utilities through which read-only access to AMS usage data is made available to the customer, the customer's REP of record, and entities authorized by the customer.

(d) Deployment and use of advanced meters.

(1) Deployment and use of an AMS by an electric utility is voluntary unless otherwise ordered by the commission. However, deployment and use of an AMS for which an electric utility seeks a surcharge for cost recovery must [shall] be consistent with this section, except to the extent that the electric utility has obtained a waiver from the commission.

(2) Six months prior to initiating deployment of an AMS or as soon as practicable after the effective date of this section, whichever is later, an electric utility that intends to deploy an AMS must [shall] file a statement [Statement] of AMS functionality [Functionality], and either a notice [Notice] of deployment [Deployment] or a request [Request] for approval [Approval] of deployment [Deployment]. An electric utility may request a surcharge under [pursuant to] subsection (k) of this section in combination with a notice [Notice] of deployment [Deployment] or a request [Request] for approval [Approval] of deployment [Deployment], or separately. A proceeding that includes a request to establish or amend a surcharge will [shall] be a ratemaking proceeding and a proceeding involving only a request [Request ] for approval [Approval] of deployment will [Deployment shall] not be a ratemaking proceeding.

(3) The statement [Statement] of AMS functionality must [Functionality shall]:

(A) state whether the AMS meets the requirements specified in subsection (g) of this section and what additional features, if any, it will have [perform];

(B) describe any variances between technologies and meter functions within the electric utility's [its] service territory; and

(C) state whether the electric utility intends to seek a waiver of any provision of this section in its request for surcharge.

(4) A deployment plan must [Deployment Plan shall] contain the following information:

(A) Type of meter technology;

(B) Type and description of communications equipment in the AMS;

(C) Systems that will be developed during the deployment period;

(D) A timeline for the web portal development or integration into an existing web portal;

(E) A deployment schedule by specific area (geographic information); and

[(F) When postings of monthly status reports on the electric utility's website will commence; and]

(F) [(G)] A schedule for deployment of web portal functionalities.

(5) An electric utility must [shall] file with the deployment plan [Deployment Plan], testimony and other supporting information, including estimated costs for all AMS components, estimated net operating cost savings expected in connection with implementing the deployment plan [Deployment Plan], and the contracts for equipment and services associated with the deployment plan [Deployment Plan], that prove the reasonableness of the plan.

(6) Competitively sensitive information contained in the deployment plan, [Deployment Plan] and the monthly progress reports required under paragraph (9) of this subsection may be filed confidentially. An electric utility's deployment plan must [Deployment Plan shall] be maintained and made available for review on the electric utility's website [for REP access]. Competitively sensitive information contained in the deployment plan must [Deployment Plan shall] be maintained and made available at the electric utility's offices in Austin. Any REP that wishes to review competitively sensitive information contained in the electric utility's deployment plan available at its Austin office[,] may do so during normal business hours upon reasonable advanced notice to the electric utility and after executing a non-disclosure agreement with the electric utility.

(7) If the request for approval of a deployment plan [Deployment Plan] contains the information described in paragraph (4) of this subsection and the AMS features described in subsection (g)(1) of this section, then the commission will [shall] approve or disapprove the deployment plan [Deployment Plan] within 150 days, but this deadline may be extended by the commission for good cause.

(8) An electric utility's treatment of AMS, including technology, functionalities, services, deployment, operations, maintenance, and cost recovery must [shall] not be unreasonably discriminatory, prejudicial, preferential, or anticompetitive.

(9) Each electric utility must [shall] provide progress reports on a monthly basis [and status reports every six months] following the filing of its deployment plan [Deployment Plan] with the commission until deployment is complete. Upon filing of such reports, an [the] electric utility operating in an area open to customer choice must [shall] notify all [certified] REPs of the filing through standard market notice procedures. A monthly progress report must [shall] be filed within 15 days of the end of the month to which it applies, and must [shall] include the following information:

(A) the number of advanced meters installed, listed by electric service identifier for meters in the Electric Reliability Council of Texas (ERCOT) region [ESI ID]. Additional deployment information if available must [may] also be provided [listed], such as county, city, zip code, feeder numbers, and any other easily discernable geographic identification available to the electric utility about the meters that have been deployed;

(B) significant delays or deviation from the deployment plan [Deployment Plan] and the reasons for the delay or deviation;

(C) a description of significant problems the electric utility has experienced with an AMS, with an explanation of how the problems are being addressed;

(D) the number of advanced meters that have been replaced as a result of problems with the AMS; and

(E) the status of deployment of features identified in the deployment plan [Deployment Plan] and any changes in deployment of these features.

(10) If an electric utility has received approval of its deployment plan [Deployment Plan] from the commission, the electric utility must [shall] obtain commission approval before making any changes to its AMS that would affect the [a REP's] ability of a customer, the customer's REP of record, or entities authorized by the customer to utilize any of the AMS features identified in the electric utility's deployment plan [Deployment Plan] by filing a request for amendment to its deployment plan [Deployment Plan]. In addition, an electric utility may request commission approval for other changes in its approved deployment plan [Deployment Plan]. The commission will [shall] act upon the request for an amendment to the deployment plan [Deployment Plan] within 45 days of submission of the request, unless good cause exists for additional time. If an electric utility filed a notice [Notice ] of deployment [Deployment], the electric utility must [shall] file an amendment to its notice [Notice] of deployment [Deployment ] at least 45 days before making any changes to its AMS that would affect the [a REP's] ability of a customer, the customer's REP of record, or entities authorized by the customer to utilize any of the AMS features identified in the electric utility's notice [Notice] of deployment [Deployment]. This paragraph does not in any way preclude the electric utility from conducting its normal operations and maintenance with respect to the electric utility's transmission and distribution system and metering systems.

(11) During and following deployment, any outage related to normal operations and maintenance that affects a REP's ability to obtain information from [with] the system must [shall] be communicated to the REP through the outage and [/] restoration notice process according to Applicable Legal Authorities, as defined in §25.214(d)(1) of this title (relating to Tariff for Retail Delivery Service). Notification of any planned or unplanned outage that affects access to customer usage data must be posted on the electric utility's web portal home page.

(12) An [The] electric utility subject to §25.343 of this title (relating to Competitive Energy Services) must [shall] not provide any advanced metering equipment or service that is deemed a competitive energy service under that section. [§25.343 of this title (relating to Competitive Energy Services).] Any functionality of the AMS that is a required feature [function] under this section or that is included in an approved deployment plan or otherwise approved by the commission [Deployment Plan] does not constitute a competitive energy service under §25.343 of this title.

[(13) An electric utility's deployment and provision of AMS services and features, including but not limited to the features required in subsection (g) of this section, are subject to the limitation of liability provisions found in the electric utility's tariff.]

(e) Technology requirements. Except for pilot programs, an electric utility must [shall] not deploy AMS technology that has not been successfully installed previously with at least 500 advanced meters in North America, Australia, Japan, or Western Europe.

(f) Pilot programs. An electric utility may deploy AMS with up to 10,000 meters that do not meet the requirements of subsection (g) of this section in a pilot program, to gather additional information on metering technologies, pricing, and management techniques, for studies, evaluations, and other reasons. A pilot program may be used to satisfy the requirement in subsection (e) of this section. An electric utility is not required to obtain commission approval for a pilot program. Notice of the pilot program and opportunity to participate must [shall] be sent by the electric utility to all REPs.

(g) AMS features.

(1) An AMS must [shall] provide or support the following minimum system features [in order to obtain cost recovery through a surcharge pursuant to subsection (k) of this section]:

(A) automated or remote meter reading;

(B) two-way communications between the meter and the electric utility;

(C) remote disconnection and reconnection capability for meters rated at or below 200 amps;[, provided that an electric utility shall be considered in compliance with this provision if it makes this function available in all advanced meters installed after the effective date of this rule, and the following meters shall also be considered in compliance with this provision: those advanced meters that were ordered prior to the effective date of this rule, not to exceed 65,000 meters over the number of meters received or ordered as of May 10, 2007, and are provisioned with all the features enumerated in this paragraph except remote disconnect and reconnect capability, if those advanced meters are installed by December 31, 2007, and the number of advanced meters installed with all the features enumerated in this paragraph except remote disconnect and reconnect capability does not exceed 18% of the total number of advanced meters installed by the electric utility pursuant to a Deployment Plan.]

(D) time-stamped [the capability to time-stamp] meter data sent to the independent organization or regional transmission organization for purposes of wholesale settlement, consistent with time tolerance and other standards adopted by the independent organization or regional transmission organization;

(E) [the capability to provide direct, real-time] access to customer usage data by [to] the customer, [and] the customer's REP of record, and entities authorized by the customer[,] provided that [:]

[(i)] 15-minute interval or shorter [hourly] data from the electric utility's AMS must [shall] be transmitted to the electric utility's or a group of electric utilities' web portal on a day-after basis;[.]

[(ii) the commission staff using a stakeholder process, as soon as practicable shall determine, subject to commission approval, when and how 15-minute IDR data shall be made available on the electric utility's web portal.]

(F) capability to provide on-demand reads of a customer's advanced meter through the graphical user interface of an electric utility's or a group of electric utilities' web portal when requested by a customer, the customer's REP of record, or entities authorized by the customer subject to network traffic such as interval data collection, market orders if applicable, and planned and unplanned outages [means by which the REP can provide price signals to the customer];

(G) for an electric utility that provides access through an application programming interface, the capability to provide at least two on-demand reads per hour per meter of a customer's advanced meter, subject to network traffic such as interval data collection, market orders if applicable, and planned and unplanned outages. An electric utility in the ERCOT region must be able to accommodate at least 6,000 on-demand read requests per day through this method, subject to network traffic [the capability to provide 15-minute or shorter interval data to REPs, customers, and the independent organization or regional transmission organization, on a daily basis, consistent with data availability, transfer and security standards adopted by the independent organization or regional transmission organization];

(H) on-board meter storage of meter data that complies with nationally recognized non-proprietary standards such as in American National Standards Institute (ANSI) C12.19 tables;

(I) open standards and protocols that comply with nationally recognized non-proprietary standards such as ANSI C12.22, including future revisions [thereto];

(J) for an electric utility in the ERCOT region, the capability to communicate with devices inside the premises, including, but not limited to, usage monitoring devices, load control devices, and prepayment systems through a home area network (HAN), based on open standards and protocols that comply with nationally recognized non-proprietary standards such as ZigBee, Home-Plug, or the equivalent through the electric utility's AMS. This requirement applies only to a HAN device paired to a meter and in use at the time that the version of the web portal approved in Docket Number 47472 was implemented and terminates when the HAN device is disconnected at the request of the customer or a move-out transaction occurs for the customer's premises; and

(K) the ability to upgrade these features [minimum capabilities] as the need arises [technology advances and, in the electric utility's determination, become economically feasible].

[(2) An electric utility shall offer, as discretionary services in its tariff, installation of non-standard meters and advanced meter features.]

[(A) A REP may require the electric utility to provide non-standard advanced meters, additional metering technology, or advanced meter features not specifically offered in the electric utility's tariff, that are technically feasible, generally available in the market, and compatible with the electric utility's AMS;]

[(B) The REP shall pay the reasonable differential cost for the non-standard advanced meters or features.]

