20250108Gas Standards Manual (GSM) 2025.pdf

2025
Gas Standards
Manual
This manual expires on December 31, 2025
© 2025 Avista Corp.
ALL RIGHTS RESERVED UNDER U.S.AND FOREIGN LAW,TREATIES AND CONVENTIONS. NO PART OF THIS WORK
MAY BE COPIED OR REPRODUCED,STORED IN A RETRIEVAL SYSTEM,OR TRANSMITTED IN ANY FORM,GRAPHIC,
ELECTRONIC OR MECHANICAL,WITHOUT PERMISSION OF THE COPYRIGHT OWNER.

FOREWORD
This manual is written to conform to the requirements of the United States Department of
Transportation Pipeline Safety Regulations, 49 CFR, Part 191 and 192. It also, where necessary,
identifies and references applicable state codes in Avista's operating territories.
The purpose of this manual is to set forth, in writing, Avista's policy pertaining to design,
construction, operation, and maintenance of its natural gas systems. The Manager of Gas
Engineering, a licensed Professional Engineer, should be the final signatory of designs that are
completed by the Gas Engineering Department. The Avista mentioned herein refers to all states
in Avista's operating territory. This manual supersedes any previous gas standards used by
Avista gas companies prior to this date.
This manual is to be used in conjunction with the Gas Emergency and Service Handbook
(GESH), Gas Construction Specifications, Manufacturer's Operating Instructions Manual for Gas
Operations (MOI), Incident Prevention Manual (Safety Handbook), Transmission Integrity
Management Program (TIMP), Distribution Integrity Management Plan (DIMP), Anti-Drug and
Alcohol Misuse Prevention Plan, Control Room Management Plan, Natural Gas Quality
Assurance/Quality Control Program, Operator Qualification Program, and Public Awareness
Program. These documents comprise Avista's Operating and Maintenance Plan as required by
§192.605 and as required by state codes.
Operations Managers and personnel designated by them (including contractors) are responsible
for adherence to these standards for proper installation and maintenance of Avista's natural gas
facilities. This manual is made available to appropriate individuals through hardcopy,
electronically, and/or via the company intranet per§192.615(b)(1)
Throughout this manual, material is referred to as approved type rather than by manufacturer's
name or catalog number. Only materials approved by Gas Engineering or currently on record as
suitable for purchase in the Supply Chain Management Department are to be used in the
construction of company gas facilities.
Within the Gas Standards Manual a "shall" or"must" is used to indicate a provision is mandatory.
• Written variances to the Gas Standards Manual (for"shall/must" statements) may be
granted except in situations where the provision is mandatory in state/federal code in
which case the variance will not be granted.
• A request to not follow a "shall" or"must" starts with the respective local Avista
manager/designated Avista representative giving their approval.
• The request will then be forwarded to the appropriate responsible reviewer as delineated
in Specification 1.4, Table 1, for approval.
• These variances should be in written form (email preferred)and maintained with the as-
built project documents.
Within the Gas Standards Manual a "should" is used to indicate that a provision is not mandatory
but is the preferred method and recommended as a good practice.
• These "should"variances requested by Avista personnel do not require approval, but the
documentation (typically within an as-built document) should explain why the"should"
preferred method was not followed.
FOREWORD REV. NO. 20
DATE 01/01/25
� i/ISTA STANDARDS 1 OF 4
Utilities NATURAL GAS

• "Should"variances requested by Avista contractors should be approved by the respective
local Avista manager/local manager-designated Avista representative before
implementing the variance. The variance grantor's name and a reason the "should"
preferred method was not followed should be documented in the as-built document.
Responsibility for maintaining the accuracy of this manual is the function of the Gas Compliance
Department. Suggestions for improvement are always welcome. Please forward suggestions or
observations to Randy Bareither in the Gas Compliance Department via the "Recommended
Changes"form from this manual or scan and send to him at Randy.Bareither(aD-avistacorp.com.
Management Commitment and Support
Throughout our operations, Avista's intent is to safeguard people from harm by mitigating risks to our
workers, the public and our infrastructure. Avista's management is committed to supporting the Gas
Standards Manual (GSM)and the corresponding activities, which seek to recognize and mitigate threats
to Avista's natural gas pipeline infrastructure. Avista's leadership provides this continuous support
through the implementation of our Safety Management System (SMS).
Avista's SMS is a comprehensive framework, which enables a systematic and deliberate approach to
managing risk, including the necessary organizational structures, accountabilities, policies, and
procedures designed to enhance the effectiveness of risk management and enable continuous safety
improvement. The GSM is evaluated and improved in accordance with the SMS framework outlined in
Avista's Pipeline Safety Management Plan. Avista's SMS and Pipeline Safety Management Plan
connects the GSM with the other plans, programs, and emergency response activities to ensure the
continued safe operation of the gas system.
Safety Management System and Human and Organizational Performance
Avista's SMS is based on and aligned with industry guidance provided in the American Petroleum
Institute (API) Recommended Practice 1173 (RP 1173) "Pipeline Safety Management Systems." RP 1173
details the components of a pipeline SMS using 10 Essential Elements and the Plan, Do, Check, Adjust
model (PDCA).
Alongside our SMS, Avista has implemented the Human and Organizational Performance (HOP)
philosophy. HOP focuses on understanding the context and conditions of work and the interactions
between people and systems. The five principles of HOP are described below.
1. Humans make errors— Being human means people will make errors, so we must strive to build
our system tolerant of those errors.
2. Error likely situations are predictable—We cannot keep people from making errors, but we can
predict and manage "error-likely" situations (situations more likely for workers to make an
error).
3. Organizations influence human behavior—An organization, it is culture and norms impact
human behavior. By building a positive safety culture and encouraging open and honest
feedback we can continually improve safety on our pipeline system.
4. Individual behavior is reinforced by co-workers—Be a safety leader! By setting a positive
example in conducting safe work, those around us will also and continually improve our safety
culture.
FOREWORD REV. NO. 20
DATE 01/01/25
� i/ISTA STANDARDS 2 OF 4
Utilities NATURAL GAS

5. Learning from past events— By learning from near misses and past events we can understand
contributing factors, implement corrective actions, and improve for the future
The graphic below illustrates the HOP principles, encompassing the 10 Elements of the SMS, embedded
into the PDCA circle showing the cyclical nature of PDCA and the continuous improvement philosophy
of the SMS. Each cycle through PDCA produces opportunities for improvement of our defenses and
controls, making our system safer over time. The components of the Plan-Do-Check-Adjust cycle are as
follows:
Plan: In the Plan step, we establish the objectives and processes necessary to deliver results in
accordance with the Avista' policies and the expected goals. By establishing output
expectations, the completeness and accuracy of the process is also a part of the targeted
improvement.
Do: In the Do step, we execute the plan designed in the previous step.
Check: The Check step involves review of the results compared with established objectives.
Comparing those results to the expected goals we ascertain any differences, looking
for deviation in implementation from the plan.
Adjust: The Adjust step is where we take action to continuously improve safety performance.
This includes analyzing the differences between actual and planned results to determine
root cause(s) and identify and implement corrective actions to improve processes and
safety on our system.
Through the integrated approach of HOP and SMS we strive to create systems tolerant of human error by
building in the capacity to fail safely.
FOREWORD REV. NO. 20
DATE 01/01/25
� i/ISTA STANDARDS 3 OF 4
Utilities NATURAL GAS

Humans Make Errors
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Quality Assurance
This manual or portions thereof should not be reproduced. If additional copies are required,
please contact the Gas Compliance Department.
Alicia
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FOREWORD • 20
DATE 01/01/25
"XIVE-ST'a STANDARDS •

2025 UPDATES
GAS STANDARDS MANUAL
Date Section No. Category Update
Jan 01, 2025 Foreword Foreword Added abbreviation "MOI"for Manufacture's
Operating Instructions Manual for Gas Operations.
Jan 01, 2025 Foreword Foreword Changed "...or..."to"...and..."and added "(including
contractors
Clarifying verbiage added to state that requests to not
Jan 01, 2025 Foreword Foreword follow a shall/should statement require approval from
the appropriate responsible reviewer.
Management The entire subsection was rewritten to align with
Jan 01, 2025 Foreword Commitment
and Support Avista's current policies and procedures.
O&M O&M Notation added to state that only one change request
Jan 01, 2025 Recommended Recommended can be submitted per form.
Changes Changes
Jan 01, 2025 1.1 Glossary Added "...commercial..."to Business District
definition for consistency with Spec. 5.11
Jan 01, 2025 1.1 Glossary Added definition"Electrofusion"
Jan 01, 2025 1.1 Glossary Modification made to the definition of"Idle Meter"for
consistency with Spec. 5.16
Jan 01, 2025 1.1 Glossary Added definition "Idle Service(Idle Riser)"
Jan 01, 2025 1.1 Glossary Added definition "Infrared (IR)Leak Detector"
Jan 01, 2025 1.1 Glossary Added definition "Inside Meter Set"
Jan 01, 2025 1.1 Glossary Added definition "Operator Identification Number
OPID "
Jan 01, 2025 1.1 Glossary Added definition "Pipe Stub Marker"
Jan 01, 2025 1.1 Glossary Added definition "Pipeline Marker(Line Marker)"
Jan 01, 2025 1.1 Glossary Modification made to the definition of"Remote Meter"
Gas Acronyms Added abbreviation "ARS"for"Alarm Response
Jan 01, 2025 1.3 and Sheet"
Abbreviations
Gas Acronyms Added abbreviation "EPIR"for"Exposed Piping
Jan 01, 2025 1.3 and Inspection Report(Form N-2534)"
Abbreviations
Gas Acronyms Added abbreviation "GCOMS"for"Gas Control
Jan 01, 2025 1.3 and Operations Management Systems"
Abbreviations
Operations and
Jan 01, 2025 1.4 Maintenance Changed "...appropriately..."to"...accordingly..."
Plan Review
Curb Valves
Jan 01, 2025 2.14 (Underground Added a reference to GSM Spec. 3.16 regarding EFV
Service Valves
Jan 01, 2025 2.15 General Portions of paragraph reworded for accuracy.
Jan 01, 2025 2.15 Permits Added "...typically..."
Meter Types,
Aluminum, and Language revised to state that these meter types are
Jan 01, 2025 2.22 Iron Case typically of this kind.
Diaphragm
Meters

2025 UPDATES
GAS STANDARDS MANUAL
Date Section No. Category Update
Changed last sentence to read: "Ultrasonic meters
Jan 01, 2025 2.22 Meter Types can be located at Gate Stations on the Interstate side
of the custody transfer point or be used tin residential
applications, delivering gas to a home or business."
Meter Set
Jan 01, 2025 2.22 Location, Added a reference to drawing A-36712.
Protection, and
Barricades
Meter Set Added language to paragraph for clarification
Jan 01, 2025 2.22 Location, regarding the use of breakaway fittings as meter
Protection, and protection only when all other options have been
Barricades exhausted.
Jan 01, 2025 2.22 Breakaway Language revised to align with standard procedures
Fitting using installation/use of breakaway fittings.
Breakaway Last sentence in paragraph added to contact Gas
Jan 01, 2025 2.22 Fitting Engineering for approval of breakaway fittings in a
meter manifold setup.
Frequency of Directional language added to paragraph for
Jan 01, 2025 2.22 Meter Tests reference to Avista's PMC Program in the Gas Meter
Testing SOP Standard.
Jan 01, 2025 2.22 Frequency of Added the word "testing"for better clarity
Meter Tests
Jan 01, 2025 2.24 Obsolete Added reference to the AC Corrective Order Types
Regulators and Remediation time Guidelines in GSM Spec 5.20
Meter Capacity Added asterisks to table and related reference below:
Jan 01, 2025 2.24 Tables— "***A rotary meter should be used instead of a
Diaphragm diaphragm meter for this application."To notations
Meters below table.
Jan 01, 2025 2.25 General Changed "...Construction Manager..."to
"...applicable local Operations Manager..."
Jan 01, 2025 2.32 Corrosion Cell Verbiage revised to be grammatically correct.
Jan 01, 2025 2.52 Corresponding Revised name of Spec 5.23 to read "Spec. 5.23,
Standards Odorization Equipment Maintenance"
Jan 01, 2025 3.12 Other Added reference to"NACE Standard SP0188-2006"
References
Jan 01, 2025 3.12 General Added reference to GSM Spec. 3.22
Jan 01, 2025 3.12 General Changed "...try..."to"...attempt..."
Jan 01, 2025 3.12 General Changed "...Operations Manager..."to"...Gas
Operations Manager..."
Verbiage added in reference to the use of CNG
Monitoring of Trailers for short term system pressure maintenance
Jan 01, 2025 3.12 Pressures and that they do not require continuous monitoring.
Verbiage added as well to discuss temporary
bypasses.
Storage and Added "...used for an alternative non-gas carrying
Jan 01, 2025 3.12 Handling of
Pipe purpose..."

2025 UPDATES
GAS STANDARDS MANUAL
Date Section No. Category Update
Storage and
Jan 01, 2025 3.12 Handling of Changed "...objects..."to"...objects/animals..."
Pipe
Storage and
Jan 01, 2025 3.12 Handling of Changed "...carrier pipe..."to"...gas carrier pipe..."
Pipe
Abrasion
Jan 01, 2025 3.12 Resistant Added "...later in this Specification..."
Overlay Wrap
Jan 01, 2025 3.12 Test Leads Language in last paragraph revised for clarity.
Jan 01, 2025 3.12 WAC Language revised to align with Washington State
480-93-175 policy and regulations.
Steel Pipe
Jan 01, 2025 3.12 Lowering Flow chart was redrawn and reformatted to be more
Decision accurate.
Flowchart
Monitoring of Verbiage added in reference to the use of CNG
Jan 01, 2025 3.13 Pressures, Trailers for short term system pressure maintenance
throughout and that they do not require continuous monitoring.
Jan 01, 2025 3.13 Field Bending Language in final paragraph revised for accuracy.
Jan 01, 2025 3.13 Tracer Wire Updated 4th paragraph to clarify CP test box
requirements at steel to plastic transitions.
Jan 01, 2025 3.13 Tracer Wire Updated 5th paragraph discussing end of plastic main
anodes, stub markers, pipe markers and little finks.
Pre-
Jan 01, 2025 3.14 Construction Added reference to Spec.4.13
Notification for
Locate Tickets
Pre-
Jan 01, 2025 3.14 Construction Language revised to clarify the definition of an
Notification for emergency in this instance.
Locate Tickets
Pre-
Jan 01, 2025 3.14 Construction Clarifying language added to final paragraph.
Notification for
Locate Tickets
Pre- Revised to add verbiage: "...and with consideration to
Jan 01, 2025 3.14 Construction protect it from damage."
Inspection
Jan 01, 2025 3.15 Scope Language revised for accuracy.
Jan 01, 2025 3.15 General Changed "...should..."to"...shall..."
Verbiage added (two places)to clarify that installation
Jan 01, 2025 3.15 General of pipeline with less cover requires approval by Gas
Engineering.
Clearances—
Jan 01, 2025 3.15 Steel and PE Changed "...is a must."to"...is a requirement..."
Pipelines

2025 UPDATES
GAS STANDARDS MANUAL
Date Section No. Category Update
Clearances— Verbiage added to clarify that casing or conduit can
Jan 01, 2025 3.15 Steel and PE be used on PE pipelines to provide added protection.
Pipelines
Clearances—
Jan 01, 2025 3.15 Steel and PE Added "...or expedient..."
Pipelines
Shoring and
Jan 01, 2025 3.15 Excavating Changed "...exposed..."to"...affected..."
Safety
Jan 01, 2025 3.15 Trench Added reference to applicable drawings at the end of
Excavation this Specification.
Marking Pipe Changed "...OAR 952-001-0070(8))."to"...OAR 952-
Jan 01, 2025 3.15 After Installation 001-0070(9))."
OR
Pressure
Jan 01, 2025 3.15 Testing After Changed "...must..."to"...should..."
Backfillin
Updated Note 10 to say: "Trench shall allow a
Jan 01, 2025 3.15 Drawing A- minimum 2'separation from any building foundation.
38315 Where feasible, dig trench more than 2'from the
foundation.
Jan 01, 2025 3.16 Steel Service Changed "...appropriate..."to"...applicable..."
Replacement
Jan 01, 2025 3.16 Excess Flow Added "...and substantially..."
y"'
Jan 01, 2025 3.16 Excess Flow Changed "...49 CFR 192.381..."to"...§192.381..."
Valves
Jan 01, 2025 3.16 Branch"Split" Added a paragraph to clarify that a CP test box is not
Service needed at these locations.
Verbiage added: "(Note: In this instance, the
Jan 01, 2025 3.16 Branch"Split" reclassified main does not require retesting for an
Service hour as is required of other main in Specification
3.18.)'
EFV—High Added language to the paragraph for clarification of
Jan 01, 2025 3.16 Pressure the typical meter location in this scenario.
Services
Services in Added clarifying verbiage to paragraph in reference
Jan 01, 2025 3.16 Heavy Snow to drawing B-36269 at the end of this specification.
Areas
Jan 01, 2025 3.16 Main Added a paragraph to clarify that a CP test box is not
Connections needed at these locations.
Service— Added "If a bypass valve is present, it must also be
Jan 01, 2025 3.16 Termination locked off."to paragraph.
Valve
New Service Added "this includes any bypass valve that may be
Jan 01, 2025 3.16 Lines Not in present."to paragraph.
Use
Jan 01, 2025 1 3.18 1 Recordkeeping I Added "... (Test Performed By) ..."
Jan 01, 2025 3.18 Recordkeeping Added note to keep handwriting on Pressure Test
Information sticker legible when printing full name.

2025 UPDATES
GAS STANDARDS MANUAL
Date Section No. Category Update
Jan 01, 2025 3.19 Horizontal Sub-section name changed from "Longitudinal
Separation Separation"to"Horizontal Separation"
Jan 01, 2025 3.19 Horizontal Changed "...longitudinal separation..."to
Separation `...horizontal separation..."
Jan 01, 2025 3.22 Scope Added "...also..."
Jan 01, 2025 3.22 General Changed "...or..."to"...and..."
Jan 01, 2025 3.22 Weld Procedure Language added for clarity and alignment with API
Qualification 1104 Section 5.4.2.9&API 1104 Section 5.4.2.10
Removal or
Jan 01, 2025 3.22 Repair of Weld Details from API 1104 Section 9.3.10 added to
Defects or paragraph.
Cracks
Removal or
Jan 01, 2025 3.22 Repair of Weld Paragraph revised to align with repair requirement
Defects or details from API 1104 Section 10.2.2.
Cracks
Removal or
Jan 01, 2025 3.22 Repair of Weld Detail added to paragraph from API 1104 Section
Defects or 10.2.2(a)and 10.2.2 (c)for accuracy.
Cracks
Jan 01, 2025 3.23 Compatibility/ Changed "...preferred..."to"...should..."
Cross Fusions
Jan 01, 2025 3.23 Compatibility/ Added the word "...heat..."
Cross Fusions
Table C: Changed fusions times for Couplings/Fittings—3
Jan 01, 2025 3.24 IPEX/Friatec/ IPS from "100"to"65"
Frialen
Table C: Changed fusions times for Tapping Tees—4 IPS
Jan 01, 2025 3.24 IPEX/Friatec/ from "151"to"120"
Frialen
Table C: Changed fusions times for Tapping Tees—6 IPS
Jan 01, 2025 3.24 IPEX/Friatec/ from "440"to"360"
Frialen
Table C: Changed fusions times for Repair Clamps—3 IPS
Jan 01, 2025 3.24 IPEX/Friatec/ from "100"to"103"
Frialen
Table C: Changed fusions times for Repair Clamps—4 IPS
Jan 01, 2025 3.24 IPEX/Friatec/ from "151"to"138"
Frialen
Table C: Changed fusions times for Repair Clamps—6 IPS
Jan 01, 2025 3.24 IPEX/Friatec/
from "440"to"450"
Frialen
Table C: Changed fusions times for Tapping Tees— 1-1/4 IPS
Jan 01, 2025 3.24 IPEX/Friatec/ from "34"to"30"
Frialen
Table C: Changed fusions times for Tapping Tees—2 IPS
Jan 01, 2025 3.24 IPEX/Friatec/ from "54"to"61"
Frialen
Table C: Added "2 IPS X 2 IPS"and aligning data to table
Jan 01, 2025 3.24 IPEX/Friatec/ under"Tapping Tee's"
Frialen pp g

2025 UPDATES
GAS STANDARDS MANUAL
Date Section No. Category Update
Table C: Changed fusions times for Tapping Tees—3 IPS
Jan 01, 2025 3.24 IPEX/Friatec/ from "100"to"150"
Frialen
Table C: Added "3 IPS X 2 IPS"and aligning data to table
Jan 01, 2025 3.24 IPEX/Friatec/ under"Tapping Tee's"
Frialen pp g
Table C: Changed fusions times for Tapping Tees—4 IPS
Jan 01, 2025 3.24 IPEX/Friatec/ from"151"to"125"
Frialen
Table C: Changed fusions times for Tapping Tees—6 IPS
Jan 01, 2025 3.24 IPEX/Friatec/ from"440"to"546"
Frialen
Table C: Added notation below table to clarify the possible
Jan 01, 2025 3.24 IPEX/Friatec/ variations in fusion times.
Frialen
Jan 01, 2025 3.25 Installing Other Changed "...defamation..."to"...deformation..."
Lycofit Fittings
Monitoring of Verbiage added in reference to the use of CNG
Jan 01, 2025 3.32 Trailers for short term system pressure maintenance
Pressure and that they do not require continuous monitoring.
Jan 01, 2025 3.32 Patching Added reference to 192.711(c).
Monitoring of Verbiage added in reference to the use of CNG
Jan 01, 2025 3.33 Trailers for short term system pressure maintenance
Pressure and that they do not require continuous monitoring.
Monitoring of Verbiage added in reference to the use of CNG
Jan 01, 2025 3.34 Trailers for short term system pressure maintenance
Pressure and that they do not require continuous monitoring.
Installing PE Language revised to align with section "Installing
Jan 01, 2025 3.42 Carrier Pipe in Steel Carrier Pipe in Casing"regarding vent pipes.
Casing
Jan 01, 2025 3.44 General Inserted the word "actively"
Coating Bond
Jan 01, 2025 3.44 Condition Language added as follows: "...if bare metal can be
Classifications— seen."
Unbonded
Pipeline Simplified paragraph to refer to Spec. 5.14 if
Jan 01, 2025 3.44 Inspection indications of internal corrosion with pitting are
Camera observed.
Extreme
Weather Event
or Natural
Jan 01, 2025 4.11 Disaster— Added "...or induced heat or fire damage..."
Transmission
Pipeline
Facilities
Inspection

2025 UPDATES
GAS STANDARDS MANUAL
Date Section No. Category Update
Extreme
Weather Event Added notation to clarify that while this guidance is a
or Natural requirement for transmission facilities, it is
Jan 01, 2025 4.11 Disaster— recommended for distribution pipeline assets as well
Transmission if/when extreme weather events or natural disasters
Pipeline
Facilities occur.
Inspection
Locating and
Jan 01, 2025 4.13 Marking Avista Added "...and comply..."
Facilities
Locating and Changed "...within two full business days..."to"prior
Jan 01, 2025 4.13 Marking Avista to the valid start date and time list on the locate
Facilities request..."
Hard to Locate Language in reference to WASHINGTON RCW
Jan 01, 2025 4.13 Facilities 19.122.030(3)(b)&(4)(b)(i-iii)revised for clarity and
Process accuracy.
Excavator Updated verbiage to say: "Marks are good for the
Jan 01, 2025 4.13 Responsibilities following timeframes starting from the day of
for Safe Digging notification to 811/One Call Center."
Review of
Jan 01, 2025 4.13 Excavation New section added
Damage
Incidents
Photograph Added following verbiage: "Photos should be
Jan 01, 2025 4.13 Requirements submitted within two business days from the date the
excavation damage is discovered."
MAOP
Jan 01, 2025 4.15 Consideration Changed "...may be..."to"...any..."
during Startup
and Shutdown
Jan 01, 2025 4.18 Scope Changed "...assure..."to"...ensure..."
Jan 01, 2025 4.18 Throughout Revised the name of GSM Spec 5.23 for accuracy.
Jan 01, 2025 4.31 221.030.001 Changed "...or..."to"...and..."
Gas Control
Jan 01, 2025 4.51 Room Language revised in opening statement for clarity and
Management accuracy.
Plan
Jan 01, 2025 4.61 General Changed "Quality Assurance"to"QA/QC"
Objectives of Added "...and submitting recommended changes
Jan 01, 2025 4.61 the QA/QC
(where appropriate)."
Program

2025 UPDATES
GAS STANDARDS MANUAL
Date Section No. Category Update
Added/updated language: "(Submission of Gas
Material Failure Reports are not required for
Material Failure failures involving the stab fitting connections on
Jan 01, 2025 4.62 Assessment plastic Continental fittings, Aldyl-A service tee
caps, or slow crack growth failures on Aldyl-A
pipe as these failures have already been well
documented.)"
Jan 01, 2025 4.62 DOT ReportableIncidents Changed "...$139,700..."to"...$145,400..."
Jan 01, 2025 4.62 Employee Injury Changed language within paragraph for accuracy.
Jan 01, 2025 4.62 Near Misses Changed "...serious injury..."to"...severe injury..."
Other
Management
Jan 01, 2025 4.62 Directed Title of subsection renamed for clarity and accuracy.
Reasons for
Conducting an
Assessment
Gas Added new line item for: Farm Taps(Upstream
Jan 01, 2025 5.10 Maintenance Source fed from a Transmission Line—Full
Matrix—Farm Inspection)
Taps
Gas
Jan 01, 2025 5.10 Maintenance Added "Grade 3 Repair"and corresponding data.
Matrix—Leak
Survey
Gas Language in "Maintenance Frequencies"for
Jan 01, 2025 5.10 Maintenance Odorometer Calibration for consistency with Spec.(s)
Matrix— 5.12&5.21.
Instruments
Gas
Jan 01, 2025 5.10 Maintenance Added "Telemetry Devices (i.e. transmitters)&
Matrix— Pressure Recorders"and corresponding data.
Instruments
Gas Leak Added paragraph discussing "Infrared (IR)Leak
Jan 01, 2025 5.11 Detection Detector".
Instruments
Gas Leak Changed "...a detector..."to"...one type of IR
Jan 01, 2025 5.11 Detection detector..."
Instruments
Sensit IRed
Jan 01, 2025 5.11 Portable Language in final paragraph revised for accuracy.
Infrared Ethane
Detector(I Red)
Sensit IRed
Jan 01, 2025 5.11 Portable Changed "Leaks shall..."to"Instrument leaks shall..."
Infrared Ethane
Detector(I Red)
Jan 01, 2025 5.11 Survey Changed "...rain..."to"...heavy rain..."
Limitations

2025 UPDATES
GAS STANDARDS MANUAL
Date Section No. Category Update
Detection of
Jan 01, 2025 5.11 Other Language rewritten for consistency and accuracy.
Combustible
Gases
Detection of
Jan 01, 2025 5.11 Other Added "WAC 480-93-185"box
Combustible
Gases
Jan 01, 2025 5.11 Maintenance Added "until protected"to frequency for survey type
Frequencies "Non-Cathodically Protected Isolated Risers"
Jan 01, 2025 5.11 Maintenance Added "until protected"to frequency for survey type
Frequencies "Other Non-Cathodically Protected Steel Pipelines"
Jan 01, 2025 5.11 Maintenance Added "until cleared or repaired"to frequency for
Frequencies survey type"Steel Shorted Casing"
Jan 01, 2025 5.11 Maintenance Changed language frequency for survey type"Grade
Frequencies 3 Leak Repair"for clarity.
Maintenance of Added clarifying language regarding annual
Jan 01, 2025 5.12 Industrial inspections of industrial meter sets.
Meters
Maintenance of Added a reference to need for performance testing as
Jan 01, 2025 5.12 Industrial noted in Spec.2.22.
Meters
Jan 01, 2025 5.12 Control Room Subsection added for consistency with GSM Spec.
Notifications 4.51.
Chart
Jan 01, 2025 5.12 Recorders and Added "... (i.e.transmitters) ...'
Telemetry
Chart
Jan 01, 2025 5.12 Recorders and Added reference to GSM Spec. 5.10.
Telemetry
Valve Types:
Jan 01, 2025 5.13 Steel Plug Changed "Most..."to"Many..."
Valves
Jan 01, 2025 5.14 Corresponding Added "Spec. 5.11, Leak Survey"
Standards
Monitoring Steel Reference to"GSM Spec. 2.32, Cathodic Protection
Jan 01, 2025 5.14 in Steel Casings Design"changed to a reference to"GSM Spec 3.12,
"Test Leads"
Jan 01, 2025 5.14 Monitoring Steel Added verbiage to final paragraph for accuracy.
in Steel Casings
Shorted Added language to contact Gas Programs and the
Jan 01, 2025 5.14 Casings Leak Survey Program Administrator regarding newly
found shorted casings.
Jan 01, 2025 5.14 Shorted Added reference to GSM Spec. 5.11.
Casings
Jan 01, 2025 5.14 Examining Added language for consistency with the need to
Internal Pipe report internal corrosion to Gas Engineering.

2025 UPDATES
GAS STANDARDS MANUAL
Date Section No. Category Update
Maintenance
and Language under frequency for"Leak Survey of
Jan 01, 2025 5.14 Remediation Isolated Steel Pipe not Cathodically Protected"
Timeframes and revised for accuracy.
Frequencies
Maintenance Language under Repair/Remediation Completion By
and for"Cathodically Protect Isolated Steel Sections of
Jan 01, 2025 5.14 Remediation Piping (including services and risers)" revised for
Timeframes and
Frequencies accuracy.
Maintenance
and Language under Repair/Remediation Completion By
Jan 01, 2025 5.14 Remediation for"Confirmed Shorted Casings"revised for
Timeframes and accuracy.
Frequencies
Jan 01, 2025 5.15 General Added "...pipeline markers and..."
Pipeline New paragraph added: "If installing tracer wire with a
Jan 01, 2025 5.15 Markers for pipeline marker(i.e. end of main), refer to
Buried Pipe Specification 3.13 Pipe Installation Plastic Mains—
Tracer Wire for recommended installation practice.""
Pipeline Verbiage added to final paragraph to clarify the use of
Jan 01, 2025 5.15 Markers for UV resistant permanent pen or other permanent
Buried Pipe means on both sides of an off-set marker are to be
done as applicable.
Jan 01, 2025 5.16 Scope Language revised for accuracy.
Jan 01, 2025 5.16 Casings Changed "...Abandonment of Mains."to
"...Abandonment of Gas Facilities."
Vault Verbiage added to clarify that abandoned vaults can
Jan 01, 2025 5.16 Abandonment be completed removed rather than filled as
applicable.
Jan 01, 2025 5.16 Inactivating Gas Changed "...complied with:"to"...followed:"
Meter Facilities
Jan 01, 2025 5.16 Idle Meters and Language added to paragraph to further define an
Idle Services idle meter.
Jan 01, 2025 5.19 Scope Changed "...in..."to"...from..."
Maintenance Language under Frequency for"Pressure Recorders"
Jan 01, 2025 5.21 Frequencies revised for accuracy.
(Table)

OPERATING AND MAINTENANCE PLAN
RECOMMENDED CHANGES
In adherence with 49 CFR 192.603 and 192.605 and Gas Standard Spec. 1.4,"Gas Operations and Maintenance Plans",
the following is a review of the existing Company O&M Plan for conducting operations,maintenance activities and
emergency responses.
(Note: Please fill out ONE Recommended Change(RC)sheet per item. If the recommended change is applicable to more
than one area of the Gas Standards Manual(GSM)or Gas Emergency and Service Handbook(GESH),submit a separate
RC for each section.)
Manual Reviewed Date
Section
Title of procedure
Reviewed by/ Submitted by
Recommended changes (please fill out separate sheets for each recommended change):
Return to Randy Bareither, MSC 6
([e-mail])
FOR OFFICE USE:
Received Date
Action(s) Taken:

TABLE OF CONTENTS
FOREWORD
1.1 GLOSSARY
1.2 INDEX
1.3 GAS ACRONYMS AND ABBREVIATIONS
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Acronym and Abbreviations List..........................................................1-13
1.4 GAS OPERATIONS AND MAINTENANCE PLANS
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
Operations and Maintenance Plan Review............................................... 1
Construction Procedures Filing with the WUTC .......................................2
WA Filing of Construction Procedures (WAC-480-93-017).........2
Records Available to Operating Personnel...............................................2
Table 1 —Standards Accountability.......................................................3-5
2.0 DESIGN
2.1 PIPE SYSTEMS
2.12 PIPE DESIGN -STEEL
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Other References...................................................................................... 1
Corresponding Standards......................................................................... 1
Design Requirements...................................................................1
General ........................................................................................ 1
Converting an Acquired System ..................................................2
Steel Pipe Coating and Marking ..................................................2
Design Formula for Steel Pipe.....................................................2
Class Location Considerations....................................................3
Transmission Lines— Design of Pipe and Components..............3
Transmission Line— Internal Corrosion Control ..........................4
Transmission Line—Approval of Change....................................5
Reporting of Proposed Construction of Transmission Main (WA)
(WAC 480-93-160)................................................................5
Design of Pipeline Components ...............................................................5
Pressure Vessels and Prefabricated Units...............................................6
Joining of Steel Pipeline Components......................................................7
Flanged Connections................................................................................7
ASTM A105 Steel Pipe Flanges and Flanged Fittings ................8
Flange and Fastener Requirements ...........................................8
Supports - General....................................................................................9
Thermal Contraction and Expansion ........................................................9
Longitudinal Stress ......................................................................9
Deflection and Bending Stress ....................................................9
Deflection Formula and Examples...........................10-11
Bending Stress Formula and Examples....................... 10
Seismic Supports....................................................................... 11
Torsional Stress......................................................................... 11
Torsional Stress Formula and Examples...................... 11
Washington State Proximity Considerations .......................................... 11
WA Proximity Considerations (WAC 480-93-020)..................... 11
Protection of Aboveground Steel Pipelines............................................ 12
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
XVIST/i STANDARDS 1 OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

Clearances and Cover............................................................................ 12
Easement Considerations....................................................................... 12
Steel Piping Data Tables ...................................................................13-14
Manufacturing Design and Composition of Line Pipe............................. 14
Pipe Specification ...................................................................... 15
Pressure Testing........................................................................ 16
Corrosion Protection.................................................................. 16
AC Mitigation on New Steel Pipelines ....................................... 16
2.13 PIPE DESIGN - PLASTIC (POLYETHYLENE)
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
Design Requirements...................................................................1
General ........................................................................................ 1
Markings on Plastic Pipe and Components.............................................. 1
Pipe Print Line on Pipe Example.................................................2
Design Pressure .......................................................................................3
Polyethylene (PE) Pipe Dimensions Table..................................3
Pressure/Temperature Limitations............................................................3
Aboveground Plastic Pipe.........................................................................4
WA Aboveground Limitations (WAC 480-93-178(6))...................4
BridgeCrossings..........................................................................4
Plastic Pipe under Waterways..................................................................4
Clearances and Cover..............................................................................4
Thermal Contraction and Expansion ........................................................4
Joining of Plastic Pipelines ....................................................................... 5
CathodicProtection................................................................................... 5
TracerWire............................................................................................... 5
2.14 VALVE DESIGN
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
Design Requirements ............................................................................... 1
General ........................................................................................ 1
ValveTypes .............................................................................................. 1
SteelPlug Valves......................................................................... 2
SteelGate Valves........................................................................ 2
SteelBall Valves..........................................................................2
Polyethylene Valves ....................................................................2
Service Line Valves .....................................................................2
Excess Flow Valve Performance Standards ............................................2
Curb Valves (Underground Service Valves)............................................. 3
Emergency Curb Valves.............................................................. 3
WA Criteria for Emergency Curb Valves (WAC 480-93-100(2)) . 3
Valves at New Housing Developments.....................................................4
Criteria for Determining Emergency Operating Plan (EOP)Valves.........4
Tying EOP Zones Together.........................................................4
Emergency Regulator Station Valves..........................................4
Transmission Line Valves.........................................................................4
Rupture Mitigation Valve (RMV) Requirements........................................ 5
ValveNumbering ......................................................................................6
Installation.................................................................................................6
ValveSupports..........................................................................................6
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
���r■sra STANDARDS 2OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

Corrosion .................................................................................................. 7
ValveCodes.............................................................................................. 7
2.15 BRIDGE DESIGN
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
Design Requirements...................................................................1
General ........................................................................................ 1
PipelineInstallation................................................................................... 1
Permits...................................................................................................... 1
DesignRequirements ...............................................................................2
Supports....................................................................................................2
SeismicSupports.........................................................................2
CorrosionProtection.................................................................................2
Casings.....................................................................................................2
2.2 METERING & REGULATION
2.22 METER DESIGN
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Other References...................................................................................... 1
Corresponding Standards......................................................................... 1
Design Requirements...................................................................1
General ........................................................................................ 1
Pipeline Companies to Follow Law and Manufacturer's
WA Recommended Installation and Maintenance
(WAC 480-93-140(1))..................................................... 1
MeterTypes................................................................................. 1
Aluminum and Iron Case Diaphragm Meters .................2
RotaryMeters .................................................................2
Turbine Meters................................................................2
Ultrasonic Meters............................................................2
Coriolis Meters................................................................2
Meter Identification....................................................................................2
WA Meter Identification Requirements (WAC 480-909-328).......2
Meter Case Pressures..............................................................................2
Meter Set Location, Protection and Barricades........................................2
WA Meter Set Assembly Location (WAC 480-90-323)................3
BreakawayFitting ........................................................................ 5
3 Foot Rule .................................................................................. 5
10 Foot Rule ................................................................................6
EarthquakeValves....................................................................................6
InsideMeter Sets......................................................................................6
Alcove Installation........................................................................ 7
Meter Room Installation............................................................... 7
Regulator and Relief Vent Design ............................................................8
Pitsand Vaults..........................................................................................8
Installation.................................................................................................8
Meter to Flanges Torque Table ...................................................9
Overbuilds................................................................................................. 9
IdleMeters ................................................................................................ 9
IdleServices ............................................................................................. 9
MultipleServices..................................................................................... 10
MultipleMeters........................................................................................ 10
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
"471visraa STANDARDS 3OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

Insulating Downstream Customer Piping................................................ 10
MeterSet Design .................................................................................... 11
Gas Meter Information Sheets................................................................ 11
Industrial Sets and Elevated Pressure Sets ........................................... 12
Identifying Sites with Special Design and Maintenance Requirements.. 12
Gas Volume Calculation ......................................................................... 13
Behavior of Natural Gas ............................................................ 13
Computing Corrected Flows...................................................... 13
Elevation Compensation............................................................ 13
Atmospheric Pressure Elevation Table ........................ 14
Pressure Compensation ............................................................ 14
Temperature Compensation...................................................... 15
Example for Computing Corrected Flow.................................... 15
Correction Codes....................................................................... 15
Meter Correction Codes............................................................. 16
Temperature Corrected Flows................................................... 17
Frequency of Meter Tests.......................................................... 17
Prover Calibration Interval ......................................................... 17
Avista's Requirements for Gas Meter Room Installations...................... 17
Regulator and Relief Ventilation ............................................................. 18
A-36275, Residential Meter Set Location Drawing................................. 19
2.23 REGULATOR DESIGN
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
Design Requirements...................................................................1
General ........................................................................................ 1
Sizing Requirements....................................................................2
Regulation of Intermediate Pressure to Service Pressure ..........2
Regulation of High Pressure to Service Pressure.......................2
WA Requirements for Proximity Considerations (WAC 480-93-020).. 3
Valves .......................................................................................... 3
Control and Sensing Lines........................................................... 3
Capacity....................................................................................... 3
Telemetering and Pressure Recorders........................................4
Regulator Station Numbering ......................................................4
2.24 METER AND REGULATOR TABLES AND DRAWINGS
Regulator and Accuracy of Set Pressure Table ....................................... 1
ReliefCapacity.......................................................................................... 1
Obsolete Regulators..............................................................................1-2
Meter Capacity Tables..............................................................................2
Diaphragm Meters .......................................................................2
RotaryMeters .............................................................................. 3
TurbineMeters............................................................................. 3
Regulator Capacity Tables ..................................................................4-11
Meter Set Regulators (30 PSIG Inlet, 46-60 PSIG MAOP) ......4-5
Meter Set Regulators (15 PSIG Inlet, 22.6-45 PSIG MAOP) ...6-7
Meter Set Regulators (5 PSIG Inlet, 10-22.5 PSIG MAOP) .....7-8
Meter Set Regulators (2 PSIG Inlet, 6-8 PSIG MAOP) ............8-9
Farm Tap Regulator 500 PSIG MAOP Inlet .............................. 10
Relief Valve Capacities at Set Point (60 MAOP Downstream).. 11
OtherApplications................................................................................... 11
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
���r■sra STANDARDS 4OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

Drawings........................................................................................... App A
A-36712, Barricade Detail / Bollard Detail...........................App A
A-36712, Barricade Detail for Close Prox. to Electric.......... App A
A-38500, Meter Set Stand for Flex Line Support.................App A
A-34175, Single Pipe Ground Support................................App A
A-34175, Double Pipe Ground Support...............................App A
A-35208, Residential Meter Sets Intermediate Pressure ....App A
A-37102, Residential Meter, 2 psig Delivery .......................App A
A-37103, Residential & Small Commercial Meter, HP ........App A
B-35207, Residential Standard Meter .................................App A
B-35207, Commercial Standard Meter................................App A
C-35209, Small Commercial Standard Meter......................App A
C-35209, Large Diaphragm Meter Set.................................App A
B-33325, 2000, 3000 and 3500 Rotary Meters ...................App A
B-33325, 5000 and 7000 Rotary Meters .............................App A
B-33325, 11000 Rotary Meter.............................................App A
B-38205, 2000, 3000, 3500 Rotary Meters Int Pressure.....App A
B-35785, Threaded 5000 and 7000 Rotary Meters.............App A
E-37197, Code 3, 2" Standard Meter Set............................App A
E-37842, Welded Farm Tap Station, 2" outlet.....................App A
E-37970, Welded Farm Tap Station, 3/4" outlet..................App A
E-33952, Single Run District Reg, 2" x 4..............................App A
E-35783, Single Run District Reg, 4" x 6..............................App A
E-35158, Dual Run District Reg, 2" x 4" ..............................App A
L-36082, Reg Station Fencing Detail...................................App A
2.25 TELEMETRY DESIGN
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Other References...................................................................................... 1
Corresponding Standards......................................................................... 1
Design Requirements ............................................................................... 1
General ........................................................................................ 1
DataCollected ............................................................................. 1
Data Path and Uses.....................................................................2
Equipment Configuration .........................................................................3
GateStations...............................................................................3
Gas Transport and Telemetry Customers ...................................3
Regulator Sites and System Pressure Monitoring.......................3
PowerPlants................................................................................4
Table of Quantities Measured......................................................4
Communications....................................................................................... 5
PowerSource ........................................................................................... 5
Electrical Classification ............................................................................. 5
SensingLines ........................................................................................5-6
Avista Procures............................................................................ 7
Customer Provides ......................................................................8
AvistaProvides............................................................................8
Notification and Timing ................................................................8
Drawing - E-37114, Gas Transportation Customer Detail........................9
2.3 CATHODIC PROTECTION
2.32 CATHODIC PROTECTION DESIGN
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
"471visraa STANDARDS 5OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

Corresponding Standards......................................................................... 1
Theory of Corrosion.................................................................. ... 1
ACvs. DC .................................................................................... 1
CorrosionCell .............................................................................. 1
Anode and Cathode Reactions....................................................2
Anode-Cathode Area Ratio..........................................................2
Electrolyte Resistivity................................................................... 3
Anode-Cathode Separation Distance..........................................3
DissimilarMetals.......................................................................... 3
The Galvanic Series.....................................................................4
StressCorrosion..........................................................................4
ControllingCorrosion ................................................................................4
Insulation......................................................................................4
MetallicCoatings..........................................................................4
Nonmetallic Materials ..................................................................5
Change in Environment...............................................................5
Cathodic Protection......................................................................5
GalvanicSystem..........................................................................5
Impressed Current System..........................................................5
Design and Installation..............................................................................5
General ........................................................................................ 5
WA Pipe Systems Corrosion Protection (WAC 480-93-110).......5
WA Grounding Well Design (WAC 173-160-456(2))...................6
AnodeSystems............................................................................ 6
ACMitigation................................................................................ 6
TestLeads................................................................................... 6
TracerWire.................................................................................. 6
SystemIsolation........................................................................... 7
Replacing Steel Main................................................................... 7
Replacing Steel Services.............................................................7
2.4 VAULTS
2.42 VAULT DESIGN
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Other References...................................................................................... 1
Corresponding Standards......................................................................... 1
Design Requirements ............................................................................... 1
General ........................................................................................ 1
Sealing and Ventilation................................................................2
Drainage ......................................................................................2
ElectricalCode.............................................................................2
2.5 ODORIZATION
2.52 ODORIZATION OF NATURAL GAS
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
Odorization................................................................................................ 1
General ........................................................................................ 1
OdorantType............................................................................... 1
OdorizerTypes ............................................................................2
Odorant Concentrations............................................................................2
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
"471visraa STANDARDS 6OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

3.0 CONSTRUCTION
3.1 PIPE INSTALLATION
3.12 PIPE INSTALLATION —STEEL MAINS
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Other References...................................................................................... 1
Corresponding Standards......................................................................... 1
Construction Requirements ...................................................................... 1
General ........................................................................................ 1
Monitoring of Pressures...............................................................2
TemporaryBypass.......................................................................2
Storage and Handling of Pipe...................................................... 3
VisualInspection.......................................................................... 3
Stringing....................................................................................... 3
MasticCoating.............................................................................4
TapeWrap...................................................................................4
Cold Applied Tape Wrap..............................................................4
Coating on Steel Risers...............................................................5
WaxType—Tape Wrap............................................................... 5
Repair and Patching Using Tape Wrap....................................... 5
Repair and Patching Using a Coating Patch ............................... 5
Field Pinhole Repair.....................................................................6
LiquidEpoxy Coating...................................................................6
Liquid Epoxy Curing Timetable.......................................6
Abrasion Resistant Overlay Wrap...........................................7-12
Installation in Ditch..................................................................... 12
TestLeads................................................................................. 12
Cadweld Procedure ..............................................................13-14
CautionTape ............................................................................. 14
MarkerBalls............................................................................... 14
Dry Line Installations ................................................................. 14
Electrical Inspection of Pipeline Coatings (Jeeping).................. 15
Voltage Settings for Conventional Coatings.............................. 15
Voltage Settings for Conventional Coatings Table.................... 15
Voltage Settings for Thin Film Coatings (FBE).......................... 16
Voltage Settings for ARO Pipe .................................................. 16
Coating Thickness for New Pipe................................................ 16
New Pipe Coating Thickness Table.............................. 16
Supports..................................................................................... 16
PipeBends................................................................................. 17
Minimum Steel Bend Radius Table .............................. 17
Mitering/Segmenting Elbows..................................................... 17
Piggingof Pipe........................................................................... 17
Pitsand Vaults........................................................................... 17
Odorizing Newly Installed Pipe.................................................. 18
Moving or Lowering Steel Pipe in Service................................. 18
Minimum Roping Distance on Both Sides of the
Moved Pipe Section Table ..................................... 18
Piping and Weld Data Collection .............................................. 19
Toughness Testing .................................................................... 19
WA High Pressure Pipeline Diameter Requirements(WAC 480-93-175)19
Recordkeeping...........................................................................20
Pipe Coupon Retention Procedures..........................................20
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
"471visraa STANDARDS 7OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

Updating Maps and Records.....................................................20
WA Recordkeeping (WAC 480-93-018(5))...................20
Steel Pipe Lowering Decision Flowchart...................................21
Drawings............................................................................................22-23
A-35447, Color Coding of Test Leads Across Insulated Ftgs ...22
B-36271, Steel Test Stations & Isolation Fittings ......................23
3.13 PIPE INSTALLATION — PLASTIC (POLYETHYLENE) MAINS
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
Construction Requirements ...................................................................... 1
General ........................................................................................ 1
QualifiedJoiners.......................................................................... 1
Monitoring of Pressures...............................................................2
Storage of Pipe and Associated Components.............................2
Handling.......................................................................................3
Installation.................................................................................... 3
Temporary Bypass.......................................................................4
FieldBending...............................................................................4
Minimum Permanent Bending Radius Table...............................4
Shear and Tensile Stresses......................................................... 5
TracerWire.................................................................................. 5
Wire Connections......................................................................... 6
Pulling Limitations........................................................................ 6
Plowing and Planting ................................................................... 6
Minimum Temporary Bending Table............................................ 7
CautionTape ............................................................................... 7
MarkerBalls................................................................................. 7
Dry Line Installations ................................................................... 7
Pulling-In...................................................................................... 8
Safe Pulling Forces...................................................................... 8
Safe Pulling Forces Table............................................8-9
Break-Away Pin or Weak Link................................................... 10
StaticCharges ........................................................................... 10
Examining Buried Pipe .............................................................. 11
Piggingof Pipe........................................................................... 11
Odorizing Newly Installed Pipe.................................................. 11
Pressure Testing........................................................................ 11
Updating Maps and Records..................................................... 11
WA Requirement to Update Records within 6 Months of a Construction
Activity (WAC 480-93-018(5)).................................................... 11
Drawings............................................................................................ 12-14
A-35776, Taping Tracer Wire to Pipe........................................ 12
A-36277, Tracer Wire & Nuts..................................................... 13
B-39147, PE Test Stations &Tracer Wire................................. 14
3.14 PRE-CHECK LAYOUT AND INSPECTION
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
Preliminary Inspection and Layout............................................................ 1
General ........................................................................................ 1
Pre-Construction Notification for Locate Tickets ......................... 1
Pre-Construction Inspection ........................................................2
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
"471visraa STANDARDS 8OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

Layout..........................................................................................2
JointDitch ....................................................................................2
3.15 TRENCHING & BACKFILLING
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
Trenching Requirements .......................................................................... 1
General ........................................................................................ 1
Cover........................................................................................... 1
Clearances—Steel and PE Pipelines..........................................2
Vegetation Clearance ..................................................................3
Shoring and Excavating Safety....................................................3
TrenchExcavation.......................................................................3
ExaminingBuried Pipe ................................................................3
PaddingMaterial..........................................................................4
Controlled-Density Backfill...........................................................4
Backfill..........................................................................................4
Compaction..................................................................................4
Marking Pipe after Installation (OR).............................................5
Pressure Testing After Backfilling................................................5
Pipeline Markers..........................................................................5
Customer Trench/ Ditch Detail Drawings....................................5
Drawings................................................................................................6-7
A-38315, Customer Supplied Ditch Relocation Spec..................6
A-38315, Customer Provided Trench Construction Spec............7
A-38315, Natural Gas Main Trench Detail...................................8
A-38315, Natural Gas Main Clearances......................................9
3.16 SERVICES
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
Installation Requirements ......................................................................... 1
General ........................................................................................ 1
Location Considerations.............................................................. 1
New Plastic Services ...................................................................2
Steel Service Replacement .........................................................2
Excess Flow Valves..................................................................................2
EFV Criteria Table .......................................................................3
EFV Symbology Table.................................................................3
Capacityof EFV...........................................................................4
EFV Capacity Tables...................................................5-7
Branch (Split) Service...............................................................7-8
Installation of Excess Flow Valves ..............................................9
EFV— Installation Procedures Service Tee Style...........9
EFV— Installation Procedures In-Line "Stick" Style........9
EFV— High Pressure Services..................................... 10
ServiceRisers......................................................................................... 10
Service Risers for Multi-Meter Manifolds................................... 11
Services in Heavy Snow Areas............................................................... 11
Service Lines in Conduit/Casing............................................................. 11
Requirement for Sealing Conduit Ends (WAC 480-93-115) ............ 11
Service Lines into Buildings.................................................................... 11
Service Lines Passing Under Buildings.................................................. 12
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
>risra STANDARDS 9OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

Main Connections ................................................................................... 12
CurbValves ............................................................................................ 12
Insertion of Old Steel Services Along Steel Main................................... 12
Insertion of Old Steel Services Along Plastic Main................................. 13
Service -Termination Valve.................................................................... 13
Steel Service Abandonment................................................................... 13
New Service Lines Not in Use................................................................ 13
Service Lines to Recreational Vehicles ................................................. 13
Service Lines to Floating Structures....................................................... 14
Service Pipe Capacities.......................................................................... 14
Service Pipe Capacities Chart................................................... 14
Pipe Sizes and Capacities Downstream of Meter..................... 14
Pipe Sizes and Capacities Downstream of Meter Charts.....14-18
Drawings............................................................................................ 19-21
A-34735, Inserting 3/4" Steel Service with PE ....................... 19
A-37169, '/2" PE Svc& EFV Off Steel IP Main ..........................20
A-37169, '/2" &3/4" PE Service and EFV Off of a Steel IP Main.21
3.17 PURGING PIPELINES
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Other References...................................................................................... 1
Corresponding Standards......................................................................... 1
Prevention of Accidental Ignition .............................................................. 1
Purging Requirements..............................................................................2
General ........................................................................................2
PurgingPlan ................................................................................2
Purging Main with Laterals ..........................................................2
InjectionRate...............................................................................2
Venting and Blow Down...............................................................3
Blow Down Procedure ..............................................................................3
StaticCharges .............................................................................3
Bleed Off of Steel Pipe ................................................................4
Bleed Off of Plastic Pipe..............................................................4
Purging Air out of Facilities to be Placed in Service............................4
Purging Services..........................................................................4
Purging Services with an Excess Flow Valve .............................4
SmallPipelines ............................................................................ 5
LargePipelines............................................................................ 5
Purgingwith Nitrogen .................................................................. 5
Nitrogen Purging Data for 4"—20" Pipe Table...............6
Verifying the Presence of Gas..................................................... 7
Purging Natural Gas Out of Existing Facilities.......................................... 7
SmallPipelines ............................................................................ 7
LargePipelines............................................................................ 7
Verifying the Absence of Gas......................................................8
Flaring of Natural Gas..................................................................8
Working on Purged Pipeline........................................................8
3.18 PRESSURE TESTING
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Other References...................................................................................... 1
Corresponding Standards......................................................................... 1
Pressure Testing Requirements............................................................... 1
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
"471visraa STANDARDS 10OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

New and Replacement Pipe........................................................ 1
DryLine Pipe ............................................................................... 1
Pressure Testing for Steel ...........................................................2
Maximum Test Pressure Permitted Table ...................................2
WA Notification to WUTC Prior to Pressure Testing
Transmission Pipe (WAC 480-93-170) .................................4
Pressure Test Chart— HP Steel Pipeline Systems......................5
Pressure Testing Chart— IP Steel Pipeline Systems ..................6
Pressure Testing Requirements for PE....................................... 7
Pressure Test Chart— Plastic Pipeline Systems.........................8
Reinstating Service Lines ............................................................8
Recordkeeping.............................................................................9
Avista Pressure Test Information Sticker .................................. 10
Pressure Test Procedures......................................................... 11
3.19 TRENCHLESS PIPE INSTALLATION METHODS
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ..................................................................................................... 1
Tracking and Potholing when Crossing Utilities .......................... 1
Horizontal Separation ..................................................................2
Depthof Cover.............................................................................2
Future Locatability........................................................................2
Steel— Minimum Radius of Curvature.........................................2
PE— Minimum Radius of Curvature ............................................3
Horizontal Directional Drilling....................................................................3
General ........................................................................................ 3
Permits.........................................................................................3
Pilot Hole Alignment.....................................................................3
HDDBore Path ............................................................................ 3
Reaming....................................................................................... 3
Pullback .......................................................................................4
HDD Discharge Mitigation Plan ...................................................4
PipeSplitting.............................................................................................4
General ........................................................................................4
Determining Factors..................................................................... 5
Equipment Requirements— Steel or PE...................................... 5
Equipment Requirements - PE .................................................... 5
Procedure ....................................................................................6
Pneumatic Missiling/Piercing....................................................................6
General ........................................................................................6
Determining Factors.....................................................................6
Missile Alignment Procedure.......................................................6
3.2 JOINING OF PIPE
3.22 JOINING OF PIPE -STEEL
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Other References...................................................................................... 1
Corresponding Standards......................................................................... 1
Welder Qualification Requirements.......................................................... 1
General ........................................................................................ 1
Qualifications of Welders............................................................. 1
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
"471visraa STANDARDS 11 OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

Recommended Initial Qualification Test—
Production and In-Svc <60 PSIG GMAW/SMAW....2
Recommended Initial Qualification Test—
Production and In-Svc >60 PSIG GMAW/SMAW... 3
Recommended Re-Qualification Test—
Production and In-Svc GMAW/SMAW.................... 3
WeldTesting................................................................................ 3
Retesting after Failure ................................................................. 3
Welder Certification Card............................................................. 3
Weld Procedure Qualification Requirements............................................4
General ........................................................................................4
Weld Procedure Qualification ......................................................4
Weld Procedure Groupings .........................................................5
Welding Control Requirements.................................................................5
Weld Type/Procedure Selection ..................................................5
WeldPreparation.........................................................................6
Non-Destructive Pre-Inspection...................................................6
Pipe End Alignment.....................................................................7
MiterJoints................................................................................... 7
Circumferential Weld Separation.................................................7
Preheating.................................................................................... 8
Post Heat Weld Treatment .......................................................... 8
Over-Cooling................................................................................ 8
Grounding Devices ...................................................................... 8
Butt Welding Technique............................................................... 8
Depositing Root Bead and Hot Pass........................................... 9
Filler and Cover Passes............................................................... 9
RollWelding............................................................................... 10
Fillet Welding ............................................................................. 10
Fillet Welding Diagram............................................................... 10
SocketWelding.......................................................................... 10
Socket Welding Diagram ........................................................... 11
Non-Destructive Testing (NDT) Requirements.......................... 11
Determining Speed of Travel..................................................... 12
Removal or Repair of Weld Defects or Cracks.......................... 12
Electrode Storage...................................................................... 13
VisualInspection..................................................................................... 13
Weld Defects/Causes/Visual Checks ...................................13-14
Appendix A Weld Procedure Index
3.23 JOINING OF PIPE - PLASTIC (POLYETHYLENE) - HEAT FUSION
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Other References...................................................................................... 1
Corresponding Standards......................................................................... 1
JoiningMethods........................................................................................ 1
General ........................................................................................ 1
Qualifying Joining Procedures..................................................... 1
Qualifications of Persons to Join Plastic Pipe ............................. 1
WA Requirements for PE Joint Tracking (WAC 480-93-080)......2
MarkingJoints..............................................................................2
Pipe Joining Certification Record.................................................2
Maintenance and Calibration of Heat Fusion Equipment............2
Butt Fusion Procedures ............................................................................2
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
"471visraa STANDARDS 12OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

General ........................................................................................2
HeatingTool................................................................................. 3
Heater Surface Temperature Table.............................................3
Approx. Melt Bead Size Table.....................................................4
Heater Plate Removal Times Table.............................................4
Butt Fusion Cooling Times Table.................................................5
Hydraulic Butt Fusion................................................................................5
Determining Drag Pressure.........................................................6
Determining Fusion Pressure......................................................6
Hydraulic Fusion Pressures (#28HF McElroy Machine)..............7
Hydraulic Shift Sequence ............................................................7
Cold Weather Fusion ................................................................................8
Butt Fusion Bead Troubleshooting Guide.................................................9
Compatibility/Cross Fusions.....................................................................9
3.24 JOINING OF PIPE - PLASTIC (POLYETHYLENE) ELECTROFUSION
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Other References...................................................................................... 1
Corresponding Standards......................................................................... 1
General ........................................................................................ 1
Qualifying Joining Procedures.....................................................2
Qualifications of Person to Join Plastic Pipe ...............................2
Maintenance and Calibration of Heat Fusion Equipment............2
Calibration Timeframes of Electrofusion Equipment ...................2
MarkingJoints..............................................................................2
Standard Coupling and Endcap Joining Procedures.............................3-4
Repair Coupling Joining Procedure..........................................................5
Saddle Joining Procedure.........................................................................5
Aldyl A Tee Repair Procedure..................................................................6
Service Line Joining Procedure................................................................6
TappingProcedure ...................................................................................6
Repair Clamp Joining Procedure...........................................................6-7
Re-fusion of Electrofusion Fittings............................................................7
Fusion/Cooling Times Table................................................................8-13
3.25 JOINING OF PIPE - PLASTIC (POLYETHYLENE) - MECHANICAL
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ..................................................................................................... 1
MarkingJoints...........................................................................................2
Procedures................................................................................................2
Procedures for Installing Approved Spigot and Sleeve
Type Couplings and Fittings using the QRP-100 Quick
Ratchet Press Tool................................................................2
Installation Procedure for Double Ended Couplings.......2
Installing Other Lycofit Fittings........................................ 3
Procedures for Installing Approved Spigot and Sleeve Type
Couplings/Fittings using the LHP-200 Hydraulic Press
Tool.................................................................................3
Procedures for Installing Approved Compression Type Service
HeadAdapters ......................................................................4
Procedure for Installing Approved Slip-Lock Type Service
Head Adapters (i.e., "Perfection" type)..................................5
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
>risra STANDARDS 13OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

Procedure for Installing Approved Weld-On 1201 and 1302
Style Steel Punch Tees with Compression Type Outlet
Connection for PE Pipe......................................................6-7
Procedure for Installing Approved Weld-On 1201 and
1302 Style Steel Punch Tees with Spigot and Sleeve Type
Outlet Connection for PE Pipe ..............................................7
Procedure for Installing Approved PE Compression X Weld
End Adapter Couplings (Sometimes Referred to as the
,Button" Fitting)......................................................................8
Procedure for Installing Approved Bolt-On Type Mechanical
Tees with Spigot and Sleeve Type Outlet Connection..........9
Procedure for Removing Scratches from PE Pipe Prior to
Installation of a Mechanical Tapping Tee............................ 10
Procedure for Installing 1/2 Inch and 3/4 Inch Abandonment
Nuts on Continental Steel to PE Service Tee ..................... 10
3.3 REPAIR OF DAMAGED PIPELINES
3.32 REPAIR OF STEEL PIPE
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Other References...................................................................................... 1
Corresponding Standards......................................................................... 1
Steel Repair Requirements....................................................................... 1
General ........................................................................................ 1
Monitoring of Pressure.................................................................2
ServiceLines ...............................................................................2
Grinding .......................................................................................2
Grinding and Fill Welding.............................................................2
Patching.......................................................................................3
Sleeving .......................................................................................3
Mueller Save-A-Valve Nipple or Equivalent.................................3
Canning (Barreling)......................................................................3
Tapping and Plugging Procedures ..............................................3
Replace Segment of Pipe............................................................3
Pre-Tested Steel Pipe..................................................................4
Dents (Pipe Distortion).................................................................4
Repair Clamps and Sleeves........................................................4
Transmission Lines......................................................................4
Leak Repair and Residual Gas Checks.......................................5
Recordkeeping.............................................................................5
Specific Repair Methods..............................................................5
Steel Repair Charts..............................................................................6-11
Steel Repair Chart where MAOP <_100 PSIG...........................6-8
Steel Repair Chart where MAOP >100 PSIG, <500 PSIG,
and <20% SMYS ....................................................................8-10
Steel Repair Chart where MAOP >_500 PSIG and
>_20% SMYS..........................................................................10-11
3.32A PERMANENT REPAIR SLEEVES
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Other References...................................................................................... 1
Corresponding Standards......................................................................... 1
General ..................................................................................................... 1
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
XV1ST, STANDARDS 14OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

Plidco Split-Sleeve Steel Repair Clamp Procedure.................................. 1
General ........................................................................................ 1
Precautions.................................................................................. 1
Installation....................................................................................2
Field Welding Instructions ...........................................................2
Welding Sequence....................................................................... 3
Testing ......................................................................................... 3
Storage ........................................................................................3
TD Williamson Permanent Hemi-Head Repair Sphere Procedure... ....... 3
General ........................................................................................ 3
Precautions.................................................................................. 3
Installation....................................................................................4
Fit-Up and Welding Sequence.....................................................4
Inspection.....................................................................................4
3.33 REPAIR OF PLASTIC (POLYETHYLENE) PIPE
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
Plastic Repair Requirements.................................................................... 1
General ........................................................................................ 1
Monitoring of Pressure.................................................................2
Pre-Tested Pipe...........................................................................2
StaticCharges ............................................................................. 2
Temporary Repairs...................................................................... 2
Permanent Repairs...................................................................... 3
Plastic Repair Selection Chart.....................................................3
Damage to Service Line .............................................................. 3
HeatDamage...............................................................................4
MarkingJoints .............................................................................4
Recordkeeping.............................................................................4
3.34 SQUEEZE-OFF OF PE PIPE AND PREVENTION OF STATIC ELECTRICITY
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ........................................................................................ 1
Squeeze-Off Tools....................................................................... 1
Monitoring of Pressures............................................................... 1
Prevention of Accidental Ignition by Static Electricity..................2
Prevention of Static Electricity Procedures...............................................2
Aerosol Static Suppression Procedure........................................ 3
Wet Soapy Rag Procedure.......................................................... 3
Squeezing Procedure ...............................................................................4
WA Requirements for Pipe Squeezing (WAC 480-93-178).........4
Squeeze Procedure..................................................................... 5
Squeeze Release Procedure....................................................... 5
PE Pipe Squeeze and Release Rates Tables..........................................6
Post-Squeeze Procedure..........................................................................6
3.35 DETAILED PROCEDURES FOR USE OF "ADAMS" STYLE REPAIR CLAMPS
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ..................................................................................................... 1
Precautions............................................................................................... 1
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
"471visraa STANDARDS 15OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

Romac Style SS1 Procedure....................................................................2
Adams and Mueller Style Procedure........................................................ 3
3.4 MISCELLANEOUS CONSTRUCTION
3.42 CASING AND CONDUIT INSTALLATION
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
Design Requirements ............................................................................... 1
General ........................................................................................ 1
WA Requirement for Sealing Conduit Ends (WAC 480-93-115). 1
CasingSize..................................................................................2
Steel Casing for Steel Carrier Pipe Spec. Table .........................2
Steel Casing for PE (Polyethylene) Carrier Pipe Spec. Table.....2
Casing Specifications ..................................................................2
Installation Requirements. ........................................................................3
Installing Steel Carrier Pipe in Casing.........................................3
WA Requirements for Test Leads (WAC 480-93-115)................4
Installing PE Carrier Pipe in Casing.............................................4
Conduits.......................................................................................5
Drawings................................................................................................6-8
B-34947, Big and Little Fink Casing Detail..................................6
E-33947, Standard Casing Detail .............................................7-8
3.43 LAND DISTURBANCE REQUIREMENTS
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ..................................................................................................... 1
Definitions ................................................................................................. 1
Storm Water Permitting Requirements.....................................................2
Storm Water Erosion Control Guidance for>1 Acre Table ...................... 3
Best Management Practices (BMPs)........................................................4
PlanningBMPs ............................................................................4
Erosion Control BMPs .................................................................5
Sediment Control BMPs ..............................................................5
Run-off Control BMPs..................................................................5
Construction Activities, Typical Gov. Agencies and Associated Permits
Table................................................................................................6-7
Exhibit A—Common BMPs and How to Implement.................................8
Silt Fence Sediment Control BMP...............................................8
Fiber Roll/Straw Wattle Sediment Control BMP..........................9
Rock Check Dam Run-off Control BMP..................................... 10
3.44 EXPOSED PIPE EVALUATION
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ..................................................................................................... 1
External Examination Plastic Pipe............................................................2
Examining Buried Steel and Pipe Coating................................................2
Examining Buried Portion of Steel Risers.................................................3
Coating Bond Condition Classifications.......................................3
Soil Type Descriptions.................................................................3
Low Cathodic Protection (CP) Read Identified.........................................4
Internal Steel Pipe Examination................................................................4
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
XVIST/i STANDARDS 16OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

Internal PE Pipe Examination...................................................................4
Pipeline Inspection Camera......................................................................4
Compliance...............................................................................................4
Records Retention .................................................................................... 5
Examples of Pipe Exposures.................................................................... 5
4.0 OPERATIONS
4.11 CONTINUING SURVEILLANCE
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ........................................................................................ 1
Information Analysis and Responsibilities ................................... 1
Extreme Weather Event or Natural Disaster—Transmission
Pipeline Facilities Inspection..................................................2
Map and Data Corrections...........................................................2
4.12 SAFETY-RELATED CONDITIONS
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ........................................................................................ 1
Reporting of Safety-Related Conditions ...................................... 1
Exceptions to Reporting Safety-Related Conditions....................2
Filing of Safety-Related Condition Report...................................3
Recordkeeping..........................................................................................3
4.13 DAMAGE PREVENTION PROGRAM
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ........................................................................................ 1
Public Awareness Program .........................................................2
Inspection and Protection of Pipeline after Railroad Accidents...2
One Call Notification System.......................................................2
Requests for Locates Through One Call .....................................3
Requesting Emergency Locates..................................................3
Locating and Marking Gas Facilities.........................................3-5
Websites for State Underground Dig Laws ....................4
Hard to Locate Facilities Process..........................................................6-7
ToleranceZone......................................................................................7-8
Diagram -WA/ID Tolerance Zone ............................................... 7
Diagram— Oregon Tolerance Zone............................................. 8
Recordkeeping.......................................................................................... 8
APWA Uniform Color Codes for Marking.................................................. 8
Excavator Responsibilities for Safe Digging............................................. 9
Locate Ticket Availability .......................................................................... 9
On-Site Inspections - General ..................................................................9
Blasting Near Pipelines.............................................................. 10
Peak Particle Velocity Chart......................................... 10
On-Site Inspections for Transmission Facilities......................... 11
Excavation Identified Without a Locate Ticket (WA).................. 12
WA Excavator Digging within 35 FT of a Transmission
Pipeline (WAC 480-93-200(9))............................................ 12
Intentional Damage or Removal of Locate Marks ..................... 12
Mapping Corrections.................................................................. 12
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
"471visraa STANDARDS 17OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

Response to Facility Damage.................................................... 13
Avista Damage to Other Facility Operators............................... 13
Review of Excavation Damage Incidents .................................. 14
Photograph Requirements......................................................... 14
3rd Party Excavation Damage: One Call Check......................... 14
WADamage Reporting........................................................................... 14
WA Excavator Notifications ....................................................... 14
Reporting of Damage (WAC 480-93-200(7)(b)) ........................ 15
Damage Record Retention (WAC 480-93-200(7)(c))................ 15
WA Notification of Excavator(WAC 480-93-200(8)) .... 15
Building Permits near Transmission Utility Easements............. 15
Right of Way Easement and Notification to Pipeline
Company (RCW Chapter 19.122.033(4))............... 15
4.14 RECURRING REPORTING REQUIREMENTS
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ........................................................................................ 1
Reporting Distribution Facilities................................................... 1
Reporting Transmission Facilities................................................ 1
Submission of Reports................................................................. 1
TIMP Performance Reporting...................................................... 2
PHMSA Conditional Reporting ....................................................2
WUTC Pipeline Leaks Emissions Report
(RCW 81.88.160) ..................................................................2
WUTC Construction Defects and Material Failures Report
(WAC 480-93-200(10)(b)) .....................................................2
DOT Drug &Alcohol MIS Form Submission
(WAC 480-93-200(13)).......................................................... 3
Plans and Procedures............................................................................... 3
WUTC Plans and Procedures (WAC 480-93-180(2)).................. 3
NPMSUpdating ........................................................................................ 3
250+ PSIG Pipelines Map Submission (Washington) .............................. 3
WADamage Reporting............................................................................. 3
WUTC Damage Reporting (RCW Chapter 19.122.053(1) & (3)) 4
WUTC Damage to Own Underground Facility
(RCW Chapter 19.122.053(2) ...............................................4
WA Utilization of the Reporting Tool (WAC 480-93-200(7))........4
WAReporting Requirements....................................................................4
WA Damage Reporting Requirement (WAC 480-93-200(7)(b)).. 5
IDDamage Reporting............................................................................... 5
ID Damage to Underground Facilities (Idaho Code Title 55
Chapter 22; 55-2208 (5)........................................................5
Document Retention.................................................................................5
WA Administrative Code Requirements for Document
Retention (WAC 480-93-200(7)(c))....................................... 5
4.15 MAXIMUM ALLOWABLE OPERATING PRESSURE (MAOP)
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ........................................................................................ 1
Determination of MAOP............................................................... 1
Steel Pipe (>_100 PSIG)Test Pressure Chart................. 1
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
"471visraa STANDARDS 18OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

Proximity Considerations (WAC 480-93-020).................2
ChangingMAOP..........................................................................2
MAOP Considerations during Startup and Shutdown .................2
Recordkeeping.............................................................................2
WA Recordkeeping Requirements (WAC 480-93-018(5))....2
4.16 CLASS LOCATIONS
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ........................................................................................ 1
ClassLocations............................................................................ 1
Class Location Boundaries..........................................................2
Drawing— Clustering Example .......................................2
Class Location Study...................................................................2
Change in Class Location............................................................2
Confirmation or Revision of MAOP..............................................3
MAOP Reconfirmation.................................................................4
Documentation of MAOP Revisions ............................................4
Records........................................................................................4
4.17 UPRATING
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ........................................................................................ 1
Uprating Requirements............................................................................. 1
Uprating Pipeline to Hoop Stress <30% SMYS...........................2
Uprating Pipeline to Hoop Stress >_30% SMYS...........................2
Considerations for Uprating Steel Pipelines................................3
Uprate in State of Washington.....................................................3
Uprating Procedure -Typical Sequence of Events...................................3
Prior to Pressure Increase...........................................................3
During the Pressure Increases....................................................4
Uprate Acceptability Criteria........................................................4
After Final MAOP is Achieved ..................................................... 5
Recordkeeping.......................................................................................... 5
4.18 ODORIZATION PROCEDURES
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ........................................................................................ 1
Odorant Concentrations............................................................................ 1
Pickling Newly Installed Pipe....................................................................2
OdorantSampling.....................................................................................2
TestPoint Review.....................................................................................2
Locations Where Odor is Inadequate.......................................................2
Odorant Level Analysis................................................................ 3
Periodic Odorizer Station Inspections....................................................... 3
Recordkeeping.......................................................................................... 3
YZ Odorometer (DTEX) ........................................................................... 3
General ........................................................................................ 3
Operating Instructions..................................................................3
Threshold Detection Level (TDL).................................................4
Readily Detectable Level (RDL) ..................................................4
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
"471visraa STANDARDS 19OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

Exhaust Background Evaluation..................................................4
Calibration of Instrument..............................................................4
4.19 CREW ACTIVITY REPORTING WASHINGTON
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ........................................................................................ 1
DailyReporting ............................................................................ 1
Submission of Reports................................................................. 1
WUTCContact............................................................................. 1
4.2 CUSTOMER NOTIFICATION
4.22 CUSTOMER OWNED SERVICE LINES
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ........................................................................................ 1
Required Information ................................................................... 1
One-Time Notification.................................................................. 1
Ongoing Notification .................................................................... 1
Recordkeeping.............................................................................2
4.3 OPERATOR QUALIFICATION PROGRAM
4.31 OPERATOR QUALIFICATION
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ........................................................................................ 1
Covered Task List—Appendix A
Evaluation Guidelines —Appendix B
Operator Qualification Acceptance Form —Appendix C
Operator Qualification Investigation Guideline Flowchart—Appendix D
4.4 INTEGRITY MANAGEMENT PROGRAMS
4.41 TRANSMISSION INTEGRITY MANAGEMENT PROGRAM (TIMP)
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
Integrity Management Principles ........................................................... 1-2
4.42 DISTRIBUTION INTEGRITY MANAGEMENT PROGRAM
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ........................................................................................ 1
Distribution Integrity Management Elements.........................................1-2
4.51 GAS CONTROL ROOM MANAGEMENT PLAN
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
Control Room Major Elements.................................................................. 1
Control Room Notifications..........................................................2
4.61 QUALITY ASSURANCE/ QUALITY CONTROL (QA/QC) PROGRAM
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ........................................................................................ 1
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
"471visraa STANDARDS 20OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

Objectives of the QA/QC Program............................................................ 1
ProgramApplicability................................................................................2
4.62 INCIDENT ASSESSMENT
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ........................................................................................ 1
Situations that Trigger Assessments........................................................ 1
Material Failure Assessment....................................................... 1
DOT Reportable Incident.............................................................2
Noticeable Trends (Multiple Occurrences)..................................3
Gas Related Fires and/or Explosions..........................................3
Non-gas Related Fires and/or Explosions...................................3
EmployeeInjury........................................................................... 3
Third-Party Damages................................................................... 3
Pipeline Ruptures and/or Rupture Mitigation Valve (RMV) Closures
(Transmission Facilities Only)...................................................................3
NearMisses.................................................................................4
Other Management Directed Reasons........................................4
Incorporation and Communication of Lessons Learned...........................4
Procedures Updating (Includes Design, Construction, Testing, Maintenance,
Operations, Emergency Response, Training, and Operator Qualification).4
5.0 MAINTENANCE
5.10 GAS MAINTENANCE TIMEFRAMES AND MATRIX
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Definitions ................................................................................................. 1
Maintenance Matrix Tables....................................................................2-6
Regulator Stations .......................................................................2
FarmTaps....................................................................................2
Heaters ........................................................................................ 3
Valves .......................................................................................... 3
LinePatrols..................................................................................4
Cathodic.......................................................................................4
LeakSurvey.................................................................................5
Odorization...................................................................................6
Vaults...........................................................................................6
Meters..........................................................................................6
Certifications................................................................................6
EmergencyPlan...........................................................................6
O & M Manual..............................................................................6
Instruments..................................................................................6
Customer Notification ..................................................................6
5.11 LEAK SURVEY
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
LeakSurvey.............................................................................................. 1
General ........................................................................................ 1
PPM Relation Table..................................................................... 1
Gas Leak Detection Instruments ..............................................2-4
Maintenance of Instruments ........................................................4
Gas Leak Survey Methods .......................................................................4
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
"471visraa STANDARDS 21 OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

Surface Gas Detection Survey ....................................................4
Soap/Bubble Leak Test ...............................................................6
Pressure Drop Test......................................................................6
Detection of Other Combustible Gases.......................................6
WA Foreign Source Leaks (WAC-480-93-185)..............6
Can't Gain Entry/Can't Find......................................................... 7
LeakSurvey Plans.................................................................................... 7
Annual Distribution System Surveys............................................ 7
Transmission and Other HP Pipelines.........................................8
250+ psig Pipelines Washington Only
(WAC 480-93-188)..........................................................8
5 Year Distribution System Survey..............................................8
SpecialSurveys...........................................................................8
WA Non-Cathodic Protected Steel Piping Surveys
(WAC 480-93-188(3)(d))............................................................9
WA Lowering or Moving Metallic Gas Pipelines
(WAC 480-93-175)................................................................9
ClassifyingLeaks.................................................................................... 10
Grade1 Leak............................................................................. 10
Grade2A Leak........................................................................... 11
Grade2 Leak............................................................................. 11
Grade3 Leak............................................................................. 12
Aboveground Outside Leak Classification................................. 12
Aboveground Inside Leak Classification.................................... 12
Underground Leak Determination........................................................... 13
Underground Leak Investigation............................................................. 13
Pin pointing/Centeri ng.............................................................................. 14
Venting Underground Leakage............................................................... 15
Gas Present in Sewer or Duct System ................................................... 15
Gas Control Room Notification ............................................................... 15
Remaining-on-the-Job ............................................................................ 15
Underground Leak Repair ...................................................................... 15
Leak Repair and Residual Gas Checks..................................... 15
Pressure Testing Replaced Segments...................................... 16
Reinstating a Damaged Service Line ........................................ 16
Service Line Leak Survey.......................................................... 16
Follow-up Inspections for Residual Gas.................................... 16
Re-Classification of Leaks ......................................................... 17
Self-Audits.................................................................................. 17
Self-Audit Records..................................................................... 17
Maintenance Frequencies ...................................................................... 18
Maintenance Frequency Schedule............................................ 18
Recordkeeping........................................................................... 19
LeakSurvey Forms................................................................................. 19
Closing Leak Reports ................................................................20
Blowing Gas and Odor Calls......................................................20
Leak Incident Reporting.............................................................20
Leak Failure Cause Definitions..........................................................20-22
WA Failure Analysis Report Requirements
(WAC 480-93-200(6)) .........................................................21
Hazardous Mechanical Fitting Failures...................................................22
5.12 REGULATOR AND RELIEF INSPECTION
Scope........................................................................................................ 1
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
���r■sra STANDARDS 22OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

Regulatory Requirements......................................................................... 1
Other References...................................................................................... 1
Corresponding Standards......................................................................... 1
General ........................................................................................ 1
Pressures Precaution .................................................................. 1
Service Regulators....................................................................................2
General Maintenance of all Service Pressures ...........................2
Maintenance of Elevated Service Pressure Accounts.................2
180 Day Inspection Criteria ......................................................... 3
Maintenance of Industrial Meter Sets................................... 3
Regulator Stations and Elevated Pressure Meter Sets............................ 3
FarmTaps.................................................................................... 3
District Regulator Stations........................................................... 3
District Regulator Station Relief Capacity Review.......................4
Gate Station Regulator and Relief Set Point Review..................4
Regulator Station Numbering ......................................................4
Control Room Notifications..........................................................4
General Station Inspection ..........................................................5
Farm Taps and HP Services........................................................5
Annual Regulator Station Maintenance....................................................5
Maintenance Procedure...............................................................6
Maintenance of Overpressure Protection Devices ......................7
Reliefand Safety..........................................................................7
MonitorTesting ............................................................................7
Strainer/Filter Inspection..............................................................7
StationValves..............................................................................7
Maintenance of Blow Down Facilities..........................................8
Changes in Station Design ..........................................................8
Maintenance of Regulator Stations Operating on Permanent
Bypass.................................................................................. 8
Portable Regulator Station Maintenance................................8
Portable CNG Trailer Maintenance.......................................8
Regulator Stations - Special Inspections.....................................8
5 Year Overhaul— Flexible Element and Boot Type Regulators..............9
Maintenance Procedures............................................................. 9
10 Year Overhaul — Diaphragm Type Regs, Relief Valves and Pilots.....9
Maintenance Procedures............................................................. 9
GateStations............................................................................................ 9
Chart Recorders and Telemetry ................................................ 10
Maintenance Frequencies ...................................................................... 10
Maintenance Frequency Table.................................................. 10
Recordkeeping........................................................................................ 11
Drawing — Regulator Identification Sequence ........................... 11
Procedure for Regulator Station and Meter Set Bypassing.................... 12
Procedure for Testing Relief Valves with Nitrogen or Bottled CNG ....... 13
5.13 VALVE MAINTENANCE
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ........................................................................................ 1
ValveTypes .............................................................................................. 1
SteelPlug Valves......................................................................... 1
SteelGate Valves........................................................................2
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
"471visraa STANDARDS 23OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

SteelBall Valves..........................................................................2
GearValves.................................................................................2
Polyethylene Valves ....................................................................2
ValveTurns..................................................................................2
Valve Turns Table........................................................... 3
Maintenance Requirements for Valve Types............................................ 3
SteelPlug Valves.........................................................................3
Steel Gate Valves........................................................................4
SteelBall Valves..........................................................................4
Steel Gear Valves........................................................................4
Polyethylene Valves ....................................................................4
General Valve Maintenance and Installation Notes..................................4
General ........................................................................................4
Maintaining Valve Boxes .............................................................5
Valve Disable/Abandonment .......................................................5
Maintenance ................................................................................6
Valve Maintenance Frequency Schedule.......................6
WA Curb Valve Requirements (WAC 480-93-100 (2))................6
Secondary Valves Maintenance..................................................6
Recordkeeping.......................................................................................... 6
Plug Valve Lubrication Procedures...........................................................7
ManualInjection...........................................................................7
SealantGun.................................................................................7
Service Valve Lubrication Procedures.........................................7
5.14 CATHODIC PROTECTION MAINTENANCE
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
Cathodic Protection Monitoring................................................................. 1
General ........................................................................................ 1
Cathodic Protection Criteria......................................................... 1
Monitoring Cathodic Protection Areas......................................... 1
Monitoring Isolated Mains Less than 100 Ft or Service Lines.....2
Monitoring Rectifiers................................................................................. 2
General ........................................................................................2
Bi-monthly Rectifier Monitoring ...................................................2
Detecting Stray Current............................................................... 3
Monitoring Critical Bonds and Diodes.......................................... 3
Monitoring Steel in Steel Casings................................................ 3
Cathodic Protection Maintenance.............................................................4
Facilities Under Restoration of Cathodic Protection....................4
WA Cathodic Deficiency Correction Requirements
(WAC-480-93-110(2))...............................................4
ShortedCasings ..........................................................................4
ElectricalShorts........................................................................... 5
IsolatedSteel ............................................................................... 5
WA Isolated Sections Leak Survey
(WAC-480-93-188(3)(d)).......................................... 5
Isolated Steel Risers....................................................................5
Isolated Steel Services ................................................................5
Examining Buried Steel Pipe and Coating...................................5
Repair and Wrapping of Pipe.......................................................5
Internal Corrosion Control.........................................................................6
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
���r■sra STANDARDS 24OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

Examining Internal Pipe...............................................................6
CP Equipment Accuracy Check...................................................6
Maintenance and Remediation Timeframes and Frequencies Table....7-8
Recordkeeping.............................................................................8
Structure-to-Electrolyte Potential (Pipe-to-Soil Potential).........................8
General ........................................................................................8
Potential Test Equipment.............................................................8
Potential Requirements ...............................................................8
Maintenance of Equipment..........................................................9
Calibration and/or Verification of Equipment...............................9
EquipmentSetup .........................................................................9
Aboveground Potential Reads.....................................................9
Exposed Pipe Reads ...................................................................9
Recordkeeping........................................................................... 10
Requesting Assistance.............................................................. 10
Monitoring Electrical Isolation of Steel Encased Pipeline.......... 10
Procedure for Testing a Casing without Test Leads............................... 10
Examples of Non-Shorted and Shorted Casings....................... 11
Alternative Procedure for Testing a Casing without Test Leads ............ 11
5.15 PIPELINE PATROLLING AND PIPELINE MARKERS
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ........................................................................................ 1
Methods of Patrolling...................................................................2
Clearance.....................................................................................3
Maintenance Frequencies ........................................................................3
Distribution Line Maintenance Frequency Table.........................3
Transmission Line Maintenance Frequency Table......................3
Recordkeeping.............................................................................4
TIMP—Transmission Patrolling...................................................4
PipelineMarkers.......................................................................................4
Pipeline Markers for Buried Pipe.................................................4
Exceptions for Marking ................................................................ 5
Washington State Additional Pipeline Marker Requirements
(WAC 480-93-124)................................................................ 5
Vegetation Guidelines..................................................................6
Markers for Aboveground Pipelines.............................................6
Washington State Pipeline Marker Surveys
(WAC 480-93-124)................................................................6
5.16 ABANDONMENT OR INACTIVATION OF FACILITIES
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ........................................................................................ 1
Abandoning Gas Facilities.....................................................................1-3
Casings........................................................................................ 3
Disabling a Curb Valve Tee......................................................... 3
Valve Abandonment ....................................................................3
Valve Box Abandonment.............................................................3
Regulator Station Abandonment..................................................3
Vault Abandonment.....................................................................3
Commercially Navigable Waterways...........................................3
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
XVIST/i STANDARDS 25OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

Inactivating Gas Meter Facilities..................................................4
Idle Meters and Idle Services ......................................................4
Maintenance Requirements......................................................................4
5.17 REINSTATING ABANDONED GAS PIPELINES AND FACILITIES
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ........................................................................................ 1
Reinstating Gas Mains and Services........................................... 1
Reinstating Gas Facilities ............................................................2
5.18 VAULT MAINTENANCE
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ........................................................................................ 1
VaultInspection ........................................................................... 1
Maintenance Frequency........................................................................... 1
Recordkeeping............................................................................. 1
5.19 COMBUSTIBLE GAS INDICATOR TESTING AND CALIBRATION
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ........................................................................................ 1
Calibration Procedures ............................................................................. 1
Maintenance Frequencies ........................................................................2
Recordkeeping..........................................................................................2
5.20 ATMOSPHERIC CORROSION CONTROL
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
Atmospheric Corrosion Control................................................................. 1
General ........................................................................................ 1
Causes of Atmospheric Corrosion............................................... 1
Inspection Requirements.............................................................2
Can't Gain Entry/Can't Find.......................................................2
Remediation................................................................................. 3
Insufficient Wrap on Steel Risers.................................................3
Order Types and Remediation Time Guidelines Table ...............4
Recordkeeping.............................................................................4
Blowing Gas and Odor Calls........................................................4
5.21 MAINTENANCE OF PRESSURE GAUGES AND RECORDERS
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Other References...................................................................................... 1
Corresponding Standards......................................................................... 1
General ........................................................................................ 1
Types of Pressure Gauges.......................................................1-3
Types of Pressure Recorders...................................................... 3
Calibration/Verification Standard Device..................................... 3
TestBenches...............................................................................4
Required Gauges by Job Type....................................................4
List of Acceptable Gauges...........................................................4
The Gauge ID and Verification Sticker........................................5
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
"471visraa STANDARDS 26OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

Responsibilities by Job Type....................................................... 5
Test Bench Locations ..................................................................6
Test Bench Gauge Verification....................................................6
Field Gauge Verification at Test Benches ................................... 7
Field Operating Guidelines for Pressure Gauges..................................... 8
Field Operating Guidelines for Pressure Recorders................................. 9
Maintenance Frequencies ........................................................................ 9
Maintenance Frequency Table.................................................... 9
Recordkeeping..........................................................................................9
5.22 HEATER MAINTENANCE
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ........................................................................................ 1
LineHeaters.............................................................................................. 1
Operation ..................................................................................... 1
Maintenance ................................................................................2
Maintenance Interval Table .........................................................2
Fluid Sampling Procedures.......................................................................2
PilotLine Heaters...................................................................................... 3
Theory of Operation..................................................................... 3
Operation/Maintenance ............................................................... 3
Maintenance Interval Table .........................................................3
Recordkeeping..........................................................................................3
5.23 ODORIZATION EQUIPMENT
Scope........................................................................................................ 1
Regulatory Requirements......................................................................... 1
Corresponding Standards......................................................................... 1
General ........................................................................................ 1
Injection Odorizers (YZ Style)................................................................... 1
Operation/Maintenance ............................................................... 1
Maintenance ................................................................................ 1
Maintenance Interval Table .........................................................2
By-pass Odorizers .................................................................................... 2
Theory of Operation.....................................................................3
Operation/Maintenance ...............................................................3
Maintenance Interval Table .........................................................3
WickOdorizers.......................................................................................... 3
Theory of Operation..................................................................... 3
Operation/Maintenance ............................................................... 3
Maintenance Interval Table ......................................................... 3
Odorant Transport.....................................................................................4
OdorantSpills ...........................................................................................4
Safety and Health Department Notification...............................................4
Recordkeeping..........................................................................................4
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
"471visraa STANDARDS 27OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

CHARTS AND TABLES
Spec. Pg.(s) Chart/Table No. Description
1.4 3-5 Standards Accountability Table
2.12 8 ASTM A105 Steel Pipe Flanges and Flanged Fittings (ASME 1316.5)Table
2.12 8 Flange and Fastener Combinations Minimum Requirements
2.12 13-14 Steel Pipe Data Table
2.13 3 Polyethylene Pipe Dimensions Table
2.14 5 Transmission Line Valve Spacing Table
2.14 5 Rupture Mitigation Valve (RMV)Table
2.14 7 Valve Codes (GIS) Chart
2.22 5 Acceptable Breakaway Fitting Applications Table
2.22 9 Meter Attachment to Flanges Torque Table
2.22 14 Atmospheric Pressure at Various Elevations Table
2.22 16 Meter Correction Codes Chart
2.22 17 Frequency of Meter Test Table
2.22 17 Prover Calibration Interval Table
2.24 1 Capacity of Regulator Table
2.24 1 Relief Capacities, Downstream Protection Table
2.24 2 Obsolete Regulators Table
2.24 2 Meter Capacity Tables - Diaphragm Meters
2.24 3 Meter Capacity Tables - Rotary Meters
2.24 3 Rotary Meter Pressure Rating
2.24 3 Meter Capacity Tables -Turbine Meters
2.24 4-5 Regulator Capacity Table - 30 psig Inlet
2.24 6-7 Regulator Capacity Table - 15 psig Inlet
2.24 7-8 Regulator Capacity Table - 5 psig Inlet
2.24 8-9 Regulator Capacity Table-2 psig Inlet
2.24 10 Farm Tap Regulator Table - 500 psig
2.24 11 Relief Valve Capacities at Set Point Table
2.24 11 Other Applications Table
2.25 4 Telemetry Quantities Measured (Inputs/Outputs)Table
2.32 3 Soil Resistivity Table
2.32 4 The Galvanic Series Chart
3.12 6 Liquid Epoxy Curing Timetable
3.12 8 Scar-Guard Ambient Temperature Table
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
>risra STANDARDS 28OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

Spec. Pg.(s) Chart/Table No. Description
3.12 11 Scar-Guard Cure Times with Water(above 41°F)
3.12 12 Scar-Guard Cure Times with 35% Propylene Glycol Solution (below 32°F)
3.12 16 Minimum Testing Voltages for Conventional Coatings Thickness-Table 1
3.12 17 New Pipe Coating Thickness Table-Table 2
3.12 17 Minimum Steel Bend Radius Table
3.12 18 Minimum Roping Distance on Both Sides of Moved Pipe Table
3.12 21 Steel Pipe Lowering Decision Flowchart
3.13 4 Minimum Permanent Bending Radius Table- PE Pipe
3.13 6 Minimum Temporary Bending Radius Table- PE Pipe
3.13 8-9 Safe Pulling Forces Table, PE Pipe
3.16 3 EVF Criteria Table
3.16 3 EFV Symbology Table
3.16 5-7 EFV Capacity Tables (with Stock Numbers)
3.16 14 Service Pipe Sizes and Capacities Chart
3.16 15 Pipe Capacities Table- PE, @ 2.0 psig AP = 0.5 psig
3.16 16 Pipe Capacities Table-Steel @ 2.0 psig OP = 0.5 psig
3.16 16 Pipe Capacities Table- PE, @ 5.0 psig AP = 3.5 psig
3.16 17 Pipe Capacities Table-Steel, @ 5.0 psig AP = 3.5 psig
3.16 17 Pipe Capacities Table- PE, @ 7.0 W.C. AP = 0.5"W.0
3.16 18 Pipe Capacities Table-Steel, @ 7.0 W.C. AP = 0.5" W.C.
3.17 6 Nitrogen Purge Data Table-4" thru 20"Pipe Volume @ 100 ft/min
3.18 2 Maximum Test Pressure Permitted (Steel) as a % of SYMS Table
3.18 5 Pressure Testing- High Pressure Steel Pipelines Table
3.18 6 Pressure Testing- Inter. Pressure Steel Pipelines Table
3.18 8 Pressure Testing Requirements- PE Pipelines Table
3.23 3 Butt Fusion Heater Surface Temperature Table
3.23 4 Minimum Melt Bead Size Table
3.23 4 Maximum Heater Plate Removal Times Table
3.23 5 Butt Fusion Cooling Times Table
3.23 7 Hydraulic Fusion Pressures Table
3.23 9 Butt Fusion Bead Troubleshooting Guide Table
3.24 2 Electrofusion Calibration Manufacturer Maintenance Table
3.24 8-13 Electrofusion Electrical Requirements and Cooling Times Table
3.32 6-8 Steel Repair Selection Chart- MAOP:5100 psig
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
>risra STANDARDS 29OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

Spec. Pg.(s) Chart/Table No. Description
3.32 8-10 Steel Repair Selection Chart— MAOP >100 psig but <20% SMYS and <500 psig
3.32 10-11 Steel Repair Selection Chart— MAOP >_500 psig or>_20% SMYS
3.32A 2 Stud Bolt and Nut Torque Chart
3.33 3 Plastic Repair Selection Chart
3.34 6 PE Pipe Squeeze and Release Rates
3.35 2 Romac Style SS1 Pipe Diameter to Torque Table
3.35 3 Adam/Mueller Series Bolt to Torque Table
3.42 2 Casing Specification Table—Steel Carrier Pipe
3.42 2 Casing Specification Table— PE Carrier Pipe
3.43 3 Storm Water Erosion Control Guidance Table
3.43 6-7 Construction Activities, Typical Governing Agencies and Associated Permits Table
4.13 8 APWA Uniform Color Code Marking Table
4.13 10 Blasting — Peak Particle Velocity Chart
4.31A 1 Task Index Table
4.31A 18 Covered Tasks Associated with Integrity Management
5.10 2-6 Gas Maintenance Matrix Tables
5.11 1 PPM Relation Table
5.11 18 Leak Survey Program Maintenance Frequency Schedule Tables
5.12 10 Gas Regulator Maintenance Frequency Schedule Table
5.13 3 Valve Turns for Each Valve Type Table
5.13 6 Valve Maintenance Frequencies Table
5.14 7-8 Maintenance and Remediation Timeframes and Frequencies Table
5.15 3 Pipeline Patrol Maintenance Frequencies Table
5.19 2 Combustible Gas Indicator (CGI) Maintenance Frequency Table
5.20 4 AC Corrective Order Types and Remediation Time Guidelines
5.21 9 Pressure Instrument Maintenance Frequency Table
5.22 2 Line Heater Maintenance Frequency Table
5.22 3 Pilot Line Heater Maintenance Frequency Table
5.23 2 Injection Odorizer Maintenance Frequency Table
5.23 3 By-Pass Odorizer Maintenance Frequency Table
5.23 3 Wick Odorizer Maintenance Frequency Table
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
���r■sra STANDARDS 30OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

DRAWINGS AND DETAILS
Spe Page(s) Drawing Sheet Rev Description of Contents
c
2.22 19 A-36275 1 of 1 11 3-Foot and 10-Foot Rule Diagram (Residential Meter Set
Location)
2.24 A A-36712 1 of 2 12 Meter Set Barricade Detail for Diaphragm Type Meters
2.24 A A-36712 2 of 2 1 Typical Meter Set Barricades
2.24 A A-38500 1 of 1 2 Standard Meter Set Stand for Flex Line Support
2.24 A A-34175 1 of 2 3 Single Pipe Ground Pipe Support- District Regular
Stations, Meter Sets
2.24 A A-34175 2 of 2 1 Double Pipe Ground Pipe Support- District Regular
Stations, Meter Sets
2.24 A A-35208 1 of 1 9 Meter Set- Residential, Standard Delivery
2.24 A A-37102 1 of 1 8 Meter Set- Residential, 2 psig Delivery
2.24 A A-37103 1 of 1 2 Meter Set- Residential, Riser Detail
2.24 A B-35207 1 of 2 0 Meter Set- H.P. Residential - MAOP 175 psig or less
2.24 A B-35207 2 of 2 7 Meter Set- H.P. Small Commercial MAOP 175 psig or less
2.24 A C-35209 1 of 2 11 Meter Set-Typical Small Diaphragm
2.24 A C-35209 2 of 2 8 Meter Set-Typical Large Diaphragm
2.24 A B-33325 1 of 4 11 Meter Set—2000, 3000 and 3500 Rotary; 7" W.C., 2 psig,
5 psig
2.24 A B-33325 2 of 4 13 Meter Set- 5000 and 7000 Rotary; 7" W.C., 2 psig
2.24 A B-33325 4 of 4 13 Meter Set- 11000 Rotary; 7"W.C., 2 psig, 5 psig
2.24 A B-38205 1 of 1 5 2000, 3000 and 3500 Rotary Meter, Intermediate Delivery
Pressure.
2.24 A B-35785 1 of 1 11 Meter Set—Threaded 5000 and 7000; 7"W.C., 2 psig, 5
psig
2.24 A E-37197 1 of 1 8 Code 3—2" Standard Meter Set
2.24 A E-37842 1 of 1 6 Welded Farm Tap Regulator Piping 2" outlet
2.24 A E-37970 1 of 1 6 Welded Farm Tap Regulator Station Piping 3/4"outlet
2.24 A E-33952 1 of 1 7 District Regulator Station—2" Inlet; 4" Outlet
2.24 A E-35783 1 of 1 7 District Regulator Station—4" Inlet; 6" Outlet
2.24 A E-35158 1 of 1 7 District Regulator Station— Dual Run 2" Inlet; 4" Outlet
2.24 A L-36082 1 of 1 2 Regulator Station Fencing Details
2.25 9 E-37114 1 of 1 2 Gas Telemetry Standards
3.12 21 A-35447 1 of 1 0 Color Coding of CP Test Leads Across Insulated Fittings
3.12 22 B-36271 1 of 1 0 Steel Test Stations & Isolation Fittings
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
>risra STANDARDS 31 OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

Spe Page(s) Drawing Sheet Rev Description of Contents
c
3.13 12 A-35776 1 of 1 1 Taping Tracer Wire to Pipe Detail
3.13 13 A-36277 1 of 1 2 Tracer Wire Connectors
3.13 14 B-39147 1 of 1 0 PE Test Stations &Tracer Wire
3.15 6 A-38315 1 of 4 3 Construction Specification for Customer Supplied Ditch for
Meter Relocation
3.15 7 A-38315 2 of 4 6 Construction Specification for PE Natural Gas Service
Customer Provided Trench Detail
3.15 8 A-38315 3 of 4 0 Construction Specification for Natural Gas Main Trench
Detail
3.15 9 A-38315 4 of 4 0 Construction Specification Natural Gas Main Clearances
3.16 19 A-34735 1 of 1 5 Inserting 3/4" Steel Pipe With CTS PE Pipe
3.16 20 B-36269 1 of 1 2 Service Installation — Heavy Snow Areas
3.16 21 A-37169 1 of 1 4 Unit Assembly— 1/2" PE Service& EFV Off Steel IP Main
3.42 6 B-34947 1 of 1 1 Big & Little Fink Casing Test Box Installation Details
3.42 7 E-33947 1 of 2 0 Steel Casing Detail - RR Crossing
3.42 8 E-33947 2 of 2 0 Steel Casing Detail - Crossing State or Interstate Highways
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
>risra STANDARDS 32OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

DIAGRAMS, ILLUSTRATIONS AND FLOWCHARTS
Spec Page(s) Description of Contents
2.13 2 Print Line on Pipe Example
2.22 6 Earthquake Valve Installation Illustration
2.32 4 The Galvanic Series Chart
3.12 21 Steel Pipe Lowering Decision Flowchart
3.16 4 Diagram of Protected Length of Service Examples
3.16 8 Diagram of Branched Service Examples
3.17 6 Illustration for Purging a Pipeline into Service
3.17 8 Illustration for Purging a Pipeline Out of Service
3.18 9 Examples of recordkeeping for single and multiple facilities.
3.18 10 Pressure Test Information sticker
3.22 4 Welder Certification Card
3.22 7 Illustration — Use of a Back Bevel
3.22 10 Diagrams of Slip Flanges- Fillet welded.
3.22 11 Diagram for Socket Weld
3.43 8 Exhibit A—Common BMPs and How to Implement
1. Silt Fence Sediment Control BMP
3.43 g Exhibit A—Common BMPs and How to Implement.
2. Fiber Roll /Straw Wattle Sediment Control BMP
3.43 10 Exhibit A—Common BMPs and How to Implement.
3. Rock Check Dam Run off Control
4.13 7 Tolerance Zone Diagrams—WA/ID
4.13 8 Tolerance Zone Diagrams - OR
4.13 10 Blasting— Peak Particle Velocity Chart
4.16 2 Example of Clustering for Class Location Boundaries
4.31 D 1 Operator Qualification Investigation Guideline Flow Chart
5.14 11 Diagram Examples of Non-shorted and Shorted Casings
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
>risra STANDARDS 33OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

This Page Intentionally Left Blank
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
"471visra STANDARDS 34OF36
Utilities
FOR GAS COMPANIES SPEC 1.0

GIS MAPPING SYMBOLOGY
C Bonded Dresser Gas Marker Ball
B: Bottom Out Line Stopper
• Test Point Container-With Inspections
r Test Point Container-No Inspections
■ Coupling.Dresser rr Test Point Container-Misc Location-Bridge Crossing
End Cap or Stub 0 Test Point Container-Misc Location-Coupon Test Station
=Expansion Joint r• Test Point Container-Misc Location-Water Crossing
YExtension Stopper Test Point Container-Misc Location-Non-Typical AC Inspection
Flange Rectifier
�
Split Tracer Wire PE Gahanic Rectifier(Anode)
Flanged Tee ® Regulator Station-District
la Dresser Insulated © Regulator Station-City Gate
OQ Regulator Station-Single Service Farm Tap
Flange Or Kerotest Insulated ( Regulator Station-Industrial Meterset
* Line Stopper ® Regulator Station-Master Meter
Qo Regulator Station-Odorizer
Reducer Regulator Station-Unclassed
Side Out Stopper Gas Leak/Repair
O Exposed Pipe
O Transition x Exposed Pipe/Gas Repair
YTop Stopper Gas Leak/Repair-Abandoned
o Exposed Pipe-Abandoned
QT Tapping Tee r Exposed Pipe.Gas Repair-Abandoned
40 Tapping Tee w/Excess Flow Valve 1: Gas Leak,-'Repair-Unattached
High Volume Tee o Exposed Pipe-Unattached
Q Inline Tee E Exposed Pipe./Gas Repair-Unattached
* Elbow • Exposed Pipe-Pipe Data Out of Sync
* Clamp • Exposed Pipe,/Gas Repair-Pipe Data Out of Sync
Undetermined Gas Stopper X Invalid Usage,Installed Status,or Normal Status
Insulating Joint,'Zunt X EOP or Emergency,Active,Closed
■ Excess Flow Valve Z EOP or Emergency,Active,Open
Barreled Dresser
T Purge Fitting EOP or Emergency,Disabled,Closed
Inline Tee with EFV
EOP or Emergency,Disabled,Open
aReducer Inbne Tee w/EFV
Secondary,Active,Closed
a Reducer Coupling w/EFV
} Anode Set �Secondary,Active,Open
• Single Service
Multiple Service �Secondary,Disabled,Closed
* Idle Riser
O Non-Metered Service "--"Secondary,Disabled,Open
TABLE OF CONTENTS REV. NO. 26
DATE 01/01/24
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Utilities
FOR GAS COMPANIES SPEC 1.0

-call other values> Gas Planning Proposals
Type SIZENUMBER
.Critical Alarm 2"
Noncritical Alarm 4"
6"
P; Pressure Recorder >6"
r Gas Warning sign Gas Planning AOI
Area Type
Barhole Location Critical Pressure
Low Pressure
Abandoned Gas Device Miscellaneous
Eop Zone Pipe — New Developments
Gas Special Condition
—Cathodic Zone
Ribbon Anode voce Field Note
Gas Event Problem Customer
•
Cathodic Conductor Structure
-HP Steel Pipe(Abandoned) O Avista Owned
HP Plastic Pipe(Abandoned) ® Foreign Owned
HP Vintage Plastic Pipe(Abandoned)
--IP Steel Pipe(Abandoned) 0 Temporary Structure
IP Plastic Pipe(Abandoned)
IP Vintage Plastic Pipe(Abandoned) Shadow Structure
0 Move If Touched
HP Steel Pipe Must Be Moved
HP Plastic Pipe
IP Steel Pipe
IP Plastic Pipe
IP Vintage Plastic Pipe
BHP Steel Pipe in Conduit
HP Plastic Pipe in Conduit
IP Steel Pipe in Conduit
IP Plastic Pipe in Conduit
IP Vintage Plastic Pipe in Conduit
BHP Steel Pipe in Casing
HP Plastic Pipe in Casing
—IP Steel Pipe in Casing
IP Plastic Pipe in Casing
IP Vintage Plastic Pipe in Casing
Unknown Pipe
—Dry Line
—Unlocatable
Gas Empty Conduit
TABLE OF CONTENTS REV. NO. 26
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Utilities
FOR GAS COMPANIES SPEC 1.0

1.1 GLOSSARY
ABANDONED PIPELINE: A pipeline permanently removed from service that has been
physically separated from its source of gas or hazardous liquid and is no longer maintained
under regulation 49 CFR Part 192, as applicable. Abandoned pipelines are usually purged of
the gas and refilled with nitrogen, water, or a non-flammable slurry mixture.
ABNORMAL OPERATING CONDITIONS: A condition identified by the operator that may
indicate a malfunction of a component deviation from normal operations that either indicates
a condition exceeding design limits or results in a hazard to persons, property, or the
environment.
ACCESS, SAFE: Condition of being reached safely and quickly for operation, inspection,
adjustment, or repair without requiring climbing over or removing obstacles. Safe access may
also be provided by use of an approved ladder.
AIR/FUEL RATIO: The proper combination of air and gas required for complete combustion.
For natural gas, the ratio is 10 to 1 (10 parts air to 1 part gas). For propane, the
corresponding ratio is 25 to 1. See also Explosive Limit.
AIR SHUTTER: An adjustable gate or door used to control the amount of primary air to an
atmospheric style burner.
ALARM: An audible or visible means of indicating to the controller that equipment or
processes are outside operator-defined, safety-related parameters.
ALCOVE: A recessed area within a building's exterior wall that is sealed from the building
interior.
ALDEHYDES: Chemical compounds formed along with carbon monoxide during the
incomplete combustion of natural gas. Aldehydes cause watering of the eyes and a burning
feeling in the throat.
ALLOWABLE PRESSURE DROP (PRESSURE DROP): The maximum allowable loss in
working pressure in a piping system, typically measured from the outlet of the gas meter to
the furthest appliance.
AMPERE (AMP): The unit of measurement of electric current proportional to the quantity of
electrons flowing through a conductor past a given point in one second.
ANODE (Cathodic Protection): The expendable material, which is buried and through which
direct current flows into the soil. Common materials used for this purpose are graphite or
carbon rods, silicon, iron, magnesium, zinc, and scrap iron.
ANODE (Corrosion): The electrode of a corrosion cell which has the greater tendency to
corrode or oxidize.
ANODE EFFICIENCY: The ratio of the actual corrosion of an anode to the theoretical
corrosion calculated from the quantity of electricity, which has passed.
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NATURAL GAS SPEC. 1.1

ANODELESS RISER: A plastic pipe sheathed inside a protective steel metallic casing. The
steel-cased plastic pipe protrudes from the soil and is part of the service line carrying gas to
the customer meter. An anode is not required in this instance because the plastic pipe
contains the gas pressure and is not susceptible to the typical corrosive processes.
ANODIC FIELD: The area in which the soil potential is raised because of current flow away
from a ground electrode (anode). The extent of this influence is a function of soil resistivity
and the magnitude of current flow.
APPLIANCE: A device which uses fuel or other forms of energy to produce light, heat, power,
refrigeration, or air conditioning. This definition shall also include vented decorative
appliances. This definition is also used interchangeably with the term "equipment' in this
policy.
APPLIANCE REGULATOR: A control device installed on an appliance fuel line to reduce
house line gas pressure to the required appliance manifold pressure.
APPROVED: Materials, equipment, appliances, methods of inspection, or construction that
are approved as a result of tests, standards, or investigations by the authority having
jurisdiction or by national authorities or testing bodies. The Company may also provide
direction in this respect as indicated in the Operating and Maintenance plan. The approval
which is most restrictive shall prevail in cases where there is a difference between Company
policy and other accepted or required standards.
APPURTENANCE: Any attachment to or component of a pipeline that may be subjected to
system pressures including (but not limited to), pipe, valves, fittings, flanges, and closures.
AREA ODOR: An odor or smell located in a general area that is thought to be natural gas, but
that may also be the result of other chemicals or actions in a given area.
ASSESSMENT: The use of testing techniques as allowed in this 49 CFR 192, Subpart 0, to
ascertain the condition of a covered pipeline segment.
ATMOSPHERIC CORROSION: As referred to in this policy, this refers to actual loss of metal
on any above ground pipeline or facility by means of rusting or other oxidation. Such
corrosion is normally evident in the form of actual pitting, flaking, or exfoliation of the metal.
Exposure to certain reactive chemicals in the atmosphere may also result in deterioration of
metal surfaces.
AUTHORITY HAVING JURISDICTION: The organization, office, or individual responsible for
approving equipment, installation, or a procedure. The authority having jurisdiction may be
the city, county, or other local building official, the supplying utility, or other deputized agency
or person per statute.
AUTOMATIC IGNITION: An ignition system that requires no manual attention to ignite the
main burner. Safety monitoring controls verify safe operating conditions at all times.
AUTOMATIC SHUT-OFF VALVE (ASV): An actuated valve that is shut automatically, either
through physically sensing abnormal conditions (earthquake, pressure exceedance, etc.), or
through electronic sensors and controls that send a signal to automatically shut a valve after
detection of an abnormal event such as rupture.
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NATURAL GAS SPEC. 1.1

BACKFILL: Earth or other material which is used to refill a ditch or trench. Also, the act of
refilling a ditch or trench.
BACKFILL (CP): The material, which is placed around anodes to ensure uniform corrosion
and, in certain instances, to extend the useful life of the anode. Coal coke or petroleum coke
is used in conjunction with carbon or Duriron anodes; while a mixture of gypsum, bentonite,
and salt is used with zinc, magnesium, and scrap iron anodes.
BAR HOLE: A hole in the ground made with a probe. Bar holes are normally made over
buried gas pipelines to determine the presence of escaping natural gas.
BAR HOLE SURVEY: An area search for leaks, made by driving or boring bar holes at
regular intervals along the route of an underground gas pipe and testing the air from the bar
hole for their gas content.
BEDDING: See PADDING
BELL HOLE: An enlarged hole other than a continuous trench, dug over and along the side of
buried pipelines or in a trench to allow room for persons to perform maintenance-related work
on the pipeline (i.e., coating repairs, welding, connections, or pipe replacement). In the broad
sense, any larger hole, other than a ditch, opened for pipeline work. Smaller holes may be
called key holes or potholes.
BLIND FLANGE: A disk for closing the end of a pipe, having holes for bolting it to a flange.
Such devices can be used to fulfill regulations concerning the inactivation of customer meters
or facilities.
BLOCK VALVE: A valve in a main line that is designed to close in or shut down gas flow.
BLOWDOWN: The depressurizing of a natural gas pipeline to facilitate maintenance on the
pipeline, accomplished by opening a valve and allowing the gas to escape to atmosphere,
usually through a vertical pipe or"stack".
BOND: A connection, usually metallic, that provides electrical continuity between structures
that can conduct electricity.
BTU: British Thermal Unit. One BTU is the amount of heat required to raise one pound of
water one Fahrenheit degree.
BUILDING: A structure or dwelling designed for occupancy or storage with sides enclosed
which could trap gas.
BUSINESS DISTRICT: An area where the public regularly congregates or where the majority
of buildings on either side of the street are regularly utilized for financial, commercial,
industrial, religious, educational, health, or recreational purposes. Mains in the right of way
adjoining a business district must also be included in the leak survey.
BUTT FUSION: Joining process for two pieces of polyethylene pipe and/or fittings in which
heat fusion is used and materials are joined by "butting" or pushing heated ends together.
BYPASS: A valve or assembly installed on a pipe, in a meter set or in a regulator station
which allows the gas to flow in a path that is not part of the normal operating conditions,
usually associated with a meter or regulator for maintenance purposes.
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NATURAL GAS SPEC. 1.1

BYPASS CUSTOMER: A customer receiving gas directly from a transmission pipeline
company or other gas company other than Avista. Pressure reducing regulators are normally
found at such stations.
CALIBRATION: The act of formally determining the accuracy of an instrument or device and
making required adjustments if it is found to be out of tolerance. Such action is normally
carried out by a certified test facility but in some instances, may be performed by the Gas
Meter Shop. (Also, refer to the definition of"verification" herein this glossary.)
CALL-OUT LIST: A list of qualified employees that are available on a round-the-clock basis to
respond to emergency and service requests. Call out lists are created and retained within
callout software, reviewed, and updated by Operations Managers. Gas Control initiates
callouts by utilizing automated functionality within the callout software.
CAN (BARREL): To encapsulate a portion of carrier facility (pipe, fitting, valve, etc.)for the
purpose of repairing or rendering that portion of the facility leak-free. Cans must be rated to at
least at the same MAOP as the encapsulated facility.
CAN'T-GAIN-ENTRY NOTICE: A Company approved form that advises the customer that an
employee has visited the premises for a certain purpose, and that the order could not be
completed as scheduled for one or more reasons.
CARBON MONOXIDE: A toxic and combustible gas produced during the incomplete
combustion of hydrocarbons (such as natural gas). Carbon monoxide is colorless and
odorless. Inhalation of carbon monoxide may cause sickness and death. The chemical
formula is CO.
CARBON MONOXIDE (CO) DETECTOR: An alarm /device to detect carbon monoxide
before most people experience symptoms.
CARRIER PIPE: The pipe or piping that goes through a casing.
CASING: A metallic pipe (normally steel) installed to contain a pipe or piping.
CASING INSULATOR: A dielectric device specifically designed to electrically isolate a carrier
pipe from a casing and provide support for the carrier pipe.
CATHODE: The electrode of a corrosion cell where a net reduction reaction occurs. In
corrosion processes the cathode is usually that area which does not corrode.
CATHODIC FIELD: The area in which the soil potential is lowered because of current flow to
a ground electrode (pipeline). The extent of this influence is a function of soil resistivity and
current density in the soil.
CATHODIC PROTECTION (CP): Reduction or prevention of corrosion of a metal surface by
making it cathodic; for example, using sacrificial anodes or impressed current rectifier
protection systems.
CHIMNEY EFFECT: The tendency of air or gas in a duct, vertical passage, or building to rise
when heated because its density becomes less than the surrounding, colder air or gas.
CITY GATE: See Gate Station.
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NATURAL GAS SPEC. 1.1

CLASS LOCATION: A geographic area representing population levels, as classified, and
described in §192.5.
CLOCK TEST: Refer to "Meter Clock Test."
CLOSE INTERVAL SURVEY: A series of closely and properly spaced pipe-to-electrolyte
potential measurements taken over the pipe to assess the adequacy of cathodic protection or
to identify locations where a current may be leaving the pipeline that may cause corrosion
and for the purpose of quantifying voltage (IR) drops other than those across the structure
electrolyte boundary, such as when performed as a current interrupted, depolarized, or native
survey.
CLOCKING INPUT: The measurement of the volume of gas that an appliance consumes
during a given period. The test dial on the gas meter is used to time how long it takes for one
complete revolution. This time is then used in the clocking formula to determine gas
consumption. The formula is: 3600/time in seconds x the dial size =the quantity of gas. The
figure must then be converted into BTU per hour by multiplying by 1,000. (Note: an exact
figure can be obtained by using the existing BTU value per cubic foot of gas as supplied.)
COATING: A liquid, liquefiable or mastic composition that, after application to a surface, is
converted into a solid protective, decorative or functional adherent film.
COATING RESISTANCE: The electrical resistance of a coating to the flow of current. Unit of
measurement is ohms per square foot. Values range from 1000 ohms to more than
1,000,000 ohms per square foot for conventional organic coatings.
CODE 5: Avista code word for a gas leak or gas odor.
CODE 9: Avista code word for a blowing gas situation.
COMBINATION CONTROL: An operating control that contains more than one switch to
monitor different functions. A fan/limit control is an example of a combination control.
COMBINATION VALVE: A gas valve that contains a regulator, a main shut-off, and an
operator all in one manufactured unit.
COMBUSTIBLE GAS INDICATOR (CGI): An instrument designed to obtain a sample of the
air in a bar hole or in an atmosphere and indicate a percentage of gas in air or ppm reading.
Combustible gas indicators are used to determine the presence or absence of natural gas, to
center or pinpoint underground leakage, and to quantify the amount of gas detected.
COMBUSTION AIR: The air supply required for complete combustion of natural gas.
COMBUSTION PRODUCTS: By-products resulting from the combustion of a fuel with the
oxygen of the air- but excluding excess air.
COMBUSTION TURBINE: An electric generator that uses a jet engine as the prime mover.
Often fueled by natural gas or other petroleum products and typically used as a peaking
plant.
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NATURAL GAS SPEC. 1.1

COMMAND CENTER: A centralized location that exists for the purpose of coordinating the
activities of emergency response personnel. This term may also apply to a temporary
headquarters or communications center set up by the Company to coordinate activities of
personnel during an emergency.
COMPLETE (RECORDS): Complete records are those in which the record is finalized, as
evidenced by a signature or date.
COMPOSITE MATERIALS: Materials used to make pipe or components manufactured with a
combination of either steel and/or plastic and with a reinforcing material to maintain its
circumferential or longitudinal strength.
COMPRESSED NATURAL GAS (CNG): Natural gas stored inside containers at a pressure
greater than atmospheric air pressure, typically up to 3600 psig. CNG is normally placed in
pressure-containing vessels (bottles)where it can be used as a portable fuel source (i.e., in
CNG vehicles and other applications not attached to a pipeline).
CONCENTRATION CELL: A corrosion cell due to the potential difference between the anode
and cathode caused by differences in composition of electrolyte.
CONDUCTOR: A substance or body that allows an electric current to pass continuously
along it.
CONDUIT: Plastic pipe installed to enable road construction, etc., prior to installation of
plastic gas mains or services where the plastic line is inserted at a later date. Also used to
describe steel services that have been inserted with a new gas service pipe.
CONFINED SPACE: Any space that is large enough for an employee to fully enter and
perform assigned work, is not designated for continuous occupancy by an employee and has
limited or restricted means of entry or exit. Confined spaces may include, but are not limited
to, tanks, vessels, silos, storage bins, hoppers, vaults, pits, manholes, tunnels, equipment
housings, bridge enclosures, etc. Refer to the Avista Incident Prevention Manual (Safety
Handbook), Part 2, Section 15—Confined/Enclosed Spaces, for additional guidance.
CONFIRMED DISCOVERY: When it can be reasonably determined, based on information
available to Avista at the time that a reportable event has occurred, even if only based on a
preliminary evaluation.
CONSTRUCTION OFFICE: As referred to in this policy, the main operating headquarters for
a region, where the persons responsible for supervision of daily construction and service
activities are located. This may also be referred to as "areas", "regions", "districts", or other
terms.
CONTROL: Any device, mechanical or electrical, which monitors or activates a piece of
equipment.
CONTROL ROOM: An operations center staffed by personnel charged with the responsibility
for remotely monitoring and controlling a pipeline facility.
CONTROLLER: A qualified individual who remotely monitors and controls the safety-related
operations of a pipeline facility via a SCADA system from a control room, and who has
operational authority and accountability for the remote operations functions of the pipeline
facility as applicable.
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NATURAL GAS SPEC. 1.1

COPPER-COPPER SULFATE ELECTRODE: A standard or reference electrode used for
determining potentials of metals in soils or other electrolytes.
CORRECTING DEVICE: An instrument installed on a meter to correct for varying pressures
or temperatures of the gas stream. The corrector can be electronic or mechanical.
CORRECTION CODE: A billing code that identifies certain assumptions related to metering
pressure and temperature.
CORROSION: The deterioration of a substance, usually a metal, resulting from a reaction
with its environment.
CORROSION CELL: A term used to describe the environment in which an anode, cathode,
electrolyte, and an electrical connection exist in which there is active current flow.
COUPLING: A sleeve-type fitting used to connect two pipes.
COVERED TASK: A covered task is an activity, identified by the operator, that (1) Is
performed on a pipeline facility, (2) Is an operations or maintenance task (state of
Washington includes new construction); (3) Is performed as a requirement of Part 192; and
(4) affects the operation or integrity of the pipeline. (Refer to Specification 4.31, Appendix A
for the list of covered tasks.)
CROSS BORE: A utility cross bore is an intersection of an existing underground utility or
underground structure by a second utility installed by trenchless technology that results in
direct contact between the two and thereby compromises the integrity of either utility or
underground structure.
CURB VALVE: A manually operated valve located near the service line that is safely
accessible to Avista personnel or other personnel authorized by Avista to manually shut off
gas flow to the service line, needed. (Definition taken from §192.385)
CURRENT: The movement of charged particles in a material. Measured in amps.
CURRENT DENSITY: As related to Cathodic Protection, the current per unit area of
electrodes, usually expressed in terms of milliamperes per square foot.
CURTAILMENT: Reductions of deliveries of natural gas by interstate pipelines to distribution
or end-use customers. This situation occurs when demand for natural gas exceeds supply,
causing pipelines; or local distribution systems; to curtail their deliveries.
CUSTOMER: The person paying the gas bill or requesting gas service.
CUSTOMER PROJECT COORDINATOR (CPC): A person responsible for construction
development, design, layout, pricing, scheduling, etc. This may also be referred to as
"construction design rep (CDR)" or"marketing design technician (MDT)" or other titles.
CUSTOMER SERVICES DEPARTMENT: The department of the Company that is
responsible for handling customer calls, answering, and resolving billing issues, originating
orders for new and subsequent service, handling high bill complaints, answering emergency
calls, etc. This may also be referred to as the "call center" or the "business office."
DRY LINE PIPE: Pipe that is installed but not put into service immediately.
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NATURAL GAS SPEC. 1.1

DAMAGE: The substantial weakening of structural or lateral support of an underground
facility, penetration, impairment, or destruction of any underground protective coating,
housing or other protective device, or the severance (partial or complete)of any underground
facility to the extent that the project owner or the affected facility owner or facility operator
determines that repairs are required.
DEFLECTION: The distance a pipe may be displaced under load.
DEGREE DAY (HEATING DEGREE DAY— HDD): A measure of the coldness of the weather
experienced, based on the extent to which the daily mean temperature falls below a
reference temperature, usually 65 degrees F.
DEKATHERM: Unit of measurement for natural gas; a dekatherm is equal to approximately
one thousand cubic feet(volume)or 1,000,000 BTUs (energy).
DELAYED IGNITION: The improper lighting of a main burner causing an explosion during
ignition. The sound of delayed ignition can range from a mild rumble to a thunderous bang
depending on the severity of the problem. The customer's concerns and perceptions should
be used in determining the existence of a delayed ignition condition.
DELIVERY PRESSURE: The pressure delivered to the customer piping. Also, it is referred to
as the "service pressure" or the "utilization pressure."
DESIGN FACTOR: The percentage of SMYS to which operating stress must be limited as
described in §192.111.
DESIGN PRESSURE: The minimum pressure that new facilities within a system should be
designed. This pressure determines the minimum required test pressure to establish MAOP
as well as the required component characteristics for design.
DIELECTRIC: A fitting or component that is partially made of a non-conducting material such
as plastic. These fittings are designed to prevent electrolysis from damaging metal surfaces
and to interrupt CP current.
DIRECT AND OBSERVE: The process by which a qualified individual oversees the work
activities of a nonqualified individual(s)and is able to take immediate corrective action when
necessary.
DISTRIBUTION: A pipeline system within which hoop stress within pipe is less than 20
percent of specified minimum yield strength (SMYS).
DISTRIBUTION CENTER: The initial point where gas enters piping used primarily to deliver
gas to customers who purchase it for consumption as opposed to customers who purchase it
for resale, for example:
1. At a metering location;
2. A pressure reduction location; or
3. Where there is a reduction in the volume of gas, such as a lateral off a transmission line.
DISTRIBUTION SYSTEM: A pipeline system with a MAOP at less than 20 percent of
specified minimum yield strength.
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NATURAL GAS SPEC. 1.1

DISTRICT REGULATOR STATION: A pressure regulating station that controls pressure to
high-or low-pressure distribution main. It does not include pressure regulation whose sole
function is to control pressure to a manifold serving multiple customers. Assembly utilizes
either a regulator and relief or regulator and monitor to reduce pressure. Master meter
stations and bypass customer stations are treated like district regulator stations and are
maintained accordingly.
DOUBLE SUBMERGED-ARC-WELDED PIPE (DSAW): Steel pipe which has a longitudinal
butt joint wherein coalescence is produced by at least two passes including at least one
inside and one outside the pipe with an electric arc.
DOWNSTREAM PIPING: The customer owned piping which typically begins at the outlet of
the meter or the regulator, whichever is furthest downstream. Also, it is referred to as "house
line" or"house piping."
DRY GAS: Gas above its dew point and without condensed liquids. For most operator
established tariff purposes, any gas containing water vapor less than 7 pounds per million
cubic feet (mmcf) is considered dry gas.
DUNNAGE: Wood material, usually 2x4's or 4x4's, placed between lifts of pipe to keep pipe
from being damaged. Dunnage can also be used to help support pipe during pipe end
alignment. May also be called cribbing or skids.
ELECTRIC RESISTANCE WELDED PIPE (ERW): Pipe which has a longitudinal butt joint
wherein coalescence is produced by the application of pressure and by heat obtained from
the resistance at the weld to electric current.
ELECTRODE: Either the corroding or non-corroding portion of a corrosion cell; Refer to
anode or cathode, whichever is appropriate. Also, it is used loosely to describe half-cells such
as the copper-copper sulfate reference electrode.
ELECTROFUSION: A plastic(polyethylene) pipe joining technique that uses a fitting
implanted with metal coils. When a current is passed through the metal coil, resistive heating
of the coils melts the pipe and fitting together which creates a heat fusion joint upon
solidification.
ELECTROLYSIS: The production of a chemical change in an electrolyte resulting from the
passage of electricity and often traditionally used to describe any and all forms of corrosion.
ELECTROLYTE: An ionized chemical substance or mixture that will conduct electric current,
such as water, soil, or many chemical solutions.
ELECTRO-NEGATIVE: A term used to designate the metal most likely to corrode in a
bimetallic corrosion cell. Magnesium and zinc, for instance, are electro-negative with respect
to copper or steel. In the same relationship, copper and steel are electro-positive.
ELECTRONIC IGNITION: An ignition system which uses a high open-ended voltage to
produce a high temperature spark to ignite the pilot or main burner.
ELEVATED DELIVERY PRESSURE: Any delivery pressure in excess of 7-inches WC (water
column)or 1/4 psig.
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NATURAL GAS SPEC. 1.1

EMERGENCY: For the purposes of this handbook, any situation, occurrence, or incident that
requires immediate action to protect life, property, or the environment.
EMERGENCY OPERATING PLAN (EOP): A plan required by Federal regulations that details
procedures to be followed to ensure the safety of the public and/or employees in the event of
a natural gas related emergency.
EMERGENCY SERVICES: Any public or private agency which has the primary responsibility
to respond to emergencies. This includes police departments, state police/patrol, fire
departments, hazmat teams, ambulance services, paramedics, etc. These agencies are
normally accessed by dialing "911".
EMERGENCY SHUTDOWN: Taking actions that are designed to shut down a station, facility,
or system or to change to a reduced operational state in the event of a failure or hazardous
situation. (See GESH 5)
EMERGENCY VALVE: A valve that may be necessary for the safe operation of a
transmission or distribution system. Such valves must be checked and serviced at intervals
not exceeding 15 months, but at least once each calendar year. (Note: An EOP valve is a
type of emergency valve, but the names are not synonymous. See "EOP Valve" definition for
further information.
EMPLOYEE: Also referred to in this policy as "gas employee", "service person", and other
titles. Denotes any person in the employ of Avista Utilities who may be responsible for
carrying out the duties as described in this handbook, or as detailed in the O & M plan. May
also refer to contract employees depending on the context of the policy and current
Union/Company agreements.
ENCODER, RECEIVER, TRANSMITTER (ERT): An auxiliary device installed on meters to
allow for remote reading.
ENTIRELY REPLACED ONSHORE TRANSMISSION PIPELINE SEGMENT: A segment of
transmission pipeline that has 2 or more miles, in the aggregate, of pipeline replaced within
any 5 contiguous miles of pipeline within any 24-month period.
EOP VALVE: Distribution or transmission valves that are located in key positions to enable
quick isolation and shut-down of a pipeline during an emergency. An EOP valve is a type of
Emergency Valve.
EROSION: Deterioration by the abrasive action of fluids, usually accelerated by the presence
of solid particles of matter in suspension. When deterioration is further increased by
corrosion, the term erosion-corrosion is often used.
EVACUATION: The process of removing or assisting in the removal of persons from an area
or structure in order to avoid danger.
EVALUATION: A process established and documented to determine an individual's ability to
perform a covered task by various methods.
EVALUATOR: An individual selected or credentialed to conduct performance or oral interview
evaluations to determine if an individual is qualified.
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NATURAL GAS SPEC. 1.1

