UNITED STATES DEPARTMENT OF AGRICULTURE

Rural Utilities Service 

BULLETIN 1730A-119 

RD-GD-2009-58

SUBJECT: Interruption Reporting and Service Continuity Objectives 

for Electric Distribution Systems

TO: All Distribution Borrowers 

EFFECTIVE DATE: Date of approval. 

OFFICE OF PRIMARY INTEREST: Electric Staff Division, Distribution Branch. 

INSTRUCTIONS: This bulletin replaces REA Bulletin 161-1, dated March 31, 1972. 

AVAILABILITY: This bulletin can be accessed via the internet at: 

http://www.usda.gov/rus/electric/bulletins.htm. 

PURPOSE: To provide guidance on recording and reporting service interruptions and 

outages, the calculation of industry standard indices for measuring distribution system 

performance and promotion of consistent outage recordkeeping and reporting among 

borrowers. 

03/24/09 

Date James R. Newby

Assistant Administrator – Electric Program

Disclaimer: The contents of this guidance document does not have the force and effect of law and is not 

meant to bind the public in any way. This document is intended only to provide clarity to the public 

regarding existing requirements under the law or agency policies.
Bulletin 1730A-119

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TABLE OF CONTENTS

1 PURPOSE AND SCOPE 4

2 INTERRUPTION REPORTING 4

3 INTERRUPTION ANALYSIS 5

4 POWER QUALITY METRICS 10

5 SERVICE CONTINUITY OBJECTIVES 13

Exhibits

Exhibit A – Manual Trouble Ticket 

Exhibit B – Interruption Report 

Exhibit C – Call Centers and IVR

Exhibit D – Step Restoration Process and Example 

Exhibit E – Calculation of Major Event Days 

Exhibit F – Normalization for Weather

Exhibit G – Reliability Indices for Substation Components

INDEX:

Power Quality 

Outage metrics 

Outage reporting

ABBREVIATIONS

AMR – Automated Meter Reading

CSR – Customer Service Representative

IEEE – The Institute of Electrical and Electronics Engineers 

IVR – Interactive Voice Response

MAIFI – Momentary Average Interruption Frequency Index 

SAIDI – System Average Interruption Duration Index 

SAIFI – System Average Interruption Frequency Index 

SCADA – Supervisory Control and Data Acquisition

TMED – Major event day identification threshold value
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DEFINITIONS

Interruption – A loss of electricity for any period longer than 5 minutes.

Power supply interruption – Any interruption originating from the transmission system, 

sub-transmission system, or the substation, regardless of ownership.

Planned interruption – Any interruption scheduled by the distribution system to safely 

perform routine maintenance.

All other interruptions – All interruptions excluding power supply, major event, and 

those that are planned.

Major event – An interruption or group of interruptions caused by conditions that exceed the 

design and operational limits of a system. See IEEE Standard 1366-2003 and Exhibit E of this 

document.

Major event day – As defined by IEEE Standard 1366, a day in which the daily SAIDI exceeds 

a threshold value, TMED. For the purpose of calculating daily system SAIDI, any interruption 

that spans multiple calendar days is accrued to the day on which the interruption began.

Statistically, days having a daily system SAIDI greater than TMED are days when the energy 

delivery system experiences stresses beyond those normally expected—such as severe weather. 

Activities that occur on major event days should be analyzed and reported separately.

Outage – The state of a component when it is not available to perform its intended function as 

a result of an event directly associated with that component. An outage could cause an 

interruption of service to customers, depending on system configuration. This definition does 

not apply to generation outages.

FORMS

RUS Form 7, “Financial and Statistical Report” 

RUS Form 300, “Rating Review Summary”
Bulletin 1730A-119

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1 PURPOSE AND SCOPE

This bulletin provides guidance on recording and reporting service interruptions and 

outages and the calculation of industry standard indices for measuring distribution 

system performance. One of the goals of the bulletin is to promote consistent outage 

recordkeeping and reporting among borrowers, and to assist them in implementing the 

major event day methodology that has been adopted by IEEE. Consistency in outage 

recordkeeping among borrowers will provide opportunities for performance 

benchmarking. In addition, to help electric systems collect useful and consistent data 

on outages, this bulletin harmonizes outage cause codes used by the Rural Utilities 

Service (RUS) and IEEE.

2 INTERRUPTION REPORTING

a The Trouble Ticket. The generation of a trouble ticket is the first step in 

interruption reporting.

(1) The first goal of the trouble ticket is to get as much information as 

possible about the interruption and to pass this information along 

quickly to the people or systems that need it.

(2) A trouble ticket is traditionally the result of a telephone call from a 

member reporting a service problem or interruption. Such telephone 

calls usually are taken by customer service representatives (CSR) using 

manual “trouble ticket” forms. However, with newer technology, 

borrowers can automate this process and render the traditional trouble 

ticket paperless.

(3) Borrower personnel should consider the process of interruption data 

gathering, reporting, and analysis and determine the point at which these 

data should be put in an electronic format. Because of the flexibility of 

software systems and the advent of services and products such as call 

centers and interactive voice response systems, the borrower has many 

choices to improve its performance in this area.

b Manual Trouble Ticket. The simplest interruption reporting is the use of a form 

as shown in Exhibit A. An employee could fill out this type of form manually 

while talking to the member on the phone. This same form could be used to 

dispatch crews and report the cause of the interruption and other pertinent 

information, making a complete record of the interruption report. It could be 

used to generate any interruption analysis or reports the borrower may find 

useful.

c Automated Trouble Ticket. Technology available today provides faster 

response to larger call volumes and allows for interruption data to be quickly 

assimilated into a computerized outage management system. The result is faster
Bulletin 1730A-119

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response and restoration times, as well as increased customer satisfaction. 