[(C) Upon request by a REP, an electric utility shall expeditiously provide a report to the REP that includes an evaluation of the cost and a schedule for providing the nonstandard advanced meters or advanced meter features of interest to the REP. The REP shall pay a reasonable discretionary services fee for this report. This discretionary services fee shall be included in the electric utility's tariff.]

[(D) If an electric utility agrees to deploy non-standard advanced meters or advanced meter features not addressed in its tariff at the request of the REP, the electric utility shall expeditiously apply to amend its tariff to specifically include the non-standard advanced meters or meter features that it agreed to deploy.]

(2) [(3)] A [An electric utility may petition the commission for a] waiver from any of the requirements of paragraph (1) of this subsection may be granted by the commission if [for portions of its service area where] it would be uneconomic or technically infeasible to implement [particular system features. A waiver may also be granted for an AMS that exceeds] or there is an adequate substitute for that [the] particular requirement [requirements in paragraph (1) of this subsection]. The electric utility must meet its [shall provide all relevant studies and cost-benefit analysis and other evidence supporting its waiver request and shall bear the] burden of proof in its waiver request. [An electric utility that has received a waiver shall explain in the report required by subsection (d)(7) of this section, technology changes and changes in the cost of deployment or savings to the electric utility that would make it economic or technically feasible to offer the system features in the affected portions of its service area. Any waiver granted by the commission shall extend only to those costs and expenses for which the waiver is granted in any proceeding in which the electric utility seeks to recover its costs through the surcharge mechanism addressed in subsection (k) of this section.]

(3) [(4)] In areas where there is not a commission-approved independent regional transmission organization, standards referred to in this section for time tolerance and data transfer and security may be approved by a regional transmission organization approved by the Federal Energy Regulatory Commission or, if there is no approved regional transmission organization, by the commission.

(4) [(5)] Once an electric utility has deployed its advanced meters, it may add or enhance features provided by AMS, as technology evolves [and in accordance with Applicable Legal Authorities]. The electric utility must [shall ] notify the commission and REPs of any such additions or enhancements at least three months in advance of deployment, with a description of the features, the deployment and notification plan, and the cost of such additions or enhancements, and must [shall] follow the monthly progress report process described in subsection (d)(9)[(8)] of this section until the enhancement process is complete.

[(6) Beginning January 1, 2008, or as soon as such meters are commercially available from the electric utility's current vendor, whichever is earlier, an electric utility shall replace, at no cost to the customer, an advanced meter with all the features enumerated in paragraph (1) of this subsection except remote disconnect and reconnect capability, if: the meter has reached the end of its useful life; the meter has been removed for repair; the premises at which the meter is located has experienced an unusually high number of disconnections and reconnections; or the REP has informed the electric utility that its customer has agreed to utilize a prepaid service and the REP has requested a meter with remote disconnection and reconnection capability. If by January 1, 2009, requests by REPs for replacement of advanced meters with all the features enumerated in paragraph (1) of this subsection except remote disconnect and reconnect capability exceed 20% of those meters, then the electric utility shall replace all of those meters as soon as possible with meters that meet the requirements of paragraph (1) of this subsection and have remote disconnect and reconnect capability.]

(h) Discretionary Meter Services. An electric utility that operates in an area that offers customer choice must offer, as discretionary services in its tariff, installation of enhanced advanced meters and advanced meter features.

(1) A REP may request the electric utility to provide enhanced advanced meters, additional metering technology, or advanced meter features not specifically offered in the electric utility's tariff, that are technically feasible, generally available in the market, and compatible with the electric utility's AMS.

(2) The REP must pay the reasonable differential cost for the enhanced advanced meters or features and system changes required by the electric utility to offer those meters or features.

(3) Upon request by a REP, an electric utility must expeditiously provide a report to the REP that includes an evaluation of the cost and a schedule for providing the enhanced advanced meters or advanced meter features of interest to the REP. The REP must pay a reasonable discretionary services fee for this report. This discretionary services fee must be included in the electric utility's tariff.

(4) If an electric utility deploys enhanced advanced meters or advanced meter features not addressed in its tariff at the request of the REP, the electric utility must expeditiously apply to amend its tariff to specifically include the enhanced advanced meters or meter features that it agreed to deploy. Additional REPs may request the tariffed enhanced advanced meters or advanced meter features under the process described in this paragraph of this subsection.

[(h) Settlement. It is the objective of this rule that ERCOT shall be able to use 15-minute meter information from advanced metering systems for wholesale settlement, not later than January 31, 2010.]

(i) Tariff. All [non-standard,] discretionary AMS features offered by the electric utility must [shall] be described in the electric utility's tariff.

(j) Access to meter data.

(1) An electric utility must [shall] provide a customer, the customer's REP of record, and other entities authorized by the customer read-only access to the customer's advanced meter data, including meter data used to calculate charges for service, historical load data, and any other proprietary customer information. The access must [shall] be convenient and secure, and the data must [shall] be made available no later than the day after it was created.

(2) The requirement to provide access to the data begins when the electric utility has installed 2,000 advanced meters for residential and non-residential customers. If an electric utility has already installed 2,000 advanced meters by the effective date of this section, the electric utility must [shall] provide access to the data in the timeframe approved by the commission in either the deployment plan [Deployment Plan] or request for surcharge proceeding. If only a notice [Notice ] of deployment [Deployment] has been filed, access to the data must [shall] begin no later than six months from the filing of the notice [Notice ] of deployment [Deployment] with the commission.

(3) An electric utility or group of electric utilities' web portal must [shall] use appropriate and reasonable [industry] standards and methods to provide [for providing] secure access for the customer, the customer's [and] REP of record, and entities authorized by the customer [access] to the meter data. The electric utility must [shall] have an independent security audit conducted within one year of providing that [the mechanism for customer and REP] access to meter data. The electric utility must [conducted within one year of initiating such access and] promptly report the audit results to the commission.

(4) The independent organization, regional transmission organization, or regional reliability entity must [shall] have access to information that is required for wholesale settlement, load profiling, load research, and reliability purposes.

[(5) A customer may authorize its data to be available to an entity other than its REP.]

(k) Cost recovery for deployment of AMS.

(1) Recovery Method. The commission will [shall] establish a nonbypassable surcharge for an electric utility to recover reasonable and necessary costs incurred in deploying AMS to residential customers and nonresidential customers other than those required by the independent system operator to have an interval data recorder meter. The surcharge must [shall] not be established until after a detailed deployment plan [Deployment Plan] is filed under [pursuant to] subsection (d) of this section. In addition, the surcharge must [shall ] not ultimately recover more than the AMS costs that are spent, reasonable and necessary, and fully allocated, but may include estimated costs that will [shall] be reconciled pursuant to paragraph (6) of this subsection. As indicated by the definition of AMS in subsection (c)(2) of this section, the costs for facilities that do not perform the functions and have the features specified in this section must [shall] not be included in the surcharge provided for by this subsection unless an electric utility has received a waiver under [pursuant to] subsection (g)(2) [(g)(3)] of this section. The costs of providing AMS services include those costs of AMS installed as part of a pilot program under [pursuant to] this section. Costs of providing AMS for a particular customer class must [shall] be surcharged only to customers in that customer class.

(2) Carrying Costs. The annualized carrying-cost rate to be applied to the unamortized balance of the AMS capital costs must [shall] be the electric utility's authorized weighted-average cost of capital (WACC). If the commission has not approved a WACC for the electric utility within the last four years, the commission may set a new WACC to apply to the unamortized balance of the AMS capital costs. In each subsequent rate proceeding in which the commission resets the electric utility's WACC, the carrying-charge rate that is applied to the unamortized balance of the utility's AMS costs must [shall] be correspondingly adjusted to reflect the new authorized WACC.

(3) Surcharge Proceeding. In the request for surcharge proceeding, [an electric utility may propose a surcharge methodology, but] the commission will set the surcharge based on [prefers the stability of] a levelized amount, and an amortization period based [ranging from five to seven years, depending ] on the useful life of the AMS [meter]. The commission may set the surcharge to reflect a deployment of advanced meters that is up to one-third of the electric utility's total meters over each calendar year, regardless of the rate of actual AMS deployment. The actual or expected net operating cost savings from AMS deployment, to the extent that the operating costs are not reflected in base rates, may be considered in setting the surcharge. If an electric utility that requests a surcharge does not have an approved deployment plan [Deployment Plan], the commission in the surcharge proceeding may reconcile the costs that the electric utility already spent on AMS in accordance with paragraph (6) of this subsection and may approve a deployment plan [Deployment Plan].

(4) General Base Rate Proceeding while Surcharge is in Effect. If the commission conducts a general base rate proceeding while a surcharge under this section is in effect, then the commission will [shall] include the reasonable and necessary costs of installed AMS equipment in the base rates and decrease the surcharge accordingly, and permit reasonable recovery of any non-AMS metering equipment that has not yet been fully depreciated but has been replaced by the equipment installed under an approved deployment plan [Deployment Plan].

(5) Annual Reports. An electric utility must [shall] file annual reports with the commission updating the cost information used in setting the surcharge. The annual reports must [shall] include the actual costs spent to date in the deployment of AMS and the actual net operating cost savings from AMS deployment and how those numbers compare to the projections used to set the surcharge. During the annual report process, an electric utility may apply to update its surcharge, and the commission may set a schedule for such applications. For a levelized surcharge, the commission may alter the length of the surcharge collection period based on review of information concerning changes in deployment costs or operating costs savings in the annual report or changes in WACC. An annual report filed with the commission will [shall] not be a ratemaking proceeding, but an application by the electric utility to update the surcharge must [shall] be a ratemaking proceeding.

(6) Reconciliation Proceeding. All costs recovered through the surcharge must [shall] be reviewed in a reconciliation proceeding on a schedule to be determined by the commission. Notwithstanding the preceding sentence, the electric utility may request multiple reconciliation proceedings, but no more frequently than once every three years. There is a presumption that costs spent in accordance with a deployment plan [Deployment Plan] or amended deployment plan [Deployment Plan] approved by the commission are reasonable and necessary. Any costs recovered through the surcharge that are found in a reconciliation proceeding not to have been spent or properly allocated, or not to be reasonable and necessary, must [shall] be refunded to electric utility's customers. In addition, the commission will [shall] make a final determination of the net operating cost savings from AMS deployment used to reduce the amount of costs that ultimately can be recovered through the surcharge. Accrual of interest on any refunded or surcharged amounts resulting from the reconciliation must [shall] be at the electric utility's WACC and must [shall] begin at the time the under or over recovery occurred.

(7) Cross-subsidization and fees. The electric utility must [shall] account for its costs in a manner that ensures [that] there is no inappropriate cost allocation, cost recovery, or cost assignment that would cause cross-subsidization between utility activities and non-utility activities. The electric utility shall not charge a disconnection or reconnection fee that was approved by the commission prior to the effective date of this rule, for a disconnection or reconnection that is effectuated using the remote disconnection or connection capability of an advanced meter.

[(l) Time of Use Schedule. Commission approval of a time of use schedule ("TOUS") pursuant to ERCOT protocols is not necessary prior to implementation of the new TOUS.]

