(3)
General obligations.
a. Each electric utility shall make
reasonable efforts to avoid and prevent interruptions of service. However, when
interruptions occur, service shall be reestablished within the shortest time
practicable, consistent with safety.
b. The electric utility's electrical
transmission and distribution facilities shall be designed, constructed,
maintained, and electrically reinforced and supplemented as required to
reliably perform the power delivery burden placed upon them in the storm and
traffic hazard environment in which they are located.
c. Each electric utility shall carry on an
effective preventive maintenance program and be capable of emergency repair
work on a scale that its storm and traffic damage record indicates as
appropriate to its scope of operations and to the physical condition of its
transmission and distribution facilities.
d. In appraising the reliability of the
electric utility's transmission and distribution system, the commission will
consider the condition of the physical property and the size, training,
supervision, availability, equipment, and mobility of the maintenance forces,
all as demonstrated in actual cases of storm and traffic damage to the
facilities.
e. Each electric
utility shall keep records of interruptions of service and make an analysis of
the records for the purpose of determining steps to be taken to prevent
recurrence of such interruptions.
f. Each electric utility shall make
reasonable efforts to reduce the risk of future interruptions by taking into
account the age, condition, design, and performance of transmission and
distribution facilities and providing adequate investment in the maintenance,
repair, replacement, and upgrade of facilities and equipment.
(4)
Definitions.
Terms and formulas when used in this rule are defined as follows:
"Customer" means
(1) any person, firm, association, or
corporation,
(2) any agency of the
federal, state, or local government, or
(3) any legal entity responsible by law for
payment of the electric service from the electric utility that has a separately
metered electrical service point for which a bill is provided. Each meter
equals one customer. Retail customers are end-use customers who purchase and
ultimately consume electricity.
"Customer average interruption duration index"
or "CAIDI" means the average interruption duration for those
customers who experience interruptions during the year. It is calculated by
dividing the annual sum of all customer interruption durations by the total
number of customer interruptions.
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"Distribution system" means that part of the
electric system owned or operated by an electric utility and designed to
operate at a nominal voltage of 25,000 volts or less.
"Electrical service point" means the point of
connection between the electric utility's equipment and the customer's
equipment.
"Electric utility" means investor-owned
electric utilities owning, controlling, operating, or using transmission and
distribution facilities and equipment subject to the commission's
jurisdiction.
"GIS" means a geospatial information system.
This is an information management framework that allows the integration of
various data and geospatial information.
"Interrupting device" means a device capable
of being reclosed whose purpose is to interrupt faults and restore service or
disconnect loads. These devices can be manual, automatic, or motor-operated.
Examples may include transmission breakers, feeder breakers, line reclosers,
motor-operated switches, fuses, or other devices.
"Interruption" means a loss of service to one
or more customers or other facilities and is the result of one or more
component outages. The types of interruption include momentary event,
sustained, and scheduled. The following interruption causes shall not be
included in the calculation of the reliability indices:
1. Interruptions intentionally initiated
pursuant to the provisions of an interruptible service tariff or contract and
affecting only those customers taking electric service under such tariff or
contract;
2. Interruptions due to
nonpayment of a bill;
3.
Interruptions due to tampering with service equipment;
4. Interruptions due to denied access to
service equipment located on the affected customer's private
property;
5. Interruptions due to
hazardous conditions located on the affected customer's private
property;
6. Interruptions due to a
request by the affected customer;
7. Interruptions due to a request by a law
enforcement agency, fire department, other governmental agency responsible for
public welfare, or any agency or authority responsible for bulk power system
security; or
8. Interruptions caused
by the failure of a customer's equipment; the operation of a customer's
equipment in a manner inconsistent with law, an approved tariff, rule,
regulation, or an agreement between the customer and the electric utility; or
the failure of a customer to take a required action that would have avoided the
interruption, such as failing to notify the company of an increase in load when
required to do so by a tariff or contract.
"Interruption duration" as used herein in
regard to sustained outages means a period of time measured in one-minute
increments that starts when an electric utility is notified or becomes aware of
an interruption and ends when an electric utility restores electric service, as
long as the duration is not less than five minutes long.