EXCESS FLOW VALVE (EFV): A device that is designed to automatically shut off the flow of
gas should the service line be severed.
EXPLOSIVE LIMITS: Lower and upper percentages expressing a range of fuel-to-air
mixtures that will burn when exposed to a high enough temperature to cause ignition. The
explosive limits of natural gas are approximately 5 percent to 15 percent gas in air but may
range slightly lower or higher depending on the methane content of the gas. Ratios outside
these should not combust or explode. The explosive limits for propane are approximately 2
percent to 10 percent.
FABRICATED UNIT: An assembly of two or more fittings and/or pieces of pipe joined
together.
FACILITY, GAS: A Company gas pipeline, meter set, fitting, station, or other related
appurtenance used in the distribution of natural gas to Avista's customers.
FARM TAP (SINGLE SERVICE FARM TAP-SSFT): A pressure regulating station that
controls pressure to a service line. Assembly usually utilizes a regulator and relief to reduce
transmission or distribution pressure to 60 psig or less.
FIELD INVESTIGATION: Avista's procedures for responding to gas related incidents,
accidents, failures, or fires (Gas Field Incident Investigation, GESH Section 17 and/or Leak
and Odor Investigation GESH Section 2). After investigating to resolve the emergency,
personnel will collect data to document or record the scene of the incident site (ref: GESH
Section 17 sheet 3 of 8 "Recording the Scene")
FIRM CUSTOMERS: Natural gas customer for whom contract demand (supply or capacity) is
reserved and to whom the seller(pipeline or producer) is obligated to furnish service at all
times, except in cases of force majeure.
FITTING: A component used in a gas facility for changing direction, branching or for change
of pipe diameter.
FITTING, PIPE (NON-RATED): A fitting that has physical characteristics (diameter, wall
thickness, grade, etc.) similar to gas pipe and whose MAOP is determined based on those
characteristics. These fittings require a pressure test to establish MAOP.
FITTING, RATED: A fitting that is designed to a specific standard (ANSI, ASTM, etc.) and has
a designated pressure rating from the manufacturer.
FLAME IONIZATION UNIT: Also referred to as an "F.I. Unit" and "Flame Pak". An extremely
sensitive gas leak detection instrument that senses the presence of methane gas by
measuring the ions produced in a hydrogen flame when gas is burned. F.I. Units can
normally detect methane down to 1 ppm.
FLOW PRESSURE: The pressure within a piping system that exists when there is a certain
amount of flow through a meter set that is representative of a "normal" load.
FLOW RATE: A volume of gas measured over a given time. The flow rate is generally
measured in cubic feet per hour(CFH) and is sometimes used synonymously with "load"
although technically these are not the same.
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FLUE GASES: Normal products of combustion: carbon dioxide and water vapor, which are
vented into the outdoor atmosphere through a flue pipe.
FORCE MAJEURE: A superior obligation, "Act of God," or any other unexpected and
disruptive event, which may serve to relieve a party from a contract or obligation.
FORCED AIR: An air delivery system that moves heated air mechanically with fans and
blowers through ductwork.
FURNACE: A self-contained appliance, used in central heating systems, for heating air by
transfer of heat of combustion through metal to the air.
GALVANIC SERIES: A list of metals and alloys arranged according to their relative
electrolytic potentials to one another in a given environment. The metals or alloys higher on
the list (more negative) are anodic to those lower on the list and the metals or alloys lower on
the list (more positive) are cathodic to those higher on the list.
GAS OPERATING ORDER: A Company approved form or electronic process that serves as
documentation of work performed in relation to installation of facilities, of work on customer
premises, of meter changes or repairs, of response to leak and odor requests, etc. This form
may take on different formats to accommodate the particular type of order being worked, or to
fit the particular system being used to generate the order.
GAS SERVICE PERSON: A Company employee who has completed a minimum 2-year
apprenticeship (or the equivalent)for the position of Gas Serviceman, and who has achieved
"Journeyman" status through evidence of completion of all required or statutory courses and
licensing.
GAS SHUT-OFF NOTICE: A Company approved form or electronic process that advises a
customer that the gas service has been closed to facilitate repairs or due to other conditions.
GATE STATION: The point at which the distribution company (Avista)taps off a pipeline
company (i.e., NWP or GTN). Custody transfer of gas occurs at this point. Even if only one
customer is downstream of this station, it is still considered a Gate Station. Generally,
regulating, odorizing, and metering equipment are found in a gate station. Other possible
names for a gate station include meter station, town border station, city gate, and odorizer
station. (If gas is not metered at the site, then the station is not considered a Gate Station,
such as the regulator stations off the Williams NW 6-inch pipeline that runs between Mead
and Starr Road Gate Stations.)
GATHERING LINE: A pipeline that transports gas from a current production facility to a
transmission line or main.
GROUND BED: Refer to anode (cathodic protection).
HAZARDOUS CONDITION: Any condition that is causing or that may cause a hazard to
persons or property. Such conditions require notification of the customer and issuance of the
appropriate hazard notice.
HEAT EXCHANGER: A device used for transferring heat from one fluid to another without
allowing them to mix, typically found in a forced air furnace.
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HEAT FUSION JOINT: Ajoint made in thermoplastic piping (polyethylene piping) by heating
the parts sufficiently to permit fusion of the materials when the materials are pressed
together.
HIGH OCCUPANCY STRUCTURE OR AREA: A structure or area that is normally occupied
by 20 or more persons on at least 5 days a week for 10 weeks in any 12-month period. (The
days and weeks need not be consecutive.) Structures and areas include churches, hospitals,
schools, and may include assembly buildings, outdoor theaters, outdoor recreation areas,
etc.
HIGH PRESSURE: Pressure that is greater than 60 PSIG.
HOLIDAY: A break or imperfection in a pipe coating.
HOLIDAY DETECTOR (JEEPING MACHINE): An electronic device for locating
discontinuities or breaks in the protective coating on a pipe, tubing, or fitting.
HOOP STRESS: The stress in a pipe wall that acts circumferentially in a plane perpendicular
to the longitudinal axis of the pipe and is produced by the pressure in the pipe.
IDLE METER: A meter installed on a service where the account is closed but the meter
remains in place.
IDLE SERVICE (IDLE RISER): A situation where the meter has been removed and the
service valve has been locked.
IGNITION TEMPERATURE: The temperature at which a substance, such as natural gas, will
ignite and continue burning with adequate air supply.
IMMEDIATE RESPONSE: Any form of prompt action taken to save lives, prevent injury, or
mitigate property damage under imminently serious conditions when time does not permit
approval from a higher authority.
IMPRESSED CURRENT: Cathodic protection current provided by rectifier type protective
systems.
INCHES OF WATER COLUMN: A standard unit of measurement typically used to describe
the amount of gas pressure in units of less than 1 PSIG. The conversion for inches of water
column is: 27.7" = 1 PSIG.
INCIDENT: An occurrence or event that happens in relation to Company gas facilities that
warrants immediate or quick action, and that may require appropriate notifications of certain
Company supervisory, or state or federal officials. Incidents may also be related to an
emergency situation.
INCIDENT ASSESSMENT: Avista's formal program and processes for identifying
improvement opportunities (organizational and individual) by assessing the practices,
standards, and procedures, among other things that resulted in the incident or near miss. The
goal is to identify corrective actions to prevent or at least reduce the consequences of a
similar future incident or near miss.
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INCONCLUSIVE: Not having a final conclusion. As applied to leak and odor investigations,
any situation involving response to a leak or odor in which the cause or reason for the leak or
odor is not evident at the conclusion of the investigation. An inconclusive leak or odor request
requires additional action.
INDUSTRIAL METER SET: A meter set that meets any of the following criteria: It meters at a
pressure greater than 5 PSIG; is a turbine meter; or has a Meter Correction Code of 3 or P.
INERT GAS: A gas that is non-explosive and non-flammable. Operators use inert gases for
testing and purging pipelines. The most common inert gas is nitrogen. High concentrations of
inert gases may cause asphyxiation.
INFLECTION: A change in course or direction of a pipeline typically made by a bend or fitting.
INFRARED (IR) LEAK DETECTOR: An intrinsically safe, portable device that uses infrared
(IR)technology to detect the presence of natural gas leaks. The detector functions by
identifying specific infrared light wavelengths and absorption characteristics for methane gas.
IR devices are extremely sensitive and can detect very small leaks with a sensitivity down to
1 PPM.
INHIBITOR: A substance which retards corrosion when added to an environment in small
concentrations.
INSIDE METER SET: A meter that is located inside a well-ventilated building, meter room, or
full enclosure. Regulator vent piping must be installed to vent gas to the outside of the
building or enclosure. See also the definition for"METER ROOM". Refer to Spec 2.22.
INPUT RATING: The fuel burning capacity of the appliance in BTU/hr as specified by the
manufacturer. Also referred to as "input' or"BTU input'.
INSULATOR: Pipe fittings such as unions, couplings, and flanges which permit electrical
separation of one section of pipe from another. Refer to "Dielectric".
INTERMEDIATE PRESSURE: Pressure that is 1 PSIG up to and including 60 PSIG.
INTERMITTENT IGNITION (IID): An ignition system that is activated only on a call for heat to
reduce standby losses. The pilot burner is ignited by either an electric spark or a hot surface
igniter. There may also be direct ignition of the burner from the ignition devices.
INTERNAL RELIEF VALVE (IRV): A relief valve that is built into many service regulators to
relieve excess gas pressure above a certain set point. The internal relief valve will open and
allow gas to escape to the atmosphere in cases where the set point is exceeded due to an
operational malfunction.
INTERRUPTIBLE GAS: Service to a customer which under contract may be interrupted
during periods of peak demand to the total system.
JEEP: An instrument used to detect imperfections (holidays)or damage to protective coating
on steel pipe. It is also known as a holiday detector.
JOULE-THOMSON EFFECT: The cooling which occurs when a compressed gas is allowed
to expand in such a way that no external work is done. The effect is approximately 7° F per
100 psi for natural gas.
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LADDER POLICY: A company policy determining the circumstances in which a ladder may
be used by company and contract personnel.
LANDFILL GAS: Gas which is composed of methane and carbon dioxide and produced by
aerobic and anaerobic decomposition of organic solid waste in a landfill.
LATERAL: A pipe in a gas distribution or transmission system which branches away from the
main trunk line.
LEAK: An uncontrolled or unauthorized discharge or escape of natural gas from the system.
LEAK CENTERING OR PINPOINTING: The procedure used to determine (normally within a
radius of several feet)from where an underground leak is originating. The procedure involves
making a series of bar holes in an area where gas may be migrating, measuring the
gas-in-air mixture at each hole, and then determining the general location of the leak by
analyzing the readings.
LEAK DETECTOR: A device for determining the concentration of gas in air.
LEAK TEST: A pressure test to determine the tightness of the system.
LIFT OF PIPE: One level stack of pipe.
LIMIT DEVICE: A temperature activated control designed to shut off the supply of gas in the
event of an over temperature situation.
LIQUEIFIED NATURAL GAS (LNG): Natural gas or synthetic gas having methane (CH4) as
its major constituent which has been changed to a liquid by lowering the temperature.
LOAD: A means of expressing the quantity of gas require to service all appliances on a piping
system over a period of one hour, as expressed in BTU/hour or in therms.
LOCAL DISTRIBUTION COMPANY (LDC): A local gas company responsible for distributing
gas to its customers. An LDC purchases gas from transmission companies for resale to the
consumer. LDC's operate and maintain the underground piping, regulators, and meters that
connect to each residential and commercial customer.
LOCKUP PRESSURE: The gas pressure contained within a piping system when there is no
consumption.
LOW PRESSURE: Operating at less than 1 psig. It is usually measured in inches of water
column.
LOWER EXPLOSIVE LIMIT (LEL): The lower explosive limit of natural gas which varies
slightly depending on the amount of methane present. For Avista, the LEL of natural gas is
generally defined as 5 percent gas in air. Refer to"Explosive Limits"for more information.
MAIN: A pipeline serving as a common source of supply for more than one service line.
MANHOLE: Any inspection or access port for the maintenance or operation of equipment or
components.
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MANIFOLD: A common piping system used as an intersection for distribution of gas to more
than one customer. A single service line and regulator typically feeds the inlet of the manifold.
Several outlet valves and meters are installed on the manifold to serve individual customers.
MANOMETER (U-GAUGE): A"U" shaped tube, filled with water or another liquid with a
specific gravity equal to water. It is used to measure pressure in units of inches of water
column.
MANUAL SERVICE LINE SHUT-OFF VALVE—See Curb Valve.
MASTER METER STATION: A meter set serving a pipeline system for distributing gas within,
but not limited to, a definable area, such as a mobile home park, housing project, or
apartment complex, where the operator purchases metered gas from an outside source
(Avista)for resale through a gas distribution pipeline system. The gas distribution pipeline
system supplies the ultimate consumer who either purchases the gas directly through a meter
or by other means, such as by rents. Master meter stations are considered district regulator
stations and are maintained accordingly.
MAXIMO: The IBM asset management system that tracks procurement, inventory, location,
and work management for planned and unplanned work activities related to assets (including
meters). In Gas Compliance, it is the system of record for scheduling, tracking and
documenting gas maintenance activity.
MAXIMUM ALLOWABLE OPERATING PRESSURE (MAOP): The maximum pressure at
which a gas pipeline or pipeline segment may be operated in accordance with the applicable
regulatory codes. The MAOP of such a gas facility is determined by the "weakest link"within
that facility and is the upper Safe Operating Limit. (See the definition of Safe Operating Limit
below.)
MECHANICAL FITTING: Fittings that connect steel or PE components in a manner other
than heat fusion or welding.
METER CLOCK TEST: Procedure where a test dial on a gas meter is observed for
movement over time. The procedure is used to identify volume of flow through the meter.
METER DATA MANAGEMENT: The system that ensures the reliability and optimized use of
available data from a smart meter system (AMI). MDM loads, validates, stores, and formats
meter/usage data from smart meter sources and enables interface to other utility systems
such as customer information, outage management, work force management, and
geographical information.
METER ROOM: A room designed to house natural gas meter(s)that is within the confines of
the building to be served.
METER SET ASSEMBLY (MSA): The equipment including meters, regulators, relief valves,
etc. required to measure and deliver gas to a customer.
METER SPOT CHECK: A procedure where the test hand on a gas meter is observed for no
movement.
METER SWIVEL: The fitting that connects to the inlet and the outlet of a small gas meter.
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METER, GAS: An instrument for measuring, indicating, or recording the volume, mass, or
energy of natural gas at its pressure and temperature at the time of measurement.
METERING PRESSURE: The pressure at which the meter is measuring gas.
MIL: A unit of length equal to 1/1000 inch used especially in measuring thickness (as in
plastic films).
MINIMUM SAFE UTILIZATION PRESSURE: Enough pressure differential to maintain
customers without pilot outage. This will typically be the Lower Safe Operating Limit. (See
"Pressure Drops" in GESH Section 5, Page 3.)
MITER JOINT: Used instead of an elbow to change direction of pipe. A miter is made by
cutting ends of pipes to be joined at angles.
MONITOR: Second regulator used in series configuration with the working regulator to
maintain downstream pressure within the necessary limits of accuracy should the controlling
regulator fail. A monitor acts as secondary backup regulator and does not release gas to
atmosphere. The monitor may be located upstream or downstream of the working regulator.
MUST: Indicates that a provision is MANDATORY for completion. The word "shall" is a
synonym and requires similar treatment in these standards.
NATIONAL TRANSPORTATION SAFETY BOARD (NTSB): An independent agency
reporting administratively to the Secretary of the Department of Transportation, charged with
the investigation of all safety-related incidents involving transportation. These include air, rail,
highway, and certain liquid and gas pipeline transportation. (The NTSB has no power to issue
regulations; however, it issues reports and recommendations.)
NATURAL GAS: A naturally occurring mixture of hydrocarbon and non-hydrocarbon gasses
found in porous geologic formations beneath the earth's surface, often in association with
petroleum. The principal constituent is methane.
NEGATIVE PRESSURE: A condition that is created when more air is exhausted out of a
building than is being replaced. This creates a partial vacuum in the building, so that air is
forced down chimneys or vents causing the products of combustion to spill into the living
space.
NEUTRAL PRESSURE POINT: The location in a converted appliance's combustion chamber
between the positive pressure zone above the flame and the negative pressure zone below
the flame. This point is usually set at about the firing door latch; however, the point may vary
with heat exchanger design.
NEW CONSTRUCTION RISER: An anodeless riser that is field fabricated and comprised of a
galvanized steel sleeve, PE pipe, and service head adapter. A new construction riser can be
built in custom lengths to accommodate instances where the standard manufactured
anodeless riser is insufficient.
NON-OBSERVABLE TASK: A task that can only be performed by a qualified individual.
NON-QUALIFIED: An individual not qualified to perform a covered task.
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NOTIFICATION OF POTENTIAL RUPTURE: Means the notification to, or observation by, an
operator of conditions indicative of a potential unintentional or uncontrolled release of a large
volume of gas from a pipeline. In the case of Avista, a "large volume of gas" is interpreted to
be 3 million cubic feet (3 MMCF).
ODORANT: A substance giving a readily distinctive perceptible odor at low concentrations in
natural gas. It is used as a method of detection of the presence of natural gas, as natural gas
itself has no odor.
ODORIZATION: The process of adding an odor to natural gas. Since natural gas is odorless,
odorant is added to the gas so that people can smell escaping or leaking gas and report the
situation to a gas company for further investigation.
ODORIZER: A piece of equipment that adds chemical odorant to flowing natural gas
pipelines.
ODOROMETER: A device used to detect the amount of natural gas as a percentage of gas in
air at the point the odorized gas can be detected by a person with a normal sense of smell.
OHM: The unit of measurement of electrical resistance.
ONE-CALL SYSTEM: A utility coordinating and notification system that allows for requests for
locations of underground facilities to be forwarded in a timely manner to the appropriate utility
for field locating and marking.
OPERATING STRESS: The stress in a pipe or structural member under normal operating
conditions.
OPERATION OF A PIPELINE: The starting, stopping, changing, or monitoring of pressure,
flow, and temperature of product through a pipeline.
OPERATIONS MANAGER: Supervisory person in charge of a particular operating area. The
operations manager may also be referred to as a "regional manager", "district manager",
"construction manager", "supervisor", or"area coordinator".
OPERATOR IDENTIFICATION NUMBER (OPID): A number assigned to gas pipeline
operators as a unique identification number for reporting to PHMSA. (Effective January 1,
2012, each operator of a gas pipeline must obtain an OPID.) Avista's OPID is 31232.
ORIFICE: The opening in an orifice cap, orifice spud, whereby the flow of gas is limited and
through which the gas is discharged.
OVERPRESSURE PROTECTION (OPP): Any device that ensures that the maximum
allowable operating pressure of a piping system is not exceeded. These devices may include,
but are not limited to relief valves, safety shutoff valves, and monitor regulators.
OXIDATION: The loss of electrons by a constituent of a chemical reaction occurs at anode.
P/S (PIPE TO SOIL): A measurement of the difference in potential between a pipeline and a
copper-copper sulfate half-cell electrode in contact with an electrolyte.
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PADDING: The placing of material free of any hard objects (rocks, etc.) below, around and
above the pipe during backfill in order to protect the pipe surface from puncture or excessive
abrasion. (Sometimes referred to as "bedding".)
PATCHING: Method of repairing damaged pipe where piece of metal usually less than 1/2
the circumference of the damaged pipe is welded over the damaged section of pipe.
PERIMETER: When conducting a leak investigation, an area that reasonably surrounds the
initial underground leak location.
PERSONAL PROTECTIVE EQUIPMENT (PPE): Personal equipment that protects the
individual who wears it by placing a barrier between that individual and a potential or known
hazard. Examples of PPE include protective eyewear, face shields, masks, gloves, boots,
hats, clothing, and respirators.
PIG: A device used to clean debris or scale from internal pipe walls and to purge water from
pipe after hydro testing. Pigs are usually forced through pipe by air compressors, but
sometimes are pulled with cables. The word is also used to refer to a sophisticated internal
inspection device (smart pig) used to assess the integrity of pipelines. See Smart Pig.
PILOT: A small flame which is utilized to ignite gas at a main burner.
PINPOINTING: The process of locating the exact source of a gas leak along a pipeline route
with a minimum of excavation. This is accomplished using a gas measuring analyzer and a
non-sparking metal plunger bar to punch holes in the ground along the pipeline's right-of-way
(see "centering").
PIPE STUB MARKER: A short section of non-operating polyethylene pipe installed vertically
at the end of a gas main or service pipe. Stub markers usually extend above grade and may
contain tracer wire to provide access for locating. These are not official pipeline markers used
to indicate potential below ground hazards.
PIPELINE: All parts of those physical facilities through which gas moves. This includes but is
not limited to pipe, valves, and other appurtenances.
PIPELINE COMPANIES: Companies that deliver gas to Avista gate stations.
PIPELINE MARKER (LINE MARKER): A round, single, double, or tri-faced sign that indicates
a potential hazard and/or to designate the location and route of distribution and transmission
pipelines or underground facilities.
PIPELINE SAFETY: Protection of the public, employees, and pipeline against the
consequences of physical failure, human error, organizational failure, damage, or other
undesirable events.
PITTING: Localized corrosion of a metal surface that is confined to a small area and takes
the form of cavities called pits.
PLUG: An external thread pipe fitting that is inserted into the open end of an internal thread
pipe fitting to seal the end of the pipe. Also, the act of sealing a hole in a vessel, such as a
pipe or tank, by inserting material in the hole and then securing it, and the material used to
seal the hole.
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POLARIZATION: The change of electrode potential resulting from the effects of current flow,
measured with respect to steady state potentials.
POLYETHYLENE: The material used to manufacture plastic pipe and some plastic fittings.
When the term "plastic" is used, it is typically synonymous with "polyethylene" or"PE".
PREFABRICATED UNIT (PRESSURE VESSEL): A fabrication that uses plate and
longitudinal seams, or an assembly utilizing components that do not have a readily available
design pressure.
PREFABRICATED WELDED ASSEMBLIES: An assembly consisting of regularly
manufactured butt-welding fittings, ASTM A-53, A-105 or API 5L pipe, and standard valves.
All components shall be connected by circumferential welds. These are exempt from the
"Prefabricated Unit and Pressure Vessel" requirements in Spec 2.12 and §192.153.
PRESSURE DROP: Refer to"Allowable Pressure Drop."
PRESSURE TEST: A test performed by pressurizing a gas line for a predetermined length of
time. A successful pressure test will show no unaccounted-for loss in pressure as indicated
on a recording chart, pressure gauge, or water manometer, thus indicating that the system is
gas tight. Also referred to as an "air pressure test." May be referred to as a "strength test' in
regulations. If water is used as the testing medium, it may be called a "hydrotest".
PRESSURE VESSEL: Refer to "Prefabricated Unit."
PROPANE: A gaseous member of the paraffin series of hydrocarbons, that, when liquefied
under pressure, is one of the components of liquefied petroleum gas (LPG). Propane
contains approximately 2,500 British thermal units (BTU) per Cubic foot. Although it is
gaseous at ordinary atmospheric conditions, it is readily compressed into a liquid. It is highly
volatile, odorless, and colorless.
PSI (pounds per square inch): The unit of pressure or measure of force on a given area.
Within the oil and gas industry, psi normally refers to the pressure of the gas or product
contained within the pipeline or pressure vessel. (Typically shown in lower case letters.)
PSIA(pounds per square inch, absolute): The pressure expressed in pounds exerted on one
square inch of surface area. The absolute refers to the total pressure sensed including the
surrounding atmospheric pressure. (Typically shown in lower case letters.)
PSIG (pounds per square inch, gauge): The pressure expressed in pounds exerted on one
square inch of surface area. The designation "gauge" indicates the readings are already
adjusted or biased to ignore the surrounding atmospheric pressure which is 14.7 psi at sea
level. If a PSIG type of gauge were not connected to any pressure source, it would read zero
even though it is actually sensing 14.7 psi at sea level. (Typically shown in lower case
letters.)
PUBLIC UTILITY COMMISSION: State agencies that inspect pipeline safety and regulate the
tariffs (pricing) of investor-owned utility companies.
PUMPKIN: A reinforcing sleeve welded over a coupling or other fitting.
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PURGE: To free a gas facility of air or gas, or of a mixture of gas and air. Purging is required
when bringing new or existing facilities into service from a depressurized state or after a
facility has been blown down/depressurized to perform work on or abandon an existing
facility.
QUALIFIED: An individual that has been evaluated and can perform assigned covered tasks
and is able to recognize and react to abnormal operating conditions.
RADIANT HEAT: Heat energy that is emitted from an object to the surrounding atmosphere.
RADIOGRAPHIC INSPECTION: Method used to determine flaws in pipe or other metals by
use of a machine that emits x-rays or gamma rays which penetrate the metal and are
transcribed onto film.
RANGE: A cooking appliance which usually includes several top burners above, and an oven
and broiler below. Also referred to as a "stove" or"cook stove".
READ: The volume of gas measured in cubic feet (CF) by the gas meter. A cubic foot of gas
measured at standard pressure and temperature contains approximately 1000 BTUs of
energy.
READING: A repeatable (sustained) representation on a device such as a combustible gas
indicator, a pressure gauge, etc.
RECTIFIER: A device used to convert alternating current(AC)to direct current(DC) and
used in the gas industry for external corrosion control of pipe and other metals.
REDUCTION: Gain of electrons by a constituent of a chemical reaction, occurs at cathode.
REFERENCE ELECTRODE: An electrode whose open-circuit potential is constant under
similar conditions of measurement, which is used for measuring the relative potentials of
other electrodes. (Often referred to as a "half-cell".)
REGULATION: The process of reducing and controlling pressure.
REGULATOR: Device used to maintain a constant downstream pressure. Also known as a
Pressure Regulator.
REGULATOR VENT: The opening in the atmospheric side of the regulator housing permitting
the free movement of the regulator diaphragm.
REGULATOR, SERVICE: A device on a service line that controls the pressure of gas
delivered from a higher pressure to the pressure provided to the customer. A service
regulator may serve one customer or multiple customers through a meter header or manifold.
RELIEF: Device used to maintain downstream pressure within necessary limits by relieving
gas to atmosphere should the working regulator fail.
REMOTE CONTROL VALVE (RCV): A valve that is operated from a location remote from
where the valve is installed. The RCV is usually operated by a controller via the SCADA
system. The linkage between the pipeline control center and the RCV may be by fiber optics,
microwave, telephone lines, or satellite.
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REMOTE METER: A meter that is installed more than three feet from a building or foundation
wall, of a structure that is served by natural gas.
REMOTE METHANE LEAK DETECTOR (RMLD): An intrinsically safe, laser methane leak
detector that is often used to detect the presence of natural gas from a remote distance or in
locations that are difficult to gain full access.
RENEWABLE NATURAL GAS: Pipeline-quality biomethane produced from biomass. It is
interchangeable with natural gas. It is carbon neutral, extremely versatile and fully compatible
with the U.S. pipeline infrastructure.
REPLACED SERVICE LINE: A gas service line where the fitting that connects the service
line to the main is replaced or the piping connected to this fitting is replaced.
RESISTIVITY: The relative degree to which soil or water resists the flow of electric current.
The most common terms in use are the ohmmeter and the ohm-centimeter.
REVERSE CURRENT SWITCH: A bond designed and constructed such that CP current can
pass in only one direction.
RISER: A general term for vertical runs of piping regardless of the size or application. (The
most common reference at Avista would be a "meter riser"which is the piping that connects
underground service piping to the gas meter.)
RUPTURE-MITIGATION VALVE (RMV): An automatic shut-off valve (ASV) or remote-control
valve (RCV)that is used to minimize the volume of gas released from the pipeline and to
mitigate the consequences of a rupture.
RUST: Corrosion product consisting primarily of iron oxide. A term properly applied only to
iron and other ferrous metals.
SACRIFICIAL PROTECTION: Reduction or prevention of corrosion of a metal in an
environment by coupling it to another metal which is electrochemically more active in that
environment.
SAFE OPERATING LIMIT: A limit established for a critical process parameter such as
temperature, pressure, or flow, and based on equipment design limits and the dynamics of
the process.
SAFETY DATA SHEET: Document that contains information on the potential health effects of
exposure to chemicals, or other potentially dangerous substances, and on safe working
procedures when handling chemical products.
SAFETY DEVICES: Devices designed to forestall the development of a hazardous or
undesirable condition in the piping system, in the equipment, in the medium being treated, or
in the combustion products.
SEAMLESS PIPE: Steel pipe which has no longitudinal butt joint. It is manufactured by hot
working the tubular product (usually over a mandrel) into the desired shape.
GLOSSARY REV. NO. 15
DATE 01/01/25
;�risra STANDARDS 22OF27
Utilities
NATURAL GAS SPEC. 1.1

SEGMENT (PIPELINE SEGMENT): A section or length of gas facility that typically has the
same physical pipe characteristics (diameter, grade, wall thickness, etc.) and which the
MAOP was established under the same pressure test. A segment may include valves and
fittings that have different characteristics from the connected line pipe.
SELF TAPPING TEE: A service tee with a self-contained cutter which is installed on in-
service pipe for drilling a hole in the pipe.
SEPARATION: The distance between two objects in any direction.
SERVICE (SERVICE LINE): A distribution line that transports gas from a common source of
supply to an individual customer to two adjacent or adjoining residential or small commercial
customers, or to multiple residential or small commercial customers served through a meter
header or manifold. A service line ends at the outlet of the meter or at the connection to a
customer's piping if there is no meter.
SERVICE HEAD ADAPTER: A PE to steel transition fitting most commonly used on a new
construction riser or a steel service that is inserted with PE pipe. The fitting is threaded onto
the outlet of the steel riser and allows for the attachment of the meter valve.
SERVICE REGULATOR: See Regulator, Service.
SERVICE VALVE or SERVICE-LINE VALVE: A valve located in a service line and located
upstream of the service regulator, meter, any meter bypass where there is no service
regulator, or connection to customer piping if there is no meter.
SHALL: Indicates that a provision is MANDATORY for completion. The word "must" is a
synonym and requires similar treatment in these standards.
SHIELDING: High resistance or non-conducting material preventing CP current from reaching
the structure, or low resistance material diverting the current away from the structure to be
protected.
SHORT: An inadvertent, undesirable contact between two buried metals, or the electrical
failure of installed insulation which destroys the desired metallic isolation of a piping system.
SHORT SECTION OF PIPE: A single piece of pipe containing no girth welds (steel)or fusion
joints (PE).
SHORTED PIPELINE CASING: A casing that is not electrically isolated from the carrier pipe.
Generally, this term is used for casings that are in direct metallic contact with the carrier pipe.
SHOULD: Indicates a provision that although not mandatory, is the preferred method and
strongly recommended as a best practice. There must be a substantial reason for not
completing such provisions within Avista's Gas Standards and oftentimes non completion of
these provisions must be documented with a reason.
SHUT-OFF VALVE (Pertaining to overpressure protection): Device used in series
configurations with regulator to maintain downstream pressure within necessary limits by
shutting off gas supply should the regulator fail.
SINGLE SERVICE FARM TAP (SSFT): See Farm Tap Regulator
GLOSSARY REV. NO. 15
DATE 01/01/25
;�risra STANDARDS 23OF27
Utilities
NATURAL GAS SPEC. 1.1

SLEEVING: Method of repairing damaged pipe where metal is welded around the full
circumference of the pipe over the damaged section. Sleeves usually come in two halves.
SMART PIG: Any of a variety of internal pipe inspection devices. These devices, or"pigs",
measure and record the internal geometry, external or internal corrosion as well as provide
information about pipe characteristics such as wall thickness and other pipe defects.
Magnetic flux leakage, ultrasonic, calipers, and geometry are examples of smart tools; also
referred to as ILI tools.
SOAP TEST: A test for gas leaks, which involves wiping or brushing the joints to be tested
with a soap and water solution, typically performed at no less than the operating pressure of
the facility. Any leaks on the piping will be identified by the formation of bubbles.
SOIL POTENTIAL GRADIENT: The voltage drop in the soil caused by direct current flowing
away from or to a ground electrode, anode, or cathode. The voltage gradient is measured
between two copper-copper sulfate half-cell electrodes a set distance apart on a radius line
from the ground electrode.
SOUR GAS: Natural gas contaminated with chemical impurities, notably hydrogen sulfide or
other sulfur compounds, which impart a foul odor to the gas. Such impurities must be
removed before the gas can be used for commercial and domestic purposes.
SOURCE OF IGNITION: Any device or object that is capable of producing a source of heat of
sufficient temperature to ignite natural gas. Examples of such devices or objects are radios,
matches, heating equipment, motors, static electricity, light switches, etc.
SPAN OF CONTROL: The maximum number of non-qualified individuals that a qualified
individual can direct and observe under Operator Qualification rules.
SPECIFIED MINIMUM YIELD STRENGTH (SMYS): The minimum yield strength prescribed
by the specifications under which pipe or non-rated pipe fittings are manufactured and sold.
SPOT CHECK: Refer to "Meter Spot Check"
STANDARD CONFIGURATION: As specified by drawings in the Gas Standards Manual.
STANDARD METERING PRESSURE: The pressure at which most residential meters
measure gas. Usually 7-inches WC (water column) or 1/4 psig. In some areas, it is 8-inches
WC.
STATIC ELECTRICITY: An electric charge, which builds up on an insulated object usually as
a result of friction. Static electricity will discharge as soon as it come close to a metallic object
or other conductor and will create a bluish spark and snapping sound. In gas leak situations,
the spark from static electricity is hot enough to cause ignition of flammable gas-in-air
mixtures.
STRAY CURRENT: Electrical current(normally direct current, DC), from either a natural or
man-made source, which could result in pipe corrosion if not properly drained or
compensated for by other means.
STRESS: The magnitude of the internal and/or external forces that act on a structure.
GLOSSARY REV. NO. 15
DATE 01/01/25
;�risra STANDARDS 24OF27
Utilities
NATURAL GAS SPEC. 1.1

STRESS CORROSION CRACKING: The formation of cracks in metallic pipe, typically in a
colony or cluster, as a result of the interaction of tensile stress, a corrosive environment, and
a susceptible material.
STRINGING: The act of laying pipe, end-to-end, alongside the pipeline ditch in preparation
for welding or fusing.
SUBMETERING: The practice of re-metering customer's building meter in order to distribute
gas to individual building tenants through privately owned or rented meters.
SUPERVISORY CONTROL AND DATA ACQUISITION (SCADA): A computer-based system
or systems used by a controller in a control room that collects and displays information about
a pipeline facility and may have the ability to send commands back to the pipeline facility.
SWEET GAS: Natural gas not contaminated with impurities, such as sulfur compounds.
Except for the removal of any liquid constituents that may be present, sweet gas can be used
for commercial and domestic use without any processing.
SYMPTOMATIC: Exhibiting symptoms. In relation to this policy, refers to any person that is
complaining of or that is outwardly exhibiting symptoms of carbon monoxide related or other
illnesses requiring immediate Company response.
SYSTEM: Natural gas facilities that are interconnected and have the same MAOP.
TARIFF: A schedule filled by a utility with a regulatory agency describing transactions
between the utility and customers in types of service, rates charged and means of payment.
TASK: A defined unit of work having an identifiable beginning and end and specific actions
that are observable and measurable.
TELEMETER: See Telemetry.
TELEMETRY: As related to Avista's gas system, telemetry, in general, is the process of
remotely monitoring gas pressure, gas temperature, and calculated values for volume, flow,
and abnormal conditions. The values are measured and calculated by instruments at Gate
Stations, Regulator Stations, Pressure Monitoring Sites, and Gas Transportation Customers.
The instruments also generate alarms/alerts when the values are outside of an acceptable
range. They transmit data via cellular modem, dial-up modems, AVA Corporate, or SCADA
networks to a server at headquarters which relays the data to the SCADA system, PI data
historian system, and Flow Cal system.
TEST MEDIUM: A substance such as water, air, or gas used to exert an internal pressure to
test for leaks or strength of a facility.
TEST POINT: An electrical connection to a gas facility, tracer wire, or structure where pipe-
to-soil potentials are taken to monitor CP, where tracer wire continuity can be checked, or to
assist in locating. Can also be used to schedule an inspection at a miscellaneous location in
Avista's GIS and Maximo. Also known as a "test station", "fink", or a "test point container".
TEST PRESSURE: The internal gauge pressure specified for testing.
THERM: A unit of energy equivalent to 100,000 BTUs. A customer is billed according to the
quantity of therms used.
GLOSSARY REV. NO. 15
DATE 01/01/25
;�risra STANDARDS 25OF27
Utilities
NATURAL GAS SPEC. 1.1

THREE-PART COMMUNICATION: A method of discourse used to positively communicate
important changes to plant facilities or other items during work activities via face-to-face,
telephone or radio discussions. This communication protocol requires three oral exchanges
between the sender and the receiver to promote a reliable transfer of information. (Also
known as 3-way communication or repeat back.)
TRACEABLE (RECORDS): Traceable records are those which can be clearly linked to
original information about a pipeline segment or facility.
TRANSMISSION LINE: A pipeline or connected series of pipelines, other than a gathering
line, that:
1. Transports gas from a gathering pipeline or storage facility to a distribution center,
storage facility, or large volume customer that is not downstream from a distribution
center;
2. Has an MAOP of 20 percent or more of specified minimum yield strength (SMYS);
3. Transports gas within a storage field; or
4. Is voluntarily designated as a transmission pipeline.
TRANSPORTATION CUSTOMER: A gas transportation customer is one who purchases
natural gas directly, usually through a broker, and pays Avista a transport fee.
TRENCH:A long ditch cut into the ground dug by a backhoe or by a specialized digging
machine such as a trencher, for the purpose of installing a pipeline.
UNION:A specialized threaded fitting used to couple two joints of threaded pipe together,
without having to turn or dismantle either run of pipe.
UPPER EXPLOSIVE LIMIT (UEL): The upper explosive limit of natural gas which varies
slightly depending on the amount of methane present. For Avista, it is generally defined as 15
percent gas in air. Refer to "Explosive Limits"for more information.
VALVE: A mechanical device used to control the flow of gas or liquid. A valve can be used
solely for fully open or closed applications, to control the direction of flow, or used to throttle
flow or regulate pressure. Typical valve types include plug valves, ball valves, globe valves
and gate valves.
VALVE BOX: A housing around an underground valve that extends to the surface of the
ground. A valve box allows access to the valve and protects the valve from mechanical
damage or the effects of weather.
VALVE SEAT: The stationary portion of the valve which, when in contact with the movable
portion, stops flow completely.
VAULT: An underground pit or enclosed structure which houses valves, pressure regulation
equipment, or other gas appurtenances.
VERIFIABLE (RECORDS): Verifiable records are those in which information is confirmed by
other complementary, but separate, documentation.
VERIFICATION: The act of checking the accuracy of an instrument or device and making
required adjustments if it is found to be out of tolerance. This process is typically done by
comparing the device to a recognized standard device that is known to be accurate.
GLOSSARY REV. NO. 15
DATE 01/01/25
;�risra STANDARDS 26OF27
Utilities
NATURAL GAS SPEC. 1.1

VOLT: The electromotive force which, when steadily applied to a conductor with one ohm
resistance, will produce a current of one ampere.
VOLTAGE: An electromotive force or a difference in electrode potentials expressed in volts.
WEAK LINK: A device or method used when pulling polyethylene pipe, typically through
methods such as horizontal directional drilling, to ensure that damage will not occur to the
pipeline by exceeding the maximum tensile stress allowed.
WELDING: A method of joining metal together using heat to fuse the pieces. Examples of
welding processes are shielded metal arc welding and gas metal arc welding.
WET GAS: Natural gas containing liquid, including water or liquefiable hydrocarbons such as
natural gasoline, butane, pentane, and other light hydrocarbons that can be removed by
chilling, pressurization, or other extraction methods. For operator established tariff purposes,
any gas containing water vapor in excess of 7 pounds per million cubic feet(mmcf) is
considered wet gas.
WICK-TYPE ODORIZER: Equipment that odorizes the natural gas by having the natural gas
flow across a wick in a pipe bottle saturated with odorant. Wick-type odorizers are generally
used for odorizing individual lines such as farm taps.
WRINKLE BENDS: Bends made by the obsolete practice of bending prior to the advent of
smooth bending technology. See 49 CFR Part 192.3 for a detailed definition of a wrinkle
bend. (Wrinkle bends are not allowed at Avista.)
YIELD STRENGTH: The yield strength is the stress level at which a material exceeds its
elastic limits, and the material begins to permanently deform.
GLOSSARY REV. NO. 15
DATE 01/01/25
��risra STANDARDS 27OF27
Utilities
NATURAL GAS SPEC. 1.1

Subject Details Sec/Section Subsection
1%at 1 foot rule GESH 4 general
10 ppm Rule CO orders GESH 3 10 ppm rule
10%survey of isolated 5.14 monitoring isolated mains less than 100 ft or service lines;
main and risers maintenance and remediation timeframes and frequencies
100 ppm Rule CO orders GESH 3 100 ppm rule
10-year overhaul of 5.12 10 year overhaul-diaphragm type regulators;relief valves
regulator stations &pilots
11000 intermediate Drawing B-33325, pg 4 2.24 Appendix A
pressure meter set
180 day inspection criteria 5.12 180 day inspection criteria
2 psiq meter sets maintenance 5.12 maintenance of elevated service pressure accounts
2 psig meter sets design 2 22 2 24 2.22 industrial sets&elevated pressure sets;2.24-
Appendix A
20%leak survey 5.11 5 year survey; maintenance frequencies
200 ppm Rule CO orders GESH 3 200 ppm rule
2000,3000,and 3500
intermediate pressure Drawing B-33325, pg 1 2.24 Appendix A
rotary meter
2000,3000,and 5000
welded rotary meter Drawing B-38205 2.24 Appendix A
press
24-hour rep restoration of service GESH 5 steps for restoration of service
250 psig and above 5.11 250+psig pipelines Washington only; maintenance
pipelines leak surveys frequencies
3 Foot Rule Drawing A-36275 2.22 Drawing A-36275
3 Foot Rule 2.22 3 Foot Rule
35 ppm Rule CO orders GESH 3 35 ppm rule
3rd Party Excavation
Damage:One Call damage prevention 4.13 3rd Party Excavation Damage:One Call Check
Check
40,000 PPM Relation of PPM Table GESH 2 Relation of PPM, Percent Gas and Percent LEL
5 psig meter sets maintenance 5.12 maintenance of elevated service pressure accounts
5 psig meter sets design 2 22 2 24 2•22-industrial sets&elevated pressure sets;2.24-
Appendix A
5000 and 7000
intermediate pressure Drawing B-33325, pg 2 2.24 Appendix A
rotary meter
5-year overhaul of 5.12 5 year overhaul-flexible element&boot type regulators
regulator stations and relief valves
5-year survey leak survey 5.11 5 year survey; maintenance frequencies
911 emergency call communication with GESH 13 communication with emergency and public officials
centers emerqencv and public officials
abandoned pipeline definition 1.1 glossary
abandoning casing 5.16 casings
abandoning commercially navigable 5.16 commercially navigable waterways
waterway
abandoning general facilities 5.16 abandoning as facilities
abandoning Idle meters/service 5.16 idle meters and idle services
abandoning mains 5.16 abandoning as facilities
abandoning maint.of abandoned facilities 5.16 maintenance requirements
abandoning meter facilities 5.16 inactivating as meter facilities
abandoning regulator stations 5.16 regulator station abandonment
abandoning services 5.16 abandoning as facilities; idle meters and idle services
abandoning reinstating after abandonment 5.17 throughout
abandoning steel services 3.16,5.16 3.16-steel service abandonment;5.16-abandoning gas
facilities
abandoning valves 5.13,5.16 5.13-valve disable/abandonment;5.16-valve
abandonment
abandoning OQ task 4.31 App A 221.060.010
abnormal operating
definition 1.1 glossary
conditions
abnormal operating
4.31 App A 4.31 App A
conditions
abrasion-resistant
overla ARO coating steel pipe 3.12 liquid epoxy coating
AC mitigation 2.12,2.32 2.12-AC Mitigation on New Steel Pipelines;2.32-AC
mitigation
access,safe definition 1.1 glossary
1

Subject Details Sec/Section Subsection
accidental ignition prevention 3.17 prevention of accidental ignition
Adams style clamp 3.35 throughout
aerosol static
su ression spray 3.34 aerosol static suppression procedure
AGA X, Fourth Edition Purging
Manual, Fourth regulatory requirements 3.17 purging pipelines
Man
AGA/ANSI LC-1 Use of CSST GESH 12 CSST
standard
air/fuel ratio definition 1.1 glossary
air shutter definition 1.1 alossary
alarm definition 1.1 glossary
alcohol screening employment GESH 2 responding employee qualifications
alcove definition 1.1 glossary
alcove meters 2.22 inside meter sets
alcove installation 2.22 inside meter sets
aldehydes definition 1.1 alossary
ald I a tee repair electrofusion 3.24,3.25 3.24-ald I a tee repairprocedure;3.25general
allowable pressure definition 1.1 glossary
drop(pressure drop)
aluminum meters meters 2.22 meter types
ambient temperature steel pipes 3.12 abrasion resistant overlay wrap
range
AMI installation GESH 6 throughout
ampere AMP definition 1.1 glossary
annual EOP training GESH 13 emergency training
annual leak surveys business districts 5.11 annual surveys
annual leak surveys transmission pipelines 5.11 general;transmission and other HP pipelines; maintenance
frequencies
annual leak surveys 5.11 annual surveys
2.14-emergency curb valves;2.22-identifying sites with
annual leak surveys high occupancy buildings 2.14,2.22,5.11 special design and maintenance requirements; 5.11 -
Annual Survey;5.11 -identifying high occupancy
structures and high occupancy areas
annual maintenance qate stations 5.12 gate stations
annual maintenance industrial meters 5.12 general station inspection;annual regulator station
maintenance
annual maintenance master meters 5.12 regulator stations and elevated pressure meter sets;
annual regulator station maintenance
annual maintenance re ulator stations 5.12 regulator stations and elevated pressure meter sets
annual maintenance cathodic instruments 5.14 calibration of equipment
annual maintenance heaters 5.22 maintenance
annual maintenance odorizers 5.23 injection odorizers(YZ type);by-pass odorizers;wick
odorizers
annual reporting 4.14 submission of reports;timp performance reporting
requirements
anode 4 1/2 lb anode 2.32 tracer wire
anode corrosion cell 2.32 corrosion cell
anode reaction 2.32 anode and cathode reactions
anode systems 2.32 anodes stems
anode tracer wire anodes 2.32 tracer wire
anode zinc anodes 2.32 tracer wire
anode(cathodic definition 1.1 glossary
protection)
anode corrosion definition 1.1 alossary
anode efficiency definition 1.1 glossary
anodeless riser definition 1.1 glossary
anodic field definition 1.1 glossary
API 1104 3.22 welder qualification requirements
appliance definition 1.1 glossary
appliance regulator definition 1.1 qlossary
appliance service GESH 10 throughout
approved definition 1.1 glossary
appurtenance definition 1.1 glossary
grinding;steel repair selection chart for pipelines with an
arc burns steel pipe repair 3.32 MAOP of 500 PSI or greater,or an operating stress of 20
percent or more of sm s at the pipeline MAOP
area odor definition 1.1 glossary
arrival times priority 1 and 2 GESH 11 priority1 and 2 arrival times
2

Subject Details Sec/Section Subsection
ASME B16.5 2.12 flanged connections
ASME B31.8 Section 831.42 2.12 design of pipeline components
ASME B31G 3.32 transmission lines
assessment definition 1.1 glossary
ASTM A105 steel pipe
flanges and flanged PSIG table 2.12 flanged connections
fittings
ASTM specification A- design requirements 2.12 manufacturing design and composition of line pipe
106
ASTM specification A- design requirements 2.12 manufacturing design and composition of line pipe
53
ASTM specification design requirements 2.13 marking on plastic pipe and components
D2513
ASTM specification other references 3.24 joiningpipe-plastic(polyethylene) electrofusion
F1055 of p p
ASTM specification design requirements 2.13 markings on plastic pipe and components
F2897
atmospheric corrosion definition 1.1 glossary
atmospheric corrosion patrollinq 5.15general;methods of patrolling
atmospheric corrosion can't get in procedures 5.20 can't gain entry/can't find
atmospheric corrosion inspection requirements 5.20 inspection requirements
atmospheric corrosion recordkeeping 5.20 recordkee in
atmospheric corrosion identify,OQ task 4.31 App A 221.110.020
atmospheric pressure elevation table 2.22 elevation compensation
atmospheric pressure table 2.22 elevation compensation
table
authority having definition 1.1 glossary
urisdiction
automatic ignition definition 1.1 glossary
AutoSol Enterprise data collection 2.25 data path and uses
Services AES
Avista First Responder restoration of service GESH 5 steps for restoration of service
Avista major gas
incident report form reporting an emergency GESH 13 responses and notifications
#N-2566
Avista requested
meter test in GESH 16 customer requested meter test
con'unction with HBI
Avista's requirements gas meter room installations 2.22 inside meter sets
Avista-side leak and above ground leakage GESH 2 above ground leakage
odor investigation
Avista-side leak and facilities covered GESH 2 facilities covered
odor investigation
Avista-side leak and follow-up inspections for GESH 2 follow-up inspections for residual gas
odor investigation residual gas
Avista-side leak and gas present in sewer or duct GESH 2 gas present in sewer or duct system
odor investigation system
Avista-side leak and investigation of gas meter GESH 2 leak and odor investigation at gas meter location
odor investigation location
Avista-side leak and leak repair and residual gas GESH 2 leak repair and residual gas checks
odor investigation checks
Avista-side leak and methods of detection GESH 2 methods of detection
odor investigation
Avista-side leak and pinpointing/centering GESH 2 pinpointing centering
odor investigation
Avista-side leak and reinstating a damaged service GESH 2 reinstating a damaged service line
odor investigation line
Avista-side leak and service line leak survey GESH 2 service line leak survey
odor investigation
Avista-side leak and underground leak GESH 2 undeground leak determination
odor investigation determination
Avista-side leak and underground leak investigation GESH 2 underground leak investigation
odor investigation
Avista-side leak and venting underground leakage GESH 2 underground leak investigation
odor investigation
Avista-side leak OQ task 4.31 App A 221.020.040
investigation-Inside
3

Subject Details Sec/Section Subsection
Avista-side leak OQ task 4.31 App A 221.020.035
investigation-outside
backfill definition 1.1 glossary
backfill clearances 3.15 clearances-steel and PE pipelines
backfill compaction 3.15 compaction
backfill cover 3.15 cover
backfill land disturbance requirements 3.43 general
backfill OQ task 4.31 App A 221.120.120
backfill CP definition 1.1 glossary
ball valves design 2.14 valve types
ball valves maintenance 5.13 steel ball valves;gear valves;valve turns;steel ball valves;
steel gear valves; poly valves
bar hole definition 1.1 glossary
bar hole probe gas incident field investigation GESH 17 responses and notifications
bar hole survey definition 1.1 alossary
5.11 -follow-up inspections for residual gas; 5.11 -re-
classification of leaks;5.11 -recordkeeping and reporting;
bar holing leak survey 5.11,GESH 2 GESH 2-investigation at above ground avista facilities;
GESH 2-underground leak investigation;GESH 2-
service line leak survey; GESH 2-blowing gas,odor calls,
and damage events-recording information
bar holing emergency response, GESH 2 external ppm survey
underground leak
barrel(canning) 3.32general;canning(barreling)
barricades requirement for 2.22 meter set protection and barricades
barricades drawing,standard 2.24 A-36712,Appendix A
barricades patrols to identify missing 5.20 inspection requirements
barricades
bascom turner maintenance 5.19 maintenance frequencies
bascom turner gas equipent description 5.11 leak detection instruments
explorers
bascom turner gas equipent description 5.11 leak detection instruments
rovers
bead, melt 3.23 butt fusion procedures
bedding definition 1.1 glossary
bell hole definition 1.1 glossary
bell holes damage prevention 4.13 on-site inspectionsgeneral
bell prover 2.22 prover calibration interval
bending steel pipe 3.12 pipe bends
bending PE(polyethylene)pi e 3.13 field bending
bending OQ task 4.31 App A 221.120.085
big fink installation drawing B-34947 3.42 B-34947
big fink installing leads&stations, OQ 4.31 App A 221.110.035
task
biomimetic detector GESH 3 carbon monoxide detector alarms
blasting 4.13 blasting near pipelines
bleed off steel pipe 3.17 bleed off of steel pipe
bleed off PE(polyethylene)pi e 3.17 bleed off of plastic pipe
blind flange definition 1.1 alossary
block valve definition 1.1 glossary
blowdown definition 1.1 glossary
blowdown 3.17,5.12 3.17-venting and blow down;5.12-maintenance of blow
down facilities
blowing as emergency requests GESH 1 priority 1 -emergencv re uests
blowing gas&odor GESH 2,4 GESH 2-blowing gas,odor calls and damage events;
calls GESH 4-throughout
blowing gas,odor calls general GESH 2 blowing gas,odor calls and damage events
and damage events
boilers GESH 12
bolt-on tees PE(polyethylene)pipe 3.25 procedure for installing approved bolt-on type mechanical
tees with spigot and sleeve type outlet connection,
bond definition 1.1 glossary
boot type seals 3.42 installing e carrier pipe in casing
boring tracer wire continuity 3.13 tracer wire
boring cover,depth of 3.19 depth of cover
boring discharge mitigation plan 3.19 HDD discharge mitigation plan
boring path selection 3.19 HDD bore path
boring ermits 3.19 permits
4

Subject Details Sec/Section Subsection
borin pilot hole alignment 3.19 pilot hole alignment
boring pullback 3.19 pullback
boring radius of curvature, PE 3.19 pe-min. radius of curvature
(polyethylene)
boring radius of curvature,steel 3.19 steel-min radius of curvature
boring reaming 3.19 reamin
boring tracking boring tools 3.19 tracking and potholing while crossing utilities
boring foreign utilities 3.19,4.13 3.19-tracking and potholing;4.13-on-site inspections-
eneral
boring potholing 3.19,4.13 3.19-tracking and potholing;4.13-on-site inspections-
eneral
bourdon tube pressure gauges 5.21 types of pressure gauges
boxes,valve 5.13 maintaning valve boxes; maintenance frequencies-valves
branch services excess flow valves 3.16 branch(split)service
branch services excess flow valves 3.16 branch(split)service
illustration(s)
break away in 3.13,3.19 3.13-break-away in or weak link;3.19pullback
breakaway fitting general 2.22 breakawa fittin
breakaway fitting acceptable breakaway fitting 2.22 breakaway fitting
applications table
bridges PE installations 2.13 aboveground lastic i e
bridges design of 2.15 throughout
bridges casings 2.15 casings
bridges corrosion protection 2.15 corrosion protection
bridges design requirements 2.15 design requirements
bridges permits 2.15 permits
bridges pipe installation on 2.15 pipeline installation
bridges supports for 2.15 supports
bridges 2.15 throughout
bridges seismic supports for 2.15 seismic supports
broken locks tampering of meter GESH 15 broken locks
btu definition 1.1 glossary
building definition 1.1 alossary
buildings of public
assemblyleak survey5.11 annual surveys
burner adjustments GESH 10 service to appliances; main burner;pilots; ignition
burner adjustments table of gas input to burner GESH Tables GESH Tables
business district definition 1.1 alossary
business district leak
5.11 annual surveys
survey
butt fusion definition 1.1 glossary
butt fusion procedure cooling times 3.23 butt fusion procedures
bypass definition 1.1,GESH A 1.1 -alossary
bypass definition 1.1 glossary
bypass customer definition 1.1 glossary
bypass odorizers usage 2.52 odorizer types
by-pass odorizers maintenance 5.23 by-pass odorizers
5.12-procedure for regulator station and meter set
bypassing procedure 5.12,GESH 9 bypassing; GESH 9-bypassing procedures-grunsky
meter chan in device
bypassing procedure-
grunsky meter bypassing procedures GESH 9 bypassing procedures
changing device
bypassing procedure-
grunsky meter general information GESH 9 general information
changing device
bvpassinq station procedure 5.12 procedure for regulator station and meter set bypassing
Cadweld procedure steel pipe process 3.12 cadweld procedure
cadweld procedure cathodic protection 3.12,3.13 3.12-cadweldprocedure;3.13-tracer wire
cadweldin 3.22 non-destructive pre-inspection
calibration definition 1.1 glossary
calibration DTEX 4.18 calibration of instrument
calibration odorization sampling 4.18 calibration of instrument
equipment
calibration FI units 5.11 leak detection instruments
calibration leak survey equipment 5.11 leak detection instruments
calibration cathodic instruments 5.14 calibration of equipment;cp equipment accuracy check
calibration electrodes for CP instruments 5.14 CP equipment accuracy check
5

Subject Details Sec/Section Subsection
calibration voltmeters 5.14 calibration of equipment;cp equipment accuracy check
calibration pressure gauges 5.21general;types of pressure recorders
calibration pressure recorders 5.21 general;types of pressure recorders;field operating
guidelines for pressure recorders
calibration CGIs 5.11, GESH 17 5.11 -leak detection instruments
call-out list definition 1.1 glossary
can barrel definition 1.1 glossary
canning(barrelling) 3.32general;cannin (barreling)
can't gain entry forced entry GESH 2 forced entry
can't gain entry as control room notification GESH 2 gas control room notification
can't qain entry remaining on the job GESH 2 remaininq on the job
can't gain entry temporary postponement of repairs GESH 2 temporary postponement of repairs
can't gain entry high bill investigation GESH 16 can't gain entry
procedures
can't gain entry leak investigation GESH 2 can't gain entry procedures
procedures
can't gain entry carbon monoxide orders GESH 3 can't gain entry
procedures
can't gain entry shutdown and restoration of GESH 5 meters turned on by other than avista;restoration of
procedures service service-logisticalphase;steps for restoration of service
can't gain entry turn off orders GESH 7 GESH 7-meters found on by serviceman; GESH 7-can't
procedures ,8 gain entry situations;GESH 8-can't gain entry procedures
can't gain entry meter change or removal GESH 9 inaccessible meters;customer not home-inside set;
procedures customer not home-outside set
can't gain entry/can't atmospheric corrosion patrols 5.20 throughout
find procedures
can't gain entry/can't
find CGE/CF 5.11 can't gain entry/can't find
can't-gain-entry notice definition 1.1 glossary
capacity tables meter,diaphragm 2.24 diaphragm meters
capacity tables meter, rotary 2.24 rotary meters
capacity tables meter,turbine 2.24 turbine meters
capacity tables regulator,elevated pressure 2.24 Appendix A
capacity tables regulator,farm tap 2.24 farm tap regulator
capacity tables regulator,service 2.24 Appendix A
capacity tables relief valve 2.24 relief valve capacities
capacity tables pipe,customer downstream 3.16 pipe sizes and capacities downstream of meter
capacity tables pipe, PE 3.16 service pipe capacities; pipe sizes and capacities
downstream of meter
capacity tables pipe,service line 3.16 service pipe capacities
capacity tables pipe,steel 3.16 service pipe capacities; pipe sizes and capacities
downstream of meter
car hit meter priority 1 emergency requests GESH 1 priority 1 emergency requests
carbon monoxide definition 1.1 alossary
carbon monoxide(CO) definition 1.1 glossary
detector
carbon monoxide call priority 1 emergency requests GESH 1 priority 1 -emergency requests;emergency instructions;
notifying emergency services 911
carbon monoxide alarm procedures GESH 3 co alarm procedures
detectors
carbon monoxide CO alarm procedures GESH 3 co alarm procedures
detectors
carbon monoxide instrument calibration GESH 3 instrument calibrations
detectors
carbon monoxide detectors types of detectors GESH 3 types of detectors
carbon monoxide UL 2034 GESH 3 UL 2034
detectors
carbon monoxide
detectors GESH 3 carbon monoxide detector alarms
carbon monoxide orders7_ GESH37 procedures for completing carbon monoxide orders
6

Subject Details Sec/Section Subsection
GESH 1 -Emergency Requests;GESH 1 -emergency
instructions;GESH 1 -notifying emergency services;
carbon monoxide GESH 3-symptoms of carbon monoxide poisoning;GESH
poisoning GESH 1,GESH 3 3-procedures for completing carbon monoxide orders;
GESH 3-carbon monoxide testing:ambient air testing;
GESH 3-notifications
carbon monoxide
testing GESH 3 carbon monoxide testing
carbon monoxide
testing:ambient air 10 ppm Rule GESH 3 10 ppm rule
testing
carbon monoxide
testing:ambient air 200 ppm Rule GESH 3 200 ppm rule
testing
carbon monoxide
testing:ambient air 35 ppm Rule GESH 3 35 ppm rule
testing
carbon monoxide
testing:ambient air GESH 3 carbon monoxide testing:ambient air testing
testing
carbon monoxide
testing:gas equipment 100 ppm Rule GESH 3 100 ppm Rule
testing
carbon monoxide
testing:gas equipment GESH 3 carbon monoxide testing;gas equipment testing
testing
carrier pipe definition 1.1 glossary
case pressures, meter 2.22 meter case pressures
casing definition 1.1 glossary
casing insulator definition 1.1 glossary
casings bridge casings 2.15 casings
casings design 3.42 design requirements
casings Fink wiring to casings drawing 3.42 B-34947
B-34947
casings highway casing drawing E- 3.42 E-33947
33947
casings insulators 3.42 installing steel carrier pipe in casing; installing pe carrier
pipe in casing
casings PE pipe within casings 3.42 installing e carrier pipe in casing
casings railroad casing drawing E- 3.42 E-33947
33947
casings sizing 3.42 casing size
casings specification 3.42 casing size
casings steel carrier pipe within casing 3.42 installing steel carrier pipe in casing
casings shorted,leak survey 5.11 special surveys
requirements
monitoring steel in steel casings; ; maintenance and
casings monitoring for CP 5.14 remediation timeframes and frequencies; Monitoring
electrical isolation of steel encased pipe
casings abandonment 5.16 casings
casings OQ task 4.31 App A 221.120.090
casings installation 3.42,4.31 App A 3.42;4.31 App A-221.120.090
cathode definition 1.1 glossary
cathode corrosion cell 2.32 corrosion cell
cathode reaction 2.32 anode and cathode reactions
cathodic field definition 1.1 glossary
cathodic instrument
calibration 5.14 calibration of equipment;cp equipment accuracy check
cathodic protection AC mitigation 2.32 AC mitigation
cathodic protection AC vs. DC 2.32 AC vs. DC
cathodic protection anode reaction 2.32 anode and cathode reactions
cathodic protection anodes stems 2.32 anodes stems
cathodic protection anode-cathode area ratio 2.32 anode-cathode area ratio
cathodic protection anode-cathode reactions, 2.32 anode and cathode reactions
chemical
cathodic protection anode-cathode separation 2.321 anode-cathode separation distance
distance
cathodic protection anodes for tracer wire 1 2.321 tracer wire
7

Subject Details Sec/Section Subsection
cathodic protection cathode reaction 2.32 anode and cathode reactions
cathodic protection change in environment 2.32 change in environment
cathodic protection current density 2.32 anode and cathode reactions
cathodic protection design 2.32 throughout
cathodic protection dissimilar environments 2.32 dissimilar environments
cathodic protection dissimilar metals 2.32 dissimilar metals
cathodic protection electrolyte resistivity 2.32 electrolyte resistivity
cathodic protection galvanic anode system 2.32 anode systems
installation
cathodic protection galvanic series 2.32 dissimilar metals
cathodic protection impressed anodes stems 2.32 anodes stems
cathodic protection impressed currents stem 2.32 impressed currents stem
cathodic protection insulation 2.32 insulation
cathodic protection metallic coatings 2.32 metallic coatings
cathodic protection non-metallic materials 2.32 nonmetallic materials
cathodic protection steel main replacement 2.32 replacing steel main
cathodic protection steel pipe replacement 2.32 replacing steel main
cathodic protection stress corrosion 2.32 replacing steel main
cathodic protection system isolation 2.32 system isolation
cathodic protection test lead color coding diagram 2.32 A-35447
cathodic protection theory of corrosion 2.32 theory of corrosion
cathodic protection tracer wire 2.32 tracer wire
cathodic protection WAC rule 2.32 design and installation
cathodic protection cadweld procedure 3.12 cadweld procedure
cathodic protection holiday 3.12 repair and patching using tape wrap
cathodic protection 'jeeping 3.12 installation in ditch
cathodic protection test leads 3.12 test leads
cathodic protection exposed steel reports 4.13 on site inspections for transmission facilities
cathodic protection steel pipe inspection reports 4.13 on-site inspections eneral
cathodic protection shorted casings, leak survey 5.11 special surveys
requirement
cathodic protection casings monitoring 5.14 monitoring steel in steel casings;shorted casings;
maintenance and remediation timeframes and frequencies
cathodic protection copper-copper sulfate half cell 5.14 cathodic protection criteria
cathodic protection critical bonds 5.14 monitoring critical bonds and diodes; maintenance and
remediation timeframes and frequencies
cathodic protection diode 5.14 monitoring critical bonds and diodes; maintenance and
remediation timeframes and frequencies
cathodic protection electrode 5.14 structure-to-electrol e potential(pipe-to soilpotential)
cathodic protection instrument calibration 5.14 calibration of equipment
cathodic protection internal corrosion control 5.14 internal corrosion control
cathodic protection isolated main less than 100 ft 5.14 monitoring isolated mains less than 100 ft or service lines;
maintenance and remediation timeframes and frequencies
cathodic protection isolated services 5.14 isolated steel risers;isolated steel services; maintenance
and remediation timeframes and frequencies
cathodic protection maintenance 5.14 throughout
cathodic protection monitoring 5.14 cathodic protection monitoring;
cathodic protection pipe-to-soil procedure 5.14 structure-to-electrol e potential(pipe-to soilpotential)
cathodic protection recordkeeping 5.14 recordkee in
cathodic protection rectifier monitoring 5.14 monitorinq rectifiers
cathodic protection remediation 5.14 maintenance and remediation timeframes and frequencies
cathodic protection shorted casings,CP 5.14 maintenance and remediation timeframes and frequencies
remediation
cathodic protection stray current 5.14 detecting stray current
cathodic protection technician 5.14 throughout
cathodic protection corrosion cell 2.32,5.14 2.32-corrosion cell;5.14-internal corrosion control
cathodic protection installing CP leads&stations, 4.31 App A 221.110.035
OQ task
3.16-service risers;4.13-on-site inspections-general;
4.13-on site inspections for transmission facilities;4.31
cathodic protection pipe-to-soil 3.16,4.13,4.31 App App A-221.110.055;5.11 -structure-to-electrolye
A,5.11,5.14 potential(pipe-to soil potential); 5.14-cathodic protection
maintenance;5.14-structure-to-electrolye potential(pipe-
to-soil otential
cathodic protection
CP definition 1.1 glossary
cathodic protection continuity,maintaining 3.16 steel service replacement
CP
8

Subject Details Sec/Section Subsection
caution toe steel pipe 3.12 caution tape
caution toe PE(polyethylene)pipa 3.13 caution tape
caution toe PE installations 3.13 caution tape
caution toe conduit marking 3.42 conduit
certification card steel weld 3.22 welder certification card
certification card PE(polyethylene)pi e joining 3.23 pipe joining certification record
chain of custody GESH 17 chain of custody; removal of company equipment
changing meters gas equipment service GESH 9 gas equipment service
changing meters handling and transporting GESH 9 handling and transporting meters
meters
chanaina meters house piping leak test GESH 9 house piping leak test
changing meters installing bypasses GESH 9 installing bypasses
changing meters new gaskets GESH 9 new gaskets
changing meters overpressure protection GESH 9 overpressure protection
changing meters pressure check GESH 9 pressure check
changing meters purging GESH 9 Durging
chanaina meters rebuilding to standard GESH 9 rebuilding to standard
charges for service GESH 11 throughout
chart recorders calibration and inspection 5.12 chart recorders and telemet
chart recorders 5.21 types of pressure recorders
chimney effect definition 1.1 glossary
chute bending table 3.13 plowing and Dlanting
citV qate definition 1.1 glossary
removal of company equipment;tagging and transporting
claims gas incident field investigation GESH 17 meters;inspection and testing of meters;testing warning;
gas incident field checklist; lightning strike/electric arcing
field checklist
clam 'oinin repair procedure 3.24 repair clam 'oinina Drocedure
clamps,repair 3.32 repair clamps and sleeves
clamps,repair Adams 3.35 throughout
class location definition 1.1 glossary
class locations considerations for steel design 2.12 class location considerations
class locations SMYS classes by SMYS 2.12 class location considerations
class locations boundaries 4.16 class location boundaries
class locations changes in class location 4.16 change in class location
classifying leaks 5.11, GESH 2 5.11 -classifying leaks; GESH 2-classifying leaks
classifying leaks grade 1 leaks 5.11,GESH 2 5.11 -grade 1 leaks; GESH 2-grade 1 leaks
classifying leaks grade 2 leaks GESH 2 5.11-grade 2 leak; GESH 2-grade 2 leak
classifying leaks grade 2A leaks GESH 2 5.11 -grade 2A leak;GESH 2-qrade 2A leak
classifying leaks grade 3 leaks GESH 2 5.11 -grade 3 leaks; GESH 2-grade 3 leaks
classifying leaks hazardous mechanical fitting GESH 2 classifying leaks
failures
classifying leaks leak failure cause definitions GESH 2 classifying leaks
classifying leaks re-classification GESH 2 classifying leaks
clean water act requirements 3.43general;storm water permitting requirements
clearances meter 2.22 3 foot rule; 10 foot rule
clearances joint ditch design 3.15 clearances-steel and PE pipelines
clearances PE(polyethylene)pi e 3.15 clearances-steel and PE pipelines
clearances sewer mains 3.15 clearances-steel and PE pipelines
clearances steel pipe 3.15 clearances-steel and PE pipelines
clearances water mains 3.15 clearances-steel and PE pipelines
clearances OQ task 4.31 App A 221.120.120
clock interval survey definition 1.1 glossary
clock test definition 1.1 glossary
2.22-example for computing corrected flow;GESH 2-
clock test(clocking), 2.22, GESH 2,3, 12, can't gain entry procedures;GESH 2-temporary
meter 17 postponement of repairs; GESH 3-can't gain entry; GESH
3-100 ppm rule; GESH 12-safety inpection report; GESH
17-lightning strike/electric arcing field checklist
clocking input definition 1.1 glossary
closing meters
(shutdown and GESH 5 closing meters
restorationprocedure)
CO detectors alarm procedures GESH 3 co alarm procedures
CO detectors I I GESH 31 carbon monoxide detector alarms
CO orders GESH 31 procedures for completing carbon monoxide orders
CO poisoning GESH 3 symptoms of carbon monoxide poisoning; initial
determination;200 ppm rule;notifications
9

Subject Details Sec/Section Subsection
coating definition 1.1glossa
coating for steel pipe thickness 3.12 liquid epoxy coating
coating for steel pipe voltage settings for'ee in 3.12 electrical inspection of pipeline coatings 'ee in
coating for steel pipe maintenance,OQ task 4.31 App A 221.110.025
coating for steel pipe atmospheric coating maint., 4.31 App A 221.110.030
OQ task
coating resistance definition 1.1 glossary
Code 3-2"standard Drawing E-37197 2.24 Appendix A
meter set
code 5 definition 1.1 glossary
code 5 odor callspriority GESH 1 priority 1 -emergencv requests
responding employee qualifications; underground leak
code 5(odor calls) procedures GESH 2 investigation; blowing gas,odor calls,and damage events-
recording information
code 9 definition 1.1 glossary
code 9(blowing aspriority GESH 1 priority 1 -emergency requests
code 9(blowing asprocedures GESH 4 throou hout
code numbers
dis atchin GESH 1 priority 1 -emergency requests; priority 2 requests
cold applied tape wrap steel pipe 3.12 tape wrap
cold weather action
GESH 13 cold weather action plan
Ian
cold weather fusion 3.23 cold weather fusion
collection turn-on GESH 7 collection turn-on order
combination control definition 1.1 glossary
combination valve definition 1.1 glossary
combustible gas definition 1.1 glossary
indicator CGI
combustible gas Bascom Turner 5.19 maintenance frequencies
indicator CGI
combustible gas calibrations 5.19 general;calibration procedures
indicator CGI
combustible gas leak survey 5.19 general;calibration procedures
indicator CGI
combustible gas maintenance 5.19 general; maintenance frequencies
indicator CGI
combustible gas recordkeeping 5.19 recordkeeping
indicator CGI
combustible gas gas incident field investigation GESH 17 responses and notifications;gas incident field checklist
indicator CGI
combustible gas investigation at above ground facilities; underground leak
indicator CGI bar hole survey GESH 2 determination;pinpointing/centerin
combustion air definition 1.1 glossary
combustion and services to be performed GESH 10 combustion and ventilation air
ventilation air
combustion products definition 1.1 glossary
combustion turbine definition 1.1 glossary
command center definition 1.1 gloss2a
commercially
navigable waterways 5.16 commercially navigable waterways
communications 2.25 throughout
communications IP-based requirements 2.25 communications
compaction backfilling 3.15 compaction
compaction tamping equipment 3.15 compaction
compensation elevation 2.22 elevation compensation
compensation pressure 2.22 pressure compensation
compensation temperature 2.22 temperature compensation
complete records definition 1.1 glossary
compressed natural definition 1.1 glossary
as CNG
compressed natural relief and safety shut-off testing; portable cng trailer
gas(CNG) maintenance 5.12 maintenance; maintenance frequencies; procedure for
testing relief valves with nitrogen or bottled cnq.
concentration cell definition 1.1 glossary
conductor definition 1.1 glossary
conduit definition 1.1 glossary
conduit Icolor 3.421 conduit
conduit linstallation 3.421 conduit
10

Subject Details Sec/Section Subsection
conduit sealing end or ends 3.16,3.42 3.16-service lines into buildings;3.42-conduit
confined space definition 1.1 glossary
confirmed discovery definition 1.1 glossary
construction defects 4.14 WUTC construction defects and material failures report
report for WUTC
construction office definition 1.1 glossary
contaminants joining, PE(polyethylene)pipe
butt 3.23 heating tool
continuing surveillance 4.11 throughout
control definition 1.1 glossary
control lines line requirements 2.23 control and sensinq lines
control room definition 1.1 glossary
controlled-density general 3.15 controlled-density backfill
backfill CDF
controller definition 1.1 glossary
cooling times butt fusion 3.23 butt fusion procedures
cooling times electrofusion 3.24 fusion/coolinq times table
copper fuel gas piping GESH 12 copper tubing
copper tubing special concerns GESH 12 copper tubing
copper-copper sulfate definition 1.1 glossary
electrode
coriolis meters general 2.22 meter types
coriolis meters gate stations 2.25 qate stations
corrected flow formula 2.22 computing corrected flows
correcting device definition 1.1 glossary
correcting device computing corrected flows 2.22 example for computing corrected flow
correction code definition 1.1 glossary
corrosion definition 1.1 glossary
corrosion erosion-corrosion 5.14 internal corrosion control
corrosion corrosion cell 2.32,5.14 2.32-corrosion cell;5.14-internal corrosion control
corrosion identifying corrosion on buried 4.31 App A 221.110.015
pipe,OQ task
corrosion atmospheric, identifying,OQ 4.31 App A 221.110.020
task
corrosion leak failure cause 5.11,GESH 2 5.11 -leak failure cause definitions;GESH 2-leak failure
cause definitions
corrosion cell definition 1.1 glossary
corrosion protection bridges 2.15 corrosion protection
corrugated stainless
see CSST
steel tubing
corrugated stainless
steel tubin CSST GESH 12 corrugated stainless steel tubing
coupling definition 1.1 glossary
coupling joining PE(polyethylene)pipe 3.24 standard coupling and endcap Joining procedures
procedure
coupon retention steel pipe 3.12 pipe coupon retention procedures
procedures
cover PE(polyethylene)pi e 3.15 cover
cover services 3.15 cover
cover steel mains,high pressure 3.15 compaction
cover requirements 3.15 cover
cover boring 3.19 depth of cover
cover OQ task 4.31 App A 221.120.120
covered task definition 1.1 glossary
crew activity reporting
4.19 throughout
in Washington
critical bonds 5.14 monitoring critical bonds and diodes; maintenance and
remediation timeframes and frequencies
cross bore 1.1,3.19 3.19-tracking and potholin
cross bore definition 1.1 glossary
cross fusion PE(polyethylene)pi e 3.23 compatibility/cross fusions
curb valve definition 1.1 glossary
curb valve tee disabling 5.16 disabling a curb valve tee
current definition 1.1 alossary
current densitV Idefinition 11.1 glossary
curtailment Idefinition 1.1 glossary
customer Idefinition 1.11 glossary
11

Subject Details Sec/Section Subsection
customer charges for
GESH 11 throughout
service
customer owned
4.22 throughout
service lines
customer piping see downstream
Di Dina
customer project coordinator role GESH 13 pre-construction emergency planning for road projects
customer project
coordinator CPC) definition 1.1 glossary
customer project 2.22,GESH 6,GESH 2.22-Industrial Sets&elevated pressure sets;GESH 6,
coordinator(CPC) 13 Required Service Information,GESH 13, Pre-Construction
Emergency Planning for Road Promects
customer requested
meter test GESH 16 customer requested meter test
customer services definition 1.1 glossary
department
customer-side leak external ppm survey GESH 2 external ppm survey
and odor investigation
customer-side leak facilities covered GESH 2 facilities covered
and odor investigation
customer-side leak gas check prior to entry GESH 2 gas checked prior to entry
and odor investigation
customer-side leak procedures upon entry GESH 2 procedures upon entry
and odor investigation
damage definition 1.1 glossary
damage prevention color codes 4.13 APWA uniform color codes for marking
damage revention dig laws 4.13 locating and marking as facilities
damage prevention inspection,on site 4.13 on-site inspections-general
damage prevention One Call 4.13 one call notification system; requests for locates through
one call;avista damage to other facility operators
damage prevention public awareness program 4.13 public awareness plan
damage prevention recordkeeping 4.13 recordkeeping of locates;on site inspections for
transmission facilities
damage prevention tolerance zone 4.13 tolerance zone
damage prevention statistics report for WUTC 4.14 WUTC construction defects and material failures report
damage prevention OQ task 4.31 App A 221.120.070
damaged meter sets GESH 9, 15 GESH 9-damage to meter sets; GESH 15-typical gas
diversion methods
damaged pipe 3.14,3.32 3.14- re-construction inspection,3.32-throughout
3.18-reinstating service;3.32-leak repair and residual
damaged service lines 3.18,3.32,3.33,5.11 gas checks;3.32-service lines;3.33-damage to service
lines;5.11 -reinstating a damaged service line; 5.11 -
service line leak survey;5.11 -special surveys
data collection measurement table 2.25 table for detailed reference to quantities measured
data collection piping and weld data collection 3.12 piping and weld data collection
deflection definition 1.1 alossary
deflection stress steel pipe(design formula 2.12 deflection and bending stress
degree day(heating
degree da -HDD definition 1.1 glossary
dekatherm definition 1.1 glossary
delayed ignition definition 1.1 alossary
delayed ignition GESH 1 priority 1 -emergency requests
delivery pressure definition 1.1 glossary
meter room installation;multiple meters; meter set design;
delivery pressure 2.22 gas meter information sheets; industrial sets and elevated
pressure sets
dents steel pipe 3.32 throu hout
depth of cover waterways 2.13 plastic pipe under waterways
depth of cover 3.15,3.19 3.15-cover;3.15-shoring and excavating safety;3.19-
depth of cover
design factor definition 1.1 glossary
design formula for
steel i e 2.12 design formula for steel pipe
desi n oressure definition 1.1 glossary
detection of other 5.11,GESH 2 5.11 -detection of other combustible gases; GESH 2-
combustible aces detection of other combustible gases
12

Subject Details Sec/Section Subsection
detecto-pak infrared
detector DP-IR 5.11 leak detection instruments
diaphragm meter capacity 2.24 diaphragm meters
diaphragm meter Drawing A-36712 2.24 Appendix A
barricade detail
diaphragm meters meter capacity 2.24 diaphragm meters
dielectric definition 1.1 glossary
dig-in procedures
checklist GESH 4 dig-in procedures checklist
digital pressure gauge general 5.21 types of pressure gauges
DIMP identified leak survey 5.11 DIMP identified surveys
surveys
direct and observe definition 1.1 glossary
direct-vent appliance,
proximityto meters 2.22 3 foot rule
discharge mitigation
3.19 HDD discharge mitigation plan
Ian
discharge velocity purging 3.17 injection rate
dispatchinq general GESH 1 general
dispatching out of area odor calls GESH 1 out of area odor calls
dispatching riorit of service requests GESH 1 priority of service requests
dispatching service requests GESH 1 priority of service requests
dispatching GESH 1 GESH 1 -throughout
dissimilar metals 2.32 dissimilar metals
distribution definition 1.1 glossary
distribution center definition 1.1 glossary
distribution integrity
management program overview 4.42 general
DIMP
distributions stem definition 1.1 glossary
regulation of intermediate pressure to service pressure;
distribution system 2.23 regulation of high pressure to service pressure;capacity;
telemetering and pressure recorders
district regulator
definition 1.1 glossary
station
district regulator
design 2.24 Appendix A
station
district regulator maintenance 512 district regulator stations;district regulator station relief
station . capacity review;annual regulator station maintenance
district regulator relief capacity review 5.12 district regulator station relief capacity review
station
diversion of service reporting diversion of service GESH 15 reporting diversion of service
diversion of service general GESH 15 throughout
doors, proximity to gas 2.22 meter set location protection and barricades; 3 foot rule;
meters alcove installation
double ended procedure for installing approved spigot and sleeve type
couplings joining of pipe 3.25 couplings and fittings using the QRP-100 quick ratchet
press tool
double submerged-arc definition 1.1 glossary
welded pipe DSAW
downstream customer insulation 2.22 insulating downstream customer piping
piping
downstream piping definition 1.1 glossary
downstream piping notification of customer 4.22 required information;one-time notification
res onsibilit
downstream piping appliances GESH 10 service to appliances;downstream piping
downstream piping combustion and ventilation GESH 10 service to appliances;combustion and ventilation air
downstream piping downstream piping GESH 10 service to appliances;downstream piping
downstream piping propane conversions GESH 10 conversion vs configuration of equipment
downstream piping safety inspection,appliances GESH 12 safety inspection report;inspection procedures
and house piping
drawings A-34175, pipe support detail 2.24 Appendix A
drawings A-34735, inserting service 3.16 A-34735
drawings A-35208, residential meter std, 2.24 Appendix A
int pressure
drawings A-35447,cathodic leads color 3.12 A-35447
coding
13

Subject Details Sec/Section Subsection
drawings A-35776,taping tracer wire to 3.13 A-35776
pipe detail
drawings A-36275, residential meter 2.22 A-36275
placement
drawings A-36277,tracer wire& 3.13 A-36277
nuts/lugs
drawings A-36712, barricade detail 2.24 Appendix A
drawings A-37102,2 psig residential 2.24 Appendix A
meter
A-37169, 1/2"&3/4"PE
drawings service and EFV off of a steel 3.16 A-37169
IP main
drawings A-37103,'bandy cane"riser 2.24 Appendix A
component
drawings A-38315s1,customer supplied 3.15 A-38315
ditch for meter relocation
A-38315s2, PE natural gas
drawings service,customer provided 3.15 A-38315s2
trench detail
drawings A-38315s3,natural gas main 3.15 A-38315s3
trench detail
drawings A-38315s4,natural gas main 3.15 A-38315s4
clearances
drawings B-33325, rotary meters, 2.24 Appendix A
welded components,
drawings B-34947,casings, Fink 3.42 B-34947
attachment
drawings B-35207, residential meter 2.24 Appendix A
standard, high pressure
drawings B-35785, rotary meters,the 2.24 Appendix A
components,
drawings B-36269,snow areas,service 3.16 B-36269
lines
drawings B-36271,fink installation 2.32 B-36271
details
B-38205, rotary meters(2000,
drawings 3000,3500,5000,7000, 2.24 Appendix A
11000
drawings B-39147, PE test stations& 3.13 B-39147
tracer wire
drawings C-35209,diaphragm meter, 2.24 Appendix A
small
drawings E-33947,casings, under 3.42 E-33947
highways and RR
drawings E-33952,district reg.station, 2.24 Appendix A
single run 2"x 4"
drawings E-35158,district reg.station, 2.24 Appendix A
dual run,2"x 4"
drawings E-35783,district reg.station, 2.24 Appendix A
single run 4"x 6"
drawings E-37197, meter set 2" 2.24 Appendix A
drawings E-37842,farm to 2" 2.24 Appendix A
drawings E-37970,farm tap 2.24 Appendix A
drawings L-36082,fencing guidelines 2.24 Appendix A
drawings B-36271,tracer wire 2.13,3.12 2.13 tracer wire;3.12 Pipe Installation-Steel Mains
Drisco Iex 3.23 butt fusion procedures
drug and alcohol
screening GESH 2 responding employee qualifications
dry as definition 1.1 glossary
dry line pipe 3.12,3.13,3.18 3.12-dry line installations;3.13-dry line installations;3.18
-dry line pipe
dry line pipe definition 1.1 qlossary
dry lines transmission lines 3.12 dry line installations
dry lines transmission lines 3.13 dry line installations
dry lines pressure testing 3.18 dry line pipe
DTEX 4.18 YZ odorometer DTEX
dual run district Drawing E-35158 2.24 Appendix A
regulator
14

Subject Details Sec/Section Subsection
dunnage definition 1.1 glossary
dunnage steel pipe,stringing 3.12 stringing
earthquake valves meters 2.22 earthquake valves
elastomer packing permanent repair sleeves 3.32Ageneral;storage
elbows steel pipe 3.12 mitering/segmentinq elbows
electric meters,
proximity to gas 2.22 meter set location protection and barricades;3 foot rule
meters
electric resistance definition 1.1 glossary
welded pipe ERW
electrode definition 1.1 glossary
electrode(welding) 3.22 throughout
electrofusion 3.24 throughout
electrolysis definition 1.1 glossary
electrolyte definition 1.1 glossary
electrolyte resistivity of 2.32 electrol to resistivit
electro-negative definition 1.1 glossary
electronic ignition definition 1.1 glossary
electronic pressure distribution system 2.25 general
recorder
elevated delivery definition 1.1 glossary
pressure
elevated delivery regulator capacities,elevated 2.24 meter set regulators(based on 5 psig inlet)
ressure pressure
elevated delivery maint.of elevated pressure 5.12 general maintence of all service pressures;maintenance of
pressure sets elevated service accounts
elevated service maintenance 5.12 general maintence of all service pressures;maintenance of
pressure accounts elevated service accounts
elevation atmospheric pressure table 2.22 elevation compensation
elevation elevation affect on pressure 2.22 elevation compensation
compensation
elevation formula 2.22 elevation compensation
compensation factor
emerency location priority 2 requests GESH 1 priority 2 requests
requests
emergency definition 1.1 glossary
emergency gas escaping inside GESH 1 emergency instructions
instructions
emergency gas escaping outside GESH 1 emergency instructions
instructions
emergency locates 4.13 requesting emergency locates
emergency operating definition 1.1 glossary
Ian EOP
emergency planning
worksheet GESH 5 general;emergency planning worksheet
emergency planning,
training,and incident curtailment rules GESH 13 curtailment rules
notification
emergency planning, incident review for control
training,and incident room interrelation GESH 13 incident review for control room interrelation
notification
emergency planning,
training,and incident official incident notification GESH 13 official incident notification
notification
emergency planning, pre-construction emergency
training,and incident planning for road projects GESH 13 pre-construction emergency planning for road projects
notification
emergency planning, available resources for
training,and incident emergency call out GESH 13 available resources for emergency call out
notification
emergency planning,
training,and incident cold weather action plan GESH 13 cold weather action plan
notification
emergency planning, communication with public
training,and incident officials GESH 13 communication with public officials
notification
15

Subject Details Sec/Section Subsection
emergency planning,
training,and incident emergency evaluation GESH 13 emergency evaluation
notification
emergency planning, emergency shutdown and
training,and incident restoration GESH 13 emergency shutdown and restoration
notification
emergency planning,
training,and incident emergency training GESH 13 emergency training
notification
emergency planning, EOP Plan and response to
training,and incident GESH 13 EOP Plan and response to emergencies
notification emergencies
emergency planning,
training,and incident incident field investigation GESH 13 incident field investigation
notification
emergency planning,
training,and incident local emergency manuals GESH 13 local emergency manuals
notification
emergency planning,
training,and incident material failure GESH 13 material failure
notification
emergency planning,
training,and incident mock emergency drills GESH 13 mock emergency drills
notification
emergency planning,
training,and incident mutual assistance GESH 13 mutual assistance
notification
emergency planning,
training,and incident notice of events GESH 13 notice of events
notification
emergency planning,
training,and incident post incident evaluations GESH 13 post incident evaluations
notification
emergency planning,
training,and incident responding to pressure alarms GESH 13 responding to pressure alarms
notification
emergency planning,
training,and incident review emergency activities GESH 13 review emergency activities
notification
emergency planning,
training,and incident snow action plan GESH 13 snow action plan
notification
emergency planning,
training,and incident general GESH 13 throughout
notification
emergency
procedures-blowing required truck tools and
GESH 4 required truck tools and supplies
or uncontrolled supplies
escaping natural gas
emergency
procedures-blowing safety equipment GESH 4 safety equipment
or uncontrolled
escaping natural gas
emergency
procedures-blowing
GESH 4 throughout
or uncontrolled
escaping natural gas
emergency response-- OQ task 4.31 App A 221.020.035
leak investigation
emergency services definition 1.1 glossary
emergency shutdown definition 1.1 glossary
emergency shutdown
and restoration GESH 5, 13 GESH 5, GESH 13 throughout
emergency valve definition 1.1 glossary
emergency valves criteria for determining 2.14 emergency curb valves
employee definition 1.1 glossary
encoder, receiver, definition 1.1 glossary
transmitter ERT
16

Subject Details Sec/Section Subsection
entirely replaced
onshore transmission definition 1.1 glossary
pipeline segment:A
EOP plan response to emergencies GESH 13 EOP plan and response to emergencies
EOP plan and response to emergencies; local emergency
EOP plan GESH 13 manuals;emergency training; pre-construction emergency
planning for road projects
EOP valves definition 1.1 glossary
EOP zone tying together 2.14 tying EOP zones together
EOP zone shutdown and restoration GESH 5 EOP zone shut down; pressurization;emergency planning
worksheet
eDoxv coatina 3.12 liquid epoxy coating
equipment, leak failure 5.11,GESH 2 5.11 -leak failure cause definitions
cause
erosion definition 1.1 glossary
ERT installation GESH 6 installation of meters, ERTs and regulators
ERT configuration GESH 6 meter ERT configurations
evacuation definition 1.1 glossary
evacuation of GESH 4 evacuation procedures
evacuation procedures GESH 4 evacuation procedures
evaluation definition 1.1 glossary
evaluation guidelines,
OO 4.31 App B 4.31 App B-throughout
evaluator definition 1.1 glossary
excavation damages photography requirements GESH 2 excavation damages(leak or no leak)
leak or no leak
excavation damages
leak or no leak GESH 2 excavation damages(leak or no leak)
excavation,leak 5.11, GESH 2 5.11 -leak failure cause definitions;GESH 2-leak failure
failure cause cause definitions
exception for safety related condition r rts 4.12 exceptions to reporting safety related conditions
exceptions for markers 3.15,5.15 3.15-pipeline markers for buried pipe;5.15-exceptions
for markin
excess flow valve definition 1.1 glossary
EFV
excess flow valves performance standards 2.14 excess flow valve performance standards
EFVs
excess flow valves branch services 3.16 branch(split)service
EFVs
excess flow valves capacities 3.16 capacity of EFV
EFVs
excess flow valves coupling style 3.16 installation of excessive flow valve
EFVs
excess flow valves in-line stick style 3.16 installation of excessive flow valve
EFVs
excess flow valves installation procedures 3.16 installation of excessive flow valve
EFVs
excess flow valves maximum protected length of 3.16 capacity of EFV
EFVs service
excess flow valves minimum requirements for 3.16 capacity of EFV
EFVs
excess flow valves symbol in Avista's GIS 3.16 excess flow valves
EFVs
excess flow valves tee style 3.16 installation of excessive flow valve
EFVs
excess flow valves service tee style 3.16 installation of excessive flow valve
EFVs
excess flow valves purging through 3.17 purging services with an excess flow valve
EFVs
exhaust background odorization 4.18 threshold detection level;exhaust background evaluation
evaluation
explosive limits definition 1.1 glossary
3.32-general; 3.32-leak repair and residual gas repair;
exposed pipe report 3.32,3.44,4.13 3.44-throughout;4.13-on-site inspections-general;4.13
-on site inspections for transmission facilities
exposed pipe by priority 2 requests GESH 1 priority 2 requests
excavation
17

Subject Details Sec/Section Subsection
exposed piping
inspection report
3.44 throughout
exposed piping 3.32-general; 3.32-leak repair and residual gas checks;
inspections 3.32,3.44,4.13 3.44-throughout;4.13-on-site inspections-general;4.13
on site inspections for transmission facilities
exposed steel
see exposed piping
inspections
fabricated unit definition 1.1 glossary
fabricated unit 3.18 pressure testing for steel
facility, as definition 1.1 glossary
failure analysis 4.11 material failure
failure causes 5.11 leak failure cause definitions
farm tap design 2.24 Appendix A
farm tap regulator capacities for farm 2.24 farm tap regulator
taps
farm taps; general station inspection;farm taps and hp
farm tap maintenance 5.12 services; 10 year overhaul-diaphragm type regulators,
relief valves&pilots;maintenance frequencies
farm tap relief capacity review 5.12 farm taps;district regulator station relief ca cit review
farm tap(single definition 1.1 glossary
service farm to -ssft
fencing detail see drawings
fencing guidelines Drawing L-36082 2.24 Appendix-A
FI (flame ionization)
5.11 maintenance of instruments
units calibrations
field bend diagram 3.13 field bending
field bending PE(polyethylene)pi e 3.13 field bending
field investigation definition 1.1 glossary
field pinhole repair steel pipe 3.12 field pinhole repair
field welding 3.32A field welding instructions
fill welding steel pipe 3.32 thou hout
filter inspection 5.12 strainer/filter inspection
filters GESH 10 service to appliances;filters
finks installation drawing B-34947 3.42 B-34947
finks installing leads and stations, 4.31 App A 221.110.035
OQ task
fire department calls GESH 1 handling fire department calls
fire department calls non-gas related incidents GESH 17 non-gas related incidents
fires priority 1 emergency requests GESH 1 priority 1 -service requests
fires GESH 1 priority 1 -service requests;handling and evaluating
emergency calls; handling fire department calls
fires incident field investigation, GESH 17 gas incident field checklist
checklist
firm customers definition 1.1 glossary
fitting definition 1.1 glossary
fitting, pipe non-rated definition 1.1 glossary
fitting, rated definition 1.1 glossary
flame ionization unit definition 1.1 alossary
flange&fastener minimum requirements 2.12 flanged connections
combinations table
flanged connections 2.12 flanged connections
flaring natural gas 3.17 flaring of natural gas
flashback velocity purging 3.17 injection rate
-procedure tor installing approved compression type
service head adapters;3.25 procedure for installing
approved slip lock type service head adapters(i.e.
"perfection"type);4.31 App A-221.070.041;4.31 App A-
221.070.045;5.12-farm taps and hp services;GESH 2-
3.25,4.31 App A, meter spot check procedure; GESH 6-utilization pressure
flow and lockup test 5.12, GESH 2,6,7, test;GESH 7-service order completion;GESH 7-
9 17 utilization pressure check(inches WC);GESH 7-
utilization pressure check(2 and 5 psig);GESH 7-non-
conventional utilization pressure check;GESH 9-pressure
check; GESH 17-preliminary data collection;GESH 17-
inspection and testing of meters;GESH 17-non-gas
related incidents;GESH 17-gas incident field checklist;
flow pressure definition 1.1 glossary
18

Subject Details Sec/Section Subsection
flow rate definition 1.1 glossa
flue gases definition 1.1 glossary
follow up inspections 5.11 follow-up inspections for residual gas
force ma'eure definition 1.1 glossary
forced air definition 1.1 alossa
forced entry GESH 2 can't gain entry can't get in situations
foreign source leaks 5.11,GESH 2 5.11 -detection of other combustible gases
and odors
foreign utilities controlled-density backfill 3.15 control led-densit backfill
foreign utilities boring near 3.19,4.13 3.19-tracking and potholing;4.13-on-site inspections-
eneral
foundation vents proximity to gas meters 2.22 Drawing A-36275
full-seal clams pipe repair 3.35 adams and mueller style procedure
furnace definition 1.1 glossary
fusion 3.23 throughout
fusion pressure formula 3.23 hydraulic butt fusion
fusion-bonded epoxy jeeping voltage settings 3.12 pipeline coatings Uee in
9)FBE coatin s
fusion-bonded epoxy jeeping voltage settings 3.12 electrical inspection ofpipeline coatings Uee in
g)FBE coatings
galvanic series definition 1.1 glossary
galvanic series cathodic protection 2.32 dissimilar metals
galvanized riser 3.25 procedure for installing approved compression type service
head adapters
galvanizing casing 3.42 casing specifications
as control room gas incident field investigation GESH 17 responses and notifications
gas control room overview 4.51 throughout
management plan
as controller GESH 5 steps for restoration of service
gas diversion breaking open meter locks or GESH 15 typical gas diversion methods
seals
as diversion damaainq the meter GESH 15 typical gas diversion methods
as diversion illegal meter bypass GESH 15 typical gas diversion methods
as diversion index tampering GESH 15 typical gas diversion methods
gas diversion obscuring meter GESH 15 typical gas diversion methods
indexes/chronic inaccessibility
as diversion re-positioning the meter GESH 15 typical gas diversion methods
as diversion running the meter backward GESH 15 typical gas diversion methods
gas equipment service conversion vs configuration of equipment GESH 10 conversion vs configuration of equipment
as equipment service hazardous conditions GESH 10 hazardous conditions
as a ui ment service service to all appliances GESH 10 service to all appliances
as equipment service service to appliances GESH 10 service to appliances
as equipment service GESH 10 throw hout
as escaping inside emergency instructions GESH 1 emergency instructions
as escaping outside emergency instructions GESH 1 emergency instructions
as explosion priority 1-emergency requests GESH 1 priority 1 -emergency requests
as fire inside emerqencv instructions GESH 1 emergency instructions
as fire outside emergency instructions GESH 1 emergency instructions
gas incident field
checklist GESH 17 gas incident field checklist
gas incident field chain of custody GESH 17 chain of custody; removal of company equipment
investigation
gas incident field controlling emergencies GESH 17 controlling emergencies
investigation
gas incident field inspection and testing of GESH 17 inspection and testing of meters
investigation meters
gas incident field non-gas related incidents GESH 17 non-gas related incidents
investigation
gas incident field preliminary data collection GESH 17 preliminary data collection
investigation
gas incident field recording the scene GESH 17 recording the scene
investigation
gas incident field removal of company GESH 17 removal of company equipment
investigation equipment
gas incident field responses and notifications GESH 17 responses and notifications
investigation
19

Subject Details Sec/Section Subsection
gas incident field tagging and transporting GESH 17 tagging and transporting meters
investigation meters
gas incident field testing warning GESH 17 testing warning
investigation
gas incident field
GESH 17 throughout
investigation
gas input to burner in table GESH tables GESH tables
cubic feet per hour
gas load and meter gas load and meter 2.22 gas load and meter information sheet
information sheet information sheet
gas material failure material failure 4.11 material failure
report
gas meter information requirements 2.22 gas meter information sheets
sheets
gas meter room Avista requirement 2.22 Avista's requirements for meter room installations
installation
gas occurrence
investigation flowchart GESH 17 gas occurrence review flowchart
gas occurrence review flowchart GESH 17 gas occurrence review flowchart
as operating order definition 1.1 glossary
gas operating order gas incident field investigation GESH 17 preliminary data collection; removal of company
e ui ment;tagging and transporting meters; non-gas
gas pipeline integrity 4.11 information analysis and responsibilities; material failure
Program manager
as service person definition 1.1 glossa
as serviceman restoration of service GESH 5 restoring service;steps for restoration of service
as shut-off notice definition 1.1 glossary
gas tariff curtailment emergency operations GESH 13 curtailment rules
rules
as transport telemetry 2.25 gas transport&telemetry customers
gas transport quantities measured,telemetry 2.25 gas transport&telemetry customers
customers
ate station definition 1.1 alossary
ate station valves 2.14 emergency regulator station valves
ate station equipment configuration 2.25 gate stations
ate station quantities measured,telemetry 2.25 gate stations
ate station maintenance 5.12 gate stations
gate valves 2.14,5.13 2.14-valve types;5.13-steel gate valves;5.13-valve
turns;5.13-steel gate valves
ciatherina line definition 1.1 glossary
ear valves 5.13 gear valves;steel ear valves
5. -grade leak;5. -above groun outs' a ea
classification;5.11 -above ground inside leak
classification;5.11 -gas present in sewer or duct system;
5.11,GESH 1,GESH 5.11 -re-classification of leaks;5.11 -maintenance
grade 1 leaks frequencies;GESH 1 -priority 1 -emergency requests;
2 GESH 2-above ground leakage;GESH 2-gas present in
sewer or duct system;GESH 2-grade 1 leak;GESH 2-
grade 2 leak;GESH 2-reclassification of leaks; GESH 2-
hazardous mechanical fittina failures
5.11 -grade 2 leak;5.11 -above ground outside leak
classification;5.11 -above ground inside leak
classification;5.11 -gas present in sewer or duct system;
grade 2 leaks 5.11, GESH 2 5.11 -re-classification of leaks;5.11 -maintenance
frequencies; GESH 2-temporary postponement of repairs;
GESH 2-gas present in sewer or duct system;GESH 2-
grade 2A leak;GESH 2-Grade 2 leak; GESH 2-re-
classification of leaks
5.11 -grade 2A leak;5.11 -grade 2 leak;5.11 -
grade 2A leak 5.11,GESH 2 maintenance frequencies;GESH 2-grade 2A leak;GESH
2-grade 2 leak
5.11 -grade 3 leak;5.11 -above ground outside leak
classification;5.11 -above ground inside leak
grade 3 leaks 5.11, GESH 2 classification;5.11 -gas present in sewer or duct system;
5.11 -re-classification of leaks;5.11 -maintenance
frequencies; GESH 2-temporary postponement of repairs;
GESH 2grade 3 leak: GESH 2-re-classification of leaks
20

Subject Details Sec/Section Subsection
rindin steel pipe 3.32 thou hout
round bed definition 1.1 glossary
Grunsky meter GESH 9 installing bypasses;bypassing procedures-grunsky meter
changer changing device
handhole cover
removed GESH 15 tampering and illegal bypasses
handling emergency emergency instructions GESH 1 emergency instructions
calls
handling emergency information to obtain GESH 1 information to obtain
calls
handling emergency notifying emergency services GESH 1 notifying emergency services(911)
calls 911
handling fire
department calls GESH 1 handling fire department calls
hard to locate facilities 4.13 hard to locate facilities process
hazard notice GESH 10 hazardous conditions
hazardous condition definition 1.1 qlossary
hazardous conditions GESH 2, 10 GESH 2-throughout;GESH 10-hazardous conditions
heat damage 3.33 heat damage
heat exchan er definition 1.1 glossary
heat fusion 3.23 throughout
heat fusion joint definition 1.1 alossary
heat ran a butt fusion 3.23 heating tool
heaters line heaters 5.22general; line heaters
heaters maintenance,all types 5.22 throughout
heaters pilot line heaters 5.22 pilot line heaters
heaters 5.22 throughout
heaters unvented GESH 12 unvented heaters
heating tool joining, PE(polyethylene)pipe
butt 3.23 heating tool
hemi-head spheres 3.32A detailed procedures for use of Id williamson permanent
hemi-head repair s heres"
high bill investigation required information GESH 16 required information
field orders
high bill investigation scheduling and order flow GESH 16 scheduling and order flow
field orders
high bill investigation adjustments GESH 16 adjustments
field procedures
high bill investigation can't gain entry GESH 16 can't gain entry
field procedures
high bill investigation customer notification GESH 16 customer notification
field procedures
high bill investigation equipment service GESH 16 equipment service
field procedures
high bill investigation HBI retention requirements GESH 16 HBI retention
field procedures
high bill investigation meter misread GESH 16 meter misread
field procedures
high bill investigation meter spot check GESH 16 meter spot check
field procedures
high bill investigation meter test GESH 16 meter test
field procedures
high bill investigation meter test procedures GESH 16 meter test procedures
field procedures
hi h bill investi ations GESH 16 throughout
high bill investigations
and customer Avista initiated meter tests GESH 16 Avista initiated meter test
requested meter tests
high bill investigations customer requested meter
and customer tests GESH 16 customer requested meter test
requested meter tests
high bill investigations
and customer customer service responsibility GESH 16 customer service responsibility
requested meter tests
high bill investigations
and customer GESH 16 throughout
-requested meter tests
21

Subject Details Sec/Section Subsection
high occupancy
definition 1.1 glossary
structure or area
high occupancy curb valve installation 214 2.14-emergency curb valves;2.22-identifying sites with
structures requirements . ,2.22 special design and maintenance requirements
high occupancy leak survey requirements 2.22,5.11 2.22-identifying sites with special design and
structures maintenance requirements;5.11 -annual surveys
hi h pressure definition 1.1 glossary
high pressure alarm responding to GESH 13 responding to pressure alarms
high/low gas priority 1 emergency requests GESH 1 priority 1 -emergency requests
pressures
holiday definition 1.1 glossary
holiday detector definition 1.1 glossary
fleeping machine
hoop stress definition 1.1 glossary
horizontal directional
drillin HDD 3.19 horizontal direction drilling
host pipe 3.19 pipe splitting
house Dir)ina see customer piping
hud part 3280 manufactured homes GESH 12 unvented heaters-manufactured homes
hydraulic butt fusion 3.23 hydraulic butt fusion
hydraulic pressure fusion pressure table 3.23 hydraulic butt fusion
hydraulic shift heat fusion 3.23 hydraulic butt fusion
sequence
hydrocarbon heat fusion 3.23 butt fusion troubleshooting guide
contamination
h drofracture 3.19 HDD borepath; HDD discharge mitigation plan
ice covering meter priority 2 requests GESH 1 priority 2 requests
Idaho-rule no. 182
(IPUC No 27)
"Contingency Plan for emergency operations GESH 13 curtailment rules
Firm Service Gas
Curtailment"
Idaho Code Title 55
Chapter 22;55-2208 4.14 ID damage reporting
5
Idaho dig law website
4.13 locating and marking gas facilities
reference
identification, meter meters 2.22 meter identification
identify corrosion on OQ task 4.31 App A 221.110.015
buried pipe
idle meter definition 1.1 qlossary
idle meter general 2.22 idle meters
idle meter removinq 5.16 idle meters and idle services
idle service line 2.22,5.16 2.22-idle services;5.16-idle meters and idle services
idle services general 2.22 idle services
ignition services to be performed GESH 10 icinition
ignition temperature definition 1.1 glossary
illegal meter bypass GESH 15 typical gas diversion methods
immediate response definition 1.1 glossary
impressed current definition 1.1 glossary
impressed current
2.32 impressed current system
system
inactivating gas meter
facilities 5.16 inactivating gas meter facilities
inches of water definition 1.1 glossary
incident definition 1.1 glossary
incident assessment definition 1.1 qlossary
restoring service;emergency planning worksheet;service
incident commander GESH 5 outage planning&restoration of service worksheet;steps
for restoration of service
incident investigation emergencies GESH 17 throughout
incidental gas leaks GESH 10 incidental gas leaks
inconclusive definition 1.1 alossary
5.11 -leak detection instruments;5.11 -underground leak
inconclusive leaks and 5.11,GESH 2 investigation;GESH 2-meter spot check procedure;
odors GESH 2-underground leak investigation;GESH 2-
inconclusive leak and odor investigation
22

Subject Details Sec/Section Subsection
inconclusive leaks and detection of other combustible GESH 2 detection of other combustible gases
odors gases
inconclusive leaks and flame Ionization follow up GESH 2 flame ionization(ppm survey)follow up
odors
incorrect meter
number GESH 9 incorrect meter number
index tampering GESH 15 typical gas diversion methods
industrial meter set definition 1.1 glossary
industrial meter sets maintenance 5.12 general maintence of all service pressures;maintenance of
industrial meter sets;maintenance frequencies
industrial meter sets design 2.22,2.24 2.22-meter set design;2.24-Appendix A
inert gas definition 1.1 glossary
inflection definition 1.1 glossary
information sheets 2.22 gas meter information sheets
inhibitor definition 1.1 glossary
INHVAC association GESH 12 minimum qualifications
injection oderizer usage 2.52 oderizer tvpes
injection odorizers 2.52,5.23 2.52-odorizer types;5.23-injection odorizers YZ type)
injection rate for
3.17 injection rate
purging
injection type odorizer type 2.52,5.23 2.52-odorizer types;5.23-injection odorizers YZ type)
injections,hand gun
lubrication 5.13 plug valve lubrication procedures
input rating definition 1.1 glossary
insertion of PE
(polyethylene)pipe 3.16 insertion of old steel services along plastic main
into steel services
insertion of steel into 3.16 insertion of old steel services along steel main
steel services
inside leak and odor GESH 2 customer side leak and odor investigation
investigation
inside meter set definition 1.1 glossary
inside meter sets 2.22 inside meter sets
inspection welding preparation 3.22 weld preparation
inspection atmospheric corrosion 5.14 maintenance and remediation timeframes and frequencies;
exposed pipe reads;recordkee in
inspection bridges 5.15general;maintenance frequencies
inspection distribution lines 5.15general;maintenance frequencies
inspection high pressure mains 5.15general;maintenance frequencies
inspection pipeline markers for buried pipe 5.15 pipeline markers for buried pipe
inspection pipelines subject to movement 5.15general; maintenance frequencies
inspection transmission lines 5.15 maintenance frequencies
inspection underwater inspections(major 5.15 maintenance frequencies;recordkeeping
crossings)
inspection orders safety inspection report GESH 12 safety inspection report
inspection procedures air tests GESH 12 air tests
inspection procedures appliance services GESH 12 appliance services
inspection procedures customer instructions GESH 12 customer instructions
inspection procedures customer safety GESH 12 customer safety
inspection procedures equipment warranties GESH 12 equipment warranties
inspection procedures meter installations GESH 12 meter installations
inspection procedures tie-in of customer house pipin9 GESH 12 tie-in of customer house DiDing
inspection reports, PE see exposed piping
inspection reports,
see exposed piping
steel
inspection,general 3.14,4.13 3.14-throughout;4.13-on-site inspections general
inspection, HP
distribution pipelines 5.10 line patrols
install gas meters large/commercial,OQ task 4.31 App A 221.070.041
install gas meters small/residential,OQ task 4.31 App A 221.070.045
installation of meters, back pressure protection GESH 6 back pressure protection
erts and regulators
installation of meters, high pressure meter sets GESH 6 high pressure meter sets
erts and regulators
installation of meters, installing bypasses GESH 6 installing bypasses
erts and regulators
23

Subject Details Sec/Section Subsection
installation of meters, insulating meter sets GESH 6 insulating meter sets
erts and regulators
installation of meters, leveling GESH 6 leveling
erts and regulators
installation of meters, marking of multiple meters GESH 6 marking of multiple meters
erts and regulators
installation of meters, meter,ert configurations GESH 6 meter,ert configurations
erts and regulators
installation of meters, meter,ert,and regulator install GESH 6 meter,ert,and regulator install
erts and regulators
installation of meters, pipe-joining GESH 6 pipe-joining
erts and regulators
installation of meters, pre-installation procedure GESH 6 pre-installation procedure
erts and regulators
installation of meters, regulator replacements GESH 6 regulator replacements
erts and regulators
installation of meters, supporting manifolds GESH 6 supporting manifolds
erts and regulators
installation of meters, vents GESH 6 vents
erts and regulators
installation test locking and unlocking meters GESH 6 locking and unlocking meters
rocedures
installation test meter test GESH 6 meter test
procedures
installation test meter-set leak test GESH 6 meter-set leak test
rocedures
installation test odorant test GESH 6 odorant test
procedures
installation test painting meters GESH 6 painting meters
procedures
installation test utilization pressure test GESH 6 utilization pressure test
rocedures
installing pipelines plastic,OQ task 4.31 App A 221.120.115
installing pipelines steel,OQ task 4.31 App A 221.120.125
insulation cathodic protection 2.32 insulation
insulator definition 1.1 glossary
intelex mock emergency drills GESH 13 GESH 13 throughout
intermediate pressure definition 1.1 glossary
intermediate pressure Drawing A-35208 2.24 Appendix A
meter set
intermittent ignition definition 1.1 glossary
IID
internal corrosion
5.14 internal corrosion control
control
internal relief valve definition 1.1 glossary
I RV
international fuel gas safety inspections GESH 12 recognized codes
code
international safety inspections GESH 12 recognized codes
mechanical code
interruptible gas definition 1.1 glossary
investigation see incident invest.
iron case meters meters 2.22 meter types
iron temperature
3.23 heating tool
(fusion)
isolated main less 5.14 monitoring isolated mains less than 100 ft or service lines;
than 100 ft maintenance and remediation timeframes and frequencies
isolated risers without CP, leak survey) 5.11 maintenance frequencies
monitoring isolated mains less than 100 ft or service lines;
isolated risers with cathodic protection 5.14 isolated steel;isolated steel risers; isolated steel services;
maintenance and remediation timeframes and frequencies
isolated risers 5.14 throughout
isolated services 5.14 isolated services
4.14-wa isolated steel and replacement program;5.14-
monitoring isolated main less than 100 ft or service lines;
isolated steel 4.14,5.14 5.14-isolated steel;5.14-isolated steel risers; 5.14-
isolated steel services;5.14-maintenance and
remediation timeframes and frequencies
24

Subject Details Sec/Section Subsection
'jeep definition 1.1 glossary
jeeping steel pipe 3.12 electrical inspection of pipeline coatings 'ee in
jeeping formula 3.12 voltage settings for thin film coatings
jeeping formula 3.12 voltage settings for conventional coatings
'Joining steel pipe 3.22 throughout
joining PE pipe 2.13,3.23,3.24,3.25 2.13-joining of plastic pipe components; 3.23-
throughout;3.24-throughout;3.25-throw hout
joining-hydraulic butt plastic pipe,OQ task 4.31 App A 221.030.010
fusion
joining-manual butt plastic pipe,OQ task 4.31 App A 221.030.005
fusion
joining-mechanical plastic pipe,OQ task 4.31 App A 221.030.020
cow lin s
joining-mechanical plastic pipe,OQ task 4.31 App A 221.030.015
service tees
joining-mechanical
spigot and sleeve type plastic pipe,OQ task 4.31 App A 221.030.025
fittings
joint ditch design pre-check layout and 3.14 joint ditch
inspection
joint ditch design see trenching
joule-thomas effect definition 1.1 glossary
joule-thomson effect 5.22 general
knitted fiberglass tape ARO for steel pipe in HDD 3.12 knitted fiberglass tape
work
ladder policy definition 1.1 glossary
landfill gas definition 1.1 glossary
large diaphragm meter Drawing C-35209 2.24 Appendix A
set drawing
lateral definition 1.1 qlossary
leak definition 1.1 glossary
leak and odor
general GESH 2 general
investigation
leak and odor investigation required information GESH 2 general
leak and odor responding employee GESH 2 general
investigation qualifications
leak centering or definition 1.1 glossary
pinpointing
leak check high pressure 3.18 pressure testing for steel
leak detector definition 1.1 qlossary
leak failure cause 5.11,GESH 2 5.11 -leak failure cause definitions;GESH-2 leak failure
definitions cause definitions
5.11 -leak detection instruments;5.11 -detection of other
combustible gases;5.11 -grade 1 leak; 5.11 -
leak investigation 5.11,GESH 2 underground leak investigation;5.11 -underground leak
determination;5.11 -leak repair and residual gas checks;
5.11 -follow up inspections for residual gas;GESH 2-
throughout
leak investigation can't gain entry procedures GESH 2 can't gain entry procedures
5.11 -leak repair and residual gas checks;GESH 2-
leak repair 5.11,GESH 2 reinstatement of service;GESH 2-leak repair and residual
gas checks;GESH 2-follow-up inspections for residual
as
leak survey 250 psig and greater pipelines 5.11 250+psig pipelines Washington only; maintenance
frequencies
leak survey 5 year surveys 5.11 5 year survey; maintenance frequencies
leak survey annual surveys 5.11 annual surveys;maintenance frequencies
leak survey barholes 5.11 underground leak determination
leak survey bubble leak tests 5.11 bubble leak test
leak survey buildings of public assembly 5.11 annual surveys
leak survey business districts 5.11 annual surveys;maintenance frequencies
leak survey calibration of equipment 5.11 leak detection instruments; maintenance of instruments
leak survey classifying leaks 5.11 classifying leaks
combustible gas indicator leak detection instruments;classifying leaks;
leak survey (CGI) 5.11 pinpointing/centering;underground leak repair;
recordkee in and reportingi
25

Subject Details Sec/Section Subsection
leak survey detecto-pak infrared detector 5.11 leak detection instruments
DP-IR
leak survey DIMP identified surveys 5.11 DIMP identified surveys
leak survey ejector aerator 5.11 pinpointing/centering
leak survey failure causes 5.11 leak failure cause definitions
leak detection instruments;surface gas detection survey;
leak survey flame ionization detector(F.I.) 5.11 survey limitations;annual surveys;transmission pipelines;
5 Vear survey;special survey
leak survey grade 1 leaks 5.11 grade 1 leaks
leak survey grade 2 leaks and grade 2A 5.11 grade 2A leak;grade 2 leak
leaks
leak survey grade 3 leaks 5.11 grade 3 leaks
leak survey
high pressure mains,250+ 5.11 250+psig pipelines Washington only; maintenance
si WA frequencies
leak survey Red 5.11 leak detection instruments
leak survey lowered pipelines 5.11 special surveys
leak survey maintenance of instruments 5.11 maintenance of instruments
leak survey mechanical fittings 5.11 leak failure cause definitions; hazardous mech.fitting
failures
leak survey methods 5.11 gas leak survey methods
leak survey avin rior to 5.11 special surveys
leak survey pressure drop test 5.11 pressure drop test
leak survey procedures 5.11 throughout
leak survey re-classification of leaks 5.11 re-classification of leaks
leak survey recordkeeping 5.11 recordkeeping and reporting
leak survey remote methane leak detector 5.11 leak detection instruments
RMLD
leak survey self-audits 5.11 self-audits
leak survey special surveys 5.11 special surveys
leak survey surface gas detection methods 5.11 surface gas detection survey
leak survey transmission pipelines 5.11 transmission and other HP pipelines; maintenance
frequencies
leak survey cathodic protection 5.14 shorted casings; isolated steel; maintenance and
remediation timeframes and frequencies
leak survey pinpointing/centering 5.11,GESH 2 5.11 -pinpointing/centering;GESH 2-pinpointing/
centering
leak survey OQ task 4.31 App A 221.230.005
leak test definition 1.1 glossary
4.18-odorant concentrations;5.11 -grade 1 leak;5.11 -
LEL 4.18,5.11,5.19, grade 2A leaks;5.11 -grade 2 leak;5.11 -grade 3 leak;
GESH 2,GESH 4 5.19;GESH 2-grade 1 leak;GESH 2-grade 2 leak;
GESH 2-grade 3 leak; GESH 4-evacuation procedures
leveling GESH 6 Ievelin
lift of pipe definition 1.1 glossary
lighting strike/electric GESH 17 lightning strike/electric arcing field checklist
arcing field checklist
limit device definition 1.1 glossary
line heater maintenance,OQ task 4.31 App A 221.080.045
line heater monthly maintenance,OQ 4.31 App A 221.080.047
line heaters 5.22 line heaters
line patrols 5.15 maintenance frequencies;recordkee in
line tamer heat fusion 3.23 cold weather fusion
link type seals 3.42 installing steel carrier pipe in casing
Ii ueified natural gas definition 1.1 glossary
liquid epoxy coating steel pipe 3.12 liquid epoxv coating
little fink installation drawing B-34947 3.42 B-34947
little fink installing leads&stations, OQ 4.31 App A 221.110.035
task
load definition 1.1 glossary
local distribution definition 1.1 glossary
com an LDC
locate wire steel pipe 3.19 future Iocatabilit
locating facilities emergency locates 4.13 requesting emergency locates
locating facilities 4.13 locating and marking as facilities
locating facilities OQ task 4.31 App A 221.230.050
locks regulator station locks 5.12 general station ins ection
locks relief valve locks 5.12 general station ins ection
26

Subject Details Sec/Section Subsection
2.23-valve;3.16-new service lines not in use;5.12-
locks valve locks 2.14,2.23,3.16,5.12, general station inspection;5.13-general valve
5.13,5.16 maintenance and installation notes; 5.16-idle meters and
idle services
locks idle riser locks 2.22,5.16 2.22-idle services;5.16-idle meters and idle services
5.16-inactivating gas meter facilities; 5.17-reinstating
gas facilities;GESH 1 -handling fire department calls;
2.22,5.16,5.17, GESH 2-procedures upon entry;GESH 2-hazardous
locks gas meter locks GESH 1,2, 3,51 6,7 conditions; GESH 2-can't gain entry procedures;GESH 3
7 8,9, 10, 12, 15, 1 initial determination;GESH 5-maps and lists; GESH 5-
restoring service; GESH 5-meters turned on by other than
avista; GESH 5-can't gain entry situations;GESH 5-
steps for restoration of service
lockup pressure definition 1.1 glossary
longitudinal stress steel pipe(design formula 2.12 longitudinal stress
low pressure definition 1.1 alossary
low pressure alarm responding to GESH 13 responding to pressure alarms
low pressure monitoring pressures GESH 5 monitoring pressures
low pressure plan of action GESH 5 plan of action
low pressure pressure drops GESH 5 pressure drops
lower explosive limit definition 1.1 glossary
LEL
lowering steel pipe decision flow chart 3.12 steel pipe lowering decision flowchart
lowering steel pipe minimum considerations 3.12 moving or lowering steel pipe in service
lowering steel pipe Washington State study 3.12 toughness testing
requirements
lowering steel pipe leak survey after 3.12,5.11 3.12-toughness testing;5.11 -special surveys;5.11 -
maintenance frequencies
general;procedure for installing approved spigot and
sleeve type couplings and fittings using the QRP-100 quick
lycofit fittings 3.25 ratchet press;procedure for installing approved spigot and
sleeve type couplings and fittings using the LHP hydraulic
press tool
procedure for installing approved spigot and sleeve type
couplings and fittings using the QRP-100 quick ratchet
lycoring 3.25 press tool;procedure for installing approved spigot and
sleeve type couplings and fittings using the Ihp-200
hydraulic press tool
main definition 1.1 glossary
main abandonment 5.16 abandoning as facilities
main burner GESH 10 main burner
maintenance cycles welder certification,steel 3.22 qualification of welders
maintenance cycles joining certification, PE'oinin 3.23 pipe joining certification record
maintenance cycles odorometer calibrations 4.18 calibration of instrument
maintenance cycles odorant sampling 4.18 odorant sampling
maintenance cycles EOP plan 5.11 grade 1 leak
maintenance cycles FI flame ionization units 5.11 maintenance of instruments
maintenance cycles leak survey 5.11 maintenance frequencies
maintenance cycles regulator stations 5.12 maintenance frequencies
maintenance cycles single service farm taps 5.12 farm taps and HP services
maintenance cycles valves 5.13 maintenance frequencies-valves
maintenance cycles cathodic instrument calibration 5.14 calibration of equipment
maintenance cycles line patrols 5.15 maintenance frequencies
maintenance cycles vaults 5.18 maintenance frequency
maintenance cycles CGI (combustible gas 5.19 maintenance frequencies
indicators
maintenance cycles pressure gauge calibrations 5.21 maintenance frequencies
maintenance cycles heaters 5.22 line heaters; pilot line heaters
maintenance cycles odorizers 5.23 injection odorizers(YZ type);by-pass odorizers;wick
odorizers
maintenance cycles meters 2.22,5.12 2.22-frequency of meter tests;5.12-maintenance
frequencies
5.11 -maintenance frequencies;5.12-maintenance
maintenance 5.11,5.12,5.14,5.15, frequencies;5.14-maintenance and remediation
frequencies 5.18,5.19,5.21 timeframes and frequencies;5.15-maintenance
frequencies;5.18-maintenance frequency;5.19-
maintenance frequencies;5.21 -maintenance fre uencies
27

Subject Details Sec/Section Subsection
major gas incident
report form N-2566 GESH 17 responses and notifications
management of
change,transmission 2.12 transmission line-approval of change
line
manhole definition 1.1 glossary
manifold definition 1.1 glossary
types of pressure gauges;required gauges by job type;list
manometer pressure gauges 5.21 of acceptable gauges;field operating guidelines for
pressure gauges
manometer u- au a definition 1.1 qlossary
manual service line definition 1.1 glossary
shut-off valve
MAOP(maximum
allowable operating changing 4.15 changing MAOP
press.)
MAOP(maximum
allowable operating determination of 4.15 determination of MAOP
press.)
MAOP(maximum
allowable operating revisions 4.16 confirmation or revision of MAOP
pressure)
MAOP reconfirmation 4.16 MAOP reconfirmation
mapping timely,within 6 months 4.11 updating maps and records
mappinq corrections 4.13 mapping corrections
marker ball 2.14,3.12,3.19 2.14-general;3.12-marker balls;3.19-future locatabilit
marker balls plastic pipe 3.13 marker balls
marker balls usage 3.12 marker balls
markers maintenance 5.15 pipeline markers for buried pipe
markers idle risers 5.16 maintenance requirements
markers aboveground pipe 3.15,5.15 3.15-pipeline markers for buried pipe;5.15-general;5.15
-Washington pipeline marker location requirements
3.15-pipeline markers for buried pipe;5.15-general;5.15
markers buried pipe 3.15,5.15 -pipeline markers for buried pipe for buried pipe;5.15-
exceptions for marking
markers exceptions for marking 3.15,5.15 3.15-pipeline markers for buried pipe;5.15-exceptions
for marking
markers OQ task 4.31 App A 221.120.110
marking gas facilities
locates 4.13 locating and marking gas facilities
marking meters marking of closed meters;marking of meters turned on by
(shutdown& GESH 5
co.
restoration
marking PE joints 3.23,3.24,3.25 3.23-marking joints;3.24-marking joints; 3.25-marking
joints
marking toe see caution tape
master meter/master safety related condition report, 4.12 exceptions to reporting safety related conditions
meter station exception
master meter/master maintenance 5.12 regulator stations and elevated pressure meter sets
meter station
master meter station definition 1.1 glossary
mastic coating steel pipe 3.12 mastic coating
material failure 4.11 material failure
material failures report 4.14 WUTC construction defects&material failures report
for WUTC
material, leak failure
5.11 leak failure cause definitions
cause
maximo definition 1.1 glossary
maximum allowable
operating pressure definition 1.1 glossary
MAOP
maximum allowable
operating pressure steel pipe 2.12 design formula for steel pipe
MAOP
maximum allowable
operating pressure PE(polyethylene)pipe 2.13 general
MAOP
28

Subject Details Sec/Section Subsection
maximum allowable
operating pressure station capacity 2.23 capacity
MAOP
maximum length of excess flow valves(EFV) 3.16 capacity of EFV
service protected
mechanical air
intakes, proximity to 2.22 avista's requirements for meter room installations
meters
mechanical chart distribution system 2.25 general
recorder
mechanical cou lin s PE(polyethylene)pipa 3.25 qeneral
mechanical fitting definition 1.1,GESH 2 1.1 -glossa
mechanical fitting definition 1.1 glossary
mechanical fittings leak survey 5.11 throughout
media inquiries GESH 4 media inquiries
melt bead size 3.23 butt fusion procedures
metallic coatings 2.32 metallic coatings
meter prover calibration interval 2.22 prover calibration interval
meter and regulator correction codes GESH 6 correction codes
design
meter and regulator meter design GESH 6 meter design
design
meter and regulator rate schedule GESH 6 rate schedule
design
meter and regulator revenue class GESH 6 revenue class
design
meter and regulator elevated pressure
GESH 6 elevated pressure identification
sizing identification
meter and regulator meter sizing GESH 6 meter sizing
sizing
meter and regulator overpressure protection GESH 6 overpressure protection
sizing
meter and regulator regulator sizing GESH 6 regulator sizing
sizing
meter and regulator vent lines GESH 6 vent lines
sizing
meter capacity diaphragm meters 2.24 diaphracim meters
meter capacity rotary meters 2.24 rotary meters
meter capacity turbine meters 2.24 turbine meters
meter change order/ checking for electrical shorts GESH 9 checking for electrical shorts
meter removal order
meter change order/ existing meter sets GESH 9 existing meter sets
meter removal order
meter change order/ general GESH 9 general
meter removal order
meter change order/ grounding of meter sets if GESH 9 grounding of meter sets if necessary
meter removal order necessary
meter change order/ inaccessible meters GESH 9 inaccessible meters
meter removal order
meter change order/ incorrect meter number GESH 9 incorrect meter number
meter removal order
meter change order/ GESH 9 throughout
meter removal order
meter change order/ required information GESH 9 required information
meter removal order
meter change orders cold weather precautions GESH 9 cold weather precautions
meter change orders contacting the customer GESH 9 contacting the customer
meter change orders customer not home-inside set GESH 9 customer not home-inside set
meter change orders set customer not home-outside GESH 9 customer not home-outside set
meter change orders determination of BTU load GESH 9 determination of BTU load
meter change orders interconnected house piping GESH 9 interconnected house pipLM
meter change orders meter change originated in the GESH 9 meter change originated in the field
field
meter change orders meter found off GESH 9 meter found off
meter change orders required meter information GESH 9 required meter information
meter clock test Idefinition 1.1 glossary
meter clock test I see clock test
29

Subject Details Sec/Section Subsection
meter data definition 1.1 glossary
management
meter information
2.22 gas meter information sheets
sheets
meter installed
backward GESH 15 typical gas diversion methods
meter provers maintenance cycles 2.22 prover calibration interval
meter remove order contacting the customer GESH 9 contacting the customer
meter remove order customer not home GESH 9 customer not home
meter remove order meter found on GESH 9 meter found on
meter remove order meter removal originated in GESH 9 meter removal originated in the field
the field
meter room definition 1.1 glossary
meter room installation 2.22 installation
meter room installation,Avista's 2.22 avista's requirement for gas meter room installations
requirements
meter room minimum requirements for 2.22 avista's requirements for meter room installations
meter room ventilation of 2.22 avista's requirements for meter room installations
meter set design 2.22 avista's requirement for gas meter room installations
meter set regulators tables 2.24 regulator tables
meter set assembly definition 1.1 glossary
MSA
meter set regulator 2.24 regulator tables
capacities
meters of check definition 1.1 glossary
meter spot check calculating small amounts of GESH 2 calculating small amounts of meter flow
meter flow
meters of check exception GESH 2 meters of check procedure
meters of check hazardous conditions GESH 2 avista side leak and odor investigation
meters of check procedures GESH 2 avista side leak and odor investigation
meters of check reinstatement of service GESH 2 reinstatement of service
meter spot check temporary repair/cold weather GESH 2 temporary repairs/cold weather exceptions
exceptions
meter swivel definition 1.1 glossary
meter tests frequency 2.22 frequency of meter tests
meter tests customer requested GESH 16 customer requested meter test
meter turn-off orders cancellations or GESH 8 cancellations or postponements
postponements
meter turn-off orders can't gain entry situations GESH 8 can't gain entry situations
meter turn-off orders cold weather precautions GESH 8 cold weather precautions
meter turn-off orders duplicate orders GESH 8 duplicate orders
meter turn-off orders elevated and high pressure GESH 8 elevated and high pressure meters
meters
meter turn-off orders general GESH 8 general
meter turn-off orders new customer GESH 8 new customer
meter turn-off orders order verification GESH 8 order verification
meter turn-off orders required information GESH 8 required information
meter turn-off orders turn off originated in the field GESH 8 turn off originated in the field
meter turn-off orders verifying non-use GESH 8 verifying non-use
meter turn-off general GESH 8 general
procedures
meter turn-off other methods GESH 8 other methods
procedures
meter turn-off wing-lock service valves GESH 8 meter lock out
procedures
meter turn-on orders GESH 1,GESH 7 GESH 1 -Priority 2-requests;GESH 7-throughout
meter turn-on orders can't gain entry situations GESH 7 can't gain entry situations
meter turn-on orders duplicate orders GESH 7 duplicate orders
meter turn-on orders meter off but access refused GESH 7 meter off but access refused
meter turn-on orders meters found on by GESH 7 meters found on by serviceman
meter turn-on orders required information GESH 7 required information
meter turn-on orders turn-on originated in the field GESH 7 turn-on originated in the field
meter turn-on bringing meters up to standard GESH 7 bringing meters up to standard
procedures
meter turn-on customer safety GESH 7 customer safety
procedures
meter turn-on determination of BTU load GESH 7 determination of BTU load
procedures
30

Subject Details Sec/Section Subsection
meter turn-on house piping leak test GESH 7 house piping leak test
procedures
meter turn-on inaccessible equipment GESH 7 inaccessible equipment
procedures
meter turn-on ladder policy GESH 7 ladder policy
procedures
meter turn-on non-conventional utilization
GESH 7 non-conventional utilization pressure check
procedures pressure check
meter turn-on purging GESH 7 purging
procedures
meter turn-on regulator validation GESH 7 regulator validation
procedures
meter turn-on service order completion GESH 7 service order completion
rocedures
meter turn-on servicing gas equipment GESH 7 servicing gas equipment
procedures
meter turn-on under sized house piping GESH 7 under sized house piping
procedures
meter turn-on utilization pressure check GESH 7 utilization pressure check
rocedures
meter turn-on utilization pressure check(2 GESH 7 utilization pressure check(2 and 5 psig)
procedures and 5psig)
meter unlock policy GESH 7 meter unlock policy
meter,ert,ami,and address markings GESH 6 address markings
regulator installations
meter,ert,ami,and can't gain entry GESH 6 can't gain entry
regulator installations
meter,ert,ami,and installation information GESH 6 installation information
re ulator installations
meter,ert,ami,and required service information GESH 6 required service information
regulator installations
meter,ert,ami,and service orders GESH 6 service orders
regulator installations
meter,gas definition 1.1 glossary
metering pressure definition 1.1 glossm
meters 10 foot rule 2.22 10 foot rule
meters 2 psig meter sets 2.22 industrial sets&elevated pressure sets
meters 3 foot rule 2.22 3 foot rule
meters 5 psig meter sets(under 2.22 industrial sets&elevated pressure sets
elevated sets
meters alcove installation 2.22 alcove installation
meters aluminum 2.22 meter types
meters aluminum and cast iron 2.22 meter types
diaphragm
meters atmos heric pressure table 2.22 elevation compensation
meters case pressure 2.22 meter case pressures
meters clearances 2.22 3 foot rule; 10 foot rule
meters corrected flow formula 2.22 computing corrected flows
meters correction codes table 2.22 correction codes
meters customer piping, insulating
from 2.22 insulating downstream customer piping
meters downstream piping 2.22 insulating downstream customer piping
meters elevated pressure sets 2.22 industrial sets&elevated pressure sets
meters gas meter information sheets 2.22 gas meter information sheets
meters gas volume calculation 2.22 gas volume calculation
meters identification 2.22 meter identification
meters idle meters 2.22 idle meters
meters idle services 2.22 idle services
meters industrial meters 2.22 meter types
meters industrial sets 2.22 industrial sets&elevated pressure sets
meters information sheets 2.22 gas meter information sheets
meters inside meter sets 2.22 inside meter sets
meters iron case 2.22 meter types
meters 2.22 meter set location protection and barricades;alcove
installation
meter set location protection and barricades; meter room
meters meter rooms 2.22 installation;avista's requirements for gas meter room
installations
31

Subject Details Sec/Section Subsection
meters meter set design 2.22 meter set design
meters multiple meters 2.22 multiple meters
meters multiple services 2.22 multiple services
meters PP&L territory location rule 2.22 3 foot rule
meters pressure compensation 2.22 pressure compensation
meters prover calibrations 2.22 prover calibration interval
meters regulator design 2.22 throughout
meters relief vent design 2.22 avista's requirements for meter room installations
meters rotary meters 2.22 meter types
special design and
meters 2.22 inside meter sets
maintanence requirements
meters temperature compensation 2.22 temperature compensation
meters temperature corrected flows 2.22 computing corrected flows
meters testing frequency 2.22 frequency of meter tests
meters turbine meters 2.22 meter types
meters types 2.22 meter types
meters vault 2.22 pits and vaults
meters ultrasonic meters 2.22 meter types
meters coriolis meters 2.22 meter types
meters protection 2.22 meter set location, protection,and barricades
meters barricades 2.22 meter set location, protection,and barricades
meters downstream insulation 2.22 insulating downstream customer piping
meters capacity tables 2.24 meter capacity tables
meters diaphragm type capacity table 2.24 diaphragm meters
meters drawings,standard 2.24 Appendix A
meters regulators for,capacity 2.24 re ulator tables
meters rotary type capacity table 2.24 rotary meters
meters standard drawings 2.24 Appendix A
meters tables for sizing 2.24 meter capacity tables
meters turbine type capacity table 2.24 meter capacity tables
2.22-meter set location protection and barricades; 2.22-
3 foot rule;2.22-10 foot rule;2.22-inside meter sets;
meters location 2 22 2 24 2.22-alcove installation;2.22-meter room installation;
2.22-multiple services;2.22-multiple meters;2.22-
meter set design;2.22-avista's requirements for gas
meter room installations;2.24 App A-throucihout
meters design 2.22,2.24,GESH 6 2.22-throughout;2.24 -throughout; GESH 6-meter and
re ulator desi n
meters installation 2.22,2.24,GESH 6 2.22-installation;2.24 -throughout;GESH 6-throughout
meters 2.22,2.24,GESH 6 2.22-throughout;2.24 -throughout; GESH 6-meter and
regulator design
meters snow areas 2.22,3.16 2.22-meter set location protection and barricades;3.16
services in heavy snow areas
meters protection 2.22,5.14 2.22-meter set location protection and barricades; 5.14-
cathodic protection maintenance
meters overbuilds 2.22,5.20 2.22-overbuilds;5.20-inspection requirements
meters insulating 2.22,GESH 6 2.22-Insulating downstream customer piping; GESH 6-
insulatinq meter sets
meters sizing 2.24,GESH 6 2.24-meter capacity tables;2.24-App A; GESH 6-meter
and regulator sizing
meters multi-meter manifolds 3.16,GESH 6 3.16-service risers for multi-meter manifolds;GESH 6-
marking of multiple meters;GESH 6-supporting manifolds
meters gas incident field investigation GESH 17 throw hout
meters turn on orders GESH 7 throughout
meters unlock policy GESH 7 meter unlock policy
meters turn off orders GESH 8 throughout
meters change orders GESH 9 meter change orders
meters remove order GESH 9 meter remove order
meters pits 2.22 pits and vaults
methanol 3.18 pressure testing for steel
3.15-Clearances-steel and PE pipelines;3.16-service
lines in conduit/casing;3.42-conduit;5.11 -classifying
3.15,3.16,3.42,5.11, leaks;5.11 -venting underground leakage;5.11 -gas
migration of gas 5.16 GESH 2,4 present in sewer or duct system;5.16-abandoning gas
facilities;GESH 2-venting underground leakage; GESH 2
gas present in sewer or duct system; GESH 2-leak repair
and residual cias checks: GESH 4-general
mil Idefinition 1 1.11 glossary
32

Subject Details Sec/Section Subsection
military time 3.18 recordkee in
minimum safe definition 1.1 glossary
utilization pressure
missing meter seals GESH 15 missing meter seals
miter joint definition 1.1 alossary
mock emergencies GESH 13 mock emergency drills
model energy code, safety inspections GESH 12 recognized codes
the
monitor definition 1.1 glossary
monitor regulator testing 5.12 maintenance of overpressure protection devices; monitor
testin
3.12-monitoring of pressures;3.13-monitoring of
monitoring pressure 3.12,3.13,3.32,3.33, pressures;3.32 monitoring of pressure;3.33 monitoring of
4.31 App A,5.12 pressure;4.31 App A-221.230.035;5.12-pressures
precaution
Mueller Save-a-Valve nipple 3.32 mueller save-a valve nipple or equivalent;steel repair
selection charts
Mueller repair clams 3.35 adams and mueller style procedure
Mueller tapping&stopping 4"and 4.31 App A 221.040.001
smaller
Mueller tapping&stopping 6"and 4.31 App A 221.040.010
larger, OQ Task
multi-meter manifolds 2.22,3.16,GESH 6 2.22-multiple meters;3.16-service risers for multi-meter
manifolds
multiple services general 2.22 multiple services
must definition 1.1 qlossary
mutual assistance 4.31, GESH 13 4.31 -mutual assistance agreement;GESH 13-mutual
assistance
mutual assistance GESH 13 mutual assistance
a reement
mutual assistance GESH 5 emergency planning worksheet;service outage planning
Ian and restoration of service worksheet
national electrical vault 2.42 electrical code
code NEC
national pipeline
mapping system updating 4.14 NPMS updating
NPMS
national transportation definition 1.1 glossary
safety board NTSB
natural forces,leak 5.11,GESH 2 5.11 -leak failure cause definitions
failure cause
natural gas definition 1.1 alossary
natural gas behavior of 2.22 behavior of natural gas
natural gas corrected flows 2.22 computing corrected flows
natural gas volume calculation 2.22 gas volume calculation
NDT(non-destructive 3.12,4.31,App A 3.12-visual inspection;4.31 App A-221.130.015
testing)
ne ative pressure definition 1.1 glossary
neutral pressure point definition 1.1 glossary
new construction riser definition 1.1 glossary
new plastic services tracer wire corrosion 3.16 new plactic services
prevention
nfpa number 54 GESH 12 recognized codes;unvented heaters and decorative
appliances;boilers
nitrogen purging with 3.17 purging with nitrogen
nitrogen volume required 3.17 purging with nitrogen
nitrogen relief testing with nitrogen, 5.12 relief and safety shut-off testing; procedure for testing relief
procedure valves with nitrogen or bottled cn
nitrogen slug purging 3.17 purging with nitrogen
non-destructive testing steel pipe 3.12 visual inspection
NDT
non-destructive testing
see NDT
(NDT)
non-emergency charges GESH 1 charges
service requests
non-emergency customer information GESH 1 customer information
service requests
33

