|(a) Application. This section applies to all electric
utilities as defined by §25.5(41) of this title (relating to
Definitions) and all transmission and distribution utilities as defined
by §25.5(137) of this title. When specifically stated, this section
also applies to electric cooperatives and municipally-owned utilities
(MOUs). The term "utility" as used in this section means an electric
utility and a transmission and distribution utility.
(1) Every utility must make all reasonable efforts
to prevent interruptions of service. When interruptions occur, the
utility must reestablish service within the shortest possible time.
(2) Each utility must make reasonable provisions to
manage emergencies resulting from failure of service, and each utility
must issue instructions to its employees covering procedures to be
followed in the event of emergency in order to prevent or mitigate
interruption or impairment of service.
(3) In the event of national emergency or local disaster
resulting in disruption of normal service, the utility may, in the
public interest, interrupt service to other customers to provide necessary
service to civil defense or other emergency service entities on a
temporary basis until normal service to these agencies can be restored.
(4) Each utility must maintain adequately trained and
experienced personnel throughout its service area so that the utility
is able to fully and adequately comply with the service quality and
(5) With regard to system reliability, a utility must
not neglect any local neighborhood or geographic area, including rural
areas, communities of less than 1,000 persons, and low-income areas.
(c) Definitions. The following words and terms, when
used in this section, have the following meanings unless the context
(1) Critical loads--Loads for which electric service
is considered crucial for the protection or maintenance of public
safety; including but not limited to hospitals, police stations, fire
stations, critical water and wastewater facilities, and customers
with special in-house life-sustaining equipment.
(2) Critical natural gas facility--A facility designated
as a critical customer by the Railroad Commission of Texas under §3.65(b)
of this title (relating to Critical Designation of Natural Gas Infrastructure)
unless the facility has obtained an exception from its critical status.
Designation as a critical natural gas facility does not guarantee
the uninterrupted supply of electricity.
(3) Energy emergency--Any event that results in or
has the potential to result in firm load shed required by the reliability
coordinator of a power region in Texas.
(4) Interruption classifications:
(A) Forced--Interruptions, exclusive of major events,
that result from conditions directly associated with a component requiring
that it be taken out of service immediately, either automatically
or manually, or an interruption caused by improper operation of equipment
or human error.
(B) Scheduled--Interruptions, exclusive of major events,
that result when a component is deliberately taken out of service
at a selected time for purposes of construction, preventative maintenance,
or repair. If it is possible to defer an interruption, the interruption
is considered a scheduled interruption.
(C) Outside causes--Interruptions, exclusive of major
events, that are caused by influences arising outside of the distribution
system, such as generation, transmission, or substation outages.
(D) Major events--Interruptions that result from a
catastrophic event that exceeds the design limits of the electric
power system, such as an earthquake or an extreme storm. These events
shall include situations where there is a loss of power to 10% or
more of the customers in a region over a 24-hour period and with all
customers not restored within 24 hours.
(5) Interruption, momentary--Single operation of an
interrupting device which results in a voltage zero and the immediate
restoration of voltage.
(6) Interruption, sustained--All interruptions not
classified as momentary.
(7) Interruption, significant--An interruption of any
classification lasting one hour or more and affecting the entire system,
a major division of the system, a community, a critical load, or service
to interruptible customers; and a scheduled interruption lasting more
than four hours that affects customers that are not notified in advance.
A significant interruption includes a loss of service to 20% or more
of the system's customers, or 20,000 customers for utilities serving
more than 200,000 customers. A significant interruption also includes
interruptions adversely affecting a community such as interruptions
of governmental agencies, military bases, universities and schools,
major retail centers, and major employers.
(8) Reliability indices:
(A) System Average Interruption Frequency Index (SAIFI)--The
average number of times that a customer's service is interrupted.
SAIFI is calculated by summing the number of customers interrupted
for each event and dividing by the total number of customers on the
system being indexed. A lower SAIFI value represents a higher level
of service reliability.
(B) System Average Interruption Duration Index (SAIDI)--The
average amount of time a customer's service is interrupted during
the reporting period. SAIDI is calculated by summing the restoration
time for each interruption event times the number of customers interrupted
for each event and dividing by the total number of customers. SAIDI
is expressed in minutes or hours. A lower SAIDI value represents a
higher level of service reliability.
(d) Record of interruption. Each utility must keep
complete records of sustained interruptions of all classifications.
Where possible, each utility must keep a complete record of all momentary
interruptions. These records must show the type of interruption, the
cause for the interruption, the date and time of the interruption,
the duration of the interruption, the number of customers interrupted,
the substation identifier, and the transmission line or distribution
feeder identifier. In cases of emergency interruptions, the remedy
and steps taken to prevent recurrence must be recorded. Each utility
must retain records of interruptions for five years.
(e) Notice of significant interruptions.
(1) Initial notice. A utility must notify the commission,
in a method prescribed by the commission, as soon as reasonably possible
after it has determined that a significant interruption has occurred.