"Interruption, momentary" means single
operation of an interrupting device that results in a voltage of zero. For
example, two breaker or recloser operations equals two momentary interruptions.
A momentary interruption is one in which power is restored
automatically.
"Interruption, momentary event" means an
interruption of electric service to one or more customers of duration limited
to the period required to restore service by an interrupting device. Note: Such
switching operations must be completed in a specified time not to exceed five
minutes. This definition includes all reclosing operations that occur within
five minutes of the first interruption. For example, if a recloser or breaker
operates two, three, or four times and then holds, the event shall be
considered one momentary event interruption.
"Interruption, scheduled" means an
interruption of electric power that results when a transmission or distribution
component is deliberately taken out of service at a selected time, usually for
the purposes of construction, preventive maintenance, or repair. If it is
possible to defer the interruption, the interruption is considered a scheduled
interruption.
"Interruption, sustained" means any
interruption not classified as a momentary event interruption. It is an
interruption of electric service that is not automatically or instantaneously
restored, with duration of greater than five minutes.
"Loss of service" means the loss of electrical
power, or a complete loss of voltage, to one or more customers. This does not
include any of the power quality issues such as sags, swells, impulses, or
harmonics. Also see definition of "interruption."
"Major event" will be declared whenever
extensive physical damage to transmission and distribution facilities has
occurred within an electric utility's operating area due to unusually severe
and abnormal weather or event and:
1.
Wind speed exceeds 90 mph for the affected area,
2. One-half inch of ice is present and wind
speed exceeds 40 mph for the affected area,
3. Ten percent of the affected area total
customer count is incurring a loss of service for a length of time to exceed
five hours, or
4. 20,000 customers
in a metropolitan area are incurring a loss of service for a length of time to
exceed five hours.
"Metropolitan area" means any community, or
group of contiguous communities, with a population of 20,000 individuals or
more.
"Momentary average interruption frequency
index" or "MAIFI" means the average number of
momentary electric service interruptions for each customer during the year. It
is calculated by dividing the total number of customer momentary interruptions
by the total number of customers served.
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"OMS" is a computerized outage management
system.
"Operating area" means a geographical area
defined by the electric utility that is a distinct area for administration,
operation, or data collection with respect to the facilities serving, or the
service provided within, the geographical area.
"Outage" means the state of a component when
it is not available to perform its intended function due to some event directly
associated with that component. An outage may or may not cause an interruption
of service to customers, depending on system configuration.
"Power quality" means the characteristics of
electric power received by the customer, with the exception of sustained
interruptions and momentary event interruptions. Characteristics of electric
power that detract from its quality include waveform irregularities and voltage
variations, either prolonged or transient. Power quality problems shall include
but not be limited to disturbances such as high or low voltage, voltage spikes
and transients, flickers and voltage sags, surges and short-time overvoltages,
as well as harmonics and noise.
"Rural circuit" means a circuit not defined as
an urban circuit.
"System average interruption duration index"
or "SAIDI" means the average sustained interruption duration
per customer served during the year. It is calculated by dividing the sum of
the customer sustained interruption durations by the total number of customers
served during the year.
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"System average interruption frequency index"
or "SAIFI" means the average number of sustained interruptions
per customer during the year. It is calculated by dividing the total annual
number of customer sustained interruptions by the total number of customers
served during the year.
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"Total number of customers served" means the
total number of customers served on the last day of the reporting
period.
"Urban circuit" means a circuit where both 75
percent or more of its customers and 75 percent or more of its primary circuit
miles are located within a metropolitan area.