Subject Details Sec/Section Subsection
non-emergency service delays GESH 1 service delays
service requests
non-emergency
service requests GESH 1 non-emergency service requests
non-observable task definition 1.1 alossary
non-qualified definition 1.1 glossary
northwest energy safety inspections GESH 12 recognized codes
code,the
notification of potential priority 1 -emergency GESH 1 priority of service requests
rupture requests
notification of potential definition 1.1 glossary
rupture
Nucleus data collection 2.25 data path and uses
numbering regulator station 2.23 regulator station numbering
obscured indexes tampering GESH 15 obscured indexes
obsolete regulators 2.24 obsolete regulators
5.11 -underground leak investigation;5.11 -blowing gas
and odor calls;GESH 2-responding employee
odor calls procedures 5.11,GESH 2 qualifications;GESH 2-underground leak investigation;
GESH 2-blowing gas,odor calls,and damage events-
recording information
odor calls priority GESH 1 priority 1 -emergencv re uests
odorant definition 1.1 glossary
odorant concentration 2.52 odorant type
odorant type 2.52 odorant type
odorization definition 1.1 glossary
odorization calibrations of odorometers 4.18 calibration of instrument
odorization DTEX YZ odorometers 4.18 YZ odorometer DETEX
odorization 4.18 calibration of instrument
odorization odorometer 4.18 odorant concentrations;odorant sampling;test point
review; recordkee in z odorometer dtex
odorization periodic inspections 4.18 periodic odorizer station inspections
odorization pickling 4.18 pickling newly installed DiDina
odorization recordkeeping 4.18 recordkee in
odorization sampling 4.18 odorant sampling
odorization test point review 4.18 test point review
odorization threshold detection 4.18general;threshold detection level TDL
odorization YZ odorometer 4.18 YZ odorometer DETEX
odorization spills of odorant 5.23 odorants ills
2.52-throughout;4.18-general;4.18-odorant
concentrations;4.18-pickling newly installed piping;4.18-
odorization odorant 2.52,4.18 odorant sampling;4.18-locations where odor is
inadequate;4.18-odorant level analysis;4.18-YZ
odorometer dtex
odorization odorant concentrations 2.52,4.18 2.52-odorant concentrations;4.18-general;4.18-odorant
concentrations;4.18 odorant sampling
odorization periodic sampling(testing), 4.31 App A 221.090.030
OQ task
odorizer definition 1.1 alossary
odorizer by-pass 2.52,5.23 2.52-odorizer type;5.23-by-pass odorizers
odorizer injection type 2.52,5.23 2.52-odorizer type;5.23-injection odorizers YZ type)
odorizer wick type 2.52,5.23 2.52-odorizer type;5.23-wick odorizers
odorizer adjusting,OQ task 4.31 App A 221.090.035
odorizer maintenance 4.31 App A,5.23 4.31 App A-221.090.025;5.23-injection odorizers(YZ
type);5.23-by-pass odorizers;5.23-wick odorizers
odorizer maintenance odorization,OQ task 4.31 App A 221.090.025
odorizers types 2.52 odorizer types
odorizin PE(polyethylene)pi e 3.13 odorizing newly installed pipe
odorometer definition 1.1 glossary
odorometer calibrations 4.18 calibration of instrument
offset staking(for
locates 4.13 locating and marking gas facilities
ohm definition 1.1 glossary
one&two family GESH 12 recognized codes;unvented heaters and decorative
dwelling code,the appliances;copper tubing
One Call color codes 4.13 a wa uniform color codes for markin
One Call dig laws 4.13 locating and markinq qas facilities
One Call linspection,on site 4.13 on-site inspections eneral
34

Subject Details Sec/Section Subsection
One Call public awareness program 4.13 public awareness program
One Call recordkeeping 4.13 recordkeeping of locates
One Call tolerance zone 4.13 tolerance zone
public awareness program;one call notification system;
One Call 4.13 request for locates through one call; requesting emergency
locates;locating and marking gas facilities;excavator
responsibilities for safe digging; locate ticket availability
one-calls stem definition 1.1 glossary
on-site inspections damage prevention 4.13 throughout
operate gas pipeline local facility remote-control 4.31 App A 221.230.055
o erations,OQ task
operating stress definition 1.1 glossary
operation of a pipeline definition 1.1 glossary
operation,leak failure 5.11,GESH 2 5.11 -leak failure cause definitions;GESH 2-leak failure
cause cause definitions
o erations planning for road projects GESH 13 re-construction emergency lannin for road projects
operations manager definition 1.1 glossary
operator qualification abnormal operating condition 4.31 general
(AO
operator qualification investigation guideline flow 4.31,App. D post reportable or OQ incident investigation
chart
operator qualification covered task 4.31 throughout
operator qualification evaluation 4.31 throughout
operator qualification tasks 4.31 throughout
operator qualification OQ Program GESH Foreword Foreword
program
OQ program evaluation guidelines 4.31,App B 4.31 App B-throu hout
OQ program review form for contractors 4.31.App.C 4.31.App.C
OQ program investigation guideline flow 4.31,App D post reportable or OQ incident investigation
chart
OQ program task list 4.31 App A task index table
OQ program 4.31 throughout
Oregon-rule no. 14-
"continuity of service" emergency operations GESH 13 curtailment rules
Oregon dig law
website reference 4.13 locating and marking gas facilities
Oregon state OAR by 860-021-0130 GESH 16 customer requested meter test
number
orifice definition 1.1 glossary
orifice meters gate stations 2.25 gate stations
other,leak failure
5.11 leak failure cause definitions
cause
outside forces,leak
failure cause 5.11 leak failure cause definitions
5.11 -above ground outside leak classification; GESH 2-
outside leak and odor 5.11,GESH 2 external ppm survey; GESH 2-avista-side leak and odor
investigations investigation;GESH 2-inconclusive leak and odor
investigation
overbuilt facilities 2.22,5.20 2.22-overbuilds;5.20-inspection requirements
overgrowth on 5.20 inspection requirements
overpressure
rotection OPP definition 1.1 glossary
overpressure design capacities 2.24 relief valve capacities at set point
protection devices
overpressure maintenance 5.12 maintenance of overpressure protection devices
protection devices
oxidation definition 1.1 glossary
/s(pipe to soil definition 1.1 glossary
paddinq definition 1.1 glossary
padding material 3.13,3.15 3.13-pulling-in;3.15-bedding material
painting exposed
5.20 remediation
piping
patching definition 1.1 glossary
patchinq steel pipe 3.32 throughout
general; methods of patrolling;clearance guidelines for
patroling pipeline 5.15 patrols and pipeline maintenance; maintenance
frequencies;recordkee in ;tim -transmission patrolling
35

Subject Details Sec/Section Subsection
patrolling gas OQ task 4.31 App A 221.030.001
pipelines
paving,leak survey
5.11 special surveys
prior
PE(polyethylene)pi e aboveground installations 2.13 aboveground plastic pipe
PE(polyethylene)pi e approved dimensions table 2.13 design formulas
PE(polyethylene)pi e cathodic protection 2.13 cathodic protection
PE(polyethylene)pi e design formulas for 2.13 design formulas
PE(polyethylene)pi e markings on PE pipe 2.13 markings on plastic pipe and components
PE(polyethylene) i e mechanical vs. heat fusion by 2.13 joining of plastic pipe components
pipe size 1 9 p p p p
PE(polyethylene) i e preferred method of joining 2.13 joining of plastic pipe components
pipe each size � g p p p p
PE(polyethylene)pi e pressure limitations of 2.13 pressure/temperature limitations
PE(polyethylene)pi e print line contents 2.13 print line on pipe example
PE(polyethylene)pi e temperature limitations of 2.13 pressure/temperature limitations
PE(polyethylene)pi e waterways 2.13 plastic under waterways
PE(polyethylene)pi e 2.13 throughout
PE(polyethylene)pi e thermal contraction/ex ansion 2.13 thermal contraction and expansion
PE(polyethylene)pi e tracer wire usage 2.13 tracer wire
PE(polyethylene)pi e insulation 2.22 insulating downstream customer piping
PE(polyethylene)pi e bending 3.13 field bendin
PE(polyethylene)pi e break-away in 3.13 break-away in or weak link
PE(polyethylene)pi e caution toe 3.13 caution tape
PE(polyethylene)pi e exposed PE inspections 3.13 examining buried pipe
PE(polyethylene)pi e handling 3.13 handling
PE(polyethylene)pi e odorizing 3.13 odorizing newly installed pipe
PE(polyethylene)pi e pigging 3.13 pigging of pipe
PE(polyethylene)pi e plow and plant 3.13 plowing and planting
PE(polyethylene)pi e pressure monitoring 3.13 monitoring of pressures
PE(polyethylene)pi e pulling limitations 3.13 pulling limitations
PE(polyethylene)pi e pulling-in 3.13 pulling-in
PE(polyethylene)pi e safe pulling forces 3.13 safe pulling forces
PE(polyethylene)pi e safe pulling forces table 3.13 safe oullina forces
PE(polyethylene)pi e storage and handling 3.13 storage of pipes and fittings; handling
PE(polyethylene)pi e tensile loading 3.13 tensile loading
PE(polyethylene)pi e warning toe 3.13 caution tape
PE(polyethylene)pi e weak link 3.13 break-away in or weak link
PE(polyethylene)pipe minimum permanent bending 3.13 field bending
radius table
PE pipe minimum temporary bend 3.13 plowing and planting
(polyethylene)p radius table
PE(polyethylene)pi e field bend diagram 3.13 field bending
PE(polyethylene)pi e clearances 3.15 clearances-steel and PE pipelines
PE(polyethylene)pipe capacities table 3.16 service pipe capacities;pipe-sizes and capacities
downstream of meter
PE(polyethylene)pi e bleed off 3.17 bleed off of plastic pipe
PE(polyethylene)pi e purging 3.17 throughout
PE(polyethylene)pi e pressure testing 3.18 pressure testing requirements for PE
PE(polyethylene)pi e minimum radius of curvature 3.19 pe-min radius of curvature
PE(polyethylene)piesplitting 3.19 pipesplitting
PE(polyethylene)pi e cooling times for fusions 3.23 butt fusion procedures
PE(polyethylene)pi e heat fusion 3.23 butt fusion procedures
PE(polyethylene)pi e re-tested 3.33 re-tested pipe
PE(polyethylene)pi e squeeze-off 3.34 throughout
PE(polyethylene)pi e casings for 3.42 installing e carrier pipe in casing
PE(polyethylene)pipe highway casing drawing E- 3.42 E-33947
33947
PE(polyethylene)pipe railroad casing drawing C 33947 3.42 E-33947,1
PE(polyethylene)pi e bridge crossings 2.13,3.13 2.13-above ground plastic pipe;3.13-installation
PE(polyethylene)pipe thermal contraction/expansion 2.13,3.13 2.13-thermal contraction and expansion;3.13-tensile
loading
PE(polyethylene)pi e tracer wire 2.13,3.13 2.13-tracer wire;3.13-tracer wire
2.13, 3.13,3.23,3.24, 2.13-joining of plastic pipe components; 3.13-qualified
PE(polyethylene)pipe joining of components 3 25 joiners;3.23-throughout;3.24-throughout;3.25-
thorou hout
36

Subject Details Sec/Section Subsection
PE(polyethylene)pipe static charges 3.13,3.17,3.33 3.13-static charges;3.17-purging plan;3.17-static
charges;3.33-static charges
PE(polyethylene) i e trenchless pipe installation 3.13,3.19 3.13-safe pulling forces;3.13-break-away pin or weak
pipe p p link;3.19-pipe splitting
PE(polyethylene)pipe electrofusion 2.13,3.24,4.31 App 2.13-joining of plastic pipeline components; 3.24-
A throughout;4.31 App A-221.030.001
PE(polyethylene)pi e pressure testing 3.18,4.31 App A 3.18-pressure testing for PE;4.31 App A-221.120.075
PE(polyethylene)pi e hydraulic butt fusion 3.23,4.31 App A 3.23-butt fusionprocedures;4.31 App A-221:030.010
PE(polyethylene)pipe butt fusion 3.23,4.31 App A 3.23-butt fusion procedures;4.31 App A-221.030.010;
4.31 App A-221.030.005
PE(polyethylene)pi e mechanical couplings 3.25,4.31 App A 3.25-general;4.31 App A-221.030.020
PE(polyethylene)pi e repair 3.33,4.31 App A 3.33-throughout;4.31 App A-221.060.015
PE(polyethylene)pi e mechanical service tees 4.31 App A 4.31 App A-221.030.015
PE(polyethylene)pi e install gas pipelines,OQ 4.31 App A 221.120.115
PE(polyethylene) design 2.14 valve types
valves
erimeter definition 1.1 glossary
5.11 -classifying leaks;5.11 -underground leak repair;
5.11 -follow-up inspections for residual gas;5.11 -leak
survey forms;GESH 2-underground leak determination;
perimeter 5.11,GESH 2 GESH 2-leak repair and residual gas checks;GESH 2-
follow-up inspections for residual gas;GESH 2-blowing
gas,odor calls,and damage events-recording
information: GESH 2-classifyina leaks
periodic meter 2.22,GESH 9 2.22-frequency of meter tests; GESH 9-general
chan eout program
periodic odorant OQ task 4.31 App A 221.090.030
testing
permanent repair
3.32A throughout
sleeves
permits brid e crossings 2.15 permits
permits boring 3.19 permits
personal protective
equipment PPE) definition 1.1 glossary
pete's plug 5.21 general;types of pressure recorders;field operating
guidelines for pressure gauges
photographic excavation damage 4.13 photograph requirements
requirements
pickling odorization 4.18 pickling newly installed piLLa
pig definition 1.1 glossary
pigging PE of eth lene pipe 3.13 installation;pigging of pipe
pigging after pressure testing 3.18 pressure testing for steel
pigging casing 3.42 installing steel carrier pipe in casing; pe carrier pipe in
casin
pilot definition 1.1 glossary
pilot filters maintenance 5.12 annual regulator station maintenance; 10 year overhaul-
diaphragm type regulators,relief valves&pilots
pilot heaters 5.22 pilot line heaters
pilot hole ali nment trenchless pipe installation 3.19 pilot hole alignment
pilot lights GESH 10 service to appliances;pilots; ignition
pilot line heaters 5.22 pilot line heaters
pinpointing definition 1.1 glossary
pinpointing and
centering 5.11,GESH 2 5.11 -pinpointing/centering
pipe data tables,steel pipe 2.12 steel pipe data tables
pipe coatings 3.12 mastic coating;tape wrap
pie lowering steel 3.12 moving or lowering steel pipe in service
pie storage and handling,steel 3.12 storage and handling of pipe
pipe storage and handling, PE 3.13 storage of pipes and fittings; handling
(polyethylene)pipe
pipe clearances,vegetation 3.15 vegetation clearance
pipe capacities,customer 3.16 pipe sizes and capacities downstream of meter
downstream
pipe capacities, PE(polyethylene) 316 service pipe capacities,pipe-sizes and capacities
.
pipe downstream of meter
pipe capacities,service lines 3.16 service pipe capacities,pipe-sizes and capacities
downstream of meter
37

Subject Details Sec/Section Subsection
pipe capacities,steel 3.16 service pipe capacities,pipe-sizes and capacities
downstream of meter
pipe purging, procedure 3.17 throughout
pipe splitting, PE(polyethylene)
3.19 pipe splitting
pipe and steel
pipe squeezing rocedure 3.34 throughout
pipe customer owned 4.22 throughout
2.13, 3.13,3.23,3.24, 2.13-joining of plastic pipe components; 3.13-qualified
pipe joining PE 3 25 joiners;3.23-throughout;3.24-throughout;3.25-
thorou hout
pipe dry line 3.12,3.13,3.18 3.12-dry line installations; 3.13-dry line installations;3.18
-dry line pipe
pipe repair, OQ task 4.31 App A 221.060.015
pipe squeezing, OQ task 4.31 App A 221.100.065
pipe purging, OQ task 4.31 App A 221.120.080
pipe bending,steel 3.12,4.31 App A 3.12-pipe bends;4.31 App A-221.120.085
pipe distortion dents steel pipe 3.32 throw hout
pipe installation PE(polyethylene)pipa 3.13 throughout
pipe installation trenchless pipe 3.19 throughout
pipe joining PE(polyethylene)pipe, 3.13 qualified joiners
qualified joiners
pipe joining steel 3.22 throughout
pipe joininq welding 3.22 throw hout
pipe joining butt fusion 3.23 butt fusion procedures
pipe joining certification card 3.23 pipe joining certification record
pipe joining drag pressure 3.23 determining drag pressure
pipe joining fusion machine 3.23 butt fusion procedures
pipe joining fusion pressure 3.23 butt fusion procedures
pipe joining heat fusion 3.23 throughout
pipe joining heating tool 3.23 heating tool
pipe joining materials 3.23 butt fusion procedures
pipe joining marking 3.23 marking joints
pipe'joininq mechanical 3.25 throughout
pipe'joining general GESH 6 pipe'joining
pipe joining electrofusion 3.24,4.31 App A 3.24-throughout;4.31 App A-221.030.001
pipe repair PE(polyethylene)pipa 3.33 throughout
pipe repair steel 3.22,3.32 3.22-removal or repair of weld defects or cracks;3.32-
throughout
pipe repair general, OQ task 4.31 App A 221.060.015
pipe splitting determining factors 3.19 determining factors
pipe splitting equipment requirements 3.19 equipment requirements-steel or PE;equipment
requirements-PE
pipe splitting oinin of replacement pipe 3.19 pipesplitting
pipe splittinq pull forces 3.19 pullback
pipe splitting replacement procedure 3.19 pipes littin
pipe splitting trenchless pipe installation 3.19 throughout
methods
pipe tables,steel 2.12 steel pipe data tables
pipeline definition 1.1 glossary
pipeline companies definition 1.1 glossary
pipeline inspection exposed pipe evaluation 3.44 pipeline inspection cameras
camera
pipeline markers see markers
pipeline safety definition 1.1 glossary
pipeline safety
management system GESH Foreword Foreward
principles
pipe-to-soil procedure 5.14 structure-to-electrol e potential(pipe-to-soilpotential)
pipe-to-soil OQ task 4.31 App A 221.110.055
it gauge steel pipe repair 3.32 throw hout
its meters 2.22 pits and vaults
pitting definition 1.1 glossary
planned meter 2.22,GESH 9 2.22-frequency of meter tests; GESH 9-general
chan eout program
planning worksheet, emergency planning worksheet;service outage planning&
shutdown& GESH 5 restoration of service worksheet;steps for restoration of
restoration service
plastic pipe see PE pipe
38

Subject Details Sec/Section Subsection
plidco split-sleeve steel repair clamp 3.32A detailed procedures for use of"plidco split-sleeve"
ermanente steel repair clam
plowing PE
of eth lene i e 3.13 plowing and planting
lu definition 1.1 glossary
plug valves design 2.14 valve types
plug valves lubrication 5.13 plug valve lubrication procedures
plug valves maintenance 5.13 maintenance requirements for valve types;general valve
maintenance and installation notes
plugging steel for repairs 3.32 tapping and plugging procedures
PMC program 2.22,GESH 9 2.22-frequency of meter tests; GESH 9general
pneumatic
missilin / iercin 3.19 pneumatic missiling/piercing
polarization definition 1.1 glossary
police/fire standing by service request GESH 1 priority 1 -emergency requests
polyethylene definition 1.1 alossary
of eth lene valves maintenance 5.13 polyethylene valves
5.10-regulator stations;5.12-portable regulator station
portable regulator 5.10,5.12 maintenance;5.12-5 year overhaul-flexible element&
stations boot type regulators and relief valves;5.12-10 year
overhaul-diaphragm type regulators,relief valves&pilots
post incident GESH 13 post incident evaluations
evaluations
potholing trenchless pipe installation 3.19 tracking and potholing while crossing utilities
power plants telemetry 2.25 power plants
Powercrete R95 curing time 3.12 liquid epoxy coating
Powercrete R95 installation 3.12 liquid epoxy coating
PP&L territory proximity of gas meters 2.22 3 foot rule
pre-check layout and
inspection joint ditch design 3.14 joint ditch
pre-check layout and layout 3.14 layout
inspection
pre-check layout and pre-construction inspection 3.14 pre-construction inspection
inspection
pre-check layout and pre-construction notification 3.14 pre-construction notification
inspection
prefabricated unit definition 1.1 glossary
(pressure vessel
prefabricated welded definition 1.1 glossary
assemblies
pressure compensation 2.22 pressure compensation
3.12-monitoring of pressures;3.13-monitoring of
pressure monitoring of 3.12,3.13,3.32,3.33 pressures; 3.32-general;3.32-monitoring of pressure;
3.33-monitoring of pressure
pressure calibration
standards 5.21 test bench gauge verification;maintenance frequencies
pressure chart calibration and inspections 5.12 chart recorders and telemetry
recorders
pressure meters 2.22 pressure compensation
compensation
pressure drop definition 1.1 alossary
pressure factor formula 2.22 pressure compensation
pressure gauges calibrations(accuracy checks 5.21 throughout
pressure recorders requirements for use 2.23 telemetering and pressure recorders
pressure recorders calibrations(accuracy checks) 5.21 field operating guidelines for pressure recorders;
maintenance frequencies
pressure test definition 1.1 glossary
pressure testing as pipelines,OQ task 4.31 App A 221.120.075
pressure testing after backfilling 3.15 pressure testing after backfillin
pressure testing class location consideration 3.18 pressure testing for steel
pressure testing fabricated unit 3.18 pressure testing for steel
pressure testinq new pipe 3.18 throughout
pressure testing re-installation testing 3.18 pressure testing for steel
pressure testing procedures 3.18 throughout
pressure testing recordkeeping 3.18 recordkee in
pressure testing requirements for high pressure 3.18 pressure testing requirements-high pressure steel
steel pipeline system
39

Subject Details Sec/Section Subsection
requirements for IN pressure pressure testing requirements-high pressure steel
pressure testing steel 3.18 pipeline systems; pressure testing requirements-
intermediate pressure steel pipeline system
pressure testing requirements for plastic pipe 3.18 pressure testing for PE
pressure testing short section of pipe 3.18 pressure testing for steel;pressure testing for PE
pressure testing
transmission testing in WA 3.18 notification to Washington UTC prior to pressure testing
state transmission pipelines
3.16-installation of requirements; 3.18-reinstating
pressure testing reinstating services 3.16,3.18,3.32,5.11 service; 3.32 monitoring of pressure;5.11 -reinstating a
damaged service line
pressure testing PE 3.18,3.25 3.18-pressure testing for PE;3.25-throughout
pressure testing replaced segments 3.18,5.11 3.18-throughout;5.11 -pressure testing replaced
segments
pressure testing OQ task 4.31 App A 221.120.075
pressure vessel definition 1.1 glossary
re-tested pipe steel 3.32 re-tested steel pipe
re-tested pipe PE(polyethylene)pi e 3.33 re-tested pipe
prevention of purging 3.17 prevention of accidental ignition
accidental ignition
prevention of repair of PE(polyethylene) 3.33 static charges
accidental ignition pipe
prevention of squeeze-off of PE 3.34 prevention of accidental ignition by static electricity
accidental ignition
prevention of OQ task 4.31 App A 221.230.040
accidental ignition
print lines PE(polyethylene)pi e 2.13 print line on pipe example
priority 1 emergency GESH 1 priority 1 -emergency requests; priority 1 and 2 arrival
requests times
priority 2 emergency GESH 1 priority 2 requests;priority 1 and 2 arrival times
requests
procedure qualification welding 3.22 qualification of welders
record PQR
procedures for
competing carbon detecting Instruments GESH 3 detecting instruments
monoxide orders
procedures for
competing carbon documentation GESH 3 documentation
monoxide orders
procedures for
competing carbon initial determination GESH 3 initial determination
monoxide orders
propane definition 1.1 glossary
propane conversions GESH 10 conversion vs.configuration of equipment
protection see barricades
protective system trenching 3.15 shoring and excavating safety
rovers maintenance cycles 2.22 prover calibration interval
rovers calibration interval 2.22 prover calibration interval
rovers SNAP prover 2.22 prover calibration interval
rovers transfer prover 2.22 prover calibration interval
proximity 2.12-WA State Proximity Considerations;2.23-regulation
considerations in 2.12,2.23,4.17 of high pressure to service pressure;4.17-uprate in state
Washington of Washington
PSI(pounds per definition 1.1 glossary
square inch
PSIA(pounds per definition 1.1 glossary
square inch,absolute
PSIG(pounds per definition 1.1 glossary
square inch,gauge)
public awareness
4.13 public awareness program
program
public utility definition 1.1 glossary
commission
pull pits 3.19 determining factors
pullback trenchless pipe installation 3.19 pullback
pulling forces PE(polyethylene)pipe into a 3.13 plowing and planting
trench
pulling forces safe pulling forces for PE 3.13 safe pulling forces
(polyethylene)pipe table
40

Subject Details Sec/Section Subsection
pulling forces safe pull force formula 3.13 safe pulling forces
pulling-in PE(polyethylene)pipa 3.13 pulling-in
pulses to customer usage 2.25 pulses to customer
pumpkin definition 1.1 glossary
purge definition 1.1 glossary
purging bleed off of plastic pipe 3.17 bleed off of plastic pipe
purging bleed off of steel pipe 3.17 bleed off of steel pipe
purging flaring 3.17 flaring of natural gas
purging injection rate 3.17 injection rate
purging lar e pipelines,>6"diameter 3.17 large pipelines
purging laterals 3.17 purging main with laterals
purging nitrogen 3.17 purging with nitrogen
purging Ian for purging 3.17 plan for purging
purging services 3.17 purging services
purging small pipelines,6"and less 3.17 small pipelines
diameter
purging static charges,buildup 3.17 purging plan;static charges
purging venting and blowdown 3.17 venting and blowdown
3.16-excess flow valve(EFV)installation procedure-
purging excess flow valve(EFV) 3.16,3.17 service tee style;3.16-excess flow valve(efv)installation
procedure-in line stick or coupling style;3.17-purging
services with an excess flow valve
purging OQ task 4.31 App A 221.120.080
qualifications of
persons to to join joining methods,electrofusion 3.24 qualifying joining procedures
plastic pipe
qualified definition 1.1 glossary
qualifying joining joining methods,electrofusion 3.24 qualifying joining procedures
procedures
qualifying joining joining methods, heat fusion 3.23 qualifying joining procedures
procedures
quality
assurance/quality overview 4.61 general;objectives of the QA/QC program
control(QA/QC)
program
radiant heat definition 1.1 glossary
radiographic definition 1.1 glossary
inspection
radiographic See NDT
inspection
radius of curvature PE of eth lene pipe 3.19 PE-min radius of curvature
radius of curvature steel pipe 3.19 steel-min. radius of curvature
railroad casing detail
drawingE-33947 3.42 E-33947,1
range definition 1.1 glossary
RCW chapter 13 building permits near transmission utiltity easements or
19.122.033(4) permits 4. rights of wa
RCW chapter
19.122.050 1 4.13 WA excavator notifications
RCW chapter 4.13 avista damage to other facility operators;WA excavator
19.122.053 notifications
RCW chapter
19.122.053 1 2 4.14 WA damage reporting
RCW chapter
19.122.053(3)(a) 4.14 WA reporting requirements
though n
RCW chapter
19.122.130 4.13 WA excavator notifications
RCW chapter 19.27 4.13 building permits near transmission utiltity easements or
rights of way
RCW chapter 4.14 250+psig pipelines map submission(Washington)
81.88.080
read definition 1.1 alossary
readily detectable 4.18 readily detectable level(RDL)
level RDL
reading definition 1.1 glossary
reaming trenchless pipe installation 3.19 reaming
41

Subject Details Sec/Section Subsection
re-classification of 5.11,GESH 2 5.11 -re-classification of leaks; GESH 2-re-classification
leaks of leaks
reconnection fees GESH 11 general
recordkeeping pressure tests 3.18 recordkee in
recordkeeping steel repairs 3.32 recordkee in
recordkee in PE(polyethylene)pi e repairs 3.33 recordkee in
recordkee in safety-related condition reports 4.12 recordkee in
recordkeeping locates 4.13 recordkee in
recordkeeping MAOPs 4.15 recordkee in
recordkeeping upratinq 4.17 recordkeeDinci
recordkeepinq customer owned service lines 4.22 recordkee in
recordkeeping leak survey 5.11 recordkeeping and reporting
recordkeeping maintenance 5.12 recordkee in
recordkeeping regulator stations 5.12 recordkee in
recordkeeping valve maintenance 5.13 recordkeeDinci
recordkeeping cathodic protection 5.14 recordkee in
recordkeeping exposed steel piping reports 5.14 exposed pipe reads
recordkeeping patrolling5.15 recordkee in
recordkeeping vault maintenance 5.18 recordkee in
recordkee in CGI's 5.19 recordkeeDinci
recordkeeping combustible gas detectors 5.19 recordkee in
recordkeeping atmospheric corrosion 5.20 recordkee in
recordkeeping pressure gauge calibrations 5.21 recordkee in
recordkeeping heaters 5.22 recordkee in
recordkeeping odorization 4.18,5.23 4.18-recordkee in ;5.23-recordkee in
recreational vehicles service lines to 3.16 service lines to recreational vehicles
rectifier definition 1.1 glossary
rectifier adjustment&repair,OQ task 4.31 App A 221.110.050
rectifier Output testing,OQ task 4.31 App A 221.110.060
reduction definition 1.1 glossary
re-establishment fees GESH 11 qeneral
reference electrode definition 1.1 glossary
regulation definition 1.1 glossary
regulator definition 1.1 glossary
regulator control and sensing lines 2.23 control and sensing lines
regulator high to service pressure 2.23 regulation of high pressure to service pressure
regulation
regulator intermediate to service 2.23 regulation of intermediate pressure to service pressure
pressure re ulation
regulator pressure recorders 2.23 telemetering and pressure recorders
regulator pressure regulation 2.23 regulation of intermediate pressure to service pressure;
regulation of high pressure to service pressure
regulator proximity consideration in WA 2.23 regulation of high pressure to service pressure
State
regulator sensing and control lines 2.23 control and sensing lines
regulator sizing requirements 2.23 sizing requirements
regulator telemetry 2.23 telemetering and ressure recorders
regulator pressure reduction,two stage 2.23 regulation of high pressure to service pressure
regulator valves for regulator stations 2.23 valves
regulator drawings 2.24 Appendix-A
regulator farm tap 2.24 Appendix-A
regulator meter set tables 2.24 Appendix-A
regulator obsolete regulators 2.24 obsolete regulators
regulator relief valve capacities table 2.24 relief valve capacities at set point
regulator station fencing drawing L- 2.24 Appendix-A
36082
regulator tables for sizing 2.24 regulator capacity tables
regulator annual maintenance,station 5.12 annual regulator station maintenance
regulator bypassing stations, procedure 5.12 procedure for regulator stations and meter set bypassing
regulator stations and elevated pressure meter sets;
regulator district regulator stations 5.12 district regulator station relief capacity review;general
station inspection;annual regulator station maintenance;
ate stations;maintenance frequencies
regulator maintenance frequencies 5.12 maintenance frequencies
regulator station annual maintenance 5.12 annual regulator station maintenance
regulator station, permanent bypass 5.12 maintenance of regulator stations operating on permanent
bypass
regulator station abandonment 5.16 regulator station abandonment
42

Subject Details Sec/Section Subsection
regulator vent orientation 2.22,5.20 2.22-3 foot rule;2.22-10 foot rule;5.20-inspection
requirements
regulator capacity of 2.23,2.24 2.23-capacity;2.24-regulator capacity tables
regulator sizing 2.23,2.24,GESH 6 2.23-sizing requirements;2.24-regulator capacity tables;
GESH 6-meter and regulator sizin
regulator design 2.23,5.12 2.23-throughout;5.12-service regulators;5.12-regulator
stations and elevated pressure meter sets
regulator numbering of stations 2.23,5.12 2.23-regulator station numbering;5.12-regulator station
numbering
regulator installations GESH 6 GESH 6-installation of meters, ERTs and regulators
regulator validation GESH 7 regulator validation
regulator replacements GESH 9 regulator replacements
regulator station bypassing,OQ task 4.31 App A 221.080.025
regulator station bypassing,OQ task 4.31 App A 221.080.025
regulator annual maintenance,station, 4.31 App A 221.080.030
OQ task
regulator station annual maintenance, 4.31 App A 221.080.030
OQ task
regulator station 5/10 year maintenance,OQ 4.31 App A 221.080.035
task
regulator station station bypassing,OQ task 4.31 App A 221.080.025
b assin
regulator station quantities measured,telemetry 2.25 regulator sites and pressure monitoring
numbering
regulator vent definition 1.1 glossary
regulator vent design of 2.22 regulator and relief vent desi n
regulator,service definition 1.1 glossary
reinstating services after excess flow valve(EFV) 3.16 installation of excess flow valves
retro-fit
reinstating services disconnected 3.18 reinstating service lines
reinstating services after abandonment 5.17 reinstatina cias facilities
reinstating services damaged 3.18,3.32 3.18-reinstating service;3.32-service lines
reinstating services customer piping GESH 2 reinstatement of service; reinstating a damaged service
line
relief definition 1.1 glossary
relief capacities table 2.24 relief ca acit
relief annual capacity review 5.12 district regulator station relief capacity review;gage station
regulator and relief set point review
gate station regulator and relief set point relief;
maintenance of overpressure protection devices;5 year
relief valve maintenance,testing 5.12 overhaul-flexible element&boot type regulators and relief
valves; 10 year overhaul-diaphragm type regulators,relief
valves&pilots
relief vent design of 2.22 regulator and relief vent design
relight chief GESH 5 steps for restoration of service
re-light turn on order GESH 7 re-light turn on order
remediation atmospheric corrosion 5.20 remediation;AC corrective order types and remediation
time quidelines
remote control valve definition 1.1 glossary
RCV
remote meter definition 1.1 glossary
remote meter meter set location,protection, 2.2 meter set location, protection,and barricades
and barricades
remote meter set service lines to floating 2.2,3.16 2.2-meter set location, protection,and barricades 3.16-
structures service lines to floating structures
remote methane leak definition 1.1 glossary
detector RMLD
remote methane leak
detector RMLD 5.11 leak detection instruments
removing meters damage to meter sets GESH 9 damage to meter sets
removing meters handling and transporting GESH 9 handling and transporting removed meters
removed meters
removing meters notification of service dispatch GESH 9 notification of service dispatch
removing meters removal of meters on GESH 9 removal of meters on manifolds
manifolds
removing meters removal of single meter GESH 9 removal of single meter
renewable nautral gas definition 1.1 glossary
repair steel 3.32 throughout
43

Subject Details Sec/Section Subsection
repair PE(polyethylene)pi e 3.33 throughout
repair temporary 3.33.GESH 2 3.33-temporary repairs; GESH 2-temporary repairs/cold
weather exceptions; GESH 2-re-classification of leaks
repair and patching repair damaged coatings and
3.12 repair and patching using coating patch
usin a coatinatch holidays
repair charts 3.32 steel repair selection charts
repair clams general use 3.32 repair clamps and sleeves
repair clams Adams 3.35 throughout
repair clams Romac 3.35 romac style ss1 procedures
repair coupling electrofusion 3.24 repair coupling joining procedure
repair sleeves 3.32,3.32A 3.32-repair clamps and sleeves,3.32A-throughout
repair,general,OQ 4.31 App A 4.31 AppA
repair,underground
leaks 5.11 underground leak repair
replaced service line definition 1.1 glossary
reDlacina steel Dipe repair segments 3.32general;steel repair selection charts
reportable incident
criteria GESH 13 reporable incident criteria
residential meter set Drawing A-37102 2.24 Appendix-A
residential meter set Drawing A-37103 2.24 Appendix-A
residential meter set Drawing B-35207 2.24 Appendix-A
high pressure
5.11 -follow-up inspections for residual gas; GESH 2-
residual follow up 5.11,GESH 2 follow-up inspections for residual gas;GESH 2-follow-up
inspections inspections for residual gas;GESH 2-blowing gas,odor
calls and damage events-recording information
resistivity definition 1.1 glossary
restoration of service can't gain entry situations GESH 5 can't gain entry situations
restoration of service cold weather GESH 5 cold weather
restoration of service dealer notification GESH 5 dealer notification
restoration of service b marking of meters turned on GESH 5 marking of meters turned off by co.
y co
restoration of service meters turned on by other-than GESH 5 meters turned on by other-than avista
avista
restoration of service pressurization GESH 5 pressurization
restoration of service Duraing GESH 5 ur in
restoration of service restoring service GESH 5 restoring service
restoration of service steps GESH 5 steps for restoration of service
reverse current switch definition 1.1 qlossary
riser definition 1.1 glossary
risers service 3.16 service risers
risers, idle 2.22,5.16 2.22-idle services;5.16-idle meters and idle services;
5.16-maintenance requirements
risers, isolated 5.14 isolated steel;isolated steel risers; isolated services
road construction role GESH 13 pre-construction emergency planning for road projects
coordinator
Romac SS1 repair 3.35 romac style ss1 procedures
clamps
roping minimum distance table 3.12 moving or lowering steel pipe in service
roping steel lowering) 3.12 moving or lowering steel pipe in service
rotary manufacturer pressure rating 2.24 rotary meters table
rotary meter general 2.22 meter types
rotary meter capacity 2.24 rotary meters table
rotary meters meter capacity 2.24 rotary meters table
runaway furnace GESH 1 priority 1 -emergency requests
rupture-mitigation definition 1.1 glossary
valve RMV
rust definition 1.1 glossary
sacrificial protection definition 1.1 glossary
saddle aoining 3.24 saddle'oining procedure
safe operating limit definition 1.1 qlossary
safety excavating 3.15 shoring and excavating safety
safety and health 5.23 safety and health department notification
department
safety data sheet definition 1.1 glossary
safety devices definition 1.1 qlossary
safety equipment GESH 4 safety equipment
safety in ection report GESH 12 safety inspection re ort
44

Subject Details Sec/Section Subsection
safety inspection recordkeeping GESH 12 recordkee in
safety inspections can't gain entry situations GESH 12 can't gain entry situations
safety inspections duplicate orders GESH 12 duplicate orders
safety inspections field requests GESH 12 field requests
safety inspections finished work GESH 12 finished work
safety inspections minimum qualifications GESH 12 minimum qualifications
safety inspections permits GESH 12 permits
safety inspections recognized codes GESH 12 recognized codes
safety inspections responsibilities GESH 12 responsibilities
safety inspections of
customer piping and GESH 12 GESH 12-throughout
appliances
safety-related corrosion that reduces wall 4.12 reporting of safety-related conditions
conditions thickness
safety-related earthquake 4.12 reporting of safety-related conditions
conditions
safety-related exceptions for filing reports 4.12 exceptions to reporting safety related conditions
conditions
safety-related flooding 4.12 reporting of safety-related conditions
conditions
safety-related landslides 4.12 reporting of safety-related conditions
conditions
sand padding 3.15 padding material
Save-a-Valve nipple steel pipe 3.32 mueller save-a-valve nipple orequivalent
SCADA alarms priority 1 -emergency GESH 1 priority 1 -emergency requests
SCADA System data collection 2.25 data path and uses
scraped/exposed pipe priority 2 requests GESH 1 priority 2 requests
by evacation
scratch repair pipe joining 3.25 procedure for removing scratches from PE pipe prior to the
procedure installation of a mechanical tapping tee
sealant gun injection valve maintenance 5.13 sealant gun injection
sealing and ventilation vault design 2.42 sealing and ventilation
sealing conduit ends 3.42 conduit
seamless pipe definition 1.1 qlossary
seamless pipe 3.42 casing specifications
segment(pipeline
definition 1.1 glossary
segment)
self tappinq tee definition 1.1 glossary
self-audits leak survey 5.11 self-audits
3.32A-detailed procedures for use of"plidco split-sleeve"
self-contained permanente steel repair clamp;3.32A-detailed
breathing apparatus 3.32A,3.34,3.35 procedures for use of Id williamson permanent hemi-head
(SCBA) repair spheres";3.34-prevention of accidental ignition by
static electricity;3.35precautions
semiconductor
detector GESH 3 types of detectors
sensing lines requirements 2.25 sensing lines
sensing taps line requirements 2.23 control and sensing lines
separation definition 1.1 glossary
service service line definition 1.1 glossary
service department natural gas accounts GESH 11 general
fees
service dispatcher restoration of service GESH 5 steps for restoration of service
service head adapter definition 1.1 glossary
service head adapters compression type 3.25 procedure for installing approved compression type service
head adapters
service head adapters slip lock type 3.25 procedure for installing approved slip lock type service
head adapters
service line valves 2.14 service line valves
service line joining procedures 3.24 service line joining procedures
service line customer owned 4.22 throughout
service outage
planning&restoration GESH 5 service outage planning&restoration of service worksheet
of service worksheet
service regulator Idefinition 1 1.11 glossary
service regulator 2.23,2.24,5.12 2.23-design requirements;2.24-throughout;5.12-
service regulators
45

Subject Details Sec/Section Subsection
service request
GESH 17 recording the scene
number
service valve and
outlet valve ownership GESH 7 service valve and outlet valve ownership
service valve or
definition 1.1 glossary
service-line valve
service valves re lacment,OQ task 4.31 App A 221.070.020
service-line valve see service valve
services branch services 3.16 branch(split)service
services buildings,service lines into 3.16 service lines into buildings
services buildings,service lines under 3.16 service lines passing under buildin s
services excess flow valves(EFVs) 3.16 excess flow valves;capacity of EFV;installation of excess
flow valve
services high pressure services 3.16 EFV-high pressure services
services idle new services not in use 3.16 new service lines not in use
services insertion of PE into steel 3.16 insertion of old steel services along steel main
services location considerations 3.16 location considerations
services multi-meter manifolds 3.16 service risers for multi-meter manifolds
services pipe capacities,customer 3.16 pipe sizes and capacities downstream of meter
downstream
services pipe capacities, int.pressure 3.16 service pipe capacities
Svc
services split services 3.16 branch(split)service
services valves for 3.16 service-termination valve;service risers-valves
services curb valves 3.16 curb valves
services customer owned 4.22 throughout
services bar holing 5.11 follow-up inspections for residual gas
services elevated service pressure 5.12 maintenance of elevated service pressure accounts
maint.
services abandonment 5.16 general;abandoning gas facilities; inactivating gas meter
facilities;idle meters and idle services
services regulators,service 2.23,2.24,5.12 2.23-general; 2.24-throughout;5.12-service regulators
services reinstating 3.18,3.32 3.18-reinstating services;3.32-service lines
3.18-pressure testing requirements;3.18-notification to
Washington UTC prior to pressure testing transmission
pipelines;3.18-pressure testing requirements-high
services pressure testing 3.18,4.31 App A pressure steel pipeline systems;3.18-pressure testing
requirements-intermediate pressure steel pipeline
systems;3.18-pressure testing requirements-plastic
pipeline systems;3.18-pressure test procedures;4.31
App A-221.120.075
sewers clearances from 3.15 clearances-steel and PE pipelines
sewers boring near 3.19 longitudinal separation
5.11-gas present in sewer or duct system; GESH 2-gas
sewers gas present within sewers 5.11,GESH 2 present in sewer or duct system;GESH 2-detection of
other combustible gases
shall definition 1.1 glossary
shear and tensile plastic pipe 3.13 shear and tensile stresses
stresses
shielding definition 1.1 glossary
shielding flux welding 3.22 weld procedure qualification
shoe plowing 3.13 plowing and planting
shoring ID rule 3.15,GESH 4 3.15-shoring and excavating safety; GESH 4-trench
safety
shoring OR rule 3.15,GESH 4 3.15-shoring and excavating safety; GESH 4-trench
safety
shoring WA rule 3.15,GESH 4 3.15-shoring and excavating safety; GESH 4-trench
safety
short definition 1.1 alossary
short section of pipe definition 1.1 glossary
short section of pipe usage 3.18 pressure testing for steel;pressure testing for PE
shorted casings,CP 5.14 shorted casings; maintenance and remediation timeframes
remediation and frequencies
shorted casings,leak
survey requirement
5.11 special surveys
shorted pipeline
definition 1.1 glossary
casin
should Idefinition 1.11 glossary-
46

Subject Details Sec/Section Subsection
shut-down of service closing meters GESH 5 closing meters
shut-down of service EOP-Zone shut down GESH 5 EOP-Zone shut down
shut-down of service maps&lists GESH 5 maps&lists
shut-down of service marking of closed meters GESH 5 marking of closed meters
shut-off valve
(pertaining to definition 1.1 glossary
overpressure
protection)
silt screening discharge miti ation plan 3.19 HDD discharge mitigation plan
single pipe ground Drawing A-34175 2.24 Appendix-A
support drawing
single run district Drawing E-33952 2.24 Appendix-A
regulator,2-in inlet
single run district Drawing E-35783 2.24 Appendix-A
regulator,4-in inlet
farm taps;general station inspection;farm taps and HP
single service farm tap 5.12 services; 10 year overhaul-diaphragm type regulators,
relief valves&pilots;maintenance frequencies
single service farm tap definition 1.1 glossary
SSFT
sleeves, repair 3.32A 3.32A-throw hout
sleeving definition 1.1 glossary
sleeving 3.32 sleevin
slug purging 3.17 purging with nitrogen
small commercial set Drawing B-35207 2.24 Appendix-A
High pressure
small diaphragm Drawing C-35209, pg 1 2.24 Appendix-A
meter set drawing
smart pig definition 1.1 glossary
SNAP prover 2.22 prover calibration interval
snow action plan GESH 13 snow action plan
snow areas 3.16 services in heavy snow areas
snow/ice covering priority 2 requests GESH 1 priority 2 requests
meter
soap test definition 1.1 glossary
soapy rag procedure 3.34 wet soapy rag procedure
soil potential gradient definition 1.1 glossary
soil types descriptions and definitions 3.44 soil type descriptions
sour as definition 1.1 alossary
source of ignition definition 1.1 glossary
span of control definition 1.1 glossary
special concerns boilers GESH 12 boilers
special concerns copper tubing GESH 12 copper tubing
special concerns corrugated stainless steel GESH 12 CSST
tubing
special concerns unvented heaters- GESH 12 unvented heaters-manufactured homes
manufactured homes
special concerns unvented heaters and GESH 12 unvented heaters and decorative appliances
decorative appliances
special leak surveys before paving 5.11 special surveys;maintenance frequencies
special leak surveys disasters 5.11 special surveys
special leak surveys near sewer and water 5.11 special surveys
special leak surveys unstable soils 5.11 special surveys
special leak surveys after lowering steel pipe 3.12,5.11 3.12-moving or lowering steel pipe in service;5.11 -
special surveys
4.17-uprating requirements;4.17-prior to pressure
special leak surveys uprating 4.17,5.11 increase;4.17-during the pressure increases;4.17-
u rate acceptability criteria;5.11 -special surveys
special leak surveys shorted casings 5.11,5.14 5.11 -special surveys;5.14-shorted casings
5.11 -underground leak investigation;5.11 -service line
special leak surveys after 3rd-party damage repairs 5.11,GESH 2 leak survey;GESH 2-underground leak investigation;
GESH 2-service line leak survey
specified minimum definition 1.1 glossary
field strength SMYS
specified minimum steel pipe 2.12 design formula for steel pipe
field strength SMYS
specified minimum PE(polyethylene)pipe 2.15 design requirements
field strength SMYS
47

Subject Details Sec/Section Subsection
specified minimum welding 3.22 throughout
field strength SMYS
speed of travel formula 3.22 determining seed of travel
split services excess flow valves EFVs 3.16 branch(split)service
splittinq,pipe 3.19 pipe s littin
spot check definition 1.1 glossary
spot check,meter GESH 2, 16 GESH 2, GESH 16-meters of check
squeeze-off of PE tools 3.34 squeeze-off tools
squeeze-off of PE 3.34 throughout
squeeze-off of PE prevention of accidental 3.17,3.34 3.17-prevention of accidental ignition;3.34-prevention of
i nition accidental ignition by static electricity
squeeze-off of PE OQ task 4.31 App A 221.100.065
farm taps;general station inspection;farm taps and HP
SSFT maintenance 5.12 services; 10 year overhaul-diaphragm type regulators,
relief valves&pilots;maintenance frequencies
standard configuration definition 1.1 qlossary
standard metering definition 1.1 glossary
ressure
static charges purging 3.17 purging plan;static charges;bleed off of plastic pipe;small
pipelines
static charges aerosol suppression 3.34 aerosol static suppression procedure
3.13-static charges;3.17 purging plan;3.17-static
static charges 3.13,3.17,3.33,3.34 charges;3.33-static charges,3.34-prevention of
accidental ignition by static electricity;3.34-prevention of
static electricity procedures
static electricity definition 1.1 glossary
static suppression
3.34 aerosol static suppression procedure
spray
station bypassing station bypassing,OQ task 4.31 App A 221.080.025
station maintenance OQ Task 4.31 App A 221.080.030
steel ball valves valve types 2.14 valve types
steel carrier pipe casing 3.42 installing steel carrier pipe in casing
steel gate valves valve types 2.14 valve t es
steel pipe ASTM standards that apply 2.12 flanged connections
steel pipe coating and marking 2.12 steel pipe coating and marking
steel pipe composition of line pipe 2.12 manufacturing design and composition of line pipe
steel pipe converting an acquired system 2.12 converting an acquired system
steel pipe deflection 2.12 deflection and bending stress
steel pipe design formula for 2.12 design formula for steel pipe
steel pipe design of pipeline components 2.12 design of pipeline components
steel pipe design tables(steel pipeline 2.12 steel pipe data tables
data
steel pipe longitudinal stress 2.12 longitudinal stress
steel pipe specifications for steel line 2.12 pipe specification
pipe
steel pipe thermal contraction/ex ansion 2.12 thermal contraction and expansion
steel pipe 2.12 throughout
steel pipe aboveground installations 2.12 protection of aboveground steel pipelines
steel pipe easements 2.12 easement considerations
steel pipe corrosion protection 2.12 corrosion protection
steel pipe replacing less than 100 feet 2.32 replacing steel services
steel pipe replacing more than 100 feet 2.32 replacing steel services
in length
steel pipe lowering decision flowchart 3.12 steel pipe lowering decision flowchart
steel pipe ARO coating of 3.12 liquid epoxy coating
steel pipe coating,thin film 3.12 voltage settings for thin film coatings FBE
steel pipe cold applied tape wrap 3.12 tape wrap
steel pipe elbows 3.12 elbows
steel pipe epoxy coating 3.12 liquid epoxy coating
steel pipe FBE coating 3.12 tape wrap;voltage settings for thin film coatings(FBE);
voltage settin s for ARO pipe
steel pipe lowering 3.12 moving or lowering steel pipe in service
steel pipe mastic coating 3.12 mastic coating
steel pipe non-destructive testing NDT 3.12 visual inspection
steel pipe storage and handling 3.12 storage and handling of pipe
steel pipe stringing 3.12 strinainal
steel pipe tape wrap 3'121 tape wrap
steel pipe warning toe 3.121 caution to e
48

Subject Details Sec/Section Subsection
steel pipe wax type tape wrap 3.12 tape wrap
steel pipe coating thickness 3.12 coating thickness for new pipe
steel pipe minimum bend radius table 3.12 pipe bends
steel pipe clearances 3.15 clearances-steel and PE pipelines
steel pipe capacities 3.16 service pipe capacities;pipe-sizes and capacities
downstream of meter
steel pipe section replacement 3.16 steel service replacement
references
steel pipe bleed off 3.17 bleed off of steel pipe;bleed off of plastic pipe
steel pipe pressure testing 3.18 pressure testing for steel
steel pipe minimum radius of curvature 3.19 steel-min. radius of curvature
steel pipe radius of curvature when 3.19 steel-min. radius of curvature; PE-min.radius of
steel pipe ioininq 3.22 throughout
steel pipe welding 3.22 throughout
steel pipe re-tested 3.32 re-tested steel pipe
steel pipe repair 3.32 throughout
steel pipe casings for 3.42 installing steel carrier pipe in casing
steel pipe highway casing drawing E- 3.42 E-33947,2
33947
steel pipe railroad casing drawing E- 3.42 E-33947,1
33947
steel pipe replacing segments 2.32,3.16 2.32-replacing steel services;3.16-steel service
replacement
steel pipe exposed steel inspections 4.13,5.11,5.14 4.13-on site inspections-general;5.11 -underground leak
repair; 5.14-exposed pipe reads
steel pipe bending 2.12,3.12,4.31 App 2.12-deflection and bending stress;3.12-pipe bend;4.31
A App A-221.120.085
3.18-pressure testing requirements for steel;3.32-
steel pipe pressure testing 3.18,3.32,4.31 App general; 3.32-service lines;3.32-canning(barreling);3.32
A -replace segments of pipe;3.32-leak repair and residual
as checks;4.31 AppA-221.120.085
steel pipe visual inspection of 3.12 visual inspection
steel pipe components joining of 2.12 oining of steel pipeline components
steel pipe lowering flowchart 3.12 steel pipe lowering decision flowchart
steel plug valves valve types 2.14 valve types
steps for restoration of
GESH 5 steps for restoration of service
services
stormwater erosion
control 3.43 storm water permitting requirements
strainer inspection 5.12 maintenance of elevated service pressure accounts; 180
day inspection criteria;strainer/filter inspection
stray current definition 1.1 glossary
stray current 5.14 detecting stray current
stress definition 1.1 qlossary
stress corrosion 2.32 stress corrosion
stress corrosion definition 1.1 glossary
cracking
stringing definition 1.1 glossary
strinainci pipe 3.12 stringing
structure fire priority 1-Emergency requests GESH 1 priority 1 -emergency requests
submetering definition 1.1 glossary
supervisory control
and data acquisition definition 1.1 glossary
SCADA
supports for bridges 2.15 supports
supports for meters 2.22 installation
supports for steel bending stress of 2.12 deflection and bending stress
pipelines
supports for steel pipelines longitudinal stress of 2.12 longitudinal stress
supports for steel seismic conditions for 2.12 seismic supports
pipelines
supports for steel torsional stress of 2.12 torsional stress
pipelines
supports for steel
i elines 2.12 supports general
surveillance 4.11 throughout
Isurvey limitations I bar holing GESH 2 under round leak investigation
49

Subject Details Sec/Section Subsection
sweet gas definition 1.1 glossa
symptomatic definition 1.1 glossary
symptoms of carbon
monoxide oisonin GESH 3 symptoms of carbon monoxide poisoning
system definition 1.1 glossary
system pressure
problems and all priority 1 -emergency
GESH 1 priority 1 -emergency requests
SCADA alarms except requests
for odorizer alams
tampering and illegal
GESH 15 tampering and illegal bypass
bass
tamping equipment compaction 3.15 compaction
tape wrap cold applied 3.12 cold applied tape wrap
tape wrap freezing temperature 3.12 cold applied tape wrap
tape wrap rimer 3.12 wax type tape wrap
tape wrap repair by taping 3.12 repair and patching using tape wrap
tape wrap wax type 3.12 wax type tape wrap
tapping PE(polyethylene)pipe service 3.24 tapping procedure
line tapping rocedure
tapping mandatory review of 3.32 tapping and pluggingprocedures
pp g procedures
pp g
tappina steel,for repairs 3.32 tapping and plugging procedures
tapping tap&stop 4"and smaller, 4.31 App A 221.040.001
Mueller.OQ Task
tapping tap&stop 4"and smaller, 4.31 App A 221.040.005
TDW OQ Task
tapping tap&stop 6"and larger, 4.31 App A 221.040.010
Mueller OQ Task
tapping tap&stop 6"and larger,TDW, 4.31 App A 221.040.015
OQ Task
tapping rocedure electrofusion 3.24 tapping rocedure
tariff definition 1.1 glossary
task definition 1.1 glossary
TD Williamson hemi-head spheres 3.32A detailed procedure for use of"td williamson permanente
hemi-head repair s heres"
TD Williamson repair spheres 3.32A detailed procedure for use of"td williamson permanente
hemi-head repair s heres"
TD Williamson tapping&stopping 4"and 4.31 App A 221.040.005
smaller,OQ Task
TD Williamson tapping&stopping 6"and 4.31 App A 221.040.015
larger, OQ Task
telemeter definition 1.1 qlossary
telemetry definition 1.1 glossary
telemetry regulator stations 2.23 telemetering and pressure recorders
telemetry communications 2.25 gas transport&telemetry customers
telemetry data collected 2.25 data path and uses
telemetry data path and uses 2.25 data path and uses
telemetry design 2.25 throu hout
telemetry electrical classification 2.25 electrical classification
telemetry equipment configuration 2.25 equipment configuration
telemetry as transport 2.25 gas transport&telemetry customers
telemetry ate stations 2.25 gate stations
telemetry power plants 2.25 power plants
telemetry power source 2.25 power source
telemetry pulses to customer 2.25 pulses to customer
telemetry quantities measured table 2.25 table for detailed reference to quantities measured
telemetry sensing lines 2.25 sensing lines
telemetry system pressure monitoring 2.25 regulator sites and pressure monitorin
telemetry transport customers 2.25 gas transport&telemetry customers
telemetry 2.25 throughout
telemetry calibration 5.12 chart recorders and telemet
telemetry inspection 5.12 chart recorders and telemet
temperature
compensation meters 2.22 temperature compensation
tem erature factor formula 2.221 temperature compensation
temporary control of broken plastic pipe GESH 4 standard methods of control(60 psig or less)
escaping as
50

Subject Details Sec/Section Subsection
temporary control of broken steel pipe GESH 4 standard methods of control(60 psig or less)
escaping as
temporary control of damage prevention GESH 4 damage prevention
escaping as
temporary control of hp control GESH 4 HP control
escaping as
temporary control of media inquiries GESH 4 media inquiries
escaping as
temporary control of standard methods of control
GESH 4 standard methods of control(60 psig or less)
escaping gas (60 psig or less)
temporary control of trench safety GESH 4 trench safety
escaping as
temporary control of UG electric precautions GESH 4 UG electric precautions
escaping as
temporary repairs 3.33,GESH 2 3.33-temporary repairs; GESH 2-temporary repairs/cold
weather exceptions; GESH 2-re-classification of leaks
test bench 5.21 throughout
test leads 3.12,3.42,5.14 3.12-test leads;3.42-WAC 480-93-115 requirement;
5.14-procedure to test casing without test leads
test medium definition 1.1 glossary
test point definition 1.1 glossary
test pressure definition 1.1 alossary
testing toughness 3.12 toughness testing
testing frequency meters 2.22 frequency of meter tests
testing of welds non-destructive,OQ task 4.31 App A 221.130.015
the International safety inspections GESH 12 recognized codes
Building Code IBC
therm definition 1.1 alossary
thermal contraction 2.12,2.13 2.12-thermal contraction and expansion;2.13-thermal
contraction or expansion
thermal expansion bridge spans over 100 feet 2.15 design requirements
thermal expansion 2.12,2.13 2.12-thermal contraction and expansion;2.13-thermal
contraction or expansion
thermal expansion PE, polyethylene pipe 2.13,3.13 2.12-thermal contraction and expansion;2.13-thermal
contraction or expansion
threaded 5000 and Drawing B-35785 2.24 Appendix-A
7000 rotary meters
three-part
communication definition 1.1 glossary
threshold detection odorization 4.18 threshold detection level(TDL)
level TDL
TIMP(integrity
management reporting,performance 4.14 TIMP performance reporting
program)
TIMP(transmission
integrity management 4.41 throughout
program)
TIMP(transmission leak survey of<30%SMYS, transmission and other HP pipelines; maintenance
integrity mgmnt Class 3&4 5.11 frequencies
program)
tolerance zone locates 4.13 tolerance zone
torsional stress steel pipe(design formula 2.12 torsional stress
toughness testing steel pipe 3.12 toughness testing
traceable records definition 1.1 glossary
tracer wire anode placement for 2.32 tracer wire
tracer wire PE of eth lene pipe 3.13 tracer wire
tracer wire wire connections 3.13 wire connections
tracer wire wire type 2.13,3.13 2.13-tracer wire;3.13-tracer wire
tracer wire installation 3.13,3.19 3.13-tracer wire;3.19-future locatabilit
tracer wire plastic,install&repair,OQ 4.31 App A 221.120.130
task
tracer wire connections 3.13 3.13-tracer wire
tracer wire and nuts, drawing 3.13 A-36277
drawing
tracer wire attachment drawing 3.13 A-35776
to pipe drawing
tracking boring tools 3.19 equipment requirements-steel or PE;equipment
requirements-PE
51

Subject Details Sec/Section Subsection
transfer prover 2.22 prover calibration interval
transitioning,to plastic
3.13 tracer wire
pipe
transmission annual 4.14 submission of reports;TIMP performance reporting
report
transmission integrity
management program principles 4.41 integrity management principles
TIMP
transmission integrity
management program overview 4.41 introduction;scope
TIMP
transmission integrity
management program patrols of transmission lines 5.15 TIMP-transmission patroling
TIMP
transmission integrity inspection,on site,damage building permits near transmission utility easements or
mgmnt program prevention 4.13 rights of way
TIMP
transmission line definition 1.1 glossary
transmission line design of pipe and 2.12 transmission lines-design of pipe and components
components
transmission line internal corrosion control 2.12 transmission line-internal corrosion control
transmission line WAC reporting of construction 2.12 reporting of proposed construction of transmission main
transmission line chan e a rovals 2.12 transmission line-approval of change
transmission line valves 2.14 transmission line valves
transmission line repairs 3.32 transmission lines
transmission line inspection 4.13 on site inspections for transmission facilities
transmission line leak survey 5.11 transmission and other HP pipelines; maintenance
frequencies
transmission line patrols 5.15 general;maintenance frequencies; recordkeeping;timp-
transmission patrolling
transmission pipeline SRC Reporting 4.12 filing of safety-related condition report
MAOP exceedance
transmission pipelines inspection 4.13 on site inspections for transmission facilities
transportation
definition 1.1 glossary
customer
trench definition 1.1 glossary
trenching backfill 3.15 throughout
trenching bedding 3.15 beddina material
trenching clearances 3.15 clearances-steel and PE pipelines
trenching compaction 3.15 compaction
trenching cover 3.15 cover
trenching protection 3.15 cover;shoring and excavating safety
trenching shoring 3.15 shoring and excavating safet
trenching vegetation clearance 3.15 vegetation clearance
trenching WA(Washington)rule for 3.15 shoring and excavating safety
shoring
trenching land disturbance requirements 3.43 general
trenching joint ditch design 3.14,3.15 3.13-joint ditch design;3.15-clearances-steel and PE
pipelines
trenching ID(Idaho)rule for shoring 3.15,GESH 4 3.15-shoring and excavating safety; GESH 4-trench
safety
trenching OR(Oregon)rule for shoring 3.15,GESH 4 3.15-shoring and excavating safety; GESH 4-trench
safety
trenchless pipe potholing 3.19 tracking and potholing while crossing utilities
installation
trenchless pipe PE pipe 3.13,3.19 3.13-safe pulling forces;3.13-break-away pin or weak
installation link; 3.19-throughout
trenchless pipe boring 3.19 general
installation methods
trouble order GESH 1 trouble order inspections
inspections
troubleshooting guide butt fusion 3.23 butt fusion troubleshooting guide
turbine meter general 2.22 meter types
turbine meter capacity 2.24 turbine meters
turbine meter meter capacity 2.24 turbine meters
turn off orders GESH 8 GESH 8-throughout
turn-on fees GESH 11 reconnection/turn on/re-establishment fees
UL 2034 Igeneral GESH 31 UL 2034
52

Subject Details Sec/Section Subsection
ultrasonic meters general 2.22 meter types
ultrasonic meters gate stations 2.25 gate stations
under film migration of
2.12 steel pipe coating and marking
moisture
underground leak general GESH 4 emergency procedures-blowing or uncontrolled escaping
detection natural gas
underground leak
5.11 underground leak repair
repair
underground leak
repair follow up 5.11 maintenance frequencies
underground migration see migration
uniform mechanical special concerns GESH 12 unvented heaters and decorative appliances;CSST
code
uniform plumbing code safety inspections GESH 12 recognized codes
union definition 1.1 glossary
unlock policy GESH 7 meter unlock policy
unvented heaters GESH 12 unvented heaters and decorative appliances; unvented
heaters-mfg. homes
upper explosive limit
UEL definition 1.1 glossary
uprating hoop stress 4.17 uprating pipeline to hoop stress<30 percent smys;
uprating i eline to hoop stress=>30 percent smys
uprating incremental pressure 4.17 uprating requirements,uprating pipeline to hoop stress<
increases 30 percent smys
uprating leak survey for 4.17 uprating requirements; recordkeeping;uprating procedure-
typical sequence of events; u rate procedure&history
uprating limitation 4.17 uprating requirements
uprating i e record form 4.17 avista utilties system u rate area pipe record
uprating rocedure 4.17 uprating rocedure-typical sequence of events
upratinq recordkeeping 4.17 recordkeeping
uprating requirements;uprating pipeline to hoop stress<
uprating repairs 4.17 30 percent smys; recordkeeping;uprating procedure-
typical sequence of events;avista utilties written plan for
pressure uprating; u rate procedure&history
upratinq Washington state 4.17 u rate in state of Washington
uprating requirements; uprate in state of Washington;
uprating written plan 4.17 uprating procedure-typical sequence of events;avista
utilities written plan for pressure uprating
utilities communication with GESH 13 communication with emergency and public officials
emergency and public officials
utilization pressure 5.12 service regulator
valve definition 1.1 glossary
valve box definition 1.1 glossary
valve box leaks 0%gas exception 5.11 leak repair and residual gas checks
valve seat definition 1.1 alossary
valves accessibility 2.14 general
valves Avista GIS codes 2.14 valve codes
valves corrosion 2.14 corrosion
valves design 2.14 throughout
valves curb,emergency 2.14 emergency curb valves
valves emergency zone(EOP) 2.14 tying EOP zones together
valves installation 2.14 installation
valves mainline 2.14 installation
valves new housing developments 2.14 valves at new housing developments
valves supports 2.14 valve supports
valves transmission line 2.14 transmission line valves
valves numbering 2.14 valve numbering
valves plug,steel 2.14 steel plug valves
valves gate,steel 2.14 steel gate valves
valves ball,steel 2.14 steel ball valves
valves PE of eth Iene 2.14 polyethylene valves
valves service line 2.14 service line valves
valves curb 2.14 curb valves(underground service valves
valves transmission valve table 2.14 transmision line valves
valves earthquake meters 2.22 earthquake valves
valves regulator 2.23 valves
valves I gear valves 5.13 steel gear valves;gear valves
53

Subject Details Sec/Section Subsection
valves maintenance cycles, 5.13 maintenance requirements for valve types;general valve
procedure maintenance and installation notes
valves recordkeeping 5.13 recordkee in
valves secondary 5.13 maintaning valve boxes;maintenance frequencies-valves;
secondary valves maintenance
valves steel 5.13 steel plug valves;steel gate valves;steel ball valves;steel
ear valves
valves regulator station 2.14,2.23 2.14-valve types;2.23-valves
valves curb 2.14,3.16 2.14-curb valve;3.16-curb valves
valves excess flow 2.14,3.16 2.14-excess flow valve performance standards,3.16-
excess flow valves
valves ball,steel 2.14,5.13 2.14-valve types;5.13-steel ball valves;5.13-steel ball
valves
valves gate,steel 2.14,5.13 2.14-valve types;5.13-steel gate valves;5.13-valve
turns;5.13-steel gate valves
2.14-valve types;5.13-steel plug valves;5.13-steel
valves plug 2.14,5.13 gear valves; 5.13-poly valves;5.13-general valve
maintenance and installation notes;5.13-plug valve
lubricationprocedures;5.13-steel plug valves
valves polyethylene 2.14,5.13 2.14-valve types; 5.13-poly valves
valves abandoning 5.13,5.16 5.13-valve disable/abandonment;5.16-valve
abandonment
valves boxes 5.13,5.16 5.13-maintaining valve boxes;5.13-maintenance
frequencies-valves;5.16-valve box abandonment
valves service 2.14,3.16,4.31 App 2.14-curb valves;3.16-curb valves;4.31 App A-
A 221.050.005
valves maintenance,OQ task 4.31 App A 221.050.005
valves replace service valves,OQ 4.31 App A 221.050.005
Task
vault definition 1.1 glossary
vaults meter vaults 2.22 pits&vaults
vaults desicin 2.42 throucihout
vaults drainage 2.42 drainage
vaults electrical code 2.42 electrical code
vaults sealing 2.42 sealing and ventilation
vaults size-related rules 2.42 sealing and ventilation
vaults ventilation 2.42 sealing and ventilation
vaults steel pipe installation within 3.12 pits and vaults
vaults abandonment 5.16 vault abandonment
vaults inspection 5.18 vault inspection
vaults maintenance cycles,general 5.18 maintenance frequency
vaults maintenance,OQ task 4.31 App A 221.080.020
vegetation guidelines 5.15 vegetation guidelines
vent pipes,casings 3.42 throucihout
ventilation meter rooms,of 2.22 Avista's requirements for gas meter room installations
venting and blow down 3.17 venting and blow down
venting system GESH 10 venting system
5.11 -venting underground leakage;GESH 2-venting
venting underground 5.11,GESH 2 underground leakage;GESH 2-gas present in sewer or
leaks duct system;GESH 2-follow-up inspections for residual
as; GESH 2-grade 1 leak; GESH 2-grade 2 leak
vents GESH 6 vent lines;vents
vents,regulator 2.22,5.20,GESH 6 2.22-3 foot rule;2.22-10 foot rule;5.20-inspection
requirements;GESH 6-vent lines; GESH 6-vents
verifiable records definition 1.1 alossary
verification definition 1.1 glossary
vibratory tamping 3.15 compaction
visual inspection weld defects inspection chart 3.22 visual inspection
visual inspection welding,OQ task 4.31 App A 221.130.005
visual inspection of 3.12,3.22,3.32A 3.12-visual inspection;3.22-general;3.32A-fit-up and
weld welding sequence
volt definition 1.1 glossary
voltage definition 1.1 glossary
voltmeters
calibrations 5.14 cp equipment accuracy check
warning toe steel installations 3.12 caution to e
warning toe conduit marking 3.42 conduit
54

Subject Details Sec/Section Subsection
Washington-rule no.
182(WN U-29) emergency operations GESH 13 curtailment rules
"continuity of service"
Washington dig law
website reference 4.13 locating and marking gas facilities
Washington Mechanical Code recognized codes GESH 12 unvented heaters and decorative appliances
Washington State recognized codes GESH 12 recognized codes;unvented heaters and decorative
Amendments appliances
Washington State O&M manual filing 1.4 construction procedures filing with the WUTC
WACs by description
Washington State proximity considerations for
2.12 WA state proximity considerations
WACs b description as facilities
Washington State reporting of transmission 2.12 reporting of proposed construction of transmission main
WACs by description construction
Washington State transmission line construction 2.12 reporting of proposed construction of transmission main
WACs by description
Washington State aboveground PE installations 2.13 above ground plastic pipe
WACs by description
Washington State maximum time limit for temp
2.13 above ground plastic pipe
WACs b description PE
Washington State PE pipe above ground 2.13 above ground plastic pipe
WACs by description
Washington State emergency curb valve
WACs by description installation 2.14 emergency curb valves
Washington State service regulator install, 2.22 general
WACs by description operation and maintenance
Washington State meter identification 2.22 meter identification
WACs by description
Washington State WACs by description meter set assembly location 2.22 meter set location, protection,and barricades
Washington State proximity of gas facilities to 2.23 regulation of high presure to service pressure
WACs by description human occupancy
Washington State cathodic protection for new 2.32 design and installation
WACs by description pipelines
Washington State cathodic protection grounding 2.32 design and installation
WACs by description wells design
Washington State pipeline protection timeframe 2.32 design and installation
WACs by description
Washington State recordkeeping,construction 3.12 updating maps and records
WACs by description
Washington State WACs by description study requirements, pipelines 3.12 toughness testing
Washington State recordkeeping,construction 3.13 updating maps and records
WACs by description
Washington State pressure testing transmission 3.18 notification to Washington UTC prior to pressure testing
WACs b description pipelines transmission pipelines
Washington State 18 notification to Washington UTC prior to pressure testing
WACs b description transmission line testing 3. transmission pipelines
Washington State joining PE(polyethylene)pipe 3.23 qualifications of persons to join plastic pipe
WACs by description pipe qualification and renewal
Washington State squeezing plastic pipe 3.34 squeezing procedure
WACs by description
Washington State casing test leads 3.42 installing steel carrier pipe in casing
WACs by description
Washington State test leads for casings 3.42 installing steel carrier pipe in casing
WACs by description
Washington State hazardous condition reports 4.11 material failure
WACs by description
Washington State incident reporting 4.11 material failure
WACs by description
Washington State mapping updates 4.11 map and data corrections
WACs by description
Washington State records availability to 4.11 map and data corrections
WACs by description personnel
Washington State updating maps within 6 4.11 map and data corrections
WACs by description months
55

Subject Details Sec/Section Subsection
Washington State excavation without locate, 4.13 excavation identified without a locate(WA transmission)
WACs by description transmission line
Washington State RCW requirements 4.13 WA excavator notifications
WACs by description
Washington State damage reporting 4.13 WA damage reporting
WACs by description
Washington State construction defects&mat'I 4.14 WUTC construction defects&material failures report
WACs by description failures r rt
Washington State damage prevention statistics 4.14 WA damage reporting
WACs by description report
Washington State drug and alcohol testing report 4.14 DOT drug and alcohol MIS form submission
WACs by description
Washington State material failures report,annual 4.14 WUTC construction defects&material failures report
WACs by description
Washington State document retention 4.14 document retention
WACs by description
Washington State damage reporting 4.14 WA damage reporting
WACs by description
Washington State WACs by description uprating 4.17 uprate in state of Washington
Washington State crew activity reporting 4.19 WUTC contact
WACs by description
Washington State cathodic protection lacking, 5.11 special surveys
WACs by description leak survey
Washington State isolated risers lacking CP, leak 5.11 special surveys
WACs by description survey
Washington State leak survey for lowered 5.11 special surveys
WACs by description pipelines
Washington State leak survey,250 psig and
5.11 250+psig pipelines Washington only
WACs b description above
Washington State leaks from foreign sources 5.11 detection of other combustible gases
WACs by description
Washington State hazardous situation 5.11 detection of other combustible gases
WACs by description notifications
Washington State valve maintenance,
5.13 maintenance frequencies valves
WACs b description emer enc curb
Washington State WACs by description line marker requirements 5.15 Washington pipeline marker requirements
Washington State marker maintenance 5.15 Washington pipeline marker requirements
WACs by description
Washington State pipeline markers for buried
WACs by description pipe 5.15 Washington pipeline marker requirements
Washington State 2.12-WA state proximity considerations;2.23-regulation
WACs by description proximity considerations 2.12,2.23,4.15 of high pressure to service pressure;4.15-determination
of MAOP
Washington State curb valves criteria 2.14,5.13 2.14-emergency curb valves;5.13-maintenance
WACs b description frequencies-valves
Washington State emergency curb valves criteria 2.14,5.13 2.14-emergency curb valves; 5.13-maintenance
WACs b description frequencies-valves
Washington State lowering steel pipe 3.12,5.11 3.12-toughness testing;5.11 -special surveys
WACs by description
Washington State material failure report 4.11,5.11 4.11 -material failure;5.11 -leak failure cause definitions
WACs by description submission
Washington State leak survey for pipelines 5.11,5.14 5.11 -special surveys;5.14-isolated steel
WACs by description lackinq CP
Washington State foreign source leak detection 5.11,GESH 2 5.11 -detection of other combustible gases; GESH 2-
WACs b description detection of other combustible gases
Washington State emergency contact notification GESH 13 communication with public officials
WACs by description
Washington State exceeding MAOP GESH 13 official incident notification
WACs by description
Washington State 480-93-017 1.4 construction procedures filing with the WUTC
WACs by number
Washington State 480-93-020 2.12 WA state proximity considerations
WACs by number
Washington State 480-93-160 2.12 reporting of proposed construction of transmission main
WACs by number
56

Subject Details Sec/Section Subsection
Washington State 480-93-178(6) 2.13 above ground plastic pipe
WACs by number
Washington State 480-93-100 2.14 emergency curb valves
WACs by number
Washington State 480-93-140(1) 2.22 general
WACs by number
Washington State 480-90-328 2.22 meter identification
WACs by number
Washington State 480-90-323 2.22 meter set location, protection,and barricades
WACs by number
Washington State 480-93-020 2.23 regulation of high presure to service pressure
WACs by number
Washington State 173-160-456(2) 2.32 design and installation
WACs by number
Washington State 480-93-110 2.32 design and installation
WACs by number
Washington State 480-93-018 3.12 updating maps and records
WACs by number
Washington State 480-93-175 3.12 toughness testing
WACs by number
Washington State 480-93-018 3.13 updating maps and records
WACs by number
Washington State 18 notification to Washington UTC prior to pressure testing
WACs b number 480-93-170 3. transmission pipelines
Washington State 480-93-080 3.23 qualifications of persons to join plastic pipe
WACs by number
Washington State 480-93-178 3.34 squeezing procedure
WACs by number
Washington State 480-93-115 3.42 general; installation requirements
WACs by number
Washington State 480-93-018 4.11 map and data corrections
WACs by number
Washington State 480-93-200(9) 4.13 excavation identified without a locate(WA transmission)
WACs by number
Washington State WACs by number 480-93-200(8) 4.13 WA excavator notifications
Washington State 480-93-200(7) 4.13 WA damage reporting
WACs by number
Washington State 480-93-180(2) 4.14 plans and procedures
WACs by number
Washington State WACs by number 480-93-200 4.14 regulatory requirements
Washington State 480-93-200(10)(b) 4.14 WUTC construction defects&material failures report
WACs by number
Washington State 480-93-200(13) 4.14 DOT drug and alcohol MIS form submission
WACs by number
Washington State WACs by number 480-93-200(7)(a) 4.14 WA damage reporting
Washington State 480-93-200(7)(c) 4.14 document retention
WACs by number
Washington State 480-93-200(7) 4.14 WA damage reporting
WACs by number
Washington State WACs by number 480-93-155 4.17 uprate in state of Washington
Washington State 480-93-200(12) 4.19 WUTC contact
WACs by number
Washington State 480-93-188 5.11 250+psig pipelines Washington only
WACs by number
Washington State 480-93-188(6) 5.11 self audits
WACs by number
Washington State 480-93-185 5.11 detection of other combustible gases
WACs by number
Washington State 480-93-188(3)(d) 5.11 special surveys
WACs by number
Washington State 480-93-175 5.11 special surveys
WACs by number
57

Subject Details Sec/Section Subsection
Washington State 2.12-WA state proximity considerations;2.23-regulation
WACs by number 480-93-020 2.12,2.23,4.15 of high pressure to service pressure;4.15-determination
of MAOP
Washington State 480-93-100(2) 2.14,5.13 2.14-emergency curb valves; 5.13-maintenance
WACs b number frequencies-valves
Washington State 480-93-110 2.32,5.14 2.32-design and installation;5.14-throughout
WACs by number
Washington State 480-93-175 3.12,5.11 3.12-toughness testing;5.11 -special surveys
WACs by number
Washington State 480-93-124 3.15,5.15 Washington pipeline marker requirements
WACs by number
Washington State 480-93-115 3.42(2 plcs) installing steel carrier pipe in casing,conduit
WACs by number
Washington State 480-93-200(6) 4.11,5.11,GESH 2 4.11 -material failure;5.11 -leak failure cause definitions;
WACs b number GESH 2-leak failure cause definitions
Washington State 4.13-WA damage reporting;4.14-WA reporting
WACs by number 480-93-200(7) 4.13,4.14 requirements;4.14-WA damage reporting;4.14-
document retention
Washington State 480-93-200(7)(b) 4.13,4.14 4.13,4.14 -WA damage reporting
WACs by number
Washington State 13 GESH 13 4.13-WA excavator notifications;GESH 13-
WACs b number 480-93-200(8) 4. , communication with public officials
Washington State 480-93-200(7)(c) 4.14,GESH 2 4.14-WA reporting requirements; GESH 2-photography
WACs b number requirements
Washington State 480-93-188(3)(d) 5.11,5.14 5.11 -special surveys;5.14-isolated steel
WACs by number
Washington State 480-93-185 5.11,GESH 2 5.11 -detection of other combustible gases; GESH 2-
WACs b number detection of other combustible qases
Washington State 480-90-183 GESH 16 customer requested meter test
WACs by number
Washington State 480-93-100(5) GESH 5 EOP-Zone shut down
WACs by number
water mains clearances from 3.15 clearances-steel and PE pipelines
water mains boring near 3.19 longitudinal separation
waterways PE installations 2.13 plastic under waterways
waterways boring 3.19 general
waterways commercially navigable 5.16 commercially navigable waterways
wax type steel pipe tape wrap 3.12 coatings on steel risers
weak link definition 1.1 glossary
weak link PE(polyethylene)pipe 3.13,3.19 3.13-safe pulling forces;3.13-break-away pin or weak
link;3.19-pullback;3.19-procedure
weak link 3.13,3.19 3.13-safe pulling forces;3.13-break-away pin or weak
link;3.19-pullback;3.19-procedure
weld procedures 3.22 Appendix A
welded farm tap
regulator station dwng, Drawing E-37842 2.24 Appendix A
2"outlet
welded farm tap
regulator station dwng, Drawing E-37970 2.24 Appendix A
3/4"outlet
welding definition 1.1 alossary
welding API 1104 3.22 welder qualification requirements
welding appendages 3.22 non-destructive pre-inspection
welding branch 3.22 qualification of welders
welding butt 3.22 qualification of welders
welding certification card 3.22 welder certification card
welding circumferential weld 3.22 circumferential weld separation
welding defects 3.22 removal or repair of weld defects or cracks
welding destructive testing 3.22 welder qualification requirements
welding electrode selection 3.22 throughout
welding electrode storage 3.22 electrode storage
welding fillet welding 3.22 fillet welding
welding as metal arc(GMAW) 3.22 welding control requirements
welding roundin devices 3.22 grounding devices
welding hot pass 3.22 visual inspection
welding initial qualification test 3.22 qualification of welders
welding inspection of the weld 3.22 visual inspection
welding miter joints 3.22 miter joints
58

Subject Details Sec/Section Subsection
welding non-destructive testing(NDT) 3.22 non-destructive testing(NDT)requirements
requirements
welding over-cooling 3.22 over-cooling
welding porosity 3.22 visual inspection
welding reheatin 3.22 oreheatina
welding pre-inspection 3.22 non-destructive pre-inspection
welding prroQcedure qualification record 3.22 weld procedure qualification requirements
welding qualification of procedures 3.22 qualification of welders
welding qualification of welders 3.22general;qualification of welders
welding repair 3.22 removal or repair of weld defects or cracks
welding re-qualification test 3.22 qualification of welders
welding roll welding 3.22 roll welding
welding root bead 3.22 depositing root bead and hot pass
welding shielded metal arc(SMAW) 3.22 throughout
welding shielding flux 3.22 weld procedure qualification
welding slag inclusions 3.22 visual inspection
welding socket welding 3.22 socket welding
welding seed of travel 3.22 determining seed of travel
welding strip capping 3.22 filler and cover passes
welding undercutting 3.22 filler and cover passes,visual inspection
welding failure cause leaks 5.11 leak failure cause definitions
welding leak failure cause 5.11 leak failure cause definitions
3.12-cadweld procedure;3.13-tracer wire;3.16-
welding cadwelding 3.12,3.13,3.16,3.22 insertion of old steel services along steel main; 3.22-non-
destructive pre-inspection
welding procedures,specific 3.22 Ap A 3.22 App A
welding procedures 3.22,App A Appendix A
welding field welding 3.32A field welding instructions
welding seal welding 3.32A field welding instructions;welding sequence
welding OQ task 4.31 App A 221.130.010
welding visual inspection of 3.12,3.22 3.12-visual inspection;3.22 non-destructive testing(NDT)
requirements;3.22-visual inspection;
welds,leak failure GESH 2 leak failure cause definitions
cause
wet gas definition 1.1 glossary
wet soapy rag 3.34 wet soapyragprocedure
procedure
wick odorizer usa a 2.52 odorizer types
wick odorizers 2.52,5.23 2.52-odorizer type;5.23-wick odorizers
wick-type odorizer definition 1.1 glossary
windows, proximity of 2.22 3 foot rule
as meters
wrapping of pipe 3.12,5.14 3.12-tape wrap; 5.14-repair&wrapping of pi e
wrinkle bend definition 1.1 glossa
X-ray of welds see NDT
X-Tru coatinq usage 1 3.121 coating on steel risers
field strength definition 1 1.11 glossa
59

1.3 GAS ACRONYMS AND ABBREVIATIONS
SCOPE:
To define common acronyms and abbreviations found in the natural gas industry.
REGULATORY REQUIREMENTS:
None.
Acronym Definition of Acronym or Abbreviation
AC Alternating Current
AC Atmospheric Corrosion
ACFH Actual Cubic Feet per Hour
A-D Analog to Digital
AES AutoSol Enterprise Service
AFM Avista Facility Management
AFUDC Allowance for Funds Used During Construction
AGA American Gas Association
AGM Aboveground Markers
AH After Hours
AMI Advanced Metering Infrastructure
AMR Automated Meter Reading
ANPRM Advanced Notice of Proposed Rulemaking
ANSI American National Standards Institute
AOC Abnormal Operating Condition
AOC Area of Concern
APGA American Public Gas Association
API American Petroleum Institute
APWA American Public Works Association
GAS ACRONYMS AND REV. NO. 9
ABBREVIATIONS DATE 01/01/25
x v#ST, a STANDARDS 1 OF 13
Utilities SPEC. 1.3
NATURAL GAS

Acronym Definition of Acronym or Abbreviation
ARCOS Automated Roster Call-out System
ARO Abrasion Resistant Overlay
ARS Alarm Response Sheet
ASME American Society of Mechanical Engineers
ASNT American Society of Non-Destructive Testing
ASTM American Society for Testing and Materials
ASV Automatic Shut-off Valve
AVA Avista
AVI Annual Visual Inspection (CP Rectifiers)
AWG American Wire Gauge
AWS American Welding Society
BAP Baseline Assessment Plan
BCF Billion Cubic Feet
BECS Building Energy Codes and Standards
BH Regular Business Hours
BMP Best Management Practices
BTU British Thermal Unit
BTUH British Thermal Unit per Hour
CABO Council of American Building Officials
CC&B Customer Care and Billing
CCB Cathodic Critical Bond
CCF One hundred cubic feet (of gas)
CDA Confirmatory Direct Assessment
CDF Controlled Density Fill
GAS ACRONYMS AND REV. NO. 9
ABBREVIATIONS DATE 01/01/25
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Utilities SPEC. 1.3
NATURAL GAS

Acronym Definition of Acronym or Abbreviation
CDR Construction Design Representative
CDT Construction Design Tool
CESCL Certified Erosion & Sediment Control Lead
CF Can't Find
CF Cubic Feet
CFH Cubic Feet per Hour
CFM Cubic Feet per Minute
CFR Code of Federal Regulations
CFS Cubic Feet Per Second
CGA Canadian Gas Association
CGA Common Ground Alliance
CGE Can't Gain Entry
CGI Combustible Gas Indicator
CIS Close-Interval Survey
CLB Comfort Level Billing
CLM Construction List Manager
CNG Compressed Natural Gas
CO Carbon Monoxide
COS Cost of Service
CO2 Carbon Dioxide
CID Cathodic Protection
CPC Customer Project Coordinator
CSR Customer Service Representative
CSS Customer Service System
GAS ACRONYMS AND REV. NO. 9
ABBREVIATIONS DATE 01/01/25
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Utilities SPEC. 1.3
NATURAL GAS

Acronym Definition of Acronym or Abbreviation
CSST Corrugated Stainless Steel Tubing
CTS Copper Tube Size
CUFT Cubic Feet(usually shown in lowercase.)
CWAP Cold Weather Action Plan
CWIP Construction Work in Progress
DA Direct Assessment
DBF Dandy Blue Flame
DC Direct Current
DCVG Direct Current Voltage Gradient
DEG Degrees
DEQ Department of Environmental Quality
DER Designated Employer Representative
DHS Department of Homeland Security
DIMP Distribution Integrity Management Program
DIRT Damage Information Reporting Tool
DOE Department of Energy
DOT Department of Transportation
DP-IR Detecto Pak Infrared Detector
DSAW Double Submerged Arc Weld
DSM Demand-Side Management
EC External Corrosion
ECDA External Corrosion Direct Assessment
EFV Excess Flow Valve
ELE Electric
GAS ACRONYMS AND REV. NO. 9
ABBREVIATIONS DATE 01/01/25
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Utilities SPEC. 1.3
NATURAL GAS

Acronym Definition of Acronym or Abbreviation
EOP Emergency Operating Procedure or Emergency Operating Plan
EPA Environmental Protection Agency
EPIR Exposed Piping Inspection Report (Form N-2534)
ERT Encoder Receiver Transmitter
ERW Electric Resistance Welded
ESC Erosion and Sediment Control Plan
F Fahrenheit
F/O Fiber Optic
F.P. Fireplace
FAF Forced Air Furnace
FBE Fusion Bonded Epoxy
FEMA Federal Emergency Management Agency
FERC Federal Energy Regulatory Commission
FI Flame Ionization
FT Foot or Feet(usually shown in lowercase.)
FVR Field Verification Report
FW Flash Weld
G Grams (usually shown in lower case)
GAAP Generally Accepted Accounting Principles
GCOMS Gas Control Operations Management System
GESH Gas Emergency and Service Handbook
GHG Greenhouse Gas
GIS Geographic Information System
GMAW Gas Metal Arc Welding
GAS ACRONYMS AND REV. NO. 9
ABBREVIATIONS DATE 01/01/25
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Utilities SPEC. 1.3
NATURAL GAS

Acronym Definition of Acronym or Abbreviation
GPG Gas Pressure Gauge
GPR Ground Penetrating Radar
GPS Global Positioning System
GPTC Gas Piping Technology Committee
GSM Gas Standards Manual
GTI Gas Technology Institute
GTN Gas Transmission Northwest
HBI High Bill Investigation
HCA High Consequence Areas
HDB Hydrostatic Design Basis
HDD Horizontal Directional Drilling
HOA High Occupancy Area
HOS High Occupancy Structure
HOS Hours of Service
HP High Pressure
HPS High Pressure Service
HSI Hot Surface Igniter
HVAC Heating, Ventilation and Air Conditioning
HVAC High Voltage Alternating Current
HWH Hot Water Heater
IC Internal Corrosion
ICDA Internal Corrosion Direct Assessment
ICS Incident Command System
ID Inside Diameter
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ABBREVIATIONS DATE 01/01/25
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Utilities SPEC. 1.3
NATURAL GAS

Acronym Definition of Acronym or Abbreviation
IEUCC Inland Empire Utility Coordinating Council
IHO Intended for Human Occupancy
ILI In Line Inspection
IMP Integrity Management Plan (or Integrity Management Program)
IN Inch or Inches (usually shown in lowercase)
INGAA Interstate Natural Gas Association of America
IOU Investor-Owned Utility
IP Internet Protocol
IPM Incident Prevention Manual (Safety Manual)
IPS Iron Pipe Size
IPUC Idaho Public Utility Commission
IRAS Integrated Risk Assessment Software
IRED Infrared Ethane Detector
IRP Integrated Resource Plan
IRV Internal Relief Valve
IT Information Technology
IUCC Idaho Utility Coordinating Council
IVP Integrity Verification Process
IVR Interactive Voice Response
JPSP Jackson Prairie Storage Project
KFGS Kettle Falls Generating Station
LB Pound or Pounds (usually shown in lowercase.)
LCD Liquid Crystal Display
LDC Local Distribution Company
GAS ACRONYMS AND REV. NO. 9
ABBREVIATIONS DATE 01/01/25
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Utilities SPEC. 1.3
NATURAL GAS

Acronym Definition of Acronym or Abbreviation
LEL Lower Explosive Limit
LNG Liquefied Natural Gas
LPG Liquefied Petroleum Gas
LTIR Lost Time Injury Rate
MAOP Maximum Allowable Operating Pressure
MCA Moderate Consequence Areas
MCF One Thousand Cubic Feet
MDM Meter Data Management
MDQ Maximum Daily Quantity
MDT Marketing Design Technician
MEA Midwest Energy Association
MIC Microbiologically Induced Corrosion
MIS Management Information System
MMBTU One Million British Thermal Units
MMCF One Million Cubic Feet
MOC Management of Change
MOP Maximum Operating Pressure
MRO Medical Review Officer
MSA Meter Set Assembly
MSDS Material Safety Data Sheet
MSS Manufacturers Standardization Society
MTR Mill Test Report
NACE National Association of Corrosion Engineers
NAPSR National Association of Pipeline Safety Representatives
GAS ACRONYMS AND REV. NO. 9
ABBREVIATIONS DATE 01/01/25
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Utilities SPEC. 1.3
NATURAL GAS

Acronym Definition of Acronym or Abbreviation
NARUC National Association of Regulatory Utility Commissioners
NDE Non-Destructive Evaluation
NDT Non-Destructive Testing
NEC National Electric Code
NFPA National Fire Protection Association
NG Natural Gas
NGL Natural Gas Liquids
NGT Not Greater Than
NGV Natural Gas Vehicle
NLT Not Less Than
NO Non-Observable
NOA Notice of Amendment
NOAA National Oceanic and Atmospheric Administration
NOI Notice of Intent
NOP Nominal Operating Pressure
NOPR Notice of Proposed Rulemaking
NOPV Notice of Probable Violation
NOT Notice of Termination
NPDES National Pollutant Discharge Elimination System
NPMS National Pipeline Mapping System
NPRM Notice of Proposed Rulemaking
NPS Nominal Pipe Size
NPT National Pipe Thread
NRC National Response Center
GAS ACRONYMS AND REV. NO. 9
ABBREVIATIONS DATE 01/01/25
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Utilities SPEC. 1.3
NATURAL GAS

Acronym Definition of Acronym or Abbreviation
NTE Not to Exceed
NTSB National Transportation Safety Board
NWP Northwest Pipeline (i.e., Williams Northwest Pipeline Company)
O&M Operation and Maintenance
OAR Oregon Administrative Rules
OCS Outer Continental Shelf
OD Outside Diameter
ODEQ Oregon State Department of Environmental Quality
OMB Office of Management and Budget
OOF Other Outside Forces
OPID Operator Identification Number
OPP Overpressure Protection
OPS Office of Pipeline Safety
OPUC Oregon Public Utilities Commission
OQ Operator Qualification
OSHA Occupational Safety and Health Administration
OSRAC Operations Safety Regulatory Action Committee
OST Office of the Secretary of Transportation
P&M Preventive and Mitigative
PAPA Pipeline Association for Public Awareness
PAW Pipeline Association of Washington
PE Polyethylene
PEF Performance Evaluation Form
PGA Purchase Gas Adjustment
GAS ACRONYMS AND REV. NO. 9
ABBREVIATIONS DATE 01/01/25
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I i►ities SPEC. 1.3
NATURAL GAS

Acronym Definition of Acronym or Abbreviation
PHMSA Pipeline and Hazardous Materials Safety Administration
PIC Potential Impact Circle
PIR Potential Impact Radius
PLC Programmable Logic Controller
PMC Periodic Meter Change-Out Program
PPB Parts per Billion (usually shown lowercase)
PPDC Plastic Pipe Data Collection (AGA)
PPE Personal Protective Equipment
PPI Plastic Pipe Institute
PPM Parts per Million (usually shown lowercase)
PPV Peak Particle Velocity
PQR Procedure Qualification Record
PSI Pounds per Square Inch (usually shown lowercase)
PSIA Pounds per Square Inch Absolute (usually shown lowercase)
PSIG Pounds per Square Inch Gage (usually shown lowercase)
PSMS Pipeline Safety Management System
PVC Polyvinyl Chloride
RCV Remote Control Valve
RCW Revised Code of Washington
RDL Readily Detectable Level
RIR Recordable Injury Rate
RMLD Remote Methane Leak Detector
RMV Rupture Mitigation Valve
RNG Renewable Natural Gas
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Utilities SPEC. 1.3
NATURAL GAS

Acronym Definition of Acronym or Abbreviation
ROW Right-of-Way
RTL Record Test Level
RTU Remote Terminal Unit
SAP Snow Action Plan
SAP Substance Abuse Professional
SCADA Supervisory Control and Data Acquisition
SCBA Self-Contained Breathing Apparatus
SCC Stress Corrosion Cracking
SCCDA Stress Corrosion Cracking Direct Assessment
SCFH Standard Cubic Feet per Hour
SDR Standard Dimension Ratio
SDS Safety Data Sheet
SEPA State Environmental Policy Act
SFR Single-Family Residence
SMAW Shielded Metal Arc Welding
SME Subject Matter Expert
SMYS Specified Minimum Yield Strength
SOP Standard Operating Procedure
SP Steel Pipeline
SSFT Single Service Farm Tap
STTR Service Tee Transition Rebuild
SWPPP Storm Water Pollution Prevention Plan
T.C. Thermocouple
TAC Technical Advisory Committee
GAS ACRONYMS AND REV. NO. 9
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NATURAL GAS

Acronym Definition of Acronym or Abbreviation
TC Temperature Compensating
TDC Top Dead Center
TDL Threshold Detection Level
TIMP Transmission Integrity Management Program
TOU Time of Use
TQM Total Quality Management
TX Transformer
UAV Unmanned Aerial Vehicle (i.e., drone)
UEL Upper Explosive Limit
UGS Underground Gas Storage
UNGSF Underground Natural Gas Storage Facility
UMC Uniform Mechanical Code
UPS Uninterruptible Power Supply
USDOT U.S. Department of Transportation
UV Ultraviolet
V.C. Vent Connector
VAC Volts Alternating Current
VAR Vehicle Accident Rate
VDC Volts Direct Current
WAC Washington Administrative Code
WC Water Column
WEI Western Energy Institute
WUTC Washington Utilities and Transportation Commission
WWP Washington Water Power
GAS ACRONYMS AND REV. NO. 9
ABBREVIATIONS DATE 01/01/25
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NATURAL GAS

1.4 GAS OPERATIONS AND MAINTENANCE PLANS
SCOPE:
To establish a procedure for updating Avista's Gas Standards Manual (GSM)and Gas Emergency and
Service Handbook(GESH).
REGULATORY REQUIREMENTS:
§192.605, §192.613
WAC 480-93-017, 480-93-180
CORRESPONDING STANDARDS:
Spec. 4.11, Continuing Surveillance
Operations and Maintenance Plan Review
The Gas Standards Manual (GSM) and the Gas Emergency and Service Handbook (GESH) are the
foundational documents in Avista's Operations and Maintenance Plan. These documents shall be
reviewed and updated as applicable once each calendar year, not to exceed 15 months. Updates will be
coordinated by the Pipeline Safety Engineer with assistance from the Gas Standards Manual Committee
and the Gas Emergency and Services Handbook Committee.
Operations managers and the Quality Assurance Department will conduct periodic reviews of the work
done by operating personnel to determine the effectiveness and adequacy of the procedures used in
normal operations and maintenance. Review of construction and maintenance activities and subsequent
incorporation of enhancements within the operations and maintenance plans is part of Avista's continuing
surveillance program as specified in Specification 4.11, Continuing Surveillance.
Avista encourages employees (and contractors)who utilize these procedures to review them for
deficiencies and recommendations. Such reviews will be analyzed, and the procedures will be modified
accordingly if deficiencies are found. Reviews, analysis, and modifications will be documented by the
Pipeline Safety Engineer.
GSM /GESH correction or enhancement requests should be submitted to the Pipeline Safety Engineer
as they are identified. The requests will be forwarded to and reviewed /incorporated within the standards
as applicable by the individual accountable for the specific standard as detailed in Table 1 of this
specification.
Individuals accountable for review of the various standards will review them at the period specified and
validate the following:
1) The Standard is in accordance with federal, state, and industry codes and standards.
2) Requested changes have been reviewed and incorporated within the standard as appropriate.
The required corrections/enhancements should be completed by the first of September each calendar
year to include approval by the Approver as noted in Table 1. Completion by this date will allow sufficient
time for the changes to be incorporated into the next year's GSM/GESH update.
GAS OPERATIONS AND REV. NO. 9
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Utilities SPEC. 1.4
NATURAL GAS

Appropriate parts of the Operating and Maintenance Plan will be prepared outlining procedures
necessary for conducting operations and maintenance and emergency operations before operations
commence on any new pipeline system. Copies of these procedures will be kept at locations where the
operations and maintenance activities are conducted.
Construction Procedures Filing With the WUTC
In the state of Washington, any new or updated construction procedures, designs, or specifications must
be provided to the Commission a minimum of 45 days prior to implementation. As a general rule, this will
be accomplished with the annual forwarding of the GSM/GESH to the Commission. In the event such
notification needs to occur during the calendar year; it must be completed under separate
correspondence.
WAC 480-93-017: State of Washington,
1. Any operator intending to construct or operate a gas pipeline facility in Washington must file with
the commission all applicable construction procedures, design, and specifications used for each
pipeline facility prior to operating the pipeline or have a plan and procedures manual on file with the
commission. All procedures must detail the acceptable types of materials,fittings, and components
for the different types of facilities in the operator's system.
2. With the exception of emergency situations,any construction plans that do not conform with Avista's
existing and accepted construction procedures, designs, and specifications on file with the
commission, must be submitted to the commission for review 45 days prior to the initiation of
construction activity.
Records Available To Operating Personnel
This manual and all manuals comprising Avista's Gas Operating and Maintenance Plan, are to be made
available to personnel performing design, construction, maintenance, and emergency response of the
natural gas systems along with maintenance and construction records which includes maps.
These manuals and records are to be made available, upon request, to responsible federal and state
regulatory personnel per§192.605(b)(3) and WAC 480-93-180.
GAS OPERATIONS AND REV. NO. 9
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Utilities SPEC. 1.4
NATURAL GAS

Table 1 -Standards Accountability
ResponsibleStandard Title Frequency
of Review
GSM Gas Standards Manual
1.0
1.0 Table of Contents Annually Pipeline Safety Engineer
1.1 Glossary Annually Pipeline Safety Engineer
1.2 Index Annually Pipeline Safety Engineer
1.3 Gas Acronyms and Abbreviations Annually Pipeline Safety Engineer
1.4 Gas Operations and Maintenance Plans Annually Pipeline Safety Engineer
2.0 Design Standards
2.12 Pipe Design-Steel Annually Design Manager
2.13 Pipe Design-Plastic(Polyethylene) Annually Design Manager
2.14 Valve Design Annually Design Manager
2.15 Bridge Design Annually Design Manager
2.22 Meter Design Annually Design Manager
2.23 Regulator Design Annually Design Manager
2.24 Meter and Regulator Tables and Drawings Annually Design Manager
2.25 Telemetry Design Annually Design Manager
2.32 Cathodic Protection Design Annually Design Manager
2.42 Vaults-Design Annually Design Manager
2.52 Odorization of Natural Gas Annually Design Manager
3.0 Construction
3.12 Pipe Installation-Steel Mains Annually Design Manager
3.13 Pipe Installation-Plastic(Poly)Mains Annually Design Manager
3.14 Precheck Layout and Inspection Annually Design Manager
3.15 Trenching and Backfilling Annually Design Manager
3.16 Services Annually Design Manager
3.17 Purging Pipelines Annually Design Manager
3.18 Pressure Testing Annually Design Manager
3.19 Trenchless Pipe Installation Methods Annually Design Manager
3.22 Joining of Pipe-Steel Annually Design Manager
3.23 Joining of Pipe-Plastic-Heat Fusion Annually Design Manager
3.24 Joining of Pipe-Plastic-Electrofusion Annually Design Manager
3.25 Joining of Pipe-Plastic-Mechanical Annually Design Manager
3.32 Repair of Steel Pipe Annually Design Manager
3.32A Permanent Repair Sleeves Annually Design Manager
3.33 Repair of Plastic Pipe Annually Design Manager
3.34 Squeeze-off of PE Pipe and Prevention of Static Electricity Annually Design Manager
3.35 Detailed Procedure for Use of"Adams"Style Repair Annually Design Manager
Clamps
3.42 Casing and Conduit Installation Annually Design Manager
3.43 Land Disturbance Requirements Annually Design Manager
GAS OPERATIONS AND REV. NO. 9
MAINTENANCE PLANS DATE 01/01/25
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Utilities SPEC. 1.4
NATURAL GAS

ResponsibleStandard Title Frequency
of Review
3.44 Exposed Pipe Evaluation Annually Compliance Manager
4.0 Operations
4.11 Continuing Surveillance Annually Compliance Manager
4.12 Safety-Related Conditions Annually Compliance Manager
4.13 Damage Prevention Program Annually Damage Prevention
Program Administrator
4.14 Recurring Reporting Requirements Annually Compliance Manager
4.15 Maximum Allowable Operating Pressure(MAOP) Annually Compliance Manager
4.16 Class Locations Annually Compliance Manager
4.17 Uprating Annually Design Manager
4.18 Odorization Procedures Annually Design Manager
4.19 Crew Activity Reporting-Washington Annually Compliance Manager
4.22 Customer Owned Service Lines Annually Compliance Manager
4.31 Operator Qualification Annually OQ Program Administrator
4.41 Transmission Integrity Management Program(TIMP) Annually TIMP Program Manager
4.42 Distribution Integrity Management Program Annually DIMP Program Manager
4.51 Gas Control Room Management Plan Annually Design Manager
4.61 Quality Assurance/Quality Control(QA/QC)Program Annually QA/QC Manager
4.62 Incident Assess., Failure Assess.&Lessons Learned Annually QA/QC Manager
5.0 Maintenance
5.10 Gas Maintenance Timeframes and Matrix Annually Compliance Manager
5.11 Leak Survey Annually Leak Survey Program Manager
5.12 Regulator and Relief Inspection Annually Design Manager
5.13 Valve Maintenance Annually Design Manager
5.14 Cathodic Protection Maintenance Annually Design Manager
5.15 Pipeline Patrolling and Pipeline Markers Annually Compliance Manager
5.16 Abandonment or Inactivation of Facilities Annually Design Manager
5.17 Reinstating Abandoned Gas Pipeline and Facilities Annually Design Manager
5.18 Vault Maintenance Annually Design Manager
5.19 Combustible Gas Indicator Testing and Calibration Annually Compliance Manager
5.20 Atmospheric Corrosion Control Annually AC Program Manager
5.21 Maintenance of Pressure Gauges and Recorders Annually Design Manager
5.22 Heater Maintenance Annually Design Manager
5.23 Odorization Equipment Maintenance Annually Design Manager
GAS OPERATIONS AND REV. NO. 9
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Utilities SPEC. 1.4
NATURAL GAS

StandardFre
of
..
Review
GESH Gas Emergency and Service Handbook
Section 1 Receiving and Dispatching Emergency Annually Operations Support Manager
Service Requests
Section 2 Leak and Odor Investigation Annually Sr. Nat.Gas Ops Mgr.
Section 3 Carbon Monoxide(CO)Orders Annually Sr. Nat.Gas Ops Mgr.
Section 4 Emergency Procedures—Blowing or Annually Sr. Nat.Gas Ops Mgr.
Uncontrolled Escaping Natural Gas
Section 5 Emergency Shutdown and Restoration of Annually Sr. Nat.Gas Ops Mgr.
Service
Section 6 Meter, ERT,AMI and Regulator Annually Design Manager
Installations
Section 7 Meter Turn-On Orders Annually Sr. Nat.Gas Ops Mgr.
Section 8 Meter Turn-Off Orders Annually Sr. Nat.Gas Ops Mgr.
Section 9 Meter Change Order/Meter Removal Annually Sr. Nat.Gas Ops Mgr.
Orders
Section 10 Gas Equipment Service Annually Sr. Nat.Gas Ops Mgr.
Section 11 Customer Charges Annually Sr. Nat.Gas Ops Mgr.
Section 12 Safety Inspections Annually Sr. Nat.Gas Ops Mgr.
Section 13 Emergency Planning,Training,and Annually Sr. Nat.Gas Ops Mgr.
Incident Notification
Section 15 Diversion of Service Annually Sr. Nat.Gas Ops Mgr.
Section 16 High Bill Investigations and Customer Annually Sr. Nat.Gas Ops Mgr.
Requested Meter Tests
Section 17 Gas Incident Field Investigation Annually QA/QC Manager
Tables Gas Input to Burner in CFH Annually Design Manager
GAS OPERATIONS AND REV. NO. 9
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Utilities SPEC. 1.4
NATURAL GAS

2.1 PIPE SYSTEMS
2.12 PIPE DESIGN -STEEL
SCOPE:
To establish a uniform procedure for designing steel gas piping systems that meets applicable regulatory
codes and provide a safe and reliable operating system.
REGULATORY REQUIREMENTS:
§192.7, §192.14, §192.18, §192.53, §192.55, §192.63, §192.67, §192.101, §192.103, §192.105,
§192.107, §192.109, §192.111, §192.113, §192.115, §192.141, §192.143, §192.144, §192.145,
§192.147, §192.149, §192.150, §192.151, §192.153, §192.159, §192.161, §192.241, §192.461,
§192.476, §192.501, §192.503, §192.505, §192.507, §192.509, §192.511, §192.611
WAC 480-93-020, 480-93-160
OTHER REFERENCES:
NACE SP0102, Section 7
CORRESPONDING STANDARDS:
Spec. 2.32, Cathodic Protection Design
Spec. 3.12, Pipe Installation— Steel
Spec. 3.15, Trenching and Backfilling
Spec. 3.18, Pressure Testing
Spec. 3.22, Joining of Pipe - Steel
DESIGN REQUIREMENTS:
General
New steel pipelines shall be in accordance with the provisions of API Standard 5L, ASTM Specification A-
53, or ASTM Specification A-106. Gas Engineering shall be responsible for the design of all applications
having an MAOP greater than 60 psig (high pressure designs). Steel pipelines must be coated and
cathodically protected per the requirements of Specification 2.32, Cathodic Protection Design.
Before using any new material, Gas Engineering will evaluate and approve the material by following the
New Gas Material Evaluation Checklist. Following this checklist will ensure the new material meets
specification and proper training has been completed with appropriate Company and contractor
personnel.
Gas Engineering will document via an engineered drawing all new projects involving high pressure gas,
and all new inside meter sets. These drawings will be peer reviewed by another engineer and final
signatory of the drawing must be a Professional Engineer.
PIPE SYSTEMS PIPE DESIGN - REV. NO. 25
STEEL DATE 01/01/24
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Utilities NATURAL GAS SPEC. 2.12

Converting an Acquired System
If acquiring a system that will be converted to natural gas and is not currently subject to 49 CFR Part 192,
Avista shall prepare a written plan to meet the requirements of§192.14. The plan shall include reviewing
past history records of the system, or if insufficient records are available, perform appropriate tests to
determine if the pipeline is in a satisfactory condition for safe operation, including visual inspection of
aboveground segments and selected underground segments for physical defects and operating
conditions which reasonably could be expected to impair the integrity of the pipeline and correct known
defects in accordance with CFR 49 Part 192. The pipeline must be tested to substantiate the maximum
allowable operating pressure permitted by CFR 49 Part 192 Subpart L. Records must be kept for the life
of the pipeline in regard to the investigation, tests, repairs, replacements, and alterations made under the
requirements of§192.14.
Steel Pipe Coating and Marking
Coating on new buried steel pipes must be applied on a properly prepared surface with an approved
coating meeting the requirements of§192.461 as follows:
• Have sufficient adhesion to the metal surface to effectively resist under film migration of moisture
• Be sufficiently ductile to resist cracking
• Have sufficient strength to resist damage due to handling and soil stress
• Have properties compatible with any supplemental cathodic protection
• Coating which is electrically insulating must also have low moisture absorption and high electrical
resistance.
• Coating must be applied and protected from damage during installation as outlined in Specification
3.12, Pipe Installation - Steel Mains.
Coated pipe shall be printed on the outside with the following information:
• Outside diameter of pipe
• Pipe wall thickness
• Pipe specification, grade, and seam type
• Coating company's name
• Date of coating application
• Coating type and thickness
• Purchase order number(Avista PO number preferred)
• Pipe manufacturer's name.
• Pipe heat number.
Factory-applied stenciling of the above printed information shall be maintained until the pipe has been
installed in the ground. If the pipe specification information has not been maintained, the pipe shall not be
used as carrier pipe. However, if the factory stencil fails, Avista personnel may reapply the required
information on the pipe before installation with complete verification of all data of the original stencil.
Design Formula for Steel Pipe
The design formula for steel pipe is given as follows:
2St
P =—xFxExT
D
PIPE SYSTEMS PIPE DESIGN - REV. NO. 25
STEEL DATE 01/01/24
X-41.5y' a STANDARDS 2 OF 16
Utilities NATURAL GAS SPEC. 2.12

Where:
P = design pressure (psig)
S = specified minimum yield strength (psi) in accordance with §192.107
D = outside diameter(in)
t= nominal wall thickness (in) in accordance with §192.109
F = design factor determined in accordance with §192.111
E = longitudinal joint factor determined in accordance with §192.113
T =temperature derating factor determined in accordance with §192.115
The design of new gas facilities and any subsequent additions or alterations to existing facilities shall
meet the maximum allowable operating pressure (MAOP) requirements of the pipeline. Future plans for
expansion or uprating may dictate a higher design MAOP. When possible, pipelines should be designed
so the MAOP of the pipeline is below 20 percent of the specified minimum yield strength (SMYS) of the
pipe.
Allowance shall be made in the overall design, in addition to internal pipeline hoop stress, for other
possible stress factors such as overburden, fill, external loads, thermal expansion and contraction, or
pipeline bending.
Class Location Considerations
For pipelines designed to operate at or in excess of 20 percent SMYS, design considerations and
pressure testing considerations must be made, as the pipeline will ultimately be limited to an MAOP as
specified by its Population Class Location. Refer to Specification 4.16, Class Locations. The MAOP of a
pipeline may not exceed that which will cause the following hoop stress as a percentage of SMYS for the
indicated Population Class Location*:
Class 1 - 72 percent SMYS
Class 2 - 60 percent SMYS
Class 3 - 50 percent SMYS
Class 4 -40 percent SMYS
*Note: A pipeline may be operated at a pressure which equates to "one class level out" if the pipeline has
previously been tested to 90 percent SMYS for the required test duration (Reference notes in subsection
"Pressure Testing" in this specification).
Transmission Lines—Design of Pipe and Components
• Each transmission line and each replacement of line pipe, valve, fitting, or other line component in a
transmission line (regardless of operating hoop stress) constructed after July 1, 2020, has the
following design and recordkeeping criteria:
o Collect or make and retain, for the life of the pipeline, records documenting that the pipe is
designed to withstand anticipated external pressures and loads in accordance with §192.103
and document that the determination of design pressure for the pipe is made in accordance with
§192.105
o Records that document the physical characteristics of the pipeline, including diameter, yield
strength, ultimate tensile strength, wall thickness, seam type, and chemical composition of
materials for pipe in accordance with §192.53 and §192.55 shall be made and retained for the
life of the pipeline. Records must include tests, inspections, and attributes required by the
manufacturing specifications applicable at the time the pipe was manufactured or installed.
PIPE SYSTEMS PIPE DESIGN - REV. NO. 25
STEEL DATE 01/01/24
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Utilities NATURAL GAS SPEC. 2.12

o Records documenting the manufacturing standard and pressure rating to which each valve was
manufactured and tested shall be made and retained for the life of the pipeline. Flanges, fittings,
branch connections, extruded outlets, anchor forgings, and other components with material yield
strength grades of 42,000 psi (X42) or greater and with nominal diameters of greater than 2
inches must have records documenting the manufacturing specification in effect at the time of
manufacture, including yield strength, ultimate tensile strength, and chemical composition of
materials.
o Must be designed and constructed to accommodate the passage of instrumented internal
inspection devices in accordance with NACE SP0102, Section 7. This does not apply to the
following:
■ Manifolds
■ Station piping such as at compressor stations, meter stations, or regulator stations
• Crossovers
■ Sizes of pipe for which an instrumented internal device is not commercially available
■ Transmission lines, operated in conjunction with a distribution system which are installed in
Class 4 locations.
• For steel transmission pipeline segments constructed on or before July 1, 2020, the following
documentation shall be retained for the life of the pipeline if they are available:
o Pipe design and the determination of design pressure in accordance with §192.103 and 192.105
o Physical characteristics of the pipeline, including diameter, yield strength, ultimate tensile
strength, wall thickness, seam type, and chemical composition of materials for pipe.
o Manufacturing standard and pressure rating for valves, flanges, fittings, branch connections,
extruded outlets, anchor forgings, and other components with material yield strength grades of
42,000 psi (X42) or greater and with nominal diameters of greater than 2 inches.
Transmission Line-Internal Corrosion Control
Each new transmission line and each replacement of line pipe, valve, fitting, or other line component in an
onshore transmission line that was installed after May 23, 2007, must have features incorporated into its
design and construction to reduce the risk of internal corrosion per the requirements of§192.476. At a
minimum, unless it is impracticable or unnecessary to do so, it must:
• Be configured to reduce the risk that liquids will collect in the line
• Have effective liquid removal features whenever the configuration would allow liquids to collect
• Allow use of devices for monitoring internal corrosion at locations with significant potential for
internal corrosion
There are design features that can be incorporated to address the requirements above including:
1. Minimizing dead ends and low areas
2. Minimizing aerial crossings since these can result in variation of temperature.
3. Designing for turbulent flow, in which the velocity at a given point varies erratically in magnitude
and direction, to decrease the chance of liquids separating from the flow and accumulating
4. Designing a pipeline to minimize entry of water and corrosive gases at receipt locations
5. Providing slam valves to isolate systems when corrosive gas is expected
6. Applying coatings to interior walls to inhibit internal corrosion
7. Identifying critical low spots and instrument the pipeline to monitor relevant operating conditions
(temperature, pressure, velocity, dew point)
8. Evaluating seasonal nature of delivery and capacity patterns and design to avoid no flow or low
flow conditions
9. Including equipment to evaluate gas characteristics and
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10. Including equipment to allow sampling at key areas, such as pig traps, isolated sections with no
flow, dead ends, and river and road crossings
When there are changes to the configuration of a transmission line, an evaluation must be done on the
impact of the change in regard to internal corrosion risk to the downstream portion of an existing onshore
transmission line and provide for removal of liquids and monitoring of internal corrosion as appropriate.
Records must be maintained to demonstrate compliance with this requirement. If it is impractical or
unnecessary to incorporate design features from 1 - 3 listed above, it shall be documented through
construction records and as-built drawings.
Transmission Line-Approval of Change
When considering a modification to Avista's transmission assets, an Approval of Change to Transmission
Pipeline System form is required to be filled out during the design or planning process. This form shall be
forwarded to the appropriate manager for approval of the change prior to the design or change. See
Section 13.4, Transmission Integrity Management Program (TIMP), for a list of changes with the
associated approving manager.
Part A of the Approval of Change to Transmission Pipeline System form is filled out by the individual
initiating the proposed change to the system and includes a list of reasons for making the proposed
change. The initiator chooses the appropriate reason driving the change to the transmission pipeline
system and provides a description of the proposed change(s).
The initiator then signs and dates the form and forwards the form to the appropriate manager for
approval. Part B— Preliminary Review is then filled out by the manager. If approved, the form then goes
to the Pipeline Integrity Program Manager for processing if there are any conditions of approval identified
as outlined in Avista's Transmission IMP Plan, Section 13 - Management of Change Plan. The Pipeline
Integrity Program Manager will file the document as appropriate.
Reporting of Proposed Construction of Transmission Main (WA)
WAC 480-93-160: In the state of Washington, a report must be filed with the WUTC at least 45 days
prior to the construction or replacement of any segment of a gas transmission pipeline equal to or
greater than 100 feet in length. Emergency repairs are exempt from this rule.
Design of Pipeline Components
Company approved pipeline components shall meet the requirements of Part 192, Subpart D. Pressure
ratings for Company approved fittings, valves, and other piping components shall be equal to or greater
than the MAOP for the pipeline being built. Design of pipeline components shall be based on unit stresses
equivalent to those allowed for comparable material in pipe or based upon a pressure rating established
by the manufacturer by pressure testing that component or a prototype of the component. In addition,
fittings, valves, and other piping components to be tested as part of the pipeline system must be able to
withstand the test pressure, which is generally a minimum of 1.5 times the proposed MAOP. Each fitting
used to make a hot tap must be designed for at least the MAOP of the pipeline system.
PIPE SYSTEMS PIPE DESIGN - REV. NO. 25
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Welded branch connections made to pipe in the form of a single connection, header, or manifold as a
series of connections must be designed to ensure that the strength of the pipeline system is not reduced
by considering the stresses in the remaining pipe wall due to the opening in the pipe or header, the shear
stresses produced by the pressure acting on the area of the branch opening, and external loadings due to
thermal movement, weight, and vibration. Branch sizes larger than 2 inches in diameter must be
evaluated per ASME B31.8, Section 831.42.
Extruded outlets must be suitable for anticipated service conditions and must be at least equal to the
design strength of the pipe and other fittings in the pipeline to which it is attached. Steel butt weld fittings
must have pressure and temperature ratings based on stresses for pipe of the same or equivalent
material. The actual bursting strength of the fitting must at least equal the computed bursting strength of
pipe of the designed material and wall thickness, as determined by a prototype that was tested to at least
the pressure required for the pipeline to which it is being added.
Field fabricated fittings (e.g., orange-peel caps and reducers) may not be used without prior approval
from Gas Engineering. Field fabricated fittings are not approved for use on pipelines that are to operate at
a hoop stress of 20 percent or more of the SMYS of the pipe. This does not include mitering of weld
elbow fittings as discussed in Specification 3.12, Pipe Installation —Steel Mains.
Flat closures (circular plate) have restricted uses. Refer to Specification 5.16, Abandonment, or
Inactivation of Facilities for approved uses of flat closures. Fish tails (pinch and weld) shall not be used.
Threaded fittings shall not be used on aboveground pipeline facilities 3 inch and larger without
concurrence by Gas Engineering. The minimum metal thickness for threaded fittings may not be less than
specified for the pressure and temperatures in the applicable standards as referenced in Part 192. When
close all-threaded nipples are used, the remaining wall thickness must meet the minimum wall thickness
requirements. Connections made of lead or other easily damaged material may not be used in the
installation of meters or regulators.
Pipeline systems should be welded where possible. Welding provides a stronger joint with less likelihood
of future leakage. Full encirclement type line stopper fittings should be used on steel pipelines with an
MAOP greater than 60 psig. Full encirclement fittings provide added stability for the tapping assembly.
Generally, service valve installations do not require full encirclement fittings. Partial encirclement or top-
stopper type fittings may be used on pipelines with an MAOP greater than 60 psig provided the pipe and
tapping gear are properly supported to minimize the stresses induced during tapping and stopping.
Pressure Vessels and Prefabricated Units
Prefabricated welded assemblies should be composed of standard pipe and fittings using circumferential
welds whenever possible. Prefabricated welded assemblies that are composed of standard pipe and
fittings using circumferential welds (such as regulator stations and meter set assemblies) are not
considered a prefabricated unit. Fabrications using plate and longitudinal seam welds (such as odorizers,
heaters and some filter housings) are considered a prefabricated unit and shall be designed, constructed,
and tested according to ASME Boiler Pressure Vessel Code and should come with a U-1 stamp and
documentation whenever possible. The following requirements shall be met for permanently or
temporarily installed prefabricated units or pressure vessels:
• Preferred Method - Pressure test the prefabricated unit or pressure vessel in its final
installation location per the requirements of Specification 3.18, Pressure Testing. The test may
be performed before or after it has been tied-in to the pipeline. Test records shall be kept for
the life of the asset; or
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• Pressure test prior to installation (shop or manufacturer test) and then perform an inspection
once it is installed prior to being placed into operation. The prefabricated unit or pressure
vessel shall be inspected after it has been placed on its support structure at its final installation
location to confirm that the prefabricated unit or pressure vessel was not damaged during any
prior operation, transportation, or installation into the pipeline. The inspection may take place
before or after it has been tied-in to the pipeline. Any inspection, repair or test records must be
kept for the life of the asset. The inspection procedure and documented inspection shall
include at a minimum:
o Visual inspection for vessel damage, including inlets, outlets, and lifting locations.
o Injurious defects that are an integrity threat may include dents, gouges, bending,
corrosion, and cracking. If any defects are found, the prefabricated unit or pressure
vessel must be either non-destructively tested, re-pressure tested, or remediated in
accordance with the applicable part 192 requirements for a fabricated unit or with the
applicable ASME Boiler Pressure Vessel Code requirements.
For temporary use of a prefabricated unit or pressure vessel, such as a temporary odorizer, the vessel
may be temporarily installed in a pipeline facility in order to complete a testing, integrity assessment,
repair, odorization, or emergency response related task, including noise or pollution abatement. The
temporary prefabricated unit or pressure vessel must be promptly removed after the task is complete.
If operational or environmental constraints require leaving a temporary prefabricated unit or pressure
vessel in place for longer than 30 days, PHMSA and the State pipeline safety authority must be notified in
accordance with §192.18.
An existing prefabricated unit or pressure vessel that is temporarily removed from a pipeline facility to
complete a testing, integrity assessment, repair, odorization, or emergency response related task,
including noise or pollution abatement, must be visually inspected for damage and injurious defects as
required above. However, a new pressure test is not required provided no damage or threats to the
operational integrity were identified during the inspection and the MAOP of the pipeline is not increased.
An existing prefabricated unit or pressure vessel that is relocated and operated at a different location
must be designed and constructed in accordance with this section and meet the testing requirements for
a newly installed prefabricated unit or pressure vessel.
Joining of Steel Pipeline Components
Mechanical fittings shall not be used to join steel pipe with the exception of bolted valves, flanges,
expansion joints, pressure couplings, threaded connections, and Victaulic couplings. In each case, the
assembly must be properly rated to meet or exceed the pipeline system MAOP. Threaded connections
shall not be used on underground pipeline systems. Flanged connections should also be avoided on
underground pipeline systems.
Flanged Connections
Flanges and flange accessories must be designed to meet the minimum requirements of ASME B16.5,
MSS SP-44, or equivalent. Each flange assembly must be rated to operate at the MAOP of the system
and must maintain its physical and chemical properties at all temperatures the system may operate in.
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ASTM A105 STEEL PIPE FLANGES AND FLANGED FITTINGS (ASME B16.5)
Rating in PSIG
Temperature ff) ANSI 150 ANSI 300 ANSI 600
-20 to 100 285 740 1480
101 to 200 260 675 1360
201 to 300 230 655 1310
Steel flange ratings are often referred to in any of the following ways, all of which have the same
meaning:
Class 150 ANSI 150
ASA 150 150 pound
150 # 150 LB
For flange joints, the bolting (bolts or stud bolts) used shall extend completely through the nuts and be in
conformance with ANSI B31.8 Section 831.22 and ASME B16.5 Section 5.3. Between the temperatures
of-20 degrees F and 400 degrees F, ANSI 150 and ANSI 300 flange joints should use ASTM A307 Gr. B
bolting; this is classified as "Low Strength". Outside this temperature range and for ratings higher than
ANSI 300, bolting shall conform to ASTM A193 Grade B7, or as defined by ASME B16.5 as "High
Strength". When using ASTM A307 bolting, either ASTM A563 or ASTM A194 nuts may be used. When
using ASTM A193 bolting, only ASTM A194 nuts maybe used. Studs shall be used on ANSI 600 flange
joints and greater. See table below for a summary:
FLANGE and FASTENER COMBINATIONS MINIMUM REQUIREMENTS
Flange Type, ANSI Bolts/Studs Nuts Gaskets
150 FF ASTM A307 Grade B ASTM A563 Grade A, Type E
- Bolts or Studs* Heavy Hex yp
150 RF ASTM A307 Grade B ASTM A563 Grade A, Type F
- Bolts or Studs* Heavy Hex yp
300 RF ASTM A307 Grade B ASTM A563 Grade A, Type F
-Bolts or Studs* Heavy Hex yp
600 RF ASTM A193 Grade B7 ASTM A194 Grade 2H, Type F
-Studs OnlyHeavyHex yp
*When the operating temperature will be outside-20°F to 450°F, use ASTM A193 Grade
137 bolts and ASTM Al94 Grade 2H nuts (see ASME B31.8, paragraph 831.22[b]).
SAE Grade 8 bolt and nuts may be found in the field and are acceptable but should not be installed on
new ANSI 150 and 300 applications. ASTM A193, A194, and A307 hardware is stamped with its grade,
ASTM 563 Grade A nuts are not marked.
Type E gaskets are a full-faced gasket with the same outside diameter as the flange. Precision cut holes
match the bolt size and pattern for the intended flange. This design facilitates proper alignment of the
gasket during installation and keeps foreign material from shorting the flange insulation. Type E gaskets
are only to be used when bolting flat faced flanges.
Type F gaskets are made to fit the raised face portion of the flange only. As there are no bolts holes in the
Type F gasket, the inside diameter of the bolt hole circle is slightly smaller than the outside diameter of
the gasket, assuring an exact, automatic positioning of the gasket.
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Supports- General
Each pipeline and its associated equipment must be anchored or supported to prevent undue strain on
connected equipment, resist longitudinal forces caused by a bend or offset in the pipe, and prevent or
dampen excessive vibrations.
Each mechanical pipeline support or anchor must be made of durable, noncombustible material, and
must be designed with enough flexibility to allow free expansion and contraction between supports.
Supports or anchors shall not be welded to the carrier pipe. Supports or anchors should be mechanically
attached to carrier pipe and cathodic isolation should be provided where needed. Supports should also
have the ability to be lowered away from the gas carrying pipe to allow for atmospheric corrosion
inspection. For exposed transmission pipelines operating at a stress level 50 percent or more of SMYS, a
support must be provided by a member that completely encircles the pipe.
Thermal Contraction and Expansion
Steel pipe expands or contracts at a rate of 0.000078 inch for every foot of pipe subjected to a 1-degree F
temperature change. The following equation may be used to calculate thermal expansion or contraction in
steel pipe:
6 = 0.000078 (L)(At)
Where: 6 = elongation if(+) or contraction if(-) (in)
L = length of steel pipe (ft)
4t= change in temperature (OF), (+) if increase or(-) if decrease
Longitudinal Stress
The following equations may be used to calculate longitudinal stress induced by thermal change for
restrained pipe:
a+ =ocE(At)
a, = 195 (At)
Where: a, = longitudinal stress (psi)
o = coefficient of thermal expansion = 6.5xl0-6 (in/in-°F)
4t= change in temperature (OF), (+) if increase or(-) if decrease
E = modulus of elasticity= 30x106 psi
Deflection and Bending Stress
Supports must be spaced so as not to cause excessive deflection and excessive stress in the pipeline
being supported. The following equations may be used to calculate deflection and bending stresses:
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Utilities NATURAL GAS SPEC. 2.12

DEFLECTION
Max deflection of empty pipe caused by its weight between supports based on a single span with free
ends:
22.5 WLA4
0 = El yz
L
Max deflection of empty pipe caused by its weight between supports based on a continuous span:
22.5 WLA4
0 =
El y
L
Max deflection of empty pipe caused by its weight between supports based on a single span with fixed
ends:
22.5 WLA4
0 =
El
2 IL .I
Where: 0 = deflection (in)
W=weight of pipe (lbs/ft). See the Steel Pipe Data Table in
this specification
L = distance between supports (ft)
E = modules of elasticity (psi)
I = moment of inertia (in4). See the Steel Pipe Data Table
in this specification
BENDING STRESS
Max bending stress in empty pipe caused by its weight between supports based on a single span with
free ends:
_ 1.5 WLA2
6B Z
L L _I
Max bending stress in empty pipe caused by its weight between supports based on a continuous span:
_ 1.2 WLA2
6B Z
I. L -!
PIPE SYSTEMS PIPE DESIGN - REV. NO. 25
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Utilities NATURAL GAS SPEC. 2.12

Max bending stress in empty pipe caused by its weight between supports based on single span with fixed
ends:
_ WLA2
6B — Z
I_ L
Where: 6B = bending stress (psi)
W=weight of pipe (lbs/ft). See the Steel Pipe Data Table in
this specification
L = distance between supports (ft)
Z = section modulus (in'). See the Steel Pipe Data Table in
this specification
Seismic Supports
In seismic prone areas, pipe supports, and hangers should be designed to withstand seismic forces. In
addition to static loads of pipeline systems, use an additional 0.2g for vertical seismic force and 0.3g for
horizontal seismic force (i.e., supports and hangers must be able to withstand 120 percent of load weight
of pipeline system in the vertical direction and 30 percent of load weight in the horizontal direction).
Torsional Stress
Design considerations must be observed if the pipe will be subjected to torsional stresses. This most
often will occur when a pipe is supported on a structure such as a bridge crossing in a "double offset'
configuration. Stresses may be induced through temperature change or by other load factors. Maximum
torsional stress of an empty pipe with restrained ends (for the section being twisted) is:
Tro
Tmax= J
Where: Tmax = maximum torsional stress (psi)
T =torque (in-lb)
ro= outside radius = do/2 (in)
J = Polar moment of inertia = Tr/32 (do—d 4)
Where: do= outside diameter(in)
d; = inside diameter(in)
Washington State Proximity Considerations
WAC 480-93-020: The following proximity considerations are required in the state of Washington.
PIPE SYSTEMS PIPE DESIGN - REV. NO. 25
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Utilities NATURAL GAS SPEC. 2.12

Gas facilities having a MAOP greater than 500 PSIG shall not be operated within 500 feet of the places
described below:
• A building that is in existence or under construction prior to the date authorization for construction is
filed with the WUTC and that is not owned and used by the petitioning operator in its gas operations;
or
• A high occupancy structure or area such as a playground, recreation area, outdoor theater, or other
place of public assembly, which is occupied by 20 or more persons, on at least 5 days a week for 10
weeks in any 12-month period (the days and weeks need not be consecutive), which is in existence
or under construction prior to the date authorization for pipeline construction is filed with the
commission; and
• A public highway, as defined in RCW 81.80.010(3).
Gas Facilities having a MAOP greater than 250 PSIG and including 500 PSIG shall not be operated
within 100 feet of the places described below:
• A building that is in existence or under construction prior to the date authorization for construction is
filed with the WUTC and that is not owned and used by the petitioning operator in its gas operations;
or
• A high occupancy structure or area such as a playground, recreation area, outdoor theater, or other
place of public assembly, which is occupied by 20 or more persons, on at least 5 days a week for 10
weeks in any 12-month period (the days and weeks need not be consecutive), which is in existence
or under construction prior to the date authorization for pipeline construction is filed with the
commission.
For proposed new construction of pipelines having the characteristics listed above, Avista must provide
documentation proving that it is not practical to select an alternate route that will avoid such locations and
further provide documents that demonstrate that the operator has considered the possibility of the future
development of the area and has designed the pipeline facilities accordingly.
During the review process, Avista must provide maps and records to the Commission showing the exact
location of the pipeline and the shortest direct distance to the places described above. Upon request of
the Commission, Avista must provide maintenance, construction, and operational history of the pipeline
system. Also, Avista must provide an aerial photograph showing the exact location of the pipeline in
reference to the places listed above.
Protection of Aboveground Steel Pipelines
Each aboveground transmission line or main not located in inland navigable water areas must be
protected from accidental damage by vehicular traffic or other similar causes, either by being placed at a
safe distance from the traffic or by installing some type of barricade.
Clearances & Cover
See Specification 3.15, Trenching and Backfilling for the requirements of cover and clearances for steel
pipelines.
Easement Considerations
When designing pipe to be installed in an easement, the minimum preferred easement width is 20 feet
extending 10 feet in each direction from the centerline of the pipe. The easement language should ensure
the Company's ability to maintain access to the pipe and restrict installation of structures, bushes, trees,
and other vegetation that could be detrimental to the buried facility within the easement.
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Utilities NATURAL GAS SPEC. 2.12