§25.133.Non-Standard Metering Service.

(a) Purpose. This section allows a customer [whose standard meter is an advanced meter] to choose to receive electric service through a non-standard meter from an electric utility that has deployed or is requesting to deploy advanced meters under a commission-approved deployment plan or notice of deployment and authorizes the electric utility [a transmission and distribution utility (TDU)] to assess fees to recover the costs associated with this section from a customer who elects to receive electric service through a non-standard [such a] meter.

(b) Applicability. This section is applicable to an electric utility, including a transmission and distribution utility, that has deployed or is requesting to deploy advanced meters under a commission-approved deployment plan or notice of deployment. Any requirement in this section that relates to retail electric providers (REPs) is applicable only to REPs and electric utilities that operate in areas open to customer choice.

(c) [(b)] Definitions. As used in this section, the following terms have the following meanings, unless the context indicates otherwise:

(1) Advanced meter--As defined in §25.130 of this title (relating to Advanced Metering).

(2) Non-standard meter--A meter that does not function as an advanced meter.

(3) Non-standard metering service--Provision of electric service through a non-standard meter from an electric utility that has deployed or is requesting to deploy advanced meters under a commission-approved deployment plan or notice of deployment.

(d) [(c)] Initiation and termination of non-standard metering service.

(1) Initiation of non-standard metering service. An electric utility that has deployed or is requesting to deploy advanced meters under a commission-approved deployment plan or notice of deployment must offer non-standard metering service to customers.

(A) An electric utility filing a deployment plan or notice of deployment under §25.130 of this title after the effective date of this section must include non-standard metering service as a part of the plan or notice. [This subparagraph applies to a TDU that, on the date that the TDU begins offering non-standard metering service pursuant to subsection (g) of this section, has completed deployment of advanced meters except for customers for whom the TDU did not install advanced meters because of the requests of the customers. The TDU shall serve on such a customer by certified mail return receipt requested notice consistent with subparagraph (D) of this paragraph within 30 days of the date that the TDU begins offering non-standard metering service pursuant to subsection (g) of this section.]

(i) Within 30 days of the date of commission approval of an electric utility's deployment plan or the filing of a notice of deployment, the electric utility must provide information on its website that describes its non-standard metering service, the process under this section to request non-standard metering service, and all the costs associated with the service.

(ii) An electric utility must provide a statement that non-standard metering service is available and provide a hyperlink to the information required under clause (i) of this subparagraph in all notices and messages delivered to a customer relating to the deployment date of advanced meters in the customer's geographic area.

[(B) This subparagraph applies to a TDU that has not completed deployment of advanced meters.]

[(i) This clause applies to a customer for whom the TDU has not, on the date that the TDU begins offering non-standard metering service pursuant to subsection (g) of this section, installed an advanced meter because of the request of the customer. The TDU shall serve on such a customer by certified mail return receipt requested notice consistent with subparagraph (D) of this paragraph within 30 days of the date that the TDU begins offering non-standard metering service pursuant to subsection (g) of this section.]

[(ii) This clause applies to a customer for whom, after the date that the TDU begins offering non-standard metering service pursuant to subsection (g) of this section, the TDU attempts to install an advanced meter as part of its advanced meter deployment plan but the customer requests non-standard metering service. The TDU shall promptly serve on such a customer by certified mail return receipt requested notice consistent with subparagraph (D) of this paragraph.]

(B) [(C)] An electric utility must [For circumstances not addressed by subparagraph (A) or (B) of this paragraph in which a customer requests from the TDU non-standard metering service, the TDU shall] provide notice to a customer consistent with subparagraph (C) [(D)] of this paragraph within seven days of the customer's request for non-standard metering service, using an appropriate means of service.

(C) [(D)] An electric utility must [Pursuant to subparagraphs (A)-(C) of this paragraph, a TDU shall] notify a customer that requests non-standard metering service of the following through a written acknowledgement.

(i) The customer will be required to pay the costs associated with the initiation of non-standard metering service and the ongoing costs associated with the manual reading of the meter, and other fees and charges that may be assessed by the electric utility [TDU] that are associated with the non-standard metering service;

(ii) The current one-time fees and monthly fee for non-standard metering service;

(iii) The customer may be required to wait up to 45 days to switch the customer's REP of record; [retail electric provider (REP),]

(iv) The customer [and] may experience longer restoration times in case of a service interruption or outage;

(v) [(iv)]The customer may be required by the customer's REP of record to choose a different product or service before initiation of the non-standard metering service, subject to any applicable charges or fees required under the customer's existing contract, if the customer is currently enrolled in a product or service that relies on an advanced meter; and

(vi) [(v)] For a customer that does not currently have an advanced meter, the date (60 days after service of the notice) by which the customer must provide a signed, written acknowledgement and payment of the one-time fee to the electric utility [TDU] prescribed by subsection (f)[(e)](3) of this section. If the signed, written acknowledgement and payment are not received within 60 days, the electric utility [TDU] will install an advanced meter on the customer's premises.

(D) [(E)] The electric utility must [TDU shall] retain the signed, written acknowledgement for at least two years after the non-standard meter is removed from the premises. The commission may adopt a form for the written acknowledgement.

(E) [(F)] An electric utility must [A TDU shall] offer non-standard metering through the following means:

(i) disabling communications technology in an advanced meter if feasible;

(ii) if applicable, allowing the customer to continue to receive metering service using the existing meter if the electric utility [TDU] determines that it meets applicable accuracy standards;

(iii) if commercially available, an analog meter that meets applicable meter accuracy standards; and

(iv) a digital, non-communicating meter.

(F) [(G)] The electric utility must [TDU shall] not initiate the process to provide non-standard metering service before it has received the customer's payment and signed, written acknowledgement. The electric utility must [TDU shall] initiate the approved standard market process to notify the customer's REP of record within three days of the electric utility's [TDU's] receipt of the customer's payment and signed, written acknowledgement. Within 30 days of receipt of the payment of the one-time fee and the signed written acknowledgement from the customer, the electric utility [TDU], using the approved standard market process, must [shall] notify the customer's REP of record of the date the non-standard metering service was initiated.

(2) Termination of non-standard metering service. A customer receiving non-standard metering service may terminate that service by notifying the customer's electric utility [TDU ]. The customer will [shall] remain responsible for all costs related to non-standard metering service.

(e) [(d)] Other electric utility [TDU] obligations.

(1) When an [a] electric utility [TDU] completes a move-out transaction for a customer who was receiving non-standard metering service, the electric utility must [TDU shall] install [and/]or activate an advanced meter at the premises.

(2) An electric utility must [A TDU shall] read a non-standard meter monthly. In order for the electric utility [TDU] to maintain a non-standard meter at the customer's premises, the customer must provide the electric utility [TDU] with sufficient access to properly operate and maintain the meter, including reading and testing the meter.

(f) [(e)] Cost recovery and compliance tariffs. All costs incurred by an electric utility [a TDU] to implement this section must [shall] be borne only by customers who choose non-standard metering service. A customer receiving non-standard metering service must [shall] be charged a one-time fee and a recurring monthly fee.

(1) An electric utility's application for approval of its non-standard metering service tariff or amended tariff must be [Not later than 25 days after the effective date of this section, each TDU shall file a compliance tariff that is] fully supported with testimony and documentation. The application must [compliance tariff shall] include one-time [onetime] fees and a monthly fee for non-standard metering service and must [shall] also include the fees for other discretionary services performed by the electric utility [TDU] that are affected by the customer's selection of non-standard metering service. The commission will allow the electric utility [Each TDU shall be allowed] to recover the reasonable rate case expenses that it incurs under this paragraph [subsection] as part of the one-time fee, the monthly fee, or both. The application must [compliance tariff filing shall] describe the extent to which the back-office costs that are new and fixed vary depending on the number of customers receiving non-standard metering service. Unless otherwise ordered, the electric utility must [TDU shall] serve notice of the approved rates and the effective date of the approved rates within five working days of the filing of the commission's final order [presiding officer's final decision,] to REPs that are authorized by the registration agent to provide service in the electric utility's [TDU's distribution] service area. Notice to REPs under this paragraph may be served by email and must[, consistent with subsection (g) of this section, shall] be served at least 45 days before the effective date of the rates [electric utility TDU begins offering non-standard metering service].

[(2) A TDU may apply to change the fees approved pursuant to paragraph (1) of this subsection. The application must be fully supported with testimony and documentation. Each TDU shall be allowed to recover the reasonable rate case expenses that it incurs under this subsection as part of the one-time fee, the monthly fee, or both. Unless otherwise ordered, the TDU shall serve notice of the approved rates and the effective date of the approved rates within five working days of the presiding officer's final decision, to REPs that are authorized by the registration agent to provide service in the TDU's distribution service area. Notice under this paragraph may be served by email and, if possible, shall be served at least 45 days before the effective date of the rates.]

(2) [(3)] An electric utility must [A TDU shall] have a single recurring monthly fee for non-standard metering service and several one-time fees, one of which must [shall] apply to the customer depending on the customer's circumstances. A one-time fee must [shall] be charged to a customer that does not have an advanced meter at the customer's premises and will continue receiving metering service through the meter currently at the premises. For a customer that currently has an advanced meter at the premises, the fee will [shall] vary depending on the type of meter that is installed to provide non-standard metering service, and the fee must [shall] include the cost to remove the advanced meter and subsequently re-install an advanced meter once non-standard metering service is terminated. The one-time fee must [shall] recover costs to initiate non-standard metering service. The monthly fee must [shall] recover ongoing costs to provide non-standard metering service, including costs for meter reading and billing. Fixed costs not related to the initiation of non-standard metering service may be allocated between the one-time and monthly fees[,] and recovered through the monthly fee over a shortened period of time.

(g) [(f)] Retail electric product compatibility. After receipt of the notice prescribed by subsection (d)(1)(C) [(c)(1)(D)] of this section, if the customer's current product is not compatible with non-standard metering service, the customer's REP of record must [shall] work with the customer to either promptly transition the customer to a product that is compatible with non-standard metering service or transfer the customer to another REP, subject to any applicable charges or fees required under the customer's existing contract. If the customer is unresponsive, the customer's REP of record may transition the customer without the customer's affirmative consent to a market-based, month-to-month product that is compatible with non-standard metering service. Alternatively, if the customer is unresponsive, the customer's REP of record may transfer the customer to another REP under [pursuant to] §25.493 (relating to Acquisition and Transfer of Customers from One Retail Electric Provider or Another) so long as the new REP serves the customer using a market-based, month-to-month product with a rate (excluding charges for non-standard metering service or other discretionary services) no higher than one of the tests prescribed by §25.498(c)(15)(A)-(C) of this title (relating to Prepaid Service). The customer's REP of record must [shall] promptly provide the customer notice that the customer has been transferred to a new product and, if applicable, to a new REP, and must [shall] also promptly provide the new Terms of Service and Electricity Facts Label.

[(g) Implementation. A TDU shall begin offering non-standard metering service pursuant to this section the later of 160 days from the effective date of this section or 45 days after the notice to REPs prescribed by subsection (e)(1) of this section.]