There are several methods for generating the automated trouble ticket, 

including, but not limited to, the use of SCADA, AMR, IVR, and call centers. 

For more discussion on these options, see Exhibit C.

d The Interruption Report. The interruption report is used to document a service 

interruption.

(1) Typically, an interruption report is completed each time a sectionalizing 

device opens permanently for the purpose of clearing a fault or

de-energizing a section of line for construction or maintenance.

(2) The report should provide enough information to comply with RUS and 

state public service commission reporting requirements for service 

reliability and continuity. Additionally, the form should capture 

information that will enable the borrower to calculate industry standard 

reliability indices, as well as to determine the effectiveness of various 

maintenance activities performed by the borrower.

(3) See Exhibit B for a sample Interruption Report.

e Reports to RUS. RUS Borrowers that borrow funds from RUS are required to 

report the system average annual interruption minutes per consumer on Form 7 

and Form 300. Shown in Table 1 is Part G of Form 7. Form 7 calls for four 

separate SAIDIs, as well as the total interruption time. The definitions of the 

terms used in Part G can be found in Part 2, Definitions.

Table 1. RUS Form 7, Part G

Part G. Service Interruptions

Item

SAIDI (in minutes)

Power 

Supply 

(a)

Major 

Event 

(b)

Planned

(c)

All Other 

(d)

TOTAL

(e)

1. Present Year

2. Five-Year Average

f Changes to Forms 7 and 300. Previously, Forms 7 and 300 called for Average 

Hours Per Consumer Per Year for (1) Power Supplier, (2) Extreme Storm, (3) 

Pre-arranged, and (4) All Other. Note that the SAIDI in minutes is now 

required, instead of average hours per consumer and that “major event” is a 

category in place of “major storm.” If SAIDI data is not available for previous 

years, use average hours per consumer per year, multiplied by 60 to convert the 

data to minutes. It should be noted, however, that other entities, such as various 

state commissions, require SAIDI to be reported in minutes.
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3 INTERRUPTION ANALYSIS

In addition to RUS’s reporting requirements, it is recommended that borrowers track 

additional information about service interruptions for more detailed analysis. The 

purpose of additional analysis is to provide feedback to the borrower’s employees, 

management, and board on how well the distribution system is serving the members.

a Cause Codes and Equipment Codes. Two codes have traditionally been 

associated with interruption reporting: cause codes and equipment codes. 

Cause codes indicate the initiating condition which would include decay, 

animals, lightning, tree limbs, etc. while the equipment code indicates what 

equipment was involved, such as a broken insulator. However, when a 

protective device such as a fuse operates (as designed) to disconnect a faulted 

conductor, no equipment has failed or been damaged. Therefore, a “special” 

equipment code is also needed to indicate that no failure of equipment or 

material defect occurred. Every interruption has a cause, but not every 

interruption results in damaged or failed equipment. Therefore, in the case 

where no equipment was damaged, the corresponding code in Table 3, “999, No 

Equipment Failure”, would be used. Including this special code ensures that 

every interruption will have a cause code and an equipment code associated 

with it even when no equipment is at fault. Recommended cause codes are 

shown in Table 2, and equipment codes are shown in Table 3.

b Weather Condition and Voltage Level Codes. In addition to cause codes and 

equipment codes, incorporating weather condition and voltage level codes may 

be beneficial.

(1) Weather Condition Codes. Weather condition codes indicate the 

conditions that existed when the interruption occurred; they are not to be 

confused with the cause codes, which indicate a weather component that 

might have initiated an interruption. These are shown in Table 4.

(2) Voltage Level Codes. Voltage level codes can be used to identify 

system behavior that is a function of the operating voltage on the 

damaged components at the time of the interruption. Table 5 indicates 

the phase-to-phase voltage level, as some systems operate “Wye” 

configurations and others operate “Delta” configurations. It is generally 

accepted that higher voltage systems are more susceptible to lightning 

damage because of different basic insulation levels. The borrower’s 

engineer may be able to determine other improvements based on these 

data as well.

(3) Explanation of Codes. All of the codes are formatted so that summary 

and high level reports are easy to produce based on the data in the 

interruption report. The borrower may choose to use additional codes 

for more detailed information and analysis. The cause codes listed in
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Table 2 represent an important development. Cause codes have been 

adapted to align with both RUS and IEEE approaches. Note that the 

codes recommended in Column 1 of Table 2 link RUS’s codes that 

borrowers are accustomed to seeing with the codes prescribed by IEEE. 

Borrowers are encouraged to use the numbering system outlined in the 

first column to categorize outages. The numbering system is flexible so 

that borrowers can add their own cause codes within each subcategory. 

Subcategory coding can be used to isolate problems with specific types 

or brands of equipment on the system and to monitor their performance.

Table 2. Cause Codes

Cause 

Code

RUS

Form 7, 

Part G, 

ColumnIEEE Code Description

Power Supply1

000 A 4 Power supply

Planned Outage

100 C 3 Construction

110 C 3 Maintenance

190 C 3 Other planned

Equipment or Installation/Design

300 D 1 Material or equipment fault/failure

310 D 10 Installation fault

320 D 10 Conductor sag or inadequate clearance

340 D 10 Overload

350 D 10 Miscoordination of protection devices

360 D 10 Other equipment installation/design

Maintenance

400 D 1 Decay/age of material/equipment

410 D 1 Corrosion/abrasion of material/equipment

420 D 6 Tree growth

430 D 6 Tree failure from overhang or dead tree without ice/snow

440 D 6 Trees with ice/snow

450 D 1 Contamination (leakage/external)

460 D 1 Moisture

470 D 6 Borrower crew cuts tree

490 D 10 Maintenance, other

Weather

500 D 2 Lightning
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510 D 7 Wind, not trees

520 D 7 Ice, sleet, frost, not trees

530 D 7 Flood

590 D 10 Weather, other

Animals

600 D 8 Small animal/bird

610 D 8 Large animal

620 D 8 Animal damage—gnawing or boring

690 D 8 Animal, other

Public

700 D 5 Customer-caused

710 D 5 Motor vehicle

720 D 5 Aircraft

730 D 5 Fire

740 D 6 Public cuts tree

750 D 5 Vandalism

760 D 10 Switching error or caused by construction/maintenance activities

790 D 10 Public, other

Other

800 D 10 Other

Unknown2

999 D 9 Cause unknown

1 This cause code is used for outages caused by something on equipment not owned by the distribution borrower. 

If an interruption is caused by something on the distribution borrower’s own transmission system, a specific cause 

should be used.