(5)
Recordkeeping
requirements.
a. Each electric
utility shall maintain a GIS and an OMS sufficient to determine a history of
sustained electric service interruptions experienced by each customer. The OMS
shall have the ability to access data for each customer in order to determine a
history of electric service interruptions. Data shall be sortable by each of,
and in any combination with, the following factors:
(1) State jurisdiction;
(2) Operating area (if any);
(3) Substation;
(4) Circuit;
(5) Number of interruptions in reporting
period; and
(6) Number of hours of
interruptions in reporting period.
b. Records on interruptions shall be
sufficient to determine the following:
(1)
Starting date and time the utility became aware of the interruption;
(2) Duration of the interruption;
(3) Date and time service was
restored;
(4) Number of customers
affected;
(5) Description of the
cause of the interruption;
(6)
Operating areas affected;
(7)
Circuit number(s) of the distribution circuit(s) affected;
(8) Service account number or other unique
identifier of each customer affected;
(9) Address of each affected customer
location;
(10) Weather conditions
at time of interruption;
(11)
System component(s) involved (e.g., transmission line, substation, overhead
primary main, underground primary main, transformer); and
(12) Whether the interruption was planned or
unplanned.
c. Each
electric utility shall maintain as much information as feasible on momentary
interruptions.
d. Each electric
utility shall keep information on cause codes, weather codes, isolating device
codes, and equipment failed codes.
(1) The
minimum interruption cause code set should include: animals, lightning, major
event, scheduled, trees, overload, error, supply, equipment, other, unknown,
and earthquake.
(2) The minimum
interruption weather code set should include: wind, lightning, heat, ice/snow,
rain, clear day, and tornado/hurricane.
(3) The minimum interruption isolating device
set should include: breaker, recloser, fuse, sectionalizer, switch, and
elbow.
(4) The minimum interruption
equipment failed code set should include: cable, transformer, conductor,
splice, lightning arrester, switches, cross arm, pole, insulator, connector,
other, and unknown.
(5) Utilities
may augment the code sets listed above to enhance tracking.
e. An electric utility shall
retain for seven years the records required by paragraphs
20.17(5)"a" through "d."
f. Each electric utility shall record the
date of installation of major facilities (poles, conductors, cable, and
transformers) installed on or after April 1, 2003, and integrate that data into
its GIS database.
g. Each electric
utility shall make its records of customer interruptions available to the
commission as needed.
(7)
Annual reliability and service
quality report. Each electric utility shall submit to the commission
on or before May 1 of each year an annual reliability report for the previous
calendar year for the Iowa jurisdiction. The report shall include the following
information:
a.
Description of
service area. Urban and rural Iowa service territory customer count;
Iowa operating area customer count, if applicable; and major communities served
within each operating area.
b.
System reliability performance.
(1) An overall assessment of the reliability
performance, including the urban and rural SAIFI, SAIDI, and CAIDI reliability
indices for the previous calendar year for the Iowa service territory and each
defined Iowa operating area, if applicable. This assessment shall include
outages at the substation, transmission, and generation levels of the system
that directly result in sustained interruptions to customers on the
distribution system. These indices shall be calculated twice, once with the
data associated with major events and once without. This assessment should
contain tabular and graphical presentations of the trend for each index as well
as the trends of the major causes of interruptions.
(2) The urban and rural SAIFI, SAIDI, and
CAIDI reliability average indices for the previous five calendar years for the
Iowa service territory and each defined Iowa operating area, if applicable. The
reliability average indices shall include outages at the substation,
transmission, and generation levels of the system that directly result in
sustained interruptions to customers on the distribution system. Calculation of
the five-year average shall start with data from the year covered by the first
Annual Reliability Report submittal so that by the fifth Annual Reliability
Report submittal a complete five-year average shall be available. These indices
shall be calculated twice, once with the data associated with major events and
once without.
(3) The MAIFI
reliability indices for the previous five calendar years for the Iowa service
territory and each defined Iowa operating area for which momentary
interruptions are tracked. The first annual report should specify which
portions of the system are monitored for momentary interruptions, identify and
describe the quality of data used, and be updated as needed in subsequent
reports.
c.
Reporting on customer outages.
(1)
The reporting electric utility shall provide tables and graphical
representations showing, in ascending order, the total number of customers that
experienced set numbers of sustained interruptions during the year (i.e., the
number of customers who experienced zero interruptions, the number of customers
who experienced one interruption, two interruptions, three interruptions, and
so on). The utility shall provide this for each of the following:
1. All Iowa customers, excluding major
events.
2. All Iowa customers,
including major events.
(2) The reporting electric utility shall
provide tables and graphical representations showing, in ascending order, the
total number of customers that experienced a set range of total annual
sustained interruption duration during the year (i.e., the number of customers
who experienced zero hours total duration, the number of customers who
experienced greater than 0.0833 but less than 0.5 hour total duration, the
number of customers who experienced greater than 0.5 but less than 1.0 hour
total duration, and so on, reflecting half-hour increments of duration). The
utility shall provide this for each of the following:
1. All Iowa customers, excluding major
events.
2. All Iowa customers,
including major events.
d.
Major event summary. For
each major event that occurred in the reporting period, the following
information shall be provided:
(1) A
description of the area(s) impacted by each major event;
(2) The total number of customers interrupted
by each major event;
(3) The total
number of customer-minutes interrupted by each major event; and
(4) Updated damage cost estimates to the
electric utility's facilities.
e.
Information on transmission and
distribution facilities.
(1) Total
circuit miles of electric distribution line in service at year's end,
segregated by voltage level. Reasonable groupings of lines with similar voltage
levels, such as but not limited to 12,000- and 13,000-volt three-phase
facilities, are acceptable.
(2)
Total circuit miles of electric transmission line in service at year's end,
segregated by voltage level.
f.
Plans and status report.
A plan for service quality improvements, including costs, for the electric
utility's transmission and distribution facilities that will ensure quality,
safe, and reliable delivery of energy to customers.
g.
Capital expenditure
information. Reporting of capital expenditure information shall start
with data from the year covered by the first Annual Reliability Report
submittal so that by the fifth Annual Reliability Report submittal five years
of data shall be available in each subsequent annual report.
(1) Each electric utility shall report on an
annual basis the total of:
1. Capital
investment in the electric utility's Iowa-based transmission and distribution
infrastructure approved by its board of directors or other appropriate
authority. If any amounts approved by the board of directors are designated for
use in a recovery from a major event, those amounts shall be identified in
addition to the total.
2. Capital
investment expenditures in the electric utility's Iowa-based transmission and
distribution infrastructure. If any expenditures were utilized in a recovery
from a major event, those amounts shall be identified in addition to the
total.
(2) Each electric
utility shall report the same capital expenditure data from the past five years
in the same fashion as in subparagraph
20.17(7)"g"(1).
h.
Maintenance. Reporting of
maintenance information shall start with data from the year covered by the
first Annual Reliability Report submittal, so that by the fifth Annual
Reliability Report submittal, five years of data shall be available in each
subsequent annual report.
(1) Total
maintenance budgets and expenditures for distribution, and for transmission,
for each operating area, if applicable, and for the electric utility's entire
Iowa system for the past five years. If any maintenance budgets and
expenditures are designated for use in a recovery from a major event, or were
used in a recovery from a major event, respectively, those amounts shall be
identified in addition to the totals.
(2) Tree trimming.
1. The budget and expenditures described in
subparagraph 20.17(7)"h"(1) shall be stated in such a way that
the total annual tree trimming budget expenditures shall be identifiable for
each operating area and for the electric utility's entire Iowa system for the
past five years.
2. Total annual
projected and actual miles of transmission line and of distribution line for
which trees were trimmed for the reporting year for each operating area and for
the electric utility's entire Iowa system for the reporting year, compared to
the past five years. If the utility has utilized, or would prefer to utilize,
an alternative method or methods of tracking physical tree trimming progress,
it may propose the use of that method or methods to the commission in a request
for waiver.
3. In the event the
utility's actual tree trimming performance, based on how the utility tracks its
tree trimming as described in numbered paragraph
20.17(7)"h"(2)"1," lags behind its planned trimming schedule
by more than six months, the utility shall be required to file for the
commission's approval additional tree trimming status reports on a quarterly
basis. Such reports shall describe the steps the utility will take to remediate
its tree trimming performance and backlog. The additional quarterly reports
shall continue until the utility's backlog has been reduced to zero.
i. The Annual
Reliability Report shall include the number of poles inspected, the number
rejected, and the number replaced.