The agency certifies that legal counsel has reviewed the proposal and found it to be within the state agency's legal authority to adopt.

Filed with the Office of the Secretary of State on November 15, 2019.

TRD-201904266

Andrea Gonzalez

Rules Coordinator

Public Utility Commission of Texas

Earliest possible date of adoption: December 29, 2019

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


SUBCHAPTER D. RECORDS, REPORTS, AND OTHER REQUIRED INFORMATION

16 TAC §25.97

The Public Utility Commission of Texas (commission) proposes §25.97, relating to Line Inspection and Safety. The proposed rule will implement the reporting requirements in Public Utility Regulatory Act (PURA) §38.102.

Growth Impact Statement

The commission provides the following governmental growth impact statement for the proposed rule, as required by Texas Government Code §2001.0221. The commission has determined that for each year of the first five years that the proposed rule is in effect, the following statements will apply:

(1) the proposed rule will not create a government program and will not eliminate a government program;

(2) implementation of the proposed rule will not require the creation of new employee positions and will not require the elimination of existing employee positions;

(3) implementation of the proposed rule will not require an increase and will not require a decrease in future legislative appropriations to the commission because it will not increase or decrease agency staffing levels;

(4) the proposed rule will not require an increase and will not require a decrease in fees paid to the commission;

(5) the proposed rule will create a new regulation to implement PURA §38.102 enacted by the 86th Legislative Session;

(6) the proposed rule will not limit an existing regulation;

(7) the proposed rule will not change the number of individuals subject to the rule's applicability; and

(8) the proposed rule will not affect this state's economy.

Fiscal Impact on Small and Micro-Businesses and Rural Communities

There is no adverse economic effect anticipated for small businesses, micro-businesses, or rural communities as a result of implementing the proposed rule. Accordingly, no economic impact statement or regulatory flexibility analysis is required under Texas Government Code §2006.002(c).

Takings Impact Analysis

The commission has determined that the proposed rule will not be a taking of private property as defined in chapter 2007 of the Texas Government Code.

Fiscal Impact on State and Local Government

Constance McDaniel Wyman, Director of Electric Utility Engineering, has determined that for the first five-year period the proposed rule is in effect, there will be no fiscal implications for the state or for units of local government under Texas Government Code §2001.024(a)(4) as a result of enforcing or administering the rule.

Public Benefits

Ms. McDaniel Wyman has also determined that for each year of the first five years the proposed rule is in effect, the anticipated public benefit expected as a result of the adoption of the proposed rule will be the implementation of PURA §38.102. There will be economic cost to affected entities required to comply with the rule under Texas Government Code §2001.024(a)(5).

Local Employment Impact Statement

For each year of the first five years the proposed rule is in effect, there should be no effect on a local economy; therefore, no local employment impact statement is required under Texas Government Code §2001.022.

Costs to Regulated Persons

Texas Government Code §2001.0045(b) does not apply to this rulemaking, because the Public Utility Commission is expressly excluded under subsection §2001.0045(c)(7).

Public Hearing

The commission staff will conduct a public hearing on this rulemaking, if requested in accordance with Texas Government Code §2001.029, at the commission's offices located in the William B. Travis Building, 1701 North Congress Avenue, Austin, Texas 78701 on Friday, January 17, 2020, at 9:00 a.m. The request for a public hearing must be received by Monday, January 13, 2020. If no request for a public hearing is received and the commission staff cancels the hearing, it will make a filing in this project prior to the scheduled date for the hearing.

Public Comments

Initial comments on the proposed rule may be submitted to the Filing Clerk, Public Utility Commission of Texas, 1701 North Congress Avenue, P.O. Box 13326, Austin, Texas 78711-3326, no later than January 6, 2020. Sixteen copies of comments to the proposed rule are required to be filed under §22.71(c) of 16 Texas Administrative Code. Reply comments may be submitted in the same manner no later than January 13, 2020. Comments should be organized in a manner consistent with the organization of the proposed rule. The commission invites specific comments regarding the costs associated with, and benefits that will be gained by, implementation of the proposed rule. The commission will consider the costs and benefits in deciding whether to modify the proposed rule on adoption. All comments should refer to project number 49827.

Statutory Authority

This new rule is proposed under §14.002 of the Public Utility Regulatory Act, Tex. Util. Code (PURA), which provides the commission with the authority to make and enforce rules reasonably required in the exercise of its powers and jurisdiction, and §38.102, which requires certain utilities to filed with the commission reports on safety processes and inspections.

Cross reference to statutes: Public Utility Regulatory Act §§14.002 and 38.102.

§25.97.Line Inspection and Safety.

(a) Purpose. This section implements the reporting requirements in Public Utility Regulatory Act (PURA) §38.102.

(b) Applicability. This section applies to electric utilities, municipally owned utilities, and electric cooperatives that own or operate overhead transmission or distribution assets.

(c) Definition. When used in this section, the term "affected entity" means an electric utility, electric cooperative, or municipally owned utility that owns or operates overhead transmission or distribution assets.

(d) Employee Training Report.

(1) Not later than May 1, 2020, each affected entity must submit to the Commission a report that includes:

(A) a summary description of hazard recognition training documents provided by the affected entity to its employees related to overhead transmission and distribution facilities; and

(B) a summary description of training programs provided to employees by the affected entity related to the National Electrical Safety Code (NESC) for construction of electric transmission and distribution lines.

(2) An affected entity must submit an updated report not later than the 30th day after the date the affected entity finalizes a material change to a document or training program included in a report submitted under paragraph (1) of this subsection.

(e) Five-Year Report.

(1) Not later than May 1 every five years, each affected entity that owns or operates overhead transmission facilities greater than 60 kilovolts must submit to the commission a report for the five-year period ending on December 31 of the preceding calendar year that includes:

(A) the percentage of overhead transmission facilities greater than 60 kilovolts inspected for compliance with the NESC relating to vertical clearance in the reporting period; and

(B) the percentage of the overhead transmission facilities greater than 60 kilovolts anticipated to be inspected for compliance with the NESC relating to vertical clearance during the five-year period beginning on January 1 of the year in which the report is submitted.

(2) The first report submitted under this subsection must be submitted not later than May 1, 2020.

(f) Annual Report. Not later than May 1 of each year, each affected entity must make a report to the commission for the preceding calendar year.

(1) For each affected entity that owns or operates overhead transmission facilities greater than 60 kilovolts, the report must include the following information related to those facilities:

(A) the number of identified occurrences of noncompliance with PURA §38.004 regarding vertical clearance requirements of the NESC for overhead transmission facilities;

(B) whether the affected entity has actual knowledge that any portion of the affected entity's transmission system is not in compliance with PURA §38.004 regarding vertical clearance requirements of the NESC for overhead transmission facilities; and

(C) whether the affected entity has actual knowledge of any violations of easement agreements with the United States Army Corps of Engineers relating to PURA §38.004 regarding the vertical clearance requirements of the NESC for overhead transmission facilities.

(2) For each affected entity that owns or operates overhead transmission facilities greater than 60 kilovolts or distribution facilities greater than 1 kilovolt, the report must include the following information related to those facilities:

(A) 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 PURA §38.004; and

(B) a description of corrective actions taken or planned to prevent the reoccurrence of fatalities or injuries described by subparagraph (A) of this paragraph.

(3) 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 an affected entity's control are not required to be included in the report under this subsection.

(g) Reporting Form. An affected entity must make a report required by this section on a form prescribed by the commission.

(h) Report Filing. An affected entity filing a report required under this subsection must include the project number designated by the commission for the report on the first page of the report and submit the correct number of copies of the report to the commission's central records for filing.

(i) Reports Publicly Available. Not later than September 1 each year, the commission will make the reports submitted under this section publicly available on the commission's Internet website.

The agency certifies that legal counsel has reviewed the proposal and found it to be within the state agency's legal authority to adopt.

Filed with the Office of the Secretary of State on November 15, 2019.

TRD-201904287

Andrea Gonzalez

Rules Coordinator

Public Utility Commission of Texas

Earliest possible date of adoption: December 29, 2019

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


CHAPTER 25. SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS

The Public Utility Commission of Texas (commission) proposes new 16 Texas Administrative Code (TAC) new 16 TAC §25.112, relating to Registration of Brokers, and new 16 TAC §25.486, relating to Customer Protections for Brokerage Services. The proposed rules will implement the requirements of Public Utility Regulatory Act (PURA) §39.3555 enacted by the 86th Texas Legislature.

Public Benefits

For each year of the first five years the proposed rules are in effect, the anticipated public benefit expected as a result of the adoption of the proposed rules will be the implementation of PURA §39.3555. There may be economic costs to affected entities required to comply with the rules under Texas Government Code §2001.024(a)(5), but those costs are necessary to implement PURA §39.3555 as enacted by the 86th Texas Legislature.

Growth Impact Statement

The commission provides the following governmental growth impact statement for the proposed rule, as required by Texas Government Code §2001.0221. The commission has determined that for each year of the first five years that the proposed rules are in effect, the following statements will apply:

(1) the proposed rules will not create a government program and will not eliminate a government program;

(2) implementation of the proposed rules will not require the creation of new employee positions and will not require the elimination of existing employee positions;

(3) implementation of the proposed rules will not require an increase and will not require a decrease in future legislative appropriations to the commission;

(4) the proposed rules will not require an increase and will not require a decrease in fees paid to the commission;

(5) the proposed rules will create new regulations to implement PURA §39.3555 as enacted by the 86th Texas Legislature;

(6) the proposed rules will not limit an existing regulation;

(7) the proposed rules will not increase the number of individuals subject to the rule's applicability; and

(8) the proposed rules will not affect this state's economy.

Fiscal Impact on Small and Micro-Businesses and Rural Communities

There is no adverse economic effect anticipated for small businesses, micro-businesses, or rural communities as a result of implementing the proposed rule. Accordingly, no economic impact statement or regulatory flexibility analysis is required under Texas Government Code §2006.002(c).

Takings Impact Analysis

The commission has determined that the proposed rules will not be a taking of private property as defined in chapter 2007 of the Texas Government Code.

Fiscal Impact on State and Local Government

James Kelsaw, Senior Utility Analyst, has determined that for the first five-year period the proposed rules are in effect, there will be no fiscal implications for the state or for units of local government under Texas Government Code §2001.024(a)(4) as a result of enforcing or administering the rule.

Local Employment Impact Statement

For each year of the first five years the proposed rules are in effect, there should be no effect on a local economy; therefore, no local employment impact statement is required under Texas Government Code §2001.022.

Costs to Regulated Persons

Texas Government Code §2001.0045(b) does not apply to this rulemaking, because the Public Utility Commission is expressly excluded under subsection §2001.0045(c)(7).

Public Hearing

The commission staff will conduct a public hearing on this rulemaking, if requested, in accordance with Texas Government Code §2001.029, at the commission's offices located in the William B. Travis Building, 1701 North Congress Avenue, Austin, Texas 78701 on Friday, January 17, 2020 at 9:00 a.m. The request for a public hearing must be received by Monday, January 13, 2020. If no request for a public hearing is received and the commission staff cancels the hearing, it will file in this project a notification of the cancellation of the hearing prior to the scheduled date for the hearing.