Steel Pipe Data Tables
The following tables provide useful dimensional and engineering data for various steel pipe specifications:
STEEL PIPE DATA TABLE
NOM. WALL
PIPE THICKNESS DIMENSIONS WEIGHTS CIRCUMFERENCE AREAS DESIGN PROPERTIES VOLUME
SIZE
IRON WALL PLUS CROSS-SECTIONAL MOMENT RADIUS
SCH. OUTSIDE INSIDE EMPTY WATER OF SECTION
PIPE NO. DIA. DIA. THICK- PIPE IN EXTERNAL INTERNAL FLOW METAL INERTIA MODULUS OF INSIDE PIPE
SIZE NESS PIPE 1 GYRATION
LB.PER LB.PER 2 2 4 3 3FT. GAL.
IN. IN IN. IN. FT. FT. IN. IN. IN. IN. IN. IN. IN. PERFT. PERFT.
314 STD. 40 1.050 .824 .113 1.131 .231 3.299 2.589 .5333 .3326 .0370 .0705 .3337 .0037 .0277
XS 80 1.050 .742 .154 1.474 .187 3.299 2.331 .4324 .4335 .0448 .0853 .3214 .0030 .0225
1 STD. 40 1.315 1.049 .133 1.679 .375 4.131 3.296 .8643 .4939 .0873 .1328 .4205 .0060 .0449
XS 80 1.315 .957 .179 1 2.172 .312 1 4.131 3.007 1 .7193 .6388 1 .1056 .1606 .4066 1 .0050 .0374
11/4 STD, 40 1.660 1.380 .140 2.273 .648 5.215 4.335 1.4957 .6685 .1947 .2346 .5397 .0104 .0777
XS 80 1.660 1.278 .191 2.997 .556 5.215 4.015 1.2828 .8815 .2418 .2913 .5237 .0089 .0666
11/2 STD. 40 1.900 1.610 .145 2.718 .882 5.969 5.058 2.0358 .7995 .3099 .3262 .6226 .0141 .1058
XS 80 1.900 1.500 .200 3.631 .766 5.969 4.712 1.7671 1.0681 .3912 .4118 .6052 .0123 .0918
2 STD. 40 2.375 2.067 .154 3.65 1.45 7.461 6.494 3.356 1.075 .666 .561 .787 .0223 .1743
XS 80 2.375 1.939 .218 5.02 1.28 7.461 6.092 2.953 1.477 .868 .731 .766 .0205 .1534
3.500 3.218 .141 5.06 3.52 10.996 10.104 8.129 1.492 2.102 1.201 1.187 .0564 .4222
3.500 3.188 .156 5.57 3.46 10.996 10.015 7.982 1.639 2.296 1.312 1.184 .0554 .4140
3 3.500 3.124 .188 6.65 3.32 10.996 9.814 7.665 1.956 2.691 1.538 1.173 .0532 .3982
STD. 40 3.500 3.068 .216 7.58 3.20 10.996 9.638 7.393 2.228 3.017 1.724 1.164 .0513 .3840
XS 80 3.500 2.900 .300 10.25 2.86 1 10.996 9.111 6.605 3.016 3.894 2.225 1.136 .0459 .3431
- 4.500 4.188 .156 7.24 5.97 14.137 13.157 13.775 2.129 5.028 2.235 1.537 .0957 .7155
4 4.500 4.124 .188 8.66 5.79 14.137 12.956 13.358 2.547 5.930 2.636 1.526 .0928 .6939
STD. 40 4.500 4.026 .237 10.79 5.52 14.137 12.648 12.730 3.174 7.233 3.214 1.510 .0884 .6613
XS 80 1 4.500 3.826 .337 14.98 4.98 14.137 12.020 11.497 1 4.407 9.610 1 4.271 1.477 .0798 .5972
- 6.625 6.313 .156 10.78 13.6 20.813 19.829 31.30 3.17 16.59 5.01 2.29 .2174 1.6260
6.625 6.281 .172 11.85 13.4 20.813 19.732 30.96 3.49 18.16 5.48 2.28 .2152 1.6096
6 6.625 6.249 .188 12.92 13.3 20.813 19.632 30.67 3.80 19.71 5.95 2.28 .2130 1.5932
STD. 40 6.625 6.065 .280 18.97 13.5 20.813 19.054 28.89 5.58 28.14 8.50 2.25 .2006 1.5008
XS 80 6.625 5.761 .432 1 28.57 13.3 1 20.813 18.099 26.07 8.40 40.49 12.22 2.19 .1810 1.3541
8.625 8.281 .172 15.53 23.3 27.096 26.018 53.86 4.57 40.81 9.46 2.99 .3740 2.7979
8.625 8.248 .188 16.94 23.2 27.096 25.915 53.44 4.98 44.37 10.29 2.98 .3711 2.7763
8.625 8.219 .203 18.30 23.0 27.096 25.821 53.06 5.38 47.64 11.05 2.98 .3685 2.7562
8 8.625 8.187 .219 19.66 22.8 27.096 25.720 52.64 5.78 51.12 11.85 2.97 .3656 2.7347
8.625 8.063 .281 25.07 22.1 27.096 25.331 51.05 7.37 64.18 14.86 2.95 .3546 2.6524
STD. 40 8.625 7.951 .322 28.55 21.7 27.096 25.073 50.03 8.40 72.49 16.21 2.94 .3474 2.5988
XS 80 8.625 7.625 .500 43.39 19.8 27.096 23.955 45.66 12.76 105.72 24.51 2.88 .3171 2.3721
10.750 10.374 .188 31.21 36.6 33.772 32.597 84.52 6.24 87.01 16.19 3.73 .5870 4.3909
10.750 10.344 .203 23.87 36.4 33.772 32.497 84.04 6.73 93.57 17.41 3.73 .5836 4.3654
10 10.750 10.312 .219 24.63 36.2 33.772 32.396 83.52 7.25 100.48 18.69 3.72 .5800 4.3396
20 10.750 10.250 .250 28.04 35.8 33.772 32.201 82.52 8.25 113.71 21.16 3.71 .5730 4.2885
STD. 40 10.750 10.020 .365 40.48 34.2 33.772 31.479 78.85 11.91 160.73 29.90 3.67 .5476 4.0963
XS 60 10.750 9.750 .500 54.74 32.4 33.772 30.631 74.66 16.10 211.95 39.43 3.63 .5185 3.8785
12.750 12.344 .203 27.2 52.0 40.055 38.780 119.9 7.99 157.2 24.7 4.43 .8326 6.2281
12.750 12.312 .219 29.3 51.6 40.055 38.679 119.1 8.62 169.3 26.5 4.43 .8268 6.1847
20 12.750 12.250 .250 33.4 51.1 40.055 38.485 117.2 9.82 191.8 30.1 4.42 .8185 6.1225
12 12.750 12.188 .281 37.4 50.6 40.055 38.290 116.7 11.01 214.0 33.6 4.41 .8104 6.0619
12.750 12.126 .312 47.4 50.0 40.055 38.095 115.5 12.19 235.9 37.0 4.40 .8020 5.9992
STD. 12.750 12.000 .375 49.6 49.0 40.055 37.699 113.1 14.58 278.3 43.8 4.38 .7854 5.9752
XS 12.750 11.750 .500 65.4 47.0 40.055 36.914 108.4 19.24 361.5 56.7 4.33 .7530 5.6329
16.00 15.562 .219 36.9 82.4 50.265 48.889 190.2 10.86 338.0 42.3 5.58 1.3208 9.8796
10 16.00 15.500 .250 42.0 81.8 50.265 48.695 188.7 12.37 384.0 48.0 5.57 1.3104 9.8008
16 16.00 15.435 .281 47.0 81.1 50.265 48.500 187.2 13.88 429.0 53.6 5.56 1.2999 9.7239
20 16.00 15.376 .312 52.0 80.5 50.265 48.305 185.7 15.38 473.0 59.2 5.55 1.2895 9.6460
STD. 30 16.00 15.250 .375 63.0 79.2 50.265 47.909 182.7 18.41 562.0 70.3 5.53 1.2684 9.4885
XS 40 16.00 15.000 .500 83.0 76.6 50.265 47.124 176.7 24.35 732.0 91.5 5.48 1.2272 9.1800
10 18.000 17.500 .250 47.0 104.2 56.549 54.978 240.5 13.94 549.0 61.0 6.28 1.6703 12.4950
18.000 17.438 .281 53.0 103.5 56.549 54.783 238.8 15.64 614.0 68.2 6.27 1.6585 12.4065
18 18.000 17.375 .312 59.0 102.5 56.549 54.585 237.1 17.36 679.0 75.5 6.25 1.6465 12.3160
STD. 18.000 17.250 .375 71.0 101.3 56.549 54.192 233.7 20.78 807.0 89.6 6.23 1.6230 12.1405
XS 18.000 17.000 .500 93.0 98.4 56.549 53.407 227.0 27.49 1 1053.0 117.0 6.19 1.5763 11.7912
NOM. WALL
PIPE THICKNESS DIMENSIONS WEIGHTS CIRCUMFERENCE AREAS DESIGN PROPERTIES
SIZE VOLUME
PLUS CROSS-SECTIONAL
IRON WALL MOMENT RADIUS
SCH. OUTSIDE INSIDE EMPTY WATER SECTION
PIPE NO. DIA. DIA. THICK- PIPE IN EXTERNAL INTERNAL FLOW METAL OF MODULUS OF INSIDE PIPE
SIZE NESS PIPE INERTIA(I) GYRATION
LB.PER LB.PER 2 2 4 3 3FT.PER GAL PER
IN. IN IN. IN. FT. FT. IN. IN. IN. IN. IN. IN. IN. FT. I FT.
PIPE SYSTEMS PIPE DESIGN - REV. NO. 25
STEEL DATE 01/01/24
� VIST' a STANDARDS 13 OF 16
Utilities NATURAL GAS SPEC. 2.12

10 20.000 19.500 .250 53.0 129.4 62.832 61.261 298.8 15.51 756.0 75.6 6.98 2.0739 15.5142
20.000 19.438 .281 59.0 128.6 62.832 61.066 296.8 17.41 846.0 84.6 6.97 2.0608 15.4157
20.000 19.376 .312 66.0 127.8 62.832 60.872 294.9 19.30 935.0 93.5 6.96 2.0476 15.3175
20 20.000 19.312 .344 78.0 126.9 62.832 60.670 292.9 21.24 1026.0 102.6 6.95 2.0341 15.2154
STD. 20 20.000 19.250 .375 79.0 126.1 62.832 60.476 291.0 23.12 1113.0 111.3 6.94 2.0211 15.1189
20.000 19.188 .406 85.0 125.3 62.832 60.281 289.2 24.99 1200.0 120.0 6.93 2.0081 15.0206
XS 30 20.000 19.000 .500 104.0 122.9 62.832 59.690 283.5 30.63 1457.0 145.7 6.90 1.9689 14.7288
10 22.000 21.500 .250 58.0 157.4 69.115 67.544 363.1 17.18 1010.0 91.8 7.69 2.5215 18.8610
22.000 21.438 .281 65.0 156.4 69.115 67.349 361.0 19.17 1131.0 102.8 7.68 2.5067 18.7511
22 22.000 21.376 .312 72.0 155.5 69.115 67.155 358.9 21.26 1250.0 113.7 7.67 2.4922 18.6428
STD. 20 22.000 21.250 .375 87.0 153.7 69.115 66.759 354.7 25.48 1490.0 135.4 7.65 2.4629 18.4237
XS 30 22.000 21.000 .500 115.0 150.1 69.115 65.973 346.4 33.77 1952.0 177.5 7.60 2.4053 17.9926
24.000 23.500 .250 63.0 188.0 75.398 73.827 433.7 18.65 1315.0 109.6 8.40 3.0121 22.5317
10 24.000 23.438 .281 71.0 187.0 75;398 73.633 431.5 20.94 1472.0 122.7 8.39 2.9962 22.4130
24.000 23.376 .312 79.0 186.0 75.398 73.438 429.2 23.22 1629.0 135.7 8.38 2.9804 22.2946
24 24.000 23.312 .344 87.0 185.0 75.398 72.237 426.8 25.56 1789.0 149.1 8.36 2.9641 22.1711
STD. 24.000 23.250 .375 95.0 184.0 75.398 73.042 424.6 27.83 1942.0 161.9 8.35 2.9483 22.0549
20 24.000 23.188 .406 102.0 183.0 75.398 72.847 422.3 30.09 2095.0 174.6 8.34 2.9326 21.9359
24.000 23.125 .438 110.0 181.8 75.398 72.649 420.0 32.39 2248.0 187.4 8.33 2.9167 21.8167
XS 24.000 23.000 .500 125.0 180.0 75.398 72.257 415.5 36.91 2549.0 212.4 8.31 2.8852 21.5831
26.000 25.500 .250 69.0 221.3 81.681 80.111 510.7 19.85 1676.0 128.9 9.10 3.5465 26.5278
10 26.000 25.376 .312 86.0 219.2 81.681 79.721 505.8 25.18 2077.0 159.8 9.08 3.5122 26.2727
26 26.000 25.312 .344 94.0 218.1 81.681 79.520 503.2 27.73 2282.0 175.5 9.07 3.4945 26.1386
STD. 26.000 25.250 .375 103.0 217.0 81.681 79.325 500.7 30.19 2478.0 190.6 9.06 3.4774 26.0125
26.000 25.188 .406 111.0 215.9 81.681 79.130 498.3 32.64 2673.0 205.7 9.04 3.4603 25.8830
XS 20 26.000 25.000 .500 136.0 212.7 81.681 78.540 490.9 40.06 3257.0 250.5 9.02 3.4088 25.4999
30.000 29.438 .281 89.0 294.9 94.248 92.435 680.6 26.23 2896.0 193.1 10.51 4.7264 35.3533
10 30.000 29.376 .312 99.0 293.7 94.248 92.287 677.8 29.10 3206.0 213.8 10.50 4.7067 35.2082
30.000 29.312 .344 109.0 292.4 94.248 92.086 674.8 32.05 3524.0 234.9 10.49 4.6862 35.0526
30 STD. 30.000 29.250 .375 119.0 291.0 94.248 91.892 672.0 34.90 3829.0 255.3 10.47 4.6664 34.9069
30.000 29.188 .406 128.0 289.0 94.248 91.696 669.1 37.75 4133.0 275.5 10.46 4.6466 34.7566
30.000 29.125 .438 138.0 288.7 94.248 91.499 666.2 40.63 4440.0 296.0 10.45 4.6264 34.6054
XS 20 30.000 29.000 .500 158.0 286.2 94.248 91.106 660.5 46.34 5042.0 336.1 10.43 4.5869 34.3167
10 34.000 33.376 .312 112.0 379.1 106.814 104.854 874.9 33.02 4685.0 275.6 11.91 6.0757 45.4494
34.000 33.312 .344 124.0 377.7 106.814 104.653 871.5 35.37 5153.0 303.0 11.90 6.0524 45.2752
34 STD. 34.000 33.250 .375 135.0 376.3 106.814 104.458 868.3 39.61 5599.0 329.4 11.89 6.0299 45.1068
34.000 33.188 .406 146.0 374.9 106.814 104.283 865.1 42.84 6045.0 355.6 11.88 6.0074 44.9357
34.000 33.124 .438 157.0 373.4 106.814 104.062 861.7 46.18 6504.0 382.6 11.87 5.9843 44.7656
XS 20 34.000 33.000 .500 179.0 370.6 106.814 103.673 855.3 52.62 7384.0 434.3 11.85 5.9396 44.4311
10 36.000 35.376 .312 119.0 425.9 113.097 111.137 982.7 34.98 5569.0 309.4 12.62 6.8257 51.0595
36.000 35.250 .375 143.0 422.9 113.097 110.741 975.9 41.97 6659.0 369.9 12.60 6.7771 50.6964
STD. 36.000 35.188 .406 154.0 421.4 113.097 110.546 972.5 45.40 7191.0 399.5 12.59 6.7533 50.5182
36.000 35.124 .438 166.0 419.9 113.097 110.345 968.9 48.93 7737.0 429.8 12.57 6.7288 50.3347
36 36.000 35.062 .469 178.0 418.4 113.097 110.151 965.5 52.35 8263.0 459.0 12.56 6.7050 50.1571
20 36.000 35.000 .500 190.0 416.9 113.097 109.956 962.1 55.76 8786.0 488.1 12.55 6.6813 49.9799
XS 30 36.000 34.750 .625 236.0 411.0 113.097 109.170 948.4 69.46 10,868.0 603.8 12.51 6.5862 49.2684
36.000 34.626 .687 259.0 408.1 113.097 108.781 941.7 76.22 11,885.0 660.3 12.49 6.5393 48.9174
40 36.000 34.500 .750 282.0 405.1 113.097 108.385 934.8 83.06 12,906.0 717.0 12.47 6.4918 48.5621
STD. 42.000 41.250 .375 167.0 579.1 131.947 129.591 1,336.4 49.04 10,622.0 505.8 14.72 9.2806 69.4200
42.000 41.188 .406 180.0 577.3 131.947 129.396 1,332.4 53.05 11,474.0 546.4 14.71 9.2528 69.2100
42 42.000 41.124 .438 194.0 575.6 131.947 129.195 1,328.3 57.19 12,350.0 588.1 14.70 9,2240 69.0000
XS 42.000 41.000 .500 221.0 572.1 131.947 128.805 1,302.3 65.19 14,036.0 668.4 14.67 9.1684 68.5800
42.000 40.876 .562 249.0 568.7 131.947 128.416 1,312.3 73.16 15,707.0 748.0 14.65 9.1131 68.1700
SURFACE AREAS OF PIPE
NOMINAL PIPE SIZE 3/4 1 1114 11/2 2 3 4 6 8 10 12 16 18 20 22 24 26 30 34 36 42
SURFACE
AREAS SQ. .275 .344 .439 .497 .622 .916 1.178 1.173 2.26 2.81 3.34 4.19 4.71 5.24 5.76 6.28 6.81 7.85 8.90 9.42 10.99
FT./FT.
Manufacturing Design and Composition of Line Pipe
Steel pipe used for natural gas piping shall meet the specifications of API 5L, ASTM A-53, or ASTM A-
106 as listed in §192.7 documents incorporated by reference or to use from a previous edition of
specifications it must meet the requirements of§192.144. Each specification requires certain chemical
and physical tests are met by the manufacturer.
ASTM A-53 covers welded and seamless black and galvanized pipe. It is suitable for coiling, bending,
welding, and general fabrication. In addition, seamless A-53 pipe can be flanged. This specification
requires tensile, hydrostatic, flattening, coiling, and bending tests. Chemical analyses are also specified.
Grades A(30,000 psi SMYS) and B (35,000 psi SMYS) are covered by this specification.
PIPE SYSTEMS PIPE DESIGN - REV. NO. 25
STEEL DATE 01/01/24
�risra STANDARDS 14 OF 16
Utilities NATURAL GAS SPEC. 2.12

ASTM A-106 covers only carbon steel pipe. It can be used in high-pressure and high-temperature service
as well as in forming applications. ASTM A-106 requires hydrostatic, tensile, bending, coiling, and
flattening tests and calls for more complete analysis than A-53. Grades A and B are covered by this
specification.
API 5L provides standards for seamless and welded pipe used in conveying gas, water, and oil in both
the natural gas and oil industries. API 5L requires hydrostatic, tensile, flattening, and bending tests.
Chemical analyses are also specified. Grades A and B are covered by this specification as well as
Grades X-42 (42,000 psi SMYS)to Grade X-80 (80,000 psi SMYS).
Gas line pipe should be specified by Gas Engineering to assure the appropriate pipe is ordered for the
particular design application. Currently Avista's welding procedures permit welding of Grade B or greater
yield strength pipe.
Pipe Specification
When specifying pipe, the following information should be provided:
• Outside diameter and wall thickness
• Pipe specification and grade
• Longitudinal seam welding process
• Coating: specify bare or type of coating
Example specifications:
A) 16"x 0.250"W.T., API 5L Grade X-42, ERW, FBE coated
B) 4"x 0.237" W.T., API 5L Grade B, seamless, bare
C) 3/4" x 0.113" W.T., ASTM A-106 Grade B, seamless, FBE coated
The following grade specifications are normally used for 2-inch and larger steel line pipe:
ASTM A-53 Grade B (35,000 psi SMYS)
API 5L Grade B (35,000 psi SMYS)
API 5L Grade X-42 (42,000 psi SMYS)
API 5L Grade X-52 (52,000 psi SMYS)
API 5L Grade X-60 (60,000 psi SMYS)
API 5L Grade X-65 (65,000 psi SMYS)
Specification ASTM A-106 Grade B, ASTM A-53 Grade B, or API 5L Grade B (35,000 psi SMYS)
seamless shall be used for size smaller than 2 inches.
API 5L Grades higher than X-52 are typically utilized for pipelines with high operating pressures and large
diameters. API 5L Grades B through X-52 and ASTM A-53 Grade B are the most economical choices for
distribution pressure. They are also more ductile and easier to work than higher yield strength pipe.
For new pipe, longitudinal seams should be specified as seamless, electric resistance weld (ERW) or
double submerged-arc-weld (DSAW). Generally, all weld types are satisfactory, and consideration should
be based on price. Sometimes seamless pipe is specified for station pipe to avoid tapping through a
longitudinal seam.
The following are the available longitudinal seam welding processes by pipe diameter size:
3/4 inch—2 inch seamless
3 inch — 16 inch electric resistance weld or seamless
18 inch—36 inch double submerged-arc-weld
PIPE SYSTEMS PIPE DESIGN - REV. NO. 25
STEEL DATE 01/01/24
X-41.5y' a STANDARDS 15 OF 16
Utilities NATURAL GAS SPEC. 2.12

Pressure Testing
New, replaced, or re-connected pipelines and facilities transporting natural gas must be pressure tested.
Refer to Specification 3.18, Pressure Testing for minimum testing requirements.
Corrosion Protection
Steel pipeline systems must be cathodically protected. Generally, buried facilities are wrapped or coated
with a protective coating that meets the requirements of§192.461. Aboveground facilities are usually
painted, meeting the requirements of§192.479. A Cathodic Protection Technician should be consulted to
recommend the appropriate cathodic protection system during the design stage of a new steel pipeline.
Refer to Specification 2.32, Cathodic Protection.
AC Mitigation on New Steel Pipelines
During the design of a new steel pipeline, it should be determined whether it will be susceptible to
detrimental effects from stray electrical currents. Things to consider are the physical location, particularly
a location that may subject the new pipeline to stray currents from other underground facilities, including
other pipelines, and induced currents from electrical transmission lines, whether aboveground or
underground. A qualified Cathodic Protection Technician should review and recommend a design for AC
mitigation where needed. Also, a qualified Cathodic Protection Technician should be present during
construction, when applicable, to identify, mitigate and monitor any detrimental stray currents that might
damage new pipelines. Refer to Specification 2.32, Cathodic Protection Design.
PIPE SYSTEMS PIPE DESIGN - REV. NO. 25
STEEL DATE 01/01/24
'41.5y' a STANDARDS 16 OF 16
utilities NATURAL GAS SPEC. 2.12

2.13 PIPE DESIGN — PLASTIC (POLYETHYLENE)
SCOPE:
To establish a uniform procedure for designing and testing plastic gas piping systems that meets
applicable regulatory codes and provide a safe, reliable operating system.
REGULATORY REQUIREMENTS:
§192.59, §192.63, §192.121, §192.159, §192.204, §192.321; §192.325, §192.327, §192.375
WAC 480-93-178
CORRESPONDING STANDARDS:
Spec. 2.3, Cathodic Protection
Spec. 3.13, Pipe Installation— Plastic
Spec. 3.23, Joining of Pipe— Plastic (Polyethylene)— Heat Fusion
DESIGN REQUIREMENTS:
General
New polyethylene pipelines and fittings shall meet the provisions of applicable ASTM specifications, be
resistant to chemicals with which contact may be anticipated and be free of visible defects as noted in
§192.59. Applicable ASTM specifications include ASTM D2513— PE Pipe & Fittings, ASTM F1055—
Electrofusion type PE Fittings, ASTM F1924— Plastic Mechanical fittings for PE Pipe, ASTM F1948—
Metallic Mechanical Fittings for PE pipe and ASTM F1978— Factory Assembled Anodeless Risers and
Transition Fittings for PE Pipe. Used polyethylene pipe shall not be installed.
Plastic (polyethylene) pipe and components may be used for underground construction of pipeline to
operate at a MAOP not to exceed 60 psig. As material and installation costs for plastic are usually less
than for steel, plastic is usually preferred for applications up to 60 psig.
Plastic pipe and components may be used for aboveground construction only as described within this
specification.
The use of medium density (PE 2406/2708) and high density (PE 100/3408/4710) PE pipe is approved for
use in pipe and fitting assemblies that use pipe, such as anodeless risers, transition fittings, and stick
EFVs. Plastic pipe and components can be used for mains and services up through 6-inch in diameter
(PHMSA allows larger sizes, but Avista is not tooled to handle them).
Before using a new material, Gas Engineering will evaluate and approve the material by following the
New Gas Material Evaluation Checklist. Following this checklist will ensure the new material meets
specification and the proper training has been completed with appropriate Avista and contractor
personnel.
Markings on Plastic Pipe and Components
Polyethylene pipe and components shall be marked per the requirements of ASTM Specifications D2513
& F2897. The markings shall be applied to remain legible under normal handling and installation
practices.
PIPE SYSTEMS REV. NO. 24
PIPE DESIGN - PLASTIC DATE 01/01/24
X-VISTa STANDARDS 1 OF 5
unlit►es SPEC. 2.13
NATURAL GAS

The markings on PE pipe shall be in black for yellow pipe and white for black pipe, and stenciled
continuously along the length of the pipe in increments no further apart than two feet including the
following information:
• Nominal pipe size (IPS, CTS, or OD)
• SDR (Standard dimension ratio) or minimum wall thickness
• Manufacturer's name or trademark
• "GAS" and "ASTM D2513"
• Material designation (PE 2406/2708, PE 100/3408/4710)
• Three additional code letters as required per ASTM D2513 (the first identifies the temperature of
pressure rating; the second letter identifies the hydrostatic design basis at highest recommended
temperature; and the third letter identifies the melt index). CEE or CEC is the proper code for the
medium and high-density PE resins Avista is currently using.
• Appropriate code information that will enable manufacturer to identify pipe (i.e., lot number with NR
(No Rework), date code, plant code etc.)
• Additional Information (i.e., coil number, feet, alphanumeric code, etc.)
• A representative 16-character tracking and traceability identifier per ASTM F2897.
• Markings on plastic fittings or non-pipe components shall be marked on the body or hub of the
assembly including the following information. (See print line examples below):
• "ASTM D2513" as well as the applicable fitting specification
• Manufacturer's name or trademark
• Size designation
• Material type designation
• Three additional code letters as required per ASTM D2513 (See bullet item 6 above)
• Appropriate code that will enable the manufacturer to identify date and location of manufacture,
fitting production, and resin lots, and any additional information agreed upon by the manufacturer.
• A representative 16-character tracking and traceability identifier per ASTM F2897.
Pipe Print Line on Pipe Example
1" CTS X 0.090 WALL -- DURA-LINE POLYPIPE POLYTOUGH GDY 20
Pipe Diameter J
Sizing System
(CTS or IPS)
Standard Dimension or Minimum Wall Thickness
Manufacturer's Name&Trademark
Gas Distribution Yellow(20=2708)
-- GAS -- PE2708 -- CEE ASTM D2513 - - S01J64NR- -2EB
Material Designation Code
Elevated Temperature Code
Standard the Pipe is Designed to
Lot Number Resin Lot Code
Plant Code
--01 NOV13 500 FEET
Date Pi Manufactured
a e pe
Running Footage
PIPE SYSTEMS REV. NO. 24
PIPE DESIGN - PLASTIC DATE 01/01/24
X VISTa STANDARDS 2 OF 5
unlit►es SPEC. 2.13
NATURAL GAS

Design Pressure
The maximum pressure allowed for plastic piping systems is determined in accordance with either of the
following formulas found in §192.121:
P = DF x 2S x t/(D-t)
P = DF x 2S/(SDR- 1)
Where:
DF = Design Factor, a maximum of 0.32. A DF of 0.40 may be used if reviewed and approved by Gas
Engineering in accordance with §192.121.
P = Design pressure in PSIG, (Avista max: 60 PSIG)
S = Long term hydrostatic strength in PSI. Use 1250 PSI for yellow pipe operating at less than 100
degrees F; use 1600 PSI for black pipe operating at less than 100 degrees F; use 1000 PSI for both
yellow and black pipe operating between 100 degrees F and 140 degrees F (Note: Avista's 60 PSIG max
design pressure for plastic pipe is based upon a 1000 PSI hydrostatic strength (up to 140 degrees F))
t= minimum wall thickness in inches
D = specified outside diameter in inches
SDR = standard dimension ratio, the ratio of the average specified outside diameter to the minimum
specified wall thickness.
The following sizes and wall thicknesses of polyethylene plastic pipe are approved for use. Use of other
sizes and wall thickness should be reviewed and approved by Gas Engineering:
NOMINAL POLYETHYLENE PIPE DIMENSIONS
SIZE IN. MIN.WALL AVERAGE O.D., AVERAGE I.D., WEIGHT,
SDR* THICKNESS, IN. IN. IN. LBS/FT.
1/2 CTS(5/8 OD) 7 0.090 0.625 0.445 0.065
3/41PS 11 0.095 1.050 0.860 0.123
1"IPS*** 11 0.120 1.315 1.075 0.193
1-1/4 IPS*** 10 0.166 1.660 1.328 0.335
1-1/2"IPS*** 11 0.173 1.900 1.554 0.404
21PS 11 0.216 2.375 1.943 0.631
31PS*** 11.5 1 0.304 3.500 2.892 1.317
41PS** 11.5 1 0.391 4.500 3.718 2.176
61PS** 11.5 0.576 6.625 5.473 F 4.717
*SDR-Standard dimension ratio is calculated by dividing the average O.D. of the pipe by the minimum wall
thickness in inches.
** NOTE-Coiled 4-inch IPS and 6-inch IPS pipe may be used if an approved pipe straightener is employed.
***Pipe sizes may be found in the field but are no longer used for new construction.
Pressure/Temperature Limitations
Under normal conditions, buried plastic pipe would not be exposed to a high temperature of 100 degrees
F or greater or a low temperature of-20 degrees F or less. The only place where plastic pipe could be
subjected to these extreme temperature points would be where the plastic pipe is encased in a service
riser or in an above grade steel casing. Approved prefabricated service risers are designed to operate at
60 psig and in a temperature range of-20 degrees F to 140 degrees F.
Plastic pipe shall not be used where it could be exposed to a temperature of higher than 140 degrees F or
a temperature less than -20 degrees F unless all of the components being installed are rated by the
manufacturer for these operating temperatures.
PIPE SYSTEMS REV. NO. 24
PIPE DESIGN - PLASTIC DATE 01/01/24
X-VISTa STANDARDS 3 OF 5
unlit►es SPEC. 2.13
NATURAL GAS

Aboveground Plastic Pipe
Plastic pipe is typically installed below ground level, with the exception of when encased in a steel riser as
part of a meter set, for a temporary bypass condition, for temporary aboveground installations/
emergency repairs, and when encased on bridge crossings. For temporary aboveground installations, the
plastic pipe must be protected from potential damage. The appropriate method of protection will depend
on the project site and associated risk of leaving the aboveground plastic pipe unattended. Possible
methods of protection include:
• Install barricades and/or fencing around the aboveground plastic pipe
• Wrap the plastic pipe in yellow caution tape
• Build an aboveground conduit casing for the aboveground plastic pipe
If the temporary aboveground plastic pipe will be in place for one week or longer, Gas Engineering should
be contacted to discuss an appropriate protection plan.
In Washington State, notification to WUTC is required if the temporary installation will exceed 30 days.
WAC 480-93-178 (6): The maximum time limit that plastic pipe may be temporarily installed above
ground is 30 days. Plastic pipe may be installed temporarily aboveground for longer than 30 days if
Avista has a written monitoring program and notifies the WUTC by telephone prior to exceeding the
30-day timeframe.
Plastic pipe shall not be installed where it would be exposed in a pit, vault, or box, except in a valve box
that is installed for a plastic valve.
Bridge Crossings
Federal regulations permit installation of polyethylene pipe on bridges. Specific design considerations
must be employed to assure that the plastic is installed in a safe manner. Gas Engineering shall design
polyethylene pipe bridge crossings. Refer to Specification 2.15, Bridge Design, and Specification 3.42,
Casing and Conduit Installation.
Plastic Pipe under Waterways
Plastic pipe should not be installed under a waterway susceptible to scouring or migration unless it is
adequately protected. This can be accomplished using additional cover or by utilizing a steel casing.
Clearances and Cover
Refer to Specification 3.15, Trenching and Backfilling for the requirements of cover and clearances for
plastic pipelines.
Thermal Contraction and Expansion
Pipe and associated fittings must be designed and installed to minimize tensile stresses as a result of
temperature change. Allowance must be made for thermal contraction when plastic pipe is installed on a
warm day; otherwise, excessive tensile stresses could occur when the pipe cools.
PE pipe expands or contracts at a rate of 0.00008 to 0.00010 feet for every foot of pipe subjected to a 1-
degree F temperature change. Therefore, the following equation may be used to calculate thermal
expansion or contraction in PE pipe:
6 = a (L)(At)
PIPE SYSTEMS REV. NO. 24
PIPE DESIGN - PLASTIC DATE 01/01/24
X VISTa STANDARDS 4 OF 5
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NATURAL GAS

Where: 6 = elongation if(+) or contraction if(-) in feet
a = Coefficient of linear expansion. Use 0.00010 for PE 2406/2708, 0.00009 for PE 3408, and
0.00008 for PE 4710.
L = length of PE pipe in feet
At= change in temperature (°F), (+) if increase or(-) if decrease
This equates to approximately 0.08 to 0.10 feet(1.0 to 1.2 inches) of contraction/expansion of pipe per
100-foot length for every 10 degrees F temperature change. This is about 12 to 15 times greater than
that of steel pipe.
Joining of Plastic Pipelines
Only approved methods of heat fusion, electrofusion or approved mechanical fittings shall be used to join
polyethylene pipe. Plastic pipe may not be joined by a threaded joint or mitered joint. The preferred
method of joining for each size of pipe is as follows:
Pipe Size Method of Joining
Mains: Electrofusion
1/2"through 1-1/4"
2"through 6" Butt fusion, electrofusion
Services:
1/2"through 1-1/4" Mechanical fitting
2" Butt fusion, electrofusion,mechanical fitting
Polyethylene to steel transition joints may be made where MAOP of steel system is 60 psig or less. The
transition joint must be made using an approved transition fitting. Install a protective sleeve over the fitting
to provide support from external forces. Refer to Specifications 3.23, Joining of Pipe— Plastic
(Polyethylene)— Heat Fusion; 3.24, Joining of Pipe— Plastic (Polyethylene)- Electrofusion, and 3.25
Joining of Plastic— Plastic (Polyethylene)— Mechanical. The use of an insert stiffener is required with
mechanical type transition fittings. The gasket material in the fitting must be compatible with the pipe
material.
Cathodic Protection
Steel portions of a plastic system (any valves, risers, and other pressurized steel components) must be
cathodically protected either off tracer wire or by use of an anode. Refer to Specification 2.32, Cathodic
Protection. These are considered short, isolated sections of steel that require monitoring. Reference
Specification 5.14, Cathodic Protection Maintenance.
Tracer Wire
Solid type coated locating wire (minimum AWG #12)shall be installed with polyethylene pipe since it is
not locatable on its own. Horizontal Directional Drill (HDD) installs shall be installed with a tracer wire as
well (minimum AWG#10 should be used). Refer to Specification 3.13, Pipe Installation — Plastic
(Polyethylene) Mains, subsection Tracer Wire for details on installing tracer wire. Electric continuity
should be maintained at all wire connections. Wire connections are to be formed by use of Avista-
approved connectors and/or crimping tool or other approved methods. Refer to Drawing A-36277 and
subsection Wire Connections in Specification 3.13, Pipe Installation — Plastic (Polyethylene) Mains.
Consideration should be made to install a Little Fink at the end of a main to make access to the locating
wire easier. Refer to Drawing B-36271, Steel Test Stations & Isolation Fittings, in Specification 3.12, Pipe
Installation —Steel Mains.
PIPE SYSTEMS REV. NO. 24
PIPE DESIGN - PLASTIC DATE 01/01/24
X-VISTa STANDARDS 5 OF 5
unlit►es SPEC. 2.13
NATURAL GAS

2.14 VALVE DESIGN
SCOPE:
To establish a uniform procedure for gas valve selection and installation.
REGULATORY REQUIREMENTS:
§192.145, §192.179, §192.181, §192.193, §192.363, §192.365, §192.381, §192.385
WAC 480-93-100
CORRESPONDING STANDARDS:
Spec. 2.12, Pipe Design - Steel
Spec. 2.13, Pipe Design — Plastic
Spec. 2.23, Regulator Design
Spec. 3.16, Services
Spec. 5.13, Valve Maintenance
DESIGN REQUIREMENTS:
General
In general, plastic (polyethylene)valves are installed on polyethylene pipelines and steel valves are
installed on steel pipelines. Polyethylene valves may only be used for applications where system MAOP
is 60 psig or less.
Each steel valve must meet the minimum requirements of API 6D, or an equivalent national or
international standard that provides an equivalent performance level. Each polyethylene valve must meet
the minimum requirements stipulated in nationally recognized standards specific to PE valves in a gas
system.
Valves used must be pressure tested to withstand shell and seat pressures to not less than 1.5 times the
maximum service pressure rating. Valve shell and seat tests are normally conducted by the manufacturer.
The valve must have a maximum service pressure rating for temperatures that equal or exceed the
maximum service temperature.
No valves shall be installed or reused other than carbon steel, stainless steel, or polyethylene valves.
Neither ductile iron valves nor cast iron valves shall be installed or reused. When installing steel valves,
weld-end types are preferred over threaded or flanged valves since they are less prone to leakage.
The valve and its operating device must be accessible and protected from tampering and damage.
Underground valves shall be installed in valve boxes or vaults. A marker ball should be installed adjacent
to the valve box on the north side and buried at, or just below, the valve box top, giving adequate cover to
the ball of about 12" to 18". Aboveground valves, except service riser and meter set outlet valves, should
be installed with locking assemblies or with valve handles removed or secured in locked stations or
buildings. Except for abnormal conditions, service riser and meter outlet valves should not be locked.
VALVE TYPES
The following are the primary types of valves used in Avista's facilities. For a more complete description
of valve types and how they are operated and maintained, refer to Specification 5.13, Valve Maintenance.
PIPE SYSTEMS REV. NO. 25
VALVE DESIGN DATE 01/01/25
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utilities NATURAL GAS SPEC. 2.14

Steel Plug Valves
Steel plug valves historically make up the majority of the existing valves in steel gas distribution systems.
These quarter-turn valves have a reduced flow port in a conical plug and are no longer the valve of choice
for new construction or as a replacement valve because they require injection of grease to maintain
proper seal and torque. Plug valves 6-inch and larger may require special gearing to aid operation.
Steel Gate Valves
Steel gate valves are the valve of choice for buried high-pressure applications. They are designed so that
a threaded stem with a steel gate or conical end travels downward and seats in a receptacle to shut off
the flow of gas. These rugged and durable valves have a full open flow port and do not require lubricating
sealants. Steel gate valves require multiple turns to operate and as a result of this have low operating
torques. They are also significantly less expensive size-for-size than comparable heavy-duty plug valves
and ball valves.
Steel Ball Valves
Modern ball valves do not need lubricating and are designed so that gas flows through a machined ball.
The port is full open when the valve is cycled by a quarter-turn, making them ideal for use in regulator
station designs. Such valves, however, should not routinely be used in throttling applications. In
applications where a trunnion-mounted ball valve will have high differential pressures across it, a small
bypass should be considered to equalize the pressure across the valve prior to opening; this will prevent
damage to valve seats. In applications intended for throttling or blowdown valves, where pressure cannot
be equalized, a plug valve or gate valve should be considered. Approved stock-item ball valves may be
used in buried intermediate pressure applications. Care must be taken, however, to assure stem torque
ratings are sufficient for buried use. Except for W valves used for farm tap station inlet piping; steel ball
valves shall not be used in buried high-pressure applications without the approval of Gas Engineering.
Polyethylene Valves
Polyethylene valves are either of ball or plug design and are used in plastic distribution systems. They are
quarter turn type and require minimal torque to operate. These valves do not need lubricating and shall
not be used aboveground or in a vault. Polyethylene valves shall only be installed using a butt fusion,
spigot, and sleeve fittings (if the fitting can be installed per the manufacturer's instructions), or an
electrofusion process. Other mechanical fittings are not approved for the installation of PE valves.
Service Line Valves
Each service line valve (commonly known as a riser valve) shall be designed to prevent removal of the
valve core, except by use of specialized tools. Each service line valve must be installed upstream of the
regulator or, if there is no regulator, upstream of the meter. Each service line must have a shutoff valve in
a readily accessible location that, if feasible, is outside the building. The customer may install a fence
around the meter set to limit public access and reduce the possibility of vandalism. If locked, an Avista
pad lock must be used to allow Avista personnel access to enter the area. The fence must allow sufficient
room for maintenance activities to occur and should be installed after consultation with the Gas Meter
Shop or the local district office, as applicable. Avista reserves the right to request removal of the fence if
the aforementioned conditions of installation are not met.
Excess Flow Valve Performance Standards
Excess flow valves (EFVs) are to be installed per the requirements discussed in Specification 3.16,
Excess Flow Valves.
PIPE SYSTEMS REV. NO. 25
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The valve must meet the manufacturer's standards and industry specification to ensure:
1. The valve will function properly up to the maximum operating pressure to which the valve is rated.
2. The valve will operate for all reasonably expected temperatures for the operating area;
3. At pressures > 10 psig:
The valve will close at or not more than 50 percent above the rated closure flow rate specified by
the manufacturer; and upon closing, reduce the flow of gas thusly:
a) For an EFV designed to allow pressure to equalize across the valve—allows no more than 5
percent of the manufacturer's specified closure flow rate, up to a maximum of 20 CFH, or
b) For an EFV designed to prevent equalization, allows no more than 0.4 CFH.
4. The valve does not close when the pressure is less than the manufacturer's minimum specified
operating pressure and the flow rate is below the manufacturer's minimum specified closure flow
rate.
An EFV must meet the applicable requirements of subparts B and D of 49 CFR, Part 192. The valve
must be marked or the presence of an EFV on the service line must be identified. The EFV must be
located as near as practical to the fitting connecting the service line to the main.
Additionally, an EFV should not be installed on a service line where there have been prior problems with
contaminants in the gas stream that could cause the valve to malfunction or interfere with the removal of
liquids from the line for necessary maintenance.
Curb Valves(Underground Service Valves)
Underground service line valves or"curb valves" shall be installed on all services where meter sets are
installed inside buildings or where it is impossible to provide ready access to a service line valve (riser
valve) at the outside wall of a building. A curb valve shall also be installed on all new or replaced service
lines where the installed meter capacity is greater than 1000 CFH and an EFV will not be installed. See
Specification 3.16, Excess Flow Valves for guidance on when an EFV is needed. These curb valves will
be considered secondary valves in most cases, see the next subsection, "Emergency Curb Valves"for
exceptions. Curb valves should be located as close to the source main as possible. Consideration should
be given to locating the valve so that it will be accessible at all times.
Emergency Curb Valves
Curb valves are considered Emergency Curb Valves when installed on services to buildings in which it
would be difficult to quickly evacuate such as churches, schools, hospitals,jails, and convalescent
homes, regardless of the size and pressure of the service line. Additionally, if the meter set is located
inside with no outside riser valve, the curb valve shall be designated as an Emergency Curb Valve.
WAC 480-93-100 (2): In the state of Washington emergency curb valves shall be installed (in addition
to the criteria listed above) regardless of pressure, for these locations:
• Service lines 2-inch in diameter and larger to commercial and industrial buildings
• High occupancy buildings of more than 4 stories which would be difficult to quickly evacuate,
regardless of the service line length or pressure.
Note: WAC 480-93-100(2) The requirement above outlines the results ofAvista's consideration of
the criteria outlined in WAC 480-93-100 (2) (a through 0. The sites noted in paragraphs (a through f)
of the WAC have been considered as locations for valve installation. The above guidelines are the
result of that consideration and are in addition to Avista's stated guidelines within this Specification.
PIPE SYSTEMS REV. NO. 25
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Emergency Curb Valves are subject to maintenance on the schedule outlined in Specification 5.13, Valve
Maintenance.
Valves at New Housing Developments
When designing a gas distribution system for a new housing development or subdivision, consideration
should be given for installing a valve at the entrance to the development or subdivision. The valve will
allow for quick isolation of gas if an incident were to happen in the subdivision.
Criteria for Determining Emergency Operating Plan (EOP) Valves
An EOP valve is a type of emergency valve that is used to divide large gas distribution systems into more
manageable zones. Each transmission and distribution system must have specially designated valves,
spaced to reduce the time to shut down a section of main in an emergency. Emergency valve spacing is
determined by the operating pressure, the size of the mains, and local physical conditions of the area
(rural, urban, business districts, and areas with predominately high-rise buildings as in a Class 4 location
for instance). Sectionalizing an area, using EOP valves, should be considered based on the number of
customers and the manpower needed for restoration in a reasonable timeframe (i.e., 24-hour period).
Refer to Section 5, Emergency Shutdown and Restoration of Service, in the Gas Emergency and Service
Handbook for further guidelines.
Tying EOP Zones Together
When designing main extensions and reinforcements, it is vital to consider where EOP zones may exist
and to be aware of conflicts that may arise by joining EOP zones together. Whenever designing
reinforcement projects, valves should be installed between the new and old pipe systems and the local
Compliance Specialist shall be notified. Additionally, when designing main extensions, consideration must
be given to the placement of valves to ensure EOP zones are not adversely impacted.
Emergency Regulator Station Valves
Each regulator station serving more than two service points must have a valve installed on the inlet piping
at a distance from the regulator station (50-feet preferred, 20-feet minimum)sufficient to permit the
operation of the valve in an emergency and designated as an emergency valve. Consideration should be
given to installing a similar valve on the regulator station outlet piping. Gate stations should always have
outlet valves. Operations personnel should coordinate efforts and work with Gas Engineering as
appropriate to ensure that applicable emergency valves are prioritized for installation where they are
required as noted above or would promote improved system safety or reliability.
Farm tap regulators (sometimes referred to single service farm taps) should also have consideration for
inlet and outlet valves. The inlet valve should be designated as a secondary valve unless there is an
extenuating reason to designate it as an emergency valve (e.g., the farm tap serves a school, church,
hospital, limited mobility occupant structure, commercial building, industrial building or other high
occupancy structure, or area.) This emergency/secondary valve designation guidance is a requirement
in Washington per WAC 480-93-100 and a best management practice in Oregon and Idaho.
PIPE SYSTEMS REV. NO. 25
VALVE DESIGN DATE 01/01/25
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utilities NATURAL GAS SPEC. 2.14

Transmission Line Valves
Each transmission line must have sectionalizing block valves spaced as follows:
Population Class Minimum Spacing of Valves
Class 4 5 Miles
Class 3 8 Miles
Class 2 15 Miles
Class 1 20 Miles
Each main line valve installed in a transmission pipeline shall be full opening to allow for the passage of
internal inspection devices.
Each section of a transmission line between block valves must have a blow-down valve with enough
capacity to allow the transmission line to be blown down as rapidly as practical. Each blowdown
discharge must be located so the gas can be blown to the atmosphere without hazard to nearby
structures and overhead electrical lines.
Refer to Specification 2.12, "Transmission Lines— Design of Pipe and Components"for more information
related to design criteria and records documentation requirements.
For transmission pipelines installed or entirely replaced after April 10, 2023, that meet the requirements
below, Rupture Mitigation Valves (RMVs) must be installed.
• Diameter greater than or equal to 6 inches; and
• Located in Class 3 or Class 4 or HCA; or
• Located in Class 1 or Class 2 area with a PIR greater than 150 feet(See Transmission Integrity
Management Program (TIMP) manual for PIR values of transmission pipelines).
Rupture Mitigation Valve (RM10 Requirements
RMVs, or alternative equivalent technology, must be installed upstream and downstream of any new or
replaced Class 3 or Class 4 or HCA pipeline segment. If there is a crossover or lateral tied into the
segment between RMVs, then the crossover or lateral pipe must also have a valve, such that, when all
valves are closed there is no flow path for gas to be transported to the rupture site. Multiple Class 3 or
Class 4 or HCA segments may be contained within a single shut-off segment. The shut-off segment shall
have valves spaced as follows:
Population Class Minimum Spacing of Valves
Class 4 8 Miles
Class 3 15 Miles
Class 2 20 Miles
Class 1 20 Miles
For laterals extending from shut-off segments that contribute less than 5 percent of the total shut-off
segment volume may have RMVs, or alternative equivalent technologies, at locations other than the
mainline connection point, as long as all laterals contributing gas volumes to the shut-off segment do not
contribute more than 5 percent of the total shut-off segment gas volume based upon maximum flow
volume at the operating pressure.
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VALVE DESIGN DATE 01/01/25
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For laterals that are 12 inches in diameter or smaller, a check valve may be installed at the mainline to
meet this requirement if it allows gas to flow in one direction and automatically prevents gas from flowing
in the direction of the shut-off segment. The check valve must be inspected, operated, and remediated at
least once every calendar year not to exceed 15 months. Avista will be required to develop and
implement maintenance procedures for the check valve and notify PHMSA in accordance with 192.18 if a
check valve is chosen over an RMV for lateral isolation.
If an alternative equivalent technology is chosen over an RMV, PHMSA must be notified in accordance
with 192.18. A technical and safety evaluation shall be included in the notice to PHMSA, and all
alternative equivalent technologies must meet the requirements of 192.634 and 192.636.
Alternative equivalent technologies may include a manually operated shut off valve, but it must be
demonstrated that installation of an RMV would be economically, technically, or operationally infeasible in
the notification to PHMSA. In addition, operating procedures would need to be developed and
implemented that appropriately designate and locate nearby personnel to ensure valve shut-off in
accordance with the timing requirements of 192.636 and must account for the following without exceeding
the maximum response time allowed:
• Time for assembly of necessary operating personnel
• Acquisition of necessary tools and equipment
• Driving time under heavy traffic conditions and at the posted speed limit
• Walking time to access the valve
• Time to shut off all valves manually
Valve Numbering
Valve numbering shall be shown within the Avista's GIS system. New valves shall receive new numbers
at the time of installation. If a valve is being changed out/replaced in the same physical location, it
should maintain the same valve numbering. If a valve is being changed out/ replaced and installed at a
new location, whether to renumber or not shall be at the discretion of the local operations manager based
on EOP Plan considerations. Refer to Spec. 5.13, Valve Maintenance, "Valve Disable/Abandonment"for
further guidance on the difference between disabling and abandoning a valve.
Installation
Valves installed on a main for operation or emergency purposes must be placed in a readily accessible
location. The operating stem must be readily accessible. Valve boxes, when utilized, shall be installed so
as to avoid transmitting external loads to the main. Valve box lids should be easily removable and painted
yellow. Cathodic protection wires, if required, should be installed in such a way that they will not be
damaged by the use of a valve key, including installing the wires on the outside of the valve box bottom.
For future use of the wires, they should be left long enough so 36" of wire can be pulled from the valve
box.
Generally, mainline valves installed within Avista's facilities should be in the open position unless there is
a specific reason for them to be closed, for example for pressure zone isolation. This includes valves that
are installed in pipe "pup" locations for future use. These valves should be open so that if the downstream
pipe is damaged, that damage will be evident and can be repaired immediately. For aboveground
installations, consideration should be given to orienting the valve, so the stem is in the horizontal position.
This will help prevent water from entering the valve.
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Weld end ball or plug valves should always be placed in the open position when welding. This will keep
the weld splatter off the ball or plug. Weld end gate valves should always be placed in the closed position
when welding. This will keep the weld splatter out of the seat.
Valve Supports
Transmission and distribution line valves shall be supported to prevent settling of the valve or movement
of the pipe to which it is attached. If the valve is installed in a buried box or enclosure, the box or
enclosure must be installed as to avoid transmitting external loads to the main. Each valve installed in
plastic systems must be designed to protect the plastic material against excessive torsional or shearing
loads when the valve is operated.
Corrosion
Buried steel valves must be externally coated or wrapped. Isolated steel valves within plastic systems
require additional cathodic protection. Refer to Specification 2.32, Cathodic Protection Design. These
isolated steel valves are considered short sections of steel and require monitoring just like any other short
section of steel and must be placed on the Short Section Cathodic Ten Percent Survey. Refer to
Specification 5.14, Cathodic Protection Maintenance for further guidance on this maintenance
requirement.
Valve Codes
Valves listed in Avista's GIS system are identified in the"USAGECODE"field by the following
abbreviations:
E = Emergency Zone Valve: A valve that isolates an EOP zone.
= Emergency Station Isolation Valve: The inlet or outlet valves to a regulator station, typically 25
feet to 50 feet outside of the station (Single-service farm tap inlet valves are not automatically
considered Emergency Station Isolation Valves and may be designated as Secondary Valves.)
X= Emergency Zone and Station Isolation Valve: A valve that is both an emergency zone valve and a
station isolation valve.
A= Emergency Mainline Valve: Any other emergency valve on a main that should be designated for
emergency situations. (Example: valves on either side of a bridge.)
M = Emergency Curb Valve: Those curb valves on services that must be designated as emergency
valves.
P = Emergency Pressure Isolation Valve: A valve that is normally closed and separates two different
pressure zones.
Y= Emergency Zone and Pressure Isolation Valve: Both an EOP zone and pressure isolation valve.
C = Secondary Curb Valve: Any other valves on services that are not used for emergencies.
S = Secondary Mainline Valve: Any other valves on mains that are not classified as any of the above
and are not used for emergencies.
PIPE SYSTEMS REV. NO. 25
VALVE DESIGN DATE 01/01/25
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utilities NATURAL GAS SPEC. 2.14

2.15 BRIDGE DESIGN
SCOPE:
To establish general guidelines for the design and installation of natural gas lines on bridge structures.
REGULATORY REQUIREMENTS:
§192.159, §192.161, §192.321, §192.323
WAC 480-93-115
CORRESPONDING STANDARDS:
Spec. 2.12, Pipe Design —Steel
Spec. 2.13, Pipe Design — Plastic
Spec. 2.3, Cathodic Protection
Spec. 3.42, Casing & Conduit Installation
DESIGN REQUIREMENTS:
General
Bridge designs are unique, and situations involved with each design are unique; therefore, Gas
Engineering shall be consulted for pipeline installations involving bridges.
Bridge crossing designs often include the use of hangers, seismic bracing, expansion joints, and other
special design features. Federal regulations permit the installation of either steel or polyethylene pipe on
bridges. Specific design considerations must be employed to so that the polyethylene pipe is installed in a
safe manner to make sure it is adequately supported and does not overheat.
Pipeline Installation
Pipelines installed on a bridge structure shall be placed to allow for future inspection of hangers, seismic
bracing, pipe, expansion joints, etc. Ideally, the pipe will be installed within the outermost girders on the
downstream side of the bridge. This allows for easy inspection while protecting the pipe from stream
flows, effects of sunlight and damage from traffic. This will involve coordination with responsible parties to
allow for manhole and crawl space access within bridge structures.
On new bridges, construction arrangements shall be made to provide suitable openings or advance
placement of the casing or pipe through the structure and abutments of the bridge. Pipe support
structures on either new or existing bridges must be coordinated closely with the agency responsible for
the bridge. The pipe support design should provide for future increases in pipe size wherever practical.
Permits
When a pipeline crosses state highway bridge structures, an application must typically be made for an
encroachment permit. The permit application shall comply with current state Department of Transportation
requirements. Permit applications for other than state highway crossings shall be obtained from the
responsible government agency.
PIPE SYSTEMS REV. NO. 12
BRIDGE DESIGN DATE 01/01/25
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Design Requirements
Pipe wall thickness shall be chosen to allow for hoop, bending, and torsional stresses due to temperature
change, pressure, weight of pipe (including weight of water if carrier pipe is to be hydrostatically tested on
the bridge), and any movement of or stresses caused by the configuration of the bridge. Pipe wall
thickness shall be as required to meet required stress calculations.
Thermal expansion forces and stresses shall be considered for bridge spans over
100 feet. Reference Specification 2.12, Pipe Design - Steel. It may be necessary to compensate for
thermal expansion by the use of approved expansion fittings or by use of pipe fittings using "U" or"L" pipe
bends.
Stresses due to temperature should be based on a temperature range of-20 degrees F to 110 degrees F.
As both allowances for thermal contraction and thermal expansion need to be considered, calculations
need to be based on probable temperature variations from the temperature at time of construction.
Maximum hoop stress due to internal gas pressure shall not exceed 40 percent of SMYS of the carrier
pipe. When possible, the pipeline should be designed so that the hoop stress is less than 20 percent of
SMYS. Use of isolation valves should be considered at both ends of bridge, outside of the bridge
structure, to allow isolation of the pipeline on the bridge structure.
Supports
Care should be taken in selection of supports, hangers, brackets, rollers, and pads. Allowance must be
made for the casing and carrier pipeline to expand and contract at a different rate than the bridge yet be
restrained and supported satisfactorily.
Seismic Supports
In seismic prone areas, pipe supports, and hangers should be designed to withstand seismic forces. In
addition to static loads of pipeline systems, use an additional 0.2g for vertical seismic force and 0.3g for
horizontal seismic force (i.e., supports and hangers must be able to withstand 120 percent of load weight
of pipeline system in the vertical direction and 30 percent of load weight in the horizontal direction).
Reference Specification 2.12, Pipe Design —Steel.
Corrosion Protection
Carrier pipe shall be electrically isolated from the bridge structure and support components through the
use of insulated fittings on pipe hangers and support hardware. Steel carrier pipe and weld joints shall be
coated with an approved coating. Coating on exposed carrier pipe should be UV resistant paint or tape
wrap. Exposed hanger hardware shall be hot-dipped galvanized, stainless steel, or other atmospheric
corrosion-resistant coating.
Casings
Some governing agencies require natural gas pipelines on bridges to be steel cased throughout the
length of the structure. If a casing is used, the space between the pipe and the casing must be effectively
open to atmosphere preferably at both ends, but at least on one end, using either a vent pipe or other
satisfactory type vent to avoid unsafe build-up of pressure in the casing due to leakage of the carrier pipe.
Reference Specification 3.42, Casing &Conduit Installation. Casing insulators, end seals, and vents shall
be installed as detailed in Specification 3.42, Casing & Conduit Installation.
PIPE SYSTEMS REV. NO. 12
BRIDGE DESIGN DATE 01/01/25
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utilities NATURAL GAS SPEC. 2.15

2.2 METERING & REGULATION
2.22 METER DESIGN
SCOPE:
To establish a uniform procedure for designing and installing metering equipment.
REGULATORY REQUIREMENTS:
§192.351, §192.353, §192.355, §192.357, §192.359.
WAC 480-90-323, 480-90-328, 480-93-140
OTHER REFERENCES:
International Fuel Gas Code (IFGC), Sec. 401.7
National Electric Code (NEC), Article 500, 501, and 504
CORRESPONDING STANDARDS:
Spec. 2.14, Valve Design
Spec. 2.23, Regulator Design
Spec. 2.24, Meter& Regulator Tables & Drawings
Spec. 3.16, Services
Spec. 5.12, Regulator and Relief Inspection
DESIGN REQUIREMENTS:
General
The amount of natural gas a customer consumes must be measured as it is delivered to the customer
primarily to provide information for billing. This measurement is accomplished by a gas meter, and it is
important to have knowledge and understanding of the gas meter and the various components associated
with metering as follows in this section.
Avista's metering and regulating equipment shall be installed, operated, and maintained in accordance
with federal and state regulations, and in accordance with the manufacturer's recommended installation
and maintenance practices.
WAC 480-93-140(1)—To ensure proper operation of service regulators, each gas pipeline company
must install, operate, and maintain service regulators in accordance with federal and state regulations,
and in accordance with the manufacturer's recommended installation and maintenance practices.
Existing meter set designs that do not currently conform to this specification should be brought up to
standard when there is an opportunity to do so with some reasonable exceptions. Refer to GESH Section
7- Meter Turn on Orders, "Bringing Meters up to Standard"for further guidance. Existing inside gas meters
should, where possible, be relocated outside when the customer piping is revised, altered, or if another
opportunity exists.
Meter Types
Common types of gas meters used in the system are as follows:
Aluminum and Iron Case Diaphragm Meters: These meters are positive displacement meters and measure
a known quantity of gas by filling and emptying chambers within the meter. This is the most common type
of meter; residential meters are typically of this kind.
METERING & REGULATION REV. NO. 25
METER DESIGN DATE 01/01/25
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New diaphragm meters are aluminum cased. Iron case meters are being phased out of the system
because they are no longer manufactured and are large, heavy, and cumbersome to maintain. Many of the
large diaphragm meters, aluminum, and iron, are being replaced with rotary meters due to their size and
difficulty in keeping them accurate as they age. Currently, however, both types are still active in the system
Rotary Meters: The rotary meter is a positive displacement meter that measures gas with two oppositely
rotating figure 8 impellers operating within a rigid casing. Rotary meters are typically used for commercial
and industrial loads. Rotary meters are smaller and lighter weight than their diaphragm counterparts and
are replacing them in the field.
Turbine Meters: As gas enters a turbine meter inlet, it exerts a force on the turbine rotor blades that turns
the rotor at a speed directly proportional to the gas flow rate that is measured by the index. Turbine meters
are used primarily for large commercial and industrial loads and for metering at Gate Stations.
Ultrasonic Meters: Ultrasonic meters operate using ultrasound-based flow measurement with little to no
pressure drop across the meter. Ultrasonic meters typically have high accuracy flow measurement with a
large capacity and range. Ultrasonic meters are not currently installed in Avista's system. Ultrasonic
meters can be located at Gate Stations on the Interstate side of the custody transfer point or be used in
residential applications, delivering gas to a home or business.
Coriolis Meters: Coriolis meters operate by measuring the mass flow rate of natural gas through a tube per
unit of time. The mass flow rate is then divided by the fluid density to determine the volumetric flow rate at
a measurement location. Coriolis meters are not currently installed in Avista's system and are primarily
located at Gate Stations on the Interstate side of the custody transfer.
Meter Identification
Meters must have a unique serial number and a tag or sticker identifying the utility's name. An updated
name tag or sticker must be installed on meters within three years of a company name change in
accordance with WAC 480-90-328.
WAC 480-90-328 - Meter Identification.—Gas utilities must identify each meter by a unique series of
serial numbers, letters, or combination of both, placed in a conspicuous position on the meter, along
with the utility's name or initials. Utilities must update the name or initials on its meters within 3 years of
a name change.
Meter Case Pressures
A manufacturer's shell test pressure on a meter must be at least 1.5 times the maximum operating
pressure of the meter. Each newly installed meter manufactured after November 12, 1970, must have
been tested to a minimum of 10 psig. A rebuilt or repaired tinned steel case meter may not be used at a
pressure that is more than 50 percent of the pressure used to test the meter after rebuilding or repairing. A
meter may not be used for pressures above the rated pressure of the meter. Reference the "Meter
Capacity Tables" under Specification 2.24, Meter& Regulator Tables & Drawings, for further information.
Meter Set Location, Protection, and Barricades
The meter and service regulator must be installed in a location readily accessible for examination, reading,
replacement, and maintenance. The meter location shall provide protection from damage due to outside
forces including but not limited to vehicles, weather, snow, and ice. When proper meter protection cannot
be provided by placement of the meter, secondary protection shall be provided. Customers may install
protective fences around meters as long as they comply with Avista's requirement for access and
maintenance. Refer to Specification 2.14, Valve Design, "Service Line Valves"for further information.
Customers may install meter protection that complies with the Avista meter set barricade/bollard detail A-
36712.
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Ideally, the meter set should be located so that the service line route is the shortest route between the gas
main and the meter set location. Where feasible, the meter and regulator should be located outside the
building at the building wall, unless located in a separate metering or regulating building or fenced area.
When multiple regulators are used, the upstream regulator in a series must be located outside the building
unless it is located in a separate metering or regulating building. Meter sets must be installed in one of the
following locations (listed in order of preference).
1. Outside, at or near ground level, adjacent to an exterior wall of the building. In heavy snow areas the
meter shall be installed under a roof overhang of 12 inches (minimum) measured from the drip line to
the front face of the meter or on the gable end of the building where possible. On new installations, if
this is not possible, approved external meter protection and a breakaway fitting should be considered
for installation to protect the meter from falling snow and ice, see "Breakaway Fitting" in this
Specification for more information. Refer to Specification 3.16, Services, "Services in Heavy Snow
Areas", for additional guidance.
2. In an alcove in the exterior wall of the building.
3. In a meter room (or meter rooms)within the interior of the building.
Should it be necessary to install the meter set in an alcove or a meter room(s), special design
considerations must be met as detailed in the "Inside Meter Set" section of this specification. A meter that
is installed more than 3 feet from the wall of a building served by gas shall be considered a "Remote Meter
Set".
These installations are not preferred but may be necessary at mobile home parks or in other special
circumstances. All remote meter set installations not serving a mobile home shall be approved by Gas
Engineering. Remote meter sets are more prone to vehicular damage and can be obstructed by
vegetation. These meter sets shall be flagged in Avista's GIS system or the asset management system for
tracking per WAC 480-90-323.
WAC 480-90-323—Meter Set Assembly Location. —When it becomes necessary to locate meters
away from the building wall or inside buildings, the gas utility must keep a record of these meter set
assemblies, including in such record the location, installation date, and leak history. Utilities must
submit copies of such records to the commission upon request.
The following should be considered (listed in the order of preference)when locating a meter and ensuring
adequate meter protection:
1. Use of the proposed or existing structure, such as under a building eave or other appropriately
designed architectural feature, to provide protection from weather, ice, or snow, or outside forces.
2. Installation of an excess flow valve (EFV) and a breakaway fitting to reduce the consequences if a
meter is damaged, see "Breakaway Fitting" in this Specification for more information. Residential
EFV's shall be installed per Specification 3.16, Services. (Oftentimes, an EFV may be a preferred
method of providing snow protection as it cannot be removed by the customer.) As noted in
Specification 3.16, EFV's must be located as close to the fitting connecting the service line to main as
practical.
3. Secondary structure -A secondary structure, sometimes referred to as a snow shed, shall be
installed at the time of the meter installation by Avista. The structure shall be per Avista
specifications.
When protection from vehicle or other outside force damage (other than snow) cannot adequately be
provided, secondary protection shall be installed by Avista. The preferred secondary protection is a meter
barricade, but a breakaway fitting may be installed in lieu of a barricade for residential meter sets when all
other options have been exhausted. See "Breakaway Fitting" in this Specification for more information.
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A barricade and breakaway fitting can be installed together to provide an additional level of protection. The
barricade shall be installed as detailed in Specification 2.24, Drawing A-36712, or according to a Gas
Engineering approved equivalent design. A 2-inch diameter barricade may be used only in residential
applications.
A 4-inch diameter barricade should be used in commercial applications, in areas where two-way vehicle
traffic is expected or when additional protection is deemed necessary based on site conditions.
It is preferred that barricades be installed at least 6 feet from primary voltage electric equipment(greater
than 600 volts). The "swing radius" of equipment doors must be taken into consideration in the "6-foot
rule". If a barricade is required within 6 feet of primary voltage electric equipment, the barricade shall be
one of the following:
• Non-conductive bollard
• Steel bollard with non-conductive sleeve
• Steel bollard bonded to electrical equipment ground.
In areas that experience heavy snowfall the meter should be installed on the gable end of the building to
protect the meter from falling snow and ice from the roof. Areas prone to heavy snowfall include the
following counties: Bonner(ID), Boundary (ID), Klamath (OR), Klickitat (WA), Kootenai (ID), Lake (OR),
Latah (ID), Lincoln (WA), Shoshone (ID), Spokane (WA), Stevens (WA), Union (OR), and Whitman (WA).
If the meter cannot be installed on the gable end of the building or if the meter is located under a roof
overhang whose drip line is less than 12 inches from the front face of the meter, a breakaway fitting and a
meter cover should be considered for installation to protect the meter. See "Breakaway Fitting" in this
Specification for more information. Company provided "snow sheds" are the preferred option, but the
customer may choose to install their own cover. Snow breaks on roofs are not an acceptable option for
meter protection. Customers who elect to install their own cover are responsible for the design and
construction of the cover.
The design of the cover must be stamped by a professional engineer and approved by Avista. Covers shall
be structurally sound and installed in a manner that does not interfere with the inspection, maintenance,
and replacement of the meter. Anchoring of the snow sheds in a "fixed foundation", such as concrete,
should occur. Guidance on concrete anchoring is as follows:
• Use one 80# bag of concrete.
• Divide the dry concrete mix between the four holes dug for the posts of the snow shed.
• Add a quart of water per hole and mix.
• Place excavated soil on top of the concrete filled holes to prevent quick drying of the concrete.
• Level the placement of the shelter before the concrete cures.
Design requirements for customer provided snow covers are as follows:
1. Be designed to withstand a uniform pressure of 500 pounds per square foot distributed over the top
surface of the structure. The snow shed must not deform or fail under this design load.
2. Have a minimum of 12 inches of clearance between the top of the meter set and the snow shed shall
be provided.
3. Must cover the entire width of the meter set, with an additional 8 inches (minimum) on either side to
allow accessibility for maintenance.
4. Must be corrosion resistant, through the use of galvanized metals, paint, or other corrosion resistant
materials.
5. Must be free standing and cannot be attached to the meter assembly in any way.
6. Shall allow for natural ventilation to mitigate accumulation of natural gas.
7. Must provide a minimum of 8 inches of overhang, measured from the front face of the meter.
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When the operating district is made aware of existing situations where the meter set is subject to possible
damage, Avista will provide meter protection at the Company's expense. In addition to minimum location
requirements as outlined in Drawing A-36275, meter sets should not be installed in the following locations:
1. Locations subject to snow or water shedding off a roof.
2. Locations subject to corrosion.
3. Locations subject to vehicular damage such as adjacent to driveways.
4. Locations subject to ground erosion or places subject to excessive vibration.
5. Locations subject to condensation or where live steam, hot liquid, or corrosive gases or vapor are
present or used.
6. Locations under or within any porch, deck patio or similar enclosure where access is limited, and the
free venting of gas is not assured.
7. Locations under interior stairways.
B. In engine, boiler, heater, or electric meter rooms.
9. Under outside fire escapes.
Breakaway Fitting
A breakaway fitting is an alternative secondary meter protection device that may be used in lieu of a
barricade for residential meter sets when all other options have been exhausted. The preferred secondary
protection is a barricade. A breakaway fitting may not be used as an alternative to a barricade in
commercial applications. In situations where a barricade or snow shelter is necessary, a breakaway fitting
can also be installed to provide an additional level of protection. A breakaway fitting may not be used as an
alternative to an EFV, curb valve, or snow shelter.
The breakaway fitting should be installed downstream of the service valve, preferably directly into the
outlet of the service valve. The following table shows meter set configurations where it is acceptable to
install a breakaway fitting. Due to flow rate restrictions, do not install a breakaway fitting in the applications
shown in gray or on any other type of meter not included in the table. Contact Gas Engineering for
approval to use a breakaway fitting in a meter manifold setup.
Acceptable Breakaway Fitting Applications
System AC250/R275 AL425 AC630 AL1000
MAOP 7"W.C. 2 PSIG 7"W.C. 1 2 PSIG 5 PSIG 7"W.C. 2 PSIG 5 PSIG T W.C. 2 PSIG 5 PSIG
46-60 PSIG ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓ ✓
22.6-45 PSIG ✓ ✓ ✓ ✓ ✓ ✓
10-22.5 PSIG ✓ ✓ ✓ ✓ ✓
6-8 PSIG ✓ ✓ ✓
3 Foot Rule
For outside meter set locations, at the time of installation of the meter, the vent of the service regulator
should not be located within a 3-foot radius of the following (refer to Drawing A-36275):
In PP&L territory (an electric utility within Avista's Oregon service area), the gas meter assembly shall
be located no closer than 3 feet from the electric meter and associated enclosure, Refer to Drawing
A-36275. (This is the one "shall" requirement of the 3-foot rule.)
• Any ignition source such as an electrical meter and associated enclosure, electric outlet, electric switch,
light fixture, disconnect, circuit breaker, air conditioner condenser or heat pump, generator, and
transformers.
• A direct-vent appliance vent, duct, or air intake
• The combustion air vent to a 90+ efficiency heating appliance or the vent terminal
• Any non-mechanical, free flow building air vent such as a foundation vent, window, dryer vent, door,
etc. unless the regulator vents above the opening in which case a 12" radius of separation is acceptable
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• Combustion air vents to fireplaces
• Any external building fire suppression system connection locations should not be within 3 feet of the
closest component of the meter set(not necessarily the regulator vent).
Also, they should not be within a 3-foot radius from the opening part or side of any window that can be
opened or any opening to a building or doorway. Where minimum distances cannot be maintained, care
must be taken to pipe the vent of the regulator to a safe location, or the meter set should be relocated.
Note: Under normal operating conditions, cable television and telephone termination boxes are not
sources of ignition.
10 Foot Rule
For outside meter set locations, the vent of the service regulator must be located at least 10 feet away
from any active fresh air intake or combustion air vents into mechanical rooms. Refer to Drawing A-36275.
Where the minimum distances cannot be maintained, care must be taken to pipe the vent of the regulator
to a safe location, or the meter set should be relocated.
Earthquake Valves
Earthquake valves are devices that are designed to shut off gas flow to a facility in the event of an
earthquake. Some customers may require an earthquake valve to be installed at their facility. If a customer
desires to have an earthquake valve, it is the customer's responsibility to purchase, install, and maintain
the valve. The earthquake valve shall only be installed on the customer owned side of the meter set,
downstream of the custody demarcation point. Since earthquake valves are designed to close when
movement is detected, the valve should be securely attached by the customer to the building and
supported in a way that allows the meter set to be maintained and disassembled without disturbing the
valve. The illustration below shows a recommended earthquake valve installation.
IA
BUILDING WALL
CUSTODY DEM7MEARTHQUAKE
KET t
(UNION, FLANAR)
PIPE SUPPORT BRACKET
0- 3 (UNISTRUT OR SIMILAR)
Z SIMILAR
BOLT OR
0
HQUAKE VALVE m SIMILAR
CUSTOMER HOUSE
PIPING
AVISTA CUSTOMER
PIPING PIPING PIPE SUPPORT
PLAN VIEW BRACKET
SCALE: NONE SECTION A-A
SCALE: NONE
Inside Meter Sets
Installing a meter set inside a building is generally undesirable because it is difficult to read and maintain
and should only be considered as a last alternative. If the meter and/or the regulator are installed within a
building, they must be located as near as practical to the point of service line entrance and be approved by
Gas Engineering. In general, any meter set inside a building must be located in a ventilated place and not
less than 3 feet from any source of ignition or any source of heat that might damage the metering
equipment. Electronic correctors mounted on meters with or without telemetry must comply with the
applicable version of the National Electric Code (NEC), Article 500, 501, and 504 for Hazardous
(classified) Locations.
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Refer to Specification 2.25, Telemetry Design for further detail on electrical classifications. If a meter set
must be installed other than outside, at or near ground level, and adjacent to an exterior wall of the
building, then the preferred location is for the meter to be installed in a building alcove.
Alcove Installation:
An alcove is a recessed area in the building's exterior wall that is sealed from the building interior and is
accessed from outside the building. An alcove must have a floor, sidewalls, and a ceiling with a minimum
1-hour fire rating. Doors may be installed for aesthetic reasons (facing outward), but venting must be
provided to the outside atmosphere (via louvers, decorative panels, or ventilation piping). Minimum venting
requirements for each alcove door are 5 inches x 10 inches screened vent, top, and bottom. If the pressure
regulator is installed within the alcove, then the service to the regulator must not penetrate into or
underneath the building.
Alcove meter locations:
• Must be dedicated to gas facilities only,
• Must not obstruct a building entrance or exit,
• Must be large enough to house the meter set(s) and/or pressure regulator assembly and provide
adequate space for installation and maintenance,
• Must be at or near ground level, and
• Must be accessible at all times to Avista service personnel.
Meter Room Installation:
If an inside meter set may not be constructed in an alcove but must be within the interior of the building
and accessed from within the building, then it is considered a "meter room" installation. Meter rooms must
be built to Avista's specifications (Refer to attachment titled "Avista's Requirements for Gas Meter Room
Installations" at the end of this specification. Inside meter sets should be installed only as a last resort.
Inside meter sets must be reviewed and approved by Gas Engineering prior to installation. Acceptable
locations for meter rooms are listed below(in order of preference):
1. On the ground floor and adjacent to an exterior wall.
2. In a basement and adjacent to an exterior wall.
3. On the ground floor, located in the interior of the building, and not adjacent to an exterior wall.
4. In a basement, located in the interior of the building, and not adjacent to an exterior wall.
5. On a floor other than the ground floor or basement and adjacent to an exterior wall.
6. On a floor other than the ground floor or basement and located in the interior of the building, and
not adjacent to an exterior wall.
7. A series of meter rooms stacked vertically on multiple floors.
Extended service piping necessary to reach the meter room from outside the building wall should be
welded steel piping between Avista's primary pressure regulator and the inside meter(or meter headers).
Extended service piping must be identified as belonging to Avista. The piping must:
• Operate at less than or equal to 5 psig within the building. Reference "Delivery Pressure" in this
specification.
• Be designed and installed in accordance with the applicable regulations, as set forth in federal, state,
and municipal codes,
• Be electrically isolated from underground gas facilities at the riser. Reference "Insulating Downstream
Customer Piping" in this specification.
• Be vapor-proof sealed at penetration points through the exterior of the building and be designed and
installed in accordance with the applicable regulations, as set forth in federal, state, and municipal
codes
Avista may contract to an approved contractor the installation of the extended service piping. An Avista
representative must supervise the installation of this piping. If the extended service piping is installed
without Avista's supervision, Avista reserves the right to require that the piping be replaced at the
contractor's expense to ensure that it has been installed to Avista's specifications.
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Acceptable locations for extended service piping are listed (in order of preference):
• In an area that is fully exposed and accessible.
• In a 1-hour fire rated chase that is fully accessible with 1-hour fire rated doors on each floor.
• In a welded steel casing approved by Avista's Gas Engineering Department that is sealed and
vented to the outside atmosphere.
Each inside meter set must have a service valve, or a curb valve located outside the building wall. The
curb valve must be maintained and accessible by a valve box. Reference Specification 2.14, Valve Design
for more information on curb valve applications.
Service regulator vents and relief vents must be piped outdoors per"Regulator and Relief Vent Design" in
this specification. Occasionally meters and/or regulators must be installed inside a structure to avoid snow
load or snow roof unloading issues. This should be a last resort and is only to be done with prior approval
from Gas Engineering.
Efforts should be made to move inside meter sets outside anytime work is required on the meter, regulator,
or service piping. If it is proposed to leave the meter set inside, contact Gas Engineering. Gas Engineering
will review the existing installation and determine if it meets current installation requirements.
Regulator and Relief Vent Design
Service regulator vent lines up to 20 feet in length shall be of minimum 1-inch pipe or sized according to
the manufacturer's instructions. Vent lines shall be constructed of minimum Schedule 40 steel or wrought
pipe unless otherwise specified by Gas Engineering. Vent lines shall be properly sloped, maintaining a rise
of at least 1/4-inch per run foot and properly doped and tightened to prevent moisture accumulation or the
entry of water. Vent lines in excess of 20 feet shall be referred to Gas Engineering for sizing.
Vent lines shall be adequately supported. On mobile homes, vent lines should not be secured to the
structure. The outside piping must be rain and insect resistant by orienting the vent pipe downward and
installing a screen in the end. Vent lines must be located at a place where gas from the vent can escape
freely into the atmosphere and away from any opening into the building. (Reference Drawing A-36275 in
this specification for minimum distances.)The vent lines must be protected from damage caused by
submergence in areas where flooding may occur.
Pits and Vaults
Ideally, meter sets should not be installed in pits or vaults, as they are difficult to access, tend to
accumulate liquids, and often contain air of questionable quality. Each pit or vault that does house a
customer meter or regulator at a place where pedestrian and/or vehicular traffic is anticipated must be able
to support that traffic. For further information regarding vaults, refer to Specification 2.42, Vault Design,
and Specification 5.18, Vault Maintenance.
Installation
Each meter set must be installed so as to minimize anticipated stresses upon the connecting piping and
the meter. Some meter sets may require additional support. For example, an external support is required
to keep rotary meters level and supported in order to function properly. A concrete pad or adjustable stand
approved by Gas Engineering is needed to support the larger diaphragm meters. If a flex line is used to
connect the meter set to the house line, a meter support may be required. A meter support should be
installed on new installations where the individual installing the meter does not feel that compaction can be
maintained and/or that settling at the meter location is likely to occur. Meter supports should also be
installed on existing meter installations where there is evidence of settling causing strain on the meter set.
In all cases the meter support shall be made of non-combustible material. Reference the Appendix A
drawings under Specification 2.24, Meter and Regulator Tables and Drawings for further details of some
frequently used supports.
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Meters must be installed and should be maintained so that they are readily accessible to meter readers
and meter service personnel. The meter should be facing the direction from which a meter reader would
approach the meter to be read. For newly installed meters/regulators and those being brought up to
standard configuration, the regulator vents shall be oriented straight downward (six o'clock position)to
prevent water from entering into the regulator and causing the regulator to freeze up. Vent screens are
required on the regulator vents to keep out insects and debris. If the regulator vent cannot be positioned
downward on its own, then a "mushroom cap"fitting may be used, or a vented elbow fitting may be
installed in the vent so that it is configured to vent in the downward position.
Only one service should be installed per customer or per building unless the building contains a firewall
between customers. Reference "Multiple Services"within this specification for requirements. Meter sets
should not be installed until the ground level is established as to final grade wherever possible. When
attaching the meter to flanges, tighten the bolts in an alternating sequence until the entire flange face
contacts the meter. Repeat the tightening sequence until the bolts area at the specified torque. By
gradually increasing the bolt torque over multiple steps, it is less likely that the flange and meter face will
bind or become misaligned. Tighten the bolts to the following torque levels based on meter manufacturer.
Manufacturer Torque ft-lb)
Romet 20
Dresser 8C thru 16M 5/8" bolts 45
Dresser 23M 5/8" bolts 60
Overbuilds
Buildings, mobile homes, carports, and structures that might entrap gas shall not be constructed over
Company gas facilities without an approved design by Gas Engineering. If an existing customer's service
line or meter set must be relocated by the Company due to any change being proposed by the customer,
(i.e., building construction making the meter set inaccessible, building over the service line, or any other
violation of the federal, state, or local regulations), the cost of the relocation should be paid by the
customer. Overbuilds that have occurred in the past should be corrected by removing the structure or
relocating the overbuilt facilities. The cost for this work should be handled on a case-by-case basis.
Idle Meters
Idle meters should be removed when it is apparent gas will not be used in the future. Refer to Specification
5.16, Abandonment, or Inactivation of Facilities. An idle meter on Rental property may remain if the
marketing representative determines that another tenant may use gas in the near future.
Idle Services
Idle services have either not had a meter installed yet or the meter has been removed and the service
valve has been locked off. They should be cut off at the main if it is determined that it is unlikely that gas
will be used in the future. If left in place, the riser is subject to the requirements of atmospheric corrosion
monitoring, Reference Specification 5.14, Cathodic Protection Maintenance to include the need to be
marked with the appropriate gas pipeline sticker.
High pressure (HP) idle risers shall be properly protected and labeled. High pressure risers shall be
marked with the appropriate "HP Gas Pipeline" sticker. When reinstating a HP idle riser into service, Gas
Engineering shall verify the MAOP and design appropriate regulation and metering equipment for the
conditions.
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Multiple Services
A building or other structure served on a single lot and/or sharing a structural component with another
building (i.e., common wall, common roof, etc.)should be supplied by only one service. Zero lot-line
structures are considered a single structure. More than one service is permitted by the following
exceptions. Additional services must be in a readily accessible location and shall not compromise safety or
system integrity.
• Single-family dwellings are not allowed additional service points unless it is for the following
exceptions:
a. Swimming pool/spa, when there is a permanent building containing the heating equipment which
is detached from the main structure. (Note: This option should only be used when it is a hardship
for customer to install downstream piping.)
b. Shops, garages, barns, and outbuildings which are detached from the main structure.
• Multiple unit residential and commercial buildings may be allowed additional service points provided
that only one service feeds a unit, or units located between a 2-hour firewall. Limiting service points
can reduce confusion and assure that no additional gas feeds go unaccounted for in a gas
emergency.
• Industrial complexes will be individually evaluated and handled on a case-by-case basis. Contact Gas
Engineering in these instances.
Multiple Meters
Multiple meters (meter manifolds or meter banks) should be grouped in one accessible location wherever
possible. Meter manifolds should be constructed so that different delivery pressures are separated using
pipe branching to allow for ease of identification.
Gas houseline piping at multiple meter installations shall be marked by a stamped metal washer or metal
tag attached by the builder or developer so that the piping system supplied by each meter is easily
identifiable per the International Fuel Gas Code (IFGC), Sec. 401.7. The identifier shall be made of brass,
galvanized steel, or other weather resistant metal that can be stamped with the unit number or other
identification. Identifiers made of soft metals (such as aluminum)that may be subject to bending or other
damage are prohibited. All tags shall be secured to the downstream piping with a metal wire of sufficient
strength to prevent tampering.
Insulating Downstream Customer Piping
The customer gas piping system must be electrically insulated from the gas service piping if the service
pipe is steel. This is necessary in order to maintain proper cathodic protection of the Company
underground gas piping system. The following methods of insulating the customer piping from the steel
service piping are used:
• Meter sets are most often installed with a service valve that is equipped with an insulating union.
This is the preferred method of insulation.
• Meter sets with a non-insulating service valve should have an insulating union installed.
Installation of an insulated meter swivel is also acceptable on existing meter sets.
• Large meter sets are most often insulated with an insulating gasket and insulating kit at a flange.
• Some large meter sets have an insulating type coupling on the outlet side of the gas meter.
On polyethylene (PE) plastic services, the tracer must terminate below the insulated fitting. Refer to
Specification 2.32, Cathodic Protection, and Specification 3.16, Services for more information. Reference
the "Standard Meter Set Drawings" under Specification 2.24, Meter and Regulator Tables and Drawings
for further details.
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utilities NATURAL GAS SPEC. 2.22

Meter Set Design
Refer to the "Standard Meter Set Drawings" under Specification 2.24, Meter and Regulator Tables and
Drawings for design of residential and commercial meter sets. These standard designs are to be used in
most applications; however, they may not be appropriate for every meter set application.
Gas Engineering will assist with the design of non-standard meter sets. Industrial meter sets are handled
on a case-to-case basis in Gas Engineering. Some parameters to include when designing a meter set are
as follows:
• Customer's total connected load and/or expected peak load (BTU/HR)
• Customer's minimum load expected.
• Customer's desired and/or required delivery pressure.
• Minimum and maximum inlet pressure to the meter set
• Relief Requirements (downstream MAOP)
• Upstream MAOP for pressure rating requirements of equipment
• Upstream MAOP for pressure rating of equipment
• Required pressure differential across the regulator.
• Pressure differential across the meter.
• Adequate test plugs and blow down valves.
• Adequate bypass valves
• Filter/Strainer requirements
• Pipe lengths required for sensing lines and meters.
• Range of the meter for low flow and peak flow conditions
• Telemetry requirements such as for transport customers
• Future load requirements
• Inlet pipe size
• Outlet pipe size
• Meter set supports.
• Valve locking devices.
• Accessibility to meter set
• Meter set protection such as barricades, fencing, locks, and buildings
• Meter location
Note: Refer to the following paragraph on Gas Information Sheets for further reference on meter set design.Also,
reference"Meter Capacity Tables"and the"Regulator Capacity Tables" under Specification 2.24, Meter and Regulator
Tables and Drawings,for more information.
Gas Load and Meter Information Sheet
A Gas Load and Meter Information Sheet for meter sets should be filled out and submitted for approval for
sizing the meter and regulator when any of the following criteria are met:
• Delivery pressure of 5 psig or higher.
• Loads greater than 1,000,000 BTU/Hr(1,000 CFH). For multiple meter manifolds, use the
maximum meter capacity for all the meters on the manifold (example: three AC250 meters at 7"
WC = maximum load of 900,000 BTU/Hr).
• Customer's load or pressure requirements change to a load greater than 1,000,000 BTU/Hr(1,000
CFH) and/or a delivery pressure of 5 psig or higher.
The sheets are to be submitted electronically to the Gas Meter Shop. Follow-up questions should be
directed to the Spokane Gas Meter Shop for Washington and Idaho projects or to the Medford Gas Meter
Shop for Oregon projects. Meter sets with conditions that meet the industrial meter set definition will be
routed to Gas Engineering from the Gas Meter Shops for design and/or approval.
METERING & REGULATION REV. NO. 25
METER DESIGN DATE 01/01/25
Xv sm a STANDARDS 11 OF 19
utilities NATURAL GAS SPEC. 2.22

Industrial Sets and Elevated Pressure Sets
Metering pressure above 7 inches WC (1/4-inch psig) is considered elevated pressure. "Metering
Pressure" is the pressure at which the gas flows through the meter and to which the volume is corrected.
"Delivery Pressure" is the pressure at which the gas is served to the customer's piping. Typically, these are
the same.
Note: Refer to "Maintenance of Elevated Pressure Meter Sets" and "Maintenance of Industrial Meter Sets"
in Specification 5.12, Regulator and Relief Inspection for pressure check requirements.
Requests for delivery pressures of greater than 5 psig or with loads greater than or equal to 14,600,000
BTU/Hr shall be submitted to Gas Engineering for review prior to making a commitment to the customer,
as these are typically large commercial or industrial meter sets that may need to be specially designed and
involve contracts. A gas planning analysis may need to be conducted to assure that gas is available at the
desired pressure.
Requests for elevated pressure meter sets at 5 psig or greater should be considered based on the
following criteria:
• Customer's equipment requires elevated pressure. (Manufacturer's equipment verification should
be attached to the Gas Load and Meter Information Sheet)
• Customer's piping requires greater than 2-inch piping for standard delivery pressure.
• Customer is adding load to an existing house line that is no longer sufficient at standard delivery
pressure.
A meter set that meets any of the following conditions is considered an "industrial" set:
• A set metering at pressures above 5 psig (note: metering pressure, not delivery pressure.)
• A turbine meter
• Meter Correction Code of 3 or P
Engineering Design Note: It is recommended to use fixed factor metering on sets with loads below
14,600,000 BTU/Hr metering at 7 inches WC, 2 psig, and 5 psig. On sets with metering pressures above 5
psig and loads equal to or greater than 14,600,000 BTU/Hr or loads greater than or equal to 14,600,000
BTU/Hr, electronic pressure correction should be used for better volume correction accuracy.
If a request is made for an elevated pressure above 5 psig and load below 14,600,000 BTU/Hr, gas
engineers can use fixed factor correcting heads on rotary meters or electronic correctors on other meters.
Identifying Sites with Special Design and Maintenance Requirements
Certain service points have specialized design and maintenance requirements and should be identified at
the time of initial installation by the Customer Project Coordinator or Gas Engineering. For example,
commercial or industrial buildings with service lines 2 inches or greater in diameter require an emergency
curb valve in Washington (WAC Rule). Additionally, high occupancy structures require an annual leak
survey. Reference Specification 2.14, Valve Design for additional site criteria that determines the
installation of curb valves (the above sites are not a complete list) as well as Specification 5.11, Leak
Survey, for details on the frequency of surveys.
METERING & REGULATION REV. NO. 25
METER DESIGN DATE 01/01/25
Xv sm a STANDARDS 12 OF 19
utilities NATURAL GAS SPEC. 2.22

GAS VOLUME CALCULATION:
Behavior of Natural Gas
Natural gas is compressible meaning that a given amount of gas can be expanded or squeezed into
different volumes. The pressure of the gas will affect its compressibility. As the pressure of the gas is
increased, the gas "squeezes" down and the given amount of gas will occupy a smaller space. As the
pressure of the gas is decreased, the gas will expand, and the given amount of gas will occupy a larger
space. Therefore, the higher the operating pressure of the gas in the system, the more capacity that
system will have.
Temperature also affects the compressibility gas. As the temperature of the gas decreases, the volume of
gas will also decrease, and the same amount of gas will then occupy a smaller space. Conversely, as the
temperature of the gas increases, the volume of gas increases", and the same amount of gas will occupy a
larger area. Therefore, the higher the temperature of the gas, the less capacity that system will have.
Computing Corrected Flows
Gas meters measure the actual gas volume passing through the meter based on the gas temperature,
metering pressure, and elevation. It is necessary to correct the actual measured gas volume to standard
metering conditions in order to calculate the SCFH (Standard Cubic Feet per Hour)delivered to the
customer. Standard conditions for natural gas are 60 degrees F, 1 atmospheric pressure (14.73 psia), and
0 feet elevation. Elevation corrections are made to at least the closest 100-foot increment. The following
calculation will correct gas at non-standard conditions to standard conditions for billing purposes.
Corrected Flow [SCFH] = (Metered Flow) * (Pf+Pe) * (Tf)Where:
Metered Flow=Actual Cubic Feet of Gas per Hour[ACFH]
Pf= Pressure Factor [Corrects metering pressure to standard conditions (14.73 psi)]
Pe = Elevation Factor [Corrects metered volume to zero feet elevation]
Tf= Temperature Factor[Corrects gas temperature to standard conditions (60°F). Tf is
only to be used when metering with a non-TC'd meter. Tf= 1 for a TC'd meter]
Elevation Compensation
The factor to compensate for elevation only is simply the atmospheric pressure of the town where the
meter is located divided by the base pressure. The factor is as follows:
Elevation Factor Pe = Paz
14.73
Where: Pe = Elevation Factor
Paz = Absolute Atmospheric Pressure (psia)at actual location
(Refer to Fig. 1)
14.73 = Standard Base Pressure (atmospheric pressure at sea
level in psia)
The following table, Fig. 1, shows atmospheric pressures for various elevations within Avista's service
territories (rounded to nearest 100-foot increment).
METERING & REGULATION REV. NO. 25
METER DESIGN DATE 01/01/25
Xv sm a STANDARDS 13 OF 19
utilities NATURAL GAS SPEC. 2.22

Atmospheric Pressure at Various Elevations Fig. 1
Elevation ft Paz Pressure(psia) Change/100 ft. Elevation(ft.) Paz Pressure(psia)
0 14.73 .053/100 ft. 3600 12.888
100 14.677 .053/100 ft. 3700 12.841
200 14.624 .053/100 ft. 3800 12.794
300 14.571 .053/100 ft. 3900 12.747
400 14.518 .053/100 ft. 4000 12.7
500 14.465 .053/100 ft. 4100 12.655
600 14.412 .053/100 ft. 4200 12.61
700 14.359 .053/100 ft. 4300 12.565
800 14.306 .053/100 ft. 4400 12.52
900 14.253 .053/100 ft. 4500 12.475
1000 14.2 .053/100 ft. 4600 12.43
1100 14.147 .053/100 ft. 4700 12.385
1200 14.094 .053/100 ft. 4800 12.34
1300 14.041 .053/100 ft. 4900 12.295
1400 13.988 .053/100 ft. 5000 12.25
1500 13.935 .053/100 ft. 5100 12.207
1600 13.882 .053/100 ft. 5200 12.164
1700 13.829 .053/100 ft. 5300 12.121
1800 13.776 .053/100 ft. 5400 12.078
1900 13.723 .053/100 ft. 5500 12.035
2000 13.67 .053/100 ft. 5600 11.992
2100 13.62 0.050/100 ft. 5700 11.949
2200 13.57 0.050/100 ft. 5800 11.906
2300 13.52 0.050/100 ft. 5900 11.863
2400 13.47 0.050/100 ft. 6000 11.82
2500 13.42 0.050/100 ft. 6100 11.779
2600 13.37 0.050/100 ft. 6200 11.738
2700 13.32 0.050/100 ft. 6300 11.697
2800 13.27 0.050/100 ft. 6400 11.656
2900 13.22 0.050/100 ft. 6500 11.615
3000 13.17 0.050/100 ft. 6600 11.574
3100 13.123 .047/100 ft. 6700 11.533
3200 13.076 .047/100 ft. 6800 11.492
3300 13.029 .047/100 ft. 6900 11.451
3400 12.982 .047/100 ft. 7000 11.41
3500 12.935 .047/100 ft.
Ref.American Meter Company Handbook E-4, 1970 ed.
Displacement Gas Meters,p. 18
(Using 14.73 psia at Sea Level per State Tariffs)
Pressure Compensation
A pressure factor is applied to adjust the volume of measured gas for meters that are measuring gas at a
pressure higher than atmospheric conditions. The following formula is used to compute the pressure
factor:
Pf= P _
14.73
Where: Pf= Pressure factor
Pg = Gauge Pressure (psig)
14.73 = Standard Base Pressure (Absolute atmospheric
pressure at Sea Level in psig)
METERING & REGULATION REV. NO. 25
METER DESIGN DATE 01/01/25
XvIST'r STANDARDS 14 OF 19
utilities NATURAL GAS SPEC. 2.22

Temperature Compensation
Many of the gas meters used in the system are TC or temperature compensating meters. They are
equipped with the mechanics to adjust the flow for temperature variations. Many meters, however, are
non-TC meters and may require a temperature factor to be applied to the volume of flow. The following
formula is used to compute the factor:
Tf= 520
460 + Tg
Where: Tf= Temperature Factor(For non-TC'd meters). Note: Value
equals 1 for a TC'd meter.
520 = Standard Base temperature of 60 degrees Fahrenheit
expressed in absolute temperature (degrees Rankine)
460 = 0 degrees Fahrenheit expressed in absolute temperature
(degrees Rankine)
Tg = Temperature of the gas stream in degrees Fahrenheit
A non-TC meter is clocked, and the uncorrected flow of gas is found to be 1000 ACFH. Metering pressure
is 30 psig, the gas temperature is 45 degrees F, and the meter is located at 1900 feet elevation. What is
the corrected flow?
Paz = 13.723 psia (from Figure 1 —Atmospheric Pressure at Various Elevations)
Pg = 30 psig
Tg = 45°F
Therefore: Pf= Pg/14.73 = 30/(14.73) = 2.04
Pe = Paz/14.73 = (13.723/14.73) = 0.93
Tf= 520/(460+Tg) = 520/(460+45) = 1.03
So:
Corrected Flow= (Measured Flow) * (Pf+Pe)*Tf
= (1000)* (2.04+0.93) * (1.03) = 3,059 SCFH
Correction Codes
Once a read is taken from a meter, it must be corrected for elevation, pressure, and/or temperature if
necessary and then converted into therms for billing purposes. The billing system completes the
conversion of the measured volume at site conditions into a volume at standard conditions. For ease of
billing, each method is assigned a Code Number which is used with the appropriate type of meter set and
is applied by the computer at the time of billing in the form of a Billing Factor. The various codes are as
follows:
METERING & REGULATION REV. NO. 25
METER DESIGN DATE 01/01/25
XvIST'r STANDARDS 15 OF 19
utilities NATURAL GAS SPEC. 2.22

METER CORRECTION CODES
CODE DESCRIPTION
1 A TC meter with a standard index for standard metering pressures of 7 inches WC or 0.25 psig. The billing
factor will be calculated by multiplying the BTU content of the gas times the quantity[elevation factor(Pe)+
pressure factor(Pf).
Billing Factor=(BTU Content)*[(Pf=0.25/14.73=0.017)+Pe]
2 A non-TC meter with a standard index for standard metering pressure of 7 inches WC or 0.25 psig. The billing
factor will be calculated by multiplying the BTU of the gas times the quantity[elevation factor(Pe)+pressure
factor(Pf)]times the temperature factor(Tf).
Billing Factor=(BTU Content)*[(Pf=0.25/14.73=0.017) +Pe)]*Tf
3 A TC meter with a base pressure index(BPI)or an electronic corrector,(usually for metering at pressures higher
than 5 psig). The billing factor will be the BTU content of the gas only.
Billing Factor=(BTU Content)
Note: The billing system does not complete a correction to standard conditions because the field device is
providing a meter reading corrected to standard conditions.(Standard Conditions at 60 degrees F, 1 Atmosphere
or 14.73 psia)
4 A TC meter with a standard index for metering at 2 psig. The billing factor will be calculated by multiplying the
BTU content of the gas times the quantity[elevation factor(Pe)+pressure factor(Pf)].
Billing Factor=(BTU Content)*[(Pf=2/14.73=0.1358)+Pe]
5 A TC meter with a standard index metering at 5 psig. The billing factor will be calculated by multiplying the
BTU content of the gas times the quantity[elevation factor(Pe)+pressure factor(Pf)].
Billing Factor=(BTU Content)*[(Pf=5/14.73=0.3394)+Pe]
6 A non-TC meter with a standard index metering at 2 psig. The billing factor will be calculated by multiplying the
BTU of the gas times the quantity[elevation factor(Pe)+pressure factor(Pf)]times the temperature factor(Tf)
Billing Factor=(BTU Content)*[(Pf=2/14.73=0.1358)+Pe]*(Tf)
7 A non-TC meter with a standard index metering at 5 psig. The billing factor will be calculated by multiplying the
BTU of the gas times the quantity[elevation factor(Pe)+pressure factor(Pf)]times the temperature factor(Tf).
Billing Factor=(BTU Content)*[(Pf=5/14.73=0.3394)+Pe]*(Tf)
8 A non-TC meter with a standard index metering at 10 psig. The billing factor will be calculated by multiplying
the BTU of the gas times the quantity[elevation factor(Pe)+pressure factor(Pf)]times the temperature factor
(Tf).
Billing Factor=(BTU Content)*[(Pf=10/14.73=0.6789)+Pe]*(Tf)
A A non-TC meter with a standard index metering at 15 psig. The billing factor will be calculated by multiplying
the BTU of the gas times the quantity[elevation factor(Pe)+pressure factor(Pf)]times the temperature factor
(Tf)
Billing Factor=(BTU Content)*[(Pf=15/14.73=1.0183)+Pe]*(Tf):
P A TC meter with a pressure compensation index(mechanical or electrical)metering at 10 psig, 15 psig,or 20
psig. The billing factor will be calculated by multiplying the BTU content of the gas times the elevation factor
(Pe)Billing Factor=(BTU Content)*(Pe)
Note: The billing system does not complete a correction to standard conditions for metering pressure and
temperature because the field device is providing a meter reading corrected to standard conditions.(Standard
Conditions @ 60 degrees F, 1 Atmosphere or 14.73 psia). Only an elevation correction is required.
NOTES:
1) Customer Bill[Therms]=(Measured Volume[CF])*(Billing Factor)/100,000
2) The billing system uses the following when calculating the quantity of gas measured:
a. BTU Content—Average calculated BTU content per cubic foot of gas for a given set of dates based on a specific
BTU zone.
b. Tg—Gas Temperature—Average gas temperature for a given set of dates based on a temperature zone.
3) NOTE:A yellow decal on the index and a yellow cap on the spring of the regulator is used to indicate a 2-psig meter set
(Code 4 or Code 6).A green decal on the index and a green cap on the spring of the regulator is used to indicate a 5-psig
meter set(Code 5 or Code 7).A red decal on the index and a red cap on the spring of the regulator is used to indicate a
Code 8,Code A,Code P,or non-standard meter set and tagged with the identifying set pressure.The decal on the index is
a redundant indicator in case the regulator spring cap is painted over.
METERING & REGULATION REV. NO. 25
METER DESIGN DATE 01/01/25
X rv#ST,aa STANDARDS 16 OF 19
Utilities NATURAL GAS SPEC. 2.22

Temperatures Corrected Flows
Gas volumes through meters that are non-temperature compensated must be corrected for the
temperature effects on the volume. This is achieved by one of three methods: a temperature-
compensating (TC) meter, a correction device installed on the meter such as an electronic corrector
(typically for large volume accounts), or by the correcting factor(imbedded in the correction code) applied
to the account through the billing system.
Special attention must be paid when setting meters in Oregon to note if they are TC (temperature
compensated) or non-TC to apply the proper correction code.
Frequency of Meter Tests
The periodic testing of gas meters is done in accordance with programs approved by each state and in
accordance with Utilities Commission rules. Avista's PMC Program (Gas Meter Measurement Performance
Program) uses statistical testing as a quality assurance measure to ensure meters continue to accurately
measure flow as the meters age. For detailed information regarding Avista's PMC Program, see the Gas
Meter Testing SOP Standard.
The following table lists the testing requirements by meter type and size.
Meter Type and Size Test Frequent
Diaphragm, 250-1000 CFH Statistical sampling
Diaphragm, between 1001 and 3000 CFH Every 10 years
Diaphragm, 3001 and greater CFH Every 5 years
Rotary, all sizes Differential test every 5 years
Turbine, all sizes Spin test annually and proof tested every 10 years
Prover Calibration Interval
Meter Provers Calibration Interval
SNAP Prover or Bell Prover Every Second Calendar Year
Transfer Prover Every Second Calendar Year
Avista's Requirements for Gas Meter Room Installations
Standard Meter Room(s) Specifications
1. Meter room construction must have a minimum 1-hour fire rating, be completely sealed from the
rest of the building, and include a self-closing airtight door.
2. Penetration points through the floors, walls, and ceilings of meter room must be vapor-proof
sealed and be designed and installed in accordance with applicable regulations, as set forth in
federal, state, and municipal codes.
3. It must be equipped with explosion-proof lighting equipment (minimum of one light), that complies
with the applicable version of National Electrical Code (NEC), Article 500 and 501 for Hazardous
(classified) Locations. Switches located outside the room are not required to be explosion-proof.
4. Meter room must be dedicated to natural gas meter sets only.
5. Meter room must be accessible at all times to Avista. Key box locations are recommended.
METERING & REGULATION REV. NO. 25
METER DESIGN DATE 01/01/25
XvIST'A STANDARDS 17 OF 19
utilities NATURAL GAS SPEC. 2.22

Meter Room Ventilation
1. Venting configurations must have a minimum of two vents, one at the top and one at the bottom of
the meter room. Vents must connect from the meter room to the outside. Specifically:
• The top vent can be installed either on the ceiling of the meter room or on one of the walls
of the meter room, located at a maximum of 1 foot from the top of the vent to the surface
of the ceiling.
• The bottom vent must be installed on one of the walls of the meter room, located a
maximum of 1 foot and a minimum of 6 inches from the bottom of the vent to the surface
of the floor.
2. Ventilation piping may be installed horizontally through the exterior wall, vertically through the roof,
or a combination of the two. The minimum size of the piping is determined by the venting
configuration.
• For vertical vent piping on the top and bottom, and for vertical venting on the top with
horizontal venting on the bottom, the minimum vent size is 4 inches.
• For horizontal venting on the bottom, the minimum vent size is 6 inches.
• Where little or no vent piping is required, such as a meter room adjacent to an outside wall
of the building where the vents are less than 1 foot in length, the minimum vent size is 4
inches. (Square louvers with the same cross-sectional area may also be used.)
3. Vent locations outside should be placed:
• A minimum of 36 inches from an electric meter or other ignition source.
• A minimum of 36 inches from a combustion air intake.
• A minimum of 36 inches from any natural gas appliance direct vent assembly or as
specified by the manufacturer of the appliance.
• A minimum of 10 feet from any mechanical air intake opening.
• Not under a carport, roof awning, or overhang larger than a standard eave.
Not under a stairwell or staircase providing the only access or exit to the building
(stairwells providing alternative access or exit to the building are an exception to this
requirement)
Regulator and Relief Ventilation
Service regulator vents and relief vents must be piped outdoors per"Regulator and Relief Vent Design" in
this specification.
METERING & REGULATION REV. NO. 25
METER DESIGN DATE 01/01/25
Xv sm a STANDARDS 18 OF 19
utilities NATURAL GAS SPEC. 2.22

® ELECTRIC AND GAS
METER'NORKING SPACE
IIECH�tJI(:�L `ELECTRIC METER
1�'�LL"R SIR IVi«KE / AND ASSOCIATED
tiV'IND"1� oil,, EQUIPMENT
•4,!C UNfT CC'n'
3' (PP&L)
�o SEE NOTE 7 DOOR
THE GREATER
DIRECT VENT - OF:64"
APPLIANCE DUCT �I 3 SEE NOTE 5 OR TOP OF
iiETER BASE
3,
,m 3' -
2' 1
ELECTRICAL ANY OPENING BELOW GROUND FIFE SPRINKLER
DEVICES REGULATOR VENi Pnr SYSTE-, CONNECTI '
SEE NOTE 1 (FOUNDATION VENT, 12" I
WINDOW,DRYER VENT, ELEVATION
DOOR, ETC.)
1. ELECTRICAL COMPONENTS,DEVICES,&ECIIIPVENT INCLUDING SNITCHES,RECEPTACLES.LIGHT ?
RYTIJIFE DISCONNECTS,CIRCUT BREAKEF: FAD MOUNTED AIR CONDiRCNERS OR HEAT PUMPS W /'
TH=T E' t,?T SUPPLY VENTILATION AIR,:',E Ef'ATORS,&TRANSFORMERS SHOULD EE AT LEAST
" FP^M REGULATOR VENT GAS METER PLAN VIEW
1 E T I'. T-LL METERS WHERE THE J E
11EJE'T TO VEHO ILIF 4 I G='. :E Co E:I.E •FP:)SION,CIR AERATION
4 [;F (:ULT TO REr1' F H[1 E FE 0L-T F -E T•11 U•fTEC cI rH AS WITHIN A PORCH,DECK.OR ENCLOSIIRE
• IN AN ENGINE GE%EF-T F ECILEV FE-TEF F ELE TTI-L F IV
• LOCATED UNDER :17`I[E:�JAIRWAr TFIfEE :.*E
• SUSCEPIU.E Tr:E E.DIVE CONDEt+'4. , _F AHERE U'oE STEAM,HOT UOUID,OR CORROSIVE GASES/VAPOFS ARE FP.ESE'Ni.
• LOCATED CU''ER TH--J YFROM OPEN FLAME
• IN DRANCE AFE,
THE METER SHOULD BE INSTALLED 3'OF LESS FROM WHERE THE HOUSE LINE ENTERS 1HE STRUCTURE,UNLESS CONDITIONS WARRANT LOCATING
1HE METER AT A GREATER DISTANCE
A. ADDi ICNAL C0RANCES&RIDAREYENTS APFLY TO LARGE,HIGH FIRUnURE AND INDUSTRIAL MEiER SETS.
5 ELECTRIC METEP WORKING SPKE SHALL BE THE GREATER OF 30'WIDE OR THE TOTAL WIMH OF THE ELECTRIC SERVICE AND METERING
EOUIPYDNi, P-TERED ON THE EQUIPMENT,AND A CLEAR SPACE OF AT LEAST 36'IN FRONT AND PERMIT AT LEAST A 90 DEGREE OPBsI+G OF
EiI IIPIIE`JT C F-:OR HINGED PANELS Nq 13CUU ARE
-LL .[I I TH. SPACE. DISTRIBUTION-GAS
E LL41 F THEIR TYPES OF MEiER PP31ECIION MAY BE STAN^ARD
Ih.T IlEC 1, ILE THE GAS METEF WIRKING SPACE AT AVISTAS METE SET
DIS,FETI '� LOCATION GUIDELINES
1. IN Pf',L 1E1'Pf r` THE Gk I,ETTT ``E"EL—H,,LL6E AVISTA CORP
< LOCATE[`... ..L::ET THAN 3 FEET L TEF;LL FF:-;4 THE SP0KANE,WASHINGTON
n ELECTRIC MEHF DJCLO:3uw. ISCALE I
- -
Oi
0 11 9-23-21 STANDARDS UPDATE CGD DR BURGER
M 10 10-10-19 STANDARDS UPDATE CGD fltg M J12N NM— SHT I 11 WE07
NO DATE REVISION BY CKD CIO r,rD of 1 A-36275
AUTOCAD DWG
METERING & REGULATION REV. NO. 25
METER DESIGN DATE 01/01/25
�visra STANDARDS 19 OF 19
Utilities NATURAL GAS SPEC. 2.22

2.23 REGULATOR DESIGN
SCOPE:
To establish a uniform procedure for designing farm tap style regulator stations, district regulator stations,
and service regulators.
REGULATORY REQUIREMENTS:
§192.181, §192.195, §192.197, §192.199; §192.201, §192.203, §192.353, §192.355, §192.357,
§192.359, §192.741
WAC 480-93-020, 480-93-130, 480-93-140
OAR 860-023-0035
CORRESPONDING STANDARDS:
Spec. 2.14, Valve Design
Spec. 2.22, Meter Design
Spec. 2.24, Meter& Regulator Tables & Drawings
Spec. 3.16, Services
Spec. 5.12, Regulator and Relief Inspection
DESIGN REQUIREMENTS:
General
Each regulating system reducing gas pressure must have overpressure protection such as a monitor
regulator, relief valve, or shut-off valve. When a relief valve is used it must be sized for a wide-open
failure of the largest capacity regulator.
Regulating systems acting as either District Regulators or Single Service Farm Taps shall be designed to
prevent any single incident from causing an over pressurization of the downstream system, including
multi-stage pressure regulation.
Regulating system equipment including monitor regulators and shut-off devices must be designed to
handle the MAOP of the system upstream of the regulating system. Service regulators shall utilize a
method of overpressure protection to ensure pressure build-up under no flow conditions does not cause
unsafe operation of any connected and properly adjusted gas utilization equipment. Overpressure
devices must be designed to meet the requirements of§192.199 by:
1. Being constructed of materials such that the operation of a device will not be impaired by corrosion.
2. Have valves and valve seats that are designed not to stick in a position that will make the device
inoperative.
3. Be designed and installed so that it can be readily operated to determine if the valve is free, can be
tested to determine the pressure at which it will operate and can be tested for leakage when in the
closed position.
4. Have supports made of noncombustible material.
5. Have discharge stacks, vents, or outlet ports designed to prevent accumulation of water, ice, or
snow, and located where gas can be discharged into the atmosphere without undue hazard.
6. Be designed and installed so that the size of the openings, pipe, and fittings located between the
system to be protected and the pressure relieving device, and the size of the vent line are adequate
to prevent hammering of the valve and to prevent impairment of relief capacity.
METERING AND REGULATION REV. NO. 15
REGULATOR DESIGN DATE 01/01/24
XvIST'r STANDARDS 1 OF 4
utilities NATURAL GAS SPEC. 2.23

7. Where installed at a district regulator station to protect a pipeline system from over-pressuring, be
designed and installed to prevent any single incident such as an explosion in a vault or damage by a
vehicle from affecting the operation of both the overpressure protective device and the district
regulator; and
8. Except for a valve that will isolate the system under protection from its source of pressure, be
designed to prevent unauthorized operation of any stop valve that will make the pressure relief valve
or pressure limiting device inoperative.
Sizing Requirements
Regulating systems should be sized to maintain the required station outlet pressure under full load
conditions with the station inlet pressure at a minimum expected value. Other factors to consider include
the pressure drop in the inlet and outlet piping, fittings, and valves within the station flow path.
Overpressure devices shall be sized to control the wide-open capacity of the regulator without exceeding
the downstream MAOP. They shall be designed and installed so that the size of the openings, pipes,
valves, and fittings located between the system to be protected and the pressure-relieving device and the
size of the vent line downstream are adequate to prevent hammering of the relief valve and to prevent
restriction of relief capacity.
Regulation of Intermediate Pressure to Service Pressure
If the MAOP of the distribution system is 60 psig or less, a suitable protective device such as an internal
relief valve on the service regulator, a monitor regulator, an independent relief valve, or an automatic
shut-off valve shall be used to prevent unsafe overpressuring of the customer's appliances if the service
regulator fails.
Regulation of High Pressure to Service Pressure
If the MAOP of the distribution or transmission system exceeds 60 psig, one of the following methods
must be used to regulate and limit, to the maximum safe value, the pressure of gas delivered to the
customer:
1. Two stage pressure reduction consisting of an upstream regulator performing a first stage pressure
cut followed by a service regulator. The upstream regulator may not be set to maintain a pressure
higher than 60 psig. A device must be installed between the upstream regulator and the service
regulator to limit the pressure on the inlet of the service regulator to 60 psig or less in case the
upstream regulator fails to function properly. This device may be either a relief valve or an
automatic shutoff valve that closes if the pressure on the inlet of the service regulator exceeds the
set pressure (60 psig or less)and remains closed until manually reset. The service regulator must
also feature a suitable protective device such as an internal relief valve, a monitor regulator, an
independent relief valve, or a shut-off valve to protect the customer's piping downstream of the
meter to a maximum safe level in the event the service regulator malfunctions.
2. A service regulator and a monitoring regulator set to limit, to a maximum safe value, the pressure of
the gas delivered to the customer.
3. A service regulator with a relief valve vented to the outside atmosphere, with the relief valve set to
open so that the pressure delivered to the customer does not exceed a maximum safe value. The
relief valve may either be built into the service regulator, or it may be a separate unit installed
downstream from the service regulator. This combination may be used alone only in those cases
where the inlet pressure on the service regulator does not exceed the manufacturer's safe working
pressure rating of the service regulator and may not be used where the inlet pressure on the
service regulator exceeds 125 psig. For higher inlet pressures, refer to (1) and (2) in this section.
METERING AND REGULATION REV. NO. 15
REGULATOR DESIGN DATE 01/01/24
Xv sm a STANDARDS 2 OF 4
utilities NATURAL GAS SPEC. 2.23

4. A service regulator and an automatic shutoff device that closes upon a rise in pressure downstream
from the regulator and remains closed until manually reset.
WAC 480-93-020: In the state of Washington, proximity consideration is required for buildings of
human occupancy within 500 feet of a gas facility having a minimum operating pressure greater than
500 psig and also within 100 feet of a gas facility having a minimum operating pressure between 250
psig and 500 psig. Refer to Specification 2.12, Pipe Design - Steel for specific requirements.
Valves
Each regulator station must have a valve installed on the inlet piping at a distance from the regulator
station sufficient to permit the operation of the valve during an emergency that might preclude access to
the station (50 feet preferred, 20 feet minimum). Refer to Specification 2.14, Valve Design. Consideration
should be given to locating a valve downstream of the station especially if the system is back fed to
enable isolation of the station from both directions.
Except for a valve that will isolate the regulating system from its source of pressure, handles from other
valves in the station should be locked or removed to prevent unauthorized operation.
Control and Sensing Lines
Each takeoff connection and attaching fitting or adapter must be made of suitable material, be able to
withstand the maximum service pressure and temperature of the pipe or equipment to which it is attached
and be designed to satisfactorily withstand all stresses without failure by fatigue.
Control and sensing lines should be located at a point of non-turbulent laminar flow. This generally is
achieved by placing sensing taps a minimum of 10 pipe diameters (based on regulator size) downstream
of valves, regulators, or fittings.
Each control line must be protected from anticipated causes of damage and must be designed and
installed to prevent damage to any one control line from making both the regulator and the overpressure
protection device inoperative. Each sensing line shall have an individual tap.
A shutoff valve must be installed in each takeoff line as near as practical to the point of takeoff. Blow
down valves must be installed where necessary. Strainers and/or filters should be installed as needed to
prevent clogging of lines or orifices by foreign materials.
Capacity
Each pressure relief station or pressure limiting station or group of those stations installed to protect a
pipeline must have enough capacity and must be set to operate as follows:
1. In a low-pressure distribution system (less than 1 psig), the pressure may not cause the unsafe
operation of any connected and properly adjusted gas utilization equipment.
2. In other pipeline systems, if:
a. The MAOP is greater than or equal to 60 psig the pressure may not exceed the MAOP plus 10
percent or the pressure that produces a hoop stress of 75 percent of SMYS, whichever is
lower.
b. The MAOP is greater than or equal to 12 psig or more, but less than 60 psig, the pressure
may not exceed the MAOP plus 6 psig.
c. The MAOP is less than 12 psig; the pressure may not exceed the MAOP plus 50 percent.
METERING AND REGULATION REV. NO. 15
REGULATOR DESIGN DATE 01/01/24
XvIST'r STANDARDS 3 OF 4
utilities NATURAL GAS SPEC. 2.23

In regulator stations with relief devices, the relief set points may not exceed those specified by Gas
Engineering. These calculations must include allowances for any pressure build-up due to pipe, fittings,
and valves in the station, as well as for any outlet pressure limitations on the regulators. Relief capacity
calculations and determination of relief set points should not be performed by field personnel.
Telemetering and Pressure Recorders
In general, telemetering should be provided to monitor system flows and pressures from areas of special
interest such as gate stations and at meter sets of large industrial customers.
Each distribution system supplied by more than one district regulator station shall be equipped with
telemetering or recording pressure gauges to indicate the gas pressure in the district.
On distribution systems supplied by a single district regulator station, Gas Engineering shall determine
the necessity of installing telemetering or recording gauges in the district, taking into consideration the
number of customers supplied, the operating pressures, the capacity of the installation, and other
operating conditions.
Reference Specification 2.25, Telemetry Design for detail regarding the design and installation of
telemetry devices.
Regulator Station Numbering
Regulator station numbering shall be generated by Gas Engineering and verified through the Avista asset
management program. Renumbering is not necessary or recommended for a station that is being rebuilt.
Consideration should be given to renumbering the station if it is moved for any reason to a new location
more than 100 feet from the former location.
METERING AND REGULATION REV. NO. 15
REGULATOR DESIGN DATE 01/01/24
XvIST'r STANDARDS 4 OF 4
utilities NATURAL GAS SPEC. 2.23

2.24 METER AND REGULATOR TABLES AND DRAWINGS
The following tables and drawings are to be used in aiding the sizing and design of gas metering and
regulating facilities. The tables are not included as standards, but as guidelines and tools. The drawings
are the standard for new installations and should be used as guidelines when bringing meters up to
standard.
In the interest of saving space within the following tables, the unit PSI is understood to mean PSIG and
the unit CFH is understood to mean SCFH. Contact Gas Engineering or the Gas Meter Shop if there are
questions regarding regulators that are not included in the tables.
The following table summarizes how the capacity of each regulator was determined based on the
manufacturer's literature.
Regulator Accuracy of Set Pressure
Make Type 7"WC 2 PSIG 5 PSIG
American 1813B +2"/-1"WC ±2%Absolute ±2%Absolute
American 1813C +2"/-1"WC ± 10% Gauge N/A
Fisher CS800 +2"/-1"WC N/A N/A
Fisher CS820 N/A ±2%Absolute ±2%Absolute
Fisher HSR +2"/-1"WC ± 1%Absolute N/A
Fisher 299H +2"/-1"WC ± 1%Absolute ± 1%Absolute
Roots B42 +2"/-1"WC ± 1%Absolute N/A
Roots CL-31-IMRV N/A ± 1%Absolute ± 1%Absolute
Roots CL-38-2IM N/A ± 1%Absolute ± 1%Absolute
Sensus 143-80 +2"/-1"WC ± 10% Gauge ± 10% Gauge
Relief Capacity
Relief capacities should be calculated to protect the downstream system as follows:
Delivery Pressure Protect downstream system to no more than
7"WC 2 PSIG
2 PSIG 5 PSIG
5 PSIG 10 PSIG
Obsolete Regulators
The following regulators are obsolete and shall no longer be utilized within the gas distribution system.
When identified, these regulators shall be replaced or scheduled to be changed out as detailed in the AC
Corrective Order Types and Remediation Time Guidelines Table in Specification 5.20.
METERING AND REGULATION REV. NO. 17
METER AND REGULATOR DATE 01101/25
TABLES AND DRAWINGS
Xv sm a STANDARDS 1 OF 11
utilities NATURAL GAS SPEC. 2.24

OBSOLETE REGULATORS
Regulator Issue
American Reliance Type K No relief valve.
American Reliance 1400, 1401, 1402, 1403 No relief valve.
American Reliance 1410, 1411, 1412, 1413 Insufficient data on relief valve performance.
Fisher S100 No relief valve.
Fisher S102 Inadequate relief valve for 3/16"or larger orifice. Relief valve
OK for 1/8"orifice.
Fisher 730C, 733C Inadequate relief valve/inconsistent lockup.
Fisher 810, 8100 Inadequate or no relief valve.
Fisher S252, S254 with 3/16"or larger orifice. Inadequate relief valve for 3/16"or larger orifice. Relief valve
OK for 1/8"orifice.
Fisher S253 No relief valve.
Fisher S292-4 Inadequate or no relief valve.
Rockwell 043-90, 043-91, 043-180, 043-181 No relief valve.
Rockwell 043-92, 043-182 with 3/16"or larger Inadequate relief valve for 3/16"or larger orifice. Relief valve
orifice. OK for 1/8"orifice.
Rockwell 107 Undocumented relief valve performance.
Rockwell 143-1, 143-4 No relief valve.
Rockwell 143-2, 143-6 with 1/4"or larger orifice. Inadequate relief valve for 1/4"or larger orifice. Relief valve
OK for 1/8"and 3/16"orifice.
Rockwell 143-80-1,143-80-4 No relief valve.
Rockwell 143-80-2 with 1/4"or larger orifice. Inadequate relief valve for 1/4"or larger orifice. Relief valve
OK for 1/8"and 3/16"orifice.
Rockwell 173 Undocumented relief valve performance.
METER CAPACITY TABLES - DIAPHRAGM METERS
PRESSURE CLASS METER CAPACITY IN CFH AT METER PRESSURE SHOWN
RATING Size Make 7"WC 2 PSI 5 PSI 10 PSI 15 PSI 20 PSI 35 PSI 50 PSI
5 psi A AC250 American 300 600 n/a n/a n/a n/a n/a n/a
5 psi A R275 Sensus' 300 600 n/a n/a n/a n/a n/a n/a
10 psi B AL425 American 525 950 1025 n/a n/a n/a n/a n/a
25 psi B AC630 American 800 1375 1500 1700 1875 n/a n/a n/a
20 psi** B AL800 American 1025 1775 2100 2600 2800 3200 4200 5100
25 psi** B AL1000 American 1275 2275 2700 3400 3700 4100 5550 6600
100 psi C AL1400*** American 1800 3125 3700 4600 5000 5600 7550 9000
100 psi C AL2300*** American 2950 5250 6200 7700 8400 9400 12675 15000
100 psi C AL5000*** American 6450 11400 13500 17000 18500 20600 27700 33000
*Formerly Rockwell/Equimeter
**Also Available in Case Rated at 100 psi
***A rotary meter should be used instead of a diaphragm meter for this application.
7-inch WC capacity based on 0.75-inch WC differential across the meter(based on manufacturer's recommendation).
2 PSIG and greater capacities are based on a 2-inch WC differential across the meter.
Grayed out meters may be found in the field but are not currently installed as new
METERING AND REGULATION REV. NO. 17
METER AND REGULATOR DATE 01101/25
TABLES AND DRAWINGS
Xv sm a STANDARDS 2 OF 11
utilities NATURAL GAS SPEC. 2.24

ROTARY METERS
METER CAPACITY IN CFH AT METER PRESSURE SHOWN
SIZE 7" WC 2 PSI 5 PSI 10 PSI 15 PSI 20 PSI 35 PSI 50 PSI
8C 800* 900 1,050 1,300 1,600 1,900 2,600 3,500
1.5M 1500* 1,700 2,000 2,500 3,000 3,500 5,000 6,600
2M 2,000* 2,200 2,600 3,300 4,000 4,700 6,700 8,700
3M 3,000 3,300 4,000 5,000 6,000 7,000 10,000 13,100
3.5M 3,500 3,900 4,600 5,800 7,000 8,200 11,700 15,300
5M 5,000 5,600 6,600 8,300 10,000 11,700 16,800 21,900
5.5M 5,500* 6,125 7,225 9,100 11,000 12,850 18,400 24,000
7M 7,000 7,800 9,300 11,700 14,100 16,400 23,500 30,700
11M 11,000 12,300 14,600 18,300 22,100 25,800 37,000 48,200
16M 16,000 17,800 121,100 126,500 31,900 1 37,400 1 53,600 70,000
23M-1 23,000 125,600 1 30,300 38,100 145,900 1 53,700 1 77,100 1100,600
ROTARY METER MANUFACTURER PRESSURE RATING(PSIG)
Schlumberger/Actaris 125
Romet 175
Roots(Cast Iron Models 11M, 16M, 23M) 125
Roots/Dresser(except 23M232) 175 (8C-5M also available in 200 PSIG)
Dresser 23M232 232
American 275
TURBINE METERS
METER CAPACITY IN CFH AT METER PRESSURE SHOWN WITH 45 DEGREE ROTORS
PRESSURE STANDARD
RATING SIZE MAKE 2 PSI 5 PSI 10 PSI 15 PSI 20 PSI 35 PSI 50 PSI 100 PSI
275 psi 3GT American 11,000 13,000 16,000 20,000 23,000 33,000 44,000 78,000
175 psi 4GT American 20,000 24,000 30,000 36,000 42,000 60,000 79,000 140,000
125 psi 4TURBO Sensus" 20,000 24,000 30,000 36,000 42,000 60,000 79,000 142,000
175 psi 6GT American 33,000 40,000 50,000 60,000 70,000 100,000 131,000 233,000
125 psi 6TURBO Sensus" 39,000 46,000 58,000 70,000 82,000 116,000 154,000 276,000
125 psi 8TURBO Sensus" 67,000 79,000 100,000 120,000 141,000 203,000 265,000 474,000
220 psi 12TURBO Sensus" 156,000 185,000 233,000 281,000 329,000 473,000 618,000 1,106,000
PRESSURE METER CAPACITY IN CFH AT METER PRESSURE SHOWN WITH 30 DEGREE ROTORS
RATING OPTIONAL
SIZE MAKE 2 PSI 5 PSI 10 PSI 15 PSI 20 PSI 35 PSI 50 PSI 100 PSI
275 psi 3GT American n/a n/a n/a n/a n/a n/a n/a n/a
175 psi 4GT American 25,400 30,000 38,000 46,000 54,000 77,500 101,000 181,000
125 psi 4TURBO Sensus" 30,500 36,000 45,000 54,000 63,000 90,800 119,000 213,000
175 psi 6GT American 55,900 66,000 83,000 100,000 117,000 167,000 134,000 394,000
125 psi 6TURBO Sensus** 64,000 75,000 95,000 114,000 134,000 190,000 252,000 450,000
125 psi 8TURBO Sensus" 101,000 119,000 150,000 181,000 211,000 300,000 397,000 711,000
220 psi 12TURBO Sensus** 257,000 304,000 383,000 461,000 540,000 767,000 1,015,000 1,816,000
Available with higher pressure ratings
""Formerly Rockwell/Equimeter
Grayed out meters may be found in the field but are not currently installed as new.
REGULATOR CAPACITY TABLES
METERING AND REGULATION REV. NO. 17
METER AND REGULATOR DATE 01101/25
TABLES AND DRAWINGS
Xv sm a STANDARDS 3 OF 11
utilities NATURAL GAS SPEC. 2.24

REGULATOR CLASSIFICATIONS:
CLASS A= RESIDENTIAL 7—inch W.C. - 0 to 500 CFH
CLASS B = RESIDENTIAL 2 PSIG, & SMALL COMMERCIAL 7 -inch W.C. &2 PSIG - 500 to 2,000 CFH
CLASS C = LARGE COMMERCIAL 7 -inch W.C. &2 PSIG -2,000 to 10,000 CFH
CLASS D = LARGE COMMERCIAL 2PSIG & 5 PSIG - 10,000 to 30,000 CFH
METER SET REGULATORS (BASED ON 30 PSIG INLET; 46-60 PSIG MAOP)
Body Size 7"W.C. 2 PSIG 5 PSIG
Class Make Type Configuration Orifice Capacity Capacity Capacity
CFH CFH CFH
A&B SENSUS 143-80 3/4"X1" 1/8" 695 695 695
INVENSYS 180 DEG 3/16" 1,465 1,465* 1,465*
EQUIMETER 1/4" 2,000* 2,000* 2,000*
ROCKWELL 5/16" ** ** **
WA/ID ONLY 3/8" ** ** **
1/2" ** ** **
B AMERICAN 1813 C 3/4"X1" 1/8" 600 650 n/a
90 & 180 DEG 3/16" 1,400 1,300 n/a
1/4" 2,300* 1,700' n/a
5/16" **** **** n/a
3/8" **** **** n/a
1/2" ** ** n/a
B AMERICAN 1813 C 1-1/4"x1-1/4" 1/8" 700 650 n/a
OREGON ONLY 90 & 180 DEG 3/16" 1,600*** 1,500 n/a
1/4" **** 2,500' n/a
5/16" **** **** n/a
3/8" **** **** n/a
B ROOTS B42 3/4"x1" 1/8" 700 500 n/a
ITRON 90 & 180 DEG 1/8"x3/16" 700 700 n/a
ACTARIS 3/16" 1,400 900 n/a
SCHLUMBERGER 1/4" 2,000* 1,230* n/a
WA/ID ONLY 5/16" ** ** n/a
Body Size 7" W.C. 2 PSIG 5 PSIG
Class Make Type Configuration Orifice Capacity Capacity Capacity
CFH CFH CFH
A&B FISHER HSR 3/4"x1" 1/8" 710 650 n/a
90 & 180 DEG 3/16" 1,480 1,150 n/a
1/4" Pending4 1,780* n/a
3/8" ** ** n/a
1/2" ** ** n/a
B&C ROOTS CL-31-IMRV 3/4"x1" 1/8" n/a 7002 7002
ITRON & 1-1/4"x1-1/4" 3/16" n/a 1,5752 1,5752
ACTARIS 180 DEG 1/4" n/a 2,2752 2,2502
SCHLUMBERGER 5/16" n/a 2,7002 2,7002
C AMERICAN 1813 B 2"x2" 1/4" 2,800 2,600 1,500
OREGON ONLY 180 DEG 3/8" 5,900 5,700 2,000
METERING AND REGULATION REV. NO. 17
METER AND REGULATOR DATE 01101/25
TABLES AND DRAWINGS
Xv sm a STANDARDS 4 OF 11
utilities NATURAL GAS SPEC. 2.24

Body Size 7" W.C. 2 PSIG 5 PSIG
Class Make Type Configuration Orifice Capacity Capacity Capacity
CFH CFH CFH
1/2" 10,300* 10,1001 3,200
5/8" **** 12,600* 3,900*
3/4" **** 15,900* 4,700*
7/8" **** 18,000* 4,600*
C FISHER CS8001Q (in) 2"X2" 3/8"x1/4" 2850 2,940 2,930
CS8201Q(lbs) 180 DEG 3/8" 6290 6,170 4,050
1/2" 11,8501 11,770 6,360
High Capacity 5/8" 18,720* 16,960* 8,380
2-1/2" IRV 3/4" 23,010* 20,850* 10,580
7/8" ** 23,130* 13,250*
C&D FISHER 299H 2"x2" 1/4"x3/8" 2,890* 2,890* 2,890*
WA/ID ONLY NO IRV 180 DEG 3/8" 6,640* 6,640* 6,640*
1/2" 11,540* 11,540* 11,540*
3/4" 24,800* 24,800* 24,800*
1" 40,950* 40,950* 40,950*
1-3/16" 51,040* 51,040* 51,040*
C&D ROOTS CL-38- 2"x2" 3/8" n/a 6,0003 6,0003
ITRON 21MRV 180 DEG 1/2" n/a 8,9003 8,9003
ACTARIS 5/8" n/a 13,6003 13,6003
SCHLUMBERGER 3/4" n/a 15,8003 15,8003
Use Black Closing Sprin -> 1" n/a 19,4003 19,4003
*Exceeds IRV capacity or has no IRV.Assemble with properly sized relief valve.
"Exceeds maximum inlet rating for orifice size, replace with proper regulator or orifice if found in the field.
Acceptable if found in the field.Do not install new in this configuration.
****Not acceptable because of IRV capacity and parameters fall outside of optimum performance criteria, replace with
proper regulator or orifice if found in the field.
Internal Relief Valve OK at typical high operating pressure of 2-4 psig below MAOP.
2 When using a CL31-IMRV regulator,a 1-inch Fisher 289H relief valve should also be installed. If the regulator is set at 2
psig,set the relief valve at 4 psig. If the regulator is set at 5 psig,set the relief valve at 8 psig.
3 When using a CL38-21MRV regulator,a 2-inch Fisher 289H relief valve should also be installed. If the regulator is set at
2 psig,set the relief valve at 4 psig. If the regulator is set at 5 psig,set the relief valve at 8 psig.
4 Capacity at 7"w.c.is not currently published by the manufacturer for this orifice size.Capacity will be updated once this
information is available from the manufacturer.
METERING AND REGULATION REV. NO. 17
METER AND REGULATOR DATE 01101/25
TABLES AND DRAWINGS
Xv sm a STANDARDS 5 OF 11
utilities NATURAL GAS SPEC. 2.24

METER SET REGULATORS (BASED ON 15 PSIG INLET; 22.6-45 PSIG MAOP)
Body Size 7" W.C. 2 PSIG 5 PSIG
Class Make Type Configuration Orifice Capacity Capacity Capacity
CFH CFH CFH
A&B SENSUS 143-80 3/4"X1" 1/8" 450 450 450
INVENSYS 180 DEG 3/16" 1,035 1,035 1,035
EQUIMETER 1/4" 1,680 1,680* 1,680*
ROCKWELL 5/16" ** ** **
WA/ID ONLY 3/8" ** ** **
1/2" ** ** **
5/8" ** ** **
B AMERICAN 1813 C 3/4"X1" 1/8" 425 425 n/a
90 & 180 DEG 3/16" 900 800 n/a
1/4" 1,400 1,000 n/a
5/16" **** **** n/a
3/8" **** **** n/a
B AMERICAN 1813 C 1-1/4"xl-1/4" 1/8" 450 425 n/a
OREGON ONLY 90 & 180 DEG 3/16" 1,000*** 850 n/a
1/4" 1,800*** 1,200 n/a
5/16" **** ** n/a
3/8" **** ** n/a
B ROOTS B42 3/4"x 1" 1/8" 425 300 n/a
ITRON 90 & 180 DEG 1/8"x3/16" 470 415 n/a
ACTARIS 3/16" 850 500 n/a
SCHLUMBERGER 1/4" 1,200' 650* n/a
WA/ID ONLY 5/16" ** ** n/a
3/8" ** ** n/a
A&B FISHER HSR 3/4"x1" 1/8" 423 380 n/a
90 & 180 DEG 3/16" 840 620 n/a
1/4" 1,475* 950* n/a
3/8" ** ** n/a
1/2" ** ** n/a
B&C ROOTS CL-31-IMRV 3/4"x1" 1/8" n/a 5002 5002
ITRON & 1-1/4"x1-1/4" 3/16" n/a 1,0252 9502
ACTARIS 180 DEG 1/4" n/a 1,3752 1,2752
SCHLUMBERGER 5/16" n/a 1,6502 1,5252
C AMERICAN 1813 B 2"x2" 1/4" 1,900 1,800 1,000
OREGON ONLY 180 DEG 3/8" 4,000 3,200 1,100
1/2" 6,400* 5,500 1,900
5/8" **** 6,200* 2,300
3/4" **** 8,500* 2,600
7/8" **** 9,600* 2,600*
C FISHER CS8001Q (in) 2"X2" 3/8" x 1/4" 1,870 1,980 1,820
CS8201Q (Ibs) 180 DEG 3/8" 3,130 4,150 1,950
1/2" 7,760 7,440 3,410
High Capacity 5/8" 12,000* 10,230 4,020
2-1/2" IRV 3/4" 16,170* 12,410* 5,440
7/8" **** 15,290* 5,830
METERING AND REGULATION REV. NO. 17
METER AND REGULATOR DATE 01/01/25
TABLES AND DRAWINGS
x rv#.ST, a STANDARDS 6 OF 11
Utilities NATURAL GAS SPEC. 2.24