The initial notice must include the general location of the significant
interruption, the approximate number of customers affected, the cause
if known, the time of the event, and the estimated time of full restoration.
The initial notice must also include the name and telephone number
of the utility contact person and must indicate whether local authorities
and media are aware of the event. If the duration of the significant
interruption is greater than 24 hours, the utility must update this
information daily and file a summary report.
(2) Summary report. Within five working days after
the end of a significant interruption lasting more than 24 hours,
the utility must submit a summary report to the commission. The summary
report must include the date and time of the significant interruption;
the date and time of full restoration; the cause of the interruption,
the location, substation and feeder identifiers of all affected facilities;
the total number of customers affected; the dates, times, and numbers
of customers affected by partial or step restoration; and the total
number of customer-minutes of the significant interruption (sum of
the interruption durations times the number of customers affected).
(f) Priorities for power restoration to certain medical
(1) A utility must give the same priority that it gives
to a hospital in the utility's emergency operations plan for restoring
power after an extended power outage, as defined by Texas Water Code, §13.1395,
to the following:
(A) An assisted living facility, as defined by Texas
Health and Safety Code, §247.002;
(B) A facility that provides hospice services, as defined
by Texas Health and Safety Code, §142.001;
(C) A nursing facility, as defined by Texas Health
and Safety Code, §242.301; and
(D) An end stage renal disease facility, as defined
by Texas Health and Safety Code, §251.001.
(2) The utility may use its discretion to prioritize
power restoration for a facility after an extended power outage in
accordance with the facility's needs and with the characteristics
of the geographic area in which power must be restored.
(g) System reliability. Reliability standards apply
to each utility and are limited to the Texas jurisdiction. A "reporting
year" is the 12-month period beginning January 1 and ending December
31 of each year.
(1) System-wide standards. The standards must be unique
to each utility based on the utility's performance and may be adjusted
by the commission if appropriate for weather or improvements in data
acquisition systems. The standards will be the average of the utility's
performance from the later of reporting years 1998, 1999, and 2000,
or the first three reporting years the utility is in operation.
(A) SAIFI. Each utility must maintain and operate its
electric distribution system so that its SAIFI value does not exceed
its system-wide SAIFI standard by more than 5.0%.
(B) SAIDI. Each utility must maintain and operate its
electric distribution system so that its SAIDI value does not exceed
its system-wide SAIDI standard by more than 5.0%.
(2) Distribution feeder performance. The commission
will evaluate the performance of distribution feeders with ten or
more customers after each reporting year. Each utility must maintain
and operate its distribution system so that no distribution feeder
with ten or more customers sustains a SAIDI or SAIFI value for a reporting
year that is more than 300% greater than the system average of all
feeders during any two consecutive reporting years.
(3) Enforcement. The commission may take appropriate
enforcement action, including action against a utility, if the system
and feeder performance is not operated and maintained in accordance
with this subsection. In determining the appropriate enforcement action,
the commission will consider:
(A) the feeder's operation and maintenance history;
(B) the cause of each interruption in the feeder's
(C) any action taken by a utility to address the feeder's
(D) the estimated cost and benefit of remediating a
feeder's performance; and
(E) any other relevant factor as determined by the
(h) Critical natural gas facilities. In accordance
with §3.65 of this title, critical natural gas standards apply
to each facility in this state designated as a critical customer under §3.65
of this title. In this subsection, the term "utility" includes MOUs,
electric cooperatives, and entities considered utilities under subsection
(a) of this section.
(1) Critical customer information.
(A) In accordance with §3.65 of this title, the
operator of a critical natural gas facility must provide critical
customer information to the entities listed in clauses (i) and (ii)
of this subparagraph. The critical customer information must be provided
by email using Form CI-D and any attachments, as prescribed by the
Railroad Commission of Texas.
(i) The utility from which the critical natural gas
facility receives electric delivery service; and
(ii) For critical natural gas facilities located in
the ERCOT region, the independent organization certified under PURA §39.151.
(B) The commission will maintain on its website a list
of utility email addresses to be used for the provision of critical
customer information under subparagraph (A) of this paragraph. Each
utility must ensure that the email address listed on the commission's
website is accurate. If the utility's email address changes or is
inaccurate, the utility must provide the commission with an updated
email address within five business days of the change or of becoming
aware of the inaccuracy.
(C) Within ten business days of receipt, the utility
must evaluate the critical customer information for completeness and
provide written notice to the operator of the critical natural gas
facility regarding the status of its critical natural gas designation.
(i) If the information submitted is incomplete, the
utility's notice must specify what additional information is required
and provide a deadline for response that is no sooner than five business
days from when the critical natural gas facility receives the written
notice. If the utility does not receive the additional information
in a timely fashion, the utility may use its discretion to determine
if it is possible to treat the natural gas facility as critical for
load shed and power restoration purposes.
(ii) If the information submitted is complete, the
utility's notice must notify the operator of the facility's critical
natural gas status, the date of its designation, any additional classifications
assigned to the facility by the utility, and notice that its critical
status does not constitute a guarantee of an uninterrupted supply