Public Comments

Initial comments on the proposed rules may be submitted to the Filing Clerk, Public Utility Commission of Texas, 1701 North Congress Avenue, P.O. Box 13326, Austin, Texas 78711-3326, no later than January 6, 2020. Sixteen copies of comments on the proposed rules are required to be submitted under 16 TAC §22.71(c). Reply comments may be submitted in the same manner no later than January 13, 2020. Comments should be organized in a manner consistent with the organization of the proposed rules. The commission invites specific comments regarding the costs associated with, and benefits that will be gained by, implementation of the proposed rules. The commission will consider the costs and benefits in deciding whether to modify the proposed rules on adoption. All comments should refer to project number 49794.

SUBCHAPTER E. CERTIFICATION, LICENSING AND REGISTRATION

16 TAC §25.112

Statutory Authority

This rule is proposed under §14.002 of the Public Utility Regulatory Act, Tex. Util. Code (PURA), which provides the commission with the authority to make and enforce rules reasonably required in the exercise of its powers and jurisdiction, and §39.3555, which requires entities that provide brokerage services in this state to register as brokers with the commission and to comply with customer protection provisions established by the commission and Chapters 17 and 39 of PURA and which requires the commission to adopt rules as necessary to implement the section.

Cross reference to statutes: Public Utility Regulatory Act §§14.002 and 39.3555.

§25.112.Registration of Brokers.

(a) Registration required. A person must not provide brokerage services, including brokerage services offered online, in this state for compensation or other consideration unless the person is registered with the commission as a broker. A retail electric provider (REP) is not permitted to register as a broker and must not knowingly provide bids or offers to a person who provides brokerage services in this state for compensation or other consideration and is not registered as a broker. A REP may rely on the publicly available list of registered brokers posted on the commission's website to determine whether a broker is registered with the commission.

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

(1) Broker--A person that provides brokerage services.

(2) Brokerage services--Providing advice or procurement services to, or acting on behalf of, a retail electric customer regarding the selection of a REP, or a product or service offered by a REP.

(c) Requirements for a person seeking to register as a broker. A person seeking to register under this section must provide the information listed in this subsection.

(1) all business names of the registrant limited to five business names;

(2) the mailing address, telephone number, and email address of the principal place of business of the registrant;

(3) the name, title, business mailing address, telephone number, and email address for the registrant's regulatory contact person;

(4) the name, title, business mailing address, telephone number, and email address of the registrant's customer service contact person;

(5) the name, title, business mailing address, telephone number, and email address of the registrant's commission complaint contact person;

(6) the form of business being registered (e.g., corporation, partnership, or sole proprietor); and

(7) an affidavit from the owner, partner, or officer of the registrant affirming that the registrant is authorized to do business in Texas under all applicable laws and is in good standing with the Texas Secretary of State; that all statements made in the application are true, correct, and complete; that any material changes in the information will be provided in a timely manner; and that the registrant understands and will comply with all applicable law and rules.

(d) Registration procedures. The following procedures apply to a person seeking to register as a broker:

(1) A registration application must be made on the form approved by the commission, verified by notarized oath or affirmation, and signed by an owner, partner, or officer of the registrant. The form may be obtained from the central records division of the commission or from the commission's Internet site. Each registrant must file its registration application form with the commission's filing clerk in accordance with the commission's procedural rules.

(2) The registrant may identify certain information or documents submitted that it believes to contain proprietary or confidential information. Registering entities may not designate the entire registration application as confidential. Information designated as proprietary or confidential will be treated in accordance with the confidentiality requirements in the Public Utility Regulatory Act (PURA), Tex. Gov't Code Chapter 552, and commission rules. If a public information act request is received for information designated as confidential, the registrant has the burden to establish that the requested information is proprietary or confidential.

(3) The registrant must promptly inform the commission of any material change in the information provided in the registration application while the application is being processed.

(4) An application will be processed as follows:

(A) Commission staff will review the submitted form for completeness. Within 20 working days of receipt of an application, the commission staff will notify the registrant by mail or e-mail of any deficiencies in the application. The registrant will have ten working days from the issuance of the notification to cure the deficiencies. If the deficiencies are not cured within ten working days, commission staff will notify the registrant that the registration application is rejected without prejudice.

(B) Commission staff will determine whether to accept or reject the application within 60 days of the receipt of a complete application.

(C) An applicant may contest commission staff's rejection of its application by filing a petition for formal review of the registration application in accordance with the commission's procedural rules. The registrant has the burden of proof to establish that its application meets the requirements of PURA and commission rules.

(e) Registration renewal. A broker registration expires three years after the date of the assignment of a broker registration number. Each registrant must submit the information required to renew its registration with the commission not less than 90 days prior to the expiration date of the current registration. An expired registration is no longer valid and the broker will be removed from the broker list on the commission's website.

(f) Registration amendment. A broker must amend its registration to reflect any changes in the information previously submitted, including business name, mailing address, email address, or telephone number within 30 calendar days from the date of the change.

(g) Suspension and revocation of registration and administrative penalty. The commission may impose an administrative penalty for violations of PURA or commission rules. The commission may also suspend or revoke a broker's registration for significant violations of PURA or commission rules. Significant violations include, but are not limited to, the following:

(1) providing false or misleading information to the commission;

(2) engaging in fraudulent, unfair, misleading, deceptive or anti-competitive practices;

(3) a pattern of failure to meet the requirements of PURA, commission rules, or commission orders;

(4) failure to respond to commission inquiries or customer complaints in a timely fashion;

(5) switching or causing to be switched the REP of a customer without first obtaining the customer's authorization; or

(6) billing an unauthorized charge or causing an unauthorized charge to be billed to a customer's retail electric service bill.

The agency certifies that legal counsel has reviewed the proposal and found it to be within the state agency's legal authority to adopt.

Filed with the Office of the Secretary of State on November 15, 2019.

TRD-201904273

Andrea Gonzalez

Rules Coordinator

Public Utility Commission of Texas

Earliest possible date of adoption: December 29, 2019

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


SUBCHAPTER R. CUSTOMER PROTECTION RULES FOR RETAIL ELECTRIC SERVICE PROVIDERS

16 TAC §25.486

Statutory Authority

This rule is proposed under §14.002 of the Public Utility Regulatory Act, Tex. Util. Code (PURA), which provides the commission with the authority to make and enforce rules reasonably required in the exercise of its powers and jurisdiction, and §39.3555, which requires entities that provide brokerage services in this state to register as brokers with the commission and to comply with customer protection provisions established by the commission and Chapters 17 and 39 of PURA and which requires the commission to adopt rules as necessary to implement the section.

Cross reference to statutes: Public Utility Regulatory Act §§14.002 and 39.3555.

§25.486.Customer Protections for Brokerage Services.

(a) Applicability. This section applies to all brokers.

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

(1) Broker--As defined in §25.112 of this title (relating to Registration of Brokers).

(2) Brokerage services--As defined in §25.112 of this title.

(3) Client--A person who receives or solicits brokerage services from a broker.

(4) Client agent--A broker who has the legal right and authority to act on behalf of a client regarding the selection of, enrollment for, or contract execution of a product or service offered by a retail electric provider (REP), including electric service.

(5) Proprietary client information--Any information that is compiled by a broker on a client that makes possible the identification of any individual client by matching such information with the client's name, address, retail electric account number, type or classification of retail electric service, historical electricity usage, expected patterns of use, types of facilities used in providing service, individual retail electric or brokerage services contract terms and conditions, price, current charges, billing records, or any information that the client has expressly requested not be disclosed. Information that is redacted or organized in such a way as to make it impossible to identify the client to whom the information relates does not constitute proprietary client information.

(c) Voluntary alteration of customer protections. A client other than a residential or small commercial class customer or applicant, or a non-residential customer or applicant whose load is part of an aggregation in excess of 50 kilowatts, may agree to a different level of customer protections than is required by this section. Any agreements containing a different level of protections from those required by this section must be memorialized on paper or electronically and provided to the client. Copies of such agreements must be provided to commission staff upon request.

(d) Broker communications.

(1) All written, electronic, and oral communications, including advertising, websites, direct marketing materials, and billing statements produced by a broker must be clear and not misleading, fraudulent, unfair, deceptive, or anti-competitive. Prohibited communications include, but are not limited to:

(A) stating, suggesting, implying or otherwise leading a client to believe that receiving brokerage services will provide a customer with more reliable service from a transmission and distribution utility (TDU);

(B) falsely suggesting, implying or otherwise leading a client to believe that a person is a representative of a TDU, REP, aggregator, or another broker;

(C) falsely stating or suggesting that brokerage services are being provided without compensation; and

(D) falsely claiming to be the client agent of a customer.

(2) All printed advertisements, electronic advertising over the Internet, and websites must include the broker's registered name.

(e) Language requirements. A broker must provide customer service and any information required by this section to a client in the language used to market the broker's products and services to that client.

(f) Required disclosures. A broker must inform a client of the following prior to the initiation of brokerage services:

(1) the broker's registered name, business mailing address, and contact information;

(2) the broker's commission registration number;

(3) the registered name of any REP that is an affiliate of the broker;

(4) a clear description of the services the broker will provide for the client. If the broker will provide services for the client that have not been identified prior to the initiation of brokerages services, the broker must provide a description of those services to the client before the client is obligated to provide compensation for the provision of those services;

(5) the duration of the agreement to provide brokerage services, if applicable;

(6) a description of how the broker will be compensated for providing brokerage services and by whom; if the broker is compensated directly by the client, the broker must disclose the details of the compensation;

(7) how the client can terminate the agreement to provide brokerage services, if applicable;

(8) the amount of any fee or other cost the client will incur for terminating the agreement to provide brokerage services, if applicable; and

(9) the commission's telephone number and email address for complaints and inquiries.

(g) Client agent requirements.

(1) An agreement between a broker and a client that authorizes the broker to act as a client agent for the client must be memorialized on paper or electronically.

(2) In addition to the requirements of subsection (f) of this section, a broker that acts as a client agent for the client must inform the client of the following:

(A) a clear description of the actions the broker is authorized to take on the client's behalf;

(B) the duration of the agency relationship;

(C) how the client can terminate the agency agreement;

(D) the amount of any fee or other cost the client will incur for terminating the agency agreement; and

(E) how the client's customer data and account access information will be used, protected, and retained by the broker and disposed of at the conclusion of the agency relationship.

(3) A broker that is authorized to act as a client agent for the client must provide evidence of that authority upon request of the client, commission staff, or a REP with which the broker seeks to enroll the client.

(h) Broker enrollments. A broker that is not an agent of a REP under §25.471(d)(10) of this title (relating to General Provisions of Customer Protection Rules) may enter into an agreement with a REP to assume all or part of the REP's responsibilities under §25.474 of this title (relating to Selection of Retail Electric Provider) for the purpose of enrolling applicants or customers for retail electric service. A broker that assumes the responsibilities of a REP under §25.474 must comply with the requirements of §25.474. A REP that enters into an agreement with a broker to assume all or part of the REP's responsibilities under §25.474 remains accountable under §25.107(a)(3) of this title (relating to Certification of Retail Electric Providers) for compliance with all applicable laws and commission rules for all activities conducted by the broker related to those responsibilities. An agreement between a REP and a broker under this subsection must be memorialized on paper or electronically and provided to the commission upon request.