2 Interruptions marked as “Cause unknown” should be further investigated to try to determine probable cause.

Table 3. Equipment/Material Failure Codes

Failure 

Code Description

Generation or Transmission

010 Generation

020 Towers, poles, and fixtures

030 Conductors and devices

040 Transmission substations

090 Generation or transmission, other

Distribution Substation

100 Power transformer

110 Voltage regulator

120 Lightning arrester

130 Source side fuse

140 Circuit breaker

150 Switch
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160 Metering equipment

190 Distribution substation, other

Poles and Fixtures, Distribution

200 Pole

210 Crossarm or crossarm brace

220 Anchor or guy

290 Poles and fixtures, other

Overhead Line Conductors and Devices, Distribution

300 Line conductor

310 Connector or clamp

320 Splice or dead end

330 Jumper

340 Insulator

350 Lightning arrester line

360 Fuse cutout (damaged, malfunction, maintenance)

370

Recloser or sectionalizer (damaged, malfunction, 

maintenance)

390

Overhead line conductors and devices, distribution, 

other

Underground Line Conductors and Devices, 

Distribution

400 Primary cable

410 Splice or fitting

420 Switch

430 Elbow arrester

440 Secondary cable or fittings

450 Elbow

460 Pothead or terminator

490 Underground, other

Line Transformer

500 Transformer bad

510 Transformer fuse or breaker

520 Transformer arrester

590 Line transformer, other

Secondaries and Services

600 Secondary or service conductor

610 Metering equipment

620 Security or street light

690 Secondary and service, other

No Equipment Damaged

999 No Equipment failure

Table 4. Weather Condition Codes
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010 Rain

020 Lightning

030 Wind

040 Snow

050 Ice

060 Sleet

070 Extreme Cold

080 Extreme Heat

090 Weather Other

100 Clear, calm

Table 5. Voltage Level Codes

001 < 1 KV(Secondary/Low Voltage)

002 5 KV

003 15 KV

004 25 KV

005 35 KV

006 60 KV

007 > 60 KV

4 POWER QUALITY METRICS

a Use and Analysis of Interruption Data. The time spent collecting the data 

described above will be wasted unless the data are analyzed and the results are 

used as a tool to improve the distribution system performance.

(1) The data can be useful in many ways. For example, interruption records, 

which included data on equipment failures, led a certain utility to 

discover that two lightning arrester manufacturers had bad batches of 

arresters, which were failing prematurely. Another utility used 

information on lightning damage and location to determine lightningprone areas in its territory. The utility then selectively improved the 

grounding in those areas, resulting in a least-cost reduction in 

interruptions caused by lightning and a reduction in equipment damage.

(2) The ultimate goal of these efforts is to reduce the number and duration 

of interruptions, improving reliability. Analysis of interruption trends, 

derived from consistent data collection over many years, helps ensure 

that money invested to improve reliability is spent wisely.
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b Definition and Use of the Major Indices. The definition of the most significant 

interruption-related indices and calculations will be discussed in thissection.

The following three indices should be calculated:

SAIDI—System Average Interruption Duration Index 

SAIFI—System Average Interruption Frequency Index 

CAIDI—Customer Average Interruption Duration Index

(1) IEEE Standard 1366-20031 defines SAIDI as the total duration of 

interruption for the average customer during a predefined period of time, 

usually one calendar year. It is measured in customer minutes.

SAIDI = Sum of Customer Interruption Durations (over the period desired)

Total Number of Customers Served

(2) As noted above, SAIDI is usually calculated for a calendar year or yearto-date but, for major event calculations, daily SAIDI values should be 

recorded. The starting time for calculating duration is determined by 

when the borrower knows about an interruption, either by automated 

means or by the first phone call from the affected area. Interruptions 

where the customer indicates that the repair can be scheduled for a later 

date still should be counted as an interruption. However, in these cases, 

the duration should be logged as the estimated amount of time required 

to repair the problem, including travel time.

(3) The total number of customers served is the average number of 

customers served over the defined time period. (The sum of the monthly 

customer count divided by the number of months.) This number should 

be the same as on the Form 7 except that public street and highway 

lighting should not be included. (Security or safety lights, billed to a 

residential customer, should not be counted on Form 7.)

(4) SAIFI is the number of interruptions that the average customer 

experiences during the year, month, or day. Interruption recovery time 

has no effect on this index.

SAIFI = Total number of customers interrupted 

Total number of customers served

(5) CAIDI is the average amount of time that a customer is without power 

for a typical interruption. It is primarily determined by response time to 

a reported interruption. However, the number of customers affected by 

an interruption can affect CAIDI because the distribution system has 

limited resources to respond to an interruption that covers an extensive 

portion of itsterritory.
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CAIDI = SAIDI

SAIFI

c Determination of a Major Event. Certain things are beyond the control of the 

distribution system—primarily natural disasters. Form 7 requires the SAIDI for 

these interruptions to be reported separately in Part G, Column (b), “Major 

Event.” It should not be included in Part G, Column (d), “AllOther.”

