| (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... |