(i) Discrimination prohibited. A broker must not refuse to provide brokerage services or otherwise discriminate in the provision of brokerage services to any client because of race, creed, color, national origin, ancestry, sex, marital status, source or level of income, disability, or familial status; or refuse to provide brokerage services to a client because the client is located in an economically distressed geographic area or qualifies for low-income affordability or energy efficiency services; or otherwise unreasonably discriminate on the basis of the geographic location of a client.

(j) Proprietary client information.

(1) A broker must not release proprietary client information to any person unless the client authorizes the release in writing on paper or electronically. This prohibition does not apply to the release of such information to:

(A) the commission;

(B) the Office of Public Utility Counsel, upon request under PURA §39.101(d); or

(C) a REP or TDU as necessary to complete a required market transaction, under terms approved by the commission.

(2) A broker is not permitted to sell, make available for sale, or authorize the sale of any client-specific information or data obtained unless the client authorizes the sale in writing on paper or electronically.

(k) Customer service and complaint handling.

(1) Client access. Each broker must ensure that clients have reasonable access to its service representatives to make inquiries and complaints, discuss charges on bills, terminate service, and transact any other pertinent business. A broker must promptly investigate client complaints and advise the complainant of the results. A broker must inform the complainant of the commission's informal complaint resolution process and the following contact information for the commission: Public Utility Commission of Texas, Customer Protection Division, P.O. Box 13326, Austin, Texas 78711-3326; (512) 936-7120 or in Texas (toll-free) 1-888-782-8477, fax (512) 936-7003, e-mail address: customer@puc.texas.gov, Internet website address: www.puc.texas.gov, TTY (512) 936-7136, and Relay Texas (toll-free) 1-800-735-2989.

(2) Complaint handling. A client has the right to make a formal or informal complaint to the commission. A broker may not use a written or verbal agreement with a client to impair this right for a client that is a residential or small commercial customer. A broker must not require a client that is a residential or small commercial customer to engage in alternative dispute resolution, including requiring complaints to be submitted to arbitration or mediation by third parties.

(3) Informal complaints.

(A) A person may file an informal complaint with the commission by contacting the commission at: Public Utility Commission of Texas, Customer Protection Division, P.O. Box 13326, Austin, Texas 78711-3326; (512) 936-7120 or in Texas (toll-free) 1-888-782-8477, fax (512) 936-7003, e-mail address: customer@puc.texas.gov, Internet website address: www.puc.texas.gov, TTY (512) 936-7136, and Relay Texas (toll-free) 1-800-735-2989.

(B) A complaint should include the following information, as applicable:

(i) the complainant's name, billing and service address, telephone number and email address, if any;

(ii) the name of the broker;

(iii) the broker's registration number;

(iv) the name of any relevant REP;

(v) the customer account number or electric service identifier;

(vi) an explanation of the facts relevant to the complaint;

(vii) the complainant's requested resolution; and

(viii) any documentation that supports the complaint.

(C) The commission will forward the informal complaint to the broker.

(D) The broker must investigate each informal complaint forwarded to the broker by the commission and advise the commission in writing on paper or electronically of the results of the investigation within 21 days after the complaint is forwarded to the broker by the commission.

(E) The commission will review the complaint information and the broker's response and notify the complainant of the results of the commission's investigation.

(F) The broker must keep a record for two years after receiving notification by the commission that the complaint has been closed. This record must show the name and address of the complainant, the date, nature and adjustment or disposition of the complaint.

(4) Formal complaints. If the complainant is not satisfied with the results of the informal complaint process, the complainant may file a formal complaint with the commission within two years of the date on which the commission closes the informal complaint. Formal complaints will be docketed as provided in the commission's procedural rules.

(l) Record retention.

(1) A broker must establish and maintain records and data that are sufficient to:

(A) verify its compliance with the requirements of any applicable commission rules; and

(B) support any investigation of customer complaints.

(2) All records required by this section must be retained for no less than two years, unless otherwise specified.

(3) Unless otherwise prescribed by the commission or its authorized representative, all records required by this subchapter must be provided to the commission within 15 calendar days of its request.

The agency certifies that legal counsel has reviewed the proposal and found it to be within the state agency's legal authority to adopt.

Filed with the Office of the Secretary of State on November 15, 2019.

TRD-201904274

Andrea Gonzalez

Rules Coordinator

Public Utility Commission of Texas

Earliest possible date of adoption: December 29, 2019

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


PART 4. TEXAS DEPARTMENT OF LICENSING AND REGULATION

CHAPTER 70. INDUSTRIALIZED HOUSING AND BUILDINGS

16 TAC §§70.22 - 70.25, 70.30, 70.60, 70.70, 70,73, 70.101

The Texas Department of Licensing and Regulation (Department) proposes amendments to existing rules at 16 Texas Administrative Code (TAC), Chapter 70, §§70.22 - 70.25, 70.30, 70.60, 70.70, 70.73, and 70.101, regarding the Industrialized Housing and Buildings Program. These proposed changes are referred to as "proposed rules."

EXPLANATION OF AND JUSTIFICATION FOR THE RULES

The rules under 16 TAC, Chapter 70 implement Texas Occupations Code, Chapter 1202, Industrialized Housing and Buildings (IHB).

The proposed rules are necessary to implement House Bill (HB) 1385 and HB 2546, 86th Legislature, Regular Session (2019) and make clean-up and clarification changes.

HB 1385 Changes

HB 1385 removed the height limit for industrialized housing and buildings regulated by the Department. The proposed rules are necessary to ensure the safety of the public as structures taller than four stories or 60 feet are now regulated by the Department. Specifically, the proposed rules ensure that persons who perform design review or inspections have necessary expertise in fire safety. The proposed rules also require builders who install structures taller than 75 feet to be registered with the Department as industrialized builders, rather than obtaining installation or alteration permits, so that the Department is better able to ensure that all necessary inspections are performed. In addition, the proposed rules remove an exemption that conflicts with the changes made by HB 1385. The proposed rules also require manufacturers to complete a certification update if they wish to construct modules or modular components that are outside the scope of their existing certification. This change is necessary to ensure that modules and modular components for new projects, such as taller structures that were not previously under the Department's regulation, will be constructed in accordance with the mandatory building codes. Furthermore, the proposed rules extend the deadline for completing work to 365 days for structures built to a code other than the International Residential Code (IRC), giving builders more time to complete more complex structures.

Additionally, the proposed rules update the site inspection requirements to account for taller, more complex structures built under the Department's program. The proposed rules do not create additional inspection requirements, but better describe the existing requirements so that they apply to all industrialized housing and buildings regulated by the Department. For example, the proposed rules delete existing language stating that on-site inspections are normally completed in three phases, as this is not true for taller and more complex structures. The proposed rules explicitly require all inspections required by the mandatory building codes, including special inspections, which may be required for taller structures. The proposed rules also require that special inspections be conducted by persons who are approved by the Industrialized Housing and Buildings Code Council (Council) and require Department approval in order to change the person or agency once the special inspection has already begun. These changes are necessary to ensure that taller structures are adequately inspected.

HB 2546 Changes

HB 2546 gives manufacturers and builders the option to construct single-family industrialized housing in accordance with certain local amendments to the statewide energy code in Texas for single-family residential construction. Those local amendments or alternative compliance paths must be requested by a municipality, county, or group of counties in the climate zone where the housing will be located and must be determined by the Energy Systems Laboratory at Texas A&M University to be equally or more stringent than the statewide energy code. The bill also required manufacturers and builders to make available all documentation necessary to evaluate the industrialized housing.

The proposed rules require manufacturers to send design review agencies information on the local amendments or alternative compliance paths to which the manufacturer will construct a modular home. This is necessary to enable the design review agency to properly review the plans for the home. The proposed rules also add an amendment to the mandatory building codes to allow single-family housing to be constructed in accordance with the local amendments and alternative compliance paths that are authorized by HB 2546.

Clean-up and Clarification Changes

The proposed rules also include several changes designed to make the rules easier to understand by adding a new subsection to the amendments to the mandatory building codes, in order to clarify that electrical tests must be performed on modular buildings as well as homes. These tests are already required in the current rules, but there is some confusion because the current rules reference a section of the National Electrical Code (NEC) which pertains to manufactured housing. By adding a new Article 545.14 to the NEC, the proposed rules will make it clearer that electrical testing is to be performed on both housing and buildings.

The proposed rules also use new language to clarify which buildings are exempt from site inspections, as the proposed language is more precise than the existing language and may lessen any confusion about which buildings do not require site inspections. Additionally, the proposed rules clarify that the prohibition on destructive disassembly applies only to modules or modular components completed in the plant and certified by a Department-issued decal or insignia. This is necessary as projects may include a mixture of modular and site-built construction.

The proposed rules also make clean-up changes, including incorporating third-party inspection agencies into the rule regarding site inspections, and changing the description of how violations and corrective actions must be documented. The new description of how to document violations gives the Department flexibility to prescribe new, more efficient methods of documentation in the future. The clean-up change adding third-party inspection agencies is necessary because the agencies are already involved, through their inspectors, in the site inspection process.

The proposed rules were presented to six members of the Texas Industrialized Building Code Council (Council) on October 29, 2019. There were fewer than a quorum of members present, so the Council did not vote on the proposed rules. However, the Council members who were present did have an opportunity to discuss the proposed rules and make changes. The Council members did not have any changes, but after the meeting, staff made non-substantive changes to the proposed §70.101 to make the proposed rule amendments easier to understand.

SECTION-BY-SECTION SUMMARY

The proposed rules amend §70.22 by requiring fire safety reviewers to have International Code Council (ICC) certification as a fire plans examiner.

The proposed rules amend §70.23 to require ICC fire inspector certifications for various third-party inspection agency personnel. Specifically, the third-party inspection agency supervisor of inspections must have ICC certification as a fire inspector I. Inspectors who perform in-plant inspections of modules or modular components that will be part of a project over 75 feet must have ICC certification as a fire inspector I and inspectors who perform installation inspections of a project over 75 feet must have ICC certification as a fire inspector II.

The proposed rules amend §70.24 by requiring third-party site inspectors who perform installation inspections of industrialized housing or buildings taller than 75 feet to have ICC certification as a fire inspector II.

The proposed rules amend §70.25 by prohibiting installation permits or alteration permits for structures that are taller than 75 feet.

The proposed rules amend §70.30 by removing an exemption for structures that are taller than 4 stories or 60 feet. The proposed amendments also renumber the subsection accordingly.

The proposed rules amend §70.60 by requiring a manufacturer, who wishes to construct modules or modular components outside the scope of the manufacturer's current certification, to complete a certification update inspection for the aspects of construction for which the manufacturer is not currently certified.

The proposed rules amend §70.70 by: (1) requiring manufacturers to send design review agencies any local amendments or alternative compliance paths, to which the manufacturer will construct a modular home; and (2) referring to a new section of the NEC, which is added in §70.101 of the proposed rules, and specifying the electrical tests that must be performed on industrialized houses and buildings.