Body Size 7"W.C. 2 PSIG 5 PSIG
Class Make Type Configuration Orifice Capacity Capacity Capacity
CFH CFH CFH
C&D FISHER 299H 2"x2" 1/4"x3/8" 1,920* 1,920* 1,870*
WA/ID ONLY NO IRV 180 DEG 3/8" 4,410* 4,360* 4,190*
1/2" 7,670* 7,580* 7,280*
3/4" 16,480* 15,990* 15,150*
1" 25,750* 25,050* 23,310*
1-3/16" 31,690* 30,760* 28,530*
C&D ROOTS CL-38- 2"x2" 3/8" n/a 3,9503 3,7503
ITRON 21MRV 180 DEG 1/2" n/a 5,4503 5,2003
ACTARIS 5/8" n/a 9,0003 8,6003
SCHLUMBERGER 3/4" n/a 10,4003 10,0003
Use Black Closing Sprin -> 1" n/a 12,8003 12,2003
Exceeds IRV capacity,or has no IRV.Assemble with properly sized relief valve.
"Exceeds maximum inlet rating for orifice size, replace with proper regulator or orifice if found in the field.
Acceptable if found in the field.Do not install new in this configuration.
****Not acceptable because of IRV capacity and parameters fall outside of optimum performance criteria, replace with
proper regulator or orifice if found in the field.
Internal Relief Valve OK at typical high operating pressure of 2-4 psig below MAOP.
2 When using a CL31-IMRV regulator,a 1-inch Fisher 289H relief valve should also be installed. If the regulator is set at 2
psig,set the relief valve at 4 psig. If the regulator is set at 5 psig,set the relief valve at 8 psig.
3 When using a CL38-21MRV regulator,a 2-inch Fisher 289H relief valve should also be installed. If the regulator is set at
2 psig,set the relief valve at 4 psig. If the regulator is set at 5 psig,set the relief valve at 8 psig.
METER SET REGULATORS (BASED ON 5 PSIG INLET; 10-22.5 PSIG MAOP)
Body Size 7" W.C. 2 PSIG
Class Make Type Orifice Capacity Capacity
Configuration CFH CFH
B AMERICAN 1813 B 2"x2" '/4" 1,000 850
OREGON ONLY 180 DEG 3/8" 2,000 1,600
'/2" 2,900 2,300
5/8" 4,000* 2,600
3/4" 5,000* 3,700
7/8" 7,000* 4,100*
1" **** 4,400*
B AMERICAN 1813 C 3/4"X1" 1/8" 250 225
90 & 180 DEG 3/16" 450 350
'/4" 650 450
5/16" 750 500
3/8" 950* 650
'/2" 1,200* 750*
9/1 6" ** **
B AMERICAN 1813 C 1-1/4" x 1-1/4" 1/8" 275 225
OREGON ONLY 90 & 180 DEG 3/16" 550 350
'/4" 1,000 500
5/16" 1,600 600
3/8" 2,100* 700'
'/2" 2,500* 900*
METERING AND REGULATION REV. NO. 17
METER AND REGULATOR DATE 01101/25
TABLES AND DRAWINGS
Xv sm a STANDARDS 7 OF 11
utilities NATURAL GAS SPEC. 2.24

Body Size 7„ W.C. 2 PSIG
Class Make Type Configuration Orifice Capacity Capacity
CFH CFH
A&B FISHER HSR 3/4"x1" 1/8" 228 *****
90 & 180 DEG 3/16" 338 250
1/4" 575 350
3/8" 938* 510*
1/Z„ ** **
B&C ROOTS CL-31-IMRV %"x1" 1/8" n/a 2752
ITRON & 1-1/4"x1-1/4" 3/16" n/a 5002
ACTARIS 180 DEG 1/4" n/a 6002
SCHLUMBERGER 5/16" n/a 6802
C FISHER CS800IQ (in) 2"X2" 3/8"x 1/4" 1,120 1,140
CS820IQ (lbs) 180 DEG 3/8" 1,120 1,850
1/2" 2,600 3,140
High Capacity 5/8" 3,670 4,120
2-1/2" IRV 3/4" 4,630* 5,150
7/8" 8,130* 6,120
1" 9,590* 7,050*
1-3/8" ** **
C&D ROOTS CL-38-2IM 2"x2" 3/8" n/a 1,9003
ITRON 180 DEG 1/z" n/a 2,6503
ACTARIS 5/8" n/a 4,2503
SCHLUMBERGER %11 n/a 4,9503
1" n/a 6,2503
"Exceeds IRV capacity,or has no IRV. Assemble with properly sized relief valve.
Exceeds maximum inlet rating for orifice size, replace with proper regulator or orifice if found in the field.
Acceptable if found in the field. Do not install new in this configuration.
****Not acceptable because of IRV capacity and parameters fall outside of optimum performance criteria, replace with
proper regulator or orifice if found in the field.
*****Not acceptable because droop/boost would exceed design criteria. Replace with proper regulator or orifice if found
in the field.
1 Internal Relief Valve OK at typical high operating pressure of 2-4 psig below MAOP.
2When using a CL31-IMRV regulator,a 1-inch Fisher 289H relief valve should also be installed. If the regulator is set at 2
psig,set the relief valve at 4 psig.
'When using a CL38-21MRV regulator,a 2-inch Fisher 289H relief valve should also be installed. If the regulator is set at
2 psig,set the relief valve at 4 psig.
METER SET REGULATORS BASED ON 2 PSIG INLET; 6-8 PSIG MAOP
Body Size 7"W.C. 2 PSIG')
Class Make Type Orifice Capacity Capacity
Configuration CFH CFH
B AMERICAN 1813 B 2"x2" 1/4" n/a 5752
OREGON ONLY 180 DEG 3/8" 1,250 1,1002
1/2" 1,600 1,6002
5/8" 2,400 1,7002
3/4" 2,700 2,2002
7/8" 3,500 2,5002
1" 4,400*1 2,8002
METERING AND REGULATION REV. NO. 17
METER AND REGULATOR DATE 01101/25
TABLES AND DRAWINGS
Xv sm a STANDARDS 8 OF 11
utilities NATURAL GAS SPEC. 2.24

B AMERICAN 1813 C 3/4"X1" 1/8"x3/16" n/a 150
90 & 180 DEG 3/16" 250 225
1/4" 350 250
5/16" 450 350
3/8" 500 425
1/2" 600* 550
9/16" 650* 550*
B AMERICAN 1813 C 1-1/4" x 1-1/4" 1/8"x3/16 n/a 150
OREGON ONLY 90 & 180 DEG 3/16" 325 225
1/4" 500 350
5/16" 600 375
3/8" 700 425
1/2" 950* 550
9/16" 1,400* 550*
A&B FISHER HSR 3/4"x1" 1/8" 148 *****
90 & 180 DEG 3/16" 220 *****
1/4" 283 200
3/8" 418 300
1/2" 623* 400
B&C ROOTS CL-31-IMRV 3/4"x1" 1/8" n/a n/a
ITRON & 1-1/4"x1-1/4" 3/16" n/a 3003
ACTARIS 180 DEG 1/4" n/a 3253
SCHLUMBERGER 5/16" n/a 3503
C FISHER CS800IQ (in) 2"X2" 3/8" x 1/4" 810 720
CS820IQ(Ibs.) 180 DEG 3/8" 1,080 1,150
1/2" 2,040 1,980
High Capacity 5/8" 2,750 2,470
2-1/2" IRV 3/4" 3,950 3,230
7/8" 4,610 3,540
1" 4,990 4,200
1-3/8" 6,250* 5,640
C&D ROOTS CL-38-2I M 2"x2" 3/8" 1,4004 1,1504
ITRON 180 DEG 1/2" 1,9504 1,6004
ACTARIS 5/8" 3,1004 2,5504
SCHLUMBERGER 3/4" 3,6504 3,0004
1111 4,55051 3,7504
"Exceeds IRV capacity or has no IRV.Assemble with properly sized relief valve.
"****Not acceptable because droop/boost would exceed design criteria. Replace with proper regulator or orifice if found
in the field.
Capacities at 2 psig delivery pressure are sized using a 3 psig inlet pressure.
2 Use American Meter spring 71424PO21 (1-2 psig)to achieve listed capacity.
'When using a CL31-IMRV regulator,a 1-inch Fisher 289H relief valve should also be installed. If the regulator is set at
2 psig,set the relief valve at 4 psig.
4 When using a CL38-2IMRV regulator,a 1-inch Fisher 289H relief valve should also be installed. If the regulator is set
at 7"WC,set the relief valve at 1 psig. If the regulator is set at 2 psig,set the relief valve at 4 psig.
'When using a CL38-2IMRV regulator with a 1 inch orifice at 7-inch WC,a 2-inch Fisher 289H relief valve set at 1 psig
should also be installed.
METERING AND REGULATION REV. NO. 17
METER AND REGULATOR DATE 01101/25
TABLES AND DRAWINGS
Xv sm a STANDARDS 9 OF 11
utilities NATURAL GAS SPEC. 2.24

FARM TAP REGULATOR 500 PSIG MAOP INLET (50 PSIG SET POINT)
150 PSIG 250 PSIG 500 PSIG
Class Make Type Body Size Orifice Inlet Inlet Inlet
Configuration Capacity Capacity Capacity
CFH CFH CFH
N/A Fisher 620 &621 3/4"x3/4" 3/32" 1,360* 2,190* 4,200*
OUT OF 1/8" 2,430* 3,910* 7,500*
PRODUCTION 1/4" 9,070* 15,000* 28,650*
3/8" N/A** N/A** N/A**
1/2" N/A** N/A** N/A**
N/A Fisher 627R* 3/4"x3/4" 3/32" 1,420* 2,275* 4,400*
IRV 1/8" 2,580* 4,100* 8090*
INADEQUATE 3/16" 5,850* 9,400* 18,300*
1/4" 9,740* 15,050* 20,000*
3/8" ** ** N/A**
1/2" ** ** N/A**
N/A Fisher 630* 2" x2" 1/8" 2,600* 4,550* 9,500*
3/16" 5,700* 9,450* 20,500*
1/4" 8,700* 15,500* 37,500*
3/8" 13,000* 34,500* 86,500*
1/2" N/A** N/A** N/A**
N/A Rockwell 041* 3/4"x3/4" 1/8" 2,600* 4,050* 8,000*
(Equimeter) OUT OF 3/16" 5,400* 8,750* 17,000*
PRODUCTION 1/4" 9,900* 15,850* 30,500*
5/16" 14,500* 21,750* N/A**
3/8" 19,000* 29,000* N/A**
N/A Rockwell 141-A* 2"x2" 1/8" 3,000* 3,700* 8,500*
(Equimeter) 1/4" 9,000* 11,000* 26,250*
(Sensus) 3/8" 21,000* 25,000* 42,000*
1/2" N/A** N/A** N/A**
5/8" N/A** N/A** N/A**
N/A Rockwell 046* 3/4"x3/4" 1/8" 2,600* 4,050* 8,000*
(Equimeter) 3/16" 5,400* 8,750* 17,000*
(Sensus) 1/4" 9,900* 14425* 24,500*
5/16" N/A** N/A** N/A**
3/8" N/A** N/A** N/A**
*Has no IRV or IRV is inadequate. Assemble with properly sized relief valve.
**Exceeds maximum inlet rating or pressure drop for orifice size.
Grayed out regulators may be found in the field but are not currently installed as new.
For inlet pressure above 500 psig MAOP and orifices above%"consult Gas Engineering.
METERING AND REGULATION REV. NO. 17
METER AND REGULATOR DATE 01101/25
TABLES AND DRAWINGS
Xv sm a STANDARDS 10 OF 11
utilities NATURAL GAS SPEC. 2.24

RELIEF VALVE CAPACITIES AT SET POINT
(60 MAOP DOWNSTREAM)
Make Type Size Orifice Set @ 50 PSIG Set @ 60 PSIG
Capacity CFH Capacity CFH
American I Axial Flow I 2" 1 100% I 164,000 190,000
3/4" x 3/4" -4 3,840 4,440
Anderson Greenwood 83 3/4"x 1" -6 8,580 9,960
3/4" x 1" -8 15,300 17,700
Fisher 289H* 1" 1" 56,500* N/A
Fisher 289HH** 1" 1" 36,000 30,000**
Fisher 1805 3/4" 3/4" 1,500 N/A
Mooney Single Port 1" 100% 38,000 43,350
Mooney Single Port 2" 100% 94,000 108,000
"Maximum set point 50 psig.
*"Maximum set point 53 psig to maintain 60 psig MAOP.
Grayed out relief valves may be found in the field, but are not currently installed as new.
For pressure conditions other than listed,consult Gas Engineering for proper sizing.
(OTHER APPLICATIONS)
Make Type Size Orifice Set @ 15" W.C. COMMENTS
Capacity CFH
Fisher 289L 1" 1" 8,300 Capacity at 2 psig build-up
METERING AND REGULATION REV. NO. 17
METER AND REGULATOR DATE 01/01/25
TABLES AND DRAWINGS
x rv#.ST, a STANDARDS 11 OF 11
Utilities NATURAL GAS SPEC. 2.24

APPENDIX A— METER AND REGULATOR DRAWINGS
DRAWING PAGE VERSION YEAR DESCRIPTION
A-36712 1 of 2 12 2021 Meter Set Barricade Detail for Diaphragm Type
Meters
A-36712 2 of 2 1 2015 Meter Set Barricade Detail for Close Proximity to
Electric Equipment
A-38500 1 of 1 2 2024 Meter Set Stand for Flex Line Support
A-34175 1 of 2 3 2014 Single Pipe Ground Support for Meter Sets and
District Regulator Stations
A-34175 2 of 2 1 2014 Double Pipe Ground Support for Meter Sets and
District Regulator Stations
A-35208 1 of 1 9 2023 Residential Meter Sets, Intermediate Pressure Gas
Dist. Systems
Residential Meter Sets, 2 psig Delivery, Intermediate
A-37102 1 of 1 8 2023 Pressure Gas Dist Systems
A-37103 1 of 1 2 2015 Meter Set, Residential, Intermediate Pressure Gas
Dist. Systems
B-35207 1 of 2 0 2016 Residential Meter Sets, High Pressure Systems with
MAOP 175 PSIG or less.
B-35207 2 of 2 7 2021 Small Commercial Standard Meter Sets, High
Pressure Systems with MAOP 175 PSIG or less.
C-35209 1 of 2 11 2023 Small Commercial Standard Meter Sets, Metering
and Regulation
C-35209 2 of 2 8 2023 Standard Meter Sets, Typically Large Diaphragm
Meter Set
B-33325 1 of 4 11 2023 2000, 3000 and 3500 Rotary Meter, Intermediate
Delivery Pressure
B-33325 2 of 4 13 2023 5000 and 7000 Rotary Meters, Intermediate Delivery
Pressure
B-33325 4 of 4 13 2023 11000 Rotary Meter, Intermediate Delivery Pressure
B-38205 1 of 1 5 2023 2000, 3000 and 3500 Rotary Meter, Intermediate
Delivery Pressure
B-35785 1 of 1 11 2023 Standard Meter Threaded 5000 and 7000 Rotary
Meters
E-37197 1 of 1 8 2023 Code 3-2" Standard Meter Set
E-37842 1 of 1 6 2022 Welded Farm Tap Station 2" outlet
E-37970 1 of 1 6 2022 Welded Farm Tap Station, 3/4" outlet
E-33952 1 of 1 7 2021 Single Run District Reg, 2" x 4"with 2" inlet/4"
outlet
E-35783 1 of 1 7 2021 Single Run District Reg, 4" x 6"with 4" inlet/6"
outlet
E-35158 1 of 1 7 2021 Dual Run District Reg, 2" x 4"with 2" inlet/4" outlet
L-36082 1 of 1 2 2008 Reg STA Fencing Detail

BLDG BLDG
Lli
Q M 2" DIA STEEL a M PREFABRICATED
> BOLLARD > METER SET
(NOTE 1) _ BARRICADE
PLAN 1 FILL PIPE WITH CL ASSEMBLY
PLAN 2 (NOTE 1)
CONCRETE. - OPTIONAL
EITHER SHAPE `V REFLECTIVE TAPE PREFABRICATED
CONCRETE FOR METER SET
POSITIVE BARRICADE
DRAINAGE OR - ASSEMBLY
of INSTALL CAP +i
(NOTE 1)
OPTIONAL Li 7 BAGS OF 60 LB
REFLECTIVE TAPE CONCRETE NEEDED
N =1I I I I I I EMBED N I I IIIII °I f al BOLLARD IN
IN =III=III
-12 CONCRETEIII III
(NOTE 2) 11L
2
ELEVATION 4 BAGS OF 60 LB - EMBED POST
CONCRETE NEEDED ELEVATION IN CONCRETE
RESIDENTIAL - OPTION 1 RESIDENTIAL - OPTION 2 (NOTE 2)
NOTES :
BLDG 1. 2" WIDE REFLECTIVE TAPE - STOCK #668-0885
4" DIA STEEL 4" WIDE REFLECTIVE TAPE - STOCK #668-0887
w BOLLARD 2" STEEL BOLLARD - STOCK # 770-4752
a M 2 BOLLARD CAP - STOCK #770-4753
> (NOTES 1 & 4) 2" PRE-FABRICATED BARRICADE - STOCK #770-4755
4" BOLLARD CAP - STOCK #770-4756
FILL PIPE WITH 4" STEEL BOLLARD - STOCK #770-4757
PLAN 3 CONCRETE. 2. AVISTA CONSTRUCTION PERSONNEL SHALL SELECT
APPROPRIATE BARRICADE STYLE AND LOCATION OF
REFLECTIVE EITHER SHAPE BARRICADE USING BEST JUDGEMENT BASED ON EXISTING
TAPE CONCRETE SITE CONDITIONS. CONCRETE DIMENSIONS AND BOLLARD
FOR POSITIVE BURY DEPTHS SHOWN ARE PREFERRED. DEVIATIONS TO
DRAINAGE OR THESE DIMENSIONS MAY BE APPROVED BY THE LOCAL
INSTALL CAP MANAGEMENT IF DIMENSIONS ARE NOT PRACTICABLE TO
ACHIEVE.
o (NOTE 1) 3. SEE SHEET 2 FOR CLEARANCE AND GROUNDING
9 BAGS OF 60 LB REQUIREMENTS WHEN INSTALLED NEAR PRIMARY VOLTAGE
CONCRETE ELECTRICAL EQUIPMENT.
4. A SINGLE BOLLARD IS AN OPTION IN COMMERCIAL
tF- I NEEDED APPLICATIONS IF THE FIELD CONDITIONS SUPPORT.
N I °I III III I DISTRIBUTION - GAS
III-III LJ STANDARD
012„ III11 1= METER SET BARRICADE/ BOLLARD DETAIL
EMBED FOR DIAPHRAGM TYPE METERS
BOLLARD IN
Q AVISTA CORP
ELEVATION CONCRETE SPOKANE, WASHINGTON
Iq COMMERCIAL (NOTE 2) NNE 11-07-07 PPRO
co SCALE DATE
o DSN T.BARRY CKD T.I f f 1 1-13-07
12 11-5-21 STANDARDS UPDATE CGD DR S.GRAF NTD SHT 1 DATE
NO DATE REVISION BY CKD I CKD L2W- NTD OF 2 A-36712
AUTOCAD DWG

• BOLLARD BOLLARD
_ 6' SEPARATION IS PREFERRED BETWEEN STEEL BOLLARDS AND
6' RULE PRIMARY VOLTAGE ELECTRIC EQUIPMENT (GREATER THAN 600V).
\ IF THE 6' SEPARATION CANNOT BE ACHIEVED, ONE OF THE
:.. • FOLLOWING IS REQUIRED:
` 1. INSTALL NON—CONDUCTIVE BOLLARD PER DETAIL 1 BELOW
TOP VIEW / 2. INSTALL NON—CONDUCTIVE SLEEVE OVER STEEL BOLLARD
PADMOUNT PER DETAIL 2 BELOW
ELECTRICAL / 3. COORDINATE WITH ELECTRIC PROVIDER TO BOND THE STEEL
EQUIPMENT BOLLARD TO THE ELECTRIC EQUIPMENT GROUND
(GREATER THAN
600V) \ EQUIPMENT DOOR
SWING RADIUS
/ NOTE:
IF THERE ARE QUESTIONS ON THE APPLICATION
OF THIS STANDARD, CONTACT GAS ENGINEERING
BOLLARD LOCATION
REFLECTIVE YELLOW PLAN VIEW
CEME—TUBE BOLLARD �..
MODEL ABOVE GRADE
(STOCK NO 601-0505) 4— NO 6 CEME—TUBE PE SLEEVE
REBAR
(STOCK NO OVER STEEL BOLLARD.
APPROXIMATELY CUT—TO—LENGTH AND
3 CUBIC FEET 570-1200) INSTALL PER MFG
OF CONCRETE INSTRUCTIONS.
PER BOLLARD '' ' (STOCK NO 770-4758)
STOCK NO 668-0530
' _'REBAR I NEW OR EXISTING
I_ I. STEEL BOLLARD
`'4 `' SHOULD BE
2' MINIMUM EVBEDDED IN
B CONCRETE PER
BELOW GRADE
i •: ; 4 + SHEET 1
.. 1
` STANDARD BLACK DETAIL 2
CEME—TUBE
NON—CONDUCTIVE SLEEVE
BELOW GRADE ELEVATION
(STOCK NO
EMBED BOLLARD ° 601-0500)
IN CONCRETE DISTRIBUTION -GAS
12"-16" STANDARD
METER SET BARRICADE DETAIL
CLOSE PROXIMITY
DETAIL 1 TO EL CTTRIC EQUIPMENT
NON-CONDUCTIVE BOLLARD AV6TA CORP
ELEVATION SPOKANE, WASHINGTON
NONE 10-1 DATE
A��RQL/
1 8-26-15 STANDARDS UPDATE CGD fl�S DATE
FORTCKDTJH
0 10-10-14 STANDARDS UPDATE JAJ (f pRNJACOBSEN NTD SHT 2 1 p2� 14
NO DATE REVISION BY CKD CKD NTDL_ of 2 A-36712

MATERIAL LIST
NO STOCK NO QTY DESCRIa"iON
S1 770-7848 1 UNISTRUT PLASTIC END CAP, WHITE
S2 570-2116 1 PIPE Cl AMP, 1 , GALVAN 717D
S3 770-7844 1 UNISTRUT CHANNEL, 1%"x 1 V8", 12 GAUGE, GALVANIZED
S4 770-7851 1 POST BASE FOR UNISTRUT CHANNEL, 6" x 6" ELECTRO—PLATED ZINC
S5 573-1021 1 UNISTRUT CHANNEL NUT,}t2", WITH LONG SPRING
S6 770-7852 1 HEX CAP SCREW, , 2 L, SILVER ZINC PLATED
S7 FAB SHOP 2 CONCRETE ANCHOR BOLT, DIAMETER
NOTE:
S2 TO BE ATTACHED AS CLOSE AS PRACTICAL TO THE OUTLET PIPING (OR A-9 VALVE) OF THE METER.
S 1 -" FLEX
CONNECTOR
RIGID PIPE (MINIMUM)
S2
Sn2 0
S3 0
S1 0
0
0 0
0
0 S5 S6 0
s4 0 (on: 2 ON 0
S2 OPPOSITE CORNERS) S3 0
0 0 S5 S6
a CONCRETE /\\j/\�j /\�j\
e
Q OPTION 1:
ANCHOR TO CONCRETE OR ASPHALT
OPTION 2:
DIRECT BURY
DISTRIBUTION - GAS
STANDARD
METER SET STAND
FOR FLEX LINE SUPPORT
AVISTA CORP
SPOKANE. WASHINGTON
2 5-16-24 STANDARDS l PDA1E CGD BDP NONE 2-4-2020 a ROVED�
1 1 1-5-21 STANDARDS UPDATE CGD DATE
OSINANDERSON CKD 1 14-20
0 10-14-20 ADDED TO STANDARDS CGD DARN LL I,Rp SqT 1 DATE
NO DATE REVISION BY qcKo NTD of A-38500
AUTOCAD DWG

SINGLE PIPE SUPPORT MATERIAL LIST
S1 770-61 10 6' PIPE, 2"0, STEEL, BARE, STD WALL
S2 770-0950 1 WELD CAP, 2", STD WALL
S3 FAB SHOP 1 HD HEX NUT, 1"0
S4 FAB SHOP 1 STUD, 1"0 x 10" LONG (ALL THREAD)
S5 FAB SHOP 1 PL-Y" x 6" x 6" LONG (BASE PLATE)
S6 FAB SHOP 2 CONCRETE ANCHOR BOLTS, -Y8"0
S7 FAB SHOP 1 PLY4" x 2" x 7" LONG (SADDLE)
S8 1 770-3210 1 1 INSULATING MATERIAL FOR SADDLE, Y,6" THICK
GAS PIPE
S7 S8 i S4
o S3 I S2
LLJ
S5
T S6 i CONCRETE
1 SUPPORT
12"
CONSTRUCTION NOTES
2"CAP DRILL 1.125 HOLE IN TOP
2" PIPE FIELD FIT, (10" THREADED STUD
PROVIDES HEIGHT ADJUSTMENT)
REMOVE ALL RUST AND SCALE, DISTRIBUTION - GAS
PAINT APPLY ONE COAT OF PRIMER, AND STANDARD
TWO COATS OF GRAY METER SINGLE PIPE GROUND SUPPORT FOR METER SETS
ENAMEL AND DISTRICT REGULATOR STATIONS
AVISTA CORP
SPOKANE, WASHINGTON
3 8-6-14 STANDARDS UPDATE JAJ 1 -a 11-05-93 Ro
2 10-09 CORRECT TO DATE TJH k6B SCAM I DATE
DSN BURGER CKD 7rl 1-09-93
1 1-97 CORRECT TO DATE JW MF DR PICKUP NTD SHT 1 DATE
NO I DATE I REVISION BY CKD CKD NTD J W of 2 A-34175
AUTOCAD DWG

PIPE SUPPORT MATERIAL LIST
S1 770-6110 10' PIPE, 2"0. STEEL, BARE, STD WALL
S2 770-0950 1 WELD CAP, 2", STD WALL
53 FAB SHOP 1 HD HEX NUT, 1"0
S4 FAB SHOP 1 STUD, 1"0 x 10" LONG (ALL THREAD)
S5 FAD SHOP 2 PL-" x 6" x 6" LONG (BASE PLATE)
S6 FAB SHOP 4 CONCRETE ANCHOR BOLTS, Y8"0
S7 FAB SHOP 1 PL Ya" x 2" x 7" LONG (SADDLE)
S8 770-3210 1 INSULATING MATERIAL FOR SADDLE. Y6" THICK
S9 FAB SHOP 1 PL Y8" x 6" x 6" (CUT TO FORM 2 EA) GUSSETS
S10 FAB SHOP 2 TS 2Y" x 2y" x �f6"
S11 FAB SHOP 2 BAR 2Yz" x RC x 21 " LONG
GAS PIPE
S3
S8 S7 DRILL lY8"O HOLE
FOR I " ALL THREAD
o S11 "
S9
S 10 I
w S4
GAS PIPE
S 1
S5 S6 I CONCRETE
II
SUPPORT
1 6" * MAINTAIN
MINIMUM OF
CONSTRUCTION NOTES 2'-8" MIN 2" CLEARANCE
2"CAP DRILL 1.125 HOLE IN TOP
FIELD FIT, (10" THREADED STUD DISTRIBUTION - GAS
2" PIPE PROVIDES HEIGHT ADJUSTMENT) STANDARD
REMOVE ALL RUST AND SCALE, DOUBLE PIPE GROUND SUPPORT FOR METER SETS
NAINI APPLY ONE COAT OF PRIMER, AND AND DISTRICT REGULATOR STATIONS
TWO COATS OF GRAY METER AVISTA CORP
ENAMEL SPOKANE, WASHINGTON
1 = 1 -0 1 10-16-09 ROV
SCALE DATE
DSN WEBB CKD 10-19-09
1 8-6-14 STANDARDS UPDATE JAJ DR TJH NT0 SKI 2 DATE
NO DATE REVISION BY CKD CKD NTD of 2 A-34175

MATERIAL LIST
QTY STOCK NO SIZE DESCRIPTION
1 MTR SHOP 20 LT CLASS "A" METER
2 770-8555 METER VALVE, INSULATED, THD, 100 PSIG, WITH BYPASS PORT
* 3 M(TR SHOP 4 x 1 CLASS "A" REGULATOR W/2 PSI CAPABILITY
�}c 4 732-5464 34" x 6" NIPPLE, THD, SCH 40
* 5 - 1"x 20 LT U-BEND, GR A. THD, COATED
6 770-8515 20LT x 1" A-9 VALVE. FNPT INSULATED UNION OUTLET
7 770-6430 4" CORRUGATED PVC
8 770-7220 ANODELESS SERVICE RISER
�}c ITEMS 3-5 ARE INCLUDED WITH
STOCK NUMBER 770-4932
BUILDING WALL
==E:r TYPICAL
HOUSE
PLAN VIEW PIPING
5 1' I
6
3 I I
NOTE:
INSTALL VENT I CONSTRUCTION NOTES:
IN DOWNWARD 1 1. PAINT FITTINGS TO CONFORM WITH METER.
POSITION 2. METER SET DIMENSIONS, LENGTH - DEPTH -
4 I HEIGHT 20" x 9" x 33".
2 3. ALCOVE DIMENSION. LENGTH - DEPTH- HEIGHT
BURY 21" x 14" x 39".
DO NOT
�i 4. CENTERLINE OF GAS SERVICE RISER TO BE 8"
ABOVE RED LINE FROM BUILDING.
5. TERMINATE TRACER WIRE BELOW THE METER
VALVE, USING HALF-HITCH KNOT. DO NOT TAPE
7 ico TRACER TO RISER.
8 N
ELEVATION SUPERSEDES A-35208 SHT 1, DATED 2-28-94
7"W.C. OR 1/4" PSIG A-35208 SHT 2. DATED 9-29-04
DELIVERY (CODE 1) DISTRIBUTION -GAS
STANDARD
GAS METER SETS, RESIDENTIAL
INTERMEDIATE PRESSURE GAS DIST. SYSTEMS
AVISTA CORP
SPOKANE, WASHINGTON
9 9-5-23 UPDATE METER VALVE TJH pRs NONE 11 9-15-04 Ro
8 8-24-22 UPDATE RISER STOCK NO TJH DRS TLB WB 9-29-04
7 10-10-19 UPDATE ITEM #6 CGD ARS DR JW Nro sm 1 DATE
NO DATE REVISION BY I CKD CKI) L$ nTO J'h of 1 A-35208
AUTOCAD DWG

MATERIAL LIST
QTY STOCK NO SIZE DESCRIPTION
1 MTR SHOP 20 LIGHT CLASS "A" METER
* 2 MTR SHOP )14" x 1" CLASS "B" REGULATOR W/2 PSI CAPABILITY
* 3 - 1" x 20LT U-BEND, GR A,THD. COATED
* 4 732-5464 4" x 6" NIPPLE, THD, SCH 40
5 770-8555 Y4" METER VALVE, INSULATED, THD, 100 PSIG. WITH BYPASS PORT
6 770-4936 1" SWIVEL, 20LT, GALVANIZED
7 770-6430 4" CORRUGATED PVC
8 770-7220 _" ANODELESS SERVICE RISER
9 1770-8515 1 20LT x 1 A-9 VALVE. FNPT INSULATED UNION OUTLET
�k ITEMS 2-4 ARE INCLUDED WITH
STOCK NUMBER 770-4932
BUILDING WALL'
1
co
TYPICAL
HOUSE
PLAN VIEW PIPING
11"
--m-I 9
3
i
2
CONSTRUCTION NOTES:
NO E: 6 1. PAINT FITTINGS TO CONFORM WITH METER.
INSTALL VENT cv 2. METER SET DIMENSIONS. LENGTH - DEPTH IN DOWNWARD HEIGHT 18" x 9" x 27".
POSITION 3. ALCOVE DIMENSION, LENGTH - DEPTH - HEIGHT
4 51 1 19' x 14" x 33".
DO NOT 4. CENTERLINE OF GAS SERVICE RISER TO BE 8"
BURY ABOVE 3"- 4" FROM BUILDING.
RED UNE 5. TERMINATE TRACER WIRE BELOW THE METER
VALVE, USING HALF-HITCH KNOT, DO NOT TAPE
TRACER TO RISER.
ELEVATION
SUPERSEDES A-35208 SHT 3. DATED 1-22-97
2 PSIG DELIVERY DISTRIBUTION -GAS
(CODE 4) STANDARD
GAS METER SETS,2 PSIG RESIDENTIAL
INTERMEDIATE PRESSURE GAS DIST SYSTEMS
Q AVISTA CORP
SPOKANE.WASHINGTON
Lp
0 8 9-5-23 UPDATE METER VALVE TJH QRS NDNE 10-20-09
"' 7 8-24-22 UPDATE RISER STOCK NO TJH pRs 5C1E ��
"' 0SN WEBB CKD aa U CrlO-21-09
6 10-10-19 REMOVE PETE'S PLUG DETAIL CGD FRS DR TJH NM SHT 1 DATE
rn
NO DATE REVISION BY CKD CKD NTD= Or A-37102
AUTOCAD DWG

MATERIAL LIST
NO SIZE DESCRIPTION OTY
3 REGULATOR, 1800 BODY, SET® 7" W.C.
1 /a"xi (DOMESTIC) 1
2 AS REO D THREAD PROTECTIVE CAPS 2
3 NIPPLE, PIPE, SCH 40, STANDARD WALL, 6 LONG
3 (DOMESTIC) 1
4 1" x 20LT U—BEND, GRADE A, THD, COATED 1
5 1 1" I NUT, METER SWIVEL, 20 LT 1
CONSTRUCTION NOTES:
1. UNIT TO BE FACTORY PREPARED AND POWDER COATED, OR
PAINTED WITH ONE ZINC—RICH PRIMER COAT AND TWO TOPCOATS
OF EPDXY PAINT GRAY IN COLOR.
2. UNIT TO BE PRESSURE TESTED TO 90 PSIG MINIMUM.
3. UNIT TO BE SHIPPED WITH THREAD PROTECTIVE CAPS INSTALLED.
4. ASSEMBLY SHALL BE PACKAGED AS ONE UNIT.
5. ITEMS 1-5 ARE INCLUDED WITH STOCK NUMBER 770-4932
4
�G REGULATOR BODY
DIMENSION MAY VARY T
i 5
3 2
NOTE:
INSTALL VENT
IN DOWNWARD
POSITION
2
SUPERSEDES A-35208 SHT 4, DATED 1 1-28-05
A-35208 SHT 5, DATED 1 1-28-05
DISTRIBUTION - GAS
STANDARD
GAS METER SETS, RESIDENTIAL
INTERMEDIATE PRESSURE GAS DIST. SYSTEMS
AVISTA CORP
SPOKANE, WASHINGTON
NONE 10-20-09 RO
2 8-26-15 STANDARDS UPDATE CGD SCALE I DATE
DSN WEBB CKD 10-21-09
1 8-6-14 MINOR CORRECTION JAJ DR TJH NTD SHT 1 DATE
NO BATE REVISION BY CKD CKD NTD� o� A-37103

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2.25 TELEMETRY DESIGN
SCOPE:
To establish a standard design for gas telemetry systems.
REGULATORY REQUIREMENTS:
§192.203, §192.741
NFPA 70: National Electrical Code (NEC), including Articles 500, 501, 504
OTHER REFERENCES:
AGA XL1001, Classification of Locations for Electrical installations in Gas Utility Areas
CORRESPONDING STANDARDS:
Spec. 2.22, Meter Design
Spec. 2.23, Regulator Design
Spec. 2.24, Meter& Regulator Tables & Drawings
Spec. 4.51, Gas Control Room Management Plan
DESIGN REQUIREMENTS:
General
Telemetry systems, including alarm set points, should be specified by Gas Engineering.
In general, telemetry is used to monitor system pressures, volumes, and flows from areas of special
interest such as gate stations, gas transportation customers, district regulator stations, selected large
industrial customers, and distribution systems with more than one source of gas.
Each distribution system supplied by more than one pressure regulating station must be equipped with
telemetry, an electronic pressure recorder, or a mechanical chart recorder to monitor the gas pressure.
Telemetry is preferred. Sites with telemetry should alarm for pressures that exceed the MAOP and for
pressures that fall below reasonable levels for reliable operation. For single-source distribution systems,
the applicable local Operations Manager in conjunction with Gas Engineering should determine the
necessity of installing telemetry or recording gauges, taking into consideration the number of customers
supplied, the operating pressures, the capacity of the installation, and other operating conditions that
might warrant the installation of monitoring devices.
Data Collected
Data collected generally includes metering pressure, gas temperature, corrected and uncorrected gas
volume, pressure upstream and downstream from regulation points, and odorizer alarms. The local
instrument, either an electronic corrector, electronic pressure recorder, or a programmable logic controller
(PLC)/remote terminal unit (RTU)/flow computer, calculates and transmits: corrected gas volume and
flow, and reports this information along with measured pressures and temperatures, high and low
pressure alarms, ambient or case temperature, instrument alarms such as pulse switches, tamper,
instrument main battery, memory battery, and communications battery voltage and alarms, high flow
alarms in selected cases, and alarm set points.
METERING & REGULATION REV. NO. 8
TELEMETRY DESIGN DATE 01/01/25
XvIST'r STANDARDS 1 OF 9
utilities NATURAL GAS SPEC. 2.25

Depending on the nature of the installation, data collected ranges from pulse accumulator volumes (from
a meter that has internal temperature compensation), to complete data (from meters with electronic
correctors)to pressure, flow, volume, and gas temperature.
Gate stations with flow computers/PLCs/RTUs should measure and report complete pressure,
temperature, volume, and flow data that is measured via transducers on upstream, metering, and
downstream piping. This may also include data such as corrected volumes, flows, and pressures from the
interstate pipeline companies, as obtained from their instruments at a gate station.
Data Path and Uses
Field data is collected with AutoSol Enterprise Service (AES) software, developed by Automation
Solutions, Inc. Avista's AutoSol server communicates with the field devices via a bank of conventional
analog telephone line modems (POTS, "plain old telephone service") and Internet Protocol (IP)
communications. New installations should be IP-based since the use of conventional land lines is being
phased out by Avista.
Field instruments collect and record hourly data, typically maintaining at least a 30-day history. The AES
server polls the field devices and downloads hourly summary data from the instruments. Polling ranges
from several times per day for older battery powered installations on Iandlines to once every 15 minutes
for selected AC powered devices.
The data collected by the AES server is placed on a network file share where SCADA, Nucleus, and PI
load it for multiple users including the Natural Gas Resources Department's use for daily nominations and
transactions with interstate pipeline companies and customers, and Gas Engineering.
Nucleus is the data warehouse and long-term repository for hourly billing data. This data is used to create
reports for both internal and external consumption. Some transportation customers receive daily and/or
monthly reports regarding usage at their site. The data in such reports is sent to customers as a
courtesy, not for billing purposes. It is considered to be"un-scrubbed" raw data and is provided on a best-
effort basis.
Data is also transferred from the AutoSol server to Avista's SCADA system for use by Gas Control. The
SCADA displays and information are also available to multiple users throughout Avista including Gas
Engineering, Pressure Controlmen, and Managers.
Data in SCADA is value reported at the time the field device was polled. SCADA's primary function is
alarming and reporting present readings with an option for a demand scan (forced polling) initiated by a
Gas Controller. Official billing hourly volume data is stored in Nucleus, not in PI or SCADA.
PI stores both instantaneous data and historical data. For Mercury/Honeywell instruments, additional data
in the audit trail for pressure history is periodically directly transferred several times daily to PI and
typically includes the maximum, average, and minimum pressures during the hourly interval, in addition to
the values at the time of polling. ABB TotalFlow flow computers also provide 1 minute trend files for
selected data. PI is accessible by multiple users within Avista. Historic gas volume hourly data is stored in
PI and Nucleus.
METERING & REGULATION REV. NO. 8
TELEMETRY DESIGN DATE 01/01/25
Xv sm a STANDARDS 2 OF 9
utilities NATURAL GAS SPEC. 2.25

EQUIPMENT CONFIGURATION:
Gate Stations
New and retrofitted measurement and telemetry installations at gate stations should utilize an ABB
TotalFlow flow computer/RTU.
Gate stations should be connected to receive uncorrected pulses from the interstate pipeline company's
turbine or rotary meter which is established as the sole billing meter. Avista's transducers for pressure
and temperature at the meter should be connected to Avista's RTUs and/or correctors and pressure
monitors so that Avista's equipment can provide our check correction. Additional pressures and
temperatures upstream and downstream of Avista-owned and operated gas heaters are also
recommended.
Orifice meters require direct measurement of differential pressure as well as static pressure as there are
no moving parts or sensors to provide a pulse.
Coriolis and ultrasonic meters generally require a pulse splitter to share their output with the interstate
pipeline and Avista as they measure mass flow directly and convert that signal to pulses that indicate the
flow rate. Avista's flow computer then converts the flow rate to volume and flow in our standard units of
MCF or CCF.
The instruments should calculate corrected volumes, flows, and alarms, and report this information along
with pressures, temperatures, internal instrument status, and alarms. AC power with battery backup is
required.
Where injection type odorizers (typically YZ brand) are owned and operated by Avista, the flow computer
should generate the control signal which is typically 4—20 mA based on the calculated flow rate.
Gas Transport and Telemetry Customers
Gas Transportation ("Transport")customers should have a Mercury/Honeywell Instruments Model Mini AT
PT or PPT or Mini Max electronic volume corrector installed with inputs from the meter for pulses (or by
mechanical coupling when mounted on the meter)and transducers for pressure and temperature. Rotary
meters with Dresser Micro PTZ correctors providing corrected pulse output may also be utilized
depending on the application. Additional pressure monitoring such as the pressure delivered to the
customer or upstream pressure if different than the metering pressure will be evaluated by Gas
Engineering on a site-specific basis.
Communications should be via a Mercury Instruments "MI Wireless" communications package with a
cellular modem and an AC power supply and rechargeable battery backup. The corrector should also
have an internal battery backup. Refer to"Transport Customers"within this specification for further detail.
Regulator Sites and System Pressure Monitoring
Regulator station sites and other pressure monitoring points selected for telemetry installations should
have a Mercury Instruments model "ERV electronic pressure recorder in a common enclosure from the
manufacturer that includes the MI Wireless communications package, power supply, rechargeable
communications battery, and 6-volt battery backup independent of the communications battery. AC power
supply is preferred. Solar may be used with Gas Engineering's approval on a site-specific basis. Both
upstream and downstream pressures should be monitored with the instrument located nearest to the
high-pressure side to minimize sense line tubing length for the highest-pressure line.
METERING & REGULATION REV. NO. 8
TELEMETRY DESIGN DATE 01/01/25
Xv sm a STANDARDS 3 OF 9
utilities NATURAL GAS SPEC. 2.25

Power Plants
Power plants requirements are site specific. Gas Engineering should be involved early in the planning
and design process. An ABB TotalFlow flow computer is preferred. A Mercury/ Honeywell instruments
Mini AT-PT may be acceptable. Instruments should have an AC power supply, rechargeable battery
backup, memory backup battery independent of the communications battery, and IP based
communications.
Table for detailed reference to quantities measured:
Site Quantities Measured (Inputs/Outputs)
Pulses for volume, uncorrected from the interstate pipeline company's meter.
Pulses for volume, corrected from the interstate pipeline company's meter or PLC when
we do not calculate our own volume.
Flow rate, corrected,from the interstate pipeline company's PLC or flow computer when
we do not calculate our own flow rate.
Pressure at each meter.
Differential pressure at orifice meters.
Pressure to Avista HP, IP, and distribution systems.
Pressure in the pipelines' upstream line.
Gate Stations Gas temperature at each meter.
Gas temperature upstream and downstream of Avista owned gas heaters.
Ambient air temperature.
Alarm contacts from the odorizer's common alarm when used.
Alarms such as security,tamper,valve position, interstate pipeline company, etc. when
available.
AC Power failure or battery charger failure.
Communications battery voltage.
Output: Analog output to odorizer, 4-20 mA signal based on flow, preferably from Avista's
flow computer. Avista may use a 4-20 mA signal from the pipelines'flow computer until
we have our own.
Pressure upstream of the regulator(s).
Regulator Stations Pressure downstream of the regulator(s).
Communications battery voltage.
Pressure at meter.
Gas Transportation
Gas temperature at meter.
Customers Pulses from meter either by mechanical coupling, pulser, or pulses, depending on meter.
Downstream or customer pressure, or upstream pressure, depending on metering
configuration, and location on system.
Notes:Instruments calculate corrected volume, corrected flow rates, and alarms based on the inputs and
programming. There are internal measurements that the instruments also provide such as case temperature, main
battery voltage, and index switch fail, which we also utilize.
Some equipment at some transport customers may not support telemetering of pressure and temperature such as
when utilizing pulses from a fixed factor or temperature compensated meter or from a corrector(e.g., Dresser micro
PTZ) that does not support communications directly with Auto Sol.
METERING & REGULATION REV. NO. 8
TELEMETRY DESIGN DATE 01/01/25
Xv sm a STANDARDS 4 OF 9
utilities NATURAL GAS SPEC. 2.25

Communications
Internet Protocol (IP) based communications is the preferred choice.
• Sierra Wireless RV50, Raven XT, or XE cellular gateway for packet switched data on the Verizon
or AT&T cellular networks for communicating via IP wirelessly. For non-flow computer
installations, a Mercury Instruments MI Wireless communications box with a port server may be
used for up to four Mercury devices.
• Avista Ethernet, (wireless when available) as part of"smart grid" projects or near an electric
substation or other facility where Avista has Ethernet.
• Land line telephone lines (POTS) and dial-up modems are the last choice for new installations
due to slow speed and long scan times by the AutoSol modem bank.
• Priorities
• New installations
• Gate stations
• Pressure monitoring stations.
• Transportation customers
Power Source
AC Line power with self-contained rechargeable battery backup is preferred. Solar voltaic power or
thermoelectric utilizing gas for fuel may be considered for certain locations with Gas Engineering's
approval, depending on the location, data being acquired and its purpose, and the economics of providing
AC power to the site.
Electrical Classification
Outdoor area classification for electrical installations are based on:
• NFPA 70/ National Electrical Code (NEC)with particular attention to Articles 500, 501, 504
relating to Hazardous (Classified Locations, primarily with respect to Class I, Divisions 1 and 2.
• American Gas Association (AGA)XL1001, Classification of Locations for Electrical Installations in
Gas Utility Areas.
• Areas within 5 feet of or directly above any relief valves or automatic vents will be treated as
Class I Division 1 (likely to have gas present during normal operation).
• Areas within 15 feet of any flanges, screwed connection, valves, relief valves, or vents will be
treated as Class I Division 2 (likely to have gas present only during abnormal operation).
• Underground (buried)flanges, screwed connections, or valves create a class I Division 2 area
above the ground.
• Electrical equipment should not be installed in the direct path of discharge from vents or relief
valves.
• Areas including pipe without valves, flanges, or screwed connections are considered non-
hazardous (ordinary) areas.
• Electronic correctors mounted on meters with or without telemetry must comply with the
applicable version of the NEC, Articles 500, 501, and 504 for Hazardous (classified) Locations.
Sensing Lines
• Small underground piping at Avista's installations is discouraged. It is preferred to use pressure
transducers tapped from the main piping and route the signal cables in conduit to the RTU or
communication box.
• Correctors and pressure recorders utilizing integral pressure transducers should be mounted as
close to the meter or piping as practical to minimize the use of small diameter exposed tubing.
METERING & REGULATION REV. NO. 8
TELEMETRY DESIGN DATE 01/01/25
Xv sm a STANDARDS 5 OF 9
utilities NATURAL GAS SPEC. 2.25

• Each sensing line should have a unique tap with 1/4-inch NPT female pipe threads for connection
to sense line tubing adaptor.
• A shutoff valve must be installed in each takeoff line as near as practical to the point of takeoff.
No taps off bottom of piping.
• Sensing lines should be located in the piping system to sense line pressures at a point of non-
turbulent laminar flow. This generally is achieved by placing sensing taps a minimum of 10 pipe
diameters downstream of any valves, regulators, or fittings. Sense line taps are typically located
with the taps for the associated regulator sense lines.
• Site specific consideration should be given to adjusting the pressure sensing location to allow for
maintenance of the tap without shutting down a single sourced system. Location of bypass
regulators and manual bypasses should also be considered.
• Each takeoff connection and attaching fitting or adapter must be made of suitable material, be
able to withstand the maximum service pressure and temperature of the pipe or equipment to
which it is attached and be designed to satisfactorily withstand all stresses without failure by
fatigue.
• Isolation valves and tees supplied by Mercury Instruments in their installation kit or similar fittings
procured separately should be used along with fittings to allow for calibration and a Ralston
"check valve type Quick Test"fitting or similar approved fitting.
• Sensing lines should be 3/8-inch OD stainless steel tubing for mechanical strength except in the
case of extremely short runs where the corrector or recorder is at the tap location such as on the
meter.
• Fittings at the instrument connections should use dielectric insulators for electrical isolation from
the gas piping and cathodic protection system.
• Sensing lines should be routed and secured above grade to provide protection from anticipated
causes of damage.
• Valve handles should be removed or locked to prevent unauthorized operation.
Pulses to Customer
Avista may, upon customer request, provide metering pulses as described below for connection to an
input to the customer's energy management system or to a remote totalizer.
The costs for these custom installations will be billed to the customer on a time and materials
basis.
Customer connection and general information regarding pulses:
• The transistors or reed switches that provide output pulses from Avista's metering installations
are designed for low voltage and low current control signal applications such as interfacing with
electronic energy management systems. Ratings are listed below. They are not for controlling
relays, solenoids, or lights.
• Manual local electrical isolation disconnect from the customers wiring should be provided by
installation of a weatherproof MIL style connector set supplied and installed by Avista in series
with the wiring from the customer near the meter. This is to protect Avista personnel working on
metering from inadvertent voltages that could be present on the wiring from the customer and
serve as a demarcation point.
• The customer is responsible for installation of conduit and wiring in accordance with requirements
outlined by Gas Engineering and communicated by Avista's Metermen or Telemetry Technicians.
• Avista will make the connection to the meter's corrector or pulser.
METERING & REGULATION REV. NO. 8
TELEMETRY DESIGN DATE 01/01/25
Xv sm a STANDARDS 6 OF 9
utilities NATURAL GAS SPEC. 2.25

• Meters without electronic volume correctors:
o Pulses should be provided by adding a magnetic volume pulser between the wiggler
shaft and the mechanical index or replace the index with a combination index/pulser
consisting of a commercially available reed switch and magnet unit that may provide 1, 2,
4, or 10 pulses per revolution.
o The reed switch is rated for low voltage and current, typical for an electronic input.
o These are dry contacts. The wetting voltage will be provided by the customer's energy
management system.
o Typical reed switch ratings are 30 VDC/21 VAC, 0.025 amps maximum.
o Acceptable pulsers include Miners & Pisani # MVP-10 and MVP-1; Honeywell/ Mercury
Instruments#206, 210, or 212; Miners and Pisani / Elster/American Meter#RVP-F1
52870K161, depending on the application.
o Avista provides and installs the above pulsers and bills the customer.
• Meters with electronic gas volume correctors:
o Corrected or uncorrected pulses, as determined by the customer's need and Avista's
metering capabilities, should be provided from the electronic corrector's isolated pulse
output.
o The pulse output is typically an open-collector transistor rated for low voltage and current
and is polarity sensitive: 3VDC min—30 VDC max (DC only), sinking up to 0.015 amps
for form C outputs and 0.005 A for Form A outputs. The wetting voltage will be provided
by the customer's energy management system.
o Avista provides and installs any additional components that may be required to obtain the
isolated pulse output and bills the customer.
• Remote Volume Totalizers/Counters: Avista may furnish remote totalizers to make use of
metering or corrector pulses to actuate a remote volume index for the customer. Costs are billed
to the customer.
• Avista will define the volume of gas that each pulse represents. Avista will also define if it is an
uncorrected reading (index or raw value and if it is temperature compensated) or a "corrected for
temperature and pressure" value from an electronic gas volume corrector.
• Disclaimer: Pulses and reports furnished to the customer are not for billing purposes. They are
local raw data and informational only. Future delivery and/or replacement data is not guaranteed.
Avista makes no other representations or warranties concerning the pulses or data and there are
no express warranties and no implied warranties pertaining to the data including, but not limited
to, any warranty of merchantability or fitness for a particular purpose, all of which are hereby
expressly disclaimed.
Transport Customers
Gas Transportation Customers: Refer to Drawing E-37114 Sheet 1, Gas Telemetry Standards, Gas
Transportation Customer. The drawing is located at the end of this specification for typical installation
details.
1. Avista procures the following on the customer's behalf and bills the customer:
a. Meter upgrades, when required, to provide metering suitable for gas transportation and
telemetry.
b. Corrector that meets current Avista requirements for gas telemetry for mounting on or
near the gas meter.
c. Wireless cellular packet switched data communications assembly and antenna that
mount near the meter or on existing structures.
d. Associated wiring and hardware to connect the individual components.
e. Avista procures and installs the above items. The customer is billed for the loaded costs
for materials, labor, travel, installation, engineering, and technical work related to
integration into Avista's telemetry system.
METERING & REGULATION REV. NO. 8
TELEMETRY DESIGN DATE 01/01/25
Xv sm a STANDARDS 7 OF 9
utilities NATURAL GAS SPEC. 2.25

2. Customer provides:
a. AC power including installation: 120 V, single phase, 15 or 20 amp dedicated or high
reliability circuit for powering the telemetry instruments which consume minimal power.
This includes all conduit, conductors, excavation, backfill, permits, and installation to get
power to the device. Avista makes the final connection at the device.
b. Conduit for communications and low voltage power between the corrector and the
communications assembly when both are not mounted adjacent to the meter and each
other. For example, if the communications box is on a wall rather than post mounted at
the meter.
c. The installation shall comply with state and local electrical codes, rules, and regulations.
Note that typically areas within 15 feet of gas piping flanges, screwed connections,
valves, reliefs, or vents are considered hazardous (classified) locations and have special
requirements. Installation of the over-current protection and disconnecting means is
required to be in an ordinary (non-hazardous) area. Refer to Electrical Classification
within this specification for additional details.
d. If a wireless or cellular radio or modem is not practical such as when there is no reliable
coverage, the customer must provide or continue to provide, at their expense, as is
standard practice for existing customers:
i. Dedicated standard voice grade telephone line with direct dialing in and out
including long distance direct dial service that is available continuously.
ii. Installation of Avista provided signal circuit protector for the phone line including
grounding.
iii. Installation of telephone cable to protector and to the penetration at the wall with
enough extra cable for Avista to terminate.
iv. Dedicated galvanized rigid steel conduit for telephone line including installation
from customer's wall penetration and interior junction box to the vicinity of
Avista's corrector at the meter. This includes all penetrations, supports, clamps,
anchors, sealants, etc.
v. If the telephone signal circuit protector is mounted outdoors, a locking box and
ground rod are required.
3. Avista provides:
a. Avista establishes, maintains, and pays for the cellular data account.
b. The cellular account must bean Avista account with the carrier for many reasons
including communications protocol, network security, and account access for service,
troubleshooting, and standardization.
4. Notification and Timing:
a. Avista's Gas Engineering requires 90 days minimum notice from the date Avista receives
"written notice"from the customer advising of their intent to sign a "Transportation
Services Agreement". This allows time to design, procure, install, test, and integrate the
field devices into the Gas Telemetry System.
b. Advice of this notice should be via e-mail either from the Natural Gas Resources
Manager or the Account Executive to both the Manager of Gas Engineering and to the
Gas Measurement Engineer.
METERING & REGULATION REV. NO. 8
TELEMETRY DESIGN DATE 01/01/25
Xv sm a STANDARDS 8 OF 9
utilities NATURAL GAS SPEC. 2.25

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METERING & REGULATION REV. NO. 8
TELEMETRY DESIGN DATE 01/01/25
��rrsra STANDARDS 9 OF 9
Utilities NATURAL GAS SPEC. 2.25

2.3 CATHODIC PROTECTION
2.32 CATHODIC PROTECTION DESIGN
SCOPE:
To establish uniform procedures for the protection of metallic pipelines from external, internal, and
atmospheric corrosion.
REGULATORY REQUIREMENTS:
§192.451, §192.452, §192.453, §192.455, §192.457, §192.459, §192.461, §192.463, §192.465,
§192.467, §192.469, §192.471, §192.473, §192.45, §192.476, §192.477, §192.479, §192.481, §192.483,
§192.485, §192.489, §192.490, §192.491
WAC 173-160-456, 480-93-110
CORRESPONDING STANDARDS:
Spec. 2.12, Pipe Design - Steel
Spec. 2.13, Pipe Design - Plastic
Spec. 2.14, Valve Design
Spec. 2.15, Bridge Design
Spec. 3.12, Pipe Installation— Steel
Spec. 3.42, Casing and Conduit Installation
THEORY OF CORROSION:
AC vs. DC
Electrical current is classified as either alternating (AC)or direct (DC). Alternating current reverses its
direction of flow many times each second. Direct current is line-directional in nature or flows in one
direction only.
In order to measure corrosion current, to determine cathodic protection current requirements, and to
verify the adequacy of protection equipment installed, it is necessary to make measurements of DC
current.
Corrosion Cell
Corrosion of a metal will only occur if all the following four items are present: an anode, a cathode, an
electrolyte, and an electrical connection between the anode and cathode. When all of these are present,
we have a corrosion cell.
Corrosion or deterioration of the metal takes place at the anode where metal ions enter solution. When
steel corrodes or oxidizes, the iron atom loses two electrons (e-) and the iron ion (Fe++)enters the
electrolyte. The initial reaction produces a corrosion product, ferrous hydroxide, which is usually white in
color. This product is often unstable and will combine further with available oxygen and water. The stable
product formed is ferric hydroxide and it exhibits a characteristic brown or rust color.
CATHODIC PROTECTION REV. NO. 17
CATHODIC PROTECTION DESIGN DATE 01/01/25
X-4, sr'a STANDARDS 1 OF 7
Utilities NATURAL GAS SPEC. 2.32

Anode and Cathode Reactions
Anode Reaction:
Fe++ + 20H —> Fe(OH)2 Unstable Ferrous Hydroxide (White)
4Fe(OH)2 + Oz + 2H20 —> 4Fe(OH)3 Ferric Hydroxide or Rust
Cathode Reaction:
2H+ + 2e-—> Hz Hydrogen Gas
4H+ + 4e- + Oz—> 2H20 Water
An associated, simultaneous reaction occurs at the cathode and combines hydrogen ions (H+)with
electrons (e-), which have been released from the anode, to form hydrogen atoms (H). This hydrogen
then plates out on the cathode, combines with oxygen to form water, or combines with other hydrogen
atoms and evolves off as molecules of gas (1-12).
The formation of hydrogen on the cathode and oxide on the anode, polarization, tends to retard the
corrosion rate. A chemical or mechanical process that removes either the protective hydrogen or oxide
films will allow corrosion to continue.
The corrosion rate of the anode is directly proportional to the current density or current flow from the
anode. Therefore, anything that can be done to stop or reduce this current flow will in turn stop or reduce
corrosion. Corrosion and corresponding corrosion control are based on this principle. The basic means of
corrosion control is primarily an effective coating installation, followed by the removal of either anode or
cathode, breaking the electrical connection between anode and cathode, removing the electrolyte, or
increasing its electrical resistance, and the application of a counter protective current.
Anode-Cathode Area Ratio
The corrosion or penetration rate is also a function of the anode-cathode area ratios as follows (assuming
a corrosion cell exists):
Cathode Area
Corrosion Rate =
Anode Area
This relationship means simply that if a large cathode is connected to a small anode, the corrosion rate
can be very severe. If the ratios are reversed, that is, a large anode connected to a small cathode, then
the corrosion rate can be drastically reduced and, in many instances, will become negligible.
If perfect coatings could be applied to the anode or cathode, they would be electrically insulated from the
electrolyte and all corrosion would stop. Since coatings are never perfect, coating the anode only will
cause accelerated pitting where there are coating holidays due to the change in anode-cathode area
ratios. Coating the cathode instead of the anode will more effectively reduce the corrosion rate without the
danger of localized pitting. For practical reasons, since anodes and cathodes are not readily
distinguishable on pipelines, both are given a coating.
Regardless of what metal is involved in a corrosion cell, the reaction at the anode and cathode is
basically the same. The anode and cathode reactions occur simultaneously and cannot occur separately.
CATHODIC PROTECTION REV. NO. 17
CATHODIC PROTECTION DESIGN DATE 01/01/25
X-4,15y' a STANDARDS 2 OF 7
Utilities NATURAL GAS SPEC. 2.32

Electrolyte Resistivity
The magnitude of the corrosion current flowing between any anode and cathode is also dependent on the
electrolyte resistance or resistivity. The greater the electrolyte resistivity the smaller the current flow, and
conversely, the lower the resistivity the greater the magnitude of corrosion current.
Soil resistivity is sometimes classified as follows:
Resistivity(Ohm-cm) Classification
0-1,000 Very Corrosive
1,000-10,000 Moderately Corrosive
10,000-Over Slightly Corrosive
Corrosion classification of soils represents, in a very general way, a means of predicting areas in which
corrosion of metals may become a problem. It is not proper to say that serious corrosion will occur
because a specific resistivity is less than 500 ohm-cm or that corrosion will not occur because resistivities
are above 10,000 ohm-cm. The corrosion classification of soils is still a useful tool to generally define
corrosive areas if used within limits as a general guide to provide for better corrosion judgment.
Anode-Cathode Separation Distance
It is important to note that separation between anode and cathode exists more often than not on the same
piece of pipe. The anode and cathode can be microscopically close or thousands of feet apart.
Anodes and cathodes are formed when metals are placed in dissimilar soils or electrolytes. These
dissimilarities can be dissolved salts, moisture, temperature, or oxygen concentrations. Anodic areas will
usually be in areas of greatest salt concentration, greatest moisture content, highest temperature, and
lowest oxygen concentration. Oxygen concentration cells are common at mechanical junctions, in
crevices, and under foreign deposits.
Dissimilar Metals
One of the most common types of corrosion is that caused by the junctions of two or more dissimilar
metals. In cases where dissimilar metals are coupled together, one metal will corrode (anode) and have
metal ions enter solution (electrolyte) and travel to the other metal (cathode). Metals are ranked by their
tendency to corrode to each other in the following table known as the Galvanic Series.
Stainless steel and chromium are listed in two places in the series as both active and passive. When
these metals are in an oxygen-starved environment, they have a greater tendency to corrode and are
therefore placed higher in the series. When in a solution containing adequate or excess oxygen, stainless
steel, and chromium are passive and are listed correspondingly toward the cathodic or protected end of
the series.
CATHODIC PROTECTION REV. NO. 17
CATHODIC PROTECTION DESIGN DATE 01/01/25
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Utilities NATURAL GAS SPEC. 2.32

The Galvanic Series
MAGNESIUM Anode-Corroding End,
ALUMINUM Least Noble, Electro-
ZINC Negative
CADMIUM
STEEL OR IRON
CAST IRON
CHROMIUM (ACTIVE)
STAINLESS STEEL(ACTIVE)
SOFT SOLDER
TIN
LEAD
NICKEL
BRASS
BRONZE
COPPER
SILVER SOLDER
CHROMIUM (PASSIVE)
STAINLESS STEEL(PASSIVE)
Cathode-Protected SILVER
End, Most Noble, GRAPHITE
Electro-Positive GOLD
PLATINUM
Stress Corrosion
Metals that have been stressed due to cold working, such as bending, threading, or riveting, will be
affected by corrosion. The stressed area will normally be anodic to the adjacent non-stressed section.
CONTROLLING CORROSION
Direct current discharges from metal to the soil at all locations where corrosion occurs underground.
Corrosion does not take place when current flows from soil to the pipe. One useful way of controlling
corrosion is to stop the discharge current flow.
Insulation
Dissimilar metals in galvanic corrosion cells can be separated electrically by using insulated or dielectric
fittings. The pipe itself can be insulated electrically from the soil electrolyte with the application of a
nonconductive coating.
Metallic Coatings
Conductive or metallic coatings such as zinc coating or galvanized coatings are applied to base metal
materials. Some of these applications are used underground but are usually more effective to combat
atmospheric corrosion problems. When used underground the coated metal is protected by the
preferential corrosion (galvanic series) of the metallic coating applied. The duration of protection is based
on the thickness and uniformity of the coating applied, the difference in potential between the two metals
(galvanic series), the soil resistivity, and at times the chemical composition of the soil.
CATHODIC PROTECTION REV. NO. 17
CATHODIC PROTECTION DESIGN DATE 01/01/25
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Utilities NATURAL GAS SPEC. 2.32

Nonmetallic Materials
Plastic pipe (polyethylene) should be used where applicable. Plastic pipe is preferred for installations in
intermediate pressure systems as it eliminates corrosion losses.
Change in Environment
Often the environment can be adjusted or altered to control or eliminate the presence of electrolytes.
Select backfill can be used which provides drainage around the pipe and assures that sharp rocks do not
damage pipe coatings. The ends of casings and conduits are sealed to assure that moisture is kept away
from the pipe. Refer to Specification 3.42, Casing and Conduit Installation.
Allowances can be made in system designs to lessen velocities, cavitation, and pulsations that might
break down protective films or oxides on the inside walls of pipes.
Cathodic Protection
It is not economically feasible to design, apply, install, and maintain a coating that will completely insulate
metal pipe from the soil electrolyte. Instead, the protection provided by an economical pipe coating is
supplemented with the application of cathodic protection, an electromechanical method that forces the
metal to become cathodic to its environment.
Galvanic System
Cathodic protection is applied galvanically by utilizing metals higher on the galvanic series such as zinc
and magnesium and bonding them to the steel pipeline via a coated conductor. By causing metals higher
on the series to become metallically part of the piping system, we cause these metals (sacrificial anodes)
to corrode and afford protection to the steel pipeline. This application is usually limited to well-coated lines
in lower soil resistivities.
Impressed Current System
In areas where current requirements are higher, impressed current protection systems be used. These
systems normally utilize a rectifier which changes alternating current(AC)to direct current(DC)which
then is caused to flow into the soil through an anode and ultimately to flow onto the pipeline thereby
canceling all undesired corrosion current.
DESIGN AND INSTALLATION:
General
Newly installed metallic pipeline facilities must be installed with an Avista-approved coating that meets the
requirements of§192.461 and must be cathodically protected within one year after installation. Refer to
Specification 2.12, Pipe Design— Steel, "Pipe Systems Corrosion Protection"for specific coating
requirements.
WAC 480-93-110: The state of Washington requires that new pipeline facilities must be protected
within 90 days after installation.
CATHODIC PROTECTION REV. NO. 17
CATHODIC PROTECTION DESIGN DATE 01/01/25
X-4, sr'a STANDARDS 5 OF 7
Utilities NATURAL GAS SPEC. 2.32

The design, operation, installation, and maintenance of cathodic protection systems shall be carried out
under the direction of a person qualified in pipeline corrosion control methods. Additionally, CP Deep Well
design shall be done by a registered Professional Engineer if installed in Washington State (ideally NACE
Level 4) and as a best management practice, such designs should be completed by a Registered PE in
other Avista jurisdictions.
WAC 173-160-456 (2): Grounding wells shall be designed by an engineer, licensed in Washington
State, trained in the design of corrosion protection wells.
Consult with a Cathodic Protection Technician before tying together or separating cathodic protection
zones. Zones could be connected by adding steel main between other areas of steel main, or by
connecting cathodic wires found at valves, regulator stations, and other sites. Zones could be separated
when steel pipe is cut off and abandoned or through the separation or severing of cathodic wires found
above or below ground.
Generally, new, and existing metallic piping systems are cathodically protected by Impressed Current
Systems.
Anode Systems
Impressed Anode System Installation: Installation of an impressed current anode should be done with
respect to remote earth. A good standard distance is 150 to 200 feet from the pipe. Anodes should be
separated a minimum of 20 feet from a surface or traditional system. For a deep well, the top anode
should be a minimum of 150 feet from the piping.
Galvanic Anode System Installation: Install galvanic anodes 3 to 5 feet from the pipe. Use a test
station to connect the anode to the pipe. Two white lead wires should be installed on the pipe during the
installation.
AC Mitigation
It may be necessary to provide AC mitigation systems on piping, which is closely parallel to or in close
proximity to electrical transmission facilities or in areas where fault currents or unusual risk of lightning
may be anticipated. A qualified Cathodic Protection Technician should review and recommend a design
for AC mitigation. A mitigation system may include the following:
• Voltage gradient control mats at test stations, valves, and other pipeline appurtenances for
personnel safety.
• Polarization cells connected between the pipeline and an AC ground such as a bare steel casing.
These cells have a high resistance to DC and low resistance to AC.
• Periodic placement of zinc anodes for protection of the pipeline during phase—to-ground faults.
In certain situations, paralleling the pipeline with zinc ribbon anodes may be recommended.
Test Leads
Test leads should be installed as discussed in Specification 3.12, Test Leads.
Tracer Wire
Insulated #12 solid coated locating wire installed with polyethylene pipe should be cathodically protected
by installing a 4-1/2 lb. zinc anode approximately every 1,000 feet. Refer to Specification 3.13, Installation
CATHODIC PROTECTION REV. NO. 17
CATHODIC PROTECTION DESIGN DATE 01/01/25
X-4, sr'a STANDARDS 6 OF 7
Utilities NATURAL GAS SPEC. 2.32

— Plastic Mains. Refer to Drawing A-36277, Wire Connections at the end of Specification 3.13, Installation
— Plastic Mains.
System Isolation
Cathodic protection systems are to be designed and operated to minimize adverse effects on adjacent
underground metallic structures.
Where stray currents from foreign cathodic protection systems are affecting Avista lines, corrective
measures are to be taken to limit/eliminate the stray current condition.
Each pipeline must be electrically isolated from other underground metallic structures, unless the pipeline
and the other structure are electrically interconnected and cathodically protected as a single unit. Care
must be taken to assure that steel components within plastic pipe systems are not isolated unless it is
planned to protect the steel as a single unit. Often it is desirable to utilize locating wire to provide cathodic
protection to isolated steel components within the plastic pipe system (contact Gas Engineering in such
cases as heavier gauge wire may be required). Wire connections to steel main or steel fittings shall be
made by the "Cadweld" process. Refer to Specification 3.12, Cadweld Procedure.
Approved insulating devices must be installed where electrical isolation of a portion of a pipeline is
necessary to facilitate the application of cathodic protection.
Each metallic pipeline must be electrically isolated from metallic casings. If isolation is not achieved
because it is impractical, other measures must be taken to minimize corrosion of the pipeline.
Insulating devices may not be installed where a combustible atmosphere is anticipated unless
precautions are taken to prevent arcing.
Replacing Steel Main
When replacing steel pipe (main)of any length, consult a Cathodic Protection Technician prior to
considering conversion to polyethylene plastic (PE) pipe. Isolation of steel services and sections of steel
main is a critical consideration and shall not occur without the permission of Gas Engineering.
The true replacement cost should be considered when replacing steel with PE. Such analysis should
consider both the cost to replace in-kind with new steel (thereby preserving cathodic protection continuity)
and the cost of replacing with PE (to include replacement of any steel services that will be isolated in the
process and any related cathodic protection work needing to be done).
Replacing Steel Services
When replacing steel services of any length, consult a Cathodic Protection Technician prior to considering
conversion to polyethylene (PE) plastic pipe.
The conversion to polyethylene (PE) plastic services should be the full length from the main to the meter
for the betterment of the gas system to prevent isolated steel locations and disbonded dresser fittings.
Refer to Specification 3.16, Services, "Steel Service Replacement"for further guidance.
CATHODIC PROTECTION REV. NO. 17
CATHODIC PROTECTION DESIGN DATE 01/01/25
X-4,15y' a STANDARDS 7 OF 7
Utilities NATURAL GAS SPEC. 2.32

2.4 VAULTS
2.42 VAULT DESIGN
SCOPE:
To establish a uniform procedure for designing vaults for regulator stations and valve assemblies.
REGULATORY REQUIREMENTS:
§192.183, §192.185, §192.187, §192.189
OTHER REFERENCES:
NEC Article 500
Standard Highway H-20 loading requirements
CORRESPONDING STANDARDS:
Spec. 5.18, Vault Maintenance
DESIGN REQUIREMENTS:
General
The use of vaults for valves or regulating stations should be avoided whenever possible. The confined
spaces created by vaults can accumulate gas, restrict available room to maintain equipment, and are
difficult to keep dry. Regulator stations should be constructed aboveground whenever possible.
Vaults shall be located in an accessible location that is away from street intersections or points where
traffic is heavy. They shall not be located in close proximity to water, steam, electric, or other facilities.
Points of minimum elevation, catch basins, or places where the access cover will be in the course of
surface waters should also be avoided when determining the location of a vault.
Each underground vault must be able to meet the loads which may be applied on it while protecting the
equipment inside. Generally, vaults installed in traveled roadways must be designed to meet Standard
Highway H-20 loading requirements.
Enough room must be provided within the vault to enable proper installation and maintenance of the
equipment.
Each pipe entering or within a regulator vault or pit must be steel, except instrumentation and control
lines, which can be copper. Where pipe extends through the vault structure, provisions must be made to
prevent the passage of gases or liquids through the opening, and to avert strain in the pipe. Polyethylene
piping may not be used inside a vault.
VAULTS REV. NO. 6
VAULT DESIGN DATE 01/01/24
XvIST'r STANDARDS 1 OF 2
utilities NATURAL GAS SPEC. 2.42

Sealing and Ventilation
Each underground vault or closed top pit containing either a pressure regulating, or relieving station must
be sealed, vented, or ventilated as follows:
• When the volume exceeds 200 cubic feet, the vault or pit must be ventilated with two ducts (one
at bottom and one at top of structure), each having at least the ventilating effect of a pipe 4 inches
in diameter and vents shall be positioned high enough above grade to disperse gas air mixtures
that might be discharged. Ventilation must be enough to minimize the ability of a combustible
atmosphere to develop within the vault
• When the volume exceeds 75 cubic feet, but is less than 200 cubic feet and the vault or pit is
sealed, each opening must have a tight fitting cover, free of openings through which an explosive
mixture might be ignited, and there must be a means for testing the internal atmosphere before
removing the cover.
• When the volume exceeds 75 cubic feet but is less than 200 cubic feet and the vault or pit is
vented, the venting shall be designed to prevent external sources of ignition from reaching the
vault atmosphere. Vents shall be directed away from potential sources of ignition.
• When the volume exceeds 75 cubic feet, but is less than 200 cubic feet and the vault or pit is
ventilated, the ventilation shall be designed to conform to the requirements described for vaults
with volumes in excess of 200 cubic feet unless the vault or pit is to be ventilated by openings in
grates or covers and the ratio of internal volume (cubic feet)to the effective ventilating area (sq.
in.) of the grate or cover is less than 20:1 in which case no additional ventilation is required.
• When the volume is less than 75 cubic feet, no ventilation is required.
Drainage
Each vault must be designed so as to minimize the entrance of water.
A vault containing gas piping may not be connected by means of a drain connection to other underground
structures.
Electrical Code
Electrical equipment in vaults must conform to the applicable requirements of the National Electric Code
(NEC)Article 500 for Hazardous (classified) Locations.
VAULTS REV. NO. 6
VAULT DESIGN DATE 01/01/24
XvISTA STANDARDS 2 OF 2
utilities NATURAL GAS SPEC. 2.42

2.5 ODORIZATION
2.52 ODORIZATION OF NATURAL GAS
SCOPE:
To establish uniform procedures for odorizing natural gas.
REGULATORY REQUIREMENTS:
§192.625
CORRESPONDING STANDARDS:
Spec. 4.18, Odorization Procedures
Spec. 5.23, Odorization Equipment Maintenance
ODORIZATION:
General
Natural gas in its natural state is odorless. A distinctive odorant is mixed with natural gas enabling it to be
detected by a person with a normal sense of smell at concentrations well below that which would allow
the natural gas to ignite.
Natural gas supplied to customers will be odorized. Natural gas will generally be odorized at or near the
gate station except where such gas is adequately odorized as received from the interstate pipeline
company.
Odorant Type
Only odorants approved by Gas Engineering shall be used to odorize gas distributed by Avista. Avista
utilizes an odorant mixture comprised of 80 percent by weight tert-butyl mercaptan and 20 percent methyl
ethyl sulfide.
In the concentrations in which it is used, the odorant in combustible gases must comply with the following:
• The odorant may not be harmful to persons, materials, or pipe.
• The products of combustion from the odorant may not be toxic when breathed nor may they be
corrosive or harmful to those materials to which the products of combustion will be exposed.
• The odorant may not be soluble in water to an extent greater than 2.5 parts to 100 parts by
weight.
ODORIZATION REV. NO. 7
ODORIZATION OF NATURAL GAS DATE 01/01/25
XvIST'r STANDARDS 1 OF 2
utilities NATURAL GAS SPEC. 2.52

Odorizer Types
Equipment for odorization must introduce the odorant without wide variations in the level of odorant.
Three different types of odorizers are used to transfer odorant into the gas stream.
Wick Odorizer-This odorizer is used for small flow applications (up to approximately 500 SCFH). It
consists of a small one pint to 3-quart bottle that is fastened in-line with the gas flow. A wick extends from
the bottle into the gas flow and odorant is transferred from the bottle to the gas via the wick. This type of
odorizer is often referred to as a "domestic" odorizer.
Bypass Odorizer-This odorizer is used for the majority of odorization applications (up to approximately
4,000,000 SCFH). A very small portion of the total volume of natural gas to be odorized is bypassed
through the odorizing unit where it is saturated with odorant vapor. The saturated gas is then reintroduced
and mixed with the gas passing through the gas main. In the process of passing through the odorizing
unit, the bypassed gas absorbs many times the amount of odorant required to provide the desired odor
intensity, therefore only a relatively small volume of saturated gas needs to be mixed with the main gas
stream. Gas is bypassed or drawn through the unit by a differential pressure created by placing a
restriction in the gas line. The volume of bypassed gas can be fine-tuned with a restrictor valve.
Infection Odorizer-This odorizer is used for high volume applications and in locations where telemetry
is available on site. Liquid odorant is injected by a pump or other mechanical means into the pipe where it
is mixed into the gas stream as it flows through the pipeline. A computer operates the odorizer and
determines the appropriate amount of odorant to inject based on the desired odorization level and the
volumetric flow rate of gas in the pipeline.
Odorant Concentrations
Refer to Specification 4.18, Odorization Procedures, "Odorant Concentrations"for details on Avista's
odorization concentration procedures.
ODORIZATION REV. NO. 7
ODORIZATION OF NATURAL GAS DATE 01/01/25
Xvism a STANDARDS 2 OF 2
utilities NATURAL GAS SPEC. 2.52

3.0 CONSTRUCTION
3.1 PIPE INSTALLATION
3.12 PIPE INSTALLATION -STEEL MAINS
SCOPE:
To establish uniform procedures for storing, handling, and installing steel gas pipe systems which adhere
to applicable regulatory codes and provide a safe, reliable gas system.
REGULATORY REQUIREMENTS:
§192.161, §192.233, §192.241, §192.243, §192.245, §192.307, §192.313, §192.315, §192.317,
§192.319, §192.750
WAC 480-93-018, 480-93-160, 480-93-175
OTHER REFERENCES:
API Standard 1104
SSPC-SP-10 Near White Blast Cleaning
NACE Standard RP027A-98
NACE Standard SP0188-2006.
ASME B31.8
ASTM A370
CORRESPONDING STANDARDS:
Spec. 2.12, Pipe Design —Steel
Spec. 2.32, Cathodic Protection Design
Spec. 3.18, Dry Line Pipe
Spec. 3.22, Pipe Joining—Steel
Spec. 5.17, Reinstating Abandoned Gas Pipelines and Facilities
CONSTRUCTION REQUIREMENTS:
General
Personnel installing and inspecting steel pipelines and facilities shall be instructed, trained, and qualified
with the equipment and procedures required to install steel pipe. Steel pipe shall be welded by personnel
tested by Avista Pressure Controlmen as discussed in Specification 3.22, Joining of Pipe- Steel.
As a best practice, prior to welding on existing high pressure (above 60 psig) steel pipelines, the welder
should attempt to verify the wall thickness of the pipe through available means such as recorded pipeline
data, pipe stenciling, or a wall thickness tester. Installations of steel pipelines and facilities shall be
inspected on a sampling basis to ensure the work conforms to Avista standards, as well as to the
applicable state, federal, and local requirements. The Inspector shall have the authority to order the
repair, or the removal and replacement, of any component that fails to meet the above requirements.
Except for those situations noted in Specification 2.13, Pipe Design—Plastic (Polyethylene), Aboveground
Plastic Pipe, pipe installed aboveground, in pits, or that passes through a wall shall be steel. Steel pipe
installed aboveground shall be protected from vehicles or other hazards by placing at a safe distance or
by installing behind barricades.
PIPE INSTALLATION REV. NO. 25
STEEL MAINS DATE 01/01/25
X-4, sr'a STANDARDS 1 OF 23
Utilities NATURAL GAS SPEC. 3.12

Steel pipe installed below ground must be protected from washouts, floods, unstable soil, landslides, or
other hazards. Considerations should be made to stop work activities on steel pipeline facilities when
lightning is seen, thunder is heard, or a thunderstorm is in the forecast. This will help minimize the
workers exposure to a possible shock hazard. Specific conditions should be discussed with the local Gas
Operations Manager for clarification.
Monitoring of Pressures
Gas personnel performing work on pipelines and facilities that could result in loss of pressure or
overpressure to the system shall install accurate pressure gauges upstream and downstream of the work
site. The pressure gauges shall be continuously monitored so that personnel can respond accordingly if
system pressures are greatly affected. (Note: CNG Trailers that are oftentimes deployed to maintain
system pressures for short periods of time do not require continuous monitoring.) It may also be
necessary to install a temporary bypass if a system is not looped or if the pipeline work could result in loss
of pressure to the system. Refer to Specification 3.12, Pipe Installation—Steel Mains for temporary
bypass details and requirements.
Additionally, there may be times when merely monitoring downstream pressure may not be sufficient to
prevent customer outages without further action. It may be necessary during warm days or periods of low
gas use to intentionally draw down the pressure of the downstream system and observe it to confirm the
existence of a looped system prior to altering the system or leaving the area. Consult Gas Engineering for
recommendations prior to altering any system's pressure. It may also be necessary to install a temporary
bypass if a system is not looped or if the pipeline work could result in loss of pressure to the system.
Refer to "Temporary Bypass" subsection in this specification for temporary bypass details and
requirements.
Any loss of pressure that may have extinguished pilots or that may have affected the normal operation of
the customer's gas equipment shall be treated as an outage and the procedures followed as outlined in
the GESH, Section 5, Emergency Shutdown and Restoration of Service.
Temporary Bypass
The installation of a temporary bypass may be necessary whenever gas personnel are performing main
or service work that could result in loss of pressure to the system. Pressure gauges should be installed
and monitored in accordance with the Monitoring of Pressures section of this specification whenever a
temporary bypass is used. Gas Engineering should be consulted for bypass sizing, except in situations
where all the following conditions are met:
• Pipeline being bypassed is 4" diameter or smaller.
• Bypass pipe or hose is 1/4" diameter or larger.
• Bypass length is 25 feet or less.
• System MAOP is between 5 and 60 psig.
• Bypass has no more than two tie-in connections (i.e., two-way bypass)
• Average daily temperature on day of bypass is forecasted to be 65 degrees F or greater
TH +TL
TQ„y = 2
Where:
Tavg =Average daily temperature forecast on day of bypass, degrees F
TH = High temperature forecast on day of bypass, degrees F
TL = Low temperature forecast on day of bypass, degrees F
PIPE INSTALLATION REV. NO. 25
STEEL MAINS DATE 01/01/25
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Utilities NATURAL GAS SPEC. 3.12

Storage and Handling of Pipe
Pipe must be handled carefully to prevent bending, denting, buckling, scratching, gouging, or other
damage. If coated pipe is to be handled with lifting equipment, use belts, slings, or padded forks to
minimize damage to the coating. Metallic equipment shall not be allowed to come in contact with the
coating.
Coated pipe 4 inches in diameter and greater shall be stored and/or hauled with flat wooden dunnage
between each layer of pipe. The entire load must be adequately secured to prevent movement. Metallic
tie-down equipment and/or lines shall be carefully padded.
Steel pipeline coatings are susceptible to damage from ultraviolet (UV) radiation. For this reason, it is
recommended that yard stock be inspected periodically and rotated to maximize the coating life.
Chalking or fading of fusion bonded epoxy and abrasion resistant overlay coatings is common for pipe
that is exposed to UV radiation and does not indicate that the coating is compromised. The utilization of
jeeping (refer to"Installation in Ditch"within this specification) is the preferred way to evaluate the
condition of the pipeline coating prior to installation. Pipe coating with excessive weathering (cracking,
etc.) should either be discarded, used for an alternative non-gas carrying purpose, or repaired with an
approved coating.
The ends of pipe shall be sealed with end caps or other acceptable means to keep water and foreign
objects/animals out of the pipe. Stenciled markings on coated pipe shall be maintained until the pipe has
been installed in the ground. If the pipe specification information cannot be verified, the pipe shall not be
used as gas carrier pipe.
Visual Inspection
Visual inspection requirements apply to welding performed on a gas carrying system. Welds shall be
visually inspected by an individual with the appropriate training and experience in visual inspection and
qualified on Visual Inspection of the Weld (221.130.005) or Welding (221.130.010) or be a qualified
welding inspector authorized by Avista. Visual inspections must be performed as per applicable section(s)
of API Standard 1104. Refer to Specification 3.22, Joining of Pipe - Steel, "Non-Destructive Testing (NDT)
Requirements".
Under the following conditions for pipe that produces a hoop stress of 20 percent or more of specified
minimum yield strength (SMYS), visual examinations of the welds by a qualified welding inspector may be
substituted for non-destructive testing (NDT):
• The pipe has a nominal diameter of less than 6 inches regardless of stress level; or
• The pipeline operates at a pressure of under 40 percent of SMYS and the welds are so limited
that NDT is impractical.
A waiver from Gas Engineering should be obtained to avoid NDT examination in either case.
Stringing
To prevent contact between the coating and the ground, it is preferred that pipe is supported on dunnage,
sandbags, or other non-metallic objects that will not cause damage to the pipe coating. In areas free of
sharp rocks and other objects that can cause damage to the pipe coating, pipe may be placed on the
ground as long as the pipe is not drug across the ground.
Pipe shall not be strung on the right-of-way in rocky areas where blasting will occur until after the blasting
is complete.
PIPE INSTALLATION REV. NO. 25
STEEL MAINS DATE 01/01/25
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Utilities NATURAL GAS SPEC. 3.12

Mastic Coating
Mastic coating, such as Royston Roskote R28 Rubberized Mastic, is a cold-applied coating with high
electrical resistivity designed to protect underground steel pipe and fittings. Mastic may be used as a field
applied coating for valves and other intricate objects that are difficult to wrap with tape or wax wrap.
Mastic shall be applied per the manufacturer's instructions on the can.
Tape Wrap
Bare steel pipe and fittings shall be coated prior to burial to protect against corrosion. Avista primarily
utilizes cold applied tape wraps for protecting bare steel pipe, weld joints, and smooth contoured fittings.
Wax type tapes may be used for irregular shaped surfaces as they are more flexible and will provide
better coverage when applied to sharp contours. Wax type tape is available for both below ground and
above ground applications. Tape for above ground applications has a special backing that is both UV and
weather resistant. Both cold applied and wax type tapes can be applied to steel materials with factory
coating types including polyethylene X-Tru coat, FBE (Fusion Bonded Epoxy), and asphalt-based
materials.
Cold Applied Tape Wrap
Cold applied tapes shall be applied in accordance with manufacturer's instructions including use of primer
when applicable.
Bare steel to be tape wrapped shall be free of water, dust, dirt, grease, oil, and other foreign matter. At a
minimum, the surface shall be cleaned by either power or hand wire brushing. Grease and oil can be
removed by use of a solvent. Surface to be coated should be wiped clean prior to tape application to
verify removal of any residual dust or film from solvent cleaning. Moisture present on the surface shall be
removed before coating.
Welds shall be cleaned of welding slag, splatter, and scale. Sharp edges or burrs shall be removed by
grinding or filing.
Some cold applied tape materials are provided with in integrated primer(such as Tapecoat H35 and H50
Gray tape) and may be applied directly to the cleaned surface. A separate, additional primer is necessary
when this tape is applied to materials at low temperatures (below 32 degrees F). When primer is required,
it shall be applied and allowed to dry prior to application of the tape wrap.
Tape should be applied using the spiral wrap method with a minimum of 1-inch overlap between
successive wraps. Wrap should overlap the factory coating by at least 4 inches. When taping pipe
positioned in the vertical position the tape should be wrapped from the bottom up to create an overlap
that does not allow moisture to accumulate at the overlapping tape joints. Care shall be taken to minimize
wrinkling of the tape wrap.
A wrinkle may contain an air space between the tape and the pipe which may cause a corrosion concern.
If a wrinkle occurs during the wrapping process, the wrinkle should be removed as much as possible by
pushing down on the wrinkle to try and achieve bondage between the tape and the pipe. If an excessive
wrinkle is present, the wrinkle shall be cut out and new tape wrap applied.
When taping pipe that is oriented horizontally, ensure that the wrap is terminated on the downhill side of
the wrapping process. This minimizes the chance or water getting between the tape and the pipe surface.
PIPE INSTALLATION REV. NO. 25
STEEL MAINS DATE 01/01/25
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Utilities NATURAL GAS SPEC. 3.12

Coating on Steel Risers
Ultraviolet(UV) resistant coatings on steel (carrier pipe) risers shall come above final grade by
approximately 2 inches to protect the steel at the soil-to-air interface.
X-Tru coating may not be used for the above ground portion of steel risers (or for any above ground pipe)
without a supplementary over coating because the X-Tru coat may degrade with UV exposure. Above
ground wax tape is the preferred over coating for X-Tru coat in aboveground applications. Existing risers
may be left with X-Tru coating if the coating is not cracked or degraded and covered with a well bonded
gray enamel paint. Cracked and degrading X-Tru coating can lead to water pooling and subsequent
corrosion and must be repaired with above ground wax tape.
Wax Type- Tape Wrap
Petrolatum or"Wax Type"tapes shall be applied in accordance with manufacturer's instructions including
use of a primer.
Bare steel to be tape wrapped shall be free of dust, dirt, grease, oil, and other foreign matter. At a
minimum, the surface shall be cleaned by either power or hand wire brushing. Grease and oil can be
removed by use of a solvent. The surface to be coated should be wiped clean to verify removal of any
residual dust or film from solvent cleaning. The primer exhibits preferential wetting and will displace
moisture on the surface when properly applied. To assist in application, excessive surface moisture
should be removed prior to primer application.
Primer is to be applied by hand to a minimum thickness as specified by the manufacturer's instructions to
ensure preferential wetting and continuous application. Primer should be used to fill any voids or gaps
prior to application of the wax tape.
Wrap the wax tape in a spiral wrap method with a minimum of a 1-inch overlap. Wrap should overlap the
factory coating by at least 4 inches. Press and form the tape so there are no air pockets or voids. When
taping pipe positioned in the vertical position the tape should be wrapped from the bottom up to create an
overlap that does not allow moisture to accumulate at the overlapping tape joints. Press and smooth lap
seams to ensure they are properly sealed. Underground applications may be backfilled immediately.
Repair and Patching Using Tape Wrap
Tape wrap may be used to repair damage in factory applied coatings or"holidays". To repair the
damaged coating, remove loose or non-bonded material. Prepare the surface of the pipe as listed
previously. No sharp points, burrs, or rough edges shall appear around the factory coating edges. Sharp
edges shall be feathered smooth prior to application of the tape.
Tape should be applied in a continuous circumferential wrap. Repair tape coating shall overlap the
adjacent undamaged factory coating a minimum of 4 inches. The tape shall be worked down onto the
surface of the steel so as to leave no wrinkles or voids appearing on the view surface of tape that is in
contact with the steel.
Repair and Patching Using a Coating Patch
A coating patch, such as Viscotaq, may be used to repair damaged coatings or holidays. Prepare the
surface of the pipe by removing dust, dirt, grease, oil, loose particles, and moisture. Use either power or
hand wire brushing to clean the surface. Use a solvent, if necessary, to remove grease or oil. Wipe the
surface dry. Install the coating patch by applying pressure to the entire patch area to ensure complete
adhesion to the pipe surface. The patch should overlap the undisturbed pipe coating by a minimum of 1
inch. Multiple coating patches can be used if necessary.
PIPE INSTALLATION REV. NO. 25
STEEL MAINS DATE 01/01/25
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Utilities NATURAL GAS SPEC. 3.12

Field Pinhole Repair
On new factory-applied coatings a pinhole holiday may be tape coated with a minimum of four inches of
tape coat and primer or covered using a coating patch. Alternatively, a ScotchkkoteTM hot melt patch
compound (226P Green) may be used. When using the hot melt compound, follow manufacturer's
recommended application procedures. Existing piping pinholes may be tape coated with a minimum of a
4 inches square section of tape coat and primer when it is impractical to complete a full circumferential
wrap.
Liquid Epoxy Coating
Liquid Epoxy Coating can be used to repair damage, holidays, or coat weld joints in Abrasion Resistant
Overlay (ARO) coated pipe when it is to be installed by boring.
Liquid Epoxy Coating shall be Powercrete R95, or as specified by Gas Engineering, and shall be applied
in accordance with the manufacturer's instructions.
Installation of Powercrete R95 shall be applied using the minimum application steps:
1. Ensure the pipe is clean of grease, oil, salts, and other contaminates. Acetone or other suitable
solvent may be used to clean the pipe.
2. Abrasive-blast clean the surface to a near white (SSPC-SP-10) using a particle blast of non-
crystalline silica material. Crystalline silica material may not be used due to possible health
concerns. A"Bristle Blaster" or similar mechanical method of preparing the pipe surface is also
acceptable as long as a near white surface cleanliness is achieved. A wire wheel is not an
approved method for surface preparation and may lead to incomplete bonding of the coating.
3. Mix Parts A and B thoroughly and apply to dry and clean pipe using plastic paddles to a uniform
desired thickness, typically 60-80 mils or on butt weld joints above the circumferential weld
height. The coating is only to be applied to pipe in which the temperature is above the dew point
to ensure no moisture is present. If necessary, the pipe may be preheated to remove moisture
and speed the cure time. Refer to the table below:
LIQUID EPDXY CURING TIME
Product Temperature in Min. Cure Time "
Degrees F
77 6.75 hours
80 5.5 hours
100 1.5 hours
Powercrete R-95 120 45 minutes
176 26 minutes
212 23 minutes
(Max Substrate Temperature)
*The temperature of the pipe must be maintained for the duration of the cure to meet the
minimum cure times specified.
PIPE INSTALLATION REV. NO. 25
STEEL MAINS DATE 01/01/25
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Utilities NATURAL GAS SPEC. 3.12

Abrasion Resistant Overlay Wrap
Abrasion resistant overlay wrap, such as Scar-Guard, can be used as an abrasion resistant overlay on
field joints and pipe that will be installed by trenchless installation methods, such as horizontal directional
drilling. The product uses a fiberglass cloth that is pre-impregnated with water-activated resin. This type
of wrap must be installed directly over a corrosion protective coating such as cold applied tape wrap or
liquid epoxy coating, and cannot be applied as a standalone anticorrosion coating.
Installation of Scar-Guard shall be done according to the following steps:
1. Install the corrosion protective coating such as cold applied tape wrap or liquid epoxy coating
(see subsections Cold Applied Tape Wrap or Liquid Epoxy Coating for installation details). Use
of liquid epoxy coating underneath the abrasion resistant overlay wrap should be considered in
extremely rough ground conditions.
The following installation instructions are specific to using cold applied tape wrap as the corrosion
protection coating. If a liquid epoxy coating is used as the corrosion protection coating, refer to
the manufacturer's installation instructions.
Scar-Guard rolls should not be stored in temperatures below 40°F. Optimum roll temperature
during installation is 70-80°F. If the ambient temperature is expected to be below 41°F during
installation, it is important to warm the rolls for 24 hours prior to installation. Do not remove Scar-
Guard from its packaging until step 4.
2. Surface preparation for Scar-Guard: The surface preparation area extends a minimum of 24" on
both sides of the weld. Perform an SSPC SP1 solvent cleaning. Remove all visible signs of oil,
grease, dust, dirt, or other surface contaminants. Clean the corrosion protection coating and the
adjacent pipe coating with a solvent cleanser.
3. Abrade the area extending 24" on both sides of the weld with 60-80 grit sandpaper. Blow off,
wipe down, or brush off the entire abraded area once preparation is complete to remove dust.
Perform an electrical inspection of the prepared area to check for holidays (refer to subsection
Electrical Inspection of Pipeline Coatings (Jeeping) later in this Specification).
Corrosion protective coating
installed per manufacturer's instructions
acea �� Factory applied epoxy coating
QteQ
aye
cJJ�
1
24"
Weld seam
24"
PIPE INSTALLATION REV. NO. 25
STEEL MAINS DATE 01/01/25
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Utilities NATURAL GAS SPEC. 3.12

4. Ambient temperature plays an important role in Scar-Guard's ability to cure and the amount of
time it takes to cure. When installing Scar-Guard in ambient temperatures below 41°F, adding a
35% propylene glycol solution and/or heating the pipe or ambient surroundings will ensure Scar-
Guard cures fully. The table below shows the recommended and required activating liquid and
heating requirements based on the ambient temperature.
Ambient Temperature Range(°F) Activating Liquid and Heating Requirements
Greater than 41 Water only
Heating optional
41 -33 35% propylene glycol solution recommended
Heating recommended
32-14 35% propylene glycol solution required
Heating recommended
Less than 14 35% propylene glycol solution required
Heating required
If the ambient temperature is below 41°F it is recommended to preheat the pipe up to 140°F prior
to application (do not exceed 140°F). Preheating is required when the ambient temperature is
below 14°F. Preheat can be accomplished using a propane torch, induction coil, infrared heater,
heated blankets, or heated tents or shelters. If conditions are windy, it may be necessary to tent
or shelter the preheated pipe to prevent rapid heat loss.
If the ambient temperature is below 41°F or is expected to drop below 41°F during the curing
process, it is recommended to use a 35% propylene glycol solution as the activating liquid. A
35% propylene glycol solution is required in ambient temperatures 32°F and below. The
propylene glycol solution will remain a liquid down to 1°F and will allow the Scar-Guard to
continue to cure when the ambient temperature is below freezing. To prepare a 35% solution,
add 1 gallon of propylene glycol (>99% USP/EP)to every 2 gallons of water. Note that some
commercially sold propylene glycol may only contain 50% propylene glycol, therefore the mixing
ratio with water should be 1 gallon of propylene glycol to every 1 gallon of water.
5. Important PPE equipment: Impermeable gloves shall be worn throughout the duration of steps 5
and 6.
Steps 5, 6 and 7 must be completed within the allotted working time as specified in the table in
step 8.
After surface preparation has been completed, soak the entire area to be wrapped with water or a
35% propylene glycol solution (as needed, see step 4). Open the foil pouch and remove the roll.
Begin the application a minimum distance of 24"from the weld. Scar-Guard must be wrapped in
the correct orientation as shown below. The "zig-zag" side of the Scar-Guard must face outward
towards the installer. The straight side must contact the pipe's surface.
PIPE INSTALLATION REV. NO. 25
STEEL MAINS DATE 01/01/25
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Utilities NATURAL GAS SPEC. 3.12

Z'4- / I t I I 'f
'Acl
Zig-zag side faces the installer Straight side faces the pipe
Installation can start on the leading or trailing edge. Apply the first wrap circumferentially around
the pipe at a 90' angle, then begin spiral wrapping with a 50% overlap towards the other edge.
Apply tension during application by pulling firmly on the roll as it is applied. Squeeze and mold
firmly in the direction of the wrap until tight. THOROUGHLY SOAK each layer(both sides, top,
and bottom)of the Scar-Guard as it is being applied, not just the outer layer. Expect to use a
minimum of 1 gallon of water or a 35% propylene glycol solution for every 25 ft2 of applied Scar-
Guard (e.g., a 10"x30' roll). Continue with the 50% overlap until the Scar-Guard extends a
minimum of 24" past the weld. Scar-Guard is applied in a minimum single pass with 50% overlap
to achieve a 2-layer system. End with a minimum of one complete circumferential wrap at a 90'
angle.
Spiral wrap with Weld seam
50%overlap I
i
End of wrap
(One full wrap at 900 to pipe)
24`
Beginning of wrap 24
(One full wrap at 900 to pipe)
Standard 2-laver application
If rough ground conditions are expected, Scar-Guard can be applied in two wraps to achieve 4-
layers of protection. Install the first wrap as described in step 5, then switch directions and
continue to spiral wrap with a 50% overlap back towards the edge where the installation started.
PIPE INSTALLATION REV. NO. 25
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Utilities NATURAL GAS SPEC. 3.12

Spiral wrap with
50%overlap
Weld seam
ago
caP\�
724"
24°
Optional 4-laver application
6. Apply the compression film immediately after the Scar-Guard has been installed. Apply the
compression film starting at the same end where wrap 1 of Scar-Guard was started and with a
50% overlap. Start a minimum of 6" beyond the outer edge of the Scar-Guard, pulling firmly
during application to compress all Scar-Guard layers together, and end 6" past the Scar-Guard on
the opposite edge. The compression film must be installed with a minimum of 4 layers thick (2
passes at 50% overlap). Apply compression film with high tension.
NOTE: Compression film should be applied before excess foaming is observed and the resin has
exceeded the working time (refer to the table in step 8). The compression film must be applied
and perforated immediately after the installation of the Scar-Guard.
Spiral wrap with 50%overlap
starting at the same end where
wrap 1 of Scar-Guard was started
,N(aP�
W<aP2
6"
Beginning of compression film
6"
S`o�t�t�aPPGca`\c�ace
GomP1es
PIPE INSTALLATION REV. NO. 25
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Utilities NATURAL GAS SPEC. 3.12

7. Perforate the compression film using the perforation tool immediately after installation of all the
layers. Use enough downward force to perforate the compression film ONLY. Leather gloves
should be worn during this step. Perforation allows the COz gas generated by the curing process,
and excess water, to escape. During curing the material will foam slightly and some of the foam
will rise through the perforations. Compression film should remain in place as long as possible,
and should only be removed prior to installation of pulling the pipe in. The film will help protect the
Scar-Guard from UV degradation should the pullback be delayed.
8. Allow Scar-Guard to reach a Shore D hardness of 60 prior to installing the pipe. Shore D
readings should only be taken in flat areas. Shore D readings taken over grooves, resin poor
fibers or foamed resin areas may result in lower values. Alternatively, rather than measuring
Shore D hardness, Scar-Guard may be allowed to cure for the minimum amount of time listed in
the table below before installing.
Important: For applications in ambient conditions below 41°F, Scar-Guard must be allowed to
cure for a minimum of 24 hours prior to pulling.
Table definitions:
Working Time—The maximum time allowed from when the Scar-Guard package is opened until
the compression film is installed and perforated.
Cure Time—The minimum time to achieve a Shore D hardness of at least 60 without the need to
measure the Shore D hardness.
Scar-Guard Cure Times with Water
(In ambient temperatures above 41°F)
Pipe Temperature °F Working Time minutes Cure Time minutes
41 5 100
75 4.5 65
90 4 75
150 3.5 80
PIPE INSTALLATION REV. NO. 25
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Utilities NATURAL GAS SPEC. 3.12

Scar-Guard Cure Times with 35% Propylene Glycol Solution
(Recommended in ambient temperatures below 41°F,
Required in ambient temperatures below 32°F)
Pipe Temperature °F Wor ing Time minutes Cure Time hours
14 25 24
23 20 24
Installation in Ditch
Coating must be inspected prior to lowering the pipe into the ditch and any damage found must be
repaired prior to backfilling. In addition to visual inspection, high pressure distribution pipelines shall be
electrically inspected using a holiday detector,jeeping machine, or similarly tested to assure no flaws are
present in the coating.
The steel pipe shall be installed in the trench with enough flexibility to prevent excessive stress from
thermal expansion or contraction. Anchors or supports shall be provided to prevent undue strain, resist
longitudinal forces, and prevent or damp out excessive vibration. Exposed pipe joints must be protected
from any end forces caused by internal pressure, thermal expansion or contraction, and weight of pipe.
For transmission pipelines with 1,000 feet or more of continuous backfill, promptly after backfilling (but not
later than 6 months after placing the pipe in service), a coating damage assessment shall be performed to
ensure the integrity of the coating. The assessment may be performed using Direct Voltage Current
Gradient(DCVG), Alternating Current Voltage Gradient (ACVG), or other technology that provides
comparable information about the integrity of the coating. The coating survey must be conducted in all
locations except those where effective coating surveys are precluded by geographical, technical or safety
reasons.
• If an alternative assessment method (other than DCVG or ACVG) is desired, PHMSA must be
notified at least 90 days in advance in accordance with 192.18.
• Any coating damage classified as severe (voltage drop greater than 60 percent for DCVG or 70
dBpV for ACVG) must be repaired in accordance with Section 4 of NACE SP0502 within 6
months after the pipeline is placed in service, or as soon as practicable after obtaining necessary
permits, not to exceed 6 months after receipt of permits.
• Records of the coating assessment findings and remedial actions must be retained for the life of
the pipeline.
Test Leads
Test leads are to be installed at the following locations to enable cathodic protection monitoring and
locating:
• New steel main installations at approximately 1,000-foot intervals when possible or as needed.
• As close as possible to bore entrance and exit points of bores extending under a river, road, or
other location in which the installed pipe depth is greater than standard installations.
• Both sides of buried insulated fittings. Refer to Drawing A-35447 and Drawing
B-36271 at the end of this Specification.
• Steel casings with steel carrier pipe. Refer to Specification 3.42, Casing and Conduit
Installations, Drawing B-34947 for details.
• On steel pipelines, where they cross other metallic pipelines. Additional test leads should be
attached to foreign pipelines if consent can be obtained.
PIPE INSTALLATION REV. NO. 25
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Utilities NATURAL GAS SPEC. 3.12

Test leads are normally a#10 white or black wire. The #10 wire may be either a solid or stranded wire.
White wires shall be used on the pipe at each location where isolation or casings are not encountered.
Test leads are to be attached to steel mains or fittings by the "Cadweld" process. Reference the Cadweld
Procedure within this specification. Joining and splice connections shall be either encapsulated in a
dielectric type of gel connector which is the preferred method, or a crimped sleeve covered by an
approved dielectric sealing compound (such as Aqua-Seal) and tape wrapped. Prior to installing wires
into an encapsulated connector, the wires should be tied together with an over-the-hand type knot
approximately 6 inches to 12 inches from the end of the wires. This knot alleviates strain on the wire
connection. Refer to Drawing A-36277, Wire Connections at the end of Specification 3.13, Installation —
Plastic Mains.
The test leads shall terminate in a suitable, accessible, and convenient location near the transition point
such as a test box or valve box. Refer to Drawing B-36271, at the end of this Specification, for additional
detail.
CADWELD PROCEDURE:
Before performing a Cadweld the pipe must be inspected to ensure the absence of defects, corrosion,
mechanical damage, or other anomalies. Refer to the "Non-Destructive Pre-Inspection" section in
Specification 3.22, Joining of Steel Pipe, for further guidance.
Select the correct Cadweld mold. There are two different types to choose from. The mold with the flat
bottom is used only on 4-inch and larger diameter pipe. The mold with a concave bottom is used only on
3/4-inch to 3-1/2-inch pipe.
Inspect the Cadweld tool and ensure it is in good working condition. Ensure the ignition controller is in
good condition and has batteries installed. If the light does not illuminate, the batteries are likely expired
and will need replacing. Identify the size of wire being used. The largest wire to be used with either mold
is#8 (without a sleeve)or#10 and #12 which both require a sleeve.
Remove coating from the pipe surface using either an electric grinder or a sanding tool such as a file or a
wire brush. An area no larger than 2 inches x 2 inches will be required. The pipe surface should be
bright and clean of debris. At this point, fill out an Exposed Piping Inspection Report form (Form N-2534).
Strip enough coating from the#10 and #12 wires to accommodate a sleeve. Leave 1/8-inch exposed
through the end of the sleeve. (A slight crimp maybe used to hold the sleeve in place). Leave 1/8-inch
of the sleeve exposed when inserted into the mold. For#8 wires, a sleeve is not required. Strip enough
coating back to leave 1/4-inch of the wire exposed when placed into the mold.
Prior to loading the cad welder or performing the Cadweld, you must preheat the mold and pipe to
eliminate moisture.
Load the Cadweld mold with the approved metal cup. Be sure to remove the clear plastic from the metal
cup prior to loading. The cup should be labeled "CA-15" and have a green top.
Connect the ignition controller termination clip to the metal cup. The black line on the metal cup that
indicates when the metal cup is fully installed.
Perform the Cadweld by holding the button on the ignition controller. The light will blink 5-10 times during
the welding procedure. (Do not move or flinch during the Cadweld process as this may cause a
substandard weld.)
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Loop the wire around the pipe to relieve any potential stresses on the Cadweld.
Use a brass hammer to verify the quality of the weld. Remove any slag from the weld site using a wire
brush.
If a poor Cadweld is performed, remove the debris, and move a minimum of 6 inches and return to Step
#4 above.
When Cadwelding multiple leads to a pipe, ensure they are installed a minimum of 6 inches apart.
Coat the Cadweld and bare pipe with a company approved coating.
Bring wires up into the appropriate test box. Refer to Drawing B-36271 for test lead details across
isolation fittings or transition fittings. Refer to Drawing B-34947 for casing test lead details. Test leads
may be either solid or stranded.
Any questions about the configuration of wires should be referred to the local Cathodic Protection
Technician.
Caution Tape
Except for horizontal directional drilling (HDD) installations, high pressure steel pipelines shall be installed
with yellow warning tape stating words to the effect of"CAUTION, GAS LINE BURIED BELOW" placed
approximately 1 foot above the main.
The use of caution tape should also strongly be considered for intermediate pressure pipelines. These
types of locations may include but are not limited to installations within private easements and dry-line
installations where the presence of a gas pipeline may be unexpected to excavators.
Marker Balls
Marker balls should be installed at stopper fittings, bottom-out fittings, side-out fittings, ends of main,
valves, stubs, and in other applicable instances in order to facilitate finding these fittings and locations in
the future. Ensure as-built drawings and the resulting mapping records are updated to indicate the
presence of these locating devices. Marker balls shall be installed with a minimum of 4 inches of vertical
clearance to the buried gas facilities. The marker ball cannot be buried deeper than 4 feet from finish
grade to allow for accurate locating. Considerations shall be made to install additional marker balls for
facilities at depths, or anticipated depths, greater than 4 feet: one being placed near the buried facility and
another being no more than 4 feet deeper than finish grade, or no deeper than 1 foot from finish grade for
areas where seasonal snowpack occurs.
Dry Line Installations
As a general rule, dry line gas lines should not be installed unless there is a high degree of certainty that
the line will be placed into service within three years. Additionally, consideration should be given to
abandoning dry lines that have been in place for five years or greater to lessen the burden of ongoing
locating of the facility. If the need arises to bring a former dry line into service that has been abandoned, it
can be done in accordance with Specification 5.17, Reinstating Abandoned Gas Pipelines and Facilities.
Refer to Specification 3.18, Dry Line Pipe, for additional details on pressure testing of dry line pipe.
PIPE INSTALLATION REV. NO. 25
STEEL MAINS DATE 01/01/25
X-4, sr'a STANDARDS 14 OF 23
Utilities NATURAL GAS SPEC. 3.12

Electrical Inspection of Pipeline Coatings (Jeeping)
An electrical inspection (commonly referred to as jeeping) is a test of the continuity of protective coating
that should be performed on steel pipe prior to underground installation. It detects bubble or blister-type
voids, cracks, thin spots, and foreign inclusions or contaminants in the coating that lowers the electrical
resistance (dielectric strength) of the coating significantly. Manufacturer's recommendations should be
followed on the use and maintenance of the equipment.
Excessive moisture or any electrically conductive material in or on the surface of the coating system can
cause appreciable leakage currents, which may lower the effective testing voltage or cause erroneous
holiday indication. Drying and cleaning of the coated surface may be necessary. Holiday detector parts
shall be kept clean and free of moisture at all times.
The voltage setting on the equipment should be adjusted to match the coating. Thin film coatings up to 20
mil thickness require a low voltage detector. Thicker film coatings greater than 20 mil thickness require
the use of a high voltage detector. Piping coating should be jeeped immediately prior to installation in
trench. This will ensure that damage to the coating does not happen after jeeping is completed from
vandalism or other occurrences while the pipe is unattended.
Voltage Settings for Conventional Coatings
The minimum testing voltage for a particular coating thickness shall be within 20 percent of the value
determined from one of the following formulas or as shown in Table 1 as recommended by NACE
Standard SP0188-2006.
Testing Voltage = 1,250 x coating thickness (mils)
Or
Testing Voltage = 7,900 x coating thickness (mm)
TABLE 1
Minimum Testing Voltage for Conventional Coating Thicknesses Such as X-Tru Coat*
mm (in) (mils) Testing
Voltage
0.51 N/A 20 5,600
0.79 N/A 31 7,700
1.0 N/A 40 7,900
1.3 N/A 50 8,800
1.6 N/A 62 9,900
2.4 3/32 94 12,000
4.0 5/32 156 16,000
4.8 3/16 188 17,000
13.0 1/2 500 28,000
16.0 5/8 625 31,000
19.0 3/4 750 34,000
*Thin-film coatings(fusion bonded epoxy)are not
covered in this table.
PIPE INSTALLATION REV. NO. 25
STEEL MAINS DATE 01/01/25
�rsr�r STANDARDS 15 OF 23
Utilities NATURAL GAS SPEC. 3.12

Voltage Settings for Thin Film Coatings (FBE)
The following formula shall be used to determine the voltage setting for thin film coatings such as fusion
bonded epoxy (FBE):
Testing Voltage (TV) = 127 x mil thickness
Example: mil thickness = 16 mils
TV= 127x16 mils
TV= 2,032 Volts
Voltage Settings for ARO Pipe
The following formula shall be used to determine the voltage setting for FBE coated pipe with an
additional ARO (Abrasive Resistant Overlay)coating:
Testing Voltage (TV) = (127 x mil thickness of FBE) + (1250 x (mil thickness of ARO))
Example: FBE mil thickness = 16 mils
ARO mil thickness = 40 mils
TV= (127 x 16) + (1250 x 40)
TV= 9,938 Volts
Coating Thickness for New Pipe
The following table is provided as a reference for typical X-Tru coat and Fusion Bonded Epoxy Coating
thickness on new pipe. The coating thickness is designed to maintain sufficient strength to resist damage
due to handling (including, but not limited to, transportation, installation, boring and backfilling) as well as
soil stress.
TABLE 2
New Pipe Coating Thickness Table
Pipe Size X-Tru Coating FBE Coating Thickness ARO Coating Thickness
Thickness
(in) (in) (mils) (mils) (mils)
1/2 .025 25 14— 18 40—60
3/4 .025 25 14— 18 40—60
1-1/4 .025 25 14— 18 40—60
2 .030 30 14— 18 40—60
4 .035 35 14— 18 40—60
6 .040 40 14— 18 40—60
8 to 20 .040 40 14— 18 40—60
Supports
Supports or anchors must be made from a durable material such as steel and/or concrete. No wood
supports or anchors shall be used. Supports or anchors should be mechanically attached to carrier pipe
and cathodic isolation should be provided between the supports or anchors where needed. Supports or
anchors shall not be welded to the carrier pipe.
PIPE INSTALLATION REV. NO. 25
STEEL MAINS DATE 01/01/25
X-4, sr'a STANDARDS 16 OF 23
Utilities NATURAL GAS SPEC. 3.12

Pipe Bends
Pipe inflections or changes in direction may be completed using appropriate bending equipment. Bends
shall be free from buckling, cracks, or other evidence of mechanical damage. Bends shall not impair the
serviceability of the pipe. Wrinkle bends are not allowed.
When bending pipe containing a longitudinal weld, the longitudinal weld shall be near as practical to the
neutral axis of the bend. The bend radius shall be no smaller than allowed by ASME B31.8 and as
summarized in the following table:
Minimum Steel Bend Radius
Nominal Pipe Minimum Radius of Bend
Diameter D in in Pipe Diameters in
Less than 12 18 x D*
12 18 x D
14 21 x D
16 24xD
18 27xD
20 and greater 30 x D
*Note: Shorter radius bends may be permitted provided the completed bend meets the serviceability criteria and the
remaining wall thickness after bending is not less than the minimum design wall thickness. Contact Gas Engineering
for assistance.
Bends should be positioned at least 6 pipe diameters from the end of the pipe or a girth/circumferential
weld. Bends and bending equipment shall be positioned so as to not affect the roundness at the ends of
the pipe or stress the circumferential weld. No bends are allowed in girth welds.
Note that minimum steel pipe bend radius in this section is not to be confused with minimum bend radius
of pipe for horizontal directional drilling and trenchless installation. Refer to Specification 3.19,
Trenchless Pipe Installation, for information with regards to minimum allowable bend radius during
trenchless installation.
Mitering/Segmenting Elbows
Welding elbows may be cut into segments to provide proper angle. Segments of elbows 2 inches or
more in diameter must be at least 1-inch across the crotch (throat).
Pigging of Pipe
For large jobs or jobs installed during wet weather, it is possible that water and debris may need to be
removed from the pipeline. Pigging should be considered at the discretion of the Avista project engineer,
foreman, or inspector.
The pig launcher and receiver must be equipped with a device capable of safely relieving the pressure
inside the launcher and receiver before inserting or removing in-line devices. An operator must use a
device to either indicate that the pressure has been relieved or prevent opening of the launcher or
receiver if the pressure has not been relieved.
Pits and Vaults
For any steel mains installed in association with a pit or vault, refer to Specification 2.42, Vault Design.
PIPE INSTALLATION REV. NO. 25
STEEL MAINS DATE 01/01/25
X-4, sr'a STANDARDS 17 OF 23
Utilities NATURAL GAS SPEC. 3.12

Odorizing Newly Installed Pipe
Newly installed pipe may present challenges with regards to meeting the required detection levels as
defined in Specification 4.18, Odorization Procedures. New pipe, especially that which is gassed up but
not immediately put into service, tends to absorb odorant in the pipe wall. Consideration should be made
to"pickle" such pipe per Specification 4.18, Odorization Procedures, "Pickling Newly Installed Pipe."
Moving or Lowering Steel Pipe in Service
Moving (or lowering)of steel pipe in service shall be performed only after careful consideration of various
factors that might cause additional stress on the pipeline. Steel pipe with mechanical joints, threaded
joints, or monolithic fittings (ex. Zunt) may not be moved due to the potential for a leak to develop at these
locations. Refer to the "Steel Pipe Lowering Decision Flow Chart" at the end of this Specification.
When a small amount of pipe movement is required, the table below may be used to determine the
minimum roping distance on both sides of the moved pipe section. This minimum roping distance will
allow the pipe to move while keeping the stress level at an acceptable level. This table may only be used
for pipelines 2 inches and smaller, that operate at 60 psig or less, and require 3 inches or less of
movement.
Minimum Roping Distance on Both Sides of the Moved Pipe Section
(MAOP = 60 psig or less)
Nominal Pipe Deflection inches
Pipe
Size
(Steel '/4 '/2 1 1-'/2 2 2-'/2 3
Pipe
inches
1/2 3 ft 4 ft 5 ft 6 ft 7 ft 8 ft 9 ft
3/4 3 ft 4 ft 5 ft 6 ft 7 ft 8 ft 9 ft
1 3 ft 4 ft 6 ft 7 ft 8 ft 9 ft 1 o ft
3 ft 5 ft 7 ft 8 ft 9 ft l o ft 11 ft
4 ft 5 ft 7 ft 9 ft l o ft 11 ft 12 ft
2 4ft 6ft 8ft loft 11 ft 13ft 14ft—
Steel pipelines that require greater than 3 inches of movement, operate above 60 psig, or are greater
than 2-inches nominal diameter must have roping calculations performed to determine whether moving
will cause an unsafe condition. Roping calculations take into consideration the required deflection of the
pipeline, existing pipe specifications, operating pressures, terrain, class location, present condition of the
pipe, anticipated stresses, and the toughness of the steel. Consult Gas Engineering when a roping
calculation is needed.
It is a requirement in Washington State to leak survey a gas facility within 30 days after being moved if
the pipeline is intermediate pressure and 2 inches diameter or less. For other states and facilities, this is a
best management practice. If leaks, flawed welds, or unsatisfactory workmanship are discovered when
the pipe is exposed for moving, they shall be repaired prior to moving the pipe.
PIPE INSTALLATION REV. NO. 25
STEEL MAINS DATE 01/01/25
X-4, sr'a STANDARDS 18 OF 23
Utilities NATURAL GAS SPEC. 3.12

Piping and Weld Data Collection
For newly installed high-pressure pipelines, the welder name, date of weld, weld procedure used, and
GPS location should be collected for each weld. The pipe and fitting information collected should include
the purchase order number, manufacturer's name, heat number, approximate segment length, coating
type, and GPS location, which should be collected for each pipe segment. This information gathered
shall be retained as part of the MAOP record for the pipeline and uploaded to Avista's GIS system.
For newly installed or rebuilt high pressure gate stations and regulator stations, the welder name, date of
welds, and weld procedures used should be collected for the station and displayed on the drawing or
placed in the MAOP file for the station. The pipe and fitting information collected should include the pipe
purchase order number, manufacturer's name, and heat number.
Toughness Testing
By engineering analysis, Avista has determined that pipelines of a certain age and size must undergo
toughness testing before lowering or roping. Toughness testing is required for all diameters of high-
pressure pipe fabricated prior to 1980, as well as all intermediate pressure pipe larger than 2 inches in
diameter and fabricated prior to 1980. Pre-1980 manufacturing techniques and this era of pipe's tendency
to exhibit lower toughness due to higher carbon levels requires this analysis before lowering. A Charpy v-
notch test is commonly used to determine the toughness of a specimen by determining the amount of
energy a material absorbs when fracturing.
An acceptable toughness level is determined when the average energy absorbed is 20 ft-Ibs or more with
no single specimen less than 15 ft-Ibs on a 10 mm x 10 mm specimen at 40 degrees F. Acceptance
criteria and testing shall be according to ASTM A370, Table 9. Consult Gas Engineering for an
interpretation of the results.
WAC 480-93-175:
High Pressure Pipelines of any Diameter and Intermediate Pressure Pipelines Larger than 2 inches
Diameter: In the State of Washington, prior to lowering any steel pipeline a study must be performed by Gas
Engineering to determine whether the action will cause an unsafe condition. This study must analyze the
following:
a) The required deflection of the pipe
b) The diameter, wall thickness and grade of the pipe
c) The characteristics of the pipeline
d) The terrain and class location
e) The present condition of the pipeline
f) The anticipated stresses of the pipeline including the safe allowable stress limits and
g) The toughness of the steel.
This study may include roping calculations or toughness testing and must be retained for the life of the
pipeline. 2 inches and Smaller Diameter, Intermediate Pressure: In the State of Washington, pipelines
operating at 60 psig or less which have a nominal diameter of 2 inches or less do not require a study to be
performed prior to lowering if the operator can certify that no undue stresses will be placed on the pipeline and
that it can be moved or lowered in a safe manner. A leak survey must be conducted within 30 days from the
date these pipelines have been moved or lowered for these pipelines.
Reference the Steel Pipe Lowering Decision Flowchart at the end of this specification for guidance on
sorting out the requirements for toughness testing and analysis. This chart is meant to identify minimum
guidelines; Avista may choose to do additional study as necessary based on the particular circumstances
of a proposed lowering site.
PIPE INSTALLATION REV. NO. 25
STEEL MAINS DATE 01/01/25
X-4, sr'a STANDARDS 19 OF 23
Utilities NATURAL GAS SPEC. 3.12

Recordkeeping
Studies, analyses, and toughness testing results shall be retained for the life of the facility. Copies of the
analysis and test results shall be retained in Gas Engineering.
Pipe Coupon Retentions Procedures
Whenever a tapping occurs on a transmission line or high pressure main, the pipe coupon should be
retrieved, properly cataloged (including date, pipe size, location, Work Order number, and any pertinent
notes), and kept at the local construction office for future testing as may be warranted.
Updating Maps and Records
Employees responsible for construction activities shall ensure field as-built documents are completed
immediately following construction, repair, or abandonment of facilities. Field as-built documents shall be
subsequently mapped by the district GIS Editor within the electronic mapping system to allow for accurate
gas facility locating and incorporation into maintenance schedules. The district manager in which the
construction activities take place is responsible to ensure that field work as-built documents are
completed and mapped in a timely manner. In Washington State, this shall be completed within 6 months
following the completion of the field work. In Idaho and Oregon this is a best management practice.
WAC 480-93-018 (5): Each gas pipeline company must update its records within 6 months of when it
completes any construction activity and make such records available to appropriate company
operations personnel.
PIPE INSTALLATION REV. NO. 25
STEEL MAINS DATE 01/01/25
X-4, sr'a STANDARDS 20 OF 23
Utilities NATURAL GAS SPEC. 3.12

Steel Pipe Lowering Decision Flowchart
Is the line HP? 0 No Is this IP line>2"diameteR
Yes Yes No
Are the existing pipe
specification known? Get roping calculation
from Gas Engineering.
No
Yes
Is the line in Washington State?
Do not lower Was the line fabricated
consider line before 1980?
placement or
protective
measures- • No Yes
Yes
No
Do
toughness
testing. Observe Observe exterior
exterior of of exposed pipe
exposed pipe for leaks or
for likes or indicators of
Test passed? indicators of flawed welds or
flawed welds or unsatisfactory
unsatisfactory workmanship-If
workmanship.If OK lower and
OK lower. follow up with
Yes No leak survey
within 30 days.
Get
moving/lowering
study from
s Engineering.
Do not lower.
Consider
replacement.
Observe exterior At minimum
of exposed pipe do a welded
for leaks or offset to
indicators of move the
flawed welds or line.
unsatisfactory
workmanship.If
OK lower.
Note:Pipe Moving/Lowering Study results shall be retained by Gas Engineering for the life of the pipeline.
PIPE INSTALLATION REV. NO. 25
STEEL MAINS DATE 01/01/25
X-4, sr'a STANDARDS 21 OF 23
Utilities NATURAL GAS SPEC. 3.12

WHITE—.
WH I TE—, —BLACK
1
INSULATED— ' ��—
FITTING BLACK INSULATED
FITTING
WHITE —BLACK
INSULATED
INSULATED—� �, FITTING
FITTING —BLACK
\WHITE
THE TEST LEADS ON THE NORTH DISTRIBUTION GAS
OR WEST SIDE OF THE INSULATED STANDARD
FITTING SHOULD BE WHITE #10 SOUTH COLOR CODING OF C.P. TEST LEADS
THE TEST LEADS ON THE SO
SOLID WIRE (STOCK NO. U . ACROSS INSULATED FITTINGS
OR EAST SIDE OF THE INSULATED AV I STA CORP
FITTING SHOULD BE BLACK #10 SPOKANE. WASHINGTON
SOLID WIRE (STOCK NO. 2831020). NONE 6-5-01 APPROVED
SCALEAT
DSN. BURGER C K 0.O 6 8 01
DR. CJ NTO._ DATE
NO DAT( REV IS ION BY CKD CKD. - NTp. 1W Of
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PIPE INSTALLATION REV. NO. 25
STEEL MAINS DATE 01/01/25
x rv#ST,aa STANDARDS 22 OF 23
Utilities NATURAL GAS SPEC. 3.12

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PIPE INSTALLATION REV. NO. 25
STEEL MAINS DATE 01/01/25
��r�sra STANDARDS 23 OF 23
Utilities NATURAL GAS SPEC. 3.12

3.13 PIPE INSTALLATION - PLASTIC (POLYETHYLENE) MAINS
SCOPE:
To establish a uniform procedure for storing, handling, and installing plastic(polyethylene) gas pipe
systems which adhere to applicable regulatory codes and provide a safe, reliable gas system.
REGULATORY REQUIREMENTS:
§192.59, §192.67, §192.159, §192.307, §192.321, §192.323
WAC 480-93-178
OTHER REFERENCES:
Performance Pipe Technical Note PP 803-TN Pull-In Applications
CORRESPONDING STANDARDS:
Spec. 2.13, Pipe Design — Plastic
Spec. 2.32, Cathodic Protection Design
Spec. 3.16, Services
Spec. 3.18, Pressure Testing
Spec. 3.19, Pipe Installation—Trenchless Pipe Installation
Spec. 3.23, Joining of Pipe— Plastic (Polyethylene)— Heat Fusion
Spec. 3.24, Joining of Pipe— Plastic (Polyethylene)— Electrofusion
Spec. 3.25, Joining of Pipe— Plastic (Polyethylene)— Mechanical
Spec. 3.34, Squeeze-Off of PE Pipe and Prevention of Static Electricity
Spec. 3.44, Exposed Pipe Evaluation
Spec. 4.18, Odorization Procedures
Spec. 5.17, Reinstating Abandoned Gas Pipelines and Facilities
CONSTRUCTION REQUIREMENTS:
General
Personnel installing and inspecting polyethylene (PE) pipelines shall be instructed, trained, and qualified
with the equipment and procedures required to install polyethylene pipelines.
Qualified Joiners
No person shall perform plastic pipe joining on polyethylene pipe and associated components until that
person has been qualified in the approved methods of plastic pipe joining. Upon completion of
qualification, a certification record will be issued and must be available for inspection when performing
plastic pipe joining in the field. Refer to Specifications 3.23, 3.24, and 3.25 for Joining of Pipe- Plastic.
No solvent joints shall be used. No person shall perform inspection of plastic joints without being qualified
by training or experience in evaluating the acceptability of plastic pipe joints made under the applicable
joining procedures.
PIPE INSTALLATION REV. NO. 23
PLASTIC MAINS DATE 01/01/25
XvIST'r STANDARDS 1 OF 14
utilities NATURAL GAS SPEC. 3.13

Installations of polyethylene pipelines and facilities shall be inspected on a sampling basis to ensure that
the work conforms to Avista standards, as well as to the applicable state, federal, and local requirements.
The Inspector shall have the authority to order the repair or the removal and replacement of any
component that fails to meet the above requirements. Installation of plastic pipe that requires squeeze-off
shall be performed in accordance with the procedures outlined in Specification 3.34, Squeeze-Off of PE
Pipe and Prevention of Static Electricity.
Monitoring of Pressures
Gas personnel performing work on pipelines and facilities that could result in loss of pressure or
overpressure to the system shall install accurate pressure gauges upstream and downstream of the work
site. The pressure gauges shall be continuously monitored as long as necessary so that personnel can
respond accordingly if system pressures are greatly affected. (Note: CNG Trailers that are oftentimes
deployed to maintain system pressures for short periods of time do not require continuous monitoring.)
Additionally, there may be times when merely monitoring downstream pressure may not be sufficient to
prevent customer outages without further action. It may be necessary during warm days or periods of low
gas use to intentionally draw down the pressure of the downstream system and observe it to confirm the
existence of a looped system prior to altering the system or leaving the area. Consult Gas Engineering for
recommendations prior to altering any system's pressure. It may also be necessary to install a temporary
bypass if a system is not looped or if the pipeline work could result in loss of pressure to the system.
Refer to Specification 3.12, Pipe Installation—Steel Mains for temporary bypass details and
requirements.
Any loss of pressure that may have extinguished pilots or that may have affected the normal operation of
the customer's gas equipment shall be treated as an outage and the procedures followed as outlined in
the GESH, Section 5, Emergency Shutdown and Restoration of Service.
Storage of Pipe and Associated Components
Per manufacturer's latest recommended practices and industry best practices, the following are
guidelines for the storage of PE pipe and associated components:
Polyethylene pipe and components shall be stored so as to prevent the possibility of the material being
damaged by crushing, gouging, or piercing. The height to which polyethylene pipe may be stacked
depends on factors such as size, wall thickness, and ambient temperature. At no time should the height
of the stack cause the pipe to be forced out of round. Care must be taken at all times to protect the
polyethylene pipe and components from fire, excessive heat, harmful chemicals, and mechanical
damage.
Yellow plastic pipe, including anodeless risers, transition fittings, and stick EFV assemblies made with
yellow PE pipe, shall not be installed in the gas system if more than 3 years (36 months) old. Black plastic
pipe, including anodeless risers, transition fittings, and stick EFV assemblies made with black PE pipe,
shall not be installed in the gas system if more than 10 years (120 months) old. The age of anodeless
risers and transition fittings is based upon the date the plastic pipe was manufactured and not the date
the riser or transition fitting was fabricated. The age of the stick EFV assembly is based upon the date the
fitting was fabricated.
PE components such as elbows, tees, couplings, valves, etc. should be stored indoors and protected
from UV exposure as a matter of company policy. PE components shall not be installed in the gas system
if they are found to be older than the following:
• Yellow plastic components—3 years (36 months)
• Black plastic components— 10 years (120 months)
PIPE INSTALLATION REV. NO. 23
PLASTIC MAINS DATE 01/01/25
Xv sm a STANDARDS 2 OF 14
utilities NATURAL GAS SPEC. 3.13

Use sandbags or planking to protect sticks of pipe from ground surface conditions that might damage the
pipe. The ends of pipe should be sealed with end caps or other acceptable means to keep debris, water,
and rodents out of the pipe. Banded bundles should be offset with wood dunnage when stacked.
Stacks should be leveled to prevent leaning and uneven loading on the bottom bundle. Pipe coils should
be stored (center hole vertical) on pallets or dunnage on a level surface.
Handling
The following guidelines must be followed for PE pipe handling:
Polyethylene pipe shall be handled carefully to eliminate the possibility of damage during loading and
unloading operations. Whether using a forklift or forks attached to the bucket of a front-end loader or
backhoe, the forks should be checked for jagged edges or burrs. If the forks are marred, cover them with
a suitable protective covering to prevent gouging of the pipe. The forks should be spread as wide as
possible.
The pipe must be supported during transport to minimize movement. Ropes and other securing devices
shall be padded to prevent damage to the pipe. Chains shall not be used to secure the pipe. Equipment
or other supplies shall not be placed on top of the pipe.
Banded bundles should be picked up one bundle at a time. Banding should not be removed until the
bundles have been transported to the storage area and secured in a stable and safe manner.
The stringing of coils of plastic pipe may be accomplished by hand or from a reel. Coils should not be
rolled over sharp objects or pulled over rough surfaces. Stringing of straight lengths should be done by
lifting the pipe from the truck to the ground. The pipe should be protected from rocks or other abrasive
material during this operation and should not be dropped.
Coiled polyethylene pipe is confined with straps at intervals within the coils. As the pipe is uncoiled, only
the outside straps should be cut.
Polyethylene pipe shall be carefully inspected for kinks, cuts, gouges, deep scratches, punctures, and
other imperfections after each of the handling operations. Defective or damaged pipe must be rejected.
Installation
Plastic pipe is typically installed below ground level with the exception of temporary emergency repairs
and encased bridge crossings. Gas Engineering must approve the use of plastic pipe above ground.
Pipe must be firmly supported along its entire length to minimize any stresses induced by settlement.
Care should be taken to assure pipe ends are kept free of debris and water at all times. As a minimum,
plastic end caps shall be used in ends of main during off-construction periods.
If water or debris is suspected to have entered pipe, the entire length of suspected line shall be pigged
until all water and/or debris is eliminated.
PIPE INSTALLATION REV. NO. 23
PLASTIC MAINS DATE 01/01/25
XvIST'r STANDARDS 3 OF 14
utilities NATURAL GAS SPEC. 3.13