(1) Previously, there has been no hard and fast rule of what constitutes a 

major event. It has usually been defined as an event that lasts a specified 

period of time and causes an interruption for at least a specified number 

of customers.

(2) For example, an ice storm that results in interruptions of up to 10 days 

and causes an interruption for 80% of customers is clearly a major event. 

In this case, the interruption records would be kept separately. In 

calculating the SAIDI for the year, the interruptions from this event 

should be included in Column (b).

(3) What about a severe thunderstorm that caused some customers 

interruptions of up to 25 hours and where 5% of the customers 

experience some kind of interruption because of it? Is this a major event 

or not? Some distribution systems would say yes and others would say 

no.

(4) It is desirable to be more consistent across the nation and to take into 

account the fact that distribution systems with lower SAIDIs should 

have a lower threshold for what constitutes a “major event.” The IEEE 

Working Group on System Design within the Distribution 

Subcommittee has carefully analyzed the situation and has developed a 

statistical approach to determine a threshold daily SAIDI level that 

determines a “major event day.” The Group has defined a “major event” 

as an interruption or series of interruptions that exceed reasonable design 

and/or operational limits of the electric power system. With the issuance 

of this Bulletin, RUS encourages all borrowers to start using this 

approach. All outages that occur during a day found to be a “major 

event day” should be reported in Form 7, Part G, Column(b).

(5) This methodology is fully described in IEEE 1366, “Guide for Electric 

Power Distribution Reliability Indices,” and in Exhibit E of this Bulletin. 

The calculation involves taking the daily SAIDI values for the last five 

years and the natural logarithm of each value in the data set. For those 

who have automated systems for recording reliability information, this 

calculation should be easily obtainable. For those who use manual 

systems, (RUS offers a simple spreadsheet, prepared by the NRECA 

T&D Engineering Committee, to determine the threshold level for major

event
Bulletin 1730A-119

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days. This spreadsheet can be downloaded from RUS’s website at

https://www.rd.usda.gov/files/UEP_1730A-119_Outage_Data_Sheet.xls.

(NOTE: Spreadsheet must be “saved” to your hard drive first and 

then opened. If spreadsheet is “opened” directly from link, it will NOT 

work correctly.)

(6) The Interruption Report (Exhibit B) is used to calculate the values 

required on Form 7, Part G. No other analysis is performed by this 

database.

d Step Restoration Process. When service is restored in several steps, the 

calculations should be made separately and then added together. The 

explanation used by the IEEE is in ExhibitD.

5 SERVICE CONTINUITY OBJECTIVES

a Demand for Good Service. Rural electric systems now providepower to

everything from the single-family farm to the computer network server farm

(1) As utility service entities, borrowers should strive to provide the level of 

service needed by the load, consistent with the cost the customer is 

willing to bear. Approaching reliability from the customer’s perspective 

will help borrower personnel develop appropriate levels of service for 

the customer’s benefit. A goal may be to improve the CAIDI for a 

feeder by 20 minutes, or it may be to reach an Average System 

Availability Index of “four nines” (99.99%).

(2) In some instances, extreme levels of reliability may be needed that are 

beyond the borrower’s ability to provide when considering such things 

as feeder lengths or degree of environmental exposure, frequency of 

storms, extreme terrain, or cost. To achieve such requirements, a joint 

approach could be used that involves adding facilities on the customer’s 

premises that are owned and maintained by the customer. The borrower 

may agree to meet a minimum reliability number supplemented by 

customer-owned backup equipment.

(3) RUS’s guidelines for service reliability should take into consideration 

those areas that are controllable by the individual borrower and those 

items that are not. All interruption categories should be analyzed to 

determine if they are acceptable with regard to customer expectations. 

The borrower should look at each category when determining or 

modifying operating and design practices and criteria. The power 

supplier should be consulted if power supply interruptions are excessive. 

For Form 300, Part II, 7(a), the “All Other” classification will be the 

primary category for evaluation. Table 6 shows the current guideline:

Table 6. Guideline

Description All Other SAIDI, in Minutes

Satisfactory (rating of 3) 200 or less
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b Establishing Reliability Objectives. When the borrower sets a reliability goal, 

personnel can take a proactive role in bringing it about through system planning 

and budgeting.

(1) A thorough analysis of interruption causes, number of accounts 

affected, and durations can tell the engineering and operations staff 

where to concentrate their efforts. Table 7 shows several areas to 

consider for review.

Table 7. Areas To Consider for Review

Right-of-way clearing Sectionalizing scheme

Level of lightning protection Response time

System grounding Personnel deployment

Pole treatment/maintenance Use of wildlife guards

Construction practices Loading levels for ice and wind

Level of system automation Line patrolling activities

(2) Prioritizing the likely contributors of interruptions will enable the 

engineer to better target capital expenditures to improve performanceof 

the system. Continuous improvement in reliability provides several 

long-term benefits including increased customer satisfaction, lower 

maintenance expenses, lower demands on operations personnel, better 

system performance during extreme weather events, and improved 

safety for line workers and the general public. Specific actions needed 

to achieve or maintain a satisfactory interruption level should be 

addressed in the construction work plan.

c Other Indices. There are several other indices that the borrower might want to 

use. Three of these—SAIFI, SAIDI, and CAIDI—were discussedabove.

Another that might be considered is MAIFI—Momentary Average Interruption 

Frequency Index—a measure of the number of breaker operations that do not go 

to lockout. MAIFI could be used to measure system coordination. It also might 

be used as one measure of the quality of the power supply by recording 

momentary transmission interruptions.