The proposed rules amend §70.73 by:

-removing language stating that on-site inspections are normally accomplished in three phases, and instead explicitly requiring all inspections required by certain codes (the IBC, IMC, IPC, IFC, IFGC, IECC, IFC, and IRC), special inspections required by the IBC, a set inspection, and a final inspection;

-requiring that special inspections be conducted by persons who are approved by the Council and meet all applicable requirements;

-requiring Department approval to change the inspector or agency once the special inspection has already begun;

-providing a longer deadline for completion (365 days) for structures that are built to a code other than the IRC;

-clarifying which structures are exempt from site inspections;

-clarifying that the prohibition on destructive disassembly during site inspections applies only to modules or modular components completed in a plant and certified by a Department-issued decal or insignia;

-changing the word "assuring" to "ensuring" as this wording may be clearer;

-adding inspection agencies as persons who may be contacted to schedule inspections;

-adding that an industrialized builder or installation permit holder may not change the inspection agency for a project once started without written approval from the Department;

-requiring inspection violations and corrective actions to be documented in accordance with Council procedures, rather than on a specific form.

The proposed rules amend §70.101(h)(5) to allow single-family industrialized housing to be built in accordance with the energy code with any local amendments or alternative compliance paths that are requested by a municipality, county, or group of counties located in the climate zone where the house will be located and are determined by the Texas Energy Systems Laboratory to be equally or more stringent than the energy code adopted by the State Energy Conservation Office (SECO). The proposed amendments also renumber the subsection accordingly.

The proposed rules amend §70.101(j) by adding a new section of the NEC, specifying which electrical tests must be performed on industrialized housing and buildings.

FISCAL IMPACT ON STATE AND LOCAL GOVERNMENT

Tony Couvillon, Policy Research and Budget Analyst, has determined that for each year of the first five years the proposed rules are in effect, there are no estimated additional costs or reductions in costs, or increase or loss in revenue, to state government as a result of enforcing or administering the proposed rules. The activities required to implement the proposed rule changes, if any, are one-time program administration tasks that are routine in nature. This will not result in an increase in program costs. Additionally, the proposed rules do not decrease program costs as they do not remove any activities performed by the Department that would cause a decrease in personnel or resources. Also, the proposed rules do not amend or impact the fees assessed by the licensing program, so the proposed rules do not increase or decrease the revenue to the State.

Mr. Couvillon has determined that for each year of the first five years the proposed rules are in effect, there is no estimated increase in costs to local governments as a result of enforcing or administering the proposed rules. There is no increase in local governments' responsibilities related to the regulation of industrialized housing and buildings.

Mr. Couvillon has determined that for each year of the first five years the proposed rules are in effect, there may be a reduction in costs to local governments as a result of enforcing or administering the proposed rules. The proposed rules implement legislation which removed the height limits for modular construction regulated by the Department. Therefore, the Department rather than local jurisdictions will now oversee inspections of manufacturing facilities that construct high-rise buildings. This may reduce local governments' costs of inspecting manufacturing facilities. However, this reduction cannot be estimated because the number of inspections that local governments will no longer need to perform cannot be estimated.

Mr. Couvillon has determined that for each year of the first five years the proposed rules are in effect, there is no estimated increase or loss in revenue to local governments as a result of enforcing or administering the proposed rules. The proposed rules do not affect the amounts local governments may collect for permits or site inspections of buildings.

LOCAL EMPLOYMENT IMPACT STATEMENT

Mr. Couvillon has determined that the proposed rules will not affect the local economy, so the agency is not required to prepare a local employment impact statement under Government Code §2001.022. Although the proposed rules might lead to more high-rise buildings being built through modular construction, the number of people needed to construct a modular building would not vary greatly from the number needed to construct a site-built building. Additionally, even if fewer workers are needed to construct a modular high-rise building than the number needed for a site-built high-rise building, that might be offset by more modular buildings being constructed.

PUBLIC BENEFITS

Mr. Couvillon also has determined that for each year of the first five-year period the proposed rules are in effect, the public benefit will be increased access to modular housing and buildings. Modular housing and buildings provide significant cost savings related to the timely construction process using a factory as opposed to site building, which is subject to delays not found in a production environment. The public will also benefit from the construction of safe high-rise modular buildings that are designed, constructed, and inspected to comply with the International Fire Code. Additionally, clarifying and clean-up amendments will help licensees and the public to understand the applicable rules and requirements.

PROBABLE ECONOMIC COSTS TO PERSONS REQUIRED TO COMPLY WITH PROPOSAL

Mr. Couvillon has determined that for each year of the first five-year period the proposed rules are in effect, there are no anticipated economic costs to persons who are required to comply with the proposed rules. There may be minimal costs to licensees for fire inspection and plan reviewer certifications. However, these certifications can be used as continuing education for other certifications which are already required, thereby minimizing or even offsetting the cost.

FISCAL IMPACT ON SMALL BUSINESSES, MICRO-BUSINESSES, AND RURAL COMMUNITIES

There will be no adverse effect on small businesses, micro-businesses, or rural communities as a result of the proposed rules. The proposed rules do not impose additional fees on any licensee or small or micro-business. Any additional costs are voluntary and could be offset by cost reductions in other areas. Additionally, the proposed rules will have no anticipated adverse economic effect on rural communities because the rules will not decrease the availability of licensees in rural communities, nor will the rules increase the cost of licensee services in rural communities.

Since the agency has determined that the proposed rules will have no adverse economic effect on small businesses, micro-businesses, or rural communities, preparation of an Economic Impact Statement and a Regulatory Flexibility Analysis, as detailed under Texas Government Code §2006.002, are not required.

ONE-FOR-ONE REQUIREMENT FOR RULES WITH A FISCAL IMPACT

The proposed rules do not have a fiscal note that imposes a cost on regulated persons, including another state agency, a special district, or a local government. Therefore, the agency is not required to take any further action under Government Code §2001.0045.

GOVERNMENT GROWTH IMPACT STATEMENT

Pursuant to Government Code §2001.0221, the agency provides the following Government Growth Impact Statement for the proposed rules. For each year of the first five years the proposed rules will be in effect, the agency has determined the following:

1. The proposed rules do not create or eliminate a government program.

2. Implementation of the proposed rules does not require the creation of new employee positions or the elimination of existing employee positions.

3. Implementation of the proposed rules does not require an increase or decrease in future legislative appropriations to the agency.

4. The proposed rules do not require an increase or decrease in fees paid to the agency.

5. The proposed rules do not create a new regulation.

6. The proposed rules do expand, limit, or repeal an existing regulation. The proposed rules expand regulations related to fire safety and alternative energy codes in order to implement legislation. Language regarding reviews, inspections, and permits for high-rise construction is added consistent with the International Building Code, which identifies high-rise buildings as 75 feet and above. The proposed rules also expand a regulation to implement new legislation related to energy code compliance for single-family modular residential construction. Additionally, clarifying language is added to ensure better understanding and compliance with existing rule requirements. The proposed rules also limit an existing regulation. Recent legislation removed height limits on modular construction which is regulated by the Department. The corresponding rule language has been removed.

7. The proposed rules do not increase or decrease the number of individuals subject to the rule's applicability.

8. The proposed rules do not positively or adversely affect this state's economy.

TAKINGS IMPACT ASSESSMENT

The Department has determined that no private real property interests are affected by the proposed rules and the proposed rules do not restrict, limit, or impose a burden on an owner's rights to his or her private real property that would otherwise exist in the absence of government action. As a result, the proposed rules do not constitute a taking or require a takings impact assessment under Government Code §2007.043.

PUBLIC COMMENTS

Comments on the proposed rules may be submitted to Vanessa Vasquez, Legal Assistant, Texas Department of Licensing and Regulation, P.O. Box 12157, Austin, Texas 78711, or facsimile (512) 475-3032, or electronically: erule.comments@tdlr.texas.gov. The deadline for comments is 30 days after publication in the Texas Register.

STATUTORY AUTHORITY

The proposed rules are proposed under Texas Occupations Code, Chapters 51 and 1202 which authorize the Texas Commission of Licensing and Regulation, the Department's governing body, to adopt rules as necessary to implement these chapters and any other law establishing a program regulated by the Department.

The statutory provisions affected by the proposed rules are those set forth in Texas Occupations Code, Chapters 51 and 1202. No other statutes, articles, or codes are affected by the proposed rules.

§70.22.Criteria for Approval of Design Review Agencies.

(a) - (b) (No change.)

(c) The minimum personnel requirements and qualifications shall be as follows.

(1) (No change.)

(2) Technical staff members may qualify for more than one discipline. The agency does not need to have an individual staff member for each discipline. The technical staff shall consist of the following positions.

(A) - (E) (No change.)

(F) The fire safety reviewer shall have:

(i) - (ii) (No change.)

(iii) certification as a fire [building] plans examiner as granted by ICC.

(G) (No change.)

(3) (No change.)

§70.23.Criteria for Approval of Third Party Inspection Agencies and Inspectors.

(a) - (b) (No change.)

(c) The minimum personnel requirements and qualifications are as follows.

(1) (No change.)

(2) The supervisor of inspections shall have:

(A) - (B) (No change.)

(C) certification as a fire inspector II as granted by ICC; and

(D) [(C)] certification as a residential energy inspector/plans examiner as granted by ICC, as a commercial energy inspector as granted by ICC, and as:

(i) - (iii) (No change.)

(3) (No change.)

(4) An inspector who performs an in-plant inspection of modules or modular components that will be part of a housing or building project over 75 feet in height must also have ICC certification as a fire inspector I or II.

(5) An inspector who performs an installation inspection of industrialized housing or buildings over 75 feet in height must also have ICC certification as a fire inspector II.

§70.24.Criteria for Approval of Third Party Site Inspectors.

(a) (No change.)

(b) The minimum qualifications for a third party site inspector are as follows:

(1) (No change.)

(2) a minimum of three years experience in building code enforcement, building inspections, or building experience. At least one year of experience shall be in the performance of building inspections; [and]

(3) one of the following energy code certifications: certification as a residential energy inspector/plans examiner, as a commercial energy inspector, or both. The inspector must have a residential energy certification to inspect housing and a commercial energy certification to inspect buildings; [.]

(4) one of the following code certification combinations:

(A) - (B) (No change.)

(C) a combination inspector as granted by ICC. In lieu of a combination inspector the inspector may have one of each of the individual certifications that are needed for certification as a combination inspector. Inspectors with this certification may perform site inspections for any industrialized housing, buildings, or site-built REFs; and[.]

(5) ICC certification as a fire inspector II if the inspector will perform installation inspections of industrialized housing or buildings over 75 feet in height.

§70.25.Permits.

(a) General.

(1) - (4) (No change.)

(5) An installation permit or alteration permit shall not be issued for a structure that is taller than 75 feet in height.

(b) - (d) (No change.)

§70.30.Exemptions.

(a) The scope of this chapter is limited by Chapter 1202; accordingly, it does not apply to:

(1) - (3) (No change.)

[(4) any residential or commercial structure which is in excess of four stories or 60 feet in height;]

(4) [(5)] a commercial building or structure that is:

(A) installed in a manner other than on a permanent foundation; and

(B) either:

(i) is not open to the public; or

(ii) is less than 1,500 square feet in total area and used other than as a school or a place of religious worship;

(5) [(6)] buildings that are specifically referenced in the mandatory building codes as exempt from permits; or

(6) [(7)] construction site buildings.