Temporary Bypass
See Specification 3.12, Pipe Installation— Steel Mains for temporary bypass details and requirements.
Field Bending
A field bend is an intentional deflection of pipe without the use of a fitting. Plastic pipe should be installed
so that there are no bends with a radius less than 25 times the outside pipe diameter(20 times the
outside diameter for SDR 7). When a fusion or fitting is present in the bend the minimum bending radius
is 100 times the outside pipe diameter of the pipe for a recommended distance of 5 times the outside
diameter on each side of the fusion or fitting. Refer to the table below:
Minimum Permanent Bending Radius
Min. Bend Min. Distance
Min. Min. Bend Radius with a for 100x
Outside Bend Ratio with Fusion or Radius Each
Min. Diameter Radius a Fusion Fitting Side of Fusion
Pipe Bend "O.D" "R" or Fitting Present or Fitting "L"
Size in. SDR Ratio in. (ft. - in.) Present "R" ft. -in. ft. - in.
1/2"CTS 7 20 0.625" 11 - 1" 100 5' -3" 0'-4"
3/4" IPS 11 25 1.050" 2' -3" 100 8'-9" 0'-6"
1-1/4" IPS 11 25 1.660" 3' -6" 100 13'- 10" 0'-9"
2" IPS 11 25 2.375" 5' -0" 100 19'- 10" 1'-0"
3" IPS 11 25 3.500" 7' -4" 100 29'-2" 1'-6"
4" IPS 11.5 25 4.500" 9' -5" 100 37'-6" 11- 11"
6" IPS 11.5 25 6.625" 13'- 10" 100 55'-3" 2'- 10"
*Calculation from Plastics Pipe Institute Handbook of Polyethylene Pipe 2nd Edition, Chapter 7 Table 4.
O.D.=PIPE OUTSIDE jO,D, DIAMETER OUTSIDE
DIAMETER(IN.)
PIPE FITTING OR
FUSION
L(IN.)=5 X O-D.(IN.)
R R
(NOTE:BEND RADIUS CAN
'
-----------------► RETURN TO 25 X O.D_AT
-----------------
R=BEND RADIUS(FT) R=BEND RADIUS(FT) THIS POINT)
R=BEND RATIO X O.D.0N.) R=100 X O.D-(IN.)
12(IN./FT) 12(IN./FT)
FOR A DISTANCE"L"TO EACH
SIDE OF FITTING OR FUSION
FIELD BEND-PE PIPE FIELD BEND-PE PIPE
(PIPE ONLY) (FUSION OR FITTING IN BEND)
PIPE INSTALLATION REV. NO. 23
PLASTIC MAINS DATE 01/01/25
XvIST'r STANDARDS 4 OF 14
utilities NATURAL GAS SPEC. 3.13

The exception to the bending radii in the above table is when PE pipe is being installed or utilized in
prefabricated risers and new construction risers. It is acceptable for the bend radius to exceed the above
values and be more similar to the approved chute bending radii shown later in this Specification.
Shear and Tensile Stresses
�he pipe must be installed so as to minimize shear or tensile stresses. When plastic pipe is installed on a
warm day, allowance must be made for thermal contraction; otherwise, excessive tensile stresses could
occur when the pipe cools. Refer to Specification 2.13, Pipe Design - Plastic.
For direct burial, where clearance from other facilities is not a problem, "snake" the pipe in the ditch to
provide excess length.
On insert work, additional pipe should be provided at ends of pipe being inserted.
For trenchless installation, refer to the use of"Safe Pulling Forces" later in this specification and
Specification 3.19, Trenchless Pipe Installation.
At tie-in locations, the pipe should be cut long so that the tie-in fittings are in compression when installed.
Whenever possible, make tie-ins during the cooler part of the day, after the pipe has cooled to ground
temperature. This is particularly important for insert construction and where clearance problems prohibit
the pipe from being "snaked".
Tracer Wire
Plastic pipe that is not encased in steel must have an electrically conducting tracer wire buried with the
pipe for locating the pipe while underground. Insulated #12 solid type coated tracer wire shall be installed
so that the wire is taped (with black electrical tape)to the upper half of the pipe at no more than 20 foot-
intervals. When installing pipe around a bend, tracer wire may need to be taped at closer intervals to
ensure that wire is in line with pipe after being backfilled for more accurate locates. Do not wrap the wire
around the buried pipe or the PE service tee tower. Refer to Drawings A-35776 at the end of this
specification.
For plastic pipe that is encased in steel, maintain continuity of the tracer wire by insertion of tracer wire
along with the plastic through the steel casing. It is recommended that multiple strands of tracer wire be
used to ensure at least one remains unbroken. Cadwelding of the tracer wire to each end of the steel
casing is one means of maintaining continuity but is not preferred as it lowers the level of cathodic
protection on the tracer wire.
A#10 yellow solid or stranded wire should be used when boring plastic pipe or when installing pipe via
split and pull. The heavier gauge wire will allow for added strength during the pullback process. It is
recommended that multiple strands of tracer wire be used to ensure at least one remains unbroken.
When boring, it is not necessary to tape the wire to the pipe as you would in an open trench installation
since the tape is likely to come off during pullback. Once the installation is completed, the tracer wire(s)
should be checked for continuity to confirm at least one was not damaged.
When transitioning from steel main to plastic main, two#10 wires shall be properly attached to the steel
main, and a tracer wire installed with the plastic main. Bring the two#10 wires and the plastic main's
tracer wire up into a CP test box. Do not tie wires together. Refer to Drawing B-39147 at the end of this
specification for details. Reference Specification 3.16 for tracer wire attachments to services.
PIPE INSTALLATION REV. NO. 23
PLASTIC MAINS DATE 01/01/25
Xv sm a STANDARDS 5 OF 14
utilities NATURAL GAS SPEC. 3.13

A 4-1/2 lb. zinc anode should be installed on the tracer wire at intervals not to exceed 1000 feet to
prevent corrosion of the tracer wires. At the end of each plastic main, a 4-1/2 lb. anode shall be installed
on the tracer wire to help with current flow for locating. When possible, install a pipe stub marker, pipeline
marker, or little fink at the end of a plastic main and bring the tracer wire above ground to assist in
locating. The tracer wire should be installed inside the pipe stub marker or installed along the outside of
the pipeline marker, terminated approximately 12-inches above grade. Do not strongly affix tracer wire to
pipe stub marker or pipeline markers to prevent wire damage if marker is struck. Recommended practice
is a half-hitch knot around the pipe stub marker or pipeline marker.
In order to monitor continuity of tracer wire and for locating, cathodic test stations should be installed as
needed i.e., approximately every 1000 feet where there is no place to connect to the system for locating,
such as a service. Refer to drawing B-39147 at the end of this specification for details.
At the riser, the tracer wire should be terminated (clipped) so that it does not make contact above the
insulated valve or with the meter, which can cause a cathodic short across the insulated fittings. Ensure a
sufficient amount of wire is left aboveground to allow connection to and testing with a multi-meter. The
tracer shall be secured to the meter riser with a half-hitch knot(do not tape wire to riser; this can trap
moisture and cause corrosion).
Wire Connections
Tracer wires will be joined by a direct-bury splice kit (in line or"Y" connection). Maintain electric continuity
at wire connections.
Joining and splice connections shall be either encapsulated in a dielectric type of gel connector which is
the preferred method, or a crimped sleeve covered by an approved dielectric sealing compound (such as
Aqua-Seal) and tape wrapped. For encapsulated connectors involving two or more cut wires, the wires
should be tied together loosely with an over-the-hand type knot approximately 6 inches to 12 inches from
the end of the wires prior to installing wires into the connector. This knot alleviates strain on the wire
connection. For encapsulated connectors involving one cut and one uncut wire, a strain relieving knot or
other wire strain relieving method is not necessary. Refer to Drawing A-36277 at the end of this
specification for encapsulated connector details.
Pulling Limitations
Polyethylene pipe may be pushed through a casing or"planted"with a plow-type chute arrangement. It is
not to be pulled through a casing pipe with mechanical equipment or pulled through the ground with a
plow unless special precautions are taken to eliminate the possibility of overstressing. Using a pulling
head incorporating a break-away device or"weak link" are two methods of eliminating the possibility of
overstressing and are discussed later in this specification. Additionally, it is recommended that pulling
forces be monitored via pressure gauge when equipment permits.
Plowing and Planting
Plowing and planting involves cutting a narrow trench and feeding the pipe into the trench through a shoe
or chute fitted just behind the trench cutting equipment. The shoe or chute should feed the pipe into the
bottom of the cut. The minimum short-term bending radius for plastic pipe during plowing installations is
as indicated in the following table:
PIPE INSTALLATION REV. NO. 23
PLASTIC MAINS DATE 01/01/25
Xv sm a STANDARDS 6 OF 14
utilities NATURAL GAS SPEC. 3.13

Minimum TemporaryBending Radius
Pipe Size SDR Outside Diameter in. Minimum Chute Bending Radius* in.
1/2" CTS 7 0.625 6
3/4" IPS 11 1.05 10
2" IPS 11 2.375 20
4" IPS 11.5 4.5 41
6" IPS 11.5 6.625 59
*Calculation from Plastics Pipe Institute Handbook of Polyethylene Pipe 2nd Edition, Chapter 10 Table 3
Small diameter coiled pipe is usually fed over the trenching equipment and through the shoe. Straight
lengths may be butt fused into a long string, then fed over and through the shoe. Plowing shoes or chutes
should be inspected periodically to assure that they are not worn and that the pipe does not kink or bind
on the shoe during installation.
Plowing operations should be completed in materials acceptable for padding (sometimes referred to as
bedding) pipe. Prior to plowing, a subsurface review of the soil conditions shall be conducted to determine
the acceptability of the soil to plowing and future padding of the installed pipe. Soil should be primarily
sand or cohesive earth with a minimum of rock.
Caution Tape
When plowing in PE pipelines that are 2 inches and larger, yellow gas caution tape with the words to the
effect"CAUTION, GAS LINE BURIED BELOW' should be installed approximately 12 inches above the
pipeline. This tape shall be installed with the pipe by feeding the tape through one of the chutes on the
plow.
The use of caution tape should also strongly be considered in open-trench pipeline installations. These
types of locations may include but are not limited to installations within private easements and dry-line
installations where the presence of a gas pipeline may be unexpected to excavators.
Marker Balls
Marker balls should be installed at ends of main, ends of service stubs, valves, and in other applicable
instances in order to facilitate finding these fittings and locations in the future. Ensure as-built drawings
and the resulting mapping records are updated to indicate the presence of these locating devices. Marker
balls shall be installed with a minimum of 4 inches of vertical clearance to the buried gas facilities. The
marker ball cannot be buried deeper than 4 feet from finish grade to allow for accurate locating.
Considerations should be made to install additional marker balls for facilities at depths, or anticipated
depths, greater than 4 feet: one being placed near the buried facility and another being no more than 4
feet deeper than finish grade, or no deeper than 1 foot from finish grade for areas where seasonal
snowpack occurs.
Dry Line Installations
As a general rule, dry line gas lines should not be installed unless there is a high degree of certainty that
the line will be "gassed up" within three years. Additionally, consideration should be given to abandoning
dry lines that have been in place for five years or greater to lessen the burden of ongoing locating of the
facility. If the need arises to bring into service a former dry line that has been abandoned, it can be done
in accordance with Specification 5.17, Reinstating Abandoned Gas Pipelines and Facilities. Refer to
Specification 3.18, Dry Line Pipe for additional details on pressure testing of dry line pipe.
PIPE INSTALLATION REV. NO. 23
PLASTIC MAINS DATE 01/01/25
Xv sm a STANDARDS 7 OF 14
utilities NATURAL GAS SPEC. 3.13

Pulling-in
Pulling-in involves cutting a trench, then pulling the pipe in from one end of the trench. Pulling-in may be
accomplished as a simultaneous operation by attaching the leading end of the pipe behind the trench
cutter or as a separate operation after the trench has been opened. In either case, pulling-in requires a
relatively straight trench and the pulling force applied to the pipe must not exceed what might damage the
pipe. Refer to"Safe Pulling Forces" below for additional information. This method should be limited to
shorter runs. Care shall be taken when pulling in pipe to protect the exterior pipe surface. Sandbags and
sand padding (sometimes referred to as bedding)to be placed in the trench to support and protect the
exterior of the pipe during pull-in.
Safe Pulling Forces
When polyethylene pipe is subjected to a significant short-term pulling stress, the pipe will stretch
somewhat before yielding. This is a possibility during pull-in installation and horizontal directional drilling
as well as split and pull procedures described further in Specification 3.19, Trenchless Pipe Installation.
The safe pulling force as shown in the following table assures that the pulling stress in the pipe is limited
to about 40 percent of its yield strength, the level at which the pipe will recover undamaged to its original
length in a day or less after the stress is removed. The safe pull force for polyethylene pipe is determined
by the following equation:
Safe Pull Force (lbs) = FYFTTy7r(OD z) (SDR
SDRz/
Where:
Fv=Tensile yield design factor
FT= Time under tension design factor
Tv=PE material yield strength
OD = Outside diameter, inches
SDR = Standard dimension ratio
Factor Recommended Values
Fv 0.40*
FT 1.00 for up to 1 hour pull 1 0.95 for u to 12 hour pull 0.91 for u to 24 hour pull
Tv (PE 2,600 psi at 2,300 psi at 100OF 1,900 psi at 120OF 1,500 psi at 140OF
2406/2708 730E
*To prevent plastic deformation and allow for full strain recovery, tensile stress in PE should not exceed
40% of yield strength
The safe pull forces for PE 2406/2708 medium density PE pipe for varying pipe temperatures, diameters
and SDRs used by Avista are shown in the following tables:
Safe pulling forces at a pipe temperature up to 730F (PE 240612708)
Safe Pull Force Safe Pull Force Safe Pull Force
Outside Standard (Ibs) (Ibs) (Ibs)
Pipe Size Diameter Dimension for up to 12 for up to 24
(In) (In) Ratio (SDR) up to 1 hour pull hour pull hour pull
'/2 CTS 0.625 7 156 148 142
% IPS 1.050 11 298 283 271
21PS 2.375 11 1,523 1,447 1,386
41PS 4.500 11.5 5,253 4,990 4,780
61PS 6.625 11.5 11,385 10,816 10,361
PIPE INSTALLATION REV. NO. 23
PLASTIC MAINS DATE 01/01/25
Xv sm a STANDARDS 8 OF 14
utilities NATURAL GAS SPEC. 3.13

Safe pulling forces at a pipe temperature between 740F and 100OF (PE 2406/2708)
Safe Pull Force Safe Pull Force Safe Pull Force
Outside Standard (Ibs) (Ibs)
Pipe Size Diameter Dimension (Ibs) for up to 12 for up to 24
(In) (In) Ratio (SDR) up to 1 hour pull hour pull hour pull
'/2 CTS 0.625 7 138 131 126
3/4IPS 1.050 11 263 250 240
2 IPS 2.375 11 1,347 1,280 1,226
41PS 4.500 11.5 4,647 4,414 4,229
61PS 6.625 11.5 10,072 9,568 91165
Safe pulling forces at a pipe temperature between 101°F and 120°F (PE 2406/2708)
Safe Pull Force Safe Pull Force Safe Pull Force
Outside Standard (Ibs) (Ibs)
Pipe Size Diameter Dimension (Ibs) for up to 12 for up to 24
(In) (In) Ratio (SDR) up to 1 hour pull hour pull hour pull
'/2 CTS 0.625 7 114 108 104
3/4IPS 1.050 11 218 207 198
21PS 2.375 11 19113 19057 19013
41PS 4.500 11.5 39839 39647 39493
61PS 6.625 11.5 89320 79904 71571
Safe pulling forces at a pipe temperature between 121°F and 140°F (PE 2406/2708)
Do not pull back if the pipe temperature is above 140°F
Safe Pull Force Safe Pull Force Safe Pull Force
Outside Standard (Ibs) (Ibs) (Ibs)
Pipe Size Diameter Dimension for up to 12 for up to 24
(In) (In) Ratio (SDR) up to 1 hour pull hour pull hour pull
'/z CTS 0.625 7 90 86 82
% IPS 1.050 11 172 163 157
21PS 2.375 11 879 835 800
41PS 4.500 11.5 3,031 2,879 2,758
61PS 6.625 11.5 6,569 6,240 5,977
If these safe pulling forces are exceeded, the pipe should be abandoned, and the pull-in operation
repeated, or the pipe should be installed by other means. Just because pipe does not break when pulling
forces are exceeded does not mean that it may not be irreparably damaged. When the pull force exceeds
the above limits, the pipe may begin to yield (stretch)to a point where it will not recover to its original
length. As polyethylene pipe will stretch as much as 800 percent to 1000 percent before it breaks, it may
be visually impossible to tell if the pipe integrity has been damaged if the safe pull force is exceeded. To
help assure safe pulling forces are not exceeded during installation of plastic pipe by mechanical means
(bore machine, backhoe, winch, etc.) a break-away device or a "weak link" shall be utilized during any
trenchless installation methods.
During pull-back, it is recommended that the exit pit farthest away from the pull-back machine be
monitored to ensure the pipe being pulled maintains a constant rate of pull-back until installation is
complete. Pipe that shows a slowed rate of installation or stops moving at the exit pit may be an indication
of the pipe being stuck in the bore hole during pull-back. Plastic (polyethylene) pipe may stretch slightly
PIPE INSTALLATION REV. NO. 23
PLASTIC MAINS DATE 01/01/25
Xv sm a STANDARDS 9 OF 14
utilities NATURAL GAS SPEC. 3.13

during the pulling operation and care should be taken to allow the pipe to recover to its original length
before it is tied in (this may take as long as 24 hours). To assure the pipe has recovered to its original
length after pullback, it is recommended that the pipe be allowed to rest in place for a period of time equal
to or greater than twice the time of pull-back or one hour, whichever is greater, up to a maximum rest time
of 24 hours before making tie-ins at either end. One way to verify pipe recovery is to compare the
measured length of the pull-back with the length of the pipe installed as determined by calculating the
differences in footage markings stenciled on the pipe.
Tie-ins may be completed without a wait period if all of the following conditions are met:
1. The HDD or split-and-pull length does not exceed 500 feet.
2. A"weak link" of reduced pipe diameter is used, not a break away pin (shear pin).
3. The "weak link" must not show any elongation during pullback. This shall be verified by
measuring the length of the weak link before and immediately after the HDD or split-and-pull
operation is completed. These measurements shall be recorded and documented in the job
paperwork. If the"weak link" shows any elongation, the pipe shall rest per the times described in
the paragraph above prior to performing any tie-ins.
Break—Away Pin or Weak Link
Pipe should be pulled-in behind a pulling head, typically shaped like a bullet that is one or two pipe
diameters larger than the pipe being pulled-in. Refer to "Pullback" in Specification 3.19, Trenchless Pipe
Installation for additional information. In order to assure the safe pull force is not exceeded during
mechanical pullback, a calibrated break-away pin or"weak link" shall be used between the pulling head
and the gas pipe as described below.
A"weak link" can be used between the pulling head and the gas pipe in lieu of a calibrated break-away
pin. A"weak link" shall consist of a one foot long (minimum)section of pipe measuring at least one
available stock pipe diameter smaller than the pipe to be pulled and composed of the same material (for
the purposes of a weak link, unimodal PE is considered the same material as bimodal). However, using
the "weak link"will not always assure that the amount of pulling force being applied is not exceeding the
safe pull force of the gas pipe (again, defined as 40 percent of the gas pipe's yield strength, the level at
which the pipe will recover undamaged to its original length in a day or less after the stress is removed).
In some cases, the pulling force exerted on the gas pipe with the "weak link" method using one pipe size
smaller may reach 60 percent of the yield strength before the "weak link"fails. In this case, the pipe will
still only stretch to a point where it will return to its original length, but this may take longer than 24 hours.
If a break away pin or"weak link"fails during a pullback installation, and it can be shown that the carrier
pipe was not subjected to unsafe pulling forces or pulling stresses greater than 40 percent of the pipe's
yield strength then it is acceptable to utilize the installed pipe without abandonment. Contact Gas
Engineering for review prior to proceeding.
Static Charges
Static electric charges may build up on both the inside and outside surfaces of polyethylene pipe.
Localized static electricity build-up occurs because polyethylene pipe does not readily conduct electricity.
Charges are generated by physical handling or by the high velocity flow of gas through polyethylene
mains and services (i.e., purging, flow of gas through restriction). Discharge of static electricity can cause
unpleasant shocks or ignite a gas-air mixture. Refer to Specification 3.34, Squeeze-Off of PE Pipe and
Prevention of Static Electricity for specific requirements.
PIPE INSTALLATION REV. NO. 23
PLASTIC MAINS DATE 01/01/25
Xv sm a STANDARDS 10 OF 14
utilities NATURAL GAS SPEC. 3.13

Examining Buried Pipe
When previously buried plastic pipe is exposed, an Exposed Piping Inspection Report (Form N-2534)
shall be completed in accordance with Specification 3.44, Exposed Pipe Evaluation.
Pigging of Pipe
Refer to Specification 3.12, Pigging of Pipe, for more information.
Odorizing Newly Installed Pipe
Newly installed pipe may present challenges with regards to meeting the required odorant detection
levels as defined in Specification 4.18, Odorization Procedures. New pipe, especially which is gassed up,
but not immediately put into service, tends to absorb odorant in the pipe walls. Consideration should be
made to "pickle" such pipe per the sub-section titled "Pickling Newly Installed Piping" in Specification
4.18, Odorization Procedures.
Pressure Testing
New or replaced main and new, replaced, or reconnected services transporting natural gas must be
pressure tested. Refer to Specification 3.18, Pressure Testing for specific requirements.
Updating Maps and Records
Employees responsible for construction activities shall ensure field as-built documents are completed
immediately following construction, repair, or abandonment of facilities. Field as-built documents shall be
subsequently mapped by the district GIS Editor within the electronic mapping system to allow for accurate
gas facility locating and incorporation into maintenance schedules. The district manager in which the
construction activities take place is responsible to ensure that field work as-built documents are
completed and mapped in a timely manner. In Washington, this shall be completed within 6 months
following the completion of the field work. In Idaho and Oregon this is a best management practice.
WAC 480-93-018 (5): Each gas pipeline company must update its records within 6 months of when it
completes any construction activity and make such records available to appropriate company
operations personnel.
PIPE INSTALLATION REV. NO. 23
PLASTIC MAINS DATE 01/01/25
Xv sm a STANDARDS 11 OF 14
utilities NATURAL GAS SPEC. 3.13

r
LING PIPE AROUND A CORNER,
TAPING OF TRACER AROUND
REQUIRED TO KEEP TRACER WIRE
H PIPE DURING BACKFILLING.
TRACER WIRE
BLACK ELECTRICAL TAPE
sF,p`,GF
NOTE: MAXIMUM DISTANCE IS 20 FEET;
HOWEVER, TRACER WIRE MAY NEED TO BE
TAPED AT CLOSER INTERVALS TO ENSURE
THAT WIRE IS IN LINE WITH THE PIPE
AFTER BACKFILLING.
DISTRIBUTION GAS
STANDARD
TAPING TRACER WIRE TO PIPE DETAIL
AVISTA CORP
SPOKANE WASHINGTON
NONE 6-22-01 APPROVED
SCALEAT
DSN. BURGER CKD.� 7-2-01
1 11-08 CORRECTED TO DATE DLO KEI DR C Nro. sHr 1 DATE
NO DATE REVISION BY CKD CKD. NTD. JW CF 1 A-35776
PIPE INSTALLATION REV. NO. 23
PLASTIC MAINS DATE 01/01/25
x rv#ST,aa STANDARDS 12 OF 14
Utilities NATURAL GAS SPEC. 3.13

ENCAPSULATED ENCAPSULATED
CONNECTOR CONNECTOR
N N
TIE KNOT TIE KNOT
6-12" FROM 6-12" FROM
ENCAPSULATED ENCAPSULATED
CONNECTOR CONNECTOR
(3) CUT WIRES (2) CUT WIRES
ENCAPSULATED
CONNECTOR
N N
TIE KNOT TIE KNOT
6-12" FROM 6-12" FROM
ENCAPSULATED ENCAPSULATED
CONNECTOR CONNECTOR
ENCAPSULATED SPLICE FOR NO SLACK CONDITION
CONNECTOR (2 OR 3 CUT WIRES)
UNCUT WIRE CUT WIRE
DISTRIBUTION GAS
STANDARD
TRACER WIRE&NUTS/LUGS
(1) CUT & (1) UNCUT WIRE
a AVISTA CORP
_ SPOKANE,WASHINGTON
�? SNONE 12-1-2004
CALE DATE Rov
�
2 9-23-21 STANDARDS UPDATE CGD MY
No DSN TJ CKD TU Crl2-2-04
M 1 10-7 MODIFY MINIMUM LENGTHS CL O>� DR JW NTD SHT 1 DATE
rn
04
NO DATE REVISION BY CKD CKD NTD J W OF _ A-36277
AUTOCAD DWG
PIPE INSTALLATION REV. NO. 23
PLASTIC MAINS DATE 01/01/25
,X-v, sra STANDARDS 13 OF 14
utilities NATURAL GAS SPEC. 3.13

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PIPE INSTALLATION REV. NO. 23
PLASTIC MAINS DATE 01/01/25
��r�sra STANDARDS 14 OF 14
Utilities NATURAL GAS SPEC. 3.13

3.14 PRE-CHECK LAYOUT AND INSPECTION
SCOPE:
To provide guidelines for layout and inspection of a job site prior to construction.
REGULATORY REQUIREMENTS:
§192.325(c)
CORRESPONDING STANDARDS
Spec. 3.12, Pipe Installation— Steel Mains
Spec. 3.15, Trenching and Backfilling
Spec. 4.13, Damage Prevention Program
PRELIMINARY INSPECTION AND LAYOUT:
General
The job location for gas pipeline installations, extensions, or replacements shall be inspected prior to any
work. During this inspection, the proposed Avista installation should be pre-marked in white paint so that
other affected parties can determine Avista's worksite.
Pre-Construction Notification for Locate Tickets
After inspecting the job site, mark the proposed installation location(s)with white marking paint or other
appropriate white marking materials prior to requesting a locate ticket through the local One Call System.
The One Call System shall be notified with the appropriate description of the dig area so that the locators
for underground facilities identified on the ticket can locate and mark the appropriate area prior to
construction. The requestor must include in the description, a contact name and phone number in case
there are questions by facility locators with regard to the locate ticket request.
Note: When filling out the locate ticket request, be sure to select (as applicable)the "Type of Work"that
most accurately reflects the work that will be done.
Notifications for locates shall be made at least 2 business days prior to planned construction (Saturdays,
Sundays and federal/state holidays are not"business days"). EXCEPTION: An exception to this
notification timeframe is when Avista is responding to a gas emergency. In this case, a notification for
locates must be made as soon as possible and Avista shall take reasonable care to protect underground
facilities. For further information on One Call Notification, see Specification 4.13, "One Call Notification
System", "Requests for Locates Through One Call", and "Requesting Emergency Locates."
An EMERGENCY in this instance, means any condition involving a clear and present danger to life,
property, or a customer service outage. In Oregon, the definition includes interruption of essential public
services and in Idaho the definition includes blockage of roads/transportation facilities that require
immediate action.
Design Locates (Oregon)— Facility locators have 10 days to respond to the request by locating and
marking facilities, providing best available information, or by contacting the person requesting the design
information to provide facility information. The excavator shall either maintain the markings, or if required
by state dig laws, request for new locates to be made. Consult the respective state underground dig laws
for specifics and refer to Specification 4.13, Damage Prevention Program, as noted above, for additional
information.
PIPE INSTALLATION REV. NO. 11
PRE-CHECK LAYOUT AND INSPECTION DATE 01/01/25
Xv sm a STANDARDS 1 OF 2
utilities NATURAL GAS SPEC. 3.14

Pre-Construction Inspection
Job planning should consider expected traffic conditions and necessary barricade requirements in
accordance with good safety practices, local safety ordinances, and Avista's Incident Prevention Manual
(Safety Handbook). Job planning should also consider possible conflict with other construction work in
immediate area.
Verify that underground structures which might be encountered during excavation are clearly marked by
the utility, city, municipality, or agency to which they belong.
When pipe is delivered and unloaded on the job site prior to the start of the work, it shall be placed in
such a way as to offer a minimum hazard to vehicular or pedestrian traffic and with consideration to keep
it protected from damage.
Pipeline materials shall be inspected for any damage prior to the start of installation. Damaged pipe or
fittings shall not be installed. If the coating on steel pipe is damaged, but the pipe itself is not, the coating
shall be repaired per Specification 3.12, Pipe Installation—Steel Mains.
Layout
When running a main extension in a residential area or commercial area, consideration should be given
to notifying property owners of impending construction. This may include written or verbal
communications and should include project purpose, duration, and method of inquiry about potential gas
service hookup.
Mains should run parallel to street, alley, or highway centerlines. Gas mains should be located on the
opposite side of the street from water mains where possible.
Gas mains shall not run through manholes or footings but shall be offset around them unless a utility
sleeve has been specifically approved by the impacted utility and Gas Engineering.
Joint Ditch
When installing mains and services in a joint trench with electric, telephone, fiber optic, cable TV, or any
other unspecified utility, consult the Avista Electric Service and Meter Requirements for ditch and service
stub requirements, or other local utility guidelines, as well as clearances as outlined in Specification 3.15,
Trenching and Backfilling. Gas should not be installed in a joint ditch with sewer.
PIPE INSTALLATION REV. NO. 11
PRE-CHECK LAYOUT AND INSPECTION DATE 01/01/25
XvISTA STANDARDS 2 OF 2
utilities NATURAL GAS SPEC. 3.14

3.15 TRENCHING AND BACKFILLING
SCOPE:
To establish uniform procedures for trenching, backfilling, and post-installation marking of natural gas
piping systems.
REGULATORY REQUIREMENTS:
§192.319, §192.325, §192.327, §192.361, §192.707
OAR 952-001-0070
WAC 480-93-124, 480-93-170
CORRESPONDING STANDARDS:
Spec. 2.12, Pipe Design - Steel
Spec. 2.13, Pipe Design — Plastic
Spec. 3.13, Pipe Installation, Plastic (Polyethylene) Mains
Spec. 3.44, Exposed Pipe Evaluation
Spec. 5.15, Pipeline Patrolling - Pipeline Markers
TRENCHING REQUIREMENTS:
General
Persons who operate excavating, boring, or trenching equipment (backhoes, track excavators, trenchers,
drilling machines, etc.) shall be experienced and knowledgeable on each piece of equipment being used.
Cover
High pressure transmission lines shall be installed with a minimum of 36 inches of cover in normal soil (42
inches is preferred) and have at least 24 inches of cover in consolidated rock.
High pressure distribution mains should be installed with a minimum of 36 inches of cover(42 inches is
preferred), but in all cases shall be installed with a minimum of 24 inches of cover.
Intermediate pressure mains should be installed with a minimum of 30 inches of cover, but in all cases
shall be installed with a minimum of 24 inches of cover.
Services should be installed with a minimum of 24 inches of cover but in all cases shall be installed with a
minimum of 18 inches cover in streets and roads, and 12 inches of cover on private property. Service
risers may be installed at a depth between 18 and 24 inches to prevent covering the `Do not bury' line on
the riser. In these circumstances, the service piping should transition to a minimum cover depth of 24
inches as soon as practical. Consideration should be given to install that portion of a service residing
within the road right-of-way at depths equivalent to a standard main depth. Additional cover may be
required on road crossings by the local jurisdiction.
Where an underground structure prevents the installations of a pipeline with the minimum cover, the
pipeline may be installed with less cover if it is provided with additional protection to withstand anticipated
external loads and the install approved by Gas Engineering. Any additional protection should not prevent
an ability to maintain the pipeline. Additional cover should be provided as needed to assure protection of
pipeline from other structures and future erosion or removal of cover.
PIPE INSTALLATION REV. NO. 23
TRENCHING & BACKFILLING DATE 01/01/25
X-4, sr'a STANDARDS 1 OF 9
Utilities NATURAL GAS SPEC. 3.15

Pipe which is installed by open trenching in a river or stream must have a minimum cover of 48 inches in
soil or 24 inches in consolidated rock and requires approval of Gas Engineering. For boring depth
requirements refer to Specification 3.19, Trenchless Pipe Installation Methods.
Clearances— Steel and PE Pipelines
Each gas pipeline should be installed with a minimum 12-inch separation from any foreign utility crossing
and for pipelines operating at 20 percent SMYS or greater this clearance is a requirement. If this
clearance cannot be maintained, the pipeline must be installed with enough clearance to allow for proper
maintenance of the facilities and be protected from damage that might result from proximity to other
utilities. Consideration should be made to protect against physical and cathodic damage that might occur
from close proximity to other structures or utilities. For PE pipelines, a casing or conduit may be used to
provide the extra measure of protection.
Each gas pipeline, including services, should be installed with a 5-foot minimum horizontal separation
from sanitary sewer and storm water pipelines or at a further distance as specified by the appropriate
regulating agency. If the sewer is pressurized, a 3-foot horizontal separation is sufficient.
No gas pipelines, including services, shall be installed through, above, or below a septic drain field
without approval of Gas Engineering. A minimum separation of 10 feet (25 feet preferred)from sewer
drain lines and leech fields should be maintained. Septic and sewer systems afford an easy path for gas
migration should a leak ever occur.
Each pipeline including services should be installed with a 3-foot minimum horizontal separation from
other non-gas underground utilities or at a further distance as specified by the appropriate regulating
agency. If this clearance cannot be maintained, the pipeline must be protected from damage that might
result from proximity to the other structure. Consideration should be made to protect against physical and
cathodic damage that might occur from close proximity to other structures or utilities.
When necessary or expedient, plastic pipe may be installed in a joint trench with other utilities. A
horizontal separation not less than 12-inches should be maintained. If this clearance cannot be
maintained, the pipe must be installed with enough clearance to allow for proper maintenance of the
facility and be protected from damage that might result from proximity to the other utilities sharing the
trench. Gas should not be installed in a joint trench with sewer.
Customer's gas piping should not be installed within 12 inches of Avista's gas pipeline. Each gas pipeline
must be installed with enough clearance from any other underground structure to allow proper
maintenance and to protect against damage that might result from proximity to other structures.
Plastic pipe shall not be installed closer than 10 feet of a steam or hot water pipeline and in general
should not be installed in an area where steam or hot water distribution systems are located. Each gas
pipeline should be installed with a minimum of 12 inches of clearance from a culvert while maintaining the
minimum cover requirements.
Pipelines installed adjacent to buildings should be done so with a concern for future maintenance and an
awareness of the possibility of gas becoming trapped under the building should a leak occur. Mains shall
be located a minimum of 5 feet from the foundation of a building. Services (excluding the meter riser
itself) shall be located a minimum of 2 feet from the foundation of a building. Where feasible, install
service lines more than 2 ft from a building. See also "Location Considerations" in Specification 3.16,
Services.
PIPE INSTALLATION REV. NO. 23
TRENCHING & BACKFILLING DATE 01/01/25
X-4, sr'a STANDARDS 2 OF 9
Utilities NATURAL GAS SPEC. 3.15

Vegetation Clearance
Gas distribution intermediate pressure mains (and services when possible)should be installed with
consideration for vegetation root growth and its impact on the pipeline. To prevent damage from
vegetation root growth the minimum clearance from a tree should be determined by measuring the
diameter of the tree (in inches)at a height of 4.5 feet above finish grade and multiplying that value by 1 to
1.5. This value is the critical root zone (in feet) per the International Society of Arboriculture.
For example, a tree with a 4 inches in diameter trunk (measured 4.5 feet above grade)will have a critical
root zone of 4 feet to 6 feet. For trees that are not fully mature or for special circumstances, the critical
root zone should be estimated based on the best available information for that tree species in the region.
Small bushes, shrubs, etc. should have at least 5 feet of horizontal clearance from the edge of the gas
facilities.
Shoring and Excavating Safety
Avista employees engaging in trenching, excavating, or shoring activities shall follow the procedures
outlined in Avista's Incident Prevention Manual (Safety Handbook). Others contracting work for Avista are
required to follow the respective state OSHA requirements. Avista's Safety Department shall be consulted
for excavations greater than 20 feet of depth.
Inspections shall be made of excavations, trenches, adjacent areas, and protective systems by a
"competent person" as defined in the Avista's Incident Prevention Manual (Safety Handbook). Such
inspections shall be performed at the start of work and as needed throughout the course of the job in
order to determine if conditions exist that could result in a cave-in, failure of protective systems, or other
hazardous situations. When the "competent person"finds evidence of a situation that could result in a
possible cave-in, failure of protective systems, or other hazardous conditions, affected employees shall
be removed from the area until the necessary precautions have been taken.
Underground utilities that have been located and exposed during the course of the construction or
excavation process shall be protected, supported, or removed as necessary to safeguard employees and
to prevent damage to the utilities.
Manufactured materials and equipment used for protective systems shall be used and maintained in
accordance with the manufacturer's instructions. Any suspected defect in such protective systems shall
be reported and corrected before use by any employee.
Trench Excavation
Trenches must be wide enough for installing pipe without damaging coating or inducing unnecessary
stresses on the pipe. At horizontal angles, the trench must have sufficient width to accommodate the
welding elbow or bend and provide clearance between the side of the trench and the pipe. See applicable
drawings at the end of the Specification for additional details.
Examining Buried Pipe
When previously buried steel or plastic pipe is exposed, an Exposed Piping Inspection Report Form
(Form N-2534)shall be completed in accordance with Specification 3.44, Exposed Pipe Evaluation.
PIPE INSTALLATION REV. NO. 23
TRENCHING & BACKFILLING DATE 01/01/25
X-4, sr'a STANDARDS 3 OF 9
Utilities NATURAL GAS SPEC. 3.15

Padding Material
When the bottom of the trench does not provide for a smooth and firm base for the pipe due to rock, etc.
a minimum padding (sometimes referred to as bedding)of 6 inches of cohesive earth or sand with
maximum aggregate of 3/4-inch size shall be used.
This material may be obtained from screened native soil or by import. This soil should consist primarily of
fines and have a minimum of sharp edge aggregate. Soil should be of a nature to allow a firm compacted
surface providing uniform support for pipe. Refer to Specification 3.13, Pipe Installation - Plastic
(Polyethylene) Mains, "Plowing and Planting"for additional bedding requirements when plowing.
Controlled-Density Backfill
Some jurisdictions may require the use of controlled density backfill (CDF) near gas mains to enhance
compaction during roadway construction. Foreign utilities may use CDF material between Avista's gas
mains and their facilities when minimum clearances are difficult to achieve. If CDF is used, it shall not be
placed directly on the pipe. A minimum of 6 inches of padding (sometimes referred to as bedding)
material shall be placed around Avista's mains before CDF material is placed.
When gas pipe is exposed adjacent to other construction / utility projects, the gas pipe shall be sufficiently
supported so that no pipe movement occurs. This can be accomplished by strapping, blocking, or other
measures as approved by an Avista Inspector or another qualified individual. Care shall be taken to
restore original compaction upon backfilling.
Backfill
A backfill of 6 inches using material as described above in Padding Material should be placed over the
top of the pipe to prevent damage from rocks while backfilling. If exceptionally large rocks (8 inches or
larger) are to be pushed back into the trench, an initial backfill of 12 inches of approved material should
be placed over the pipe.
If Caution Tape will be installed at the particular location, it is at the one foot level of cover that the tape
should be installed. Reference Specification 3.12, Pipe Installation - Steel Mains, and Specification 3.13,
Pipe Installation - Plastic Mains for additional information regarding the use of Caution Tape.
Backfill must provide firm continuous support under and around the pipe. It must be free of sharp objects,
rocks, frozen materials, large clods, or any other materials that could be detrimental to the pipe or pipe
coating. Materials used for support must be well compacted. Avoid using backfill or supporting materials
that could create undue stress or damage to the pipe. To allow for backfill settlement, at casing pipe gaps
and where plastic is located on disturbed earth; the pipe should be lifted slightly while the backfill is
packed underneath.
Compaction
Compaction levels shall be as specified by the appropriate regulating agency. In general, traveled
roadways and improved right of ways require 95 percent compaction. Driveways should be compacted
similar to roadways.
Heavily traveled roadways and arterials may have special requirements pertaining to sub-base
construction and compaction. Care should be taken to prevent damage to the buried gas facilities when
placing and compacting backfill.
PIPE INSTALLATION REV. NO. 23
TRENCHING & BACKFILLING DATE 01/01/25
X-4, sr'a STANDARDS 4 OF 9
Utilities NATURAL GAS SPEC. 3.15

Proper compaction should be provided under and around pipe and fittings at branch connections,
transitions, service connections, and riser locations to prevent differential settlement even if CDF will be
used. This should be accomplished by using hand operated tamping equipment(such as a hand tamper,
vibratory plate, whacker, or pogo stick)adjacent to the pipe.
Sand backfill may be placed directly on top of pipe or fittings. A minimum of 12 inches of backfill must be
in place before using hand operated tamping equipment directly over the pipe, or a minimum of 18 inches
if using equipment mounted compacting devices (such as a hoe-pack, or vibratory roller). A sheep's foot
style compactor attached to a backhoe or excavator requires at least 24 inches of cover. Consideration
should be made regarding the age of the pipe, operating pressure, and quality of backfill prior to allowing
these types of activity over gas mains. When construction activity occurs adjacent to or over existing
pipelines and facilities, these same cover requirements apply. If tamping or compaction activities are
planned to occur over an existing high pressure main with less than 24 inches of cover, contact Gas
Engineering.
Marking Pipe After Installation (OR)
In areas of ongoing excavation or construction (such as residential or commercial site development) in
Oregon, newly installed facilities shall be located and marked with locate paint or appropriate flagging for
backfilled facilities immediately upon placement. For shaded pipe in a ditch where Avista is not backfilling
the ditch, locate and mark using locate paint on the sand or"natural gas" caution/marking tape which may
be placed on the sand over the pipe using sand in various places to anchor the tape in place so that the
location of the pipe is still visible. (This is a requirement in Oregon per OAR 952-001-0070 (9)).
Pressure Testing After Backfilling
Plastic pipe should be installed and backfilled prior to pressure testing to bring attention to any potential
damage that may occur during the installation and backfill process. Pre-tested pipe may only be used
where it is not feasible to conduct a post construction pressure test.
Pipeline Markers
For further guidance, refer to Specification 5.15, Pipeline Patrolling and Pipeline Markers, in subsections
"Pipeline Markers for Buried Pipe"," Exceptions for Marking," "Washington Pipeline Marker
Requirements," and "Markers for Aboveground Pipelines."
Customer Trench/Ditch Detail Drawings
(See following pages)
PIPE INSTALLATION REV. NO. 23
TRENCHING & BACKFILLING DATE 01/01/25
X-4 sr'a STANDARDS 5 OF 9
Utilities NATURAL GAS SPEC. 3.15

BUILDING I
u SPOILS °
CUSTOMER
o BELLHOLE 12"MIN 2'MIN
(SEE DETAIL)
NEW r-- —,
METER --� i �� �. ��.�.;:��
CUSTOMER L— —J NATIVE BACKFILL INSTALLED
TRENCH o �� /, BY CUSTOMER
(SEE DETAIL) N �/\ ` `•
c PIPE&COVER
INSTALLED BY AVISTA
EXISTING
METER _z
COHESIVE SAND
SITE PLAN PROVIDED&INSTALLED
BY CUSTOMER
METER MOVE
TRENCH DETAIL
2'-6"MIN 2'-6"MIN ELEVATION VIEW
NOTES:
1. CUSTOMER IS RESPONSIBLE TO CALL FOR LOCATES
EXISTING 2 BUSINESS DAYS IN ADVANCE OF DIGGING.
PIPE z 2. HAND DIG WITHIN 24"OF EXISTING UTILITY LOCATE
MARKS.
3. MAINTAIN 12"CLEARANCE FROM OTHER UTILITIES.
4. PLACE SPOILS AT LEAST 2'FROM EDGES OF
EXCAVATION.
5. CUSTOMER RESPONSIBLE FOR ALL PIPING
DOWNSTREAM OF METER.
6. CUSTOMER SHALL HAVE 1 YARD OF SAND ON SITE
BELLHOLE DETAIL (UNLESS OTHERWISE SPECIFIED BY AVISTA
REPRESENTATIVE)PER 10'OF DITCH.
PLAN NEW 7. SOIL/SAND SHOULD BE COVERED DURING WINTER
MONTHS.
SPOILS $• AVISTA RESERVES THE RIGHT TO INSPECT AND
APPROVE ALL DITCHES PRIOR TO CREW INSTALL
2-6" MIN 2-6"MIN 2'MIN OF FACILITIES.
DUSTING PIPE '\
(DEPTH WILL VARY) DISTRIBUTION GAS
CONSTRUCTION SPECIFICATION
BELLHOLE DETAIL CUSTOMER SUPPLIED DITCH
ELEVATION VIEW FOR METER RELOCATION
AVISTA CORP
SPOKANE,WASHINGTON
4 9-21-23 STANDARDS UPDATE TJH MDY NNE 1 9-20-17 ROVED�
3 9-23-21 STANDARDS UPDATE CGD DRS SCALE DATE 4
DSN FORT CKD DRS 1 —18-17
2 10-12-20 STANDARDS UPDATE CGD f} DR MER�EDITH NTD SIT 1 DATE
NO DATE REVISION BY CKD CKD 77 NTD OF 4 A-38315
PIPE INSTALLATION REV. NO. 23
TRENCHING & BACKFILLING DATE 01/01/25
�rsr�r STANDARDS 6 OF 9
Utilities NATURAL GAS SPEC. 3.15

SPOILS
2'MIN
NATIVE FILL
N N
ELECTRIC/COMMUNCATKINS CONDUIT
Z SHOWN FOR HORIZONTAL CLEARANCE
ONLY CONSULT WITH APPROPRIATE UTILITY ELECT 3
FOR DEPTH AND OTHER REOUIREMENTS.
COMAS io
3" WIN 12*MIN 12'MIN 3"MIN
2 = GAS
s SAND OR AVISTA APPRO'vEC
o COHESIVE NATIVE o
BEDDING AND COVER
12"hNN 1 AS REQUNEO
SERVICE I JOINT USE UTILITY TRENCH DETAIL
TRENCH DETAIL
NOTES:
1. CUSTOMER IS RESPONSIBLE TO CALL FOR LOCATES 2 BUSINESS DAYS IN ADVANCE OF DIGGING.
2. HAND DIG WITHIN 24"OF POSTING UTILITY LOCATE MARKS.
3. ALL CUSTOMER DITCHES MUST PASS AVISTA INSPECTION.
4. A MINIMUM SEPARATION OF 10'(25'PREFERRED)FROM SEWER DRAIN LINES AND LEECH FIELDS SHOULD BE MAINTAINED.PLASTIC PPE
SHALL NOT BE INSTALLED THROUGH,ABOVE, OR BELOW DRAIN FIELDS_
5. GAS PIPE SHOULD HAVE A MINIMUM OF 3'SEPARATION FROM WATER AND 5'SEPARATION FROM SEWER. GAS PIPING SHOULD NOT BE
INSTALLED IN A JOINT TRENCH WITH SEWER
6. PLASTIC PIPE SHOULD BE INSTALLED WITH A MINIWM OF 12"OF CLEARANCE FROM CULVERTS.
7. TRENCH SHAH ALLOW FOR AT LEAST 12" RADIAL SEPARATION FOR ANY UTILITY CROSSINGS.
8. A MINIMUM BEDDING AND PADDING OF 6'OF COHESIVE SKID SHALL BE USED WHEN NATIVE MATERIAL IS NOT SUITABLE(NATIVE
MATERIAL MUST BE APPROVED BY AVISTA REPRESENTATIVE).NATIVE FILL SHALL BE FREE Of RUBBISH.CINDERS, CHEMICAL REFUSE.
ROCK LARGER THAN 4-.OR OTHER MATERIALS THAT COULD CAUSE DAMAGE TO THE PIPE.
9. SOIL/SAND SHOULD BE COVERED DURING WINTER MONTHS,
10. TRENCH SHALL ALLOW A MINIMUM 2'SEPARATION FROM ANY BUILDING FOUNDATION.WHERE FEASIBLE,D1G TRENCH MORE THAN 2'
FROM THE FOUNDATION.
11. FINAL GRADE SHOULD BE WITHIN 6- FROM TOP OF DITCH,
12. AVISTA RESERVES THE RIGHT TO INSPECT AND APPROVE ALL DITCHES PRIOR TO CREW INSTALL OF FACILITIES.
DISTRIBUTION GAS
CONSTRUCTION SPECIFICATION
PE NATURAL GAS SERVICE
CUSTOMER PROVIDED TRENCH DETAIL
6 11-1-24 STANDARDS UPDATE CGD BVB AVISTA CORP
SPOKANE. WASHINGTON
5 9-21-23 STANDARDS UPDATE TJH MDY ICGNE 19-25-17
E R D�
4 9-23-21 STANDARDS UPDATE CGD DRC SCALE
C DATE
oz D;N FORT CKD MS 1 -18-17
3 10-12-20 STANDARDS UPDATE LL-CKD
DR MEREDITH NTD SHT 2 DATE
NO DATE REVISION JprF NTD r"; of 4 A-38315
PIPE INSTALLATION REV. NO. 23
TRENCHING & BACKFILLING DATE 01/01/25
X-v sm a STANDARDS 7 OF 9
Utilities NATURAL GAS SPEC. 3.15

SPOILS
2'MIN
,7\—\7777\—
NATIVE FILL OR CDF
AS REQUIRED BY
a i a SOME JURISDICTIONS
� i I
a �w
_Uj L — CAUTION TAPE
z
�aa
v= o z
N
Z
iD
6" MIN+
G
SAND OR AVISTA APPROVED
Z COHESIVE NATIVE BEDDING
tO AND COVER
N
UTILITY CROSSING
(ABOVE OR BELOW)
GAS MAIN TRENCH DETAIL
NOTES:
REFER TO SPECIFICATION 3.14 AND 3.15 FOR CLEARANCES SHOWN IN DRAWING AND GIVEN BELOW.
REFER TO SPECIFICATION 3.42,CASING AND CONDUIT INSTALLATION,FOR GAS MAIN INSTALLATIONS UNDER RAILROADS AND HIGHWAYS.
IF INSTALLING GAS PIPE BY OPEN TRENCHING IN A RIVER/STREAM,INSTALL GAS MAIN WITH A MINIMUM 24 INCHES OF COVER IF AREA IS
CONSOLIDATED ROCK OR 48 INCHES OF COVER IF AREA IS STANDARD SOIL CONDITIONS.
1. IF LARGE ROCKS(8 INCHES OR LARGER)WILL BE PUSHED INTO THE TRENCH, 12 INCHES OF SUITABLE PADDING SHOULD BE INSTALLED.
2. FOR ROADWAYS AND IMPROVED RIGHT OF WAYS,95 PERCENT COMPACTION IS REQUIRED WITH THE FOLLOWING BACKFILL REQUIREMENTS:
o. 12 INCHES OF BACKFILL PRIOR TO MANUAL TAMPING.
b. 18 INCHES OF BACKFILL PRIOR TO EQUIPMENT MOUNTED COMPACTING DEVICES.
c. 24 INCHES OF BACKFILL PRIOR TO USING A SHEEP'S FOOT STYLE COMPACTOR ATTACHED TO A BACKHOE OR EXCAVATOR.
d. REFER TO LOCAL REGULATING AGENCY FOR SPECIAL MATERIAL AND LIFT THICKNESS REQUIREMENTS.
* IF NATIVE SOIL CONDITIONS MEET THE PADDING AND
BACKFILL REQUIREMENTS IN SPECIFICATION 3.15,THEN DISTRIBUTION GAS
6 INCH BEDDING MATERIAL AROUND THE PIPE IS NOT CONSTRUCTION SPECIFICATION
APPLICABLE.IN OTHER SCENARIOS WHERE A 6 INCH
TRENCH SIDEWALL BEDDING CLEARANCE IS NOT NATURAL GAS MAIN
NECESSARY,CARE MUST BE TAKEN TO PROTECT THE TRENCH DETAIL
PIPELINE FROM DAMAGE IN ACCORDANCE WITH BACKFILL
REQUIREMENTS IN SPECIFICATION 3.15. AVISTA CORP
SPOKANE, WASHINGTON
NONE 1 9-21-23 a OVER
SCALE DATE
DSN BENZEL CKD —1-23
0 9-21-23 STANDARDS UPDATE TJH MDY OR TJH NM_ SHT 3 DATE
NO DATE REVISION BY CKD CKo MDY NTD RLB of 4 A-38315
PIPE INSTALLATION REV. NO. 23
TRENCHING & BACKFILLING DATE 01/01/25
X-v sm a STANDARDS 8 OF 9
Utilities NATURAL GAS SPEC. 3.15

0
00
r
10'MIN 0 0�
(PE PIPE) °
= 12" FOR 1"OF TREE TRUNK DIA
MEASURED 54"ABOVE FINISH GRADE
(TREE)
5'MIN 5'MIN
(3'IF PRESSURIZED) (BUSH/SHRUB)
= I
0 3'MIN 10'MIN-25'PREFERRED
(OR PER LOCAL AGENCY) (DRAIN FIELD SEWER MAIN)
z U) Lp
t/7
a�� I cn
012" MIN
(JOINT TRENCH)
N
c 5'MIN
_ a (FOUNDATION)
12" MIN
STEAM/ STORM/ OTHER OTHER GAS CUSTOMER
HOT WATER SEWER UNDERGROUND UTILITIES AVISTA GAS
UTILITIES OR CULVERT
(ELEC.COMM,WATER,ETC) JOINT TRENCH
(PE PIPE ONLY,
NO SEWER)
AVISIA,MAIN G NOTE:
REFER TO SPECIFICATION 3.15 FOR CLEARANCES SHOWN IN DRAWING.
DISTRIBUTION GAS
CONSTRUCTION SPECIFICATION
UTILITY CROSSING NATURAL GAS MAIN
(ABOVE OR BELOW) CLEARANCES
v AVISTA CORP
SPOKANE, WASHINGTON
N NE 9-21-23 A ROVED
UTILITY CROSSING SCALE DATE
DSN BENZEL CKD -1-23
0 9-21-23 STANDARDS UPDATE TJH MDY oR TJH NTD I"HT 4 DATE
NO DATE REVISION BY CKD CKD MDY NM RLB of 4 A-38315
PIPE INSTALLATION REV. NO. 23
TRENCHING & BACKFILLING DATE 01/01/25
x v#ST, a STANDARDS 9 OF 9
Utilities NATURAL GAS SPEC. 3.15

3.16 SERVICES
SCOPE:
To establish uniform procedures for designing, locating, and installing natural gas services.
REGULATORY REQUIREMENTS:
§192.361, §192.363, §192.365, §192.367, §192.371, §192.375, §192.381, §192.383, §192.385, §192.725
WAC 480-93-100, 480-93-115
CORRESPONDING STANDARDS:
Spec. 2.12, Pipe Design - Steel
Spec. 2.13, Pipe Design - Plastic
Spec. 2.14, Valve Design
Spec. 3.13, Pipe Installation— Plastic Mains
Spec. 3.15, Trenching and Backfilling
Spec. 3.18, Pressure Testing
Spec. 5.16, Abandonment or Inactivation of Facilities
INSTALLATION REQUIREMENTS:
General
New or re-commissioned services shall be tested to the pressures required for a new line installation.
Refer to Specification 3.18, Pressure Testing.
Location Considerations
Consideration shall be given to the location of the service and riser so that each meter and service
regulator, whether inside or outside of a building, is installed in a readily accessible location and protected
from corrosion and other damage, including vehicular damage that may be anticipated.
Service lines should be run to the meter in the shortest, least obstructive path possible while meeting
other clearance requirements. When crossing roads, services should run at right angles to the road. In
best practice, consider avoiding installation of service lines under existing or probable future driveways,
patios, home addition areas, and egress window areas.
If condensates are present in the gas where it might cause interruption in the gas supply to the customer,
the service line must be sloped so condensates will drain toward the main or into drips at the low points in
the service line.
Service lines must be installed to minimize anticipated piping strain /external loading.
See Spec 3.13—"Pipe Installation —Plastic Mains"for additional considerations related to field bending of
PE pipe.
See Spec 3.15—"Trenching and Backfilling"for additional considerations related to clearances.
PIPE INSTALLATION REV. NO. 25
SERVICES DATE 01/01/25
X-4, sr'a STANDARDS 1 OF 21
Utilities NATURAL GAS SPEC. 3.16

New Plastic Services
When installing a new plastic service near, equal to, or exceeding 1,000 feet in length, a 4-1/2 lb. zinc
anode should be installed to prevent corrosion of the tracer wire. Install one anode near the main and
install any additional anodes at 1,000-foot spacings toward the service riser. (Refer to Specification 3.13,
Tracer Wire, for further guidance.)
Steel Service Replacement
When replacing or repairing sections of steel service, care must be taken to maintain cathodic protection
(CP) as well as the ability to locate the pipe. Below is a hierarchy of preferences when replacing all or a
portion of a steel service:
1. Convert the service to polyethylene plastic (PE)the full length from the main to the meter for the
betterment of the gas system to prevent isolated steel locations and to prevent disbonded dresser
fittings.
2. In situations where only a portion of the service is to be replaced or repaired, install new steel
pipe to maintain CP continuity. An example of this is offsetting a steel service for installation of a
window well.
3. Replace the service from the riser back as far as practical using PE pipe and install a transition
fitting before reaching the main. A stress relieving sleeve should be installed at the steel to PE
transition point prior to completion of the service connection. Refer to Spec 2.13—"Joining of
Plastic Pipelines". The following must also be completed in this scenario:
a. Install a marker ball at the transition.
b. Install tracer wire from the transition to the riser.
c. Note accurate centerline measurements of the exact location of the transition on the
applicable work order.
Excess Flow Valves
An excess flow valve (EFV) is a device that is designed to automatically, and substantially shut off the
flow of gas should the service line be severed. An EFV shall be installed in any of the following
circumstances where the operating pressure is 10 psig or greater:
• On each newly installed or replaced service line serving a single-family residence.
• On each newly installed or replaced service line serving a multifamily residence when the meter
capacity, at the time of meter installation, is under 1,000 CFH; and
• On each newly installed or replaced service line serving a small commercial facility when the
capacity, at the time of meter installation, is under 1,000 CFH; and
• On each newly installed or replaced branched service line if an EFV does not already exist. The
EFV should be installed so that it protects both services on a branched service.
NOTE: Refer to"Replaced Service Line" in Specification 1.1, Glossary, for a detailed definition.
As noted in §192.383, customers have a right to request an EFV on service lines not exceeding 1000
SCFH and who are not exempt from needing to have one as discussed below. Avista is required to notify
customers regarding their right to request an EFV and will do so via its website and/or through periodic
monthly bill inserts. Avista is required to keep evidence of such notifications if asked during pipeline
safety inspections and provide EFV reporting on its Distribution Annual Report required by§191.11.
Although not explicitly required, consideration should be given to installing an EFV when a service line is
exposed near the main and an opportunity to install an EFV exists. Additionally, the EFV must be marked,
or its presence be identified on the service line and must be located as close to the fitting connecting the
service line to the main as practical.
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Utilities NATURAL GAS SPEC. 3.16

Where an EFV is not required to be installed:
• Service points with existing loads above 1000 CFH where an EFV is not sufficient or not practical.
In these cases, however, a curb valve shall be installed on new or replaced services lines. (Refer
to Specification 2.14, Valve Design, "Curb Valves"for more information.). EFVs are preferred if
they are able to meet the flow requirements of the service.
• Industrial services.
• An EFV meeting the performance standards, as specified in §192.381, is not commercially
available.
• Systems that operate at a pressure of less than 10 psig.
• Service lines where there have been prior problems with contaminants in the gas stream that
could cause the EFV to malfunction or interfere with the removal of liquids from the line for
necessary maintenance.
Criteria for deter ining when to use an EFV or curb valve.
Single-Family Multifamily Residences Commercial Customers Served
Residence by a Single Service Line
Any Meter Installed Meter Installed Meter Installed Meter Installed Meter
Capacity Capacity<_ Capacity> Capacity<_ Capacity>
1,000 SCFH 1,000 SCFH 1,000 SCFH 1,000 SCFH
Operating Nothing Nothing Install Curb Nothing Install Curb
Pressure< 10 Required Required Valve Required Valve
PSIG
Operating Install EFV or Install EFV or
Pressure>_10 Install EFV* Install EFV* Curb Valve Install EFV* Curb Valve
PSIG
*Subject to exceptions listed above this table.
The excess flow valves are available in three styles:
1. PE bolt-on service tee with EFV incorporated into the outlet.
a. To be used on new PE services.
2. In-line "stick" EFV.
a. For use on existing PE stubs. Locate EFV at road right-of-way line.
b. For use off of steel main downstream of the transition fitting.
3. Mechanical coupling with built in EFV.
a. For use on existing PE stubs. Locate EFV at road right-of-way line.
b. For use off of steel main downstream of the transition fitting.
Individuals designing services shall use the following charts under Capacity of EFV to determine which
EFV to install based on the customer's projected load. The design that goes to construction shall indicate
if an EFV is to be installed based on the requirements of this specification. The EFV symbol shall be
shown in Avista's AFM (GIS) system. This enables Avista to run reports on the number of excess flow
valves installed in the system on a yearly basis. The following table shows EFV symbology in Avista's
GIS.
Symbol Description
E Stick EFV
O Tapping tee with integrated EFV
Q Inline Tee with EFV
Reducer Inline Tee with EFV
E Reducer Coupling with EFV
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Utilities NATURAL GAS SPEC. 3.16

Capacity of EFV
The following tables are used to size the EFV based on the lowest pressure (psig)the service line will
operate and the minimum trip rate in cubic feet per hour(CFH). Designers should use 10 psig in the
tables as the lowest pressure the service line will operate at unless the system operates at a pressure
lower than 10 psig.
The smallest capacity (not length) EFV capable of managing the anticipated load shall be selected,
unless there are extenuating circumstances. In such cases, contact Gas Engineering for assistance. If the
projected load exceeds the capacity of the EFV in the following tables at 10 psig, select a higher capacity
EFV or install a curb valve. A higher capacity EFV may need to be specified and special ordered in
certain applications.
"Maximum Length of Service Protected" in the last column of the tables is the maximum distance from
where the excess flow valve is located that it will trip at the minimum flow rate if the service line were
damaged.
EXAMPLE: If a service line is 800 feet in length at a pressure of 10 psig, a tap tee with integrated 775
EFV would protect 1,054 feet of service line. This EFV provides adequate protection. See diagram
below.
Max Length of Service Protected=1.054 feet
Tap Tee with EFV--.O Service
Meter
Length of service=800 feet
If the length of the service line is longer than the max length of service protected listed in the table, install
a second EFV in the service to protect the remaining length of service.
EXAMPLE: If a service line is 1,400 feet in length at a pressure of 10 psig, a tap tee with integrated 775
EFV would protect the first 1,054 feet of service line. If the damage occurs beyond 1,054 feet, the excess
flow valve may not trip. In this scenario, a stick EFV can be installed to protect the remaining 346 feet of
service line. See diagram below.
Stick EFV to protect
Max Length of Service Protected=1,054 feet The remaining 346
I/feet of service
Tap Tee with EFV---,n Service E Meter
Length of service=1,400 feet
When an existing customer load is increased and the service line has an EFV, the EFV capacity must be
evaluated and the EFV upsized if necessary.
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Utilities NATURAL GAS SPEC. 3.16

EFV Capacity Tables
775 CFH, LYCO EFV II SERIES, '/2"
Inlet Pressure(psig) Min Trip Flow Rate(CFH) Max Length of Service Protected (ft)
5 692 8
10* 775 34
15 850 57
20 919 80
25 983 102
30 1,044 124
35 1,101 146
40 1,155 168
45 1,206 190
50 1,256 211
55 1,304 233
60 1,350 255
Grayed area to assist in troubleshooting.
*Note: 10 psig is recommended for determining the appropriate EFV
775 CFH, LYCO EFV I SERIES, %"
Inlet Pressure(psig) Min Trip Flow Rate (CFH) Max Length of Service Protected (ft)
5 692 446
10* 775 1,054
15 OF 850 11 1,619
20 919 2,163
25 983 2,694
30 1,044 3,220
35 1,101 3,742
40 1,155 4,262
45 1,206 7,782
50 1,256 5,303
55 1,304 5,824
60 1,350 6,347
Grayed area to assist in troubleshooting.
*Note: 10 psig is recommended for determining the appropriate EFV
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SERVICES DATE 01/01/25
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Utilities NATURAL GAS SPEC. 3.16

1200 CFH, LYCO EFV I SERIES, W
Inlet Pressure(psig) Min Trip Flow Rate(CFH) Max Length of Service Protected (ft)
5 1071 116
10* 1200 388
15 1316 642
20 1423 887
25 1523 1127
30 1616 1364
35 1704 1600
40 1788 1835
45 1868 2071
50 1945 2306
55 2019 2543
60 2090 2780
Grayed area to assist in troubleshooting.
*Note: 10 psig is recommended for determining the appropriate EFV
1800 CFH, LYCO EFV I SERIES, W
Inlet Pressure(psig) Min Trip Flow Rate(CFH) Max Length of Service Protected (ft)
7 1672 8
10* 1800 78
15 1998 1185
20 2183 V 285
25 2356 382
30 2520 476
35 2676 568
40 2826 659
45 2790 749
50 3109 838
55 3244 926
60 3375 1013
Grayed area to assist in troubleshooting.
*Note: 10 psig is recommended for determining the appropriate EFV
PIPE INSTALLATION REV. NO. 25
SERVICES DATE 01/01/25
XVIST'aa STANDARDS 6 OF 21
Utilities NATURAL GAS SPEC. 3.16

The RW Lyall 475, 3/4-inch EFVB, stick style was used up through the year 2007 and the following table
is used for troubleshooting only. This model EFV is no longer being installed as of 1/1/2008.
TROUBLE SHOOTING TABLE ONLY
EFV STICK, 3/4', 475 CFH, RW LYALL LYCO EFV I SERIES
Inlet Pressure (psig) Min Trip Flow Rate (CFH) Max Length of Service Protected(ft)
5 424 1,395
10 475 2,875
15 521 4,249
20 563 5,569
25 603 6,859
30 640 8,132
35 675 9,397
40 708 10,657
45 739 11,917
50 770 13,177
55 799 14,439
60 827 15,704
Branch (Split) Service
A branch or split service is a distribution line that transports gas from a common source service of supply
to two adjacent or adjoining residential or small commercial customers. Branch services may be initiated
near an adjacent property owner's meter provided the adjacent customer's written approval is obtained to
work on their property, otherwise a branch can be done at the curb within the public right-of-way. The
advantage of a branch is to avoid cutting asphalt or concrete. A branch service should only be installed
when both the existing and new services are located on the adjacent, nearby sides of the structure, not
the far side of either.
Branching of an existing branched service shall not be done to add a third residential or small commercial
customer(see definition of"customer" in the Glossary) unless a portion of the existing service line is
reclassified as a gas main. Branching off an existing branched service line to add additional service
point(s) is allowed if the new service point(s) serve either of the existing customers (see example below).
Verify that the service line has sufficient capacity for the total connected load.
When a plastic service is split off a steel service, attach the plastic service tracer wire to the steel service
pipe. A CP test box is not needed at this location.
PIPE INSTALLATION REV. NO. 25
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Utilities NATURAL GAS SPEC. 3.16

�.
j Customer 1 Property
I j
Customer 1 Customer 1
j Service Point A Service Point B c
��—New service 1
i I
j Service
i�—New service
I i j
i
I I
I I
Customer 2 Customer 2 1
1 Service Point A Service Point B 1
I I
I I
Customer 2 Property
L._._._._._._._._._._._..................._J
To connect a third residential or small commercial customer to an existing branched service, the portion
of the existing service line from the gas main to the first service line connection will need to be reclassified
as a gas main (see example below).
r._._.------------------_._._._._.------------_._._._._._._._.1
Customer 1 Property Portion of the existing
j service line that needs to be
Customer 1 Customer 1 reclassified as main if a third
Service Point A Service Point B customer is connected c
I �
I
Service Reclassify as Main
i
1 New service—i
I i j
1 i
� - - — - --- - - - - - - --- -- - - - _ _ - - - - 1_ _ _ _i
1 j i I
1 1
I Customer 2 Customer 2 Customer 3
A
I Service Point A Service Point B Service Point A
I �
I j I
L Customer 2 Property I Customer 3 Property
._._._._._._._._._._._._._._._._._._._._._.-._._._._._._._._.�
To be reclassified as main, the pipe's depth will need to meet the requirements for a gas main. Refer to
Specification 3.15, Trenching & Backfilling for pipe depth requirements. Identify on the job paperwork the
pipe segment that has been reclassified as a gas main so that GIS is updated appropriately. Verify that
the line has sufficient capacity for the total connected load. (Note: In this instance, the reclassified main
does not require retesting for an hour as is required of other main in Specification 3.18.)
When branching off of an existing service, an EFV should be installed such that it protects all downstream
services, unless there are extenuating circumstances such as those listed earlier in this specification in
the subsection entitled "Excess Flow Valves". If the existing service already has an EFV installed, the new
capacity of the combined customer loads must be evaluated and the EFV upsized if necessary. Consider
the following when designing branch services in regard to excess flow valves:
1. If the combined load of the branch services exceeds the specified CFH in the EFV sizing tables
based on the minimum operating system pressure (10 psig), refer to subsection entitled "Excess Flow
Valves"for guidance.
2. Large custom home areas may necessitate separate services.
3. A 1/2-inch service should not be split or branched due to potential capacity issues.
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Installation of Excess Flow Valves
The excess flow valve (EFV) is a precision device and should be handled with care. Excessively rough
handling and/or the allowing of dirt, sand, or other debris to enter the EFV carrier(tee, stick, or coupling)
could cause damage to the device, rendering it inoperable. The following are procedures for installing and
putting a service with an excess flow valve into operation by style of EFV:
Excess Flow Valve (EFV) Installation Procedure—Service Tee Style:
The following procedure is to be used when installing a service tee style excess flow valve (EFV):
1. Run service line and install riser. Install EFV identification washer on riser, immediately below the
service valve.
2. Use air compressor to purge debris out of service line prior to installing and connecting to the
service tee EFV.
3. Perform pressure test on entire service line back to the service tee using standard testing
procedures.
4. Ensure that the EFV is not tripped by observing the pressure gauge for a slow, steady rise in
pressure. If the pressure"bumps" or rises quickly, the EFV is probably tripped. Shut off air and
allow the EFV to reset and equalize the pressure in the service line. Resume pressurization while
observing the pressure gauge.
5. Pressurize the service line to the proper test pressure (90 psig minimum) and observe for
pressure drops. The length of the test is determined by the table in Specification 3.18, Pressure
Testing.
6. When test is complete, slowly bleed the pressure off at the main.
7. Tap the main, back off the tap slowly to avoid tripping the EFV.
8. Purge the service line of air at the riser. A test regulator with a 1/8-inch orifice or a 90-degree
elbow with cap that has 1/8-inch drilled orifice may be used to control flow and avoid tripping the
EFV. Orient the purging device in a safe direction for gas flow. Open service valve slowly at riser
until fully open to avoid tripping the EFV. If the EFV trips, reset the EFV by closing the service
valve and allowing the bypass gas to equalize. Use a combustible gas indicator to check for 93
percent gas or higher. For additional information, refer to Specification 3.17, Purging Pipelines,
"Purging Services."
9. Set the meter and purge slowly to avoid tripping the EFV.
10. Record the EFV data on the As-built and/or service card.
Excess Flow Valve (EFV) Installation Procedure—In-Line Stick or Coupling Style:
For use off a steel main, existing service stub, and when branching off an existing service that does not
already have an excess flow valve. Refer to Standard Unit Assembly Drawing A-37169 at the end of this
specification for EFV installations from an existing steel service tee. Note: Prior to completing the
connection of the EFV to the steel tee, be sure to install a stress-relieving sleeve on the service line that
will help protect the rigid steel to PE transition per the requirements in Spec 2.13—"Joining of Plastic
Pipeline Components".
1. Run service line and install riser. Install identification washer on riser, immediately below the
service valve.
2. Use air compressor to purge debris out of service line prior to installing EFV.
3. Connect EFV stick or coupling in proper position (with arrow pointing away from source of gas)
with mechanical fittings to the stub or steel service tee in the bell hole depending on which type of
connection is being made.
4. Perform pressure test on the service line, including the EFV, using standard testing procedure.
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5. Ensure that the EFV is not tripped by observing the pressure gauge for a slow, steady rise in
pressure. If the pressure"bumps" or rises quickly, the EFV is probably tripped. Shut off air and
allow the EFV to reset and equalize the pressure in the service line. Resume pressurization while
observing the pressure gauge.
6. Pressurize the service line to the proper test pressure (90 psig minimum) and observe for
pressure drops. The length of the test is determined by the table in Spec 3.18 Pressure Testing.
7. When test is complete, slowly bleed the pressure off.
8. Tap the main or make final connection. Back off the tap or squeezer slowly to avoid tripping the
EFV.
9. Purge service line of air at the riser. A test regulator with a 1/8-inch orifice or a 90-degree elbow
with cap that has 1/8-inch drilled orifice may be used to control flow and void tripping the EFV.
Orient the purging device in a safe direction for gas flow. Open service valve slowly at riser until
fully open to avoid tripping the EFV. If the EFV trips, reset the EFV by closing the service valve
and allowing the bypass gas to equalize. Use a combustible gas indicator to check for 93 percent
gas or higher. For additional information, refer to Specification 3.17, Purging Pipelines, "Purging
Services."
10. Set the meter and purge slowly to avoid tripping the EFV.
11. Record the EFV data on the As-built and/or service card.
EFV—High Pressure Services
A high-pressure service is defined as a steel service line carrying pressure in excess of 60 psig up to a
customer, typically at the meter immediately adjacent to the building being served. In general, high-
pressure services should be minimized. It is preferred to design intermediate distribution systems and
serve customers with intermediate pressure.
When a high-pressure service is necessary, the service shall be installed utilizing a Mueller Autosafe
Model H-17842 Curb Valve Tee at the main. This valve tee operates with a ball check (EFV)and is
designed to shut off at flows exceeding 500 CFH. No exceptions are to be made without concurrence by
Gas Engineering.
Not more than one customer shall be served off a high-pressure service (i.e., no branching). Should it be
necessary to branch the existing high-pressure service, a regulator station or"farm tap"type regulator
station must be installed near the main. High-pressure service designs shall be reviewed by Gas
Engineering.
Service Risers
Service risers should be installed a minimum of 8 inches from the finished building wall with the service
termination valve approximately 10 inches from ground level or finished grade to accommodate proper
riser installation (refer to the drawings in Specification 2.24).
For installation in heavy snow areas refer to the"Services in Heavy Snow Areas" section of this
specification. The service valve should be positioned so that the shut off is facing away from the building
or the meter and easily accessible for operation. The service valve and meter shall not be in contact with
the ground except for applications detailed in Drawings A-36712 and C-35209 in Specification 2.24.
Variance to these requirements must be approved by Gas Engineering.
The service riser and tracer wire (if applicable) shall be installed through a 4-inch diameter, or larger, non-
metallic sleeve (i.e., PVC or corrugated drainpipe). The sleeve should be installed to a depth of 12-18
inches below grade and extend to a height 3-4 inches above grade. The sleeve once positioned, is filled
with soil.
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The purpose of setting the sleeve above grade is to prevent eventual accumulation of debris around the
riser and assure future concrete, pavement or other customer improvements do not contact the riser. It
also provides an opening around the riser that aids in leak survey and detection as well as provides
access to take a cathodic pipe-to-soil reading.
The PE "pigtail' on anodeless service risers may be shortened, if necessary, to accommodate unique
installation requirements. The steel portion of the riser may be rethreaded in the event the threads are
damaged as long as the riser nipple is Schedule 80, and the original threads are completely removed
before rethreading. Schedule 40 risers may not be rethreaded. No other modifications are allowed to the
steel portion of the riser.
Service Risers for Multi-Meter Manifolds
Service risers for multi-meter manifolds should be installed a minimum of 12 inches from the finished
building wall.
Services in Heavy Snow Areas
Location of the riser and meter set shall be on a non-shed side of the roof, where possible. On new
installations, approved external meter protection and a breakaway fitting should be installed to protect the
meter from falling snow and ice. Refer to Specification 2.22, Meter Design, "Meter Set Location Protection
and Barricades" and "Breakaway Fitting"for further guidance. If a suitable site cannot be found, an inside
meter installation may be considered. (Contact Gas Engineering for approval before installing an inside
meter). On meter sets installed inside a structure to avoid snow loads, the service valve should be
installed approximately 6 feet aboveground, level to the riser, and anchored to the wall per Drawing B-
36269 at the end of this Specification.
Service Lines in Conduit/Casing
When it is necessary to install a service line in a conduit/casing, the end nearest the building wall must be
sealed to prevent or slow the migration of gas towards the building in the event of a leak in the service
piping. This end seal may be made with expansion foam or other suitable seal. This is required not only in
Washington (per WAC 480-93-115(4)) but also in Oregon and Idaho.
WAC 480-93-115 (4): Whenever a gas pipeline company installs a service line in a casing or conduit,
the gas pipeline company must seal the casing at the end nearest the building wall to prevent or slow
the migration of gas towards the building in the event of a leak.
Service Lines into Buildings
The service line or service riser should not pass through a concrete wall, floor slab, or a foundation wall
without design approval by Gas Engineering. Each underground service line that enters a building below
grade must:
• In the case of a metal service line, be protected against corrosion.
• In the case of a plastic service line, be protected from shearing action and backfill settlement and a
steel anodeless riser be used (either prebuilt or"new constructions")where it enters the building wall.
• Enter into a normally usable and accessible part of the building and
• Be encased in a gas-tight conduit as it passes through the foundation or floor.
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The space between the conduit and the service line must be sealed to prevent gas leakage into the
building and, if the conduit is sealed at both ends, a vent line from the annular space must extend to a
point where gas would not be a hazard, and extend above grade, terminating in a rain and insect resistant
fitting. If the service is steel, it is best to have a bare steel conduit with spacers installed to ensure the
carrier pipe does not short to the conduit.
Service Lines Passing Under Buildings
The installation of service lines under buildings should be performed only as a last resort and only after
prior approval from Gas Engineering. Service lines installed under buildings must be cased, sealed, and
vented to the outside atmosphere.
Main Connections
Each service line connection to a main should be located at the top of the main to prevent dust, shavings,
and debris from entering the service line. If connection to the top of the main is not practical, then the
service may be connected to the side of the main using approved fittings. A main shall not transition
directly to a service without use of a service tee, except in cases where the gas main is less than 1-inch in
diameter.
Service connections to main by use of compression-type fittings must be designed and installed to
effectively sustain the longitudinal pullout, or thrust forces caused by contraction or expansion of the
piping, or by anticipated external or internal loading. If gaskets are used in connecting the service line to
the main connection fitting, they must be compatible with the gas in the system.
When installing a plastic service off a steel main, attach the service tracer wire to the steel main. A CP
test box is not needed for service connections. Contact a Cathodic Protection Technician for proposed
deviations from standard policy.
Curb Valves
Underground service valves or"curb valves" shall be installed on all services where meter sets are
installed in buildings or where it is impossible to provide ready access to a service line valve at an outside
wall of a building. A curb valve shall also be installed on all new or replaced service lines where the load
is greater than 1000 CFH and an EFV is not practical for installation. For additional criteria of where curb
valve shall be installed refer to Specification 2.14, Valve Design, "Curb Valves."
Insertion of Old Steel Services Along Steel Main
Insertion should be done only as a last resort when open trenching is too costly. In these cases, it is often
possible to pull short services that are reasonably straight out of the ground and pull new plastic pipe and
tracer wire through the void left by the steel service pipe that is removed. Pulling force limitations on
plastic pipe shall be monitored and adhered in accordance with Specification 3.13, Pipe Installation -
Plastic Mains.
When insertion of an old steel service is to be performed off steel main, electrical continuity should be
maintained along the service. This shall be performed as shown in Drawing A-34735 at the end of this
specification. The tracer wire shall be cadwelded to the main near the old steel service and the other end
of the tracer wire shall be cadwelded to the steel service being inserted.
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Utilities NATURAL GAS SPEC. 3.16

Insertion of Old Steel Services Along Plastic Main
When an old steel service is to be inserted and new plastic main is to be run, the electrical continuity of
the service should be maintained. In order to accomplish this, splice the tracer wire at the main and
perform a Cadweld to the steel service being inserted. The cadwelding process must be done prior to
inserting the plastic pipe inside.
Without Gas Engineering's approval, new, smaller diameter PE shall not be inserted into existing
PE main or service unless the old pipe has been split open (as in a pipe-replacement project).
Service— Termination Valve
The service termination valve shall be the first exposed threaded fitting aboveground other than a service
head adapter for field fabricated risers. The valve shall be one of the following types:
• On steel services, an insulated type, with the insulating portion on the outlet side of the valve.
• On plastic services, a non-insulating type of valve may be used; however, the insulated valve is
preferred.
Unless a meter set assembly is to be immediately installed, the service valve shall be locked off and an 8-
inch idle riser nipple and cap assembly shall be installed or alternatively an approved meter bar. If a
bypass valve is present, it must also be locked off. A gas warning sticker(Stock Item Number 662-0426
or 662-0428)shall be applied to the assembly to help prevent future damage to the service riser.
Steel Service Abandonment
Refer to Specification 5.16, Abandonment or Inactivation of Facilities, for further guidance on steel service
abandonment.
New Service Lines Not in Use
Each service line that is not placed in service upon completion of installation must comply with one of the
following until the customer is supplied with gas:
• The valve that is closed to prevent the flow of gas to the customer must be provided with a locking
device or other means designed to prevent the opening of the valve by unauthorized persons. This
includes any bypass valve that may be present.
• A mechanical device or disc that will prevent the flow of gas must be installed in the service line or in
the meter assembly.
• The customer's piping must be physically disconnected from the gas supply and the open ends
sealed.
Service Lines to Vehicles
Service lines shall not be installed to any type of recreational vehicle including but not limited to motor
homes, travel trailers, and campers. Service lines for food truck courts require Gas Engineering design
and approval.
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Service Lines to Floating Structures
If a gas service is being installed to serve a floating structure, Avista's service line and MSA must be
installed and terminate on solid ground or a solid structure on shore. These types of meters would be
considered a "Remote Meter Set". See additional requirements for these meters in Specification 2.22,
Metering & Regulation, Meter Set Location, Protection and Barricades.
Service Pipe Capacities
The following table may be utilized in sizing natural gas services. The tables provide maximum flow rates
in SCFH for various lengths, sizes, and piping materials with inlet pressure of 15 psig. Flows are given
assuming a 5 psig drop in pressure from the beginning of the service (inlet from main)to the end of
service (inlet of the meter). Contact the Gas Planning Department for guidance in situations where the
design criteria fall outside of the parameters of the table.
Plastic(roughness=0.000060) Steel(roughness=0.00180)
1/2" 3/4" 1-1/4" 2" 3" 4" 6" 3/4" 1-1/4" 2" 4" 6"
Length(ft) CTS IPS IPS IPS IPS IPS IPS Std. Std. Std. Sch.10 Sch.10
20 1,513 9,059 27,150 75,300 213,700 414,300 1,140,000 6,443 25,131 72,717 444,231 1,315,231
40 1,031 6,207 18,660 51,890 147,600 286,600 790,400 4,524 17,679 51,208 313,257 928,002
60 822 4,968 14,960 41,670 118,700 230,700 637,100 3,675 14,379 41,683 255,244 756,476
80 700 4,240 12,790 35,650 101,700 197,700 546,400 3,169 12,413 36,008 220,669 654,238
100 617 3,748 11,310 31,570 90,140 175,400 485,000 2,825 11,072 32,136 197,077 584,476
125 544 3,313 10,010 27,960 79,880 155,500 430,300 2,516 9,874 28,674 175,981 522,087
150 492 2,994 9,055 25,310 72,360 140,900 390,200 2,289 8,989 26,119 160,411 476,039
175 450 2,749 8,318 23,260 66,550 129,600 359,100 2,113 8,303 24,135 148,313 440,256
200 418 2,552 7,727 21,620 61,880 120,600 334,200 1,970 7,749 22,536 138,563 411,416
300 322 2,035 6,175 17,310 49,610 96,760 268,500 1,593 6,280 18,289 112,661 334,791
400 1 282 1,733 5,265 14,770 42,390 1 82,730 229,800 1,369 5,406 15,762 97,232 289,136
500 248 1,529 4,651 13,060 37,520 73,250 203,600 1,217 4,811 14,039 86,710 257,994
1000 167 1,035 3,159 8,894 25,630 50,130 139,700 841 3,339 9,776 60,643 180,806
1500 132 823 2,517 7,130 20,490 40,110 111,900 675 2,692 7,897 49,128 146,679
2000 111 699 2,141 6,051 17,480 34,230 95,620 578 2,308 6,781 42,280 126,371
Pipe Sizes and Capacities Downstream of Meter
As a matter of standard practice, Avista personnel should not design customer piping systems
downstream of the meter. As Avista does not own or maintain stream of customer piping, liability may be
incurred by Avista if we design a customer's piping system. Avista's Account Representatives have been
provided a list of professional engineering consultants that responded to a request for qualifications
solicitation by Gas Engineering to design downstream gas piping for customers. Contact the applicable
Account Representative for your area should you need to refer to the aforementioned list.
It is sometimes necessary, when working with customers to verify their piping systems are adequate to
meet their load requirements. For this reason, the following tables are provided. The tables give
maximum flows for various lengths, sizes, and piping materials with inlet pressures from regulation of 5.0
psig, 2.0 psig, or 7.0-inch WC (water column). Pressure drop allowed from beginning to end of pipe (Delta
P) are shown for each table.
PIPE INSTALLATION REV. NO. 25
SERVICES DATE 01/01/25
X-4, sr'a STANDARDS 14 OF 21
Utilities NATURAL GAS SPEC. 3.16

Pipe Capacities-Downstream of Meter P1 =2.0 psig
Flow in CFH for various lengths,sizes,and piping material P2=1.5 psig
Based on 0.60 S.G.&95%efficiency factor to account for equiv. Delta P=0.5 psig
length of pipe for fittings
Plastic (roughness = 0.000060
1/2" 3/4" 1-1/4" 2" 3" 4" 6"
Length ft CTS IPS IPS IPS IPS IPS IPS
20 314 1,926 5,846 16,392 47,004 91,692 254,561
40 211 1,306 3,977 11,182 32,151 62,817 174,793
60 167 1,039 3,171 8,932 25,722 50,304 140,162
80 142 883 2,699 7,612 21,947 42,951 119,791
100 125 778 2,381 6,723 19,401 37,988 106,030
125 110 685 2,100 5,936 17,147 33,592 93,833
150 99 618 1,895 5,361 15,498 30,377 84,904
175 90 566 1,737 4,918 14,227 27,896 78,014
200 83 524 1,611 4,564 13,210 25,910 72,494
300 66 416 1,281 3,635 10,541 20,696 57,992
400 58 352 1,087 3,091 8,977 17,640 49,480
500 54 310 958 2,726 7,924 15,580 43,740
1000 42 207 644 1,841 5,371 10,581 29,786
1500 31 164 510 1,462 4,274 8,430 23,772
2000 1 23 1 138 1 432 1 1,240 3,632 1 7,172 1 20,249
PIPE INSTALLATION REV. NO. 25
SERVICES DATE 01/01/25
X-v sm a STANDARDS 15 OF 21
Utilities NATURAL GAS SPEC. 3.16

Steel (roughness = 0.00180)
3/4" 1" 1-1/4" 2" 3" 4" 6"
Length (ft) Std. Std. Std. Std. Std. Sch. 10 Sch. 10
1,513 2,879 5,965 17,378 49,221 107,100 318,335
40 1,048 1,999 4,151 12,127 34,428 75,025 223,399
60 843 1,611 3,351 9,809 27,892 60,845 181,403
80 722 1,381 2,876 8,432 24,005 52,408 156,401
100 640 1,225 2,553 7,494 21,358 46,659 139,359
125 567 1,086 2,266 6,658 18,995 41,526 124,134
150 513 984 2,054 6,043 17,255 37,744 112,911
175 472 905 1,890 5,566 15,905 34,809 104,199
200 438 841 1,758 5,182 14,819 32,447 97,184
300 350 673 1,411 4,167 11,943 26,190 78,585
400 298 574 1,205 3,567 10,239 22,477 67,539
500 263 508 1,066 3,160 9,082 19,955 60,025
1000 178 344 726 2,162 6,240 13,748 41,506
1500 141 274 578 1,727 4,999 11,035 33,388
2000 120 232 492 1,472 4,268 9,432 28,587
Pipe Capacities-Downstream of Meter P1 =5.0 psig
Flow in CFH for various lengths,sizes,and piping material P2=1.5 psig
Based on 0.60 S.G.&95%efficiency factor to account for equiv. Delta P=3.5 psig
length of pipe for fittings
Plastic (roughness = 0.000060)
1/2" 3/4" 1-1/4" 2" 3" 4" 6"
Length (ft) CTS IPS IPS IPS IPS IPS IPS
20 986 5,939 17,860 49,679 141,390 274,570 757,277
40 669 4,056 12,234 34,121 97,357 189,351 523,411
60 522 3,241 9,794 27,358 78,177 152,184 421,225
80 453 2,762 8,360 23,378 66,874 130,265 360,892
100 399 2,440 7,391 20,688 59,230 115,431 320,027
125 352 2,154 6,534 18,303 52,447 102,263 283,725
150 317 1,946 5,906 16,558 47,478 92,612 257,102
175 291 1,785 5,422 15,211 43,641 85,157 236,524
200 269 1,656 5,035 14,132 40,565 79,180 220,017
300 214 1,319 4,018 11,296 32,477 63,451 176,546
400 181 1,122 3,422 9,632 27,725 54,203 150,959
500 159 989 3,020 8,510 24,518 47,958 133,665
1000 107 667 2,046 5,785 16,713 32,747 91,487
1500 84 530 1,628 4,611 13,345 26,175 73,230
2000 71 449 1,383 3,924 11,371 22,320 62,509
PIPE INSTALLATION REV. NO. 25
SERVICES DATE 01/01/25
x rv#ST,aa STANDARDS 16 OF 21
Utilities NATURAL GAS SPEC. 3.16

Steel (roughness = 0.00180)
3/4" 1" 1-1/4" 2" 3" 4" 6"
Length (ft) Std. Std. Std. Std. Std. Sch. 10 Sch. 10
20 4,341 8,225 16,968 49,157 138,612 300,765 891,068
40 3,040 5,767 11,911 34,558 97,559 211,840 628,129
60 2,465 4,680 9,674 28,096 79,382 172,460 511,673
80 2,123 4,032 8,341 24,247 68,552 148,994 442,269
100 1,889 3,591 7,433 21,621 61,164 132,985 394,916
125 1,681 3,197 6,621 19,275 54,560 118,672 352,574
150 1,527 2,907 6,023 17,544 49,687 108,111 321,326
175 1,408 2,681 5,558 16,200 45,902 99,906 297,047
200 1,312 2,499 5,184 15,117 42,853 93,294 277,481
300 1,058 2,018 4,191 12,243 34,757 75,738 225,511
400 907 1,732 3,601 10,535 29,939 65,286 194,559
500 805 1,538 3,200 9,371 26,656 58,162 173,455
1000 553 1,059 2,210 6,497 18,539 40,535 121,193
1500 443 850 1,776 5,233 14,964 32,763 98,120
2000 378 726 1,519 4,484 12,843 28,147 84,406
Pipe Capacities-Downstream of Meter P1 =7.0"W.C.
Flow in CFH for various lengths,sizes,and piping material P2=6.5"W.C.
Based on 0.60 S.G.and 95 percent efficiency factor to account for equivalent length of pipe for Delta P=0.5"W.C.
fittings
Plastic (roughness = 0.000060)
1/2" 3/4" 1-1/4" 2" 3" 4" 6"
Length (ft) CTS IPS IPS IPS IPS IPS IPS
20 51 276 856 2,438 7,093 13,950 39,200
40 38 185 575 1,645 4,805 9,471 26,680
60 25 146 455 1,306 3,822 7,543 21,290
80 19 123 385 1,108 3,247 6,416 18,130
100 15 114 339 975 2,861 5,657 16,000
125 12 105 297 857 2,521 4,987 14,120
150 10 100 267 772 2,272 4,499 12,750
175 9 95 244 706 2,081 4,122 11,690
200 8 91 226 654 1,928 3,822 10,850
300 5 74 178 517 1,529 3,035 8,632
400 4 56 165 437 1,296 2,576 7,337
500 3 45 154 384 1,140 2,267 6,466
1000 2 22 115 257 763 1,523 4,361
1500 1 15 78 230 603 1,205 3,460
2000 1 11 59 210 509 1,020 2,934
PIPE INSTALLATION REV. NO. 25
SERVICES DATE 01/01/25
x rv#ST,aa STANDARDS 17 OF 21
Utilities NATURAL GAS SPEC. 3.16

Steel (roughness = 0.00180)
3/4" 1" 1-1/4" 2" Y 4" 6"
Length (ft) Std. Std. Std. Std. Std. Sch. 10 Sch. 10
20 236 455 956 2,837 8,163 16,840 44,940
40 159 308 650 1,938 5,601 11,580 34,480
60 126 245 517 1,548 4,484 9,290 27,720
80 107 207 439 1,318 3,826 7,936 23,720
100 104 182 3871 1,163 3,382 7,020 21,010
125 98 160 341 1,026 2,987 6,208 18,600
150 92 144 307 925 2,698 5,612 16,830
175 87 133 281 848 2,476 5,152 15,470
200 82 131 260 786 2,297 4,784 14,370
300 63 188 206 624 1,829 3,815 11,490
400 47 106 182 529 1,554 3,247 9,799
500 38 95 173 465 1,369 2,864 8,655
1000 19 49 134 311 921 1,934 5,872
1500 13 33 99 286 730 1,534 4,673
2000 10 25 70 243 618 1,301 3,970
PIPE INSTALLATION REV. NO. 25
SERVICES DATE 01/01/25
x rv#ST,aa STANDARDS 18 OF 21
Utilities NATURAL GAS SPEC. 3.16

REPLACE SERVICE VALVE
WITH LOCK WING INSULATED VALVE
3/4" SERVICE HEAD ADAPTER
REAM THREADED END OF EXISTING
3/4" SERVICE PIPE BEFORE BEGINNING
PE PIPE INSERTION =
EXISTING 3/4" STEEL SERVICE PIPE
CADWELD TRACER
WIRE TO MAIN &
WRAP AROUND TEE
FOR ALIGNMENT
EXTERNAL
PROTECTIVE
PE SLEEVE
1/2" C.T.S�FLARE P=ENDPE PIPE OR INSTPROTECTSSARY TO CUT OUT SECTION
fSTEEL
TING STEEL MAIN (STK#770-7521) OF OLD SERVICE PIPE BECAUSE OF
3/ PUNCH TEE OBSTRUCTION, CADWELD#14 TRACER
AND COMPRESSION COUPLING WIRE TO EACH END OF OLD STEEL
FOR 1/2 C.T.S. PE PIPE SERVICE TO MAINTAIN CONTINUITY
FROM METER TOWARD MAIN
DISTRIBUTION -GAS
STANDARD
INSERTING 3/4"STEEL SERVICE PIPE
5 12-4-13 CORRECTED TO DATE SLG eRS WITH 112" PE PLASTIC
a 4 1 1-08 CORRECTED TO DATE DLO AVISTA CORP
SPOKANE.WASHINGTON
�? 3 06-00 RINSED TRACER WIRE CONNECTION CJ CKD NNE 1 1-17-95 APPRO
a' SCALE I DATE
0 2 1-97 CORRECTED TO DATE JW DSrfAULKENBERRY CKD 10-18-95
1 1 12-95 REVERSED INSULATED VALVE RP ME DR PICKUP NTD SHT_ DATE
NO I DATE REVISION BY I CKD CKD NTD J W OF 1 A-34735
AUTOCAD DWG
PIPE INSTALLATION REV. NO. 25
SERVICES DATE 01/01/25
x-v sm a STANDARDS 19 OF 21
Utilities NATURAL GAS SPEC. 3.16

3
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PIPE INSTALLATION REV. NO. 25
SERVICES DATE 01/01/25
�rsr�r STANDARDS 20 OF 21
Utilities NATURAL GAS SPEC. 3.16

MATERIAL LIST
ITEM Y" STOCK NO %" STOCK NO OTY DECRIPTION
1 771-8300 771-8302 1 EXCESS FLOW VALVE, 775 CFH
2 771-7535 770-5740 1 COUPLING, MECHANICAL
3 578-0264 578-0264 1 2" CONDUIT, PVC GAS SLEEVE, SCH 40, YELLOW
4 770-6340 1 770-6342 AS REQb PIPE. PE, BI-MODAL
5 770-5551 770-5556 1 0-RING, FOR CONTINENTAL SERVICE TEE
6 770-5561 770-5566 1 SEAL RING, FOR CONTINENTAL SERVICE TEE
7 770-5570 770-5571 IF NEEDED STEEL PLUG CAP, FOR CONTINENTAL SERVICE TEE
8 770-5580 770-5585 IF NEEDED STIFFENER, FOR CONTINENTAL SERVICE TEE
9 770-5540 770-5545 IF NEEDED COMPRESSION NUT, FOR CONTINENTAL SERVICE TEE
CONSTRUCTION NOTES
1 CONSTRUCT AND INSTALL PER COMPANY STANDARDS
2 THIS ASSEMBLY TO BE INSTALLED WHEN RETROFITTING AN EXISTING PE SERVICE FROM A STEEL MAIN, OR
INSTALLING A NEW PE SERVICE FROM AN EXISTING STEEL TO PE SERVICE TEE
3 IF NECESSARY, REMOVE THE PLASTIC PIPE FROM THE STIFFENER BY CUTTING SLITS ALONG THE PIPE OR BY
HEATING THE PIPE TO LOOSEN ITS GRIP ON THE STIFFENER.
IF THE STIFFENER IS PULLED OUT FROM THE TEE DURING THE PIPE REMOVAL PROCESS, OR IF THE STIFFENER
4 IS DAMAGED AND NEEDS REPLACED, A NEW STIFFENER CAN BE INSTALLED. USE A BRASS HAMMER TO TAP
THE NEW STIFFENER INTO THE TEE UNTIL IT SEATS.
5 INSTALL EFV AND COUPLING IF APPLICABLE
6 INSTALL YELLOW PVC SLEEVE OVER COMPRESSION FITTING ON SERVICE TEE OUTLET AND MECHANICAL
COUPLING
7 REPLACE SERVICE TEE 0-RING AND SEAL RING
8 REPLACE SERVICE TEE CAP, STIFFENER, AND COMPRESSION NUT IF NEEDED
EXISTING STEEL TO
PE SERVICE TEE 12"
i .4r - - - -- - - -- - - - - -1
5 6 (REQUIRED)
"JO)O0000
7 8 9 (IF NEEDED)
1 3 2 4 OR EXISTING
NOTE. INSTALL PROTECTIVE SLEEVE OVER
EXISTING STEEL COMPRESSION FITTING AND MECHANICAL COUPLING
IP MAIN ELEVATION
DISTRIBUTION - GAS
STANDARD
UNIT ASSEMBLY
4 9-19-23 UPDATE CONSTRUCTION NOTES CGD DRS y„&a"PE SERVICE AND EFV OFF OF A STEEL IP MAIN
3 8-24-22 UPDATE EFV STOCK NO TJH AVISTA CORP
�RS SPOKANE, WASHINGTON
2 8-3-17 STANDARDS UPDATE SJM pRS 3 = t-0 07-19-11 ��RLOLVL�ED
1 8-26-15 STANDARDS UPDATE CGD ME GALE DAB u�Lt
DSN J. WEBB CKD (/Q 08-12-11
0 8-12-11 ISSUED FOR STANDARDS TJH �/ TJH NTD SHT 1 DATE
NO DATE REVISION BY CKD CKD DRS WD OF 1 A-37169
PIPE INSTALLATION REV. NO. 25
SERVICES DATE 01/01/25
,a-v, sra STANDARDS 21 OF 21
Utilities NATURAL GAS SPEC. 3.16

3.17 PURGING PIPELINES
SCOPE:
To establish uniform procedures for the purging of air or natural gas from distribution and transmission
facilities.
REGULATORY REQUIREMENTS:
§192.629, §192.751
OTHER REFERENCES:
AGA XK1801 Purging Manual, Fourth Edition
CORRESPONDING STANDARDS:
Spec. 3.12, Pipe Installation - Steel
Spec. 3.13, Pipe Installation - Plastic
Spec. 3.32, Repair for Steel Pipe
Spec. 3.33, Repair for Plastic Pipe
Spec. 3.34, Squeeze-Off PE Pipe and Prevention of Static Electricity
Prevention of Accidental Ignition
It is essential that vented natural gas and air/gas mixtures be diffused into the air without hazard to
Company personnel, the general public, or property. Each potential source of ignition must be
removed from the area and a fire extinguisher must be provided. In addition to the precautions
discussed in this specification, those who work on or near gas pipeline facilities shall be aware of the
risks of their activities. In all situations, traiged individuals shall be able to identify risks in their
immediate area including sources of ignition that may not be obvious. Some factors to consider:
• Cars, trucks, and engine-driven construction equipment: Where are vehicles in relation to a
potential gas envelope? Remain upwind of the gas facilities whenever possible.
• Warning Signs: Are passing motorists and pedestrians aware of the presence of gas facilities?
Ensure appropriate signage is in place and that it provides sufficient information to warn of the risks
of gas-fueled fires. Such warning signs include not only those that are permanently affixed at Gate
Stations and Regulator Stations but also temporary signage that may be placed any time the public
should be informed of a temporary gas ignition risk in an area.
• Sparks from hand tools: Are precautions being taken when accessing vaults and manhole covers?
Avoid glancing blows on metal, concrete, and stone to prevent sparks.
• Sparks from electrical switches, telephones, and flashlights: Do not ring doorbells, operate
thermostats, telephones, or light switches when in a potentially explosive environment. Do not use
flashlights unless they are of the explosion-proof variety.
• Traffic signals: Are Street lighting and signal control boxes nearby? If possible, request that the
appropriate agency temporarily disconnect these devices during a blowing-gas event.
• Welding equipment: Do not permit the use or storage of welding equipment where a dangerous
gas-air mixture may exist. Prior to welding, cutting, or other hot work in or around a structure or
area including a trench containing gas facilities, a thorough check shall be made with a combustible
gas indicator(CGI)for the absence of a combustible gas mixture. CGI readings shall continuously
be taken while repairs are being made until the area is made safe.
PIPE INSTALLATION REV. NO. 15
PURGING PIPELINES DATE 01/01/24
X-4, sr'a STANDARDS 1 OF 8
Utilities NATURAL GAS SPEC. 3.17

PURGING REQUIREMENTS:
General
Purging of air or natural gas in accordance with this standard prevents a hazardous mixture of gas and air
from occurring in the pipeline. Purging is required:
• When new facilities are brought into service.
• Post blowdown when existing facilities are brought back into service and the removal of air is
necessary.
• Post blowdown when existing facilities are temporarily taken out of service and the removal of
natural gas is necessary.
• Post blowdown when lines are to be abandoned.
Purging operations should be performed continuously without interruption to minimize the surface contact
time between air and gas. Natural diffusion/mixing at the gas to air interface will occur during the purge,
so minimizing the duration of the purging operation helps to mitigate the formation of a hazardous
mixture.
Purging Plan
When necessary, a written plan for purging should be prepared prior to the work (preferably during the
design phase) and reviewed with the Company personnel involved. The following items should be
discussed and included in the written plan as needed:
• The extent of the facility to be purged, points of isolation, and vent locations.
• The purging medium to be used.
• Minimum purge velocity, maximum allowable time for purge, and purge setup
• Purge connection and vent sizes
• Schedule of Operations and procedural steps
• Safe working practices, especially around plastic pipe due to concerns of static charges that may
develop. Refer to Specification 3.34, Squeeze-Off of P.E. Pipe and Prevention of Static Electricity
• Means of communication during purge.
• Means of determining when purge is complete.
• Procedures for handling emergencies, such as gas ignition.
• Notification of local agencies if required (police, fire, air pollution, noise abatement).
• Backup provision, in case of unanticipated occurrences (i.e., compressor failure, insufficient
supply of purging gas, etc.).
Purging Main with Laterals
When purging a pipeline which has laterals or branches, care must be taken to remove the air or gas from
all sections of the piping system. The main (trunk)section should be purged first, then each lateral.
Injection Rate
Injection of purging medium must be done at a high velocity (100 lineal feet per minute minimum)within
the pipeline. A high velocity will maintain a turbulent interface between the purge gases to minimize
stratification (i.e., layering of gas and air) and mixing within the pipeline. A purging rate of 100 feet per
minute is easily maintained within a pipeline by partially opening a main line valve in all but low pressure
systems.
PIPE INSTALLATION REV. NO. 15
PURGING PIPELINES DATE 01/01/24
X-4,15y' a STANDARDS 2 OF s
Utilities NATURAL GAS SPEC. 3.17

Venting and Blow Down
A permanent or temporary steel vent stack shall be used that is valved and in the vertical position. It
should be of a safe height to keep the natural gas out of the work area and to blow it in a safe direction.
The vent pipe shall be grounded using a 12-inch minimum grounding rod. Buildings, overhead lines,
aircraft landing patterns, and other obstructions or sources of ignition should be considered when
determining the location for venting the gas. Plastic pipe shall not be used as a vent stack as electrical
charges on the pipe can cause ignition. An anodeless riser, however, may be used as a vent stack so
long as an effective grounding device can and does get installed.
The vent stack should be smaller than the piping being purged, except when purging 1/4" and smaller
diameter piping. Sizing the vent stack smaller than the pipe helps ensure that the discharge velocity is
greater than the flashback velocity, so accidental ignition from outside cannot travel back into the piping.
Blow Down Procedure:
Assure a safe work area that prevents the general public, non-essential personnel, and equipment from
entering. Access shall be restricted only to personnel required to be within the work area. All other
individuals and equipment should be kept a safe distance away. If possible, place no smoking /warning
signs, barricades, and yellow plastic warning tape as necessary to assist.
Employ appropriate PPE and safety equipment as required by existing field conditions per Section 4 of
the GESH and Part 7, Section 7.5 of the Avista Incident Prevention Manual (Safety Handbook) prior to
entering the work area.
Survey the existing field conditions to understand the potential hazards to venting gas at a specific
location. Take the necessary precautions to allow the discharge of gas to the atmosphere without hazard.
Non-required personnel should be moved to a safe distance from the blow down stack.
On permanent blow down facilities that utilize closure devices or blind flanges on the outlet of the blow
down stack, bleed off any pressure that might exist between the operating valve and this fitting prior to
removal of the fitting.
Begin the blow down operation by operating the vent stack valve to allow a controlled release of gas from
the blow down stack to atmosphere. It is important to monitor the pressure in the line you are intending to
blow down and verify the pressure is dropping, indicating that the line is isolated from the system.
Continue to survey the immediate area for changes to existing field conditions and follow strict
precautions to prevent accidental ignition of venting gas and to ensure the safety of Company personnel,
the general public, and/or property during blow down.
Follow the purging requirements further outlined in this specification. Purging, once started, must be
continued until completed so as not to allow combustible mixtures of gas and air to develop.
When possible, consideration must be given to the public with regard to noise and odor as well as to any
applicable state and local noise and pollution abatement requirements. Such considerations may include
the notification of residents in close proximity to the blow down operations, the use of noise suppressers,
reduction of line pressure, reduced rate of venting, etc. Gas Control should be notified prior to the purging
procedure so they can react to calls from the public and dispatch crews, as necessary.
Static Charges
Polyethylene is a poor conductor of electricity; therefore, precautions must be taken to prevent build-up of
static electrical charges on plastic pipe during purging operations. Refer to Specification 3.34, Squeeze-
off of PE Pipe and Prevention of Static Electricity.
PIPE INSTALLATION REV. NO. 15
PURGING PIPELINES DATE 01/01/24
�rsr�r STANDARDS 3 OF 8
Utilities NATURAL GAS SPEC. 3.17

Bleed Off of Steel Pipe
When bleeding off pressure in steel pipelines that have been stopped-off or valved-off, a steel-valved vent
stack shall be installed to bleed-off the pressure remaining in the pipeline prior to cutting the pipe. Refer
to"Venting and Blow Down" in this Specification. If the system does not bleed down, shut valve to vent
stack and check fittings used to stop the flow. A bonding cable shall be connected across the proposed
opening before cutting a steel pipe apart. The cable will carry the electrical current and prevent sparking.
Bleed Off of Plastic Pipe
When bleeding-off pressure in plastic pipelines that have been squeezed-off or valved-off, a steel-valved
vent stack (service tee connected to a riser with a valve) shall be installed to bleed off the pressure
remaining in the pipeline prior to cutting the pipe. Do not purge through the squeezers without
installing these additional fittings to control the flow and direction of the bleed-off gas. Refer to
"Venting and Blow Down" in this specification. If the system does not bleed down, shut valve to vent stack
and check fittings used to stop the flow.
On small diameter pipe (1/2 inch and 3/4 inch)there may not be the ability to install a steel-valved vent
stack due to unavailability of fittings to connect to the pipe before making a cut in the pipe. On short
sections of pipe in all diameters (for example stubs and transition fittings)there may not be enough
clearance to squeeze and install a steel-valved vent stack before making the cut in the pipe. In these
cases, the pipe shall be squeezed or shutoff in a location that minimizes the amount of gas to be bled off.
For pipe larger than 3/4-inch diameter, the length of pipe being bled off shall not exceed 5 feet without the
use of a steel-valved vent stack.
PURGING AIR OUT OF FACILITIES TO BE PLACED IN SERVICE:
NOTE: For any diameter of pipe, it is important to monitor the pressure during the purging process. At no
time can the pressure exceed the MAOP. If at any time the pressure exceeds the MAOP plus the
allowable build-up, contact Gas Engineering.
Purging Services
Service installations may be purged by opening the riser valve after the service tee been tapped. Care
must be taken to blow gas away from structures by connecting a meter bend or street elbow to the riser
valve and pointing the stream of gas in a safe direction. The valve should be opened slowly to the fully
open position; no person or object should be in the exhaust stream area. The operator shall hold the
wrench and keep it in contact with the valve stem at all times. Care must be taken to be aware of all
potential ignition sources and direct the purge in a safe direction. See Sheet 1 of this specification for
further guidance on "Prevention of Accidental Ignition."
A sufficient amount of gas should be blown to atmosphere and a combustible gas indicator used to
ensure that all air is removed from the line. Service lines should be purged immediately after the service
tee has been tapped and gas is in the service line.
Purging Services with an Excess Flow Valve
As an Excess Flow Valve (EFV) is designed to shut off excess flow, purging of a service with an EFV
must be done with care. The purging procedure is outlined in Specification 3.16, Services, "Installation of
Excess Flow Valve."
PIPE INSTALLATION REV. NO. 15
PURGING PIPELINES DATE 01/01/24
X-4, sr'a STANDARDS 4 OF 8
Utilities NATURAL GAS SPEC. 3.17

Small Pipelines
Purging of Pipelines 6 inches in Diameter and Smaller.
Small diameter pipelines should be purged by direct displacement (i.e., gas-to-air or air-to-gas)or by
using nitrogen (i.e., inert purge medium). Purging of air by direct displacement is accomplished by
injecting gas at high enough velocities to limit stratification (i.e., layering of gas and air)and ensure
turbulent flow at the air to gas interface (refer to "Injection Rate" above). Purging of air using nitrogen is
accomplished by completely filling the pipeline with nitrogen, or by injecting a slug of nitrogen (refer to
"Purging with Nitrogen" below).
Small diameter plastic gas mains shall be purged by controlling the flow rate with a valve on the vent
stack or riser. The vent stack or riser shall be located no further than 5 feet from the end of the pipe being
put into service. Avoid squeezing near the venting end as this is the area of concern for static buildup.
Large Pipelines
Purging Pipelines Larger than 6 inches in Diameter.
For mains greater than 6 inches diameter, it is desirable to purge using nitrogen. This can be
accomplished by completely filling the pipeline with nitrogen, or by separating the air from the natural gas
with a slug of nitrogen (refer to"Purging with Nitrogen" below). These techniques eliminate or minimize air
to gas stratification and mixing which otherwise would be accelerated due to the greater cross-sectional
area of the large diameter pipe.
When the use of nitrogen is impractical, pipelines with a diameter greater than 6 inches are purged of air
by injecting natural gas into the line at high velocities. Mixing of air and gas is more of a problem for larger
diameters and the purge will usually take longer.
Purging with Nitrogen
To prevent explosive mixtures when purging long, large diameter lines, a slug of nitrogen can be injected
into the line prior to the purging medium which acts as a barrier to prevent mixing of air and gas. The
nitrogen will mix with the air and the gas, but as long as a sufficient volume of nitrogen is injected at a
high enough velocity (refer to "Injection Rate" above), a buffer of pure nitrogen will be maintained
between the mixed regions. The table below gives the required volumes of nitrogen for various pipeline
diameters and lengths.
Immediately following the introduction of the nitrogen slug, natural gas shall be injected into the pipeline in
a continuous and rapid manner and vented at the terminal end until the vented gas is free from air. Check
for the presence of 93 percent gas or higher with a CGI. If there is difficulty achieving 93 percent gas,
contact Gas Engineering. Following are additional facts regarding inert slug purging:
• Purge velocity is extremely important. Avoid a slow purge to minimize stratification between heavier
and lighter gases.
• The amount of nitrogen necessary to purge short lengths (500 feet or less)of large-diameter pipe
satisfactorily at practical purge velocities exceeds the volume of the line.
• Changes in horizontal or vertical direction because of elbows or return bends do not destroy the
nitrogen slug.
• A temperature variation in the order of 20 degrees F has no effect on mixing of the nitrogen slug with
combustible gas or air.
• Turbulence, even if it causes mixing, is much less the cause of deterioration of the slug than is
stratification, which is the process of layering.
• A delay of approximately three minutes between the addition of the nitrogen slug and the purge
medium will destroy the slug. (Delays of any nature should be avoided)
PIPE INSTALLATION REV. NO. 15
PURGING PIPELINES DATE 01/01/24
X-4, sr'a STANDARDS 5 OF 8
Utilities NATURAL GAS SPEC. 3.17

NITROGEN PURGING DATA FOR 4" -20" PIPE
VOLUME OF NITROGEN REQUIRED FOR INERT SLUG FOR VARIOUS PIPE SIZES
Pipe Cu. Ft. Nitrogen Per Length of Pipe
Pipe Content
Diameter Cu. Ft.i 500' 1,000, 2,000' 5000' 10,000, 20,000' 50,000'
Ft.
4" 0.09 19 23 29 40 53 71 107
6" 0.22 46 56 70 98 129 173 261
8" 0.37 77 94 117 164 217 291 439
10" 0.58 121 147 184 257 340 457 688
12" 0.83 173 211 263 368 486 653 985
16" 1.3 280 342 430 605 802 1,080 1,632
18" 1.67 360 440 553 777 1,030 1,387 2,097
20" 2.08 448 548 689 968 1,283 1,728 2,611
24" 3.01 649 793 997 1,401 1,857 2,501 3,779
This table is based on providing a slug which will reduce to about 100 feet in length at end of purge. To provide an additional
safety factor,some operators use double the amount of nitrogen indicated.
NOTE: One cylinder of nitrogen at 2200 psig=220 cubic feet at atmospheric pressure.
NOTE: Values for 24"diameter pipe were derived/interpolated from 22"and 26"diameter pipe values found in Table 5-4 of AGA
Purging Manual XK1801.
Information from Table 5-4,"Purging Manual", Fourth Edition,AGA,Cat. No.XK1801,2018.
Once a continuous and pure flow of natural gas is obtained through the vent stack, the venting valve shall
be closed. Pressure within the main shall be allowed to build up to the available gas pressure. Close the
throttling (or control)valve, then the venting valve shall be opened, and the accumulated pressure
allowed to dissipate. This procedure should be repeated a minimum of two times to ensure that any
pockets of air were not bypassed in the pipeline due to a laminar flow condition.
Following completion of the above steps, the pipeline may be placed in service. The following illustration
shows a guideline for purging a pipeline into service (replacing air with natural gas).
Purge Until
93%Gas Read
If Needed, Inject with CGI
Inert Gas Slug Here
(see"Purging with
Nitrogen"in this
specification)
Valve;Stopper,or I I Vent Port for Steel Vent Stack
Squeeze Point Injecting Inert Vent Stack Valve
Gas Slug
End of Pipeline
5'Max 5'Max
In Service Pipeline Section Being Purged
Verifying the Presence of Gas
PIPE INSTALLATION REV. NO. 15
PURGING PIPELINES DATE 01/01/24
X-4 sr'a STANDARDS 6 OF 8
Utilities NATURAL GAS SPEC. 3.17

The use of a combustible gas indicator(CGI)to check for 93 percent gas or higher is the method that
should be used when purging air out of facilities to be placed into service. If there is difficulty achieving 93
percent gas, contact Gas Engineering.
PURGING NATURAL GAS OUT OF EXISTING FACILITIES:
NOTE: For any diameter of pipe, it is important to monitor the pressure during the purging process. At no
time can the pressure exceed the MAOP. If at any time the pressure exceeds the MAOP plus the
allowable build-up, contact Gas Engineering.
Small Pipelines
Purging of Pipelines 6-inches Diameter and Less:
Lines 6-inches in diameter and smaller are purged of natural gas by direct displacement (i.e., gas-to-air or
air-to-gas) or by using nitrogen. Purging of gas by direct displacement is accomplished using an air mover
or by purging with air at high enough velocities to limit stratification (i.e., layering of gas and air)and
ensure turbulent flow at the gas to air interface. Purging of gas using nitrogen is accomplished by
completely filling the pipeline with nitrogen, or by injecting a slug of nitrogen (refer to"Purging with
Nitrogen" section).
In cases such as services of Can't Gain Entry Cut-offs where both ends of the line are not accessible, gas
may be purged out by"flushing"the line several times with nitrogen. This is accomplished by injecting
nitrogen to a safe pressure level (at or below the MAOP) in the service, releasing it to atmospheric
pressure and repeating, as necessary. The disposal of large volumes of natural gas into the atmosphere
should be minimized as far as practical by transferring as much as possible to adjacent systems.
Large Pipelines
Purging of Pipelines Larger than 6-inches Diameter:
For mains greater than 6-inches diameter, it is desirable to purge using nitrogen. This can be
accomplished by completely filling the pipeline with nitrogen, or by separating the natural gas from the air
with a slug of nitrogen (refer to "Purging with Nitrogen" section). These techniques eliminate or minimize
gas to air stratification and mixing which otherwise would be accelerated due to the greater cross-
sectional area of the large diameter pipe and reduces purge time.
When it is impractical to use nitrogen, pipelines with a diameter greater than 6 inches can be purged of
natural gas with air at high velocities via the direct displacement method. Except for short lengths, this
should be performed with an air mover. Contact Gas Engineering for further guidance. The following
illustration shows a guideline for purging a pipeline out of service with an air mover(replacing natural gas
with air).
PIPE INSTALLATION REV. NO. 15
PURGING PIPELINES DATE 01/01/24
X-4,15y' a STANDARDS 7 OF s
Utilities NATURAL GAS SPEC. 3.17

Purge Until
0%Gas Read
Air Drawn with CGI
Through by
Air Mover(Do
not force air Air Mover
into pipeline
being purged) Steel Vent Stack
Valve,Stopper,or Squeeze Point Vent Port (Grounded)
—
(Size to be greater than or equal to Vent Stack Valve
Vthe size of the air mover outlet)
End of Pipeline
Mx 5'Max
In Service Pipeline Section Being Purged
Verifying the Absence of Gas
A combustible gas indicator(CGI)should be used to verify 0% gas when purging gas from existing
facilities or when working around structures that could contain or trap combustible gas. Structures to
consider include but are not limited to existing pipelines, abandoned pipelines, casings, sewers, confined
spaces, and vaults.
Flaring of Natural Gas
Occasionally, it is desirable to flare (ignite)gas during a purge to eliminate odor, ensure that uncontrolled
combustion does not occur, and to reduce methane emissions to the atmosphere. Consideration should
be given to the distraction this might create to the public in high visibility areas. If this procedure is to be
used, refer to "Venting and Blow Down" in this specification.
Working on Purged Pipeline
When it is necessary to perform work on an existing pipeline which has been purged, precautions shall be
taken to verify that a combustible mixture has not developed inside the pipeline due to leakage from a
segment of pipeline remaining in service, or from the release of gas from residual liquids in the pipeline.
Special care must be taken when performing cutting or welding on such a line. The degree of isolation
should be determined by observing any pressure increases within the purged space with all vents closed
and by monitoring for the presence of natural gas.
PIPE INSTALLATION REV. NO. 15
PURGING PIPELINES DATE 01/01/24
X-4,15r'a STANDARDS 8 OF s
Utilities NATURAL GAS SPEC. 3.17

3.18 PRESSURE TESTING
SCOPE:
To provide a procedure that covers the requirements of pressure testing for new, replaced, or re-
connected pipelines and facilities.
REGULATORY REQUIREMENTS:
§192.121, §192.143, §192.503, §192.505, §192.506, §192.507, §192.509, §192.511, §192.513,
§192.515, §192.619, §192.620, §192.719, §192.725
WAC 480-93-170
OTHER REFERENCES:
ASTM A234 or A860 standards
CORRESPONDING STANDARDS:
Spec. 3.12, Pipe Installation—Steel
Spec. 3.13, Pipe Installation—Plastic
Spec. 3.17, Purging Pipelines
Spec. 3.32, Repair of Steel Pipe
Spec. 3.33, Repair of Plastic(Polyethylene) Pipe
PRESSURE TESTING REQUIREMENTS:
New and Replacement Pipe
New and replaced pipelines and facilities transporting natural gas must be tested and shall maintain a
constant test pressure (excluding fluctuations because of temperature and sunlight)for durations in
accordance with the tables in this specification.
Dry Line Pipe
"Dry line" pipe (pipe that is installed but not put into service immediately) shall be installed and tested
according to the appropriate standard specifications. At the completion of successful pressure testing, the
new dry system should be left with approximately 60 psig air remaining in the pipe. Mark the pressure as
left on the pipe near the end of the pipe or logical future point of connection with a permanent marker.
The presence of this pressure at the time the pipe is put into service will confirm there has been no
damage during the time the system was idle. If pressure has been lost, the pipe is assumed to have
sustained damage somewhere and any damaged portion must be repaired and then tested as if new
before it is put into service. For further guidance on the installation of Dry Line Pipe, refer to Specification
3.12, Pipe Installation—Steel Mains, and Specification 3.13, Pipe Installation — Plastic (Polyethylene)
Mains under the heading Dry Line Installations.
PIPE INSTALLATION REV. NO. 22
PRESSURE TESTING DATE 01/01/25
X-4, sr'a STANDARDS 1 OF 11
Utilities NATURAL GAS SPEC. 3.18

Pressure Testing for Steel
Following are general guidelines for pressure testing steel pipelines:
1. Maximum test pressure permitted, expressed as a percent of SMYS:
CLASS LOCATION 1 2 3 4
AIR OR INERT GAS 80 75 50 40
NATURAL GAS 80 30 30 30
WATER 100 100 100 100
2. Leak Tests/Safety: When testing a high-pressure steel installation (including regulator stations
and farm taps)with air, inert gas, or natural gas, a leak test shall be performed at 100 psig before
increasing to the ultimate required test pressure. This leak test shall be undertaken for the
purpose of evaluating any above ground piping joints and fittings for leaks and is documented on
the "High Pressure Leak Check Performed at psig" line of the Pressure Test Information
sticker. Appropriate safety precautions (limiting access, barricading, warning signs, etc.),
depending on the test medium, shall be taken to protect employees involved in the test procedure
as well as the general public.
3. Maximum test capabilities of fittings such as valves and elbows must be determined before
testing.
4. The minimum test pressure shall not be less than 1.5 times the MAOP. The only exception is for
pipelines where testing to 1.5 times the design pressure creates problems due to limitations
imposed by valves or fittings (refer to Note 3). Contact Gas Engineering should this condition
occur.
5. Pipelines 6-inches in diameter and larger which are designed to operate at more than 40 percent
SMYS are to be tested to a minimum of 90 percent SMYS and as close to 100 percent SMYS as
practical (tests of ERW pipe should be limited to a maximum of 95 percent SMYS). This will
permit them to continue to operate at an established MAOP should a class location change occur.
However, a test to 90 percent of SMYS is not to be used as an alternative to designing a pipeline
to meet a higher-class location which may reasonably be anticipated to occur in the future. Refer
to Note 6 for additional information regarding large-diameter pipe testing procedures.
Pre-Installation Tests: For short sections of pipe for which a post installation test is impractical,
such as a section replacement or repair, a pre-installation pressure test may be substituted. A
short section of pipe must contain only a single piece of pipe with no girth welds (steel) or fusion
joints (PE). The pre-installation test must comply with the pressure requirements and durations
for a post installation test and shall be documented on a Pre-Tested Pipe form (N-2743). The
form is to be kept with the as-built job construction documents.
For pre-tested steel pipe, as long as the material has been stored and managed as described in
Specification 3.12, Pipe Installation —Steel, and there is no evidence of corrosion or damage to
the materials following a successful pressure test, there is no limit to the life of the pressure test
and the materials may be considered of reasonable integrity for use. Refer to Specification 3.32,
Repair of Steel Pipe, "Pre-tested Steel Pipe"for recordkeeping requirements for pre-tested steel
pipe.
PIPE INSTALLATION REV. NO. 22
PRESSURE TESTING DATE 01/01/25
X-4, sr'a STANDARDS 2 OF 11
Utilities NATURAL GAS SPEC. 3.18

If a component other than pipe is the only item being replaced or added to a pipeline, a pressure
test after installation is not required if the manufacturer of the component certifies that any of the
following are true (however a soap test of the tie in weld/connection shall be performed at no less
than the operating pressure of the system):
a. The component was tested by the manufacturer to at least the maximum allowable
operating pressure of the pipeline to which it is being added;
b. The component is manufactured under a quality control system that ensures each item
manufactured is at least equal in strength to a prototype and that the prototype was
tested to at least the maximum allowable operating pressure of the pipeline to which it is
being added (carbon steel fittings and components other than pipe that meet ASTM A105
or ASTM A234, e.g., steel weld caps or threaded fittings); or
C. The component has a pressure rating per an ASME/ANSI classification, MSS
specifications, or by strength calculations described in §192.143.
d. Note: Butt weld steel caps with a specification greater than Grade B do not meet any of
the above criteria and do require a pressure test.
If a single component is replaced or added with no pressure test, the soap test should be
documented using "SOAP" as the test medium and showing the date and time the test is
performed as well as who performed the test. This should be documented on the job card or
yellow pressure test sticker.
6. Full encirclement pressure control type fittings, once welded to large diameter mains, may be leak
tested to 100 psig for 20 minutes against a test cap. This may be performed to assure a leak tight
weld prior to tying in the pressure control fitting to the remainder of the piping which shall be
tested normally in a separate pressure test as required by this specification. This variance from
normal testing procedures may be invoked by recommendation of Gas Engineering when the
carrier pipe to which the fitting is being welded is of a large enough diameter(generally larger
than 8 inches) at a test pressure that might cause deformity of the carrier pipe.
7. Testing of replacement pipe: If a segment of pipeline is repaired by cutting out the damaged
portion, the replacement pipe section must be tested to the pressures required for a new line
installation.
8. Testing instrument pipelines: Instrument pipelines made of steel pipe and subjected directly to
mainline gas pressures shall be tested in accordance with the applicable test requirements in the
above table. It is not necessary to test tubing, but all fittings and connections should be checked
for leaks.
9. Tests to over 50 percent SMYS should be performed with water as the test medium, unless such
a test is impractical. Where a hydrostatic test is impractical, air or inert gas may be used, with the
limitations shown in Note 1. Buildings within 300 feet of the test section must be evacuated during
the test if air or inert gas is used as the test medium.
10. Without prior approval from Gas Engineering, testing using water, air, or inert gas is not permitted
where the test section is isolated from an operating pipeline only by a closed valve, squeeze off
equipment, or plugging equipment, since leakage may occur creating an undesirable and
potentially hazardous situation.
PIPE INSTALLATION REV. NO. 22
PRESSURE TESTING DATE 01/01/25
X-4, sr'a STANDARDS 3 OF 11
Utilities NATURAL GAS SPEC. 3.18

11. Where pipelines are installed on street or highway bridges under permits from governmental
agencies, more stringent testing may be required by the agency than would be required by this
gas standard.
12. Pipe for which hydrostatic testing is used shall be pigged to remove all water from within the pipe.
It may be necessary to utilize additional means of drying the pipe such as pigging with methanol
or introduction of a medium such as nitrogen or desiccated air into the pipeline. Refer to
Specification 3.12, Pigging of Pipe, for more information. Contact Gas Engineering for assistance.
13. Care should be taken to address environmental concerns and regulations with respect to the
disposal of the test medium.
Notification to Washington UTC Prior to Pressure Testing Transmission Pipelines
WAC 480-93-170(1): In the state of Washington, the commission must be notified in writing at least 3
business days prior to the commencement of any pressure test of a gas pipeline that will have an
MAOP that produces a hoop stress of 20 percent or more of the SMYS of the pipe used. Pressure test
procedures must be on file with the commission or submitted at the time of notification.
a) Pressure tests of any such gas pipeline built in Class 3 or Class 4 locations, or within 100
yards of a building, must be at least 8 hours in duration.
b) When the test medium is a gas or compressible fluid, the operator must notify the appropriate
public officials so that adequate public protection can be provided for during the test.
c) In an emergency situation where it is necessary to maintain continuity of service, the
requirements of subsection (1) of this section and subsection (1)(a)of this section may be
waived by notifying the commission by calling the emergency notification line (1-888-321-
9144) prior to performing the test.
PIPE INSTALLATION REV. NO. 22
PRESSURE TESTING DATE 01/01/25
X-4, sr'a STANDARDS 4 OF 11
Utilities NATURAL GAS SPEC. 3.18

PRESSURE TESTING REQUIREMENTS— HIGH PRESSURE STEEL PIPELINE SYSTEMS'
TEST DURATION
PIPE PRESSURE LENGTH OF TEST
SIZES (MINIMUM) TEST OF MAIN (MINIMUM) TYPE OF
DESCRIPTION (in) IN PSIG MEDIUMS (ft.) (Hours) GAUGE REMARKS
As Specified Air, Natural Recording
<_2 by Gas Gas, Inert 0-500 1 Chart
High Engineering Gas,Water3
Pressure: Gas
Mains,
As Specified Air, Natural Recording Soa test joints of
Services 2, '2 by Gas Gas, Inert 3 0-500 4 Chart p
Engineering Gas,Water above grade or
Regulator exposed pipe and
Stations, Farm As Specified Air, Natural Recording fittings during the
Taps,and All by Gas Gas, Inert3 501-2,000 8 Chart test.
Meter Set Engineering Gas,Water
Assemblies As Specified Air, Natural
All by Gas Gas, Inert Over 2,000 24 Recording
Engineering Gas,Water Chart
High As Specified Air, Natural
Pressure: All by Gas Gas, Inert N/A 1 Recording To operate at<30
Cans, Barrels
Engineering Gas,Water3 Chart percent SMYS
Prefabricated As Specified Air, Natural
Welded All by Gas Gas, Inert N/A 4 Recording To operate at>_30
Assemblies or Engineering Gas,Water3 Chart percent SMYS
Units'
Tie-in Joints Current
(all pressures) All Operating Soap Test4 N/A N/A N/A
Pressure
' For installations less than 20 percent SMYS. Refer to WAC 480-93-170(1)for installations with an MAOP that
produces a hoop stress of 20 percent or more of SMYS. Refer to 192.505 for installations with an MAOP that
produces a hoop stress of 30 percent or more of SMYS.
2 Pressure tests of services includes service pipe and service riser. (Does not include customer meter.)
S If water is the test medium, then the test must run for at least 24 hours to allow the pipe and water temperatures to
stabilize.
4 When soap testing,the entire joint shall be visually checked to ensure there are no leaks. Use a mirror or other
means, if necessary,to inspect the entire joint.
5 See the section on Pressure Vessels and Prefabricated Units in Specification 2.12 for more information.
PIPE INSTALLATION REV. NO. 22
PRESSURE TESTING DATE 01/01/25
�rsr�r STANDARDS 5 OF 11
Utilities NATURAL GAS SPEC. 3.18

PRESSURE TESTING REQUIREMENTS—INTERMEDIATE PRESSURE STEEL PIPELINE SYSTEMS
TEST
PRESSURE LENGTH DURATION
PIPE (MINIMUM) TEST OF MAIN OF TEST TYPE OF
DESCRIPTION SIZES IN PSIG MEDIUM (Ft) (Min) GAUGE REMARKS
Air, Natural
All 90 Gas,or Inert 0-10 10 Min Gauge'
Gas
Air, Natural
Intermediate All 90 Gas,or Inert 11-1000 1 Hr. Gauge'
Pressure Gas Gas
Mains Air, Natural 1001- 1 Hr. per 1000 4
All 90 Gas,or Inert 10,000 Ft.' Gauge
Gas
Air, Natural Over Recording
All 90 Gas,or Inert 10,000 24 Hrs. Chart
Gas
Air, Natural
All 90 Gas,or Inert 0-200 10 Min. Gauge
Gas
Intermediate Air, Natural It is recommended to
Pressure Gas All 90 Gas,or 201-1000 1 Hr. Gauge soap test joints of
Services' Inert Gas above grade or
Air, Natural exposed pipe and
All 90 Gas,or Inert Over 1000 1 Hr. Ft r 1000 Gauge fittings during the test
Gas to check for leaks.
Intermediate
Pressure:
Cans, Barrels
& Air, Natural
Prefabricated All 90 Gas,or Inert N/A 15 Min. Gauge
Gas
Welded
Assemblies or
Units6
Intermediate
Pressure Air, Natural
Industrial All 90 Gas,or Inert N/A 1 Hr. Gauge
Meter Set Gas
Assemblies
Tie-in Joints Current
All Operating Soap Testa N/A N/A N/A
(all pressures) Pressure
' Round up to the next full hour
' Pressure tests of services includes service pipe and service riser. (Does not include customer meter.)
3 When soap testing,the entire joint shall be visually checked to ensure there are no leaks. Use a mirror or other
means, if necessary, to inspect the entire joint.
4 If an analog gauge is used, the gauge shall have a range of 0-150 psi with 1 psi divisions(maximum)and an
accuracy of±0.25 percent of full scale (maximum). If a digital gauge is used, the gauge shall meet or exceed the
resolution and accuracy of the analog gauge specified above.
6 If a pressure test combines both main and service, the total length of main plus the service shall be considered as
main (i.e., 800 ft of main plus 600 ft of service tested together shall be tested as 1,400 feet of main)
6 See Prefabricated Unit and Pressure Vessel section in Specification 2.12 for more information.
PIPE INSTALLATION REV. NO. 22
PRESSURE TESTING DATE 01/01/25
X-4, sr'a STANDARDS 6 OF 11
Utilities NATURAL GAS SPEC. 3.18

Pressure Testing Requirements for PE
Following are general guidelines for pressure testing PE pipelines:
1. Maximum test capabilities of fittings such as valves and elbows must be determined before
testing.
2. The minimum test pressure shall not be less than 90 psig.
3. The maximum test pressure for medium density polyethylene pipe shall not exceed 125 psig.
Testing in excess of 120 psig should not exceed a duration of 48 hours. Contact Gas Engineering
if your test will approach these criteria.
4. Pre-installation Tests: For short sections of pipe for which a post installation test is impractical, a
pre-installation test may be substituted. The pre-installation test must comply with the pressure
requirements for a post installation test and shall be documented on a Pre-Tested Pipe form (N-
2743) and the form kept with the as-built job construction documents. The following definition
shall apply:
A Short Section of Pipe is defined as a single piece of pipe containing no girth welds (steel)or
fusion joints (PE).
If a component other than pipe is the only item being replaced or added to a pipeline, a leak test
after installation is not required if the manufacturer of the component certifies that any of the
following are true (however a soap test of the tie in connection shall be performed at no less than
the operating pressure of the system):
a. The component was tested by the manufacturer to at least the maximum allowable
operating pressure of the pipeline to which it is being added;
b. The component is manufactured under a quality control system that ensures each item
manufactured is at least equal in strength to a prototype and that the prototype was
tested to at least the maximum allowable operating pressure of the pipeline to which it is
being added (PE fittings that meet ASTM D2513 standards, e.g., end caps); or
c. The component has a pressure rating per an ASME/ANSI classification, MSS
specifications, or by strength calculations described in §192.143.
If a single component is replaced or added with no leak test, the soap test should be documented
using "SOAP" as the test medium and showing the date and time the test is performed as well as
who performed the test. This should be documented on the job card or yellow pressure test
sticker.
5. Where feasible, plastic pipe must be installed and backfilled prior to pressure testing to expose
any potential damage that could have occurred during the installation process. During the testing,
the pipe shall not be exposed to temperatures above 140 degrees F per the requirements of
§192.121 and §192.513.
For pre-tested plastic pipe, as long as the pipe and fitting materials have not reached or exceeded their
useful life per Specification 3.13, Pipe Installation— Plastic, and the pre-tested materials show no
evidence of damage following a successful pressure test then there is no limit to the life of the pressure
test and the materials may be considered of reasonable integrity for use (refer to Specification 3.33,
Permanent Repair Sleeves, "Pre-tested PE Pipe"for recordkeeping requirements for pre-tested PE pipe).
PIPE INSTALLATION REV. NO. 22
PRESSURE TESTING DATE 01/01/25
X-4, sr'a STANDARDS 7 OF 11
Utilities NATURAL GAS SPEC. 3.18