Should be explained (rating of 2 or less) More than 200
Bulletin 1730A-119

Exhibit A

Page 1

MANUAL TROUBLE TICKET

TROUBLE TICKET

DATE TIME RECEIVED BY

ACCOUNT NO. REPORTED BY PHONE NO. TIME POWER WENT OFF

SERVICE OFF ENTIRELY 

NEIGHBORS ALSO OFF 

SERVICE DROP DOWN 

LIGHTS DIM

CHECKED FUSES

ADDRESS

CAUSE

LOCATION OF CAUSE

RECLOSER OR TAP LOCATION ASSIGNED TO TIME TRUCK NO.

ACTION TAKEN

RESTORED SERVICE TO TIME REMARKS

RESTORED SERVICE TO TIME

RESTORED SERVICE TO TIME

MATERIAL OR EQUIPMENT; CAUSE OF INTERRUPTION CODES

REVIEWED BY

Dispatcher Superintendent Engineer
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Exhibit B

Page 1

INTERRUPTION REPORT

INTERRUPTION REPORT REPORT NO.

DATE TIME RECEIVED BY

LOCATION OR SWITCH NO. REPORTED BY TIME POWER WENT OFF

SUBSTATION

FEEDER CAUSE

DISTRICT LOCATION OF CAUSE

ASSIGNED TO TIME TRUCK NO.

ACTION TAKEN

RESTORED SERVICE TO DATE TIME NO. CUSTOMERS CUSTOMER-MINUTES

RESTORED SERVICE TO DATE TIME NO. CUSTOMERS CUSTOMER-MINUTES

RESTORED SERVICE TO DATE TIME NO. CUSTOMERS CUSTOMER-MINUTES

TOTAL CUSTOMERS TOTAL CUSTOMER-MINUTES

MATERIAL OR EQUIPMENT CODES

CAUSE EQUIP WEATHER RUS FORM 7

REVIEWED BY

Dispatcher Superintendent Engineer
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Exhibit C

Page 1

CALL CENTERS AND IVR

1 CALL CENTERS

a Call centers have grown out of a need by borrowers to handle larger call 

volumes with people rather than machines. The call center can be staffed either 

in-house by borrower employees or outsourced to a call center at a different 

location. Because of economics or the desire to have high-volume call handling 

capabilities with live customer service representatives (CSR), outsourcing may 

be the way to go for many borrowers. In either case, the CSR will talk to the 

member, gathering information needed to identify the member and the location 

of the interruption, along with any other information the member may have 

about the interruption. The CSR also may be able to share information about 

the interruption with the member if the borrower is already aware of it. Call 

centers could then electronically forward such information to the appropriate 

operating personnel for dispatching and service restoration or as input to an 

interruption management system. In some cases, if properly equipped, the call 

center may actually dispatch the trouble ticket to the crew doingrestoration.

b Successful operation of a call center involves being sure the CSRs are trained to 

provide a positive image of the borrower. The member should not be able to 

tell whether the CSR is a borrower employee or an employee of an outsource 

call center. These CSRs should have fast, reliable access to a customer database 

that will quickly provide account location and status—such as service turned off 

for nonpayment. This database should be updated at least daily. These CSRs 

also should have access to information concerning status of interruptions so they 

can keep members informed as the interruption progresses.

2 INTERACTIVE VOICE RESPOSE (IVR) SYSTEMS

a If a borrower is willing to use advanced call answering technologies it may want

to investigate the use of an interactive voice response (IVR) system, which uses 

electronic voice messaging to handle large call volumes fast and efficiently.

These systems are especially attractive if the borrower is using an automated 

interruption management system. As in the call center application, these 

systems can be implemented either in-house or outsourced to third-party 

vendors. Often, this decision is based on a borrower’s ability to size its 

incoming phone lines to handle the phone traffic needed when large 

interruptions occur. For example, the existing borrower capability may be only 

12 to 24 incoming lines, while third-party facilities may be capable of more than 

500 incoming lines. Such increased call handling capability is especially 

critical if the borrower is using an automated outage management system. The 

borrower also may consider using an emergency overload system, where the 

calls go to the third party only after a set call volume is reached.
Bulletin 1730A-119

Exhibit C

Page 2

b An IVR system works very much like a call center, except the customer is 

talking to a machine and not a person. However, with advance speech 

recognition systems becoming more common, these systems are becoming more 

and more member-friendly.

c IVR systems also require access to a current customer database giving account 

location and status. Most IVR systems use customer phone numbers for 

account recognition. This can be done using caller ID systems or by having 

customers enter their phone numbers in response to requests from the IVR. 

Using phone numbers for account recognition requires borrowers to be diligent 

in keeping the numbers current for all accounts. For multiple accounts, the IVR 

system must have a way to determine which account is actually out. This can 

be done if the IVR uses text messaging of some account location field, which 

would uniquely identify the location with the member; or the IVR, using speech 

recognition, could ask the customer to leave a message describing the proper 

location. If both of these methods fail, the IVR could simply forward the 

customer’s call to a person for resolution.

d IVR systems also have the ability, when tied to an outage management system, 

to give customers feedback on interruption status and restoration time.
Bulletin 1730A-119

Exhibit D

Page 1

THE STEP RESTORATION PROCESS AND EXAMPLE

The following case illustrates the step restoration process. A feeder serving 1,000 customers 

experiences a sustained interruption. Multiple restoration steps are required to restore service to 

all customers. The table shows the times of each step, a description and associated customer 

interruptions, and minutes they were affected in a timeline format.

Relative 

Time Description Customers Duration (minutes)

CustomerMinutes of 

Interruption

00:00 1,000 customers interrupted.

00:45 500 customers restored;

500 customers still out of service.

500 45 22,500

1:00 Additional 300 customers restored; 

200 customers still out of service.

300 60 18,000

1:10 Feeder trips again; 800 previously 

restored customers interrupted again. 

(200 remained out and were not 

restored at this time.)

1:30 800 customers restored again. 800 20 16,000

2:00 Final 200 customers restored. 

Event ends.

