Current through Reg. 50, No. 13; March 28, 2025
(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
(K) the
ability to upgrade these features as the need arises.
(2) A waiver from any of the requirements of
paragraph (1) of this subsection may be granted by the commission if it would
be uneconomic or technically infeasible to implement or there is an adequate
substitute for that particular requirement. The electric utility must meet its
burden of proof in its waiver request.
(3) 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) Once an electric utility has deployed its
advanced meters, it may add or enhance features provided by AMS, as technology
evolves. The electric utility must 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 follow the monthly progress
report process described in subsection (d)(9) of this section until the
enhancement process is complete.
(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.
(i) Tariff. All discretionary AMS features
offered by the electric utility must be described in the electric utility's
tariff.
(j) Access to meter data.
(1) A customer may authorize its meter data
to be available to an entity other than its REP. An electric utility must
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 be
convenient and secure, and the data must 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 provide access to the
data in the timeframe approved by the commission in either the deployment plan
or request for surcharge proceeding. If only a notice of deployment has been
filed, access to the data must begin no later than six months from the filing
of the notice of deployment with the commission.
(3) An electric utility's or group of
electric utilities' web portal must use appropriate and reasonable standards
and methods to provide secure access for the customer, the customer's REP of
record, and entities authorized by the customer to the meter data. The electric
utility must have an independent security audit conducted within one year of
providing that access to meter data. The electric utility must promptly report
the audit results to the commission.
(4) The independent organization, regional
transmission organization, or regional reliability entity must have access to
information that is required for wholesale settlement, load profiling, load
research, and reliability purposes.
(k) Cost recovery for deployment of AMS.
(1) Recovery Method. The commission will
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 not be established until after a detailed deployment plan is
filed under subsection (d) of this section. In addition, the surcharge must not
ultimately recover more than the AMS costs that are spent, reasonable and
necessary, and fully allocated, but may include estimated costs that will 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 not be included in the surcharge provided for by this
subsection unless an electric utility has received a waiver under subsection
(g)(2) of this section. The costs of providing AMS services include those costs
of AMS installed as part of a pilot program under this section. Costs of
providing AMS for a particular customer class must 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 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 be correspondingly adjusted to reflect the new
authorized WACC.
(3) Surcharge
Proceeding. In the request for surcharge proceeding, the commission will set
the surcharge based on a levelized amount, and an amortization period based on
the useful life of the AMS. 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, 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.
(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 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.
(5) Annual Reports. An electric utility must
file annual reports with the commission updating the cost information used in
setting the surcharge. The annual reports must 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 not be a
ratemaking proceeding, but an application by the electric utility to update the
surcharge must be a ratemaking proceeding.
(6) Reconciliation Proceeding. All costs
recovered through the surcharge must 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 or amended 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
be refunded to electric utility's customers. In addition, the commission will
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 be at the electric utility's
WACC and must begin at the time the under or over recovery occurred.
(7) Cross-subsidization and fees. The
electric utility must account for its costs in a manner that ensures 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.