PRESSURE TESTING REQUIREMENTS - PLASTIC PIPELINE SYSTEMS
OPERATING
PIPELINE TEST LENGTH DURATION
PIPE PRESSURE PRESSURE TEST OF MAIN OF TEST TYPE OF
DESCRIPTION SIZES PSIG MINIMUM MEDIUM FEET MINIMUM GAUGE REMARKS
Air, Natural
All Up to 60 90 Gas,or Inert 0-10 10 Min. Gauge'
Gas
Air, Natural
All Up to 60 90 Gas,or Inert 11-1000 1 Hr. Gauge'
Gas I It is
Air, Natural 1001- 1 Hr. per 4 recommended
Intermediate All Up to 60 90 Gas,or Inert 10,000 1000 Ft.
Pressure Gas joints of above
Gas Mains Air, Natural Over Recording grade or
All Up to 60 90 Gas,or Inert 10,000 24 Hrs. Chart exposed pipe
Gas and fittings
Air, Natural during the test
All Up to 60 90 Gas,or Inert 0-200 10 Min. Gauge to check for
Gas leaks.
Intermediate Air, Natural
Pressure Gas All Up to 60 90 Gas,or Inert 201-1000 1 Hr. Gauge
ServicesZ Gas
Air, Natural
All Up to 60 90 Gas,or Inert Over 1 Hr. per Gauge'
Gas 1000 1000 Ft.
Current
Tie-in Joints All All Operating Soap Testa N/A N/A N/A
Pressure
' Round up to the next full hour
2 Pressure testing of services includes service pipe and service riser. (Does not include customer meter.)
3 When soap testing,the entire joint shall be visually checked to ensure there are no leaks. Use a mirror or other
means, if necessary, to inspect the entire joint
4 If an analog gauge is used, the gauge shall have a range of 0-150 psi with 1 psi divisions(maximum)and an
accuracy of±0.25 percent of full scale (maximum). If a digital gauge is used, the gauge shall meet or exceed the
resolution and accuracy of the analog gauge specified above.
5 If a pressure test combines both main and service,the total length of main plus the service shall be considered as
main (i.e., 800 ft of main plus 600 ft of service tested together shall be tested as 1,400 feet of main)
Reinstating Service Lines
A service line that has been broken, pulled, or damaged resulting in the interruption of gas supply to the
customer shall be pressure tested from the break back to the meter location for the same duration and to
the pressures required for a new service.
If damage is not the cause for service disconnection, then any part of the original service line that is
disconnected (meaning any part of the service that was physically separated or detached from the
system) must be tested in the same manner as a new service line from the point of disconnect to the
meter valve with the exception of, any part of the original service line used to maintain pressure and
continuous service to the customer need not be tested.
PIPE INSTALLATION REV. NO. 22
PRESSURE TESTING DATE 01/01/25
X-4, sr'a STANDARDS 8 OF 11
Utilities NATURAL GAS SPEC. 3.18

Recordkeeping
Pressure test information and/or charts must be completed and retained for the life of the facility. If only a
spring gauge is required for a pressure test, consideration should be given to avoid complicating the
project records by completing a pressure test chart as well.
Where multiple pressure tests are performed on a single installation, there shall be a record for each test.
An example of this would be any continuous on-going job or installation such as a new plat or long main
installed where more than one pressure test was conducted during construction.
I i
I I I
I
I r_
— = E.isting r
= Nev: I I New 2"PE pipe laterals=
2 pressure test stickers
Example of a single unitiassembly Example of multiple facilities on same job.
tested together.
Record the following information on the appropriate pressure test form, sticker, chart, or electronic service
order/work order as applicable. (Note: The recording of the following data is required for both initial
pressure tests of newly installed pipe and pressure tests for retested existing pipe after a damage/
repair.)
• Operator's name
• Employee's name performing the test.
• Test medium used.
• Test pressure.
• Test duration.
• Date of test
• Time of day (use military time)
• Chart Box Setting (as applicable)
• Pipe diameter and footage for each diameter of pipe on a single test.
• Failed test information - If a pressure test fails, fill out the initial pressure information and mark the
"test failed" box, then make repairs, re-pressure test and record the information on a new
Pressure Test Information sticker(Form N-2490).
• Elevation variations, whenever significant(typically applicable for hydro testing)
Care must be utilized to ensure that the time period of the test agrees with the type of test chart being
used.
Refer to Specification 3.33, Repair of Plastic Pipe, "Pre-Tested PE Pipe"for further information of
recordkeeping requirements for pre-tested piping.
PIPE INSTALLATION REV. NO. 22
PRESSURE TESTING DATE 01/01/25
X-4, sr'a STANDARDS 9 OF 11
Utilities NATURAL GAS SPEC. 3.18

Below is an example of the Pressure Test Information sticker(Form N-2490)that should be filled out.
These stickers can also be used on a pressure chart by placing sticker on back of chart(Ensure "Time of
Day" is recorded in military time).
Only individuals who are Operator Qualified on Task 221.120.075, Pressure Testing Gas Pipelines, shall
sign off(Test Performed By)on pressure testing charts and/or test stickers. Note: Please legibly print full
name.
Furthermore, only the person actually performing the pressure test shall sign off on the applicable
documentation.
7WSTW PRESSURE TEST INFORMATION
Test Medium Used
Pressure Tested To PSIG
Gauge Number GPG-
Time of Day Test Started (MilitaryTime)
For Hr. Min.
Diameter of Pipe Footage
Diameter of Pipe Footage
Diameter of Pipe Footage
Test Failed ❑ (repair, retest, record info on new form)
❑ High Pressure Leak Check Performed at psig
The 'As Constructed"information indicated on this print is correct.
All construction complied with current Avista standards/
specifications
Date of Test Test Performed By (Print Name)
N-2490 (01-17)
PIPE INSTALLATION REV. NO. 22
PRESSURE TESTING DATE 01/01/25
�rsr�r STANDARDS 10 OF 11
Utilities NATURAL GAS SPEC. 3.18

PRESSURE TEST PROCEDURES:
1. Isolate the test segment by sealing any open ends such as with a fused cap, welded cap, or a
blind flange, etc.
2. Connect the pressure testing equipment and assemblies to the line.
3. Pressurize the line to the test pressure minimum per the requirements of this specification. Test
pressure should be slightly higher than the specified minimum to assure that the temperature
changes during the test do not cause the test pressure to fall below the minimum allowed to
establish the required design MAOP. If the line to be pressure tested is at a high-pressure facility,
the test must be held at approximately 100 psig and a leak test performed of above ground pipe
joints, and fittings prior to pressurizing the line to the ultimate test pressure.
4. Maintain the test for the duration as specified in the charts per this specification. For long
segments of pipe, maintain the test long enough to be certain that the temperature of the test
medium has stabilized.
5. It is recommended to soap test joints of above grade or exposed pipe and fittings during the test
to check for leaks.
6. Compare the readings before and after the test. If there is no pressure drop during the test, the
pipe has passed the pressure test.
7. If the pressure cannot be maintained, there is a leak that needs to be located and repaired. If a
test fails, record the information from the test on the form, sticker, or chart and note that it has
failed. Fluctuations in ambient temperature during the test may cause the pressure to either
increase or decrease during the test. If a pressure fluctuation occurs and if it is suspected to be
contributed to an ambient temperature change, consult Gas Engineering for further guidance
before concluding the test. Ensure Gas Engineering documentation of the influence of
temperature on a pressure test is stored with the job file.
8. Make repairs and then repeat the pressure test and record the new pressure test information on
another pressure test form, sticker, or chart.
9. When the pressure test shows no sign of leakage, purge the line per company procedures,
Specification 3.17, Purging of Pipelines, and tie in the pipe.
10. Record the test data as outlined in the Recordkeeping section of this specification on the
appropriate pressure test form, sticker, or chart.
PIPE INSTALLATION REV. NO. 22
PRESSURE TESTING DATE 01/01/25
X-4, sr'a STANDARDS 11 OF 11
Utilities NATURAL GAS SPEC. 3.18

3.19 TRENCHLESS PIPE INSTALLATION METHODS
SCOPE:
To provide a procedure that covers trenchless pipe installation methods such as Horizontal Directional
Drilling (HDD), Pipe Splitting and Pneumatic Missiling/Piercing.
REGULATORY REQUIREMENTS:
§192.303
CORRESPONDING STANDARDS:
Spec. 3.12, Pipe Installation—Steel
Spec. 3.13, Pipe Installation— Plastic
Spec. 3.15, Trenching and Backfill
Spec. 3.18, Pressure Testing
GENERAL:
Tracking and Potholing when Crossing Utilities
In order to help prevent a cross bore from occurring, existing underground utilities that cross a trenchless
installation path (regardless of the angle of the crossing) must be verified using depth measurement, as-
built records (i.e., sewer), potholing and/or exposing to protect the existing facilities prior to installation.
Tracking the location and depth of the bore head should be utilized for directional boring installations.
Reasonable means of tracking the location (and depth when possible) of the pneumatic missile are
recommended for missile installations (for example using a metal detector, pipe locator, or feeling ground
surface vibration).
Approved methods for verifying the location and depth of existing utilities within road right-of-way, public
or private utility easement include:
1. Natural gas, petroleum, power, phone, cable TV and fiber optic lines believed to be within 24" of the
full diameter of the proposed bore or ream hole (whichever is greater) shall be potholed to verify
their exact location before crossing and these types of existing utilities shall be exposed within the
proposed bore path. An additional 24" on the underside of the utility shall be exposed in the pothole
if the proposed bore path is beneath the existing utility. This should allow adequate clearances to be
visually verified. If these existing utilities are deeper than 24" below the full diameter of the proposed
bore or ream hole (whichever is greater)then exposure of the utility may not be required as long as
the pothole extends a minimum of 24" below the proposed bore or ream hole within the bore path
and reasonable effort is made to verify the accuracy of the locate during potholing.
2. Existing gravity fed sanitary/storm sewer, pressurized sewer and water utilities that have structures
(manholes, catch basins, inlets/outlets, valve boxes, clean-outs, etc.)that can be measured and
verified to be more than 24" above or below the full diameter of the proposed bore or ream hole may
not need to be potholed. If these existing utilities cannot be verified for depth in the area that the
bored crossing will take place, then the existing utility shall be potholed per item 1 above.
3. Use additional information on sewer maps and as-built records, if available, in combination with
items 1 and 2 above.
4. If incomplete information persists, either an alternative bore path must be chosen, or the facilities
installed via open trench.
PIPE INSTALLATION REV. NO. 14
TRENCHLESS PIPE INSTALLATION DATE 01/01/25
X-4, sr'a STANDARDS 1 OF 6
Utilities NATURAL GAS SPEC. 3.19

Approved methods for verifying the location and depth of existing customer owned utilities within private
property include:
1. Use a fish tape to locate any unconfirmed drainpipe or conduit.
2. Use sewer as-built/card records for information on depth and location, if available. It is
recommended to also look for visual indicators such as a cleanout, locate marks, pipes inside the
structure, etc. to support the information on the card.
3. Use technologies such as GPR (Ground Penetrating Radar)or in pipe camera technology.
4. If incomplete information persists, an alternative bore path must be chosen, or the facilities be
installed via open trench.
Pipe camera technology may be used after installation to verify that the utility has not been damaged. If at
any point it is suspected that a sewer cross-bore situation has occurred, then a camera inspection of that
facility shall be completed within the area of concern.
Horizontal Separation
To account for locate inaccuracy and a wandering drill head, cutting tool or missile, gas pipeline, including
services, should be installed with a 4-foot minimum horizontal separation from other underground utilities.
When using trenchless installation methods close to other utilities, consideration should be made to
pothole them at regular intervals to verify location and separation. Gravity sewer lines, drain fields, steam,
and hot water lines require further separation. Refer to Specification 3.15, Trenching and Backfill,
"Clearances—Steel and PE Pipelines"for details regarding separation from these utilities.
Depth of Cover
Minimum depth of cover for trenchless pipe installations shall be consistent with Avista standards as
outlined in Specification 3.15, Trenching and Backfill, except at waterways. With respect for future
accessibility and maintenance of pipe facilities, it is recommended that a maximum depth of cover of 8-
feet be established most specifically during HDD operations unless conflicts or conditions exist that
require pipe be installed at greater depth (i.e., water crossings, utility conflicts, or geographical features).
When crossing waterways, the depth of cover will be dependent upon a number of factors including the
length of the bore, geological features, size of crossing, obstructions, etc. Consult Gas Engineering for
guidance regarding appropriate depths of cover. To reduce the potential for hydro-fracture extreme care
should be exercised when boring at depths less than 20-foot of cover.
Future Locatability
Pipe installed by any form of trenchless technology must be locatable. PE mains shall have a tracer wire
installed in conjunction with the installation as detailed in Specification 3.13, Pipe Installation — Plastic
(Polyethylene) Mains. Steel mains shall have a test lead wire bonded to the main near the entry or exit
location or have other means of attaching locating equipment to identify the pipe. Refer to Specification
3.12, Pipe Installation—Steel Mains for additional information. In situations where traditional locating
methods will not be capable of locating the main, due to extreme pipe depths, (>12 feet) marker balls
should be located over the pipe installation path. The marker balls should be placed, when possible, at
approximately 10-foot spacing and at a depth of approximately 24 inches. The marker balls will be used
as a reference, in addition to traditional locating methods, to identify the pipe location. Marker balls should
be mapped in GIS to indicate where they have been installed for locating assistance.
Steel—Minimum Radius of Curvature
The following formula is used to determine the minimum radius of curvature (in feet)for steel pipe:
Minimum radius of curvature (feet) = Nominal pipe diameter(inches)x 100
Example: Minimum radius of curvature for 6-inch steel pipe = 6 x 100 = 600 feet
PIPE INSTALLATION REV. NO. 14
TRENCHLESS PIPE INSTALLATION DATE 01/01/25
X-4, sr'a STANDARDS 2 OF 6
Utilities NATURAL GAS SPEC. 3.19

PE—Minimum Radius of Curvature
For plastic pipe, the minimum radius of curvature during trenchless installation is summarized in the table
titled Minimum Permanent Bending Radius in Specification 3.13, Pipe Installation, Plastic (Polyethylene)
Mains.
HORIZONTAL DIRECTIONAL DRILLING:
General
Horizontal Directional Drilling (HDD) may be suitable for areas in which it is beneficial the avoid
excavation at the ground surface.
Permits
Proper permits shall be in place as required by state and local jurisdictions before beginning any HDD
project.
Pilot Hole Alignment
The pilot hole alignment shall be established with the desired entry and exit points, desired depth of
cover, and consideration to the final pipe curvature during the design phase.
HDD Bore Path
HDD bore site and path selection shall consider several factors including but not limited to the
identification of underground obstacles, soil conditions, and suitable bore path alignment. Enough area
must be available at the site to allow for the layout of drilling equipment and materials, as well as enough
room to allow for proper containment of drilling mud and water. For creek, river, and environmentally
sensitive areas, special considerations must be made to prevent hydrofracture and a mitigation plan must
be in place to prevent and/or contain any lost fluids. Refer to"Discharge Mitigation Plan" in this
specification for additional information regarding what to do in the event of a spill or hydrofracture.
Reaming
For pipe less than 4-inch in diameter, reaming is usually not necessary if soil conditions are good, and the
pilot hole has not collapsed. For pipe 4-inch in diameter and larger, once the pilot hole is established it
should be enlarged with a reamer. Reaming should be accomplished using push- or pull-reaming passes
and large quantities of drilling mud to flush tailings from the hole.
The drill operator is responsible to determine and implement a final reamed hole diameter and other
applicable actions that will ensure a successful bore and a pullback of the pipe that results in minimizing
damage to the pipe and pipe coating.
As a rule of thumb, the size of the final reamed hole should be a minimum of 1.5 times the pipe diameter;
however, the size of the reamed hole should not create settlement or cave-in issues. If the bore path is
made up of boulders, gravel, and/or cobble, additional swabbing passes and/or a larger final ream pass
may be required to prevent damage to the carrier pipe and its coating as applicable.
PIPE INSTALLATION REV. NO. 14
TRENCHLESS PIPE INSTALLATION DATE 01/01/25
X-4, sr'a STANDARDS 3 OF 6
Utilities NATURAL GAS SPEC. 3.19

Pullback
The pipe should be pulled through the bore hole using a pulling head with a swivel joint installed between
the pipe and drill stem. The pulling head is typically shaped like a bullet and is one or two pipe diameters
larger than the pipe being pulled in. The leading end of the carrier pipe being pulled through the bore hole
shall be closed prior to starting pullback to prevent any debris from entering the carrier pipe during
installation. The pipe should be supported on rollers or booms at the aboveground work site as it is pulled
through the bore hole to prevent buckling or damage caused from dragging along the ground. When
possible, it is desirable to fully assemble the product pipe and complete the pullback without stopping to
minimize the risk that the pipe will become stuck in the bore hole or that the bore hole will collapse. If
there is a delay between the establishment of the reamed pilot hole and the pullback step, swab passes
may be required to re-establish the bore hole.
During the pulling operation, both the pulling end and trailing end of the gas pipe should be monitored for
continuous and smooth movement. Also, the leading end should be pulled past the termination point,
approximately 3 percent of total length being pulled and observed to assure that excessive damage has
not occurred to the pipe and to allow for any potential contraction or recovery of the pipe.
When pulling in plastic (polyethylene) pipe, constant monitoring of pullback forces should be performed
using a calibrated pressure gauge if available on the pullback equipment. The use of a break-away device
or a "weak link" is required. Refer to Specification 3.13, Pipe Installation— Plastic, for pullback force
limitations and use of a break away device or"weak link" and pipe recovery.
HDD Discharge Mitigation Plan
The drilling operator shall monitor the drilling operation for any uncontrolled discharge of drilling products.
When a risk exists for an undesirable discharge of drilling fluids to the environment the operator shall
follow an established discharge mitigation plan that includes at a minimum the following preventative and
mitigative measures:
1. Implementation of appropriate silt screening or barriers to prevent release of drilling fluids.
2. Work above the high water mark.
3. Monitor waterways during the drilling operation for any signs of hydrofracture.
4. In the event of an uncontrolled discharge stop the drilling operation.
5. Suspend pumping drilling mud into the bore hole.
6. In the event of a hydrofracture, minimize the hydraulic pressure in the bore hole by removing
accessible drilling fluids.
7. Clean up (where possible)the discharged fluid.
8. Immediately notify the Avista Cultural/Environmental Permits Coordinator, at 509-495-2559.
9. Do not resume drilling without the approval of the permit coordinator and the project manager.
PIPE SPLITTING:
General
The trenchless pipe splitting method is suitable for the trenchless replacement of existing steel and PE
gas pipelines with existing diameters ranging from 1/2-inch to 8-inches. The newly inserted pipe must be
the same nominal size or smaller than the existing host pipe.
The splitting of an existing steel or PE pipeline is to be accomplished with a dedicated cutter assembly
and expanding head. An expanding head coupled behind the cutter assembly further opens the split pipe
and compresses any displaced ground material into the surrounding ground.
PIPE INSTALLATION REV. NO. 14
TRENCHLESS PIPE INSTALLATION DATE 01/01/25
X-4, sr'a STANDARDS 4 OF 6
Utilities NATURAL GAS SPEC. 3.19

The expanding head incorporates a new pipe attachment coupling or device that enables the new
replacement pipe to be secured and towed behind the expanding head. The cutter assembly is pulled by
a small diameter rigid steel rod or cable controlled by an approved pulling device.
Determining Factors
When determining whether an existing gas line (host pipe)should be considered for replacement by this
method, the following shall be considered:
• Pipe size.
• Pipe Material.
• Pipe repair clamps on existing line.
• Bends in the line.
• Length of line to be replaced.
• Burial depth.
• Surrounding ground material.
• Suitable insertion and pull pit locations.
• Existing utility locations.
• Any other condition that may prevent successful pipe replacement by this method.
Equipment Requirements— Steel or PE
The equipment suitable for performing the pipe splitting process depends upon the application. For steel
or PE pipe splitting it is acceptable to use a hydraulically operated rod pulling machine complete with
engine or electrically driven hydraulic power supply unit such as a Hammerhead HydroBurst HB3038 or
HB5058 static rod pulling system coupled to dedicated Pipe Splitter or equivalent. A directional boring
machine may also be utilized for this process.
Each individual rigid steel pull rod section shall have its outside diameter small enough to be inserted into
the host pipe to be replaced. The pull rod shall have adequate flexibility to negotiate gradual bends in
existing host pipe during push out and pull back operation. The pipe splitter assembly shall consist of a
robust steel body housing the appropriate steel roller cutter disks or fins and rear expander head with new
pipe attachment device.
Equipment Requirements-PE
For PE pipe, the equipment suitable for performing the splitting process must be of sufficient size and
type for the work being performed.
It is acceptable to use the following mechanical devices:
• Backhoe, excavating equipment.
• Hydraulically operated bore equipment.
• Mechanical cable puller.
A pipe splitter assembly shall consist of either a robust steel body housing the appropriate steel roller
cutter disks or fins and rear expander head or a robust steel body larger than the diameter of the pipe
with fin/knife like barbs welded to the expanding body. Both options will incorporate a new pipe
attachment device.
PIPE INSTALLATION REV. NO. 14
TRENCHLESS PIPE INSTALLATION DATE 01/01/25
X-4, sr'a STANDARDS 5 OF 6
Utilities NATURAL GAS SPEC. 3.19

Procedure
During the operation, there must be constant communication between the operator of the mechanical
pulling device and the person at the entry pit, either by means of hand signals or two-way communication.
Do not enter the receiving pit while the pulling device is in operation.
Refer to "Pullback" in this section for additional information, but a break away device or a "weak link"
(refer to Specification 3.13) shall be used ahead of the new PE pipe being pulled. Install a minimum of
two tracer wires with the new pipe. Before beginning the operation, insert a camera to verify the location
of known fittings.
Excavate and expose identified fittings and remove, if possible, prior to splitting. Cut the services from the
main and remove the mechanical fittings if possible. On locations where services will be tied back in to
the main, cut out the existing host pipe in this vicinity to aid the installation of the new service tee.
PNEUMATIC MISSILING/PIERCING:
General
The use of pneumatic missiles or piercing tools as a trenchless installation method is suitable for gas
main and service pipes with diameters ranging from 1/2-inch up to 2-inches in size if ground conditions
support this installation method. Typically, this method is used for PE installations less than 100 feet in
length.
Determining Factors
When determining whether a new gas line should be installed by this method, the following shall be
considered:
• New pipe size
• Length of installation
• Burial depth
• Surrounding ground material (Ground fill, layering, compaction, etc.)
• Suitable insertion and pull pit locations.
• Existing utility locations
• Any other condition that may prevent successful pipe installation by this method.
Missile Alignment Procedure
The missile alignment shall be established with the desired entry and exit points defined and desired
depth of cover established prior to installation. Prior to the operation of a pneumatic missile or piercing
tool, all required tools and equipment should be inspected to ensure they are safe for use. Inspect the
project site to identify any potential hazards or obstructions. Call for locates, pothole and verify existing
utilities per the "Tracking and Potholing" section of this Specification. Excavate the entry and exit pits and
determine the length of the bore. It is recommended that the air hose be marked to aid in tracking and
monitoring of progress. Use the appropriate alignment tools to line up the missile or piercing tool. Operate
the tool per the manufacturer's instructions. During operation, walk the bore path and track the progress
of the pneumatic tool. Once the bore hole is complete pullback or insert the new carrier pipe, as
necessary. Protect the leading end of the pipe being installed to prevent debris from entering the pipe
during pullback or insertion.
PIPE INSTALLATION REV. NO. 14
TRENCHLESS PIPE INSTALLATION DATE 01/01/25
X-4, sr'a STANDARDS 6 OF 6
Utilities NATURAL GAS SPEC. 3.19

3.2 JOINING OF PIPE
3.22 JOINING OF PIPE -STEEL
SCOPE:
To establish a uniform method for initial and renewal qualification of welders, weld procedure
qualification, and to define acceptable welding practices. Welding performed on the pipeline system shall
follow the Code of Federal Regulation, Title 49, Part 192. Welding performed in the state of Washington
shall also comply with WAC 480-93-080.
REGULATORY REQUIREMENTS:
§192.221, §192.225, §192.227, §192.229, §192.231, §192.235, §192.241, §192.243, §192.245
WAC 480-93-080
OTHER REFERENCES:
API 1104—Welding of Pipelines and Related Facilities
API 1104 Appendix B— In Service Welding
ASME/ANSI B31.8—Gas Transportation and Distribution Piping Systems
CORRESPONDING STANDARDS:
Spec. 2.12, Pipe Design —Steel
Spec. 3.12, Pipe Installation—Steel
Spec. 3.32, Repair of Damaged Pipelines— Repair of Steel Pipe
WELDER QUALIFICATION REQUIREMENTS:
General
Pipeline welding shall be performed by welders or welding operators tested and qualified by Avista and
qualified to API 1104*. Employees qualified to complete production welds shall be qualified to this
standard and applicable sections of API 1104. Welders qualified to complete in-service welds shall be
qualified to API 1104 and may also be qualified to applicable sections of API 1104—Appendix B.
Individuals qualified to this standard also satisfy the skills required for Visual Inspection of the Weld
(221.130.005). Welds that will not be exposed to the test pressure and that will not be a part of the gas
carrying system need not be completed by a qualified welder or to a qualified weld procedure. Welding
processes commonly used in pipeline welding procedures include shielded metal arc (SMAW)and gas
metal arc (GMAW).
(*) Denotes the edition of API-1104 currently adopted under CFR 49, Part 192, 192.7(b)(9).
Qualification of Welders
No welder may weld with a particular welding process unless, within the preceding 6 calendar months,
the welder has engaged in welding with that process. Alternatively, welders may demonstrate they have
engaged in a specific welding process if they have performed a weld with that process that was tested
and found acceptable under section 6, 9, 12, or Appendix A of API 1104 within the preceding 7-1/2
months.
JOINING OF PIPE REV. NO. 24
STEEL DATE 01/01/25
X-4, sr'a STANDARDS 1 OF 14
Utilities NATURAL GAS SPEC. 3.22

Welders may maintain an ongoing qualification status by performing full circumferential welds, tested, and
found acceptable under the above acceptance criteria at least twice each calendar year, but at intervals
not exceeding 7-1/2 months. If the initial welder qualification occurs after June 30th, the welder does not
need to requalify the same calendar year. Initial qualification welds shall be evaluated by destructive
testing. Re-qualification welds may be determined acceptable by non-destructive (radiographic)or
destructive testing. If non-destructive testing is used to re-qualify a welder, the technician evaluating the
weld must include the name of the welder being re-qualified on the non-destructive testing evaluation
form. Welders who fail to re-qualify within the 7-1/2-month interval shall complete the initial qualification
requirements when qualifying to weld.
Welders shall be initially qualified per Section 6.3, "Multiple Qualification"of API 1104 and by welding
process (GMAW and/or SMAW). If a welder desires to weld with multiple processes a successful initial
qualification or re-qualification test shall be completed with all desired processes. One of the following
qualification tests shall be completed as appropriate for the welder's area of service and qualifications.
Welders shall be qualified by the following variables:
1) Process (GMAW and/or SMAW)
2) Direction of welding (Vertical Uphill and/or Vertical Downhill)
3) Diameter(6.625-inches or 12.75 inches for All Diameters)
4) When welding with the SMAW process a change of filler metal classification from Group 1 or 2 to
Group 3 or from Group 3 to Group 1 or 2.
A welder shall only weld within the parameters of their qualifications. Re-qualification is required if any of
the above essential variables is changed.
Recommended Initial Qualification Test—Production and In-service <60 psiq
Process: GMAW or SMAW
Qualification Procedure: E6010* or ER-70-S*and as determined by material yield strength and process.
*Note: The qualification will only qualify the welder to weld downhill.
Qualification Material: 6.625 inch or 12.750-inch Diameter with a wall thickness >_ 0.250 inches.
Yield Strength: ASTM A53, Grade B thru API 5L Grade X52
Weld Test 1: Butt Weld, Horizontal Fixed Position
Weld Test 2: Layout, Cut, Fit, and Weld a full-sized branch on pipe connection. A full-size hole shall be
cut into the run. Weld shall be completed in the horizontal fixed position with the branch down.
Acceptance Criteria:
Butt-
A) Visual per API 1104, Section 6.4
B) Destructive testing per API 1104, Section 6.5
Branch -
A) Weld shall exhibit a neat, uniform workman like appearance.
B) Weld shall exhibit complete penetration around entire circumference.
C) Complete root beads shall not contain any burn through of more than inch. The sum of the
maximum dimensions of separate unrepaired burn-through in any continuous 12-inch length of
weld shall not exceed 1/2 inch.
D) Destructive testing per API 1104, Section 6.3.1 (4 Nick Breaks).
Welder Qualifications: A welder who has successfully completed both of the qualification welds shall be
qualified to complete welds on all non-pressurized piping and weld on in-service piping with a Maximum
Allowable Operating Pressure (MAOP) less than or equal to 60 psig with the Process qualified (SMAW or
GMAW) in all positions, wall thicknesses,joint designs, fittings, and diameters <_ 6.625 inches or all
diameters if test completed on 12.750 inch material.
JOINING OF PIPE REV. NO. 24
STEEL DATE 01/01/25
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Utilities NATURAL GAS SPEC. 3.22

Recommended Initial Qualification Test—In-Service Weldinq >60 psiq
Process: GMAW or SMAW
Qualification Procedure: E7018*or ER70-S as appropriate and as determined by material yield strength
and process.
*Note: This qualification will qualify the welder to weld uphill for E7018.
Qualification Material: 12.750-inch Diameter with a wall thickness >_ 0.250 inches.
Yield Strength: ASTM A53, Grade B through API 5L Grade X52
Weld Test 1: Layout, Cut, Fit, and Weld a 12.750-inch diameter sleeve 8 inches long onto a 12.75-inch
diameter pipe 16 inches long. Weld shall be completed at an angle 45 degrees from the Horizontal (6G
Position).
Welder Qualifications: A welder who has successfully completed the qualification weld and subsequent
destructive testing as outlined in API 1104, shall be qualified to weld with the Process Qualified (SMAW
or GMAW), on all pressurized systems, in all positions, all diameters, all wall thicknesses, all material
grades, and all branch connection sizes.
Recommended Re-Qualification Test—Production and In-Service
Process: GMAW or SMAW
Qualification Procedure: E6010, E7018, or ER-70-S and as determined by material yield strength and
process.
Qualification Material: 6.625 inch or 12.750-inch Diameter with a wall thickness >_ 0.250 inches.
Yield Strength: ASTM A53, Grade B through API 5L Grade X52
Weld Test 1: Butt Weld, Horizontal Fixed Position
Welder Qualifications: A welder who has successfully completed the re-qualification weld shall be
qualified to weld within the variables of their original qualification.
Weld Testing
Pressure Controlmen of Avista are the only personnel authorized to administer weld testing. The person
administering the weld test shall also be the inspector. Each weld test shall be completed using an
approved welding procedure. The individual administering the weld test shall document all appropriate
information on the Welder Qualification Test Report (Form N-2562), including results of the destructive
test as outlined in API 1104. Records of welder qualification shall be retained for at least 6 years from the
date of qualification.
Retesting after Failure
A welder who has failed the qualification test may be allowed to retest no sooner than 48 hours later and
after completing further practice and/or training. A welder who has failed the qualification test shall not
perform any welding on gas facilities until they pass the qualification test.
Welder Certification Card
Welders passing the qualification test and destructive testing shall be issued a company Welder
Certification card by the evaluator performing the weld evaluation test. This certification card should
indicate the name of the qualified individual, date of qualification, expiration date, process qualified
(SMAW or GMAW), Qualification Parameters (In-service<_ 60 psig and Production or High Pressure),
Qualified Diameter(<_6.625-inches or All Diameters), approved weld direction, approved filler metal
groupings when appropriate, and the name of the evaluator. The qualified individual must have the card
available for inspection when performing welding in the field. Welder Certification cards shall be valid for 6
months.
JOINING OF PIPE REV. NO. 24
STEEL DATE 01/01/25
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Utilities NATURAL GAS SPEC. 3.22

WELD CERTIFICATION CARD
Front of Card:
,jli! WELDER
iPaRflSTA CERTIFICATION
Welder No.
Certification Date
Expiration Date*
Qualified for Welding Process
SMAW ❑
(See back of card) GMAW ❑
'Card holder must call for test 2 weeks in advance.
Qualified By:
N-2691(9-20)
Back of Card:
Direction Filler Metal Pressure
Process Diameters of Welding Grouping Class
❑SMAW ❑ <_6.625 ❑ Uphill ❑ Group 1 ❑ <_ 60 psig
❑ All Dia. ❑ Downhill E6010 ❑ All
❑ All ❑ Group 2 Pressures
E8010
❑ Group 3
E7018
❑GMAW ❑, :56.625 ❑ Downhill ❑ Group 5 ❑ 1560 psig
❑ All Dia. ER70-S ❑ All
Pressures
Note: Welder is qualified to the variables listed above. The welder may complete a weld using any
qualified Avista weld procedure within the parameters of the employees' qualifications.
WELD PROCEDURE QUALIFICATION REQUIREMENTS:
General
Detailed weld procedures shall be developed and qualified in accordance with API 1104, Section 5 and
copies of these procedures shall be on site where welding is being performed. Procedures shall be
retained and followed when completing welds.
Weld Procedure Qualification
Details of each qualified procedure shall be recorded on a Procedure Qualification Record (PQR). The
qualification record shall include the details as outlined in Section 5.3, API 1104. The PQR shall be
maintained as long as the procedure is in use.
JOINING OF PIPE REV. NO. 24
STEEL DATE 01/01/25
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Utilities NATURAL GAS SPEC. 3.22

The quality of the welds used to qualify the procedures shall be determined by destructive testing as
detailed in API 1104, Section 5.6 for Butt Welds and Section 5.8 for Fillet Welds. A procedure must be re-
established as a new procedure specification and must be re-qualified when any of the essential variables
listed in API 1104 Section 5.4.2 are changed as listed below:
• Welding Process—Change in weld process
• Base Material Yield Strength Grouping —Change in base metal grouping
• Joint Design— Major change in joint design
• Position —A change from roll to fixed, or vice versa
• Wall Thickness Grouping —A change from one wall thick group to another
• Filler Metal—Change in filler metal group
• Electrical Characteristics—Change from DC electrode positive to DC electrode negative or vice
versa. A change in current from DC to AC or vice versa
• Time between Passes—An increase in the maximum time between passes
• Direction of Welding—Change from uphill to downhill or vice versa
• Shielding Gas Flow Rate—Change in shielding gas, mixture, or increase/decrease in flow rate
range greater than 20% of the nominal flow rate
• Shielding Flux—A change in shielding flux that changes the AWS classification number
• Speed of Travel —Change in speed range
• Preheat— Decrease in specified minimum preheat temperature
Procedure changes other than those listed above are allowed when specifically authorized by the
company, as provided for in Section 5.4 of API 1104. Authorized changes shall be noted on a revised
procedure specification.
Weld Procedure Groupings
Production weld procedures shall be grouped as specified in API 1104 and as follows:
1) Process—(SMAW, GMAW)
2) Base Material—(Yield Strength <_42,000 psi, Yield Strength >42,000 psi and < 65,000 psi, Yield
Strength > 65,000 psi requires a separate procedure for each pipe grade)
3) Diameter—(Dia. < 2.375 inches, Dia. 2.375 inches through 12.750 inches, Dia. >12.75 inches)
4) Wall Thickness—(w.t. < 0.188 inches, w.t. 0.188 inches through 0.750 inches, w.t. > 0.750
inches)
5) Weld Position— Fixed or Rolled
In-service welding procedures will be grouped as follows:
1) Process—(SMAW, GMAW)
2) Base Material—(Yield Strength <_42,000 psi, Yield Strength >42,000 psi and < 65,000 psi, Yield
Strength > 65,000 psi requires a separate procedure for each pipe grade)
3) Diameter—(Dia. < 2.375 inches, Dia. 2.375 inches through 12.750 inches, Dia. >12.750 inches)
4) Wall Thickness—(w.t. < 0.188 inches, w.t. 0.188 inches through 0.750 inches, w.t. > 0.750
inches)
When qualifying a weld procedure, the procedure qualification material shall be of the highest yield
strength material in the category. When material of lower yield strength is selected the procedure shall
only be qualified to the maximum yield strength tested.
WELDING CONTROL REQUIREMENTS:
Weld Type/Procedure Selection
JOINING OF PIPE REV. NO. 24
STEEL DATE 01/01/25
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Utilities NATURAL GAS SPEC. 3.22

Prior to the welding of pipe or fittings, the welder must first select the proper welding procedure. When
welding pipe or fittings of two different yield strengths the procedure for the material of the highest yield
strength shall apply. If welding on intermediate pressure pipe and the grade is unknown, select the
welding procedure for material grade X46 <_X52. If welding on high pressure pipe and the grade is
unknown, contact Gas Engineering for assistance determining the correct welding procedure.
Weld procedures shall be located on-site where welding is being performed. Piping, fittings, and
appurtenances to be arc welded shall be welded using one of the following arc welding processes:
• Shielded metal arc welding (SMAW)
• Gas metal arc welding (GMAW)
This standard covers the SMAW process using cellulose electrodes (AWS Exx10)for production welding
or in-service welding on systems with an operating pressure of 60 psig or less and GMAW or SMAW
using a cellulose electrode (E6010)for the root pass followed by a low-hydrogen (E7018) electrode for
the filler and cap pass for production welding or in-service welding on systems operating at any pressure
or stress level.
Welding on pipe greater than 12-inch diameter(nominal)should be welded simultaneously by a minimum
of 2 welders on opposite sides of the pipe (often referred to as brother-in-law welding). If this is not
possible, the single welder shall weld one quadrant(1/4 of circumference) at a time, moving to the
opposite quadrant after each pass, and welding the opposite quadrant to offset expansion/contraction
stresses due to welding.
Weld Preparation
Tools and equipment used for welding shall be of a capacity suited to the work to be performed. The
welding operation must be protected (shielded)from weather conditions (rain, snow, ice, or high winds)
that would impair the quality of the completed weld.
Prior to the welding, the weld groove and the adjacent surfaces shall be cleaned and kept free of all dirt,
paint, rust, scale, moisture, oil, grease, or other foreign material harmful to welding. Cleaning should be
performed by filing, hand or power wire brushing or grinding, and/or using approved solvents. Before
sections of pipe and fittings are assembled for welding, all rust, scale, slag, dirt, liquids, or other foreign
matter shall be removed from the inside surface of the pipe by swabbing with clean rags or by other
acceptable methods. Responsible person(s) on the job shall ensure compliance with this requirement.
Non-Destructive Pre-Inspection
Prior to welding or cadwelding on a pipeline, a visual inspection of the carrier pipe shall be completed.
Visual inspection shall ensure the surface is free of manufacturing defects, corrosion, dents, scrapes,
gouges, or other anomalies that may be detrimental to the pipeline.
When welding appendages, stopper fittings, service tees, cadwelding, etc. to high pressure in-service (>
60 psig) piping, the area of the carrier pipe to be welded should be inspected to verify wall thickness and
verify for the absence of laminations using ultrasonic test equipment prior to welding. If inspection of the
carrier pipe is required in the area of the long seam weld protrusion, the cap of the weld may be removed
to a smooth contour with the adjacent pipe using a powered sanding disk.
On pipe with suspected or known long seam anomalies, the long seam weld should be inspected using
an X-Ray, shear-wave ultrasonic or magnetic particle inspection prior to welding to verify the integrity of
the carrier pipe and the absence of subsurface cracks, discontinuities, or inclusions.
JOINING OF PIPE REV. NO. 24
STEEL DATE 01/01/25
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Utilities NATURAL GAS SPEC. 3.22

Pipe End Alignment
ASME B31.8, Appendix I shall govern the end preparations for butt welding regarding internal and
external offset. Pipe and/or fittings joined by welding shall be aligned to minimize any offset(high-low) of
pipe wall surfaces around the circumference of the pipe. For pipe designed at less than 20 percent SMYS
and the nominal wall thickness of the adjoining ends does not vary more than 1/8-inch, no special
treatment is necessary provided adequate penetration and bond is accomplished in welding.
If the internal offset exceeds 1/8-inches for pipe designed at < 20 percent SMYS or 3/32-inches for>_ 20
percent SMYS, a piece of transition pipe with a wall thickness between the two shall be used or the use of
a back bevel (14 degrees minimum and 30 degrees maximum) made on the inside end of the thicker
section. External offset shall be limited to the out-of-roundness and pipe and fitting end diameter
tolerances given in the material specifications. The illustration below shows the use of a back bevel.
30' MAX
14' MIN (1:4)
If the pipe or fitting ends are defective or damaged (scratches, gouges, dents, etc.), the ends shall be re-
beveled.
The joint design and fit up shall be governed by the appropriate weld procedure. The Root-opening gap
for SMAW and GMAW welds shall preferably be 1/16 of an inch, not to exceed 3/32 of an inch. The joint
design for Fillet welds shall ensure a full penetration weld.
Hammers used for aligning pipe and fittings must be bronze or brass faced. Care should be exercised to
avoid denting, gouging, or scratching the pipe and/or fittings. When aligning abutting lengths of pipe for
welding, the longitudinal seams shall be staggered (no closer than 3 inches).
The pipe or component must be aligned to provide the most favorable condition for depositing the root
bead and the alignment must be maintained while the root bead is being deposited. A lineup clamp
should be used for butt welds on pipe in the field with a nominal diameter of 2-inches or larger. If a lineup
clamp is used it shall be left in place until the root bead is at least 50 percent completed and equally
deposited around the weld groove. No stress (pipe movement) shall be placed on the weld until the weld
is complete.
Miter Joints
Miter joints are not allowed. Inflections are to be completed using an appropriate pipe bending machine or
fittings. Refer to Specification 3.12, Pipe Installation - Steel Mains for details related to mitering weld
elbows.
Circumferential Weld Separation
The minimum separation between any two circumferential welds, wherever possible, shall be:
• One pipe diameter for welds on pipelines other than station piping, but never less than 3 inches
(Note: Fittings may be welded back-to-back)
JOINING OF PIPE REV. NO. 24
STEEL DATE 01/01/25
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Utilities NATURAL GAS SPEC. 3.22

• Six inches for station piping or fabricated assemblies 6-inch nominal O.D. and larger. One pipe
diameter for piping smaller than 6-inch nominal O.D.
• One inch, as measured along the inside arc radius of any welding elbow and transverse
segments of these elbows, 2-inch or more in nominal diameter.
Adequate working clearance shall be provided and maintained around the pipe and/or fittings at all points
to be welded so that the work can be performed safely.
Branch connection welds including reinforcing member welds, should be located at least 3 inches away
from circumferential welds whenever possible.
Maintaining minimum weld separation assures adequate ductility of the welded assembly and avoids
stress concentrations.
Preheating
Preheating pipe prior to completing a weld helps ensure a superior weld by removing moisture and
contaminates from the surface of the steel. Preheating pipe ensures a proper temperature can be
maintained when completing in-service welds and reduces the potential for cracking.
Refer to the individual welding procedures for when preheating is required. The preheated area shall be
at least 6 inches wide, centered about the weld, and shall extend around the entire circumference of the
pipe or fitting.
Preheat temperature shall be checked with temperature sensitive crayons, such as "Tempilstick",
pyrometer or infrared gun, at the weld area outside of the weld groove. If welding is interrupted, the weld
area shall again be preheated before welding is resumed.
Post Heat Weld Treatment
Avista's current welding procedures do not require post heat weld treatment.
Over-Cooling
Welding on pipelines experiencing high gas flow rates should be avoided as high gas flow rates may cool
welds too quickly and cause weld defects including weld cracking.
Welds shall be allowed to air cool in ambient conditions unless a post heat treatment is specified in the
welding procedure. Water, forced air, or other means of expediting cooling shall not be used.
Grounding Devices
Grounding devices shall be positively attached to the pipe in such a manner to prevent arcing between
the grounding device and pipe. No welding electrode or grounding device shall be permitted to arc to the
pipe except in the actual bevel being welded. Grounds should not be located on flanges or threaded
components such as caps or plugs as this may cause arcing across the threads. Grounds should be
located as near as practical to the weld and should not be placed on the opposite side of a valve.
Butt Welding Technique
Horizontal and vertical fixed position shielded metal-arc welding with cellulose electrodes (AWS Exx10)or
wire electrode (ER70S-2, 6) shall be performed by the "Downhill" method. Welding with low-hydrogen
electrodes (E7018) shall be performed by the "Uphill" method.
JOINING OF PIPE REV. NO. 24
STEEL DATE 01/01/25
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Utilities NATURAL GAS SPEC. 3.22

Pipes to be welded shall be aligned and the root opening (gap) shall be aligned as in the weld procedure
specification and should suit the preference of the welder responsible for the integrity of the root bead.
During alignment and tacking, the joint is held together by a lineup clamp. Care must be taken during joint
alignment and preparation to ensure full penetration and complete fusion during root bead (first pass)
deposit.
Depositing Root Bead and Hot Pass
Strike the arc in the weld groove only. Thoroughly clean the root before applying hot pass (second bead).
Disc grinding shall be used to remove bumpy starts and slag, improve bead contour, or remove excessive
"wagon tracks" before applying the hot pass. Wagon tracks are slag-filled crevices on either side of the
root bead.
Applying the hot pass with sufficient heat(amperage)will melt out shallow wagon tracks and float any
remaining slag to the surface. Start the hot pass immediately after completion of the root bead as
delineated in the Weld Procedure, typically within 5 minutes.
Filler and Cover Passes
A side-to-side weave motion is used when applying the filler passes. Filler metal shall be added to any
concave portion of the filler passes, before applying the cover pass.
On heavy wall pipe and fittings (greater than standard wall thickness)where the welding groove is wide,
more than one bead per layer shall be used for filling in the "downhill' direction.
Strip capping shall be used for making the cover pass when welding in the vertical fixed position. Wash
passes are not acceptable when welding in this position.
Filler and cover passes made using the weave motion when welding downhill on horizontally fixed pipe
and fittings shall be no wider than four times the electrode diameter. Welds shall be uniform and without
undercutting.
Two beads shall not be started at the same location. The face of the completed weld should be
approximately 1/8 inch greater than the width of and centered on the original groove. At no point shall the
crown surface be below the outside surface of the pipe, nor should it be raised above the parent metal
more than 1/1 6-inch.
Filler and cover passes made using the weave motion welding uphill on horizontally fixed pipe and fittings
shall be no wider than 5/8-inch using 3/32-inch diameter rod and 1-inch using 1/8-inch diameter rod.
On pipe or fittings in the vertical fixed position, each weld layer shall be deposited with multiple passes in
the horizontal plane. Wash passes shall not be permitted. The completed weld shall be thoroughly
brushed and cleaned.
JOINING OF PIPE REV. NO. 24
STEEL DATE 01/01/25
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Utilities NATURAL GAS SPEC. 3.22

Roll Welding
Roll welding is not permitted. Repositioning of the pipe joint is permitted as long as all welding is
performed while the pipe is in a fixed position.
Fillet Welding
In-service circumferential fillet welds on sleeves for high-pressure transmission pipelines with an MAOP of
20 percent SMYS or greater shall be made using low-hydrogen electrodes E7018 or GMAW using
ER70S-2, 6 wire. Fillet welds on sleeves and fittings for high pressure pipelines operating at an MAOP
less than 20 percent SMYS may be completed using an E6010 root with E7018 filler and cap however an
all low-hydrogen process (GMAW) is preferred. For intermediate pressure distribution pipelines with and
MAOP 60 psig or less, cellulose electrodes (AWS Exx10) are acceptable for fillet and longitudinal welds.
Fillet welds shall be essentially flat with full throat and legs of uniform length in accordance with the
welding procedure. Undercutting in the fillet weld where the leg meets the parent metal is prohibited. If
undercutting occurs in this area, it shall be ground out and a reinforcing pass applied in the undercut
area.
The welder shall use caution and experience when welding on pressurized piping. It is prudent to know
the wall thickness of the carrier pipe when welding so that Speed of Travel, Voltage, and Amperage can
be controlled properly within the parameters of the procedure to produce a satisfactory weld without burn
through. Extreme care shall be exercised by an experienced welder when welding large fittings to thin
wall pipe to ensure the proper control of heat input to ensure good penetration without burn through.
As recommended per ANSI B31.8, slip flanges should be fillet welded on both the front and the back of
the fitting per the diagrams below.
y
1.4t 1.4
t 1.4t 1.4t
yz'MAX
t t
0.707t
(OR t IF PREFERRED)
FRONT AND BACK WELD FACE AND BACK WELD
Socket Welding
Socket welds shall be made with a space between the pipe and socket weld fitting within the ranges and
dimensions shown in the diagram below. This will help eliminate stresses in the weld metal due to thermal
expansion of the pipe during the welding process. If the end of the pipe is cut, the end should be square
so the space between the pipe and socket weld fitting is uniform. Refer to the diagram below for an
illustration.
JOINING OF PIPE REV. NO. 24
STEEL DATE 01/01/25
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Utilities NATURAL GAS SPEC. 3.22

Socket Weld
Fitting
Pipe
Preferred: Minimum Acceptable:
Y,s"minimum or install socket spacer ring Ya"or tnominal,whichever is less
Non-Destructive Testing(NDT) Requirements
Welds on pipelines with an MAOP that results in a pipe stress level of 20 percent or more of SMYS shall
be non-destructively tested by any process other than trepanning that will clearly indicate defects that
may affect the integrity of the weld. NDT inspection should also be considered for gas pipelines being
installed on a bridge with an MAOP of 250 psig or more. The NDT results shall be interpreted by a person
certified to Level II in accordance with recommendations by the American Society for Nondestructive
Testing or other recognized organization when practical. The acceptability of a weld that is non-
destructively tested or visually inspected shall be in accordance with API 1104 Section 9. The person
evaluating the weld must include the name of the welder on the non-destructive testing evaluation form.
When NDT testing is required, the following percentages of each day's field welds selected at random by
the Operator must be examined using NDT over their entire circumference (when there is more than one
welder, a sample of each welder's work for each day must be included in the random selection):
• 10 percent (at a minimum) of welds - Class 1 locations
• 15 percent(at a minimum) of welds - Class 2 locations
. 100 percent of welds - Class 3 and 4 locations and at crossings of major or navigable rivers, and
within railroad or public highway rights-of-way, including tunnels, bridges, and overhead road
crossings. Exception: Where 100 percent is impractical, at least 90 percent of the welds shall be
non-destructively inspected. (Any girth weld not tested must have been impracticable to test)
• 100 percent of welds at pipeline tie-ins, including tie-ins of replacement sections.
When NDT testing is required, a record must be retained for the life of the pipeline showing by milepost or
by geographic feature, the number of girth welds made, the number non-destructively tested, the number
rejected, and the disposition of the rejects.
Non-destructive testing of welds shall be completed by a third-party contractor. Contractor work shall be
completed in accordance with contractor qualified procedures accepted by Avista. Contractor shall
maintain qualified procedures in accordance with industry standards and must be available on the job
site. Avista shall maintain a copy of current contractor qualified procedures.
Welds shall be visually inspected by an individual qualified in visual inspection. A welder may visually
inspect their own welds when qualified to do so. Inspection by the welder does not preclude external
inspection to ensure conformance and acceptability by the company. Visual Inspection Criteria are listed
within this specification for reference.
In addition to visual inspection of the weld, the welder or weld inspector shall ensure that the weld is
completed in a workmanlike manner and in accordance with the procedure.
JOINING OF PIPE REV. NO. 24
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Utilities NATURAL GAS SPEC. 3.22

Procedure inspection criteria should include the following:
1. Inspect the joint alignment and fit up.
2. Preheat requirements are being met, if required.
3. Use of proper electrodes for the procedure being used.
4. Check the amperage settings with an ammeter and verify the voltage settings to make sure that they
fall within the ranges specified for the electrode size and type for the weld procedure being used.
5. Verify the speed of travel is within the parameters of the procedure by timing and recording the
actual welding time for each pass needed for the procedure and calculate the speed of travel in
inches per minute.
6. Check for potential weld defects as listed within this specification.
7. On completion of weld, check for appearance and cap size.
Determining Speed of Travel
Use the following formulas to determine the speed of travel in inches per minute:
Speed of Travel (inches per minute) = Distance (inches) _Total Seconds x 60
Example: Determine the speed of travel if a 5-1/2" long weld was made in 39 seconds.
Travel Speed = 5.5 inches _ 39 seconds x 60 = 8.46 inches per minute
If the welding time was over a minute, use the following formula to convert welding time to seconds:
Total Seconds = Minutes x 60 + Seconds
Example: Determine the welding time in seconds if the weld took 2 minutes and 12 seconds to complete.
Total Seconds = 2 minutes x 60 + 12 = 132 seconds
Removal or Repair of Weld Defects or Cracks
With the exception of shallow crater cracks and star cracks not exceeding a length of 5/32 inch, no weld
containing cracks, regardless of size or location shall be acceptable. Welds containing cracks and other
unacceptable defects that are detected during or immediately after welding shall be repaired or removed.
Cracks to be repaired in butt welds or fillet welds of branch connections or sleeves that are 8 percent or
more of the weld length must be cut out and replaced. If the aggregate length of more than one crack in a
single weld is 8 percent or more of the weld length, then the weld must also be cut out and replaced.
Cracks to be repaired of any length in longitudinal welds in pipe operating with an MAOP of 20 percent or
more of SMYS or 500 psig or greater must be repaired by replacing the pipe segment. Cracks in
longitudinal welds in pipe operating with an MAOP below 20 percent of SMYS or 500 psig may be
repaired using the patching, sleeving, or canning repair methods given in Specification 3.32, Repair of
Steel Pipe.
If a longitudinal or branch connection weld has a crack that is less than 8 percent of the weld length, the
weld may be repaired by grinding, filing, or machining the repair cavity to bright clean base metal, and fill
welding. If the aggregate length of more than one crack in a single weld is 8 percent or more of the weld
length, then the weld must be cut out and replaced. Refer to Specification 3.32, Repair of Steel Pipe for
other permissible repair methods.
Repair of a crack or defect in a previously repaired area can only be repaired by an appropriate sleeve or
the section cut out and replaced.
JOINING OF PIPE REV. NO. 24
STEEL DATE 01/01/25
X-4, sr'a STANDARDS 12 OF 14
Utilities NATURAL GAS SPEC. 3.22

Electrode Storage
Cellulose electrodes (AWS Exx10) shall be stored in protected dry storage areas and shall not be heated
(store at room temperature 60-80 degrees F).
To perform properly, Low-Hydrogen E7018 electrodes must be stored and handled in a manner which will
prevent absorption of moisture. Low hydrogen electrodes shall be either stored in their manufacturer's
unopened container or a holding oven or electrode warmer which must be maintained at 250-350 degrees
F.
If used immediately, low-hydrogen electrodes may be issued for use directly from freshly opened
hermetically sealed containers. Low hydrogen electrodes which have been exposed to high moisture
conditions or have been removed from the holding oven or electrode warmer for a length of time
exceeding four hours shall be discarded.
Electrodes in unopened sealed containers remain dry indefinitely under good storage conditions. The
storage area should be enclosed, clean, dry, and have adequate facilities for safe storage to prevent
deterioration. Welders who become qualified to use low-hydrogen electrodes shall be thoroughly
instructed in storage and handling requirements.
Visual Inspection
WELD DEFECTS/CAUSES/VISUAL CHECK:
Inadequate Penetration without high-low is an incomplete filling of the weld root.
Causes— Improper welding technique, insufficient joint space, or improper fit-up.
Visually check-Joint space and fit-up, and conformance to the weld procedure.
Inadequate Penetration Due to High/Low is defined as the condition that exists when one edge of the root
is exposed (or unbonded).
Cause- Because adjacent pipe or fitting joints are misaligned.
Visually check-For proper use and adjustment of clamps.
Incomplete Fusion is defined as a surface imperfection between the weld metal and the base material
that is open to the surface. It can be in the root or in the cap.
Cause— Improper welding technique.
Visually check-For conformance to welding procedure including amperage and travel speed and joint
design.
Incomplete Fusion Due to Cold Lap is defined as an imperfection between two adjacent weld beads or
between the weld metal and base metal that is not open to the surface.
Cause- Improper welding technique.
Visually check-For conformance to the welding procedure, proper interpass cleaning. Welding angle
can contribute to this defect.
JOINING OF PIPE REV. NO. 24
STEEL DATE 01/01/25
X-4, sr'a STANDARDS 13 OF 14
Utilities NATURAL GAS SPEC. 3.22

Internal Concavity is defined a bead that is properly fused to and completely penetrates the pipe wall
thickness along both sides of the bevel, but whose center is somewhat above the inside surface of the
pipe wall.
Cause— Excessively wide joint space and improper welding technique.
Visually check-For conformance to the welding procedure including joint space.
Burn-Through is defined as a portion of the root bead where excessive penetration has caused the weld
puddle of the root or hot pass to be blown into the pipe causing a rounded contour in the middle of the
root pass.
Causes— Root pass too thin, excessive, or improper grinding of root pass, pipe out of alignment.
Visually check-For conformance to the welding procedure including pipe alignment.
Slag Inclusions is defined as a nonmetallic solid entrapped in the weld metal or between the weld metal
and the parent metal. Elongated slag inclusions are usually called "wagon tracks".
Cause— Flux coating particles trapped between weld passes or between the pipe bevel and the weld
metal.
Visually check-Proper cleaning between passes, proper amperage for the electrode diameter, and
proper voltage.
Porosity is defined as gas trapped by solidifying weld metal before the gas has a chance to rise to the
surface of the molten puddle and escape. (A"gas pocket' is a term of porosity that is intended to
describe a pore within the body of the weld while a "pinhole" describes porosity on or near the edge of the
cap pass).
Visually check-For proper cleaning of pipe bevels and root face. Electrodes that may have absorbed
excessive moisture or been frozen can produce porosity.
Undercutting is defined as a groove melted into the parent metal to the toe or root of the weld and left
unfilled by weld material.
Cause—High amperage and a long arc; incorrect electrode position.
Visually check-For conformance to the welding procedure and proper machine setting for arc force
(open circuit voltage).
JOINING OF PIPE REV. NO. 24
STEEL DATE 01/01/25
X-4 sr'a STANDARDS 14 OF 14
Utilities NATURAL GAS SPEC. 3.22

APPENDIX A -WELD PROCEDURE INDEX
BUTT WELDS - PRODUCTION (NON-PRESSURIZED)
PROCEDURE WELDING FILLER PIPE/FITTING O.D. PIPE/FITTING WALL MATERIAL
NUMBER PROCESS MATERIAL DIAMETER RANGE THICKNESS RANGE GRADE
B1 SMAW E6010 < 2.375" < 0.188" Gr. B
B3 SMAW E6010 2.375" <_ 12.750" < 0.188" Gr. B <_X42
B4 SMAW E6010 2.375" <_ 12.750" 0.188" <_ 0.750" Gr. B <_X42
B5 SMAW E6010 >12.750" 0.188" <_ 0.750" Gr. B <_X42
B6 SMAW E6010 2.375" <_ 12.750" < 0.188" X46 <_ X52
B7 SMAW E6010 2.375" <_ 12.750" 0.188" <_ 0.750" X46 <_ X52
B8 SMAW E6010 >12.750" 0.188" <_ 0.750" X46 <_ X52
B9 SMAW E7018 2.375" <_ 12.750" 0.188" <_ 0.750" X65
B17 SMAW E8010 2.375" <_ 12.750" 0.188" <_ 0.750" X46 <_ X52
B19 SMAW E8010 2.375" <_ 12.750" 0.188" <_ 0.750" X65
B21 GMAW ER-70-S-6 < 2.375" < 0.188" Gr. B
B23 GMAW ER-70-S-6 2.375" <_ 12.750" < 0.188" Gr. B <_X42
B24 GMAW ER-70-S-6 2.375" <_ 12.750" 0.188" <_ 0.750" Gr. B <_X42
B26 GMAW ER-70-S-6 2.375" <_ 12.750" < 0.188" X46 <_ X52
B27 GMAW ER-70-S-6 2.375" <_ 12.750" 0.188" <_ 0.750" X46 <_ X52
B29 GMAW ER-70-S-6 2.375" <_ 12.750" 0.188" <_ 0.750" X65
FILLET WELDS - PRODUCTION (NON-PRESSURIZED) -or-IN SERVICE PRESSURIZED <_ 60 PSIG
PROCEDURE WELDING FILLER PIPE/FITTING O.D. PIPE/FITTING WALL MATERIAL
NUMBER PROCESS MATERIAL DIAMETER RANGE' THICKNESS RANGE' GRADE
F2 SMAW E6010 < 2.375" 0.188" <_0.750" Gr. B
F3 SMAW E6010 2.375" <_ 12.750" 0.188" <_0.750" Gr. B <_X42
F4 SMAW E6010 < 2.375" < 0.188" Gr. B<_X42
F5 SMAW E6010 < 2.375" 0.188" <_0.750" Gr. B<_X42
F6 SMAW E6010 < 2.375" < 0.188" X46<_X52
F7 SMAW E6010 < 2.375" 0.188" <_0.750" X46<_X52
F9 SMAW E6010 2.375"<_ 12.750" 0.188" <_0.750" X46 <_X52
F12 SMAW E8010 < 2.375" < 0.188" Gr. B <_X42
F13 SMAW E8010 < 2.375" 0.188" <_0.750" Gr. B <_X42
F14 SMAW E8010 < 2.375" < 0.188" X46 <_X52
F15 SMAW E8010 < 2.375" 0.188" <_0.750" X46 <_X52
F17 SMAW E8010 < 2.375" 0.188" <_0.750" X65
F19 SMAW E8010 2.375"<_ 12.750" 0.188" <_0.750" Gr. B <_X42
F21 SMAW E8010 2.375"<_ 12.750" 0.188" <_0.750" X46 <_X52
F23 SMAW E8010 2.375"<_ 12.750" 0.188" <_0.750" X65
FILLET WELDS -PRODUCTION NON-PRESSURIZED -or- IN SERVICE ALL PRESSURES, ALL %SMYS
PROCEDURE WELDING FILLER PIPE/FITTING O.D. PIPE/FITTING WALL MATERIAL
NUMBER PROCESS MATERIAL DIAMETER RANGE' THICKNESS RANGE' GRADE
F41 GMAW ER-70-S-6 < 2.375" < 0.188" Gr. B <_X42
F42 GMAW ER-70-S-6 < 2.375" 0.188" <_0.750" Gr. B <_X42
F43 GMAW ER-70-S-6 2.375" <_ 12.750" 0.188" <_0.750" Gr. B <_X42
F45 GMAW ER-70-S-6 < 2.375" < 0.188" X46<_X52
F46 GMAW ER-70-S-6 < 2.375" 0.188" <_ 0.750" X46<_X52
F47 GMAW ER-70-S-6 2.375" <_ 12.750" 0.188" <_0.750" X46<_X52
F49 GMAW ER-70-S-6 < 2.375" 0.188" <_0.750" X65
F61 SMAW E7018 < 2.375" 0.188" <_0.750" Gr. B <_X42
F62 SMAW E7018 2.375" <_ 12.750" 0.188" <_0.750" Gr. B <_X42
F64 SMAW E7018 < 2.375" 0.188" <_0.750" X46<_X52
F65 SMAW E7018 2.375" <_ 12.750" 0.188" <_0.750" X46<_X52
Table continued on following page

APPENDIX A -WELD PROCEDURE INDEX CONTINUED
REPAIR SLEEVE - PRODUCTION NON-PRESSURIZED -or-IN SERVICE PRESSURIZED <_60 PSIG
PROCEDURE WELDING FILLER PIPE/FITTING O.D. PIPE/FITTING WALL MATERIAL
NUMBER PROCESS MATERIAL DIAMETER RANGE' THICKNESS RANGE' GRADE
F24 SMAW E6010 2.375" <_ 12.750" 0.188" <_ 0.750" Gr. B <_X42
F25 SMAW E6010 >12.750" 0.188" <_ 0.750" Gr. B <_X42
F28 SMAW E6010 2.375" <_ 12.750" 0.188" <_ 0.750" X46 <_X52
F29 SMAW E6010 >12.750" 0.188" <_ 0.750" X46 <_X52
REPAIR SLEEVE - PRODUCTION NON-PRESSURIZED -or- IN SERVICE ALL PRESSURES, ALL %SMYS
PROCEDURE WELDING FILLER PIPE/FITTING O.D. PIPE/FITTING WALL MATERIAL
NUMBER PROCESS MATERIAL DIAMETER RANGE' THICKNESS RANGE' GRADE
F31 SMAW E7018 2.375" <_ 12.750" 0.188" <_ 0.750" Gr. B <_X42
F32 SMAW E7018 2.375" <_ 12.750" 0.188" <_ 0.750" X46 <_ X52
F33 SMAW E7018 >12.750" 0.188" <_ 0.750" Gr. B <_X42
F34 SMAW E7018 >12.750" 0.188" <_ 0.750" X46 <_ X52
F44 GMAW ER-70-S-6 2.375" <_ 12.750" 0.188" <_ 0.750" Gr. B <_X42
F48 GMAW ER-70-S-6 2.375" <_ 12.750" 0.188" <_ 0.750" X46 <_ X52
F51 GMAW ER-70-S-6 2.375" <_ 12.750" 0.188" <_ 0.750" X65
F53 GMAW ER-70-S-6 >12.750" 0.188" <_ 0.750" Gr. B <_X42
F54 GMAW ER-70-S-6 >12.750" 0.188" <_ 0.750" X46 <_X52
Full encirclement fitting, "barrel", and "can" installation requirements: The longitudinal seam weld shall be
done by following the appropriate butt weld procedure applicable to the material specifications for the fitting, barrel
or can. The fillet weld shall be done by following the appropriate fillet weld procedure applicable to the material
specifications for the fitting, barrel or can and not the gas carrying pipe.
' For fillet welds, pipe/fitting O.D. and wall thickness ranges are referring to the branch pipe or fitting
specifications.
2 Select welding procedure based on the higher of the two material grades. If welding on intermediate pressure
pipe and the grade is unknown, select the welding procedure for material grade X46 <_X52. If welding on high
pressure pipe and the grade is unknown, contact Gas Engineering for assistance determining the correct welding
procedure.

Utilities
PROCEDURE NUMBER: B1
Weld Category: Production,Non Pressurized
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: Gr.B
PIPE DIAMETER/W.T. RANGE QUALIFIED: <2.375"O.D./<0.188"W.T.
FILLER MATERIAL: AWS E6010 Root, Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or O -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40°F: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40°F and below: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
+5°
1/16"± 1/32" 30° 0°
1 2
2
1
f1/16"± 1/32"
JOINT DESIGN WEAVE OR STRINGER
WEAVE OR STRINGER
WELD PASS SEQUENCE
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 3/32" E6010 50-100 18-32 4-14 N/A
2 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
Rem.* SMAW 1/8" E6010 60-130 18-38 4-15 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE(IPM)
3/32" E6010,All Passes 50-100 18-32 4-14
1/8"(E6010,All Passes) 60-130 18-38 4-15
.Remaining number of passes needed to achieve joint and weld design requirements as shown above.
/+ PROCEDURE CERTIFICATION
Approved: LC Date:9-6-19
This proced a conducted in accordance with and meets the requirements of API 1104, Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: B3
Weld Category: Production,Non Pressurized
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: Gr.B<_X42
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375"<_ 12.750"O.D./<0.188"W.T.
FILLER MATERIAL: I AWS E6010 Root, Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Oxy-acetylene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: Lineup clamp should be used for welds in the field. If clamp is used it shall be kept in place until root bead
is at least 50%complete.
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40°F: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40°F and below: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
+5°
1/16"± 1/32", 30° -0°
1 2
2
1
�-1/16"± 1/32"
JOINT DESIGN WEAVE OR STRINGER
WEAVE OR STRINGER
WELD PASS SEQUENCE
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 3/32" E6010 50-100 18-32 4-14 N/A
2 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
Rem." SMAW 1/8" E6010 60-130 18-38 4-15 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE(IPM)
3/32"(E6010,All Passes) 50-100 18-32 4-14
1/8" E6010,All Passes 60-130 18-38 4-15
"Remaining number of passes needed to achieve joint and weld design requirements as shown above.
/,+ PROCEDURE CERTIFICATION
GC
Approved: Date:9-12-19
This proced a conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: B4
Weld Category: Production,Non Pressurized
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: Gr.B<_X42
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375"<_ 12.750"O.D./0.188"<_0.750" W.T.
FILLER MATERIAL: AWS E6010 Root, Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Ox -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: Lineup clamp should be used for welds in the field. If clamp is used it shall be kept in place until root bead
is at least 50%complete.
TIME BETWEEN PASSES: 5 Minutes Max.Between RoWHot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40°F: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40°F and below: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
+5°
1/16"± 1/32" 30° -0°
3 1 2
2 3
1
H-1/16"± 1/32" WEAVE
JOINT DESIGN
STRINGER
WELD PASS SEQUENCE
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
2 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
3 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
Rem." SMAW 1/8" E6010 60-130 18-38 4-15 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
3/32"(E6010,Pass 1) 50-100 18-32 4-14
5/32" E6010,Pass 2—Remaining) 100-180 18-40 4-16
.Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: uZ41 I Date:9-12-19
This proced a fvV conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: B5
Weld Category: Production,Non Pressurized
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: Gr.B<_X42
PIPE DIAMETER/W.T. RANGE QUALIFIED: > 12.750"O.D./0.188"<0.750" W.T.
FILLER MATERIAL: AWS E6010 Root, Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: Two Preferred,One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Ox -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: Lineup clamp should be used for welds in the field. If clamp is used it shall be kept in place until root bead
is at least 50%complete.
TIME BETWEEN PASSES: 5 Minutes Max.Between RoWHot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40°F: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40°F and below: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
+5°
1/16"± 1/32" 30° -0°
3 1 2
2 3
1
H-1/16"± 1/32" WEAVE
JOINT DESIGN
STRINGER
WELD PASS SEQUENCE
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
2 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
3 SMAW 5/32" E6010 100-180 18-40 4-16 N/A
Rem." SMAW 3/16" E6010 140-225 28-36 5-18 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
1/8"(E6010,All Passes) 60-130 18-38 4-15
5/32" E6010,Pass 2—Remaining) 100-180 18-40 4-16
3/16"(E6010,Pass 3—Remaining) 140-225 28-36 5-18
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: u z� I Date:9-12-19
This proced a fvVconducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: B6
Weld Category: Production,Non Pressurized
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X46<_X52
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375"<_ 12.750"O.D./<0.188"W.T.
FILLER MATERIAL: AWS E6010 Root, Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Oxy-acetylene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: Lineup clamp should be used for welds in the field. If clamp is used it shall be kept in place until root bead
is at least 50%complete.
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40°F: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40oF and below: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
+50
1/16"± 1/32" 30' -0°
1 2
2
1
�I �f1/16"± 1/32"
JOINT DESIGN WEAVE OR STRINGER
WEAVE OR STRINGER
WELD PASS SEQUENCE
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 3/32" E6010 50-100 18-32 4-14 N/A
2 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
Rem.* SMAW 1/8" E6010 60-130 18-38 4-15 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE(IPM
3/32" E6010,All Passes 50-100 18-32 4-14
1/8" E6010,All Passes 60-130 18-38 4-15
Remaining number of passes needed to achieve joint and weld design requirements as shown above.
/+ PROCEDURE CERTIFICATION
Approved: LC i � Date:9 12-19
This proced re s conducted in accordance with and meets the requirements of API 1104, Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: B7
Weld Category: Production,Non Pressurized
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X46<_X52
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375"<_ 12.750"O.D./0.188"<_0.750" W.T.
FILLER MATERIAL: AWS E6010 Root, Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Oxy-acetylene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: Lineup clamp should be used for welds in the field. If clamp is used it shall be kept in place until root bead
is at least 50%complete.
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40°F: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40°F and below: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
+5°
1/16"t 1/32" 30° -0°
3 1 2
2 3
1
H-1/16"'t 1/32" WEAVE
JOINT DESIGN
STRINGER
WELD PASS SEQUENCE
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
2 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
3 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
Rem.* SMAW 1/8" E6010 60-130 18-38 4-15 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE(IPM)
3/32" E6010,Pass 1 50-100 18-32 4-14
5/32" E6010,Pass 2—Remaining) 100-180 18-40 4-16
.Remaining number of passes needed to achieve joint and weld design requirements as shown above.
/,+ PROCEDURE CERTIFICATION
Approved: LL I Date:9-12-19
This procedLye conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: B8
Weld Category: Production,Non Pressurized
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X46<_X52
PIPE DIAMETER/W.T. RANGE QUALIFIED: > 12.750"O.D./0.188"<0.750" W.T.
FILLER MATERIAL: AWS E6010 Root, Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: Two Preferred,One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Ox -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: Lineup clamp should be used for welds in the field. If clamp is used it shall be kept in place until root bead
is at least 50%complete.
TIME BETWEEN PASSES: 5 Minutes Max.Between RoWHot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40°F: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40°F and below: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
+5°
1/16"± 1/32" 30° -0°
3 1 2
2 3
1
H-1/16"± 1/32" WEAVE
JOINT DESIGN
STRINGER
WELD PASS SEQUENCE
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
2 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
3 SMAW 5/32" E6010 100-180 18-40 4-16 N/A
Rem." SMAW 3/16" E6010 140-225 28-36 5-18 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
1/8"(E6010,All Passes) 60-130 18-38 4-15
5/32" E6010,Pass 2—Remaining) 100-180 18-40 4-16
3/16"(E6010,Pass 3—Remaining) 140-225 28-36 5-18
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: u z� I Date:9-12-19
This proced a fvVconducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: B9
Weld Category: Production,Non Pressurized
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIEPLI X65
PIPE DIAMETER/W.T. RANGE QUALIFIED: I 2.375"<_ 12.750"O.D./0.188"<_0.750"W.T.
FILLER MATERIAL: I AWS E6010 Root, E7018 Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: E6010 Downhill
E7018 Uphill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or O -acetylene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: Lineup clamp should be used for welds in the field. If clamp is used it shall be kept in place until root bead
is at least 50%complete.
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40°F: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40°F and below: 200° F minimum-400° F maximum preheat pipe and fitting)
JOINT AND WELD DESIGN
+5°
1/16"± 1/32" 30° 0° 4
3 1 2
2 3
1
H-1/16' 1/32" WEAVE
JOINT DESIGN
STRINGER
WELD PASS SEQUENCE
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
2 SMAW 3/32" E7018 70-110 20-35 2-10 N/A
3 SMAW 3/32" E7018 70-110 20-35 2-10 N/A
Rem.* SMAW 3/32" E7018 70-110 20-35 2-10 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
3/32" E6010,Pass 1 50-100 18-32 4-14
1/8"(E7018,Pass 2—Remaining) 90-160 20-40 4-12
5/32" E7018,Pass 2—Remaining) 110-200 20-40 4-14
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: LC �,� Date:9-12-19
This proced a ftif conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: B17
Weld Category: Production,Non Pressurized
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X46<X52
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375":— 12.750"O.D./0.188":—0.750" W.T.
FILLER MATERIAL: AWS E6010 Root, E8010 Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Ox -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: Lineup clamp should be used for welds in the field. If clamp is used it shall be kept in place until root bead
is at least 50%complete.
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40oF: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40oF and below: 200°F minimum-400° F maximum
JOINT AND WELD DESIGN
+50
1/16"± 1/32" 30' 0°
3 1 2
2 3
1
H-1/16"'± 1/32" WEAVE
JOINT DESIGN
STRINGER
WELD PASS SEQUENCE
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
2 SMAW 1/8" E8010 60-130 18-38 4-15 N/A
3 SMAW 1/8" E8010 60-130 18-38 4-15 N/A
Rem.* SMAW 1/8" E8010 60-130 18-38 4-15 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
3/32" E6010,Pass 1 50-100 18-32 4-14
5/32" E8010,Pass 2—Remaining) 100-180 18-40 4-16
3/16" E8010,Pass 2—Remaining) 110-225 18-40 5-18
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
�j PROCEDURE CERTIFICATION
Approved: I Date:5-29-20
This proced a fvag conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: B19
Weld Category: Production,Non Pressurized
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X65
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375"<_ 12.750"O.D./0.188"<_0.750" W.T.
FILLER MATERIAL: AWS E6010 Root, E8010 Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Ox -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: Lineup clamp should be used for welds in the field. If clamp is used it shall be kept in place until root bead
is at least 50%complete.
TIME BETWEEN PASSES:_1 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40°F: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40°F and below: 200°F minimum-400° F maximum
JOINT AND WELD DESIGN
+5°
1/16"± 1/32" 30° -0°
3 1 2
2 3
1
H-1/16"± 1/32" WEAVE
JOINT DESIGN
STRINGER
WELD PASS SEQUENCE
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
2 SMAW 1/8" E8010 60-130 18-38 4-15 N/A
3 SMAW 1/8" E8010 60-130 18-38 4-15 N/A
Rem.* SMAW 1/8" E8010 60-130 18-38 4-15 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
3/32" E6010,Pass 1 50-100 18-32 4-14
5/32" E8010,Pass 2—Remaining) 100-180 18-40 4-16
3/16" E8010,Pass 2—Remaining) 110-225 18-40 5-18
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
l/ PROCEDURE CERTIFICATION
Approved: ��./ Date:8-25-20
This proced a fvagconducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: B21
Weld Category: Production,Non Pressurized
WELDING PROCESS: I Manual Gas Metal Arc— GMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: Gr.B
PIPE DIAMETER/W.T. RANGE QUALIFIED: <2.375"O.D./<0.188"W.T.
FILLER MATERIAL: AWS 5.18 ER-70-S-6 Root, Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or O -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40OF: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40°F and below: 200° F minimum-4000 F maximum
JOINT AND WELD DESIGN
+50
1/16"± 1/32" 30' -0°
1 2
2
1
�I �f1/16"± 1/32"
JOINT DESIGN WEAVE OR STRINGER
WEAVE OR STRINGER
WELD PASS SEQUENCE
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) GAS MIXTURE, FLOW RATE
1 GMAW 0.03" ER-70-S-6 85-130 16-25 4-17 75%Ar,25%CO2,20-40 CFH
2 GMAW 0.03" ER-70-S-6 85-130 16-25 4-17 75%Ar,25%CO2,20-40 CFH
Rem.' GMAW 0.03" ER-70-S-6 85-130 16-25 4-17 75%Ar,25%CO2,20-40 CFH
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: Date:9-12-19
This procedLtrp I onducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: B23
Weld Category: Production,Non Pressurized
WELDING PROCESS: I Manual Gas Metal Arc— GMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: Grd. B<X42
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375"<_ 12.750"O.D./<0.188"W.T.
FILLER MATERIAL: AWS 5.18 ER-70-S-6 Root, Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or 0 -acetylene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: Lineup clamp should be used for welds in the field. If clamp is used it shall be kept in place until root bead
is at least 50%complete.
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40oF: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40OF and below: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
+5a
1/16"± 1/32" 30' -0°
1 2
2
1
f1/16"± 1/32"
JOINT DESIGN WEAVE OR STRINGER
WEAVE OR STRINGER
WELD PASS SEQUENCE
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) GAS MIXTURE, FLOW RATE
1 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
2 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
Rem* GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE(IPM)
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
//' PROCEDURE CERTIFICATION
Approved: u Date:9-12-19
This proced re s conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: B24
Weld Category: Production,Non Pressurized
WELDING PROCESS: I Manual Gas Metal Arc— GMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: Gr.B<_X42
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375"<_ 12.750" O.D./0.188"<_0.750"W.T.
FILLER MATERIAL: I AWS 5.18, ER-70-S-2,6 Root,Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Oxy-acetylene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: Lineup clamp should be used for welds in the field. If clamp is used it shall be kept in place until root bead
is at least 50%complete.
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40°F: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40°F and below: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
+5°
1/16"t 1/32" 30° -0°
3 1 2
2 3
1
H-1/16"'t 1/32" WEAVE
JOINT DESIGN
STRINGER
WELD PASS SEQUENCE
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE SPEED(IPM) GAS MIXTURE, FLOW RATE
1 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
2 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
3 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
Rem.* GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE(IPM)
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: I Date:9-12-19
This proced a conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: B26
Weld Category: Production,Non Pressurized
WELDING PROCESS: I Manual Gas Metal Arc— GMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X46<_X52
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375"<_ 12.750"O.D./<0.188"W.T.
FILLER MATERIAL: AWS 5.18 ER-70-S-6 Root, Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or 0 -acetylene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: Lineup clamp should be used for welds in the field. If clamp is used it shall be kept in place until root bead
is at least 50%complete.
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40OF: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40OF and below: 2000 F minimum-4000 F maximum
JOINT AND WELD DESIGN
+50
1/16"± 1/32" 30' 0°
1 2
2
1
�I �f1/16"± 1/32"
JOINT DESIGN WEAVE OR STRINGER
WEAVE OR STRINGER
WELD PASS SEQUENCE
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) GAS MIXTURE, FLOW RATE
1 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
2 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
Rem." GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: Date:9-12-19
This proced a conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: B27
Weld Category: Production,Non Pressurized
WELDING PROCESS: I Manual Gas Metal Arc— GMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X46<_X52
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375"<_ 12.750"O.D./ 0.188"<_0.750"W.T.
FILLER MATERIAL: AWS 5.18, ER-70-S-2,6 Root,Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Oxy-acetylene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: Lineup clamp should be used for welds in the field. If clamp is used it shall be kept in place until root bead
is at least 50%complete.
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40°F: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40°F and below: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
+5°
1/16"t 1/32" 30° -0°
3 1 2
2 3
1
H-1/16"'t 1/32" WEAVE
JOINT DESIGN
STRINGER
WELD PASS SEQUENCE
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) GAS MIXTURE, FLOW RATE
1 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
2 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
3 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
Rem.* GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE(IPM)
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: I Date:9-12-19
This proced conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: B29
Weld Category: Production,Non Pressurized
WELDING PROCESS: I Manual Gas Metal Arc— GMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X65
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375"<_12.750"O.D./0.188"<_0.750" W.T.
FILLER MATERIAL: AWS 5.18, ER-70-S-2,6 Root,Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Ox -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: Lineup clamp should be used for welds in the field. If clamp is used it shall be kept in place until root bead
is at least 50%complete.
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40°F: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40°F and below: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
+5°
1/16"± 1/32" 30° -0°
3 1 2
2 3
1
H-1/16"± 1/32" WEAVE
JOINT DESIGN
STRINGER
WELD PASS SEQUENCE
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) GAS MIXTURE,FLOWRATE
1 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
2 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
3 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
Rem." GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
/+ PROCEDURE CERTIFICATION
U Approved: Date:9-12-19
This procedu conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F2
Weld Category: Production and In-Service, (Pressurized<_ 60 PSIG)
WELDING PROCESS: I Manual Shielded Metal Arc—(SMAW)
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: Gr. B
PIPE DIAMETER/W.T. RANGE QUALIFIED: <2.375"O.D./0.188"<_0.750"W.T.
FILLER MATERIAL: AWS E6010 Root, Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Oxy-acetylene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES: 5 Minutes Max. Between Root/Hot Pass and One Fill Pass; Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40°F: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40°F and below: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
B
0
45°+5° 4
- °
2 3 za
T
3B/8 BUT NOT 1.4T BUT NOT
1/16"t 1/32" LESS THAN 1/4" LESS THAN 5/32"
JOINT DESIGN(BRANCH) WELD PASS SEQUENCE(BRANCH) WELD PASS SEQUENCE(SOCKET)
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 3/32" E6010 50-100 18-32 4-14 N/A
2 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
3 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
Rem.' SMAW 1/8" E6010 60-130 18-38 4-15 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
3/32"(E6010,All passes) 50-100 18-32 4-14
1/8" E6010,All passes 60-130 18-38 4-15
5/32" E6010, Pass 2—Remaining) 100-180 18-40 4-16
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
/+ PROCEDURE CERTIFICATION
Approved: LC �zl Date: 10-7-16
This procedyfe#Npg conducted in accordance with and meets the requirements of API 1104, Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F3
Weld Category: Production and In-Service, (Pressurized<_ 60 PSIG)
WELDING PROCESS: I Manual Shielded Metal Arc—(SMAW)
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: Gr.B<_X42
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375"<_ 12.750"O.D./ 0.188"<_0.750"W.T.
FILLER MATERIAL: I AWS 5.1,E6010 Root, Hot,and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Oxy-acetylene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES: 1 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40OF: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40oF and below: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
B
A311
45°±00 _ 4
1 2 3
T
1/16"± 1/32" 3B/8 BUT NOT 1.4T BUT NOT
LESS THAN 1/4" LESS THAN 5/32"
JOINT DESIGN (BRANCH) WELD PASS SEQUENCE(BRANCH) WELD PASS SEQUENCE(SOCKET)
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
2 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
3 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
Rem.* SMAW 1/81, E6010 60-130 18-38 4-15 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE(IPM)
3/32" E6010,All passes 50-100 18-32 4-14
5/32" E6010,Pass 2—Remaining) 100-180 18-40 4-16
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
�j PROCEDURE CERTIFICATION
Approved: I Date: 10-7-16
This procedyfe conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F4
Weld Category: Production and In-Service, (Pressurized<_ 60 PSIG)
WELDING PROCESS: I Manual Shielded Metal Arc—(SMAW)
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: Gr. B<_X42
PIPE DIAMETER/W.T. RANGE QUALIFIED: <2.375"O.D./<0.188"W.T.
FILLER MATERIAL: AWS 5.1 -E6010 Root, Hot,and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Oxy-acetylene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES: 5 Minutes Max. Between Root/Hot Pass and One Fill Pass; Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40°F: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40°F and below: 200° F minimum-400° F maximum)
JOINT AND WELD DESIGN
B
4
45°±�° _ 4
1 2 3 3 2 11
T
t 1 1
3B/8 BUT NOT 1.4T BUT NOT
1/16"t 1/32" LESS THAN 1/4" LESS THAN 5/32"
JOINT DESIGN(BRANCH) WELD PASS SEQUENCE(BRANCH) WELD PASS SEQUENCE(SOCKET)
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 3/32" E6010 50-100 18-32 4-14 N/A
2 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
3 SMAW 1/81, E6010 60-130 18-38 4-15 N/A
Rem.' SMAW 1/8" E6010 60-130 18-38 4-15 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
3/32"(E6010,All passes) 50-100 18-32 4-14
1/8" E6010,All passes 60-130 18-38 4-15
.Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: GC Date: 10-7-16
This proced e conducted in accordance with and meets the requirements of API 1104, Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F5
Weld Category: Production and In-Service, (Pressurized <_ 60 PSIG)
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: Gr.B<_X42
PIPE DIAMETER/W.T. RANGE QUALIFIED: <2.375"O.D./0.188"<_0.750"W.T.
FILLER MATERIAL: AWS 5.1 -E6010 Root, Hot,and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or O -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40OF: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40OF and below: 2000 F minimum-4000 F maximum
JOINT AND WELD DESIGN
B
4
45°±po _ 4
1 2 3 3 2 11
T
1/16"± 1/32" 313/8 BUT NOT 1.4T BUT NOT
LESS THAN 1/4" LESS THAN 5/32"
JOINT DESIGN (BRANCH) WELD PASS SEQUENCE(BRANCH) WELD PASS SEQUENCE(SOCKET)
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
2 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
3 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
Rem.* SMAW 1/8" E6010 60-130 18-38 4-15 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE(IPM)
3/32" E6010,All passes 50-100 18-32 4-14
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: I Date: 10-7-16
This proced conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F6
Weld Category: Production and In-Service, (Pressurized<_ 60 PSIG)
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X46<_X52
PIPE DIAMETER/W.T. RANGE QUALIFIED: <2.375"O.D./<0.188"W.T.
FILLER MATERIAL: AWS 5.1 -E6010 Root, Hot,and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Ox -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES: 1 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40°F: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40°F and below: 200' F minimum-400° F maximum
JOINT AND WELD DESIGN
B
A31
45°±00 _ 4
1 _ 2 3 1
T
3B/8 BUT NOT LiAT BUT NOT
1/16"± 1/32" LESS THAN 1/4" LESS THAN 5/32"
JOINT DESIGN (BRANCH) WELD PASS SEQUENCE(BRANCH) WELD PASS SEQUENCE(SOCKET)
WELDING PARAMETERS AND ELCTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 3/32" E6010 50-100 18-32 4-14 N/A
2 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
3 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
Rem.* SMAW 1/8" E6010 60-130 18-38 4-15 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE(IPM)
3/32" E6010,All passes 50-100 18-32 4-14
1/8" E6010,All asses 60-130 18-38 4-15
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
/'// PROCEDURE CERTIFICATION
Approved: K G.� Date: 1-21-19
This proced a conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

'Aiim,,ikuiVISTA
Utilities
PROCEDURE NUMBER: F7
Weld Category: Production and In-Service, (Pressurized<_ 60 PSIG)
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X46<_X52
PIPE DIAMETER/W.T. RANGE QUALIFIED: <2.375"O.D./0.188"<—0.750"W.T.
FILLER MATERIAL: AWS 5.1 -E6010 Root, Hot,and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Ox -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40OF: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40°F and below: 200, F minimum-4000 F maximum
JOINT AND WELD DESIGN
B
A::
45° Do 1 23
1/16"± 1/32" 313/8 BUT NOT 1.4T BUT NOT
LESS THAN 1/4" LESS THAN 5/32"
JOINT DESIGN (BRANCH) WELD PASS SEQUENCE(BRANCH) WELD PASS SEQUENCE(SOCKET)
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 3/32" E6010 50-100 18-32 4-14 N/A
2 SMAW 3/32" E6010 50-100 18-32 4-14 N/A
3 SMAW 3/32" E6010 50-100 18-32 4-14 N/A
Rem.* SMAW 3/32" E6010 50-100 18-32 4-14 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE(IPM)
1/8" E6010,All passes 60-130 18-38 4-15
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
�j PROCEDURE CERTIFICATION
Approved: I Date: 10-7-16
This procedurgrwlrseonducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F9
Weld Category: Production and In-Service, (Pressurized<_ 60 PSIG)
WELDING PROCESS: I Manual Shielded Metal Arc—(SMAW)
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X46<_X52
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375"<_ 12.750"O.D./0.188"<_0.750"W.T.
FILLER MATERIAL: AWS 5.1,E6010 Root, Hot,and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Oxy-acetylene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES: 5 Minutes Max. Between Root/Hot Pass and One Fill Pass; Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40°F: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40°F and below: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
B
A31
45°±�° _ 4
1 2 3
T
313/8 BUT NOT 1.4T BUT NOT
1/16"t 1/32" LESS THAN 1/4" LESS THAN 5/32"
JOINT DESIGN(BRANCH) WELD PASS SEQUENCE(BRANCH) WELD PASS SEQUENCE(SOCKET)
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
2 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
3 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
Rem.' SMAW 1/8" E6010 60-130 18-38 4-15 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
3/32" E6010,All asses 50-100 18-32 4-14
5/32" E6010, Pass 2—Remaining) 100-180 18-40 4-16
'Remaining number of passes needed to achieve joint and weld design requirements as shown above.
/+ PROCEDURE CERTIFICATION
Approved: LC Date: 10-7-16
This procedu a conducted in accordance with and meets the requirements of API 1104, Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F12
Weld Category: Production and In-Service, (Pressurized<_ 60 PSIG)
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: Gr.B<_X42
PIPE DIAMETER/W.T. RANGE QUALIFIED: <2.375"O.D./<0.188"W.T.
FILLER MATERIAL: AWS E6010 Root, E8010 Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Ox -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES:_1 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40°F: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40oF and below: 2000 F minimum-400° F maximum
JOINT AND WELD DESIGN
B
45'1 5' _ 4
1 2 3 'A31
T
3B/8 BUT NOT 1.4T BUT NOT
1/16"t 1/32" LESS THAN 1/4" LESS THAN 5/32"
JOINT DESIGN (BRANCH) WELD PASS SEQUENCE(BRANCH) WELD PASS SEQUENCE(SOCKET)
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 3/32" E6010 50-100 18-32 4-14 N/A
2 SMAW 1/8" E8010 60-130 18-38 4-15 N/A
3 SMAW 1/8" E8010 60-130 18-38 4-15 N/A
Rem.* SMAW 1/8" E8010 60-130 18-38 4-15 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
1/8" E6010,Pass 1 60-130 18-38 4-15
3/32" E8010,Pass 2—Remaining) 50-100 18-32 4-14
5/32" E8010,Pass 2—Remaining) 100-180 18-40 4-16
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: Date: 11-1-21
This proced a conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F13
Weld Category: Production and In-Service, (Pressurized<_ 60 PSIG)
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: Gr.B<_X42
PIPE DIAMETER/W.T. RANGE QUALIFIED: <2.375"O.D./0.188"<—0.750"W.T.
FILLER MATERIAL: AWS E6010 Root, E8010 Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Ox -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES:_1 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40°F: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40oF and below: 2000 F minimum-400° F maximum
JOINT AND WELD DESIGN
B
45'1 5' _ 4
1 2 3 'A31
T
3B/8 BUT NOT 1.4T BUT NOT
1/16"t 1/32" LESS THAN 1/4" LESS THAN 5/32"
JOINT DESIGN (BRANCH) WELD PASS SEQUENCE(BRANCH) WELD PASS SEQUENCE(SOCKET)
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
2 SMAW 1/8" E8010 60-130 18-38 4-15 N/A
3 SMAW 1/8" E8010 60-130 18-38 4-15 N/A
Rem.* SMAW 1/8" E8010 60-130 18-38 4-15 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
3/32" E6010,Pass 1 50-100 18-32 4-14
3/32" E8010,Pass 2—Remaining) 50-100 18-32 4-14
5/32" E8010,Pass 2—Remaining) 100-180 18-40 4-16
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: Date: 11-1-21
This proced a conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F14
Weld Category: Production and In-Service, (Pressurized<_ 60 PSIG)
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X46<_X52
PIPE DIAMETER/W.T. RANGE QUALIFIED: <2.375"O.D./<0.188"W.T.
FILLER MATERIAL: AWS E6010 Root, E8010 Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Ox -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES:_1 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40°F: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40oF and below: 2000 F minimum-400° F maximum
JOINT AND WELD DESIGN
B
45'1 5' _ 4
1 2 3 'A31
T
3B/8 BUT NOT 1.4T BUT NOT
1/16"t 1/32" LESS THAN 1/4" LESS THAN 5/32"
JOINT DESIGN (BRANCH) WELD PASS SEQUENCE(BRANCH) WELD PASS SEQUENCE(SOCKET)
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 3/32" E6010 50-100 18-32 4-14 N/A
2 SMAW 1/8" E8010 60-130 18-38 4-15 N/A
3 SMAW 1/8" E8010 60-130 18-38 4-15 N/A
Rem.* SMAW 1/8" E8010 60-130 18-38 4-15 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
1/8" E6010,Pass 1 60-130 18-38 4-15
3/32" E8010,Pass 2—Remaining) 50-100 18-32 4-14
5/32" E8010,Pass 2—Remaining) 100-180 18-40 4-16
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: Date: 11-1-21
This proced a conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F15
Weld Category: Production and In-Service, (Pressurized<_ 60 PSIG)
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X46<_X52
PIPE DIAMETER/W.T. RANGE QUALIFIED: <2.375"O.D./0.188"<—0.750"W.T.
FILLER MATERIAL: AWS E6010 Root, E8010 Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Ox -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES:_1 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40°F: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40oF and below: 2000 F minimum-400° F maximum
JOINT AND WELD DESIGN
B
45'1 5' _ 4
1 2 3 'A31
T
3B/8 BUT NOT 1.4T BUT NOT
1/16"t 1/32" LESS THAN 1/4" LESS THAN 5/32"
JOINT DESIGN (BRANCH) WELD PASS SEQUENCE(BRANCH) WELD PASS SEQUENCE(SOCKET)
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
2 SMAW 1/8" E8010 60-130 18-38 4-15 N/A
3 SMAW 1/8" E8010 60-130 18-38 4-15 N/A
Rem.* SMAW 1/8" E8010 60-130 18-38 4-15 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
3/32" E6010,Pass 1 50-100 18-32 4-14
3/32" E8010,Pass 2—Remaining) 50-100 18-32 4-14
5/32" E8010,Pass 2—Remaining) 100-180 18-40 4-16
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: Date: 11-1-21
This proced a conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F17
Weld Category: Production and In-Service, (Pressurized<_ 60 PSIG)
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X65
PIPE DIAMETER/W.T. RANGE QUALIFIED: <2.375"O.D./0.188"<—0.750"W.T.
FILLER MATERIAL: AWS E6010 Root, E8010 Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Ox -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40OF: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40OF and below: 2000 F minimum-4000 F maximum
JOINT AND WELD DESIGN
B
4
45°±po 4 1
1 2 3 3 2 11 1
T
3B/8 BUT NOT LiAT BUT NOT
1/16"± 1/32" LESS THAN 1/4" LESS THAN 5/32"
JOINT DESIGN (BRANCH) WELD PASS SEQUENCE(BRANCH) WELD PASS SEQUENCE(SOCKET)
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
2 SMAW 1/8" E8010 60-130 18-38 4-15 N/A
3 SMAW 1/8" E8010 60-130 18-38 4-15 N/A
Rem.* SMAW 1/8" E8010 60-130 18-38 4-15 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
3/32" E6010,Pass 1 50-100 18-32 4-14
3/32" E8010,Pass 2—Remaining) 50-100 18-32 4-14
5/32" E8010,Pass 2—Remaining) 100-180 18-40 4-16
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: dZ Date: 11-1-21
This proced a conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F19
Weld Category: Production and In-Service, (Pressurized<_ 60 PSIG)
WELDING PROCESS: I Manual Shielded Metal Arc- SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: Gr.B<_X42
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375"<< 12.750"O.D./ 0.188"<_0.750"W.T.
FILLER MATERIAL: AWS E6010 Root, E8010 Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Ox -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES:-j 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40°F: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40OF and below: 2000 F minimum-4000 F maximum
JOINT AND WELD DESIGN
B
4
45°±0o _ 2 4
1 _ 3 3 2 1J. 1
T
3B/8 BUT NOT 1.4T BUT NOT
1/16"± 1/32" LESS THAN 1/4" LESS THAN 5/32"
JOINT DESIGN (BRANCH) WELD PASS SEQUENCE(BRANCH) WELD PASS SEQUENCE(SOCKET)
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
2 SMAW 1/8" E8010 60-130 18-38 4-15 N/A
3 SMAW 1/8" E8010 60-130 18-38 4-15 N/A
Rem.* SMAW 1/8" E8010 60-130 18-38 4-15 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
3/32" E6010,Pass 1 50-100 18-32 4-14
3/32" E8010,Pass 2-Remaining) 50-100 18-32 4-14
5/32" E8010,Pass 2-Remaining) 100-180 18-40 4-16
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
'/ PROCEDURE CERTIFICATION
Approved: �Z Date: 11-1-21
This proced a conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F21
Weld Category: Production and In-Service, (Pressurized<_ 60 PSIG)
WELDING PROCESS: I Manual Shielded Metal Arc- SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X46<_X52
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375"<< 12.750"O.D./ 0.188"<_0.750"W.T.
FILLER MATERIAL: AWS E6010 Root, E8010 Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Ox -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES:-j 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40°F: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40OF and below: 2000 F minimum-4000 F maximum
JOINT AND WELD DESIGN
B
4
45°±0o _ 2 4
1 _ 3 3 2 1J. 1
T
3B/8 BUT NOT 1.4T BUT NOT
1/16"± 1/32" LESS THAN 1/4" LESS THAN 5/32"
JOINT DESIGN (BRANCH) WELD PASS SEQUENCE(BRANCH) WELD PASS SEQUENCE(SOCKET)
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
2 SMAW 1/8" E8010 60-130 18-38 4-15 N/A
3 SMAW 1/8" E8010 60-130 18-38 4-15 N/A
Rem.* SMAW 1/8" E8010 60-130 18-38 4-15 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
3/32" E6010,Pass 1 50-100 18-32 4-14
3/32" E8010,Pass 2-Remaining) 50-100 18-32 4-14
5/32" E8010,Pass 2-Remaining) 100-180 18-40 4-16
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
'/ PROCEDURE CERTIFICATION
Approved: �Z Date: 11-1-21
This proced a conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F23
Weld Category: Production and In-Service, (Pressurized<_ 60 PSIG)
WELDING PROCESS: I Manual Shielded Metal Arc- SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X65
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375"<< 12.750"O.D./ 0.188"<_0.750"W.T.
FILLER MATERIAL: AWS E6010 Root, E8010 Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Ox -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES:-j 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40°F: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40OF and below: 2000 F minimum-4000 F maximum
JOINT AND WELD DESIGN
B
4
45°±0o _ 2 4
1 _ 3 3 2 1J. 1
T
3B/8 BUT NOT 1.4T BUT NOT
1/16"± 1/32" LESS THAN 1/4" LESS THAN 5/32"
JOINT DESIGN (BRANCH) WELD PASS SEQUENCE(BRANCH) WELD PASS SEQUENCE(SOCKET)
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
2 SMAW 1/8" E8010 60-130 18-38 4-15 N/A
3 SMAW 1/8" E8010 60-130 18-38 4-15 N/A
Rem.* SMAW 1/8" E8010 60-130 18-38 4-15 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
3/32" E6010,Pass 1 50-100 18-32 4-14
3/32" E8010,Pass 2-Remaining) 50-100 18-32 4-14
5/32" E8010,Pass 2-Remaining) 100-180 18-40 4-16
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
'/ PROCEDURE CERTIFICATION
Approved: �Z Date: 11-1-21
This proced a conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F24
Weld Category: Production and In-Service (Pressurized <_ 60 psig)
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: Gr.B<X42
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375"<_ 12.750"O.D./0.188"<_0.750"W.T.
FILLER MATERIAL: I AWS E6010 Root, Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill for fillet and groove
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or O -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: Jack and Chain or Similar
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40oF: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40oF and below: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
6
5 4
1
I T
1.4T BUT NOT
LESS THAN 5/32"
/s"(+%6",-0") 11 2 3 60'+0 0
f
NOTE:BACKING STRIP MUST HAVE
SIMILAR CHEMICAL COMPOSITION AS SLEEVE
MATERIAL.RECOMMENDED THICKNESS IS 0.070"-0.125"
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1,4 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
2,5 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
3,6 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
Rem* SMAW 1/8" E6010 60-130 18-38 4-15 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE(IPM)
3/32" E6010,Pass 1,4 50-100 18-32 4-14
5/32"(E6010,Pass 2,5—Remaining) 100-180 18-40 4-16
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: Q Date: 10-7-16
This proced a conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F25
Weld Category: Production and In-Service (Pressurized <_ 60 psig)
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: Gr.B<X42
PIPE DIAMETER/W.T. RANGE QUALIFIED: > 12.750"O.D./0.188"<_0.750"W.T.
FILLER MATERIAL: I AWS E6010 Root, Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill for fillet and groove
NUMBER OF WELDERS: Two Preferred,One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or O -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: Jack and Chain or Similar
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40oF: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40oF and below: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
6
5 4
1
I T
1.4T BUT NOT
LESS THAN 5/32"
/s"(+%6",-0") 11 2 3 60'+0 0
f
NOTE:BACKING STRIP MUST HAVE
SIMILAR CHEMICAL COMPOSITION AS SLEEVE
MATERIAL.RECOMMENDED THICKNESS IS 0.070"-0.125"
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1,4 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
2,5 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
3,6 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
Rem* SMAW 1/8" E6010 60-130 18-38 4-15 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE(IPM)
3/32" E6010,Pass 1,4 50-100 18-32 4-14
5/32"(E6010,Pass 2,5—Remaining) 100-180 18-40 4-16
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: Q Date:9-5-18
This proced a conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F28
Weld Category: Production and In-Service (Pressurized <_ 60 psig)
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X46<X52
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375"<_ 12.750"O.D./0.188"<_0.750"W.T.
FILLER MATERIAL: AWS E6010 Root, Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill for fillet and groove
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or O -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: Jack and Chain or Similar
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40oF: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40oF and below: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
6
5 4
1
I T
1.4T BUT NOT
LESS THAN 5/32"
/s"(+%6",-0") 11 2 3 60'+0 0
f
NOTE:BACKING STRIP MUST HAVE
SIMILAR CHEMICAL COMPOSITION AS SLEEVE
MATERIAL.RECOMMENDED THICKNESS IS 0.070"-0.125"
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1,4 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
2,5 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
3,6 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
Rem* SMAW 1/8" E6010 60-130 18-38 4-15 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE(IPM)
3/32" E6010,Pass 1,4 50-100 18-32 4-14
5/32"(E6010,Pass 2,5—Remaining) 100-180 18-40 4-16
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: Q Date: 10-7-16
This proced a 4RXconducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F29
Weld Category: Production and In-Service (Pressurized <_ 60 psig)
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: 1X46<X52
PIPE DIAMETER/W.T. RANGE QUALIFIED: I > 12.750"O.D./0.188"<_0.750"W.T.
FILLER MATERIAL: I AWS E6010 Root, Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill for fillet and groove
NUMBER OF WELDERS: Two Preferred,One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or O -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: Jack and Chain or Similar
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: If ambient temperature above 40oF: No preheat required unless to remove moisture from pipe/fitting
If ambient temperature 40oF and below: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
6
5 4
1
I T
1.4T BUT NOT
LESS THAN 5/32"
/s"(+%6",-0") 11 2 3 60'+0 0
f
NOTE:BACKING STRIP MUST HAVE
SIMILAR CHEMICAL COMPOSITION AS SLEEVE
MATERIAL.RECOMMENDED THICKNESS IS 0.070"-0.125"
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1,4 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
2,5 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
3,6 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
Rem* SMAW 1/8" E6010 60-130 18-38 4-15 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE(IPM)
3/32" E6010,Pass 1,4 50-100 18-32 4-14
5/32"(E6010,Pass 2,5—Remaining) 100-180 18-40 4-16
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: Q Date:9-5-18
This proced a 4RXconducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F31
Weld Category: All Pressures, All % SMYS
WELDING PROCESS: I Manual Shielded Metal Arc—(SMAW)
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: Gr.B<X42
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375"<_ 12.750"O.D./0.188"<_0.750"W.T.
FILLER MATERIAL: I AWS E6010 Root, E7018 Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: E6010 Downhill
E7018 Uphill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Ox -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP:_1 Jack and Chain or Similar
TIME BETWEEN PASSES: 1 5 Minutes Max. Between Root/Hot Pass and One Fill Pass; Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
6
5 4
1
T
'j
1 AT BUT NOT
LESS THAN 5/32" it
01.
-0°
NOTE:BACKING STRIP MUST HAVE
SIMILAR CHEMICAL COMPOSITION AS SLEEVE
MATERIAL.RECOMMENDED THICKNESS IS 0.070"-0.125"
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) GAS MIXTURE, FLOW RATE
1,4 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
2,5 SMAW 3/32" E7018 70-110 20-35 2-10 N/A
3,6 SMAW 3/32" E7018 70-110 20-35 2-10 N/A
Rem.* SMAW 3/32" E7018 70-110 20-35 2-10 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
3/32" E6010, Pass 1,4 50-100 18-32 4-14
1/8"(E7018, Pass 2,5-Remaining) 90-160 20-40 4-12
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
/+ PROCEDURE CERTIFICATION
Approved: LL Date: 3-23-17
This procedu conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F32
Weld Category: All Pressures, All % SMYS
WELDING PROCESS: I Manual Shielded Metal Arc—(SMAW)
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X46_<X52
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375"<_ 12.750"O.D./0.188"<_0.750"W.T.
FILLER MATERIAL: AWS E6010 Root, E7018 Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: E6010 Downhill
E7018 Uphill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Ox -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP:_1 Jack and Chain or Similar
TIME BETWEEN PASSES: 1 5 Minutes Max. Between Root/Hot Pass and One Fill Pass; Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
6
5 4
1
T
'j
1 AT BUT NOT
LESS THAN 5/32" it
01.
-0°
NOTE:BACKING STRIP MUST HAVE
SIMILAR CHEMICAL COMPOSITION AS SLEEVE
MATERIAL.RECOMMENDED THICKNESS IS 0.070"-0.125"
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) GAS MIXTURE, FLOW RATE
1,4 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
2,5 SMAW 3/32" E7018 70-110 20-35 2-10 N/A
3,6 SMAW 3/32" E7018 70-110 20-35 2-10 N/A
Rem.* SMAW 3/32" E7018 70-110 20-35 2-10 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
3/32" E6010, Pass 1,4 50-100 18-32 4-14
1/8"(E7018, Pass 2,5-Remaining) 90-160 20-40 4-12
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
/+ PROCEDURE CERTIFICATION
Approved: LL Date: 3-23-17
This procedu conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F33
Weld Category: All Pressures,All % SMYS
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: Gr.B<X42
PIPE DIAMETER/W.T. RANGE QUALIFIED: > 12.750"O.D./0.188"<—0.750"W.T.
FILLER MATERIAL: AWS E6010 Root, E7018 Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: E6010 Downhill
E7018 Uphill
NUMBER OF WELDERS: Two Preferred,One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or O -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: Jack and Chain or Similar
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: 2000 F minimum-4000 F maximum
JOINT AND WELD DESIGN
6
5 4
1
I T
1.4T BUT NOT /
LESS THAN 5/32"
+10°
0") 11 2 3 60° -0°
f
NOTE:BACKING STRIP MUST HAVE
SIMILAR CHEMICAL COMPOSITION AS SLEEVE
MATERIAL.RECOMMENDED THICKNESS IS 0.070"-0.125"
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) GAS MIXTURE, FLOW RATE
1,4 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
2,5 SMAW 3/32" E7018 70-110 20-35 2-10 N/A
3,6 SMAW 3/32" E7018 70-110 20-35 2-10 N/A
Rem.* SMAW 3/32" E7018 70-110 20-35 2-10 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
3/32" E6010,Pass 1,4 50-100 18-32 4-14
1/8" E7018,Pass 2,5-Remaining) 90-160 20-40 4-12
.Remaining number of passes needed to achieve joint and weld design requirements as shown above.
/+ PROCEDURE CERTIFICATION
Approved: GL Date:9-5-18
This proced conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F34
Weld Category: All Pressures,All % SMYS
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X46<_X52
PIPE DIAMETER/W.T. RANGE QUALIFIED: > 12.750"O.D./0.188"<—0.750"W.T.
FILLER MATERIAL: AWS E6010 Root, E7018 Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: E6010 Downhill
E7018 Uphill
NUMBER OF WELDERS: Two Preferred,One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or O -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP:_1 Jack and Chain or Similar
TIME BETWEEN PASSES: 1 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: 2000 F minimum-4000 F maximum
JOINT AND WELD DESIGN
6
5 4
1
I T
1.4T BUT NOT /
LESS THAN 5/32"
+10°
f
NOTE:BACKING STRIP MUST HAVE
SIMILAR CHEMICAL COMPOSITION AS SLEEVE
MATERIAL.RECOMMENDED THICKNESS IS 0.070"-0.125"
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) GAS MIXTURE, FLOW RATE
1,4 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
2,5 SMAW 3/32" E7018 70-110 20-35 2-10 N/A
3,6 SMAW 3/32" E7018 70-110 20-35 2-10 N/A
Rem.* SMAW 3/32" E7018 70-110 20-35 2-10 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
3/32" E6010,Pass 1,4 50-100 18-32 4-14
1/8" E7018,Pass 2,5-Remaining) 90-160 20-40 4-12
.Remaining number of passes needed to achieve joint and weld design requirements as shown above.
/+ PROCEDURE CERTIFICATION
Approved: GL Date:9-5-18
This proced conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F41
Weld Category: All Pressures,All % SMYS
WELDING PROCESS: I Manual Gas Metal Arc(GMAW)
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: Gr. B<_X42
PIPE DIAMETER/W.T. RANGE QUALIFIED: <2.375"O.D./<0.188"W.T.
FILLER MATERIAL: AWS 5.18—ER70-S-2,6'-Root, Hot,and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Oxy-acetylene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES: 5 Minutes Max. Between Root/Hot Pass and One Fill Pass; Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
B
4".."
45°±0° _ 4
1 2 3 3T
3B/8 BUT NOT 1.4 NOT
1/16"t 1/32" LESS THAN 1/4" LESS THAN 5/32"
JOINT DESIGN(BRANCH) WELD PASS SEQUENCE(BRANCH) WELD PASS SEQUENCE(SOCKET)
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) GAS MIXTURE, FLOW RATE
1 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
Rem." GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
'Remaining number of passes needed to achieve joint and weld design requirements as shown above.
�+ PROCEDURE CERTIFICATION
Approved: LL Date:4-9-18
This procedur)KvO55,tonducted in accordance with and meets the requirements of API 1104, Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F42
Weld Category: All Pressures, All % SMYS
WELDING PROCESS: I Manual Gas Metal Arc(GMAW)
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: Gr. B<_X42
PIPE DIAMETER/W.T. RANGE QUALIFIED: <2.375"O.D./0.188"<_0.750"W.T.
FILLER MATERIAL: AWS 5.18-ER-70-S-2,6 Root,Hot,and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Oxy-acetylene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES: 5 Minutes Max. Between Root/Hot Pass and One Fill Pass; Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
B
4".."
45°±0° _ 4
1 2 3 3T
3B/8 BUT NOT 1.4 NOT
1/16"t 1/32" LESS THAN 1/4" LESS THAN 5/32"
JOINT DESIGN(BRANCH) WELD PASS SEQUENCE(BRANCH) WELD PASS SEQUENCE(SOCKET)
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) GAS MIXTURE, FLOW RATE
1 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
2 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
Rem." GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
'Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: fn dz Date:4-9-18
This procedLife fva4 conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F43
Weld Category: All Pressures, All % SMYS
WELDING PROCESS: I Manual Gas Metal Arc(GMAW)
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: Gr.B<_X42
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375"<_ 12.750"O.D./0.188"<_0.750"W.T.
FILLER MATERIAL: AWS 5.18, ER-70-S-2,6 Root,Hot,and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Ox -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: 200° F minimum-400°F maximum
JOINT AND WELD DESIGN
B
— 4
45°±p 4
o
1 2 3 3 2 1i
T
3B/8 BUT NOT 1.4T BUT NOT
1/16"t 1/32" LESS THAN 1/4" LESS THAN 5/32"
JOINT DESIGN (BRANCH) WELD PASS SEQUENCE(BRANCH) WELD PASS SEQUENCE(SOCKET)
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) GAS MIXTURE, FLOW RATE
1 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
2 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
Rem.* GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE(IPM)
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: Date:4-9-18
This procedu a conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F44
Weld Category: All Pressures, All % SMYS
WELDING PROCESS: I Manual Gas Metal Arc—(GMAW)
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: Gr.B<X42
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375"<_ 12.750"O.D./0.188"<_0.750"W.T.
FILLER MATERIAL: I AWS 5.18 ER-70-S-6 Root, Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill for fillet and groove
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Ox -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: Jack and Chain or Similar
TIME BETWEEN PASSES: 5 Minutes Max. Between Root/Hot Pass and One Fill Pass; Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
6
5 4
1
T
1.4T BUT NOT
LESS THAN 5/32"
0') 1 2 3 60'+0 o
NOTE:BACKING STRIP MUST HAVE
SIMILAR CHEMICAL COMPOSITION AS SLEEVE
MATERIAL.RECOMMENDED THICKNESS IS 0.070"-0.125"
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) GAS MIXTURE, FLOW RATE
1,4 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
2,5 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
3,6 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
Rem" GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE(IPM)
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
/+ PROCEDURE CERTIFICATION
Approved: GC Date: 10-7-16
This procedu a conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F45
Weld Category: All Pressures, All % SMYS
WELDING PROCESS: I Manual Gas Metal Arc(GMAW)
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X46<_X52
PIPE DIAMETER/W.T. RANGE QUALIFIED: <2.375"O.D./<0.188"W.T.
FILLER MATERIAL: AWS 5.18-ER-70-S-2,6 Root,Hot,and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Oxy-acetylene TEMP. MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES: 5 Minutes Max. Between Root/Hot Pass and One Fill Pass; Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
B
4".."
45°±0° _ 4
1 2 3 3T
3B/8 BUT NOT 1.4 NOT
1/16"t 1/32" LESS THAN 1/4" LESS THAN 5/32"
JOINT DESIGN(BRANCH) WELD PASS SEQUENCE(BRANCH) WELD PASS SEQUENCE(SOCKET)
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) GAS MIXTURE, FLOW RATE
1 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
Rem." GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
'Remaining number of passes needed to achieve joint and weld design requirements as shown above.
�+ PROCEDURE CERTIFICATION
Approved: LC Date:4-9-18
This proced a feXconducted in accordance with and meets the requirements of API 1104, Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F46
Weld Category: All Pressures, All % SMYS
WELDING PROCESS: I Manual Gas Metal Arc(GMAW)
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X46<_X52
PIPE DIAMETER/W.T. RANGE QUALIFIED: <2.375"O.D./0.188"<_0.750"W.T.
FILLER MATERIAL: AWS 5.18-ER-70-S-2,6 Root,Hot,and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Oxy-acetylene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES: 5 Minutes Max. Between Root/Hot Pass and One Fill Pass; Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
B
4".."
45°±0° _ 4
1 2 3 3T
3B/8 BUT NOT 1.4 NOT
1/16"t 1/32" LESS THAN 1/4" LESS THAN 5/32"
JOINT DESIGN(BRANCH) WELD PASS SEQUENCE(BRANCH) WELD PASS SEQUENCE(SOCKET)
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) GAS MIXTURE, FLOW RATE
1 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
2 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
Rem." GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
'Remaining number of passes needed to achieve joint and weld design requirements as shown above.
/+ PROCEDURE CERTIFICATION
GC Approved: �ll Date:4-9-18
This procedu a conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F47
Weld Category: All Pressures, All % SMYS
WELDING PROCESS: I Manual Gas Metal Arc— GMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X46<_X52
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375"<_ 12.750"O.D./0.188"<_0.750"W.T.
FILLER MATERIAL: AWS 5.18, ER-70-S-2,6 Root,Hot,and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Ox -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP.: 200° F minimum-400°F maximum
JOINT AND WELD DESIGN
B
A31
45°+�0 _ 4
1 2 3
T
313/8 BUT NOT 1.4T BUT NOT
1/16"t 1/32" LESS THAN 1/4" LESS THAN 5/32"
JOINT DESIGN (BRANCH) WELD PASS SEQUENCE(BRANCH) WELD PASS SEQUENCE(SOCKET)
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) GAS MIXTURE, FLOW RATE
1 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
2 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
Rem." GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE(IPM)
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: I Date:4-9-18
This proced a fiaKconducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F48
Weld Category: All Pressures,All % SMYS
WELDING PROCESS: I Manual Gas Metal Arc— GMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X46<_X52
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375"<_ 12.750"O.D./0.188"<_0.750"W.T.
FILLER MATERIAL: AWS 5.18 ER-70-S-6 Root, Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill for fillet and groove
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or O -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: Jack and Chain or Similar
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: 200° F minimum-4000 F maximum
JOINT AND WELD DESIGN
6
5 4
1
T
1.4T BUT NOT
LESS THAN 5/32"
Ys"(+Ys", 0") 1 2 3 60"+0.
NOTE:BACKING STRIP MUST HAVE
SIMILAR CHEMICAL COMPOSITION AS SLEEVE
MATERIAL.RECOMMENDED THICKNESS IS 0.070"-0.125"
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) GAS MIXTURE, FLOW RATE
1,4 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
2,5 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
3,6 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
Rem* GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: Date: 10-7-16
This proced conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F49
Weld Category: All Pressures, All % SMYS
WELDING PROCESS: I Manual Gas Metal Arc(GMAW)
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X65
PIPE DIAMETER/W.T. RANGE QUALIFIED: <2.375"O.D./0.188"<_0.750"W.T.
FILLER MATERIAL: AWS 5.18-ER-70-S-2,6 Root,Hot,and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Oxy-acetylene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES: 5 Minutes Max. Between Root/Hot Pass and One Fill Pass; Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
B
4".."
45°±0° _ 4
1 2 3 3T
3B/8 BUT NOT 1.4 NOT
1/16"t 1/32" LESS THAN 1/4" LESS THAN 5/32"
JOINT DESIGN(BRANCH) WELD PASS SEQUENCE(BRANCH) WELD PASS SEQUENCE(SOCKET)
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) GAS MIXTURE, FLOW RATE
1 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
2 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
Rem." GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
'Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: Date:4-9-18
This proced a fvag conducted in accordance with and meets the requirements of API 1104, Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F51
Weld Category: All Pressures, All % SMYS
WELDING PROCESS: I Manual Gas Metal Arc— GMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X65
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375"<_ 12.750"O.D./0.188"<_0.750"W.T.
FILLER MATERIAL: AWS 5.18 ER-70-S-6 Root, Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill for fillet and groove
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Ox -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: Jack and Chain or Similar
TIME BETWEEN PASSES: 1 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: 200° F.Minimum-400' F Maximum
JOINT AND WELD DESIGN
6
5 4
1
I T
1.4T BUT NOT
LESS THAN 5/32"
/s"(+%6", 0'.) 1 2 3 60'+10'
-0°
1
NOTE:BACKING STRIP MUST HAVE
SIMILAR CHEMICAL COMPOSITION AS SLEEVE
MATERIAL.RECOMMENDED THICKNESS IS 0.070"-0.125"
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) GAS MIXTURE, FLOW RATE
1,4 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
2,5 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
3,6 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
Rem* GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE(IPM)
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: 4U., dzy FDte: 10-7-16
This proced conducted in accordance with and meets the requirements of API 1104, Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F53
Weld Category: All Pressures,All % SMYS
WELDING PROCESS: I Manual Gas Metal Arc— GMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: Gr.B<X42
PIPE DIAMETER/W.T. RANGE QUALIFIED: > 12.750"O.D./0.188":—0.750"W.T.
FILLER MATERIAL: AWS 5.18 ER-70-S-6 Root, Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill for fillet and groove
NUMBER OF WELDERS: Two Proffered,One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or O -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: Jack and Chain or Similar
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: 200° F minimum-4000 F maximum
JOINT AND WELD DESIGN
6
5 4
1
T
1.4T BUT NOT
LESS THAN 5/32"
Y6"(+Y6", 0") 1 2 3 60"+0.
NOTE:BACKING STRIP MUST HAVE
SIMILAR CHEMICAL COMPOSITION AS SLEEVE
MATERIAL.RECOMMENDED THICKNESS IS 0.070"-0.125"
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) GAS MIXTURE, FLOW RATE
1,4 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
2,5 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
3,6 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
Rem* GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
�+ PROCEDURE CERTIFICATION
Approved: Date:9-5-18
This proced conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F54
Weld Category: All Pressures,All % SMYS
WELDING PROCESS: I Manual Gas Metal Arc— GMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X46<_X52
PIPE DIAMETER/W.T. RANGE QUALIFIED: > 12.750"O.D./0.188":—0.750"W.T.
FILLER MATERIAL: AWS 5.18 ER-70-S-6 Root, Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: Downhill for fillet and groove
NUMBER OF WELDERS: Two Preferred,One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or O -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: Jack and Chain or Similar
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: 200° F minimum-4000 F maximum
JOINT AND WELD DESIGN
6
5 4
1
T
1.4T BUT NOT
LESS THAN 5/32"
Ys"(+Y6", 0") 1 2 3 60"+0.
NOTE:BACKING STRIP MUST HAVE
SIMILAR CHEMICAL COMPOSITION AS SLEEVE
MATERIAL.RECOMMENDED THICKNESS IS 0.070"-0.125"
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) GAS MIXTURE, FLOW RATE
1,4 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
2,5 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
3,6 GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
Rem* GMAW 0.03" ER-70-S-6 85-130 16-25 4-13 75%Ar,25%CO2,20-40 CFH
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
�+ PROCEDURE CERTIFICATION
Approved: Date:9-5-18
This proced conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F61
Weld Category: All Pressures, All % SMYS
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: Gr.B<_X42
PIPE DIAMETER/W.T. RANGE QUALIFIED: <2.375"O.D./0.188"<_0.750"W.T.
FILLER MATERIAL: AWS E6010 Root, E7018 Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: E6010 Downhill
E7018 Uphill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Ox -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: 200° F minimum-400°F maximum
JOINT AND WELD DESIGN
B
4
45`±Do _ 4
1 2 2 3 3 11
T
3B/8 BUT NOT 1.4T BUT NOT
1/16"t 1/32" LESS THAN 1/4" LESS THAN 5/32"
JOINT DESIGN (BRANCH) WELD PASS SEQUENCE(BRANCH) WELD PASS SEQUENCE(SOCKET)
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 3/32" E6010 50-100 18-32 4-14 N/A
2 SMAW 3/32" E7018 70-110 20-35 2-10 N/A
3 SMAW 3/32" E7018 70-110 20-35 2-10 N/A
Rem." SMAW 3/32" E7018 70-110 20-35 2-10 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
1/8"(E6010,Pass 1) 60-130 18-38 4-15
1/8"(E7018, Pass 2—Remaining) 90-160 20-40 4-12
"Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: dzil I Date: 10-7-16
This procedu conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F62
Weld Category: All Pressures, All % SMYS
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: Gr.B<_X42
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375"<_ 12.75"O.D./0.188"<_0.750"W.T.
FILLER MATERIAL: AWS E6010 Root, E7018 Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: E6010 Downhill
E7018 Uphill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Ox -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
B
4
45°±po _ 4
1 2 3 3 2 11
T
1/16"± 1/32" 313/8 BUT NOT 1.4T BUT NOT
LESS THAN 1/4" LESS THAN 5/32"
JOINT DESIGN (BRANCH) WELD PASS SEQUENCE(BRANCH) WELD PASS SEQUENCE(SOCKET)
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED Gas Mixture and
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) Percent
1 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
2 SMAW 3/32" E7018 70-110 20-35 2-10 N/A
3 SMAW 3/32" E7018 70-110 20-35 2-10 N/A
Rem.* SMAW 3/32" E7018 70-110 20-35 2-10 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
3/32" E6010,All passes 50-100 18-32 4-14
1/8"(E7018, Pass 2-Remaining) 90-160 20-40 4-12
.Remaining number of passes needed to achieve joint and weld design requirements as shown above.
PROCEDURE CERTIFICATION
Approved: Date: 10-7-16
This proced a conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F64
Weld Category: All Pressures, All % SMYS
WELDING PROCESS: I Manual Shielded Metal Arc—(SMAW)
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X46<_X52
PIPE DIAMETER/W.T. RANGE QUALIFIED: <2.375"O.D./0.188"<—0.750"W.T.
FILLER MATERIAL: AWS E6010 Root, E7018 Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: E6010 Downhill
E7018 Uphill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or O -acetylene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: I As Needed
TIME BETWEEN PASSES: 1 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: 1 2000 F minimum-4000 F maximum
JOINT AND WELD DESIGN
B
4
45°±po _ 4
1 2 3 3 2 11
T
3B/8 BUT NOT 1.4T BUT NOT
1/16"t 1/32" LESS THAN 1/4" LESS THAN 5/32"
JOINT DESIGN (BRANCH) WELD PASS SEQUENCE(BRANCH) WELD PASS SEQUENCE(SOCKET)
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 3/32" E6010 50-100 18-32 4-14 N/A
2 SMAW 3/32" E7018 70-110 20-35 2-10 N/A
3 SMAW 3/32" E7018 70-110 20-35 2-10 N/A
Rem.' SMAW 3/32" E7018 70-110 20-35 2-10 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE(IPM)
1/8" E6010,All asses 60-130 18-38 4-15
1/8" E7018,Pass 2—Remaining) 90-160 20-40 4-12
*Remaining number of passes needed to achieve joint and weld design requirements as shown above.
/+ PROCEDURE CERTIFICATION
Approved: L6 I Date: 10-7-16
This proced conducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

Utilities
PROCEDURE NUMBER: F65
Weld Category: All Pressures, All % SMYS
WELDING PROCESS: I Manual Shielded Metal Arc— SMAW
PIPE AND FILLER MATERIAL REQUIREMENTS
PIPE GRADES QUALIFIED: X46<_X52
PIPE DIAMETER/W.T. RANGE QUALIFIED: 2.375"<_ 12.750"O.D./0.188"<—0.750"W.T.
FILLER MATERIAL: AWS E6010 Root, E7018 Hot and Filler Passes
PRODUCTION WELDING CONDITIONS
PRODUCTION PIPE POSITION: Pipe in Horizontal or Vertical Fixed Position DIRECTION OF WELDING: E6010 Downhill
E7018 Uphill
NUMBER OF WELDERS: One Minimum WELDING TECHNIQUE: Stringer or Weave
PREHEAT METHOD: Propane or Ox -acet lene TEMP.MEASUREMENT: Pyrometer, Infrared Gun,or
METHOD OF WELD CLEANING: Power Brushing or Grinding Temperature Sticks
WELD CURRENT/POLARITY: Direct Current/Reverse Polarity POSTHEAT TREATMENT: None Required
TYPE/REMOVAL OF CLAMP: As Needed
TIME BETWEEN PASSES: 5 Minutes Max.Between Root/Hot Pass and One Fill Pass;Remaining Passes within 24 hrs.
PREHEAT/INTERPASS TEMP: 200° F minimum-400° F maximum
JOINT AND WELD DESIGN
B
4
45°±po _ 4
1 2 3 3 2 11
T
1/16"± 1/32" 313/8 BUT NOT 1.4T BUT NOT
LESS THAN 1/4" LESS THAN 5/32"
JOINT DESIGN (BRANCH) WELD PASS SEQUENCE(BRANCH) WELD PASS SEQUENCE(SOCKET)
WELDING PARAMETERS AND ELECTRICAL CHARACTERISTICS
PASS FILLER MATERIAL WELDING PARAMETERS TRAVEL SPEED GAS MIXTURE AND
NO. PROCESS SIZE CLASSIFICATION AMPERAGE VOLTAGE (IPM) PERCENT
1 SMAW 1/8" E6010 60-130 18-38 4-15 N/A
2 SMAW 3/32" E7018 70-110 20-35 2-10 N/A
3 SMAW 3/32" E7018 70-110 20-35 2-10 N/A
Rem.* SMAW 3/32" E7018 70-110 20-35 2-10 N/A
OPTIONAL APPROVED WELDING PARAMETERS FOR USE WITHIN ABOVE SPECIFIED CLASIFICATION
ELECTRODE DIAMETER AMPERAGE RANGE VOLTAGE RANGE TRAVEL SPEED RANGE IPM
3/32" E6010,Pass 1 50-100 18-32 4-14
1/8"(E7018,Pass 2-Remaining) 90-160 20-40 4-12
.Remaining number of passes needed to achieve joint and weld design requirements as shown above.
/,+ PROCEDURE CERTIFICATION
G[Approved: Date: 10-7-16
This proceduiC 4aXconducted in accordance with and meets the requirements of API 1104,Twentieth Edition and DOT Part 192.