200 120 24,000

Totals: 1,800 80,500

The graph below shows the steps as they happened:

Step Restoration Time Chart 

(Designer: X axis is Time; Y axis is Number of Customers

00:00 00:45 01:00 01:10 01:30 02:00

1000

customers

Step 1

800

customers

New 

Step 1

500

customers

Step 2 200 customers Step 3

Example SAIFI = 1,800/1,000 = 1.8 interruptions 

Example CAIDI = 80,500/1,800 = 44.7 minutes 

Example SAIDI = 80,500/1,000 = 80.5 minutes
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Exhibit E 

Page 1

CALCULATION OF MAJOR EVENT DAYS

1 INTRODUCTION

The following process (“Beta Method”) is used to identify major event days. This is a 

methodology developed by IEEE, available in IEEE Standard 1366TM-2003, “IEEE 

Guide for Electric Power Distribution Reliability Indices.” Its purpose is to allow 

major events to be studied separately from daily operation and, in the process, to better 

reveal trends in daily operation that would be hidden by the large statistical effect of 

major events. This approach supersedes previous major event definitions.

2 MAJOR EVENT DAYS

a Definition. A major event day is a day when the daily system SAIDI exceeds a 

threshold value, TMED. The SAIDI index is used as the basis of this definition, 

since it leads to consistent results regardless of utility size and because SAIDI is 

a good indicator of operational and design stress. Even though SAIDI is used to 

determine major event days, all indices should be calculated based on removal 

of the identified days.

b Calculation of Threshold. In calculating daily system SAIDI, any interruption 

that spans multiple days is accrued to the day on which the interruption begins. 

The major event day identification threshold value, TMED, is calculated at the 

end of each reporting period asfollows:

(1) Collect values of daily SAIDI for five sequential years ending on the last 

day of the last complete reporting period. If fewer than five years of 

historical date are available, use all available historical data until five 

years of historical data are available.

(2) Only those days that have a positive SAIDI/day value will be used to 

calculate the TMED. Exclude the days that have nointerruptions.

(3) Take the natural logarithm, of each daily SAIDI value in the data set.

(4) Find α (Alpha), the average of the logarithms—also known as the logaverage—of the data set.

(5) Find β (Beta), the standard deviation of the logarithms—also known as 

the log-standard deviation—of the data set.

(6) Compute the major event day threshold, TMED, using this equation:

TMED = e (α+2.5β)
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Exhibit E 

Page 2

(7) Any day with daily SAIDI greater than the threshold value TMED that 

occurs during the subsequent reporting period is classified as a major 

event day.
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Exhibit F 

Page 1

NORMALIZATION FOR WEATHER

Accurate and useful reliability reporting eventually will require ways to accommodate and 

understand the effect of lightning. The weather varies across the country and it varies from 

year to year. Most thunderstorms are not considered major events but they can have a dramatic 

effect on the number of customer interruptions throughout the year. Normalizing the 

interruption data for the incidence of lightning may be a useful area to explore. Plotting the 

number of customer interruptions and cloud-to-ground lightning strikes may point to areas 

where actions are needed to maintain or improve a system’s lightning protection.
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Exhibit G 

Page 1

RELIABILITY INDICES FOR SUBSTATION COMPONENTS

1 INTRODUCTION

a Background. The reliability of the electric system is an important factor in maintaining 

a healthy economy, as well as a high degree of customer satisfaction.

(1) In recent years, many consumer advocates and regulatory bodies have expressed 

concern that the reliability of the electric delivery system is being compromised 

due to an increased focus on competition and profitability. Many states have 

passed, or are in the process of passing legislation and/or approving regulations 

intended to refocus attention on maintaining and improving reliability. As time 

goes on, these laws and/or rules are expected to become more structured and 

pervasive.

(2) The reliability of the electric system is affected by all three components of the 

electric system—generation, transmission, and distribution. Generation 

reliability is ensured by, among other things, maintaining adequate planning and 

operating reserves. With a few notable exceptions, the establishment and 

enforcement of specific reserve requirements by regional reliability councils and 

power pools has resulted in few service interruptions due to the lack of 

generation capacity.2 As a result, most service interruptions experiencedby

end-use customers are the result of interruptions of transmission and distribution 

(T&D) facilities, not production facilities. Of these delivery system 

interruptions, the majority of interruptions are generally the result of 

interruptions of distribution facilities. Even so, interruptions on the 

transmission system also play an important role in providing reliable electric 

service and, in some areas, are a key component of overall interruption rates.

Interruptions of transmission facilities, although fewer in number, tend to cover 

a wider area than distribution interruptions and affect more customers.

(3) One ingredient in maintaining and improving reliability is the development of a 

consistent set of reliability indices that may be used to measure, report and 

compare reliability. To date, most industry effort in this regard has addressed 

the measuring and indexing of total systemreliability

(4) The Institute of Electrical and Electronic Engineers (IEEE), for example, has 

developed a draft reliability guideline that seeks to standardize the 

calculation of reliability indices for end-to-end electric utility systems.3 

Unfortunately, there is not any comparable guideline for measuring the

2 The brown outs experienced during 2001 in California are, of course, notable exceptions.

3 IEEE P1366 Draft Full Use Guide for Electric Power Distribution Reliability Indices, prepared by the Working 

Group on System Design, Draft #9, dated December 23, 2002. While the guide refers to “Distribution, Reliability 

Indices,” the indices really focus on total system reliability.
Bulletin 1730A-119

Exhibit G 

Page 2

reliability of just the transmission and distribution substation components of the 

delivery system.

b Purpose

(1) This Exhibit provides borrowers and others guidance on the 

development of reliability indices that may be used for benchmarking 

the performance of the transmission and distribution substation 

components of the delivery system. To accomplish this, the Exhibit 

establishes certain common definitions, measurement techniques and 

indices in an attempt to ensure consistent and comparable calculations. 