(b) (No change.)

§70.60.Responsibilities of the Department--Plant Certification.

(a) - (h) (No change.)

(i) A manufacturer that wishes to construct modules or modular components outside the scope of the manufacturer's certification must successfully complete a certification update inspection for the aspects of construction for which the manufacturer is not currently certified.

(j) [(i)] If the department determines that the manufacturer is not capable of meeting the certification requirements or that the manufacturer is unable to complete the certification inspection requirements, then the certification team will issue a non-compliance report. The non-compliance report will detail the specific areas in which the manufacturer was found to be deficient and may make recommendations for improvement.

(k) [(j)] If any personnel of a design review agency or third party inspection agency participate as members of a certification team, the agency is considered a participant in the certification team and is responsible for compliance with Texas Occupations Code, Chapter 1202, rules adopted by the commission, and decision, actions, and interpretations of the council in performing the certification, inspection and related activities.

§70.70.Responsibilities of the Registrants--Manufacturer's Design Package and REF Builder's Construction Documents.

(a) (No change.)

(b) In-plant documentation for manufacturers and construction documents for REF builders. The manufacturer and REF builder shall provide the DRA the documentation necessary to demonstrate compliance with the mandatory building codes in §70.100 and §70.101. At a minimum the documentation shall include the following:

(1) - (8) (No change.)

(9) energy compliance details, including any local amendments or alternative compliance paths to which the structure will be constructed under Occupations Code, Section 1202.1536;

(10) - (20) (No change.)

(c) Compliance control program for manufacturers. The utilization of mass production techniques and assembly line methods in the construction of industrialized housing, buildings, modules, and modular components along with the fact that a large part of such construction cannot be inspected at the ultimate building site, requires manufacturers to develop an adequate compliance control program to assure that these structures meet or exceed mandatory code requirements and are in compliance with the rules and regulations of this chapter. The compliance control program shall be documented in the form of a manual that must be approved by the design review agency. A 100% inspection of the construction of industrialized housing or buildings may be authorized in lieu of a compliance control program and certification of the manufacturer in accordance with §70.60. The manufacturer shall provide the design review agency a compliance control manual that must, at the minimum, contain the following:

(1) - (8) (No change.)

(9) step-by-step test procedures, a description of the station at which each production test is performed, a description of required testing equipment, and procedures for periodic checking, recalibration, and readjustment of test equipment. Procedures shall be included for, but not limited to, electrical tests as specified in the National Electrical Code, Article 545-14 [550-17], gas supply pressure tests, water supply pressure tests, drain-waste-vent system tests, concrete slump tests, and concrete strength tests;

(10) - (14) (No change.)

(d) - (f) (No change.)

§70.73.Responsibilities of the Registrants--Building Site Construction and Inspections.

(a) - (b) (No change.)

(c) Responsibility for on-site construction. The industrialized builder or installation permit holder shall be responsible for assuring that the foundation and the installation of an industrialized house, building, or site-built REF complies with the manufacturer's or REF builder's on-site construction specifications or documentation that have been approved in accordance with §70.70 [of this chapter], any unique on-site construction details, the engineered foundation design, and the mandatory building codes.

(d) - (e) (No change.)

(f) Responsibility for inspections outside the jurisdiction of a municipality or within a municipality without a building inspection agency or department. When the building site is outside a municipality, or within a municipality that has no building department or agency, a council-approved inspector will perform the required inspections in accordance with this section and the inspection procedures established by the council to assure completion and attachment in accordance with the documents approved in accordance with §70.70, the mandatory building codes, the foundation system drawings, and any unique on-site construction detail drawings.

(1) Minimum inspection requirements are listed below. Re-inspections are required whenever deviations from the approved construction documents or mandatory building codes are noted. Inspections may occur concurrently. The industrialized builder or installation permit holder shall ensure that work is not concealed prior to the inspection.

(A) Inspections completed during installation shall be as required by the inspection requirements of Chapter 1 of the IBC, IMC, IPC, IFC, IFGC, IECC, IFC, and IRC as applicable.

(B) A set inspection shall be completed for each module set or for each modular component installed.

(C) Special inspections shall be completed as required per Chapter 17 of the IBC.

(D) A final inspection shall be made after all construction and all corrections are complete.

[(1) The on-site inspection is normally accomplished in three phases: foundation inspection, set inspection, and final inspection. The foundation inspection shall be performed before the concrete is poured.]

(2) For structures built in accordance with the IRC, the [The] final inspection shall be completed within 180 days of the start of construction. For all other structures, the final inspection shall be completed within 365 days of the start of construction. The department may grant an extension upon receipt of a written request that demonstrates a justifiable cause.

(3) Site inspections are required for the first installation of all industrialized housing and permanent industrialized buildings. Exception: Site inspections are not required for the installation of equipment buildings or shelters where the structure is occupied only during installation and maintenance of the equipment housed in the structure, unless the structure is [unoccupied industrialized buildings not open to the public, such as communication equipment shelters, that are not] also classified as a hazardous occupancy by the mandatory building code.

(4) (No change.)

(5) The industrialized builder, or installation permit holder, is responsible for scheduling each phase of the inspection with the inspector or inspection agency and for ensuring that all inspections have been completed. [Additional inspections will be scheduled as required for larger structures and to correct violations.]

(A) The industrialized builder, or installation permit holder, may utilize a different inspector or inspection agency for different projects, but may not change the inspector or agency for a project once started without the written approval of the department.

(B) Special inspections required by the mandatory building codes shall be conducted by persons who are approved in accordance with Council procedures and meet the qualification requirements outlined in Chapter 17 of the IBC or as required by applicable State laws. Persons or agencies that perform special inspections may not be changed once the inspection has begun without approval from the department.

(6) The inspector shall give the industrialized builder or installation permit holder a copy of the site inspection report upon completion of each inspection including re-inspections. Violations shall be documented in accordance with the Council approved inspection procedures [on the Violations Report form]. The industrialized builder or installation permit holder is responsible for ensuring [assuring] that all violations are corrected.

(7) The industrialized builder, or installation permit holder, shall not permit occupancy, or release the house or building for occupation, until a successful final inspection has been completed. A final on-site inspection report shall be issued showing no outstanding violations prior to occupation, or release for occupation, of the house or building. Exception: Occupancy of the house or building may be permitted and approved with outstanding items provided that the items are not in violation of the mandatory building codes.

(A) The industrialized builder or installation permit holder shall maintain a copy of the on-site inspection reports in accordance with the requirements of §70.50 and make a copy of all on-site inspection reports available to the department upon request. The reports shall include a list of all violations and corrective action in accordance with the inspection procedures approved by the council. [documented on the Violations Report form.]

(B) - (C) (No change.)

(g) Destructive disassembly shall not be performed at the site in order to conduct tests or inspections on the modules or modular components completed in the plant and certified by the decal or insignia attached by the manufacturer, nor shall there be imposed standards or test criteria different from those required by the approved installation instructions, on-site construction documentation, and the applicable mandatory building code. Nondestructive disassembly may be performed only to the extent of opening access panels and cover plates.

(h) - (j) (No change.)

§70.101.Amendments to Mandatory Building Codes.

(a) - (g) (No change.)

(h) The 2015 International Energy Conservation Code shall be amended as follows.

(1) - (4) (No change.)

(5) Add new item 4 to Section R401.2 Compliance to read as follows: "Alternative for single-family housing only. A manufacturer or builder may choose to use the energy code with any local amendments or alternative compliance paths that are requested by a municipality, county, or group of counties located in the climate zone where the house will be located and are determined by the Texas Energy Systems Laboratory to be equally or more stringent than the energy code adopted by the State Energy Conservation Office (SECO).

(6) [(5)] Add new Section C501.7 Moved buildings to add the following sentence: "Moved industrialized buildings that bear approved certification decals or insignia, and that may also bear an alteration decal, in accordance with the requirements of Texas Occupations Code, Chapter 1202 and 16 Texas Administrative Code, Chapter 70, and that have not been altered or modified since the decal, insignia, or alteration decal was attached, shall be considered to be in compliance with the current mandatory building codes adopted by the Texas Industrialized Building Code Council."

(7) [(6)] Amend Chapter C6 Referenced Standards and Chapter R6 Referenced Standards as follows.

(A) Add to Chapter C6 PNNL/DOE, Pacific Northwest National Laboratory/Department of Energy Conservation, https://www.energycodes.gov/software-and-webtools, as a promulgating agency, COMcheck Version 4.0.5.2 or later, Commercial Energy Compliance Software as the referenced standard, and section C102.1.2 as the referenced code section.

(B) Add to Chapter R6 PNNL/DOE, Pacific Northwest National Laboratory/Department of Energy Conservation, https://www.energycodes.gov/software-and-webtools, as a promulgating agency, REScheck Version 4.6.3 or later, Residential Energy Compliance Software as the referenced standard, and section R102.1.2 as the referenced code section.

(C) Add to Chapter R6 the Texas Energy Systems Laboratory, 402 Harvey Mitchell Parkway South, College Station, TX 77845-3581, as a promulgating agency, IC3, v 3.10 or later, International Code Compliance Calculator as the referenced standard, and section R102.1.2 as the referenced code section.

(i) (No change.)

(j) The 2014 National Electrical Code shall be amended as follows.

(1) Add [to add] the following to Article 310.1 Scope: "Aluminum and copper-clad aluminum shall not be used for branch circuits in buildings classified as a residential occupancy. Aluminum and copper-clad aluminum conductors, of size number 4 AWG or larger, may be used in branch circuits in buildings classified as occupancies other than residential."

(2) Add new Article 545.14, Testing, to read as follows.

(A) "(A) Dielectric Strength Test. The wiring of each modular house, building, or component shall be subjected to a 1-minute, 900-volt, dielectric strength test (with all switches closed) between live parts (including neutral conductor) and the house, building, or component ground. Alternatively, the test shall be permitted to be performed at 1080 volts for 1 second. This test shall be performed after branch circuits are complete and after luminaires or appliances are installed. Exception: Listed luminaires or appliances shall not be required to withstand the dielectric strength test. Exception: A DC dielectric tester can be used as an alternate to the use of an AC dielectric tester. The applied test voltage for testing with a DC tester shall be 1.414 times the value of the equivalent AC test voltage."

(B) "Continuity and Operational Tests and Polarity Checks. Each modular house, building, or component shall be subjected to all of the following: (1) An electrical continuity test to ensure that all exposed electrically conductive parts are properly bonded; (2) An electrical operational test to demonstrate that all equipment, except water heaters and electric furnaces, are connected and in working order; (3) Electrical polarity checks of permanently wired equipment and receptacle outlets to determine that connections have been properly made."

The agency certifies that legal counsel has reviewed the proposal and found it to be within the state agency's legal authority to adopt.

Filed with the Office of the Secretary of State on November 15, 2019.

TRD-201904312

Brad Bowman

General Counsel

Texas Department of Licensing and Regulation

Earliest possible date of adoption: December 29, 2019

For further information, please call: (512) 463-3671