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TITLE 16ECONOMIC REGULATION
PART 2PUBLIC UTILITY COMMISSION OF TEXAS
CHAPTER 25SUBSTANTIVE RULES APPLICABLE TO ELECTRIC SERVICE PROVIDERS
SUBCHAPTER FMETERING
RULE §25.130Advanced Metering

(a) Purpose. This section addresses the deployment, operation, and cost recovery for advanced metering systems.

(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.

(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) Advanced Metering System (AMS) -- A system, including advanced meters and the associated hardware, software, and communications systems, including meter information networks, that collects time-differentiated energy usage and performs the functions and has the features specified in this section.

  (3) Deployment Plan -- An electric utility's plan for deploying advanced meters in accordance with this section and either filed with the commission as part of the Notice of Deployment or approved by the commission following a Request for Approval of Deployment.

  (4) Enhanced 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 secure, 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 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 file a statement of AMS functionality, and either a notice of deployment or a request for approval of deployment. An electric utility may request a surcharge under subsection (k) of this section in combination with a notice of deployment or a request for approval of deployment, or separately. A proceeding that includes a request to establish or amend a surcharge will be a ratemaking proceeding and a proceeding involving only a request for approval of deployment will not be a ratemaking proceeding.

  (3) The statement of AMS functionality must:

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

    (B) describe any variances between technologies and meter functions within the electric utility's 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 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) A schedule for deployment of web portal functionalities.

  (5) An electric utility must file with the 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, and the contracts for equipment and services associated with the deployment plan, that prove the reasonableness of the plan.

  (6) Competitively sensitive information contained in the 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 be maintained and made available for review on the electric utility's website. Competitively sensitive information contained in the deployment plan must 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 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 approve or disapprove the 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 not be unreasonably discriminatory, prejudicial, preferential, or anticompetitive.

  (9) Each electric utility must provide progress reports on a monthly basis following the filing of its deployment plan with the commission until deployment is complete. Upon filing of such reports, an electric utility operating in an area open to customer choice must notify all REPs of the filing through standard market notice procedures. A monthly progress report must be filed within 15 days of the end of the month to which it applies, and must 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. Additional deployment information if available must also be provided, 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 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 and any changes in deployment of these features.

  (10) If an electric utility has received approval of its deployment plan from the commission, the electric utility must obtain commission approval before making any changes to its AMS that would affect the 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 by filing a request for amendment to its deployment plan. In addition, an electric utility may request commission approval for other changes in its approved deployment plan. The commission will act upon the request for an amendment to the deployment plan within 45 days of submission of the request, unless good cause exists for additional time. If an electric utility filed a notice of deployment, the electric utility must file an amendment to its notice of deployment at least 45 days before making any changes to its AMS that would affect the 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 of 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 the system must 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 electric utility subject to §25.343 of this title (relating to Competitive Energy Services) must not provide any advanced metering equipment or service that is deemed a competitive energy service under that section. Any functionality of the AMS that is a required feature under this section or that is included in an approved deployment plan or otherwise approved by the commission 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 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 be sent by the electric utility to all REPs and all entities authorized by a customer to have read-only access to the customer's advanced meter data.

(g) AMS features.

  (1) An AMS must provide or support the following minimum system features:

    (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.

    (D) time-stamped meter data;

    (E) access to customer usage data by the customer, the customer's REP of record, and entities authorized by the customer provided that 15-minute interval or shorter data from the electric utility's AMS must be transmitted to the electric utility's or a group of electric utilities' web portal on a day-after basis;

    (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;

    (G) for an electric utility that provides access through an application programming interface, the capability to provide on-demand reads of a customer's advanced meter data, subject to network traffic such as interval data collection, market orders if applicable, and planned and unplanned outages;

    (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 or International Electrotechnical Commission (IEC) DLMS-COSEM standards;

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

    (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

Cont'd...

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