Without such standards, meaningful benchmarking would be impossible.

(2) By developing reliability benchmark measures fortransmission

and distribution substations, G&Ts and their distribution members will 

obtain a planning and management tool to consistently measure and 

evaluate reliability performance to the delivery point. The development 

of these benchmark measures is not intended to supplant the draft IEEE 

standard reliability measures but, rather, to build from and add further 

definition. Thus, it is hoped that the results will complement and 

augment the efforts by IEEE and others and to arrive at comparative 

indices and measurements that will be an important tool in enhancing 

system reliability.

c Caveats

It is important to list several caveats at the outset. First, the guidelines 

contained herein focus on outages of that portion of the transmission system that 

directly supplies the delivery points serving the distribution borrower membersystems (or similar points to other wholesale customers). Sometimes this is 

referred to as the subtransmission system. It does not address the impact of 

outages on the bulk power supply facilities. Second, the guidelines do not 

address the impact of outages of primary distribution delivery facilities (i.e., 

outages of facilities occurring on the load side of the delivery point). Finally, 

the reliability indices defined in this guide are intended for benchmarking 

purposes only, not to set standards ofperformance.

d Reference Document

IEEE P1366 Trial Use Guide for Electric Power Distribution Reliability Indices, 

prepared by the Working Group on System Design, Draft #9, dated December 

23, 2002 has been used as a reference for preparing this exhibit.

2 DEFINITIONS
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Exhibit G 

Page 3

The following definitions were adopted for use in this exhibit: 

a Customers Served (at a DeliveryPoint)

The number of Customers Served at a Delivery Point is based upon an end-ofyear annual customer count, generally one customer per meter. In the case of 

some installations of dual fuel, storage water heating, cycled air conditioning or 

other special programs, there may be more than one meter serving the customer. 

These installations are counted as a single customer. All other meters are 

counted as one customer (except for non-billed customer submeters).4 In the 

case of non-metered accounts (street lights, area lights and other flat rate 

accounts) some judgment may be necessary to arrive at an accurate customer 

count. Generally non-metered accounts used for street and highway lighting 

need to be counted as single customers per account. On the other hand, nonmetered area and security lighting associated with a customer premises or 

business location need not be counted since the use is associated with a primary 

account.

b Delivery Point

For purposes of this study, a delivery point is defined as the point at which 

power and energy from the G&T is delivered to the distribution borrower. 

Depending on the G&T and the particular Delivery Point, this may be the high 

side of a Distribution Substation, the low side of a Distribution Substation, a 

Transmission Substation or a point on a Transmission or Distribution line.

c Distribution Substations

Distribution Substations generally function as Delivery Points that directly serve 

retail customers at voltages that are typically below 34.5 kV.

d Distribution SubstationEquipment

All equipment from the source side bushings of the substation high side breaker 

or fuse to the load side bushings of the feeder breakers or OCRs.

e Foreign Transmission

Foreign Transmission is defined as transmission facilities that are owned and 

operated by companies other than the G&T that directly serve distribution 

member-system Delivery Points. Foreign owners may be IOUs, independent 

transmission companies, federal transmission owner or another G&T.

4 This definition deviates slightly from draft IEEE Standard P1366 in that the draft standard simply counts each 

meter as a customer, apparently not taking into account that some customers have multiple meters and some flat 

rate customers may not have meters
Bulletin 1730A-119

Exhibit G 

Page 4

f Interruption

The loss of service to one or more customers connected to the Delivery Point 

resulting from the outage of one or more components on the transmission 

system or in the Delivery Point substation.

g Interruption Duration

The period (measured in minutes) from the initiation of an interruption to a 

customer until service has been restored to that customer. For purpose of this 

study, the duration extends until service is restored to all customers of a delivery 

point regardless of whether restoration to a portion of the affected customers 

occurred partway through the interruptions through actions of the G&T or the 

distribution system operator.

h Interruption, Momentary Event

An interruption of less than five minutes in duration limited to the period 

required to restore service by an interruption device. As such, switching 

operations must be completed within a period of less than five minutes. This 

definition includes all reclosing operations which occur in less than five minutes 

of the first interruption. For example, if a recloser or breaker operates two, 

three, or four times and then holds, those momentary interruptions shall be 

considered one momentary interruption event.

i Interruption, Sustained

Any interruption five minutes or longer induration. 

j Outage

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.

k Reporting Period

The Reporting Period is assumed to be a calendar year January through 

December, unless otherwise stated.

l Transmission Exposure Miles
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Exhibit G 

Page 5

Total miles of transmission or subtransmission lines that directly serve Delivery 

Points. The distance is measured as the total miles of lines of transmission from 

the nearest breaker(s) that protects the Delivery Point. The measurement for 

three terminal lines includes the total exposure miles serving the Delivery Point. 

Exposure Miles are reported for the normally closed configuration that serves 

the Delivery Point.

3 RELIABILITY INDICES

The following reliability indices are recommended for benchmarking the reliability of 

the transmission and distribution substation components of the delivery system.

(1) Basic factors

These basic factors specify the data needed to calculate the indices. 

i denotes an interruption event

ri = Restoration Time for each Interruption Event

TE = Transmission Exposure Miles

E = Event

D = Delivery Point

T = Total

IME = Number of Momentary Interruption Events

ND

Event

= Number of Interrupted Delivery points for each Interruption

Ni = Number of Interrupted Customers for each Interruption event

During Reporting Period

NTD = Total Number of Delivery Points Served for the Area Being 

Indexed

NT = Total Number of Customers Served for the AreaBeing Indexed

NTE = Total Number of Exposure Miles for the Area BeingIndexed

(2) Traditional Reliability Indices (Sustained Interruptions)
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Exhibit G 

Page 6

The following four indices are generally consistent with the indices defined in 

draft IEEE P1366, modified, of course, to apply to interruptions on the specified 

transmission systems and distribution substations:

(1) SAIFI. System Average Interruption Frequency Index (sustained 

interruptions). This index, which approximately 81 percent of the 

utilities responding to a 1997 IEEE survey use, is designed to provide a 

measure of how often a customer experiences a sustained outage in a 

defined area.