3.23 JOINING OF PIPE - PLASTIC (POLYETHYLENE) - HEAT FUSION
SCOPE:
To establish a uniform heat fusion procedure to produce sound, homogeneous joints which adhere to the
applicable manufacturer and regulatory codes.
REGULATORY REQUIREMENTS:
§192.271, §192.273, §192.281, §192.283, §192.285, §192.287, §192.756
WAC 480-93-080
OTHER REFERENCES:
ASTM F2620
Performance Pipe Bulletin PP-750
Plastics Pipe Institute (PPI) Reference 33 (TR-33)
Plastics Pipe Institute (PPI)Technical Note 13 (TN-13)
CORRESPONDING STANDARDS:
Spec. 2.13, Pipe Design - Plastic
Spec. 3.13, Pipe Installation— Plastic
Spec. 3.34, Squeeze-Off of PE Pipe and Prevention of Static Electricity
JOINING METHODS:
General
Heat fusion is one technique used to join plastic (polyethylene) pipe, either by manual or hydraulic
methods. Butt fusions on 6" pipe shall only be done using hydraulic methods. Heat may not be applied
with a torch or other open flame.
Qualifying Joining Procedures
Before any written procedure is used for making heat fusion plastic pipe joints, the procedure must be
qualified by subjecting specimen joints that are made according to the procedure to the applicable testing
requirements in §192.283. Copies of qualified written joining procedures must be located on site where
plastic pipe joining is being performed.
Qualifications of Persons to Join Plastic Pipe
No persons shall perform heat fusion joining on polyethylene pipe until that person has received training
in the procedures and has made acceptable specimen joints similar to those that will be made in the field.
This person must also hold a current qualification. Persons must be re-qualified once each calendar year
not to exceed 15 months. If any field production joints fail during pressure testing, then the individual who
performed that particular joining process is no longer qualified and must re-qualify on that heat fusion
procedure unless it can be shown that the joint failed due to factors that are outside of the joiner's control
(i.e., equipment malfunction or material flaw).
The specimen joints must be visually examined during and after joining and found to have the same
appearance as a joint or photographs of a joint that is acceptable under the manufacturer's procedures
and tested in accordance with ASTM F2620. The joint must be cut into at least 3 longitudinal straps, each
of which is found not to contain voids or discontinuities on the cut surfaces of the joint area and be
deformed by a bending test. If failure occurs, it must not initiate in the joint area.
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WAC 480-93-080: Requires employees working in the state of Washington to requalify under an
applicable procedure, if during any twelve-month period the person has not made any joints under that
procedure.
Employees or contractors working in or with potential to work in the state of Washington shall
complete a plastic pipe joint for each type of joining process that an individual is qualified in following
annual Operator Qualification Training, between April 1 and December 31. The results of the
completed joints shall be tracked on form N-2596, "Plastic Pipe Field Joint Tracking, Washington".
Successful completion of this mid-year qualification will ensure compliance with the twelve-month
qualification interval in Washington State. Failure to complete and document a PE joint will render the
individual unqualified to perform that PE joining procedure starting on January 1 and until
requalification is performed in first quarter Refresher Training.
Gas Managers are responsible for ensuring compliance of their employees that work in Washington
State. Completed joint tracking forms shall be sent to the appropriate Compliance Technician for
retention. Completed joint tracking forms shall be retained for three years.
Marking Joints
For all types of plastic joints, the qualified individual who performed the joint shall use a permanent
marker to legibly sign the pipe with their first initial and full last name and shall also mark the date of the
joint. It is recommended to write down the time that the joint was fused so that the appropriate cooling
times can be easily determined.
Pipe Joining Certification Record
Each individual that successfully qualifies or requalifies on plastic pipe joining shall be issued a company
Plastic Pipe Joining Certification Record. This certification record indicates the name of individual, date of
certification, procedures under which the individual is qualified, and the expiration date of the certificate.
The individual must have the record and the joining procedures available for inspection when performing
plastic pipe joining in the field.
Maintenance and Calibration of Heat Fusion Equipment
Avista and its contractors must maintain equipment used in joining plastic pipe in accordance with the
manufacturer's recommended practices or with written procedures that have been proven by test and
experience to produce acceptable joints as noted in §192.756. For Avista and its contractors,
documentation of this requirement shall be completed through the signing of the Pressure Test
Information Sticker(Form N-2490 or similar) on the applicable as-built construction document.
By signing the aforementioned document, an operator qualified individual is attesting that construction
complied with current company standards/specifications and specifically in this case, that the heat fusion
equipment is being maintained as appropriate. See the Manufacturer's Operating Instructions Manual for
Gas Operations, Sections 2 and 3 (as applicable)for fusion equipment maintenance specifics.
BUTT FUSION PROCEDURES:
General
The following butt heat fusing procedure shall be strictly followed for each joint in order to produce sound
homogeneous joints for the following like materials— DRISCOPIPE, DRISCOPLEX, ENDOT, PLEXCO
2406, POLYPIPE, and UPONOR 2406. Avista has adopted Performance Pipe's procedure for butt
fusions from Bulletin PP-750, which is in alignment with ASTM F2620.
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Avista's approved butt fusion procedure also aligns with the Generic Butt Fusion Joining Procedure for
Field Joining of Polyethylene Pipe that was tested per CFR 192.283 and published as part of Technical
Reference 33 (TR-33) in 2012 as a follow-up to Technical Note 13 (TN-13) published in 2007 both by the
Plastics Pipe Institute (PPI).
A butt fusion shall not be made closer than 3 pipe diameters or 12 inches, whichever is greater, from a
previous squeeze point. Failure to meet these separations may result in damage to the joint. Refer to
Spec 3.34 related to requirements for squeezing plastic pipe. Regardless of the cutter being used, when
cutting a PE pipe to length before fusing take precaution to eliminate or minimize the introduction of
contamination to the pipe surfaces or the fusion equipment. Refer to butt fusion procedure (Step 1.a
below)for a list of common contaminants.
Heating Tool
Heating tool surfaces must be up to temperature before you begin. All points on both heating tool
surfaces where they will contact the pipe or fitting ends must be within the parameters listed in the heater
surface temperature table below. The maximum temperature difference between any two points on the
heating surfaces must not exceed 20 degrees F. It is recommended to periodically check the accuracy of
the infrared or contact pyrometer by using ice water. You should observe a reading close to 32 degrees F
Butt Fusion
Heater Surface Temperature
DRISCOPIPE, DRISCOPLEX, ENDOT, PLEXCO, POLYPIPE,AND UPONOR 2406
Heater Surface Temperature Interface Pressure
400°F min -450°F max* 75 +/- 15 psi
*Note:It is recommended that the iron temperature on the outer surface where the
actual PE pipe touches the iron be between 430°F and 450°F.
1. Before installing the component(pipe or fitting) in the fusion machine, clean the inside and
outside of the component(pipe or fitting) ends by wiping with a clean, dry, lint-free non-synthetic
cloth or paper towel to remove all foreign matter and potential contaminants. Replace cloth often
as foreign matter and contaminants build up on the surface. If the contamination cannot be
removed this way, wash the pipe with water and a clean cloth or paper towel to remove the
contamination, rinse the pipe with water and dry thoroughly with a clean, dry, lint-free non-
synthetic cloth or paper towel. If contamination such as soap was transferred to the pipe ends
during cutting, use 90% or greater isopropyl alcohol or acetone on a clean cloth or isopropyl
alcohol wipes on the ends of the pipe to clean the contamination, and allow to dry thoroughly. Do
not use the facer to remove contamination. Refer to 1.a. below for a list of common contaminants.
Pipe preparation and cleaning are critical to any fusion process. Improperly cleaned or prepared
pipe ends may result in contamination of the fusion equipment and a poor fusion compromising
joint performance.
a. Common Potential Contaminants include but are not limited to the following: release
agents (silicone or soybean products), silicone-based lubricants, petroleum-based products,
lubricating oils, rust inhibitors, wax, solvent residue, water/moisture, dirt/dust, plastic
shavings, natural body oils, grease, bentonite drilling mud or dust from drilling mud, soap, etc.
2. Align the components with the machine, place them in the clamps, and then close the clamps. Do
not force pipes into alignment against open fusion machine clamps. When working with coiled
pipe, if possible, "S"the pipes on each side of the machine to compensate for coil curvature and
make it easier to join. Component ends should protrude past the clamps enough so that facing
will be complete. Bring the ends together and check high-low alignment. Adjust alignment as
necessary by tightening the high side down.
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3. Insert facing unit between pipe or fitting ends and lock onto guide rods. Face pipe ends to the
stops. Place the facing tool between the component ends and face them to establish smooth,
clean, parallel mating surfaces. Complete facing produces continuous circumferential shavings
from both ends. Face until there is a minimal distance between the fixed and moveable clamps.
Some machines have facing stops. If stops are present, face down to the stops. Remove the
facing tool and clear all shavings and pipe chips from the component ends and ensure pipe ends
are clean. Do not touch the component ends with your hands after facing.
4. After facing is complete, check alignment of pipe ends to ensure the maximum OD high-low
misalignment is less than 10% of the pipe minimum wall thickness. Adjust high-low if necessary.
If adjustment is made, reinsert facing unit and reface to the stops. Bring the component ends
together, check alignment, and check for slippage against fusion pressure. Look for complete
contact all around both ends with no detectable gaps, and outside diameters in high-low
alignment. If necessary, adjust the high side by tightening the high side clamp. Do not loosen the
low side clamp because components may slip during fusion. Re-face if high-low alignment is
adjusted.
5. Check temperature at heater plate and compare with heater surface temperature table, then wipe
surface clean. Verify the heating tool is maintaining the correct temperature in the fusion zone by
using an approved infrared or contact pyrometer. Place the heating tool between the component
ends and move the ends against the heating tool. The initial contact should be under moderate
pressure to ensure full contact. Hold contact pressure very briefly then release pressure without
breaking contact. Pressure must be reduced to contact pressure at the first indication of melt
around the pipe ends. Hold the ends against the heating tool without force. Beads of melted
polyethylene will form against the heating tool at the component ends. When the proper melt
bead size is formed, quickly separate the ends, and remove the heating tool.
Minimum Melt Bead Size Table
Main Pipe Sizes in Minimum Melt Bead Size in
1 1/4 and smaller 1/32
2 through 3 1/16
Above 3 through 8 3/16
During heating, the melt bead will expand out flush to the heating tool surface or may curl slightly
away from the surface. If the melt bead curls significantly away (concave)from the heating tool
surface, unacceptable pressure during heating may be indicated.
6. Immediately after heating tool removal, QUICKLY inspect the melted ends, which should be flat
smooth and completely melted. If the melt surfaces are acceptable, immediately and in a
continuous motion, bring the ends together and apply the correct joining force. Do not slam. Apply
enough joining force to roll both melt beads over the pipe surface.
The maximum time allowed for opening the machine, removing the heater, and bringing the pipe
ends together is shown in the Maximum Heater Plate Removal Times Table below.
Maximum Heater Plate Removal Times Table
Avista Pipe OD Sizes in &SDR Maximum Heater Plate Removal Time Seconds
1/2"to 1 1/4" All SDRs 4
2" SDR 11; 3 IPS SDR 11.5 8
4" SDR 11.5 10
6" SDR 11.5 15
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If hydrocarbon contamination is encountered on the pipe face during a butt fusion, stop the fusion
process. Do not complete butt fusion welds on the pipe unless sound pipe can be found to
complete the fusion process. When contamination is a concern, it is preferred to use mechanical
fittings on plastic pipe 2-inch diameter and smaller. For situations with pipe larger than 2-inch
diameter where mechanical fittings are not available, it is recommended that electrofusion fittings
be used to join pipe if contamination is a concern. Electrofusion fittings may be used on 2-inch
and smaller, but mechanical connections are preferred. See Specification 3.24, Joining of Pipe—
Plastic (Polyethylene) - Electrofusion for information regarding the electrofusion process. Contact
Gas Engineering as necessary for additional assistance. Refer to the Butt Fusion Troubleshooting
Guide at the end of this specification.
7. Maintain joining force against the ends for a minimum of 11 minutes per inch of pipe wall
thickness, refer to Butt Fusion Cooling Times Table. Joining force can be maintained manually or
by using the fusion machine latch mechanism to hold the jaws in place (e.g., McElroy cam locks).
For ambient temperatures 100 °F and higher, additional cooling time may be needed. Do not try
to shorten cooling time by applying water, wet cloths, etc. Pulling, installation, pressure testing,
and rough handling shall be avoided for at least an additional 30 minutes.
8. On both sides, the double bead should be rolled over to the surface and be uniformly rounded
and consistent in size all around the joint. The double bead width should be 2 to 2-1/2 times its
height above the surface, and the v-groove depth between the beads should not be more than
half the bead height.
When butt fusing to molded fittings, the fitting-side bead may have an irregular appearance. This
is acceptable provided the pipe-side bead is correct. It is not necessary for the internal bead to
roll over to the inside surface of the pipe.
Butt Fusion Cooling Times Table
DRISCOPIPE, DRISCOPLEX, ENDOT, PLEXCO, POLYPIPE, AND UPONOR 2406
Pipe Size SDR Cooling Time min Cool to Rough Handle min
2" IPS 11 2-1/2 30
3" IPS 11.5 3-1/2 30
4" IPS 11.5 4-1/2 30
6" IPS 11.5 6-1/2 30
9. If at any time during the fusion process there is doubt regarding the success of the fusion or if
contamination is a concern, abandon and remove the fusion joint and re-start the process of
making a new fusion joint.
HYDRAULIC BUTT FUSION:
Refer to the manufacturer's operation manual for maintenance and special operation of the fusion
equipment.
The procedure for butt fusion above is the same; however, when using a hydraulic fusion machine, the
fusion pressure must be determined using the recommended interface pressure from the pipe
manufacturer and the following procedures:
The pressure gauge on the manifold block indicates the pressure at the carriage valve. How much
pressure depends on the position of the selector valve and the pressure set on the specific pressure-
reducing valve. With the selector valve up, the facing pressure can be set. It may be necessary to adjust
the carriage speed, while facing, with the top pressure-reducing valve to control facing speed.
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Shift the selector valve to the center position and set the heating pressure (if required). If heating
pressure is not required, set the pressure reducing valve at its lowest setting or the drag pressure,
whichever is higher. The heating and fusion pressures can be calculated using the following calculations:
Determining Draq Pressure:
The following steps are applicable to McElroy#28 or#250 hydraulic fusion machines only.
1. After facing the pipe, move the carriage so that the pipe ends are approximately 2-inches apart.
2. Shift the carriage control valve to the middle (neutral) position.
3. Select the heating mode and adjust the heating pressure reducing valve to its lowest pressure by
turning the valve counterclockwise.
4. Shift the carriage control valve to the left.
5. If the carriage doesn't move, gradually increase the pressure by turning the valve clockwise.
Increase the pressure until the carriage moves. If the carriage moves with the heating pressure
reducing valve at its lowest pressure, record a drag pressure of 30 PSI and skip steps 6 and 7.
6. Quickly reduce the heating pressure by turning the valve counterclockwise until the carriage is
just barely moving.
7. Record the pressure. (This is the actual DRAG pressure, which is used in the calculation of the
fusion pressure).
Note: Some pressure gauges may not have enough resolution to register an accurate reading
below the lower limits of the gauge. If pressure gauge registers 0 PSI for drag pressure, it is
recommended to use 30 PSI for drag pressure or to replace the pressure gauge with a higher
resolution gauge.
Determining Fusion Pressure:
The following is the calculation for determining fusion pressure:
(OD—t)x t x PI x IFP + DRAG
TEPA
OD = Outside diameter of pipe (should be marked on pipe)
t=Wall thickness (OD divided by SDR)
PI = 3.1416
SDR = Standard dimension ratio (Should be marked on pipe—Refer to Note Below)
IFP = Manufacturer's recommended interfacial pressure (75 psig +/- 15)
TEPA= Total effective piston area (standard high force for specific machine)
DRAG = Force required to move pipe
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Example: Calculating for 6-inch IPS pipe using a#28HF McElroy machine
OD of Pipe = 6.625
SDR of Pipe = 11.5
IFP = 75 psi
DRAG = 30 psi (determined using above procedure)
TEPA=4.710 (#28HF McElroy machine)
(6.625 - .576)x .576 x 3.1416 x 75+ 30 psi drag = 204 psi
4.710
Note: Fusion of pipes or fittings with different SDRs is acceptable as long as the varied materials only
have up to one SDR difference (i.e., SDR 11 to SDR 13.5 or SDR 9 to SDR 11). When fusing pipes or
fittings with unlike SDRs use the higher SDR (thinner wall pipe)when determining the required fusion
pressure.
Hydraulic Fusion Pressures
#28HF McElroy Machine TEPA= 4.710
Nominal Fusion Pressure Fusion Pressure
Pipe SDR Fusion Pressure (PSI) (PSI) (PSI)
Diameter (IFP = 60 PSI)* IFP = 75 PSI)- (IFP = 90 PSI)*
2" IPS 11 19 23 28
3" IPS 11 41 51 61
4" IPS 11 67 84 100
6" IPS 11 145 181 218
3" IPS 11.5 39 49 58
4" IPS 11.5 64 80 97
6" IPS 11.5 139 174 209
* Fusion Pressures in this table do not include DRAG. Be sure to account for DRAG to determine proper
hydraulic fusion pressure.
Hydraulic Shift Sequence:
1. Move the carriage to the right to open a gap and allow insertion of the heater plate.
2. Check the fusion position and shift the selector valve handle down to the fusing position. Allow
the gauge pressure to drop to the machines minimum pressure setting.
3. Ensure that the heater surface is free of any potential contaminants. Use a clean non-synthetic
cloth to clean the surfaces, as necessary.
4. Verify heater temperature then insert heater between the pipe ends.
5. Prepare pipe for fusion as previously described in this specification (or as recommended by the
pipe manufacturer).
6. Move the carriage to the left, bringing the heater into contact with both pipe ends.
7. Shift the selector valve to the center position and allow the gauge pressure to drop to the
machines minimum pressure setting.
8. When the gauge drops to its minimum setting, return the carriage control valve to neutral position.
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9. Allow the pipe to melt.
10. After obtaining the proper melt, shift the selector valve down to fusion position and move the
carriage to the right just enough to remove the heater.
11. QUICKLY REMOVE THE HEATER and inspect the melted ends, which should be flat, smooth,
and completely melted.
12. If the melt surfaces are acceptable, move the carriage to the left, bringing the pipe ends together
under the pipe manufacturer's recommended pressure.
13. Allow the joint to cool under pressure as listed in the butt fusion procedure previously described in
this specification (or as recommended by the pipe manufacturer).
Cold Weather Fusion
1. Carefully remove (by light tapping and wiping) ice, snow, or frost from inside and outside the pipe
ends and the areas to be clamped in the joiner. Otherwise, they will melt when exposed to the
heating tool and spot chill the polyethylene. This may cause incomplete fusion. Also, frost and ice
on the clamping surfaces of the pipe may cause slippage during fusion.
2. In the case of high winds and rain, the heating tool should be shielded to prevent excessive heat
loss and to keep the tool dry at all times. A canopy should be used to shield the heating tool and
fusion area from wind, snow, and rain.
3. Always check the manufacturer's recommendations for any temperature limitations with
equipment, such as the "Line Tamer", which has problems re-rounding pipe in freezing
conditions.
The length of the heating cycle necessary to obtain a complete melt pattern will depend not only on the
outdoor temperature, but wind conditions, pipe tolerances, and operator variation. Melt pattern is the key.
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Butt Fusion Troubleshooting Guide
BUTT FUSION BEAD TROUBLESHOOTING GUIDE
Observed Condition Possible Cause
Excessive double bead width Overheating; excessive joining force
Double bead v-groove too deep Excessive joining force; insufficient heating;
pressure during heating
Flat top on bead Excessive joining force; overheating
Non-uniform bead size around pipe Misalignment; defective heating tool; worn
equipment; incomplete facing
One bead larger than the other(except Misalignment; component slipped in clamp; worn
when fusing pipe to molded fitting or equipment; defective heating tool; incomplete
when fusing dissimilar materials) facing
Beads too small Insufficient heating; insufficient joining force
Shallow v-groove— Insufficient heating &
Bead not rolled over to surface insufficient joining force
Deep v-groove— Insufficient heating & excessive
joining force
Beads too large Excessive heating time
Squared outer bead edge Pressure during heating
Rough, sandpaper-like, bubbly, or Hydrocarbon contamination
pockmarked melt bead surface
Compatibility/Cross Fusions
When connecting polyethylene pipe and/or fittings that have different densities or unlike material
properties an electrofusion process or mechanical fittings should be utilized. If circumstances require
heat fusion, then the butt-fusion procedure outlined earlier in this section may be utilized if the following
conditions are met:
• Material Melt Index (MI)—0.05 g/10 min < MI < 0.25 g/10 min
(i.e. — Plexco, Driscoplex, Driscopipe, Yellowstripe, Uponor& Polypipe PE 2406/2708 and PE
100/3408/4710)
One bead may be larger than the other when fusing two dissimilar materials. This is acceptable provided
both bead sizes are uniform around their respective pipes.
When connecting to Driscopipe 7000, Driscopipe 8000, Driscopipe 8600, or DuPont/Uponor"Aldyl A"
pipe, connections shall be made utilizing either the electrofusion process or by use of mechanical fittings.
These older materials have higher melt indices that are outside the acceptable range for cross fusing
using this butt fusion process.
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3.24 JOINING OF PIPE - PLASTIC (POLYETHYLENE) - ELECTROFUSION
SCOPE:
To establish procedures to be followed in the joining of plastic pipe by means of the electrofusion process
in Avista's natural gas distribution systems.
REGULATORY REQUIREMENTS:
§192.271, §192.273, §192.281, §192.283, §192.285, §192.287, §192.756
WAC 480-93-080
OTHER REFERENCES:
ASTM F1055
CORRESPONDING STANDARDS:
Spec. 2.13, Pipe Design - Plastic
Spec. 3.13, Pipe Installation— Plastic
Spec. 3.23, Joining of Pipe— Plastic (Polyethylene)— Heat Fusion
Spec. 3.33, Repair of Plastic(Polyethylene) Pipe
Spec. 3.34, Squeeze-Off of PE Pipe and Prevention of Static Electricity
General
Electrofusion is a plastic (polyethylene) pipe joining technique that uses a fitting implanted with metal
coils. When a current is passed through the metal coils, resistive heating of the coils melts the pipe and
fitting together which creates a heat fusion joint upon solidification (i.e., cooling).
The following procedures are for the joining of polyethylene plastic pipe during construction or repair
operations. This electronic fusion system utilizes a sequence processor or control unit and a specially
designed electrofusion fitting. The sequence processor is computerized in order to provide precise control
of fusion time, temperature, and joining pressure. A recognition resistor identifies fittings to the control unit
and automatically sets the correct fusion time. The control unit also monitors critical aspects of the fusion
process and will sound an alarm if part of the process is faulty or incomplete. A self-diagnostic function is
built into the unit and is accessible by pressing and holding the start button at power up or by use of a
personal computer. The electrical fusion system is not intrinsically safe or explosion proof. In repair
situations where 100 percent shut off is not available, escaping gas should be vented away from the
control unit.
Electrofusion fittings shall have been tested and qualified by the manufacturer under§192.283 and ASTM
F1055 prior to use as an approved fitting. Currently approved electrofusion style fittings include Georg
Fischer Central Plastics, Innogaz, IPEX/Friatec/Frialen, Jameson, and M.T. Deason all of which meet
these qualifications according to each manufacturer. The manufacturer's instructions should be consulted
before performing any electrofusion procedures. Reference Avista's Manufacturer's Operating
Instructions Manual for Gas Operations for additional information. An electrofusion shall not be made
closer than 3 pipe diameters or 12 inches, whichever is greater, from a previous squeeze point.
Failure to meet these separations may result in damage to the fittings or joint. Clearances from previous
squeeze points shall be visually confirmed (i.e., exposed), except for new pipeline installations where the
field as-built documents have not yet been submitted and the absence of previous squeeze points can be
inferred with certainty. Refer to Spec 3.34 related to requirements for squeezing plastic pipe.
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utilities NATURAL GAS SPEC. 3.24

Qualifying Joining Procedures
Before any written procedure is used for making electrofusion plastic pipe joints, the procedure must be
qualified by subjecting specimen joints that are made according to the procedure to the applicable testing
requirements in §192.283 and ASTM F1055. Copies of qualified written joining procedures must be
located on site where plastic pipe joining is being performed.
Qualifications of Persons to Join Plastic Pipe
No person may perform electrofusion on polyethylene pipe until that person has received training in the
procedures and has made acceptable specimen joints similar to those that will be made in the field. This
person must also hold a current qualification. Persons must be re-qualified once each calendar year not
to exceed 15 months. If any field electrofusion joints fail during pressure testing, then the individual who
performed that particular joining process is no longer qualified and must re-qualify on that electrofusion
procedure unless it can be shown that the joint failed due to factors that are outside of the joiner's control
(i.e., equipment failure or material flaw).
The electrofusion specimen joints must be visually examined during and after joining and found to have
the same appearance as a joint or photographs of a joint that is acceptable under the procedure. The
specimen joints must also be tested in accordance with the requirements in paragraph 9.4 (Joint Integrity
Tests)of ASTM F1055.
Maintenance and Calibration of Heat Fusion Equipment
Avista and its contractors must maintain equipment used in joining plastic pipe in accordance with the
manufacturer's recommended practices or with written procedures that have been proven by test and
experience to produce acceptable joints as noted in §192.756. For Avista and its contractors,
documentation of this requirement shall be completed through the signing of the Pressure Test
Information Sticker(Form N-2490 or similar) on the applicable as-built construction document.
By signing the aforementioned document, an operator qualified individual is attesting that construction
complied with current company standards/specifications and specifically in this case, that the heat fusion
equipment is being maintained as appropriate. See the Manufacturer's Operating Instructions Manual for
Gas Operations, Sections 2 and 3 (as applicable)for fusion equipment maintenance specifics.
Calibration Timeframes for Electrofusion Equipment
Electrofusion machines should be returned to the factory for calibration or maintenance on a time basis
as recommended by the manufacturer of the equipment and the record of calibration/maintenance sticker
updated at that time. See the table below for recommended maintenance schedule by manufacturer.
Manufacturer Recommended Service/Maintenance Schedule
IPEX Friamat Annually
IPEX Genesis F3 Every 3 Years
Georg Fisher/Central Plastics MSA 340 Every 2 Years
Marking Joints
For all types of plastic joints, the qualified individual who performed the joint shall use a permanent
marker to legibly sign the pipe with their first initial and full last name and shall mark the date of the joint.
It is recommended to write down the time that the joint was fused so that the appropriate cooling times
can be easily determined.
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STANDARD COUPLING AND ENDCAP JOINING PROCEDURES:
1. Determine that all necessary tools and equipment are available and good working order before
beginning the procedure. When using a generator, the generator should always be engaged before
plugging the control unit in. A 3500-watt minimum generator is required, although 5000 watt is
recommended. A 110-volt, 30 amp, GFCI A/C power source will also be required.
2. It is critical that the pipe ends to be joined have a square, even cut. It is recommended that a pipe
tape be used to mark the pipe prior to cutting to help ensure a square cut. Once the pipe is cut,
remove any burrs or shavings from the pipe ends that may have occurred during the cutting
process.
3. Thoroughly clean each pipe end inside and out using clean water or isopropyl alcohol with a clean,
lint-free cloth to remove any foreign matter or potential contaminants. Replace cloth often as foreign
matter and contaminants build up on the surface. Refer to Specification 3.23 —Sheet 3, Joining of
Pipe— Plastic (Polyethylene)— Heat Fusion, "Butt Fusion Procedures"for a list of common
contaminants. Pipe preparation and cleaning are critical to any fusion process. Improperly cleaned
pipe may result in a poor fusion and a potentially compromised joint.
4. Once the fusion area is cleaned, visually check for scratches in the fusion area that appear to be 10
percent or more of the pipe wall. Minor scratches are not unusual on installed pipe, especially on
pipe installed via directional drill. Use an approved pit gauge to measure the depth of scratches that
are of concern. The edges of the scratch may need to be widened slightly to ensure the
measurement point of the gauge can reach the bottom of the scratch to properly measure the
depth. Care must be taken not to deepen the scratch. If a scratch is found to be equal to or greater
than 10 percent of the wall thickness of the pipe, either replace the section with new pipe or repair
the pipe using an approved repair fitting, per Specification 3.33, Repair of Plastic Pipe. If not,
proceed to Step 5 in preparation for electrofusion fitting installation.
5. Prior to peeling the pipe, scrape the fusion surface with a scraper, as needed, to remove any ridges
that may have been created from displaced material due to scratching. This will help ensure a
uniform surface prior to peeling the pipe. Use only scraping equipment recommended by the
manufacturer or approved by Avista (emery cloth and sandpaper are not approved tools). Once
scraped, or if scraping is not required, peel the pipe using an approved peeler to remove any
surface oxidation along with any contamination such as bentonite, oil, grease, or perspiration that
may have built up on the outside layer of pipe. Failure to do so could result in contamination within
the fusion zone. A full encirclement peeler is recommended. For best results, use a silver metallic
permanent marker(do not use a black permanent marker or grease pencil)to mark lines on the
area of pipe prior to peeling. The mark lines should run parallel with the pipe and be about 1-inch
apart over the entire area of the pipe to be peeled. Secure the peeling tool on the pipe and begin
the peeling process. Continue to peel until mark lines are removed. This is usually accomplished
with 1 pass of the tool. Do not exceed more than one pass of the peeler on 2-inch and smaller
diameter pipe and two passes of the peeler on pipe sizes larger than 2-inch. If necessary, during
the peeling process, remove the tool and clean the blade area with a clean, dry, lint-free cloth to
remove build-up of material (isopropyl alcohol also works well to clean the blade). It is possible
scratches may still exist in the fusion zone after scraping and peeling. This is acceptable as long as
the scratches are clean and are not deep enough to have removed 10 percent or more of the
original pipe wall. Once peeling is complete, deburr the outside edge of the pipe end near the
prepared fusion surface with a scraper. This should help to protect the wire coils of the electrofusion
fitting when sliding the fitting over the end of the pipe.
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6. Possible recontamination of the prepared surface should be avoided. Do not touch the peeled pipe
surfaces or the inside of the fitting with your hands as perspiration and body oils could contaminate
joining areas and affect joint integrity. If contaminates are suspected on the fitting, clean the fitting
with isopropyl alcohol and a clean lint-free cloth. If contaminants are suspected on the pipe, or if the
pipe was installed by a horizontal direction drill using bentonite, clean ONLY the peeled/scraped
area of the pipe with isopropyl alcohol and a clean lint-free cloth taking care not to wipe the pipe
outside of the peeled area because contaminants may be redeposited onto the peeled/scraped
surface. Let the alcohol evaporate completely prior to assembling the pipe and fitting.
7. Determine the stab depth of the fitting by measuring half the length of the coupling. Mark each pipe
end an equivalent length with a silver metallic permanent marker. Do not use a black permanent
marker or grease pencil to mark the stab depth as this may contaminate the pipe surface.
8. Slide the coupling or endcap onto one pipe end until the squared end of the pipe meets with the
internal stop in the fitting. With couplings, insert the second pipe end into the fitting so that the end
also meets the internal stops. If the fitting is being used for a repair the internal stops may be
removed. Check the measurement marks to assure the pipe is inserted to the proper stab depth.
9. If there is a possibility of movement in the assembly during the fusion cycle, an alignment clamping
tool should be utilized. Be sure to maintain the proper stab depth. For best results, the alignment
clamps should be placed as close to the fitting as possible. For coiled pipe larger than 3/4-inch (and
for other binding installations), the use of two clamps on each side of the coupling is recommended.
Ensure the clamps are supported to avoid putting stress on the fusion joint.
10. Connect the control unit to the A/C power source. The sequence processor will automatically
perform a quick diagnostic check.
11. Attach the leads from the control unit to the fitting terminals. If a barcode is present, scan the
barcode to identify the fitting. Verify the correct fitting type is displayed on the control unit.
12. Press the start button to begin the fusion cycle. Fusion cycle time will count down on the visual
display.
13. When the fusion cycle is complete, "End of Fusion" as well as the "Cooling Time" will appear on the
visual display. Disconnect the leads from the fitting and allow the fusion to cool for the minimum
time before removing the clamp(s).
14. After removing the clamp(s), additional cooling time shall be allowed before subjecting the joint to
bending, burying, pressure testing, or similar handling or backfill stress. Refer to the table at the
end of this specification for recommended cooling times for various sized electrofusion fittings.
15. Fusion joints shall be subjected to a pressure test as specified in this standard and a visual soap or
leak detector test as appropriate.
Note 1: If the fitting is installed and the normal electrofusion process is complete, but there is no
indication of the pop-up indicator rising, then additional investigation is required. Under these
circumstances, if the electrofusion fitting feels hot to the touch within each fusion zone, alignment of the
fitting appears good after the fusion and the fitting passes the required pressure testing per Spec 3.18
then the fitting may remain. If not, or there are any indicators of an unsuccessful fusion then the fitting
shall be cut out and replaced. Not all fittings have pop-up indicators (i.e., Georg Fischer Central Plastics).
If a pop-up indicator is not present on the fitting, then follow the directions and information provided by the
electrofusion processor during installation as well as perform the investigation described above.
Note 2: If there are any doubts about the success of the electrofusion process the fitting shall be cut out
and replaced.
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REPAIR COUPLING JOINING PROCEDURE:
1. Make sure that there is enough room in the excavation to install the fitting and the clamping devices.
This repair procedure will require 2 electrofusion fittings per repair section.
2. Cut out and remove the section of damaged pipe.
3. Follow the procedures as outlined under"Standard Coupling & Endcap Joining Procedures" steps
#1 through#7 for cleaning, preparing, and marking the existing pipe ends.
4. Remove the internal fitting stops by bottoming the pipe end to the internal stops. Apply a sudden
thrust to the end of the coupling so that the stops cleanly snap out. Make sure that the fitting stops
are completely removed from the I.D. of the fitting. To avoid contamination of the inside of the
coupling do not use your fingers to remove the loose stops.
5. Slide the fittings onto each of the existing pipe ends.
6. Insert the new section of pipe into place. Make sure that both ends of the new section are cleaned,
prepared, and marked properly. The new section should fit into place between the existing pipe ends
with no more than approximately 1/16-inch clearance on each side.
7. Slide a coupling over the pipe junction until both measurement marks are visible. Measurement
marks should not extend more than 1/16-inch from the coupling end. Repeat on the other side of the
repair section.
8. Follow the procedures as outlined under"Standard Coupling & Endcap Joining Procedures" steps
#10 through#15, to complete the fusion process.
SADDLE JOINING PROCEDURE:
1. Follow steps#3 and #4 as outlined under"Standard Coupling and Endcap Joining Procedures"to
clean the surfaces to be joined with a clean cloth to remove any dirt or contamination and inspect the
pipe for scratches or other damage. If a scratch equal to or deeper than 10 percent of the wall
thickness of the pipe is present, either replace the section with new pipe or repair the pipe using an
approved repair fitting, per Specification 3.33, Repair of Plastic Pipe.
2. Center the saddle fitting on the pipe to determine the required fusion area. Mark the pipe with a
silver metallic permanent marker to show the length of the area to be prepared.
3. Prior to peeling the pipe, scrape the entire fusion surface on the pipe with a scraper, as needed, to
remove any ridges that may have been created from displaced material due to scratching. This will
help ensure a uniform surface prior to peeling the pipe. Use only scraping equipment recommended
by the manufacturer or approved by Avista (emery cloth and sandpaper are not approved tools for
electrofusion installations). Once scraping is complete, or if scraping is not required, peel the entire
pipe surface required for the saddle in order to remove oxidation and potential contaminates. A full
encirclement peeler is recommended. Follow step#5 in the procedures as outlined under"Standard
Coupling & Endcap Joining Procedures"for scraping and peeling.
4. Possible recontamination of the prepared surface should be avoided. Do not touch the peeled pipe
surface or the inside of the fitting with your hands as perspiration and body oils could contaminate
joining areas and affect joint integrity. If contaminates are suspected on the fitting, clean the fitting
with isopropyl alcohol and a clean lint-free cloth. If contaminants are suspected on the pipe, or if the
pipe was installed by horizontal direction drill using bentonite, clean ONLY the peeled area of the
pipe with isopropyl alcohol and a clean lint-free cloth taking care not to wipe the surrounding pipe
because contaminants may be redeposited onto the prepared surface. Let the alcohol evaporate
completely prior to assembling the pipe and fitting.
5. Position the saddle on the clean, peeled area and place the appropriate saddle clamp under the
pipe, adjacent to the saddle fitting.
6. Slide the clamping tool onto the edges of the saddle fitting until the clamp is squarely aligned
beneath the fitting. Tighten the clamp to secure the fitting in place.
7. Follow steps#10 through #15 in "Standard Coupling & Endcap Joining Procedures"to complete the
fusion process. The table at the end of this specification should be consulted for the proper cooling
times for tapping tees.
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ALDYL A TEE REPAIR PROCEDURE:
1. Before initiating the repair, be sure the electrofusion equipment and qualified personnel are on site. A
universal barcode electrofusion control box is the preferred method for translating the barcode data.
2. After excavating the tee, clean the stack and (using approved scraping and peeling tools) scrape and
peel the outside diameter of the stack down to the intersection of the tee outlet, as needed, in
preparation for electrofusion. Follow step#5 in "Standard Coupling and Endcap Joining Procedures".
3. Either scrape and peel the outside diameter of the repair fitting insert using approved tools or clean
the outside diameter with isopropyl alcohol. If the insert is contaminated or has been out of the bag
and exposed to the environment for an extended time, it should be discarded.
4. Install the prepared insert into the 1.25-inch coupling until the shoulder of the insert stops against the
coupling.
5. Install the coupling over the stack of the tee until it bottoms out.
6. Electrofuse the coupling to the tee and insert using the barcode mode or manually input the code
using the advanced functions of the processor.
7. After removing the electrofusion cables, allow the assembly to cool for 10 minutes.
8. If not already done, lightly lubricate the 0-ring (Dow Corning Silicone Grease#111 or equal) and
install it on the plug.
9. Thread the plug assembly into the insert until it bottoms out. The top of the plug should be flush with
the top of the insert. Use a standard 1/2-inch square drive to turn the plug into the insert. This
completes the repair kit assembly process.
SERVICE LINE JOINING PROCEDURE:
To make the service line connection, follow the "Standard Coupling & Endcap Joining Procedures" as
outlined above. The clamp utilized should be one provided by or recommended by the manufacturer
specifically for performing the service line connection. The table at the end of this specification should be
consulted for the proper cooling times for service line connections (reducers).
TAPPING PROCEDURE:
1. Ensure the joint has completely cooled before attempting to perform this tapping procedure. Use a
tapping tool recommended by the manufacturer.
2. To"punch" the main, remove the cap and insert the tapping tool.
3. Slowly turn the tapping tool clockwise to tap the main. Continue turning until the cutter contacts the
lower stop inside the tee. The lower stop ensures that the proper"punch" depth has been achieved.
4. Back the tapping tool out by turning it counterclockwise until the cutter contacts the upper stop inside
the tee. The upper stop ensures that the cutter is fully retracted so that gas flow is not restricted.
5. Install the cap by screwing it all the way down until the collar of the cap touches the front face of the
drill spigot. Then loosen the cap half a turn to relieve the 0-ring tension.
6. As a best practice, consider creating notes and/or marking the tee (e.g., tape, marker, etc.)to keep
track of whether the tee has been tapped out.
REPAIR CLAMP JOINING PROCEDURE:
1. Measure the size of the damaged area of pipe and determine if the damaged area will completely fit
into the cold zone area inside the dome of the repair clamp. The cold zone is the area of pipe that will
be inside and in contact with the electrofusion fitting but away from the electrofusion melt zone. The
cold zone helps to prevent the melt from extruding out of the joint. The cold zone diameter for each
size of repair clamp is as follows:
3-inch IPS = 2.0 inches (75 mm)
4-inch IPS = 3.1 inches (78 mm)
6-inch IPS = 3.3 inches (85 mm)
If the damaged area of pipe will not fit underneath the dome and inside the cold zone, the repair
clamp cannot be used, and a different repair method will need to be utilized or the damaged section
will need to be replaced. Refer to Specification 3.33, Repair of Plastic Pipe, for approved repair
methods.
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2. Follow steps#3 and #4 as outlined under"Standard Coupling and Endcap Joining Procedures"to
clean the surfaces to be joined with a clean cloth to remove any dirt or contamination and inspect
the pipe for scratches or other damage. If a scratch equal to or deeper than 10 percent of the wall
thickness of the pipe is present, either replace the section with new pipe or repair the pipe using
an approved repair fitting, per Specification 3.33, Repair of Plastic Pipe.
3. Measure and mark the pipe surface covered by the fitting with a silver metallic permanent marker.
4. Prior to peeling the pipe, scrape the fusion surface on the pipe with a scraper, as needed, to
remove any ridges that may have been created from displaced material due to scratching. This
will help ensure a uniform surface prior to peeling the pipe. Use only scraping equipment
recommended by the manufacturer or approved by Avista (emery cloth and sandpaper are not
approved tools). Once scraping is complete, or if scraping is not required, peel the entire pipe
surface required for the repair clamp to remove oxidation and potential contaminates. A full
encirclement peeler is recommended. Follow step#5 in the procedures as outlined under
"Standard Coupling and Endcap Joining Procedures"for scraping and peeling.
5. Do not touch the peeled pipe surface or the inside of the fitting with your hands as perspiration
and body oils could contaminate joining areas and affect joint integrity. If contaminants are
suspected on the fitting, clean the fitting with isopropyl alcohol and a clean lint-free cloth. If
contaminants are suspected on the pipe, or if the pipe was installed by horizontal direction drill
using bentonite, clean ONLY the peeled area of the pipe with isopropyl alcohol and a clean lint-
free cloth taking care not to wipe the surrounding pipe because contaminants may be redeposited
onto the prepared surface. Let the alcohol evaporate completely prior to assembling the fitting.
6. Align and install the repair clamp in the cleaned, peeled area over the damaged section of pipe
ensuring that the damaged area of the pipe is completely encapsulated inside the dome of the
fitting and inside the cold zone (refer to Step 1 for the cold zone size for each size of repair
clamp). Firmly tighten all bolts, working diagonally, without using excessive force until the clamp
is flush with the pipe. Assembly of pipe and fitting must be in a clean, supported, and stress-free
condition as much as possible.
Note: Both halves of the repair clamp have electrofusion capability. The bottom half of the repair
clamp (the smooth side without the raised dome) does not need to be electro fused to the pipe. Only
the half covering the repair needs to be electro fused.
7. Follow the procedures outlined in "Standard Coupling & Endcap Joining Procedures" steps#10
through#15 to complete the fusion process. The table at the end of this specification should be
consulted for the proper cooling times for repair clamps.
Re-fusion of Electrofusion Fittings
If during the first 25 percent of the electrofusion heat cycle the power supply to the fusion unit is lost (i.e.,
power outage, generator runs out of fuel, or the leads become disconnected) it is acceptable to re-fuse
the electrofusion fitting as long as the fitting is allowed to cool for at least one hour unless ambient
temperature is reached prior to one hour and the fitting remains undisturbed during the cooling process.
If the fusion process is interrupted during the second attempt the fitting shall be cut out and replaced.
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FUSION/COOLING TIMES BY MANUFACTURER
TABLE A: GF Central Plastics
Fitting (inches) Fusion Clamped Pressurized Rough
Times Cooling /Tapping Handling
Couplings/Endcaps (sec) Time (min)' Time (min) Time (min)
1/2 CTS 20 5 15 30
1/21PS 20 5 15 30
3/41PS 35 5 15 30
1 CTS 40 5 15 30
11PS 45 10 15 30
1-1/41PS 75 10 20 30
21PS 60 10 20 30
31PS 180 15 30 35
41PS 200 15 30 35
61PS 500 20 40 45
Reducers
3/4 x'/2 20 5 15 30
1 x'/2 30 5 15 30
1 x 3/ 30 5 15 30
2 x 1-1/4 45 10 20 30
Tapping Tees
1-1/41PS 45 10 20 30
2 I PS 90 10 20 30
31PS 90 10 20 30
41PS 90 10 20 30
61PS 90 10 20 30
WB HV Tapping Tees
2 x 1-1/4; 2 x 2 90 10 25 30
3 x 1-1/4; 3 x 2 60 10 25 30
4 x 1-1/4;4 x 2 60 10 25 30
6 x 1-1/4; 6 x 2 60 10 25 30
Branch Saddles
2 x 2 90 10 25 30
3 x 2 60 10 25 30
4 x 2 60 10 25 30
6 x 2 60 10 25 30
6 x 4 150 15 30 45
Warning:A.C. current only. D.C. current can result in damage to processor.
Times show above are based upon Manufacturer's recommendations and are not
additive
'Clamping of fittings is not always required. Refer to Spec. 3.24, Sheet 4 for
direction related to clamping.
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TABLE B: Innogaz
Fitting (inches) Fusion Clamped Pressurized Rough
Times Cooling /Tapping Handling
Couplings/Endcaps (sec) Time (min)' Time (min) Time (min)
1/2 CTS 17 3 15 15
1/21PS 45 3 15 15
3/4 IPS 27 6 15 15
1 CTS 29 6 15 15
1 IPS 37 6 15 15
1-1/4 IPS 46 6 20 20
21PS 85 10 20 20
3 IPS 120 8 30 30
41PS 160 10 30 30
6 IPS 300 14 40 40
Aldyl-A Tapping Tee Repair Kit
1-1/4" IPS 46 10 20 20
Reducers
3/4 x 1/2 23 4 15 15
1 x 112 20 4 15 15
1 x 3/4 27 5 15 15
2 x 1-1/4 65 10 15 15
Tapping Tees
1-1/4 IPS 28 10 20 20
21PS 70 10 20 20
31PS 70 10 20 20
4 IPS 70 10 20 20
61PS 70 10 20 20
WB HV Tapping Tees
2 x 1-1/4; 2 x 2 70 10 25 25
3 x 1-1/4; 3 x 2 70 10 25 25
4 x 1-1/4;4 x 2 150 16 25 25
6 x 1-1/4; 6 x 2 150 16 25 25
Warning:A.C. current only. D.C. current can result in damage to processor.
Times show above are based upon Manufacturer's recommendations and are not
additive.
'Clamping of fittings is not always required. Refer to Spec. 3.24, Sheet 4 for
direction related to clamping.
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TABLE C: IPEX/Friatec/Frialen
Fitting (inches) Fusion Clamped Pressurized Pressurized /
Times Cooling Time (min) Rough
Couplings/Endcaps (sec)' Time (min)' 580 PSI Handling Time
(min) > 80 PSI
1/2 CTS 27 5 8 10
1/21PS 28 5 8 10
3/41PS 28 5 8 10
1 CTS 28 5 8 10
11PS 28 5 8 10
1-1/4 IPS 34 10 15 25
2 IPS 54 10 15 25
3 IPS 65 10 30 40
4 IPS 120 10 30 40
61PS 360 20 60 75
Reducers
3/4 x'/2 28 5 8 10
1 x'/2 28 5 8 10
1 x% 28 5 8 10
2 x 1-1/4 54 10 15 25
Repair Clamps
3 IPS 103 10 30 40
4 IPS 138 10 30 40
61PS 450 20 60 75
Before
Fusion Before
Times Pressurizing Ta in
via Outlet pp g
Tapping Tees (sec)' min (min)
1-1/4 IPS 30 15 20
2 IPS 61 15 20
2 IPS x 2 IPS 53 15 20
31PS 150 20 30
3 IPS x 2 IPS 100 20 30
41PS 125 20 30
61PS 546 30 45
Warning:A.C. current only. D.C. current can result in damage to processor.
Times shown above are based upon Manufacturer's recommendations and are not
additive.
'Fusion times may vary(e.g. +8 to-5 seconds) from the table value due to
temperature compensation adjustments applied automatically by the control unit.
'Clamping of fittings is not always required. Refer to Spec. 3.24, Sheet 4 for
direction related to clamping.
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TABLE D: Jameson
Fitting (inches) Fusion Clamped Pressurized Rough
Times Cooling /Tapping Handling
Insertion Tap Tee (sec) Time (min) Time (min) Time (min)
2 x 1 90 25 25 10
4 x 1 120 25 25 10
6 x 1 120 25 25 10
Warning:A.C. current only. D.C. current can result in damage to processor.
Times show above are based upon Manufacturer's recommendations and are not
additive.
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TABLE E: M.T. Deason
Fitting (inches) Fusion Clamped Pressurized Rough
Times Cooling /Tapping Handling
Couplings (sec)' Time (min)2 Time (min) Time (min)
1/2 CTS On Label 5 15 15
3/4 IPS On Label 5 15 15
1 CTS On Label 10 20 20
1 IPS On Label 10 20 20
1-1/4 IPS On Label 10 20 20
2 IPS On Label 10 20 20
3 IPS On Label 10 20 20
4 IPS On Label 10 20 20
6 IPS On Label 20 40 40
Endcaps
1 CTS On Label 5 15 15
2 IPS On Label 10 20 20
3 IPS On Label 10 20 20
4 IPS On Label 10 20 20
6 IPS On Label 10 20 20
Reducers
3/4 x'/2 On Label 5 15 15
1 x'/2 On Label 5 15 15
1 x% On Label 10 20 20
1-1/4 x 1 On Label 10 20 20
4 x 2 On Label 10 20 20
6 x 4 On Label 20 35 35
Tapping Tees
1-1/4 IPS On Label 10 25 25
2 IPS On Label 10 25 25
3 IPS On Label 10 25 25
4 IPS On Label 10 25 25
6 IPS On Label 10 25 25
WB HV Tapping Tees
2 x 1-1/4; 2 x 2 On Label 10 25 25
3 x 1-1/4; 3 x 2 On Label 10 25 25
4 x 1-1/4;4 x 2 On Label 10 25 25
6 x 1-1/4; 6 x 2 On Label 10 25 25
Warning:A.C. current only. D.C. current can result in damage to processor.
Times show above are based upon Manufacturer's recommendations and are not
additive.
Manufacturer does not publish fusion time. Refer to the fitting label for proper
fusion time.
2Clamping of fittings is not always required. Refer to Spec. 3.24, Sheet 4 for
direction related to clamping.
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TABLE E: M.T. Deason Continued
Fitting (inches) Fusion Clamped Pressurized Rough
Times Cooling /Tapping Handling
Branch Saddles (sec)' Time (min)2 Time (min) Time (min)
2 x 2 On Label 10 25 25
3 x 2 On Label 10 25 25
4 x 2 On Label 10 25 25
4 x 4 On Label 10 25 25
6 x 2 On Label 10 25 25
6 x 4 On Label 20 35 35
6 x 6 On Label 10 25 25
Repair Saddles
3 IPS On Label 10 25 25
4 IPS On Label 10 25 25
6 IPS On Label 10 25 25
22.5°/45'/90' Elbows
1 CTS On Label 10 30 30
2 IPS On Label 10 20 20
3 IPS On Label 10 20 20
4 IPS On Label 10 20 20
6 IPS On Label 20 40 40
Warning:A.C. current only. D.C. current can result in damage to processor.
Times show above are based upon Manufacturer's recommendations and are not
additive.'Manufacturer does not publish fusion time. Refer to the fitting label for
proper fusion time.
2Clamping of fittings is not always required. Refer to Spec. 3.24, Sheet 4 for
direction related to clamping.
JOINING OF PIPE REV. NO. 17
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utilities NATURAL GAS SPEC. 3.24

3.25 JOINING OF PIPE - PLASTIC (POLYETHYLENE) - MECHANICAL
SCOPE:
To establish procedures to be followed in the joining and repair of plastic pipe by means of mechanical
fittings and couplings in Avista's natural gas distribution systems.
REGULATORY REQUIREMENTS:
§192.271, §192.273, §192.281, §192.283, §192.285, §192.287
CORRESPONDING STANDARDS:
Spec. 2.13, Pipe Design — Plastic (Polyethylene)
Spec. 3.13, Pipe Installation— Plastic (Polyethylene) Mains
Spec. 3.16, Services
Spec. 3.18, Pressure Testing
Spec. 3.22, Joining of Pipe -Steel
Spec. 3.33, Repair of Plastic (Polyethylene) Pipe
Spec. 3.34, Squeeze-Off of PE Pipe and Prevention of Static Electricity
General
Heat fusion or electrofusion fittings should be used whenever practical to join polyethylene pipe.
Company-approved mechanical couplings may be used to connect plastic pipe in repair situations and for
new installations where warranted. Service head adapters may be used in cases where non-cathodically
protected riser replacement is impractical or in cases where prefabricated risers for plastic services are
impractical or unavailable. Service head adapter fittings shall be of the type designed to effectively resist
pullout forces (Category 1-A, ASTM D-2513).
Mechanical fittings shall have been tested and qualified by the manufacturer under§192.281 and
§192.283 prior to use as an approved fitting. Approved mechanical fittings shall utilize only gasket
material compatible with plastic pipe, employ a rigid internal tubular stiffener in conjunction with the outer
coupling and meet a listed specification based upon the applicable material.
Joining of plastic pipe by mechanical fittings shall only be performed by properly trained and qualified
personnel who shall qualify initially and re-qualify annually. Persons must be re-qualified once each
calendar year not to exceed 15 months. If any field mechanical joints fail during pressure testing, then
the individual who installed that particular fitting is no longer qualified and must re-qualify on that
mechanical fitting installation procedure unless it can be shown that the joint failed due to factors that are
outside of the installer's control (i.e., equipment malfunction or material flaw).
For Aldyl-A pipe, the use of RW Lyall Lycofit mechanical fittings is only allowed on 1/2-inch and 3/4-inch
diameter pipe. Joining of Aldyl-A pipe larger than 3/4-inch diameter should be made using an approved
electrofusion fitting.
PE valves may be installed using spigot and sleeve mechanical fittings as long as the fitting can be
installed per the manufacturer's instructions. Other mechanical fittings are not approved for the
installation of PE valves. Mechanical couplings or fittings shall not be re-used. A mechanical connection
shall not be made closer than 3 pipe diameters or 12 inches, whichever is greater, from a previous
squeeze point. Failure to meet these separations may result in damage to the fittings or joint.
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Clearances from previous squeeze points shall be visually confirmed (i.e., exposed), except for new
pipeline installations where the field as-built documents have not yet been submitted and the absence of
previous squeeze points can be inferred with certainty. Refer to Spec 3.34 related to requirements for
squeezing plastic pipe.
When making a mechanical connection if the carrier pipe becomes discolored and appears to yield during
insertion of the spigot or stab end of the fitting it is recommended the installation be cut out and replaced.
An alternative joining method may need to be considered during replacement.
Marking Joints
For all types of plastic joints, the qualified individual who performed the joint shall use a permanent
marker to legibly sign the pipe with their first initial and full last name and shall also mark the date of the
joint.
Procedures
PROCEDURE FOR INSTALLING APPROVED SPIGOT AND SLEEVE TYPE COUPLINGS AND
FITTINGS USING THE QRP-100 QUICK RATCHET PRESS TOOL (REFERENCE: LIT-
LCQRP1001NST-2E):
Note: The QRP-100 ratchet press is for installation of Lycofit 1/2-inch CTS and 3/4-inch IPS fittings only.
Refer to the Manufacturer's Operating Instructions Manual and the manufacturer provided instruction
document packaged with each fitting for further details and diagrams to supplement the following
procedure.
Installation Procedure for Double Ended Couplings
1. Inspect the installation tool for proper orientation prior to installation. If there is any damage or
deformation present on the tool or tool jaws utilize a different tool where these conditions do not
exist.
2. Inspect the fitting for signs of damage prior to installation. Inspect the spigot barbs and metal
stiffener for deformation that may indicate damage to the entire spigot. Discard the fitting if any of
these conditions exist.
3. Wipe the pipe sections to be joined with a clean, dry cloth to assure there is no dirt, grease, or oil in
the assembly area. Slide the completion sleeve onto the PE pipe exposing approximately 3 inches
of the pipe end. Note: Completion sleeves are non-directional and can be installed onto the pipe via
either end.
4. Slide the LycoRing, with the small diameter first (thin end), onto the PE pipe and position it
approximately 1/2 inch further than the length of the fitting's spigot from the end of the pipe. Note:
The LycoRing may be damaged if the ring is pushed over the side of the pipe.
5. Place the spigot into the ratchet tool's fixed jaw. With one hand, slide the completion sleeve onto
the LycoRing until the LycoRing starts to grip the pipe. Position the pipe and completion sleeve into
the ratchet tool's movable end, the spigot should be on the fixed end. Align the pipe to the spigot
and push the pipe into the spigot, stopping when the pipe reached the first barb on the spigot.
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6. Operate the ratchet tool and advance the pipe onto the spigot. Stop advancement when the pipe
covers the last barb on the spigot. Inspect the PE pipe for signs of damage or undue stress after it
has been advanced over the spigot. Note: To prevent possible damage to the PE pipe, ensure that
the spigot and the completion sleeve are fully seated in the ratchet tool's fixed jaw and that the tool
and the pipe/coupling alignment is square so that the pipe does not drag on the edges of the tool
jaw. Do not apply lubricants to the fitting's spigot, sleeve, or the PE pipe.
7. Reverse the ratchet direction and ratchet the tool enough to pull the completion sleeve back to
expose the LycoRing. Remove the LycoRing by pulling it off of the side of the pipe using the pull tab
on the ring.
8. Reverse the ratchet tool's ratchet direction and advance the completion sleeve over the pipe and
spigot by operating the ratchet. Stop the completion sleeve advancement when the sleeve is fully
inserted over the spigot and the sleeve face is in full contact with the fitting flange. If site conditions
prohibit the sleeve face from fully contacting the fitting flange resulting in a gap, there shall be at
least one point of contact between the sleeve face and the fitting flange. Inspect the joint and again
the PE pipe to ensure that there is no damage that may have occurred during the installation
process.
9. Complete the other side of the coupling by repeating Steps 2 through 8.
10. Test the fitting per Specification 3.18, Pressure Testing.
Installing Other Lycofit Fittings
Refer to page 4 of the QRP-100 Lyco Quick Ratchet Press installation procedure in the Manufacturer's
Operating Instructions Manual for Gas Operations for guidelines on the proper spigot flange location for
each type of Lycofit fitting as well as the placement of the spigot flange in the ratchet tool's jaw during
installation. Apply the same steps used for installing double ended couplings as specified above.
PROCEDURE FOR INSTALLING APPROVED SPIGOT AND SLEEVE TYPE COUPLINGS AND
FITTINGS USING THE LHP-200 HYDRAULIC PRESS TOOL (REFERENCE: LIT-LCLHPINST Rev.
1
Note: The LHP-200 hydraulic press is for installation of Lycofit 1-1/4-inch, 1-1/2-inch, and 2-inch IPS
fittings only. Lubricate the hydraulic tool's shafts with non-synthetic lubricant only. Refer to the
Manufacturer's Operating Instructions Manual and the manufacturer provided instruction document
packaged with each fitting for further details and diagrams to supplement the following procedure.
1. Inspect the hydraulic tool to ensure there is not any damage or deformation present on the tool that
might compromise the integrity of the final joint.
2. Inspect the fitting for signs of damage prior to installation. Inspect the spigot barbs and metal
stiffener for deformation that may indicate damage to the entire spigot. Discard the fitting if any of
these conditions exist.
3. Wipe the pipe sections to be joined with a clean, dry cloth to assure there is no dirt, grease, or oil in
the assembly area. Slide the completion sleeve and then the LycoRing onto the pipe so that the
LycoRing is approximately 3-1/2 inches from the end of the pipe. Nest the spigot flange in the
saddle of either press plate. Place the tool so that the press plate opposite of the spigot is behind
the completion sleeve.
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4. Slide the PE pipe over the end of the spigot and operate the hydraulic pump until the press plate is
in contact with the completion sleeve. Note: Ensure the completion sleeve engages the LycoRing
and that the LycoRing does not slip along the PE pipe.
5. Continue operating the hydraulic pump to move the press plate and advance the spigot into the PE
pipe until the pipe covers the last barb on the spigot. Inspect the PE pipe for signs of damage or
undue stress after it has been advanced over the spigot. Note: Do not apply lubricants to the
fitting's spigot, sleeve, or the PE pipe.
6. Release the hydraulic pressure and allow the tool jaw to open enough to pull the completion sleeve
back and expose the LycoRing. Remove the LycoRing by pulling it off of the side of the pipe using
the pull tab on the ring.
7. Operate the hydraulic pump to move the press plate and advance the completion sleeve over the
pipe and the spigot. Stop pumping when the sleeve face is in full contact with the fitting flange. If
site conditions prohibit the sleeve face from fully contacting the fitting flange resulting in a gap,
there shall be at least one point of contact between the sleeve face and the fitting flange. Inspect
the joint and again the PE pipe to ensure that there is no damage that may have occurred as part of
the install process.
8. Complete the other side of the coupling by repeating Steps 2 through 7.
9. Test the fitting per Specification 3.18, Pressure Testing.
PROCEDURE FOR INSTALLING APPROVED COMPRESSION TYPE SERVICE HEAD ADAPTERS
(REFERENCE: ECN 2172 Rev D 9/07 0000-99-1045-00):
1. If installing on existing steel riser, cut upstream end (minimum 2 feet from the bend), de-burr, and
install a protective sleeve. Remove old service valve from top of riser, inspect, and clean the pipe
threads, as necessary.
2. If pre-building a new galvanized riser, determine proper length and location of the bend. Bend
and/or cut riser to the appropriate configuration. De-burr cut end and install a protective sleeve.
Refer to Specification 3.16, Services, Drawing A 34735.
3. Insert 1/2-inch CTS I.D. (5/8-inch O.D.) polyethylene pipe through the riser, leaving a 10 inch
minimum length of pipe extending above the riser.
4. Insert liner over the 5/8-inch O.D. pipe and slide down into the riser casing. (Top end riser liner is
optional - use if available with current supply of service head adapters).
5. Apply pipe joint compound to the riser threads. Do not over-apply.
6. Install the line shield nut on the riser casing with the compression end facing up, then tighten with a
wrench.
7. Slide the seal ring over the pipe and into the line shield nut.
8. Insert service pipe onto the adapter-coupling stiffener, applying pressure to the plastic pipe until it
bottoms out in the adapter coupling. Push entire assembly to the line shield nut.
9. Tighten adapter coupling until it bottoms out against the shoulder of the line shield nut.
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10. Install new service valve and tighten.
11. Purge the service line and then pressurize. Check the regulator for flow and lockup. Test per
Specification 3.18, Pressure Testing.
PROCEDURE FOR INSTALLING APPROVED SLIP-LOCK TYPE SERVICE HEAD ADAPTERS (i.e.,
"PERFECTION" TYPE):
1. Follow Steps 1 and 2 under procedures for compression type service head adapters, as
appropriate.
2. Inspect the gas riser casing for burrs and damaged threads. Deburr and rethread if necessary.
3. Disconnect the service head adapter fitting from the inlet device supplied (short section of pipe
nipple, threaded on one end). If the riser is already threaded, discard this short nipple. If riser is not
threaded, this nipple may be welded to end of riser to provide threaded end.
4. Push the PE service line through the threaded steel nipple and/or bushing or riser casing until it
extends 6 to 8 inches beyond the casing outlet.
5. Square cut the end of the PE service line and wipe clean with a dry cloth. Inspect to be sure that
there are no scratches, gouges, or surface defects in the last 4 inches of the service line. If
scratches or gouges are visible, cut off the defective area, and repeat steps 3 and 4.
6. Chamfer the square cut end of the PE service line with a chamfering tool recommended or supplied
by the manufacturer.
7. Determine the stab depth required by checking the length of hex on the fitting body (length of hex
equals the stab depth). Mark the stab depth on the PE service line with a soft marking instrument
(grease pencil, etc.).
8. Stab the service head adapter fitting onto the PE service line until the service line bottoms out in the
fitting. The mark on the PE service line should be within 1/8-inch from the end of the fitting. Note:
Do not twist the fitting or pipe until fully stabbed.
9. Reconnect the service head adapter fitting and the inlet device. After applying pipe joint compound
to the riser threads, place the assembly back on the riser threads and tighten.
10. Install the service valve and tighten.
11. Purge the service line and pressurize. Check regulator for flow and lockup. Leak test per
Specification 3.18, Pressure Testing.
JOINING OF PIPE REV. NO. 21
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PROCEDURE FOR INSTALLING APPROVED WELD-ON 1201 AND 1302 STYLE STEEL PUNCH
TEES WITH COMPRESSION TYPE OUTLET CONNECTION FOR PE PIPE
Note: Aspects of this procedure are related to welding the steel service tee onto a steel main. These
steps are described in this procedure; however, welding shall be completed using an approved weld
procedure in accordance with Specification 3.22, Joining of Pipe—Steel. Services shall be installed per
Specification 3.16, Pipe Installation —Services.
1. Before installation of the service tee, confirm the punch is rated for the steel pipe to be tapped.
a. 3/8-inch punches are rated for tapping pipe with a 0.280-inch maximum wall thickness and a
70,000-psi maximum yield strength.
b. 1/4-inch, 1/2-inch, 3/4-inch, and 1-inch punches are rated for tapping pipe with a 0.250-inch
maximum wall thickness and 65,000 psi maximum yield strength
2. Verify the compression fitting on the outlet of the tee is the correct size for the PE pipe being
connected. Verify the SDR of the PE pipe matches the SDR stamped on the end of the stiffener.
3. Remove the O-ring cap, the punch, outlet seal ring, and compression nut from the service tee and
place in the plastic bag in which the tee was shipped. Do not remove the splatter shield from the
inlet.
4. Remove the coating on the mainline and thoroughly clean off any residual rust, dirt, etc....in the
area where the service tee is to be welded.
5. Weld the service tee onto the main. Note: the service tee must be cool to the touch before re-
inserting the punch (removed during Step 3).
6. Once the service tee is installed on the main, the PE service can be connected to the tee one of
two ways as follows:
a. Install the compression nut and seal ring on the outlet of the tee. Do not tighten the
compression nut.
-Or-
b. Slide the compression nut and seal ring onto the PE pipe.
7. Cut the end of the PE service pipe square, deburr inside and outside, and clean thoroughly to
assure there is no dirt, grease, oil etc. on the pipe in the assembly area.
8. Mark the appropriate stab length on the pipe.
a. For 3/8-inch OD, 5/8-inch OD, 7/8-inch OD and 1/2-inch IPS: Stab length = 1-11/16"
b. For 3/4-inch IPS, 1-inch IPS, 1-1/4-inch IPS, and 1-1/8-inch OD: Stab length = 1-7/8-inch
9. Insert the PE pipe into the tee until it bottoms in the fitting. Note: Prior to completing the service line
connection be sure to install a stress-relieving sleeve on the service line that will help protect the
rigid steel to PE transition per the requirements in Spec 2.13—"Joining of Plastic Pipeline
Components". Also, refer to Drawing A-37169 in Spec 3.16 for an example of a sleeve installation
on a steel tee with PE transition.
10. Tighten the compression nut until it bottoms on the shoulder of the tee (metal to metal). The stab
length line should be no more than 3/16 of an inch from the face of the compression nut. If the stab
length line is more than 3/16 of an inch from the face of the compression nut, disassemble the joint
and repeat Steps 6 through 10.
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11. Prior to tapping the tee fitting to allow gas to the service line, pressure test the tee and new outlet
piping as applicable per Specification 3.18, Pressure Testing.
12. Insert the punch in the service tee and turn clockwise by hand to avoid cross threading. Apply
proper lubricant to the punch threads and tip prior to tapping. Acceptable lubricants include thread
cutting oil, tapping fluid, or tapping grease.
13. Use a standard hex wrench (see note below) or a ratchet wrench with Continental drive key and
bushing to make the tap. It is important to ensure retention of the coupon by running the punch all
the way down until the punch seats on the main. Continental drive key and bushing information:
a. 1/2-inch body tees use 23-3691-00 Hex Drive Key, Bushing, and Socket Adapter
b. 3/4-inch body tees use 23-3692-00 Hex Drive Key, Bushing, and Socket Adapter
Note: The manufacturer has approved the use of a standard hex wrench or the Continental drive
key and bushing.
14. To allow gas to the service line, back the punch valve up until it protrudes 2 to 3 threads above the
top of the tee.
15. Insert the hex drive of the O-ring plug cap into the socket of the punch valve and run the unit down
until it is leak tight. Take care as the threads of the O-ring plug engage the threads of the tee body
to prevent cross threading.
16. As a best practice, consider creating notes and/or marking the tee (e.g., tape, marker, etc.)to keep
track of whether the tee has been tapped out.
PROCEDURE FOR INSTALLING APPROVED WELD-ON STYLE 1201 AND 1302 STYLE STEEL
PUNCH TEES WITH SPIGOT AND SLEEVE TYPE OUTLET CONNECTION FOR PE PIPE
Note: Aspects of this procedure are related to welding the steel service tee onto a steel main. These
steps are described in this Specification; however, welding shall be completed using an approved weld
procedure in accordance with Specification 3.22, Joining of Pipe—Steel. Services shall be installed per
Specification 3.16, Pipe Installation —Services.
1. To install the steel service tee, follow steps 1-5 in the separate procedure listed above in this
specification (Procedure for Installing Approved Weld-On 1201 and 1302 Style Steel Punch Tees
with Compression Type Outlet Connection for PE Pipe).
2. Once the service tee is connected to the main install the outlet pipe as described in the separate
procedure listed in this specification (use the procedure for the QRP-100 ratchet press tool for 1/2-
inch CTS and 3/4-inch IPS fittings or the procedure for the LHP-200 hydraulic press tool for 1-1/4-
inch IPS and 2-inch IPS fittings). Note: Prior to completing the service line connection be sure to
install a stress-relieving sleeve on the service line that will help protect the rigid steel to PE
transition per the requirements in Spec. 2.13—"Joining of Plastic Pipeline Components". Also, refer
to Drawing A-37169 in Spec. 3.16 for an example of a sleeve installation on a steel tee with PE
transition.
3. Prior to tapping the tee fitting to allow gas to the service line, pressure test the tee and new outlet
piping as applicable per Specification 3.18, Pressure Testing.
4. Once the service is connected to the outlet of the service tee, tap the tee to complete the service
following steps 11-15 in the separate procedure listed above in this specification (Procedure for
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Installing Approved Weld-On 1201 and 1302 Style Steel Punch Tees with Compression Type Outlet
Connection for PE Pipe)
5. As a best practice, consider creating notes and/or marking the tee (e.g., tape, marker, etc.)to keep
track of whether the tee has been tapped out.
PROCEDURE FOR INSTALLING APPROVED PE COMPRESSION X WELD END ADAPTER
COUPLINGS (SOMETIMES REFERRED TO AS THE "BUTTON" FITTING) (REFERENCE: ECN 2625
REV "D" 08/29/14):
Note: Step 2 of this procedure is related to welding the coupling. Welding shall be completed using an
approved weld procedure in accordance with Specification 3.22, Joining of Pipe—Steel.
1. Before welding the adapter coupling, remove the seal ring and compression nut from the coupling
body and place in the plastic bag in which the coupling was shipped.
2. Weld coupling body following an approved welding procedure.
3. Allow welded coupling to cool to ambient temperature before installing PE pipe.
4. After the weld has cooled to ambient temperature, the PE service can be connected to the fitting
one of two ways as follows:
a. Install the seal ring and compression nut. Do not tighten the compression nut.
-Or-
b. Slide the compression nut and seal ring onto the PE pipe.
5. Verify that the coupling is the correct size for the polyethylene (PE) pipe. Verify the SDR (or wall
thickness)of the pipe matches the SDR (or wall thickness)stamped on the end of the stiffener.
6. Cut PE pipe ends square, deburr inside and outside, clean thoroughly to assure there is no dirt,
grease, oil, etc. on assembly area of pipe.
7. Mark the appropriate stab length on the pipe.
a. For 3/8" OD, 5/8" OD, 7/8" OD and IPS: Stab length = 1-11/16"
b. For 1/" IPS, 1" IPS, 1-1/4" IPS, and 1-1/8" OD: Stab length = 1-7/8"
8. Insert the PE pipe until it bottoms in the fitting. Note: Prior to completing the service line connection
be sure to install a stress-relieving sleeve on the service line that will help protect the rigid steel to
PE transition per the requirements in Spec. 2.13—"Joining of Plastic Pipeline Components". Also,
refer to Drawing A-37169 in Spec. 3.16 for an example of a sleeve installation on a steel tee with
PE transition.
9. Tighten compression nut until it shoulders against the outlet. The line marked for stab length should
be no more than 3/16 of an inch from face of nut. If it is not, disassemble the joint and reinstall
following steps 5 through 9.
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PROCEDURE FOR INSTALLING APPROVED BOLT-ON TYPE MECHANICAL TEES WITH SPIGOT
AND SLEEVE TYPE OUTLET CONNECTION (REFERENCE: LIT-LCTTINST Rev. 1E):
Note: Refer to the Manufacturer's Operating Instructions Manual and the manufacturer provided
instruction document packaged with each fitting for further details and diagrams to supplement the
following procedure.
1. Thoroughly clean the entire pipe surface where the tapping tee will be installed. Do not place the
saddle O-rings over gouges or scratches on the pipe surface. If a scratched surface is unavoidable,
refer to the procedure below for repairing scratches prior to tee installation.
2. Remove the tapping tee from the bag. Take care not to allow dirt to contaminate the O-rings or to
enter the cutter cavity. Position the top half of the tapping tee to the main and align the tee's outlet
spigot in a horizontal position and press the tee onto the pipe surface. Align the bottom half of the
tee with the bolt holes in the top half. Press the halves together evenly leaving an equal gap
between the halves on both sides. Spin the four flange nuts onto the bolt studs until hand tight (nuts
should spin freely). Note: It is preferred the service tee be installed on the top of the main with the
spigot outlet in the horizontal position, however it is acceptable to rotate the tee as much as 90-
degrees up or down from horizontal.
3. Tighten the nuts using a nut driver. Tighten the nuts one turn at a time in a crisscross pattern until
the corners of the top and bottom flanges are brought together(approximately 60 to 95 in-lbs). Do
not over tighten.
4. Install the outlet pipe as described in the separate procedure listed in this specification (use the
procedure for the QRP-100 ratchet press tool for 1/2-inch CTS and 3/4-inch IPS fittings or the
procedure for the LHP-200 hydraulic press tool for 1-1/4-inch IPS and 2-inch IPS fittings).
5. Pressure test the tee and new outlet piping as applicable per Specification 3.18, Pressure Testing.
6. Remove the tapping tee cap. Be careful to keep dirt out of the cap and cutter area. Insert a 3/8-inch
Lyall manufactured Lyco hex drive tool into the cutter and advance the cutter down until contact has
been made with the cutter stop. Do not continue to advance the cutter once contact has been made
with the stop. Unscrew the cutter until the top of the cutter is approximately 1/4 inch below the rim
of the tapping tee top.
7. Inspect the cap for cleanliness and seating of the O-ring in the groove. Inspect the tapping tee top
rim and threads for cleanliness and cutter position. Re-install the cap and tighten by hand until the
cap contacts the stop. Do not use a wrench to tighten the cap.
8. As a best practice, consider creating notes and/or marking the tee (e.g., tape, marker, etc.)to keep
track of whether the tee has been tapped out.
9. Pressurize and soap test tapping tee cap, saddle, and outlet connections to assure proper assembly.
10. During backfill, ensure that the earth is fully compacted under the tapping tee, its outlet connection,
and the adjacent PE pipe.
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PROCEDURE FOR REMOVING SCRATCHES FROM PE PIPE PRIOR TO THE INSTALLATION OF A
MECHANICAL TAPPING TEE:
This procedure shall be used when:
1. The surface of the PE pipe where the tee will be installed contains scratches that can cause an
inadequate sealing surface between the pipe and the tee, and
2. Installing the tee in an alternative non-scratched location is not practical.
This procedure shall not be used if the depth of any scratch exceeds 10 percent of the wall thickness of
the pipe. If a scratch deeper than 10 percent of the wall thickness of the pipe is present, either replace the
section with new pipe or repair the pipe using an approved repair fitting, per Specification 3.33, Repair of
Plastic (Polyethylene) Pipe.
Scratch Repair Procedure:
1. Thoroughly clean the entire pipe surface where the mechanical fitting will be installed. An alcohol
wipe is the preferred method for cleaning the pipe surface.
2. Mark the edges of proposed location of the mechanical fitting with a marker. Extend sanding of the
surface a minimum of 1/2" beyond the edges of the fitting to ensure the entire area where the fitting
contacts the pipe is repaired and to allow for proper visual inspection of the repair.
3. Use 80-grit emery cloth and sand the surface of the pipe evenly where the fitting will be installed until
most of the scratches are removed. If the scratch depth is such that the use of 80 grit emery cloth
will cause further damage to the pipe surface, this step may be skipped and may proceed to Step 4.
Do not remove more than 10 percent of the wall thickness of the pipe. Do not use a scraper or
peeler to remove the scratches.
4. Use 180-grit emery cloth and sand the surface until no scratches remain.
5. Use 280-grit emery cloth and sand the surface once more to prepare the final surface.
6. Wipe the sanded surface clean with an alcohol wipe.
7. Continue with the Bolt-on Mechanical Tee procedure in this specification.
PROCEDURE FOR INSTALLING 1/2 INCH AND 3/4 INCH ABANDONMENT NUTS ON CONTINENTAL
STEEL TO PE SERVICE TEE (REFERENCE: ECN 2620 REV"E" 07/22/14):
1. Remove the service tee cap. Screw down the punch completely to shut off gas flow.
2. Remove the existing compression nut and seal ring and discard.
3. Cut the PE service line as close as possible to the end of the stiffener. Do not remove the remaining
pipe from the stiffener.
4. Assemble the abandonment nut with a new seal ring onto the outlet of the service tee. Tighten the
abandonment nut until it contacts the shoulder of the service tee.
5. Unscrew (back out)the service tee punch to allow gas pressure through the tee to the abandonment
nut and then reinstall the service tee cap. Soap test the joints for leaks.
JOINING OF PIPE REV. NO. 21
PLASTIC - MECHANICAL DATE 01/01/24
X-4, sr'a STANDARDS 10 OF 10
Utilities NATURAL GAS SPEC. 3.25

3.3 REPAIR OF DAMAGED PIPELINES
3.32 REPAIR OF STEEL PIPE
SCOPE:
To establish uniform procedures for determining appropriate repairs based on extent of damage to steel
distribution and transmission pipelines. Each segment of pipeline that becomes unsafe must be replaced,
repaired, or removed from service.
REGULATORY REQUIREMENTS:
§192.241, §192.243, §192.245, §192.309, §192.485, §192.627, §192.711, §192.712, §192.713,
§192.715, §192.717, §192.719, §192.723, §192.725
OTHER REFERENCES:
ASME B31G— Manual for Determining the Remaining Strength of Corroded Pipelines
CORRESPONDING STANDARDS:
Spec. 2.12, Pipe Design —Steel
Spec. 3.12, Pipe Installation—Steel Mains
Spec. 3.13, Pipe Installation— Plastic (Polyethylene) Mains
Spec. 3.17, Purging Pipelines
Spec. 3.18, Pressure Testing
Spec. 3.22, Joining of Pipe—Steel
Spec. 3.44, Exposed Pipe Evaluation
Spec. 4.12, Safety-Related Conditions
GESH Section 4— Emergency Procedures, "Temporary Control of Escaping Gas"
STEEL REPAIR REQUIREMENTS:
General
Each operator shall take necessary measures prior to beginning repairs to assure that the public and
Company personnel are protected from danger. Typically, repairs should be made as soon as practical,
depending on the degree of the hazard. Welding equipment shall not be used where an uncontrolled gas-
air mixture exists. Prior to welding, cutting, or other hot work in or around a structure or area including a
trench containing gas facilities, a thorough check shall be made with a combustible gas indicator(CGI).
CGI readings shall continuously be taken while repairs are being made until the area is made safe.
Welded repairs shall be performed by qualified welders using a qualified welding procedure.
Refer to Specification 3.22, Joining of Steel Pipe. Whenever a previously buried pipeline is exposed, an
Exposed Piping Inspection Report form (Form N-2534) shall be completed. Refer to Specification 3.44,
Exposed Pipe Evaluation, for more information. Only those methods of repair as detailed in this standard
are approved as permanent repairs to welded steel mains. When a repair cannot be made in
conformance with the conditions of this standard, the section of defective pipe shall be replaced with a
new piece of pipe. The most appropriate method of repair permitted shall be selected from the proper
"Steel Repair Selection Chart" based on operating pressure and stress (refer to the attached charts).
If a segment of steel pipeline is repaired by cutting out the damaged portion, the replacement pipe must
be tested to the pressures required for a new line installation and specific information about the pressure
test and pipe material shall be documented on the Pre-Tested Pipe Documentation form (N-2743). Refer
to Specification 3.18, Pressure Testing, "Recordkeeping."
REPAIR OF DAMAGED PIPELINES REV. NO. 21
REPAIR OF STEEL PIPE DATE 01/01/25
X-4,15y' a STANDARDS 1 OF 11
Utilities NATURAL GAS SPEC. 3.32

Regardless of which method of repair is used, exposed pipe must be cleaned and recoated with an
approved coating installed according to the manufacturer's instructions and per Specification 3.12, Pipe
Installation —Steel Mains.
Corrosion damage shall be measured by a device such as a pit gauge to determine the depth of pitting.
Whenever exposed, underground Dresser-style or other steel mechanical compression fittings shall be
cut out or canned (barreled). A Cathodic Protection Technician shall be contacted to verify that the fitting
is not being used as an isolation point. Cutting out or barreling may inadvertently create a problem
between two separated cathodic protection systems so additional steps may be necessary before
removing or barreling the fitting.
Monitoring of Pressure
Gas personnel performing work on pipelines and facilities that could result in loss of pressure or
overpressure to the system shall install accurate pressure gauges upstream and downstream of the work
site. The pressure gauges shall be continuously monitored as long as is necessary, so that personnel can
respond accordingly, if system pressures are greatly affected. (Note: CNG Trailers that are oftentimes
deployed to maintain system pressures for short periods of time do not require continuous monitoring.)
Additionally, there may be times when merely monitoring downstream pressure may not be sufficient to
prevent customer outages without further action. It may be necessary during warm days or periods of low
gas use to intentionally draw down the pressure of the downstream system and observe it to confirm the
existence of a looped system prior to altering the system or leaving the area. Consult Gas Engineering for
recommendations prior to altering any system's pressure. It may also be necessary to install a temporary
bypass if a system is not looped or if the pipeline work could result in loss of pressure to the system.
Refer to Specification 3.12, Pipe Installation—Steel Mains for temporary bypass details and
requirements.
Any loss of pressure that may have extinguished pilots or that may have affected the normal operation of
the customer's gas equipment shall be treated as an outage and the procedures followed as outlined in
the GESH, Section 5, Emergency Shutdown and Restoration of Service.
Service Lines
When a service line has been disconnected for repair, refer to"Reinstating Service" in Specification 3.18,
Pressure Testing.
Grinding
When grinding to eliminate a defect, care must be used to remove the entire defect. A 60-grit sanding
wheel should be used. Such grinding shall be smoothly contoured to the pipe to eliminate all possible
points of stress concentration. The wall thickness shall not be ground to less than what is required for the
design pressure of the pipeline.
Arc burns on steel pipe to be operated at a pressure that produces a hoop stress of 40 percent or more of
SMYS must have a remaining wall thickness that is equal to either the minimum required by the
tolerances in the specification to which the pipe was manufactured, or the nominal wall thickness required
for the design pressure of the pipeline.
Grinding and Fill Welding
When grinding and fill welding, the repair area must be ground clean. The fill weld metal shall penetrate
the base material. The surface of the finished repair weld shall be ground smooth to the contour of the
pipe on lines operating over 100 psig. Arc welding is required for all repairs.
REPAIR OF DAMAGED PIPELINES REV. NO. 21
REPAIR OF STEEL PIPE DATE 01/01/25
X-4,15y' a STANDARDS 2 OF 11
Utilities NATURAL GAS SPEC. 3.32

Patching
Patches shall have a wall thickness greater than or equal to the pipe they are being installed on, have
rounded corners, and be designed to operate at less than 20 percent SMYS at the pipeline MAOP.
Contact Gas Engineering for assistance determining the proper patch specifications.
Welded patches may not be used on transmission pipelines in accordance with 192.711(c).
Sleeving
Sleeve design and testing shall be similar to patch design but must be full encirclement and should
feature a backing strip. Sleeve length should extend a minimum of 6 inches on each end of defect. Refer
to the Specification 3.22, Joining of Steel Pipe, Appendix A, for specific weld procedures for sleeve
installation.
Mueller Save-A-Valve Nipple or Equivalent
A Mueller Save-A-Valve nipple or equivalent fitting may be used to repair an individual corrosion pit
(either leaking or non-leaking)where the diameter of the pit at the surface of the pipe is less than the
inside diameter of the nipple. The weld shall be visually inspected. Refer to the "Steel Repair Selection
Charts" at the end of this specification for MAOP and operating stress limitations when using the Mueller
Save-A-Valve or equivalent type fittings.
Canning (Barreling)
Gas main repair cans may be used for repairs on pipelines with a design pressure which produces a hoop
stress of less than 20 percent SMYS. The can shall be designed and fabricated using approved pipe and
fittings (use of plate shall not be allowed) and pressure tested to 1.5 times the MAOP. Canning shall not
be used on pipelines operating at pressures greater than 60 psig without concurrence of Gas
Engineering. Canning repairs on systems operating above 60 psig shall be designed by Gas Engineering.
Tapping and Plugging Procedures
A copy of the manufacturer's detailed tapping and plugging procedures for the type(s) of equipment
utilized in each construction area must be kept at locations where tapping and plugging activities are
conducted. Both the tapping and plugging procedures should be reviewed periodically to ensure that
responsible personnel are familiar with operating and maintenance of tapping and line stopping
equipment. Additionally, these procedures shall be reviewed as part of an equipment check and tailboard
in the field prior to tapping. Only qualified individuals shall perform tapping and plugging operations
unless an individual is being observed on a one-to-one basis. (Refer to Specification 3.12, Pipe
Installation - Plastic, "Pipe Coupon Retention Procedures,"for further guidance on retention of pipe
coupons for transmission and high pressure mains.)
Replace Segment of Pipe
Remove the section of pipe containing the defect from service and purge section, as necessary. Remove
cylindrical barrel section of pipe containing defect by making two circumferential cuts. Replacement pipe
shall be of equal or better material based on the system design pressure and design requirements of
Specification 2.12, Pipe Design-Steel. Pipe used to replace a segment of pipeline must be pressure
tested to the requirements of new main and to meet the MAOP of the pipeline system being repaired.
Refer to Specification 3.18, Pressure Testing.
REPAIR OF DAMAGED PIPELINES REV. NO. 21
REPAIR OF STEEL PIPE DATE 01/01/25
X-4,15y' a STANDARDS 3 OF 11
Utilities NATURAL GAS SPEC. 3.32

Pre-Tested Steel Pipe
When making a repair as a result of third-party damage or material failure and it is not possible or
practical to test the section of pipe being replaced, pre-tested pipe shall be used. A Pre-Tested Pipe
Documentation form (N-2743)shall be filled out and kept at the local office for all pre-tested pipe.
Once the pipe is installed, a copy of the Pre-Tested Pipe Documentation form must be kept for the life of
facility with the project file (not at the warehouse with the uninstalled pipe records). If pre-tested steel pipe
is used to make a repair on high pressure facilities, then a copy of the Pre-Tested Pipe Documentation
form and pressure test chart must be sent to Gas Engineering to include in the project file and system
MAOP records. The tested pipe shall be segregated from the rest of the pipe stock and identified as pre-
tested pipe. The pipe should be periodically inspected and remarked as necessary to indicate its status.
Refer to Specifications 3.12 and 3.13 for further guidance on Storage and Handling of pipe and
Specification 3.18 regarding pre-installation testing.
Dents(Pipe Distortion)
Distortion or denting may be defined as a depression, which produces a gross disturbance in the
curvature of the pipe wall (as opposed to a scratch or gouge, which reduces the pipe wall thickness). The
depth of a dent shall be measured as the gap between the lowest point of the dent and the prolongation
of the original contour of the pipe in any direction. Dents on a longitudinal or circumferential weld
operating at less than 20 percent SMYS can be treated the same as a dent, which does not affect a weld.
Dents in a pipeline with a MAOP equal to 20 percent SMYS, or more, which affect the longitudinal or
circumferential weld shall be removed or repaired by a method that reliable engineering tests and
analysis show can permanently restore the serviceability of the pipe. A dent with mechanical damage is
more severe than a dent or mechanical damage alone.
Repair Clamps and Sleeves
Percent distortion shall be defined as the ratio of the depth of the dent to the actual diameter of the pipe
times 100. Distortion exceeding the limitations in the "Steel Repair Selection Charts" shall be removed.
Repair clamps shall only be used when it is not practical to use the repair methodologies as instructed in
the "Steel Repair Selection Charts". Only approved repair clamps and sleeves may be used (refer to the
Foreword of this manual for what is considered "approved"). Unless detailed in the following specifications
the manufacturer's installation procedures shall be followed. Repair clamps should be temporary unless
they are welded in place and meet the required ANSI ratings of the main. An anode shall be cad welded
to all permanent clamps and the clamps coated in mastic. Contact the Cathodic Protection department to
determine proper size of anode.
Transmission Lines
Repairs to transmission pipelines should follow Section 6 (Remediation of Anomalous Conditions) of the
Transmission Integrity Management Plan (TIMP). None of Avista's transmission pipelines currently have
the capability to find anomalies using `smart pig' In-Line-Inspection (ILI)tooling, so discovery of an
anomalous condition would require exposure of the pipe and visual examination. As a best practice, any
repairs should be made immediately or within the one-year timeframe as if it were in an HCA.
Each segment of transmission pipe with general corrosion and with a remaining wall thickness less than
that required for the MAOP of the pipeline must be replaced. Corrosion pitting so closely grouped as to
affect the overall strength of the pipe is considered general corrosion. A segment of transmission pipe
with localized corrosion pitting to a degree where leakage might result shall be replaced or repaired, or
the operating pressure must be reduced commensurate with the strength of the pipe, based on actual
remaining wall thickness, and calculated and documented in accordance with TIMP Evaluation and
Remediation Practice (E&RP)#13—Analysis of Predicted Failure Pressure.
REPAIR OF DAMAGED PIPELINES REV. NO. 21
REPAIR OF STEEL PIPE DATE 01/01/25
X-41.5y' a STANDARDS 4 OF 11
Utilities NATURAL GAS SPEC. 3.32

All repair methods shall be determined by Gas Engineering and must be performed using pipe and
material properties that are documented in traceable, verifiable, and complete (TVC) records. If
documented data required for any analysis, including predicted failure pressure for determining MAOP, is
not available, it must be obtained in accordance with TIMP Section 14.3— Verification of Pipeline Material
Properties and Attributes.
The operating pressure must be at a safe level during repair operations. Consideration should be given to
lowering the operating pressure to less than 80% of the setpoint when the anomalous condition was
discovered, until the repair can be completed, or in accordance with TIMP Section 6.7.2.
Testing of repairs made by welding shall be visually inspected to ensure that the welding is performed in
accordance with the welding procedure and that the acceptability of a nondestructive weld is in
accordance with Section 9 of API 1104 per§192.241. Under the following conditions, visual examinations
of the welds may be substituted for radiographic examinations:
1. The pipe has a nominal diameter of less than 6 inches regardless of stress level; or
2. The pipeline operates at a pressure of less than 40 percent of SMYS and the welds are so limited
that radiographic testing is impractical.
A waiver from Gas Engineering should be obtained to avoid NDT examination in either case.
Leak Repair and Residual Gas Checks
After a leak is repaired, it shall be checked for residual gas while the excavation is still open by a person
qualified in Avista Side Leak Investigation. The perimeter of the leak area shall be bar holed and checked
with a combustible gas indicator in percent gas mode to determine if repairs were adequate and if there is
migration from a secondary leak. A minimum of four bar hole readings shall be taken at equally spaced
points at the perimeter of the excavation or from within the bell hole prior to backfill to fulfill this
requirement.
If readings indicate the presence of gas, the perimeter shall be expanded, and additional bar hole
readings taken until the extent of the leak is found and documented down to less than 0.05 percent gas in
air. If the discovery of gas is determined to be a second leak, a new order shall be established by
contacting the Avista Call Center. Bar hole locations shall be mapped as appropriate. Repairs to
damaged service lines require additional leak survey actions. Refer to "Service Line Leak Survey" in
Specification 5.11, Leak Survey for more information.
Whenever a pipeline is exposed, whether steel or PE, an Exposed Piping Inspection Report form (Form
N-2534) shall be completed. Further detail regarding the use of the Exposed Piping Inspection Report
form is detailed in Specification 3.44, Exposed Pipe Evaluation.
Pressure test information is required if a section of pipe is replaced. It can either be tested in the field or
by using pretested pipe. Refer to Specification 3.18, Pressure Testing.
Recordkeeping
Records and maps of repairs performed shall be retained for the life of the facilities.
Specific Repair Methods
The following three Steel Repair Selection Charts detail the repair methodology to be used for damaged
steel pipelines.
REPAIR OF DAMAGED PIPELINES REV. NO. 21
REPAIR OF STEEL PIPE DATE 01/01/25
X-4,15y' a STANDARDS 5 OF 11
Utilities NATURAL GAS SPEC. 3.32

STEEL REPAIR SELECTION CHART FOR PIPELINES WITH AN MAOP OF 100 PSIG OR LESS
TYPE OF DEFECT
• • �� ••
EXTENT OF DEFECT PERMISSIBLE METHODS OF REPAIR LIMITATIONS ON METHODS
A.DENT LESS THAN 10%DISTORTION 1.NO REPAIR REQUIRED NO NOTCHES,SCRATCHES,GOUGES OR GROOVES IN
DENT.
B.DENT-MORE THAN 10% 1.SLEEVING OR CANNING DENT MUST NOT PREVENT PROPER FIT UP.
DISTORTION(1/2"FOR 4-1/2"O.D.&
SMALLER) 2.REPLACE SEGMENT OF PIPE ENTIRE SECTION AFFECTED MUST BE REMOVED.
C.NOTCH,SCRATCH,GOUGE, 1.GRINDING LESS THAN 10%DISTORTION OR DENT(1/2"FOR 4-1/2"
GROOVE-LESS THAN 50%OF PIPE O.D.&SMALLER). PIPE WALL NOT TO BE REDUCED TO
WALL THICKNESS LESS THAN 50%OF ORIGINAL NOMINAL WALL
THICKNESS.
D.NOTCH,SCRATCH,GOUGE, 1.GRINDING AND WELDING LESS THAN 10%DISTORTION OR DENT(1/2"FOR 4-1/2"
GROOVE-MORE THAN 50 PERCENT O.D.&SMALLER. REPAIR NOT TO EXCEED 1/4
OF PIPE WALL THICKNESS CIRCUMFERENCE OF PIPE NOR 5 SQUARE INCHES.
NOT MORE THAN ONE REPAIR PER FOOT OF PIPE
LENGTH.
2.PATCHING LESS THAN 10%DISTORTION OR DENT(1/2"FOR 4-1/2"
O.D.&SMALLER. PATCH NOT TO EXCEED 1/2 PIPE
CIRCUMFERENCE. LENGTH NOT OVER 10 PIPE
DIAMETERS ON PIPE OVER 8-5/8 O.D. A MINIMUM OF 3"
CLEARANCE BETWEEN PATCHES. PATCH SHALL HAVE
ROUNDED CORNERS,WALL THICKNESS SHALL MEET
OR EXCEED CARRIER PIPE,AND OPERATE AT LESS
THAN 20%SMYS AT PIPELINE MAOP.
3.SLEEVING OR CANNING DENT MUST NOT PREVENT PROPER FIT UP.
4.REPLACE SEGMENT OF PIPE ENTIRE SECTION AFFECTED MUST BE REMOVED.
E.HOLE 1.PATCHING PATCH NOT TO EXCEED 1/2 PIPE CIRCUMFERENCE.
LENGTH NOT OVER 10 PIPE DIAMETERS ON PIPE OVER
8-5/8 O.D. A MINIMUM OF 3"CLEARANCE BETWEEN
PATCHES. PATCH SHALL HAVE ROUNDED CORNERS,
WALL THICKNESS SHALL MEET OR EXCEED CARRIER
PIPE,AND OPERATE AT LESS THAN 20%SMYS AT
PIPELINE MAOP.
2.SLEEVING OR CANNING MATERIAL USED TO FABRICATE SLEEVE OR CAN MUST
NOT EXCEED 20%SMYS AT THE PIPELINE MAOP.
3.LEAK CLAMP PRESSURE RATING OF CLAMP MUST MEET OR
EXCEED THE PIPELINE MAOP.
4.REPLACE SEGMENT OF PIPE ENTIRE SECTION AFFECTED MUST BE REMOVED.
REPAIR OF DAMAGED PIPELINES REV. NO. 21
REPAIR OF STEEL PIPE DATE 01/01/25
x rv#ST,aa STANDARDS 6 OF 11
Utilities NATURAL GAS SPEC. 3.32

TYPE OF DEFECT
PERMISSIBLE METHODS OF
EXTENT OF DEFECT REPAIR LIMITATIONS ON METHODS
A.DEPTH LESS THAN 50%OF PIPE WALL 1.NO REPAIR REQUIRED CLEAN AND RECOAT BURIED PIPE OR
THICKNESS REPAINT ABOVE GRADE PIPE.
B.DEPTH OVER 50%OF PIPE WALL THICKNESS BUT 1.GRINDING AND WELDING REPAIR NOT TO EXCEED'%
LESS THAN 80%-NO LEAKAGE. CIRCUMFERENCE OF PIPE NOR 5
SQUARE INCHES.NOT MORE THAN
ONE REPAIR PER FOOT OF PIPE
LENGTH.
2.PATCHING PATCH NOT TO EXCEED 1/2 PIPE
CIRCUMFERENCE. LENGTH NOT
OVER 10 PIPE DIAMETERS ON PIPE
OVER 8-5/8 O.D. A MINIMUM OF 3"
CLEARANCE BETWEEN PATCHES.
PATCH SHALL HAVE ROUNDED
CORNERS,WALL THICKNESS SHALL
MEET OR EXCEED CARRIER PIPE,
AND OPERATE AT LESS THAN 20%
SMYS AT PIPELINE MAOP.
3.SLEEVING OR CANNING NO LIMITATIONS.
4.MUELLER SAVE-A-VALVE NIPPLE 2"MAXIMUM SIZE NIPPLE.
(OR EQUIVALENT FITTING)
5.LEAK CLAMP
C. DEPTH 80%OF PIPE WALL THICKNESS OR 1.PATCHING SAME AS 2.13.2.
MORE-INCLUDING LEAKING CORROSION PITS 2.SLEEVING OR CANNING NO LIMITATIONS.
3.MUELLER SAVE-A-VALVE NIPPLE 2"MAXIMUM SIZE NIPPLE.
(OR EQUIVALENT FITTING)
4.LEAK CLAMP
5.REPLACE SEGMENT OF PIPE ENTIRE SECTION AFFECTED SHOULD
BE REMOVED.
D.EXTENT OF THE CORROSION IS SUCH THAT THE 1.REPLACE SEGMENT OF PIPE ENTIRE SECTION AFFECTED SHOULD
REPAIRS IN A,B&C ARE NOT FEASIBLE. BE REMOVED.
TYPE OF DEFECT
PERMISSIBLE METHODS OF
EXTENT OF DEFECT REPAIR LIMITATIONS ON METHODS
7AA 1.PATCHING SAME AS 2.6.2.EXISTING FACILITIES ONLY.
2.SLEEVING OR CANNING EXISTING FACILITIES ONLY
3.MUELLER SAVE-A-VALVE 2"MAXIMUM SIZE NIPPLE,FOR EXISTING FACILITIES
NIPPLE ONLY.
(OR EQUIVALENT FITTING)
TYPE OF DEFECT
PERMISSIBLE METHODS OF
EXTENT OF DEFECT REPAIR LIMITATIONS ON METHODS
A. ANY LONGITUDINAL WELD CRACK 1.REPLACE SEGMENT OF ENTIRE SECTION AFFECTED MUST BE REMOVED. IF
GREATER THAN 2"LONG,A BRANCH OR PIPE NOT FEASIBLE TO TAKE MAIN OUT OF SERVICE,
CIRCUMFERENTIAL WELD CRACK THAT IS INSTALL SLEEVE.
MORE THAN 8%OF WELD LENGTH,OR A
CRACK THAT PENETRATES EITHER THE
ROOT OR SECOND BEAD
B.ANY LOGINTUDINAL WELD CRACK LESS 1.GRINDING OR FILL IF CRACK PENETRATES EITHER THE ROOT OR THE
THAN OR EQUAL TO 2"LONG,A BRANCH WELDING SECOND BEAD,REPLACE PIPE SEGMENT
OR CIRCUMFERENTIAL WELD CRACK
LESS THAN OR EQUAL TO 8%OF WELD 2.PATCHING,SLEEVING OR LIMITATIONS FOR PATCHES SAME AS 2.6.2.
LENGTH,OR OTHER DEFECTS CANNING
3.REPLACE SEGMENT OF ENTIRE SECTION AFFECTED MUST BE REMOVED.
PIPE
REPAIR OF DAMAGED PIPELINES REV. NO. 21
REPAIR OF STEEL PIPE DATE 01/01/25
��r�sra STANDARDS 7 OF 11
Utilities NATURAL GAS SPEC. 3.32

TYPE OF DEFECT
:•� • •-
PERMISSIBLE METHODS OF
EXTENT OF DEFECT REPAIR LIMITATIONS ON METHODS
A.ALL 1.CANNING EXISTING FACILITIES ONLY.
REPLACE FITTING OR CLAMP NO LIMITATIONS.
STEEL REPAIR SELECTION CHART FOR PIPELINES WITH AN MAOP GREATER THAN 100 PSIG
BUT LESS THAN 500 PSIG, AND AN OPERATING STRESS LESS THAN 20 PERCENT OF SMYS AT
THE PIPELINE MAOP
TYPE OF DEFECT
-1. MECHANICAL■AMAGE:NOTCHES,SCRATCHES,GOUGES, -•• HOLES
PERMISSIBLE METHODS OF
EXTENT OF DEFECT REPAIR LIMITATIONS ON METHODS
A.DENT-LESS THAN 5%DISTORTION 1.NO REPAIR REQUIRED NO NOTCHES,SCRATCHES,GOUGES AND GROOVES
IN DENT.
B.DENT-MORE THAN 5%DISTORTION(3/8" 1.SLEEVING OR CANNING DENT MUST NOT PREVENT PROPER FIT UP.MATERIAL
FOR 6-5/8"O.D.&SMALLER) USED TO FABRICATE CANS MUST NOT EXCEED 20%
SMYS.
2.REPLACE SEGMENT OF ENTIRE SECTION AFFECTED MUST BE REMOVED.
PIPE
C.NOTCH,SCRATCH,GOUGE,GROOVE- 1.GRINDING PIPE WALL NOT TO BE REDUCED TO LESS THAN 90%
LESS THAN 10%OF PIPE WALL OF NOMINAL PIPE WALL THICKNESS.DENT OR
THICKNESS DISTORTION LESS THAN 5%OF O.D.
D.NOTCH,SCRATCH,GOUGE,GROOVE 1.GRINDING AND WELDING DENT OF DISTORTION LESS THAN 5%OF O.D.(3/8"
DEPTH-MORE THAN 10%BUT LESS THAN FOR 6-5/8"O.D.AND SMALLER). REPAIR NOT TO
30%OF PIPE WALL THICKNESS EXCEED 1/4 OF PIPE CIRCUMFERENCE NOR 4 SQUARE
INCHES. NOT MORE THAN ONE REPAIR PER 5 PIPE
DIAMETERS OF LENGTH.
2.PATCHING DENT OR DISTORTION LESS THAN 5%OF O.D.(3/8"
FOR 6-5/8"O.D.AND SMALLER). PATCH NOT TO
EXCEED 1/2 PIPE CIRCUMFERENCE. LENGTH NOT
OVER 10 PIPE DIAMETERS ON PIPE OVER 8-5/8 O.D. A
MINIMUM OF 3"CLEARANCE BETWEEN PATCHES.
PATCH SHALL HAVE ROUNDED CORNERS,WALL
THICKNESS SHALL MEET OR EXCEED CARRIER PIPE,
AND OPERATE AT LESS THAN 20%SMYS AT PIPELINE
MAOP.
3.SLEEVING OR CANNING DENT MUST NOT PREVENT PROPER FIT UP. MATERIAL
USED TO FABRICATE CANS MUST NOT EXCEED 20
SMYS.
E.NOTCH,SCRATCH,GOUGE,GROOVE- 1.PATCHING PATCH NOT TO EXCEED 1/2 PIPE CIRCUMFERENCE.
DEPTH GREATER THAN 30%OF PIPE LENGTH NOT OVER 10 PIPE DIAMETERS ON PIPE OVER
WALL THICKNESS 8-5/8 O.D. A MINIMUM OF 3"CLEARANCE BETWEEN
PATCHES. PATCH SHALL HAVE ROUNDED CORNERS,
WALL THICKNESS SHALL MEET OR EXCEED CARRIER
PIPE,AND OPERATE AT LESS THAN 20%SMYS AT
PIPELINE MAOP.
2.SLEEVING OR CANNING DENT MUST NOT PREVENT PROPER FIT UP.MATERIAL
USED TO FABRICATE CANS MUST NOT EXCEED 20%
SMYS PERCENT.
3.REPLACE SEGMENT OF ENTIRE SECTION AFFECTED MUST BE REMOVED.
PIPE
F.HOLE 1.PATCHING PATCH NOT TO EXCEED 1/2 PIPE CIRCUMFERENCE.
LENGTH NOT OVER 10 PIPE DIAMETERS ON PIPE OVER
8-5/8 O.D. A MINIMUM OF 3"CLEARANCE BETWEEN
PATCHES. PATCH SHALL HAVE ROUNDED CORNERS,
WALL THICKNESS SHALL MEET OR EXCEED CARRIER
PIPE,AND OPERATE AT LESS THAN 20 PERCENT SMYS
AT PIPELINE MAOP.
2.SLEEVING OR CANNING MATERIAL USED TO FABRICATE SLEEVE OR CAN MUST
NOT EXCEED 20%SMYS AT THE PIPELINE MAOP.
3.LEAK CLAMP PRESSURE RATING OF CLAMP MUST MEET OR
EXCEED THE PIPELINE MAOP.
4.REPLACE SEGMENT OF ENTIRE SECTION AFFECTED MUST BE REMOVED.
PIPE
REPAIR OF DAMAGED PIPELINES REV. NO. 21
REPAIR OF STEEL PIPE DATE 01/01/25
��r�sra STANDARDS 8 OF 11
Utilities NATURAL GAS SPEC. 3.32

TYPE OF DEFECT
2. CORROSION DAMAGE,TO INCLUDE BOTH GENERAL CORROSION AND LOCALIZED CORROSION PITTING(AS MEASURED
WITH A PIT GAUGE)
PERMISSIBLE METHODS OF
EXTENT OF DEFECT REPAIR LIMITATIONS ON METHODS
A.DEPTH LESS THAN 20%OF PIPE WALL 1.NO REPAIR REQUIRED CLEAN AND RECOAT BURIED PIPE OR REPAINT ABOVE
THICKNESS GRADE PIPE.
B.DEPTH BETWEEN 20%AND 30%OF 1.GRINDING AND WELDING REPAIR NOT TO EXCEED%CIRCUMFERENCE OF PIPE
PIPE WALL THICKNESS NOR 4 SQUARE INCHES.NOT MORE THAN ONE REPAIR
PER 5 DIAMETERS OF LENGTH.
2.PATCHING SAME AS 1.E.1.
3.SLEEVING NO LIMITATIONS.
4.MUELLER SAVE-A-VALVE 2"MAXIMUM SIZE NIPPLE.
NIPPLE(OR EQUIVALENT
FITTING
5.LEAK CLAMP
C.DEPTH OVER 30%OF PIPE WALL 1.PATCHING SAME AS 1.E.1.
THICKNESS BUT LESS THAN 80%-NO LEAKAGE 2.SLEEVING NO LIMITATIONS.
3.MUELLER SAVE-A-VALVE 2"MAXIMUM SIZE NIPPLE.
NIPPLE(OR EQUIVALENT
FITTING
D.DEPTH 80%OF PIPE WALL THICKNESS 1.PATCHING SAME AS 1.E.1.
OR MORE-INCLUDING LEAKING CORROSION PITS 2,SLEEVING NO LIMITATIONS.
3.MUELLER SAVE-A-VALVE 2"MAXIMUM SIZE NIPPLE.
NIPPLE(OR EQUIVALENT
FITTING
4.REPLACE SEGMENT OF ENTIRE SECTION MUST BE REMOVED.
PIPE
E.EXTENT OF THE CORROSION IS SUCH 1.REPLACE SEGMENT OF ENTIRE SECTION AFFECTED SHOULD BE REMOVED.
THAT THE REPAIRS IN A,B,C&D ARE PIPE
NOT FEASIBLE
TYPE OF DEFECT
3. LEAKS IN WELD OR PIPE WELD SEAM
PERMISSIBLE METHODS OF
EXTENT OF DEFECT REPAIR LIMITATIONS ON METHODS
A.ALL 1.PATCHING SAME AS 1.E.1.EXISTING FACILITIES ONLY.
2.SLEEVING OR CANNING EXISTING FACILITIES ONLY.MATERIAL USED TO
FABRICATE CANS MUST NOT EXCEED 20%SMYS.
3.MUELLER SAVE-A-VALVE 2"MAXMIUM SIZE NIPPLE,FOR EXISTING FACILITIES
NIPPLE(OR EQUIVALENT ONLY.
FITTING)
TYPE OF DEFECT
NON-LEAKING4. OR DEFECTS D •- -
PERMISSIBLE METHODS OF
EXTENT OF DEFECT REPAIR LIMITATIONS ON METHODS
A. ANY LONGITUDINAL WELD CRACK 1.REPLACE SEGMENT OF ENTIRE SECTION AFFECTED MUST BE REMOVED.IF
GREATER THAN 2"LONG,A BRANCH OR PIPE NOT FEASIBLE TO TAKE MAIN OUT OF SERVICE,
CIRCUMFERENTIAL WELD CRACK THAT IS INSTALL SLEEVE.
MORE THAN 8%OF WELD LENGTH,OR A
CRACK THAT PENETRATES EITHER THE
ROOT OR SECOND BEAD
B. ANY LONGITUDINAL WELD CRACK 1.GRINDING AND FILL IF CRACK PENETRATES EITHER THE ROOT OR
LESS THAN OR EQUAL TO 2"LONG,A WELDING SECOND BEAD,REPLACE PIPE SEGMENT.
BRANCH OR CIRCUMFERENTIAL WELD
CRACK LESS THAN OR EQUAL TO 8%OF
WELD LENGTH,OR OTHER DEFECTS
2.PATCHING,SLEEVING OR LIMITATIONS FOR PATCHES SAME AS 1.E.1.MATERIAL
CANNING USED TO FABRICATE CANS MUST NOT EXCEED 20%
SMYS.
3.REPLACE SEGMENT OF ENTIRE SECTION AFFECTED MUST BE REMOVED.
PIPE
REPAIR OF DAMAGED PIPELINES REV. NO. 21
REPAIR OF STEEL PIPE DATE 01/01/25
Xvism a STANDARDS 9 OF 11
Utilities NATURAL GAS SPEC. 3.32

TYPE OF DEFECT
5. LEAKS IN BODY OF • IN CLAMPS
-
PERMISSIBLE METHODS OF
EXTENT OF DEFECT REPAIR LIMITATIONS ON METHODS
A. ALL 1.REPLACE FITTING OR NO LIMITATIONS.
CLAMP
2.CANNING EXISTING FACILITIES ONLY.MATERIAL USED TO
FABRICATE CANS MUST NOT EXCEED 20%SMYS.
STEEL REPAIR SELECTION CHART FOR DISTRIBUTION PIPELINES WITH AN MAOP OF 500 PSI
OR GREATER, REFER TO TRANSMISSION LINES SECTION ABOVE FOR TRANSMISSION
REPAIRS
TYPE OF DEFECT
D• NOTCHES, • GROOVES, •
PERMISSIBLE METHODS OF
EXTENT OF DEFECT REPAIR LIMITATIONS ON METHODS
A. DENT LESS THAN 2°%DISTORTION 1.NO REPAIR REQUIRED NO NOTCHES,SCRATCHES,GOUGES,AND GROOVES
IN DENT.NO WELDS AFFECTED BY DENT.
B.DENT MORE THAN 2%DISTORTION(1/4" 1.SLEEVING DENT MUST NOT PREVENT PROPER FIT UP.IF DENT
FOR O.D.LESS THAN 12.750") AFFECTS A WELD,REPAIR AS IN 1.13.2.
2.REPLACE SERGMENT OF ENTIRE SECTION AFFECTED MUST BE REMOVED.
PIPE
C.NOTCH,SCRATCH,GOUGE,GROOVE- 1.GRINDING PIPE WALL NOT TO BE REDUCED TO LESS THAN 90%
DEPTH LESS THAN 10%OF PIPE WALL OF NOMINAL WALL THICKNESS(90%ON WELDED PIPE
THICKNESS AND LESS THAN 8%OF PIPE 20"O.D.OR LARGER)DENT OR DISTORTION LESS
W.T.FOR WELDED PIPE 20"O.D.OR THAN 2%OF O.D.(1/4"FOR O.D.LESS THAN 12.750").
LARGER
D.NOTCH,SCRATCH,GOUGE,GROOVE- 1.SLEEVING OR CLOCK DENT OR DISTORTION MUST NOT PRVENT PROPER FIT
DEPTH 10%OR MORE OF PIPE WALL SPRING® UP.
THICKNESS.DESIGN PRESSURE LESS
THAN 40%SMYS.
E.NOTCH,SCRATCH,GOUGE,ARC BURN 1.REPLACE SEGMENT OF ENTIRE SECTION AFFECTED MUST BE REMOVED. IF
GROOVE-DEPTH 10%OR MORE OF PIPE PIPE NOT FEASIBLE TO TAKE MAIN OUT OF SERVICE,
WALL THICKNESS. DESIGN PRESSURE REPAIR WITH SLEEVE AS IN 1.6.1.%
40%SMYS OR MORE. (8%OR MORE FOR
WELDED PIPE 20"OR LARGER.
F.HOLE 1.SLEEVING MATERIAL USED TO FABRICATE SLEEVE MUST NOT
EXCEED 20%SMYS AT THE PIPELINE MAOP.
2.REPLACE SEGMENT OF ENTIRE SECTION AFFECTED MUST BE REMOVED.
PIPE
TYPE OF DEFECT
2. CORROSION DAMAGE,TO INCLUDE BOTH GENERAL CORROSION AND LOCALIZED CORROSION PITTING(AS MEASURED
WITH A PIT GAUGE)
PERMISSIBLE METHODS OF
EXTENT OF DEFECT REPAIR LIMITATIONS ON METHODS
A. DEPTH 10%OR LESS OF PIPE WALL 1.ENGINEERING TO ENGINEERING TO DETERMINE THE APPROPRIATE
THICKNESS. DETERMINE THE REMAINING REPAIR METHOD,IF ANY.
STRENGTH OF THE PIPE.
B.DEPTH OVER 10%OR LESS OF PIPE 1.PATCHING PIPE OF NOT MORE THAN 40,000 PSI SMYS. LENGTH
WALL THICKNESS BUT LESS THAN 80%- OR WIDTH OF PATCH NOT TO EXCEED 1/2 PIPE
NO LEAKAGE CIRCUMFERENCE. A MINIMUM OF 3"CLEARANCE
BETWEEN PATCHES.PATCH SHALL HAVE ROUNDED
CORNERS.
2.SLEEVING NO LIMITATIONS.
3.REPLACE SEGMENT OF ENTIRE SECTION AFFECTED MUST BE REMOVED.
PIPE
C.DEPTH 80%OF PIPE WALL THICKNESS 1.PATCHING SAME AS 2.B.1.
OR MORE-INCLUDING LEAKING CORROSION PITS 2,SLEEVING NO LIMITATIONS.
3.REPLACE SEGMENT OF ENTIRE SECTION AFFECTED MUST BE REMOVED.
PIPE
D.EXTENT OF THE CORROSION IS SUCH 1.REPLACE SEGMENT OF ENTIRE SECTION AFFECTED SHOULD BE REMOVED.
THAT THE REPAIRS IN A,B,&C ARE NOT PIPE
FEASIBLE
REPAIR OF DAMAGED PIPELINES REV. NO. 21
REPAIR OF STEEL PIPE DATE 01/01/25
Xvism a STANDARDS 10 OF 11
Utilities NATURAL GAS SPEC. 3.32

TYPE OF DEFECT
PERMISSIBLE METHODS OF
EXTENT OF DEFECT REPAIR LIMITATIONS ON METHODS
A. ALL 1.REPLACE SEGMENT OF ENTIRE SECTION AFFECTED MUST BE REMOVED.IF
PIPE NOT FEASIBLE TO TAKE MAIN OUT OF SERVICE,
REPAIR WITH SLEEVE.
NON-LEAKING4. OR DEFECTS WELD• PIPE WELD SEAM
-
PERMISSIBLE METHODS OF
EXTENT OF DEFECT REPAIR LIMITATIONS ON METHODS
A.ANY LONGITUDINAL WELD CRACK 1.REPLACE SEGMENT OF ENTIRE SECTION AFFECTED MUST BE REMOVED.IF
GREATER THAN 2"LONG,A BRANCH OR PIPE NOT FEASIBLE TO TAKE MAIN OUT OF SERVICE,
CIRCUMFERENTIAL WELD CRACK MORE INSTALL SLEEVE.
THAN 8%OF WELD LENGTH,OR A CRACK
THAT PENETRATES EITHER THE ROOT OR
SECOND BEAD
B. ANY LONGITUDINAL WELD CRACK 1.GRINDING OR FILL AT LEAST 1/8"WALL THICKNESS REMAINING. REDUCE
LESS THAN OR EQUAL TO 2",A BRANCH WELDING PRESSURE TO BELOW 20%SYMS PRIOR TO MAKING
OR CIRCUMFERENTIAL WELD CRACK REPAIR. INSPECT REPAIR. IF DEFECT REMAINS,
LESS THAN OR EQUAL TO 8%OF WELD REPAIR AS IN 4.A.1.
LENGTH,OR OTHER DEFECTS 2.SLEEVING NO LIMITATIONS.
3.REPLACE SEGMENT OF ENTIRE SECTION AFFECTED MUST BE REMOVED.
PIPE
TYPE OF DEFECT
:•� • •-
PERMISSIBLE METHODS OF
EXTENT OF DEFECT REPAIR LIMITATIONS ON METHODS
A. ALL 1.REPLACE FITTING OR X-RAY TIE-IN WELDS OF REPLACED FITTINGS.
CLAMP
REPAIR OF DAMAGED PIPELINES REV. NO. 21
REPAIR OF STEEL PIPE DATE 01/01/25
Xvism a STANDARDS 11 OF 11
Utilities NATURAL GAS SPEC. 3.32

3.32A PERMANENT REPAIR SLEEVES
SCOPE:
To establish uniform procedures for installation of permanent repair sleeves.
REGULATORY REQUIREMENTS:
§192.241, §192.245, §192.309, §192.725
OTHER REFERENCES:
API 1104 OR API 1107
CORRESPONDING STANDARDS:
Spec. 3.22, Joining of Pipe—Steel
Spec. 3.32, Repair of Steel Pipe
General
Employees performing welding operations on permanent repair sleeves shall be properly trained and
qualified to weld on permanent sleeves per API 1104:
DETAILED PROCEDURES FOR USE OF "PLIDCO SPLIT-SLEEVE" PERMANENT STEEL REPAIR
CLAMP:
General
The Plidco Split-Sleeve may be used for permanent repairs of defects in steel pipelines where a full
encirclement sleeve is required or where field conditions preclude other methods of repair. The sleeve
consists of 2 semi-circular sections of a specified steel seamless pipe with bolting ears on opposing
sides. The sleeve is separated into two pieces by removing the bolts and studs. It is then installed on the
pipe, the bolts, and studs re-installed and torqued. A special elastomer seal and retainer system
accomplishes the sealing process. The Plidco Split-Sleeve may also be welded into position. Refer to
manufacturer's installation instructions if further detail is needed from procedures below.
Precautions
The following precautions shall be observed when installing the Plidco Split-Sleeve:
• Make sure that there is sufficient space in the trench to safely install the sleeve, torque the bolts, and
perform the welding operation (if necessary).
• If installing the sleeve on a pipeline that has an active leak, take precautions to avoid accidental
ignition of gas. Use a self-contained breathing apparatus (SCBA) if entering an oxygen deficient
atmosphere.
• Make sure that the sleeve is the proper size and length to fully cover the damaged area.
• Check the working pressure and temperature on the label of the sleeve. Do not exceed the maximum
working pressure or temperature (also note minimum working temperature).
• Do not use the sleeve to couple pipe.
• Remove all coatings, rust, and scale from the pipe surface where the circumferential seals of the
sleeve will contact the pipe. The seal can tolerate minor surface irregularities up to +- 1/32 of an inch.
• Use caution when transporting, lifting, and installing the sleeve as contact with the sleeves or retaining
rings can result in the seals being damaged or pulled from their grooves.
• On models with vent taps, make sure that a nipple and valve are installed prior to installation (leave
the valve in the open position until the sleeve is torqued). In some cases, the vent tap may be simply
plugged off.
REPAIR OF DAMAGED PIPELINES REV. NO. 9
PERMANENT REPAIR SLEEVES DATE 01/01/24
X-VISTa STANDARDS 1 OF 4
unlit►es SPEC. 3.32A
NATURAL GAS

Installation
1. Coat exposed surfaces with a lubricant(Buns-Nitrile seals may be lubricated with either a petroleum,
silicone, or glycerin-based lubricant. See manufacturer's instructions if using a sleeve with other than
Buna-N).
2. Disassemble the sleeve. Clean and lubricate the stud bolts and nuts. Prove free and easy running
prior to installation.
3. Place reference marks on the pipe as necessary to assist with centering the sleeve over the damage
area.
4. Assemble the sleeve around the pipe making sure the yellow painted ends are matched, and that the
sleeve is centered over the leak or damaged area as much as possible. Consider loosely assembling
the sleeve to one side of the leak (or damage), then re-positioning it over the critical area.
5. Torque stud bolts and nuts uniformly to the following:
Nominal Diameter Wrench Opening Torque (ft-lb)
of Stud Bolt(in) Across Flats (in)
5/8— 11 1-1/16 56
3/4 - 10 1-1/4 98
7/8-9 1-7/16 156
1 —8 1-5/8 233
(See manufacturer's instructions for torque specifications for larger sizes)
6. To complete assembly, the stud bolts should be rechecked for the recommended torque. The side
bars are gapped approximately 1/8-inch when the sleeve is fully tightened.
Field Welding Instructions
The following instructions shall be followed when permanently welding the Plidco Split-Sleeve on steel
pipelines.
• The pipeline should be operating at or near MAOP before performing welding operations.
• Use electrodes which have been properly stored in a dry box and are of equal or greater tensile
strength than the pipe. Low hydrogen electrodes (E-XX18) are recommended for the fillet welds due to
their high resistance to moisture pick-up and hydrogen cracking. They are also the preferred electrode
for seal welding the stud bolts and nuts. SMAW filler metals that include the cellulose coated
electrodes (E-XX10)are acceptable provided they are proven by procedure qualification. Do not use
cellulose coated electrodes for seal welding the stud bolts and nuts. The GMAW welding process may
also be used.
• Carefully control the size and shape of the circumferential fillet welds. The size of the fillet weld should
be at least 1.4 times the wall thickness of the pipe.
• The fillet weld face should have a concave face, with streamlined blending into both members of the
sleeve. Avoid notches and undercuts.
• Monitor the heat generated by welding or preheating, particularly near the area of the seals. Use
temperature crayons or probe thermometers. If the heat generated approaches the temperature limit of
the seal material, welding should be halted or sequenced to another part of the fitting so that the
affected area has a chance to cool (allow cooling in ambient conditions, do not force cool the area).
• The stud bolts are made of AISI 4140 steel with high carbon equivalence (grade 137). Use low
hydrogen electrodes (E-XX18) and a modest (not over 200 degrees F) preheat to reduce the problem
of hydrogen cracking or pinholes.
The pre-heat will dry out any moisture, oil dampness, or thread lubricant that may be present in the seal
weld area. GMAW welding procedures may also be used.
REPAIR OF DAMAGED PIPELINES REV. NO. 9
PERMANENT REPAIR SLEEVES DATE 01/01/24
X-VISTa STANDARDS 2 OF 4
unlit►es SPEC. 3.32A
NATURAL GAS

Welding Sequence
1. Fillet weld the ends of the sleeve to the pipe.
2. Seal weld the side openings.
3. Re-torque the stud bolts and nuts.
4. Seal weld around the bottoms of the nuts to the sidebars.
5. Seal weld the nuts to the stud bolts.
Testing
Test the Plidco sleeve if required. Test pressure can be up to 1-1/2 times the design working pressure.
Storage
Store the sleeves in a protected area, out of sunlight. Wrapping the container or sleeve in plastic will help
to also protect it from deterioration due to ozone and other atmospheric contaminants. It is recommended
that the elastomeric packing, the stud bolts, and the nuts be coated with a heavy grease to prevent
rusting and deterioration.
The elastomer packing has a shelf life of 2 to 20 years depending on the storage precautions used. Use
the "thumbnail"test to determine if the elastomer is still usable. Push your thumb into the exposed
packing. If it returns to its original shape, it should be okay to use. If the thumbnail imprint remains, it
should be replaced.
DETAILED PROCEDURES FOR USE OF "TD WILLIAMSON PERMANENT HEMI-HEAD REPAIR
SPHERES":
General
A 20-inch diameter repair sphere is available for use with 4-inch, 6-inch, 8-inch, and 10-inch pipe sizes.
This repair sphere is available marked but not cut to a specific pipe size which requires field scarfing.
Paint marks on the sleeves indicate approximate points to scarf(check actual pipe dimensions to
determine actual points to cut).
Precautions
The following precautions shall be observed when installing the repair sphere:
• Make sure that there is sufficient space in the trench to safely install the sleeve, torque the bolts, and
perform the welding operation (if necessary).
• If installing the sleeve on a pipeline that has an active leak, take precautions to avoid accidental
ignition of gas. Use a self-contained breathing apparatus (SCBA) if entering an oxygen deficient
atmosphere.
• Make sure that the sleeve is the proper size and length to fully cover the damaged area.
• Check the working pressure and temperature on the label of the sleeve. Do not exceed the maximum
working pressure or temperature (also note minimum working temperature).
• Do not use the sleeve to couple pipe.
REPAIR OF DAMAGED PIPELINES REV. NO. 9
PERMANENT REPAIR SLEEVES DATE 01/01/24
X-VISTa STANDARDS 3 OF 4
unlit►es SPEC. 3.32A
NATURAL GAS

Installation
1. Check the area on the pipe where fitting is to be installed. Clean pipe thoroughly and check
roundness. Pipe more than 1/8-inch out of roundness may require special preparation such as
grinding the fitting bore.
2. Remove moisture from the pipe before installing sleeve. Heat from an oxy-fuel torch is the most
common method of removal.
3. Clean sleeve edges thoroughly where weld is to be made. Remove any paint, dirt, rust, oil, or other
foreign matter.
4. Center and level sleeve. The sleeve should be positioned so that the vent port is on the top.
5. Remove the pipe plug from the top of the sleeve.
Fit-Up and Welding Sequence
Employees performing welding operations on the repair spheres shall be properly trained and qualified to
weld on permanent sleeves per API 1104:
1. Reduce the welding gap on the end fillet weld to a uniform minimum (1/8-inch maximum is
recommended).
2. Establish a 1/16-inch to 3/16-inch gap between the top and bottom fitting halves for the longitudinal
welds.
3. Use electrodes which have been properly stored in a dry box and are of equal or greater tensile
strength than the pipe. Low hydrogen electrodes (E-XX18) are recommended for the fillet welds due
to their high resistance to moisture pick-up and hydrogen cracking. The GMAW welding process may
also be used. Use the proper sequence of welds:
• Longitudinal weld first
• One end of circumferential weld
• Other end of circumferential weld
4. Replace the pipe plug in the vent after completion of welding.
Inspection
Conduct a visual examination for cracks, lack of fusion, or undercutting.
REPAIR OF DAMAGED PIPELINES REV. NO. 9
PERMANENT REPAIR SLEEVES DATE 01/01/24
X-VISTa STANDARDS 4 OF 4
unlit►es SPEC. 3.32A
NATURAL GAS

3.33 REPAIR OF PLASTIC (POLYETHYLENE) PIPE
SCOPE:
To establish uniform procedures for determining appropriate repairs based on the extent of damage to
plastic distribution pipelines. Each segment of pipeline that becomes unsafe must be replaced, repaired,
or removed from service.
REGULATORY REQUIREMENTS:
§192.311, §192.614, §192.725
CORRESPONDING STANDARDS:
Spec. 2.13, Pipe Design — Plastic
Spec. 3.13, Pipe Installation, Plastic (Polyethylene) Mains
Spec. 3.17, Purging Pipelines
Spec. 3.18, Pressure Testing
Spec. 3.23, Joining of Pipe - Plastic- Heat Fusion
Spec. 3.25, Joining of Pipe - Plastic- Mechanical
Spec. 3.34, Squeeze-Off of PE Pipe and Prevention of Static Electricity
Spec. 3.44, Exposed Pipe Evaluation
Spec. 5.14, Cathodic Protection
Spec. 5.17, Reinstating Gas Pipelines and Facilities
PLASTIC REPAIR REQUIREMENTS:
General
Each operator shall take necessary measures prior to beginning repairs to assure that the public and
Company personnel are protected from danger. Each imperfection or damage that would impair the
serviceability of plastic pipe must be repaired or removed.
Prior to performing repairs to plastic pipe, a thorough check shall be made with a combustible gas
indicator(CGI). CGI readings shall be continuously taken while repairs are being made until the area is
made safe.
Only those methods of repair as detailed in this standard are approved as permanent repairs to
polyethylene mains. When a repair cannot be made in conformance with the conditions of this standard,
the section of defective pipe shall be cut out and replaced with a new piece of pipe.
If a segment of plastic pipeline is repaired by cutting out the damaged portion, the replacement pipe must
be tested to the pressures required for a new line installation and specific information about the pressure
test and pipe material shall be documented on the Pre-Tested Pipe Documentation form (N-2743). Refer
to Specification 3.18, Pressure Testing, "Recordkeeping."
When a pipeline is exposed, an Exposed Piping Inspection Report form (Form N-2534) shall be
completed. Refer to Specification 3.44, Exposed Pipe Evaluation for more information.
REPAIR OF DAMAGED PIPELINES REV. NO. 21
REPAIR OF PLASTIC PIPE DATE 01/01/25
XvIST'r STANDARDS 1 OF 4
utilities NATURAL GAS SPEC. 3.33

Monitoring of Pressure
Gas personnel performing work on pipelines and facilities that could result in the loss pressure or
overpressure to the system shall install accurate pressure gauges upstream and downstream of the work
site. The pressure gauges shall be continuously monitored as long as is necessary, so that personnel
can respond accordingly if system pressures are greatly affected. (Note: CNG Trailers that are oftentimes
deployed to maintain system pressures for short periods of time do not require continuous monitoring.)
Additionally, there may be times when merely monitoring downstream pressure may not be sufficient to
prevent customer outages without further action. It may be necessary during warm days or periods of low
gas use to intentionally draw down the pressure of the downstream system and observe it to confirm the
existence of a looped system prior to altering the system or leaving the area. Consult Gas Engineering
for recommendations prior to altering any system's pressure. It may also be necessary to install a
temporary bypass if a system is not looped or if the pipeline work could result in loss of pressure to the
system. Refer to Specification 3.12, Pipe Installation—Steel Mains for temporary bypass details and
requirements.
Any loss of pressure that may have extinguished pilots or that may have affected the normal operation of
the customer's gas equipment shall be treated as an outage and the procedures followed as outlined in
the GESH, Section 5, Emergency Shutdown and Restoration of Service.
Pre-Tested Pipe
When making a repair as a result of third-party damage or material failure, and it is not possible or
practical to test the section of pipe being replaced, pre-tested pipe shall be used. A Pre-Tested Pipe
Documentation form (N-2743)shall be filled out and kept at the local office for all pre-tested pipe.
Once the pipe is installed, a copy of the Pre-Tested Pipe Documentation form must be kept for the life of
facility with the project file (not at the warehouse with the uninstalled pipe records). The tested pipe shall
be segregated from the rest of the pipe stock and identified as pre-tested pipe. The pipe should be
periodically inspected and remarked as necessary to indicate its status. Refer to Specification 3.13, Pipe
Installation - Plastic (Polyethylene) Mains for PE print line information and for storage and handling of the
pipe. Refer to Specification 3.18, Pressure Testing regarding pre-installation testing.
Static Charges
Polyethylene is a poor conductor of electricity; therefore, precautions must be taken to prevent build-up of
static electrical charges on plastic pipe that is damaged and leaking or at squeeze points. These static
charges, if not properly grounded, might cause ignition in a gaseous atmosphere. Refer to Specification
3.34, Squeeze-Off of PE Pipe and Prevention of Static Electricity, "Prevention of Accidental Ignition by
Static Electricity," and Specification 3.17, Purging Pipelines, "Prevention of Accidental Ignition"for further
items to consider when working near gas pipeline facilities.
Temporary Repairs
Temporary repairs may be made using an approved full encirclement stainless steel clamp; however,
these clamps are not acceptable as a permanent repair solution.
REPAIR OF DAMAGED PIPELINES REV. NO. 21
REPAIR OF PLASTIC PIPE DATE 01/01/25
Xv sm a STANDARDS 2 OF 4
utilities NATURAL GAS SPEC. 3.33

Permanent Repairs
Permanent repairs may be made by replacing the damaged pipe with a workable length of new pipe or an
approved repair fitting. A repair fitting shall be installed per the manufacturer's instructions.
The following "Plastic Repair Selection Chart" details the required repairs for damaged polyethylene pipe.
PLASTIC REPAIR SELECTION CHART
EXTENT OF DEFECT PERMISSIBLE METHOD OF PERMANENT
TYPE OF DEFECT As measured by a pit gauge) REPAIR
Depth (inches) If defect is less than this depth (i.e., 10 percent of
Pipe Size Pipe Wall the pipe wall), pipe damage should be sanded
1/2"CTS 0.009" smooth. Soap test to assure that no crack or slice
IPS 0.009 ill "
21, exists. Refer to Spec. 3.25, Joining of Pipe-
Scratches, gouges, " IPS 0.01 1-1/ " IPS 0.016" Plastic—Mechanical,for complete instructions for
1-1/2" IPS 0.01
cuts, and abrasions 7" pipe.sanding
2" IPS 0.021" If defect is equal or greater than this depth,
3" IPS 0.030" defective pipe shall be replaced with new pipe or
4" IPS 0.039" repaired with an approved repair fitting.
6" IPS 0.058"
Kinks,wrinkles, Defective pipe shall be replaced with new pipe or
creases, holes, and No limit an approved repair fitting.
punctures
Defective pipe shall be replaced with new pipe.
Cracks No limit The new pipe segment should extend at least 3
pipe diameters or 12 inches,whichever is greater,
from each end of the crack.
Damage to Service Line
Repair requirements for a dig-in or otherwise damaged plastic service lines.
Direct buried plastic service:
Visually inspect the plastic pipe upstream and downstream from the area of contact. When a service line
has been disconnected for repair(merely changing out the meter valve does not apply) resulting in an
interruption of gas supply to the customer, the service line must be re-tested from the point of disconnect
to the meter valve in the same manner as a new service line before reconnecting. If provisions are made
to maintain continuous service to the customer such as by installation of a bypass or maintaining line
pack in some fashion, any part of the original service line used to maintain continuous service need not
be tested. Refer to Specification 3.18, Pressure Testing. After third party excavation damage to services,
a gas leak survey must be performed from the point of damage back to the service tie-in.
Plastic service inserted into an existing casing:
If casing is damaged (broken, bent, or crushed), replace the plastic carrier pipe 2-feet upstream and
downstream of the dig-in location and soap-test the replaced section. The casing pipe should be cut back
1-foot from the plastic pipe tie-in points and casing plugs should be installed where the plastic exits and
enters the casing. Follow the same procedures as above. If additional damage is found, replace the
service.
REPAIR OF DAMAGED PIPELINES REV. NO. 21
REPAIR OF PLASTIC PIPE DATE 01/01/25
Xv sr'a STANDARDS 3 OF 4
utilities NATURAL GAS SPEC. 3.33

Heat Damage
Repair requirements for plastic service inserted risers or prefabricated non-corrodible risers for meter sets
exposed to, or damaged by, a fire or excessive heat:
• Plastic pipe is sensitive to heat. Therefore, whenever a plastic service inserted riser or
prefabricated non-corrodible riser may have been subjected to unusually high temperatures, such
as being exposed to a house fire or meter fire, the plastic insert, or the entire riser must be
replaced.
• Pressure testing of the service is not sufficient because the plastic piping inside the riser may
hold a short duration air pressure test but could still be damaged to the point that, on a long-term
basis, it will eventually rupture.
Marking Joints
For plastic joints, the qualified individual who performed the joint shall use a permanent marker to legibly
sign the pipe with their first initial and full last name and shall also mark the date of the joint.
Recordkeeping
Records and maps of repairs performed shall be retained for the life of the facilities.
REPAIR OF DAMAGED PIPELINES REV. NO. 21
REPAIR OF PLASTIC PIPE DATE 01/01/25
XvIST'r STANDARDS 4 OF 4
utilities NATURAL GAS SPEC. 3.33

3.34 SQUEEZE-OFF OF PE PIPE AND PREVENTION OF STATIC ELECTRICITY
SCOPE:
To establish a procedure by which polyethylene pipe may be squeezed-off in order to control gas
distribution pressure in emergency situations or during certain pipeline construction procedures. Also
included in this section are procedures for prevention of accidental ignition by static electricity when
working with polyethylene (PE) pipe.
REGULATORY REQUIREMENTS:
§192.751
WAC 296-809, 480-93-178
CORRESPONDING STANDARDS:
Spec. 2.13, Pipe Design - Plastic
Spec. 3.13, Pipe Installation - Plastic Mains
Spec. 3.17, Purging Pipelines
Spec. 3.33, Repair of Plastic Pipe
Avista's Incident Prevention Manual (Safety Handbook)
General
The primary method for pressure control in Avista's distribution systems is the use of available system
valves. When polyethylene pipe is encountered, squeeze-off using suitable tools and equipment may
also be used as a control method. Squeeze-off is frequently used to stop the flow of gas for emergency
repairs; it can also be used to control pressure during the construction of plastic pipelines.
Squeeze-Off Tools
Squeeze-off tools suitable for use on plastic pipe consist of round steel bars and a mechanical or
hydraulic means of forcing the bars together. The tools are designed to squeeze the pipe until the inside
surfaces meet and shutoff is achieved. To ensure proper flow control and to minimize damage to plastic
pipe, squeeze-off tools shall have mechanical stops to limit the minimum gap between the squeeze bars
to a tolerance that will prevent damage to the pipe. The bars themselves shall be rounded and shall
conform to the diameter recommended by the pipe manufacturer.
Monitoring of Pressures
Gas personnel performing work on pipelines and facilities that could result in the loss of pressure or
overpressure to the system shall install accurate pressure gauges upstream and downstream of the work
site. The pressure gauges shall be continuously monitored as long as is necessary, so that personnel can
respond accordingly if system pressures are greatly affected. (Note: CNG Trailers that are oftentimes
deployed to maintain system pressures for short periods of time do not require continuous monitoring.)
Additionally, there may be times when merely monitoring downstream pressure may not be sufficient to
prevent customer outages without further action. It may be necessary during warm days or periods of low
gas use to intentionally draw down the pressure of the downstream system and observe it to confirm the
existence of a looped system prior to altering the system or leaving the area. Consult Gas Engineering for
recommendations prior to altering any system's pressure.
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It may also be necessary to install a temporary bypass if a system is not looped or if the pipeline work
could result in loss of pressure to the system. Refer to Specification 3.12, Pipe Installation —Steel Mains
for temporary bypass details and requirements. Any loss of pressure that may have extinguished pilots or
that may have affected the normal operation of the customer's gas equipment shall be treated as an
outage and the procedures followed as outlined in the GESH, Section 5, Emergency Shutdown and
Restoration of Service.
Prevention of Accidental Ignition by Static Electricity
Static electricity can build up on any non-conductor such as plastic pipe, therefore the possibility exists
that a spark discharge of sufficient energy could cause ignition of natural gas if the proper air/gas mixture
is present. It is also possible for repair crews to receive shocks from static electricity even if ignition does
not occur.
Potential for ignition is present if all three of the following conditions are present:
1. There is sufficient gas flow to cause extensive turbulence in the pipe;
2. Rust, dust, or other foreign particles are present in the gas streams; and
3. A static charge is present at a point where a combustible air/gas mixture is present.
Emergency flow control situations requiring squeeze-off of polyethylene pipe may involve working in the
vicinity of blowing gas. Squeezing, purging, and repair work should only be performed by a trained and
qualified individual. The following procedures shall be considered or complied with as appropriate
whenever working with blowing gas and plastic pipe:
• If a repair is involved, consider excavating squeeze-off holes at approximately 50-feet from the
damaged area, if possible. This will help to limit direct exposure of the employee to blowing gas
and debris from the excavation. This will also act as a safety precaution to help mitigate the
potential for build-up of static charge due to squeeze-off at the location where gas is releasing to
atmosphere.
• If working in the vicinity of leaking gas, CGI readings shall continuously be taken while repairs are
being made until the area is made safe.
• A fire suit of appropriate flame-resistant material shall be worn when controlling blowing gas or in a
confined hazardous atmosphere. Refer to Avista's Incident Prevention Manual (Safety Handbook).
• If gas is blowing, place the proper fire extinguisher near the job site per Avista's Incident
Prevention Manual (Safety Handbook).
• During an emergency situation, a properly trained and qualified gas employee shall assess the
need for a Self-Contained Breathing Apparatus (SCBA). If it is determined that an SCBA is
required, refer to Avista's Incident Prevention Manual (Safety Handbook)for specific requirements.
• Refer to Specification 3.17, Purging Pipelines, "Prevention of Accidental Ignition"for additional
considerations when working in a potentially explosive environment.
PREVENTION OF STATIC ELECTRICITY PROCEDURES
In addition to properly grounding the squeezing tool, one of the two following procedures shall be used to
prevent the build-up of static electricity on pipe and tools during squeeze-off. These procedures are not
intended to replace the need to properly ground the squeezing equipment.
For either of the following procedures be sure to properly ground the squeezing tool before contacting the
pipe. This will protect the operator in the event of a static discharge by providing a safe path to ground.
The ground strap must be attached to a conductive element on the squeeze tool (i.e., metal)to function
as intended. Improper connection of the ground strap will provide inadequate protection from a static
discharge.
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Aerosol Static Suppression Procedure
Only company approved aerosol static suppressor can be sprayed on tools, into cuts, outside or inside
pipe or any surface area where needed to suppress static.
Only the surfaces that have been wet by the aerosol static suppressor will dissipate static
electricity.
(The aerosol suppressor sprayed on the OUTSIDE of a pipe will not suppress static charges on the
INSIDE of the pipe).
Surfaces sprayed with aerosol static suppressor do not need to be kept wet to suppress static. Note that
these procedures are not intended to replace the need to properly ground the squeezing tool.
Operating Temperatures—Aerosol static suppressor is effective from any temperature up to 120 degrees
F. If the product freezes while in use on a pipe, static will still be suppressed. Freezing will not diminish its
static suppression abilities. Aerosol static suppressor will freeze at temperatures below 30 degrees F.
However, if the aerosol freezes, simply thaw, shake, and spray. Freezing will not damage the product.
Employees are required to use static suppressant anytime a plastic pipeline is damaged, repaired, taken
out of service, or put into service.
1. Pipe Surfaces— Hold the aerosol about 1-foot away from surface and direct spray onto the
surface which you wish to suppress static. Spray the entire pipe surface exposed in excavation or
bell hole. Spray only enough so the surface appears wet. The aerosol can be held upside down to
reach under the pipe. However, periodically upright can to refill internal dip tube and continue
spraying. Visually verify the surface of the plastic pipeline being