SAIFI = Total Number of Customer Interruptions 

Total Number of Customers Served

To calculate the index, use the following equation:

SAIFI =

∑ Ni 

NT

(2) SAIDI. System Average Interruption Duration Index. This index, used 

by approximately 83 percent of the respondents to the 1997 IEEE 

survey, measures the average minutes (or hours) of interruption per 

customer.

SAIDI = Sum of Customer Interruption Durations

Total Number of Customers Served

To calculate the index, use the following equation:

∑ r N

SAIDI = i i

NT

(3) CAIDI: Customer Average Interruption Duration Index. This index 

represents the average time required to restore service to the customer 

per sustained interruption. Approximately 75 percent of the respondents 

to the 1997 IEEE survey use thisindex.

CAIDI = Sum of Customer Interruption Durations

Total Number of CustomerInterruptions

To calculate the index, use the following equation:
Bulletin 1730A-119

Exhibit G 

Page 7

i

CAIDI =

∑ r N

i i

∑ N

i

SAIDI = SAIFI

(4) ASAI. Average Service Availability Index. This index, used by 

approximately 53 percent of the respondents to the 1997 IEEEsurvey, 

represents the fraction of time, often expressed in percentage that a 

customer has power provided during the reportingperiod.

ASAI = Customer Minutes Service Availability 

Customer Minutes Service Demand

To calculate the index, use the following equation:

ASAI =

NT × (Number of hours/yr) − ∑ r Ni

NT × (Number of hours/yr)

Note: There are 8760 hours in a non-leap year, 8784 hours in a leap year

(3) G&T Specific Reliability Indices (SustainedInterruptions)

In addition to the four traditional indices, four indices specifically focused on 

G&T systems are recommended:

(1) SADPIFI. System Average Delivery Point Interruption Frequency 

Index. This index, which measures the average number of interruptions 

per delivery point for the system, is similar to SAIFI but is based upon 

delivery points rather than customers.

SADPIFI = Total Number of Delivery Point Interruptions 

Total Number of Delivery Points Served

To calculate the index, use the following equation:

SADPIFI =

∑ ND 

N

TD

(2) SADPIDI. System Average Delivery Point Interruption Duration Index. 

This index measures the average interruption duration per delivery point. 

It is similar to SAIDI, but based upon delivery points rather than 

customers.
Bulletin 1730A-119

Exhibit G 

Page 8

SADPIDI = Sum of Delivery Point Interruption Durations 

Total Number of Delivery Points Served

To calculate the index, use the following equation:

∑ r N 

SADPIDI = i D

N

TD

(3) SAILMI. System Average Interruption Line Miles Index. This index 

measures the number of transmission caused interruptions per 

transmission exposure mile.

SAILMI = Total Number of Delivery Point Interruptions 

Transmission Exposure Miles

To calculate the index, use the following equation:

∑ ND

SAILMI = N

TE

(4) SADLMI: System Average Duration Line Miles Index. This index is 

somewhat similar to SAILMI, measuring system average duration of 

transmission caused interruptions per transmission exposure mile.

SADLMI = Sum of Delivery Point Interruption Durations 

Transmission Exposure Miles

To calculate the index, use the following equation:

∑ r N 

SADLIMI = i D

N

TE

(4) Momentary Indices

Momentary interruptions have a significant impact on a customer’s reliability 

experience. In fact, many utilities report anecdotally that customers often seem 

more concerned about momentary interruptions than sustained interruptions.

Measuring momentary reliability, however, requires an enhanced focus and 

more extensive data gathering for the development of meaningful transmission 

reliability indices. Momentary Indices may either be calculated for each
Bulletin 1730A-119

Exhibit G 

Page 9

momentary outage, or by Momentary Event. For the purposes of this guide, all 

Momentary Indices are assumed to be calculated by Momentary Event. The 

following momentary indices are recommended for use in benchmarking the 

performance of the transmission and distribution substation components of the 

delivery system.

(1) MAIFI. Momentary Average Interruption Frequency Index. This index, 

used by approximately 18 percent of the respondents to the 1997 IEEE 

survey, is similar to SAIFI but tracks the average frequency of 

momentary interruptions.

MAIFI = Total Number of Customer Momentary Interruptions 

Total Number of Customers Served

To calculate the index, use the following equation:

MAIFIE = ∑ IM E N i

N T

(2) MSADPIFI. Momentary System Average Delivery Point Interruption 

Frequency Index. This index, which measures the average number of 

momentary interruptions per delivery point for the system, is similar to 

MAIFI but is based upon delivery points rather thancustomers.

MSADPIFI = Total Number of Momentary Delivery Point Interruptions

Total Number of Delivery Points Served

To calculate the index, use the following equation:

MSADPIFI = ∑ IM E N D

N TD

(3) MSAILMI: Momentary System Average Interruption Line Miles Index. 

This index measures the overall transmission system interruptions per 

load serving exposure mile.
Bulletin 1730A-119

Exhibit G 

Page 10

MSAILMI = Total Number of Momentary Delivery Point Interruptions

Transmission Exposure Miles

To calculate the index, use the following equation:

MSAILMI = ∑ IM E N D

N TE

(5) Use

These indices are currently in use by several G&Ts across the country to 

benchmark reliability performance within their organizations and with other 

G&Ts. Multiple years of consistently tracking this data can lead to 

comprehensive reporting to management, distribution borrower members, RUS, 

regulatory bodies, and transmission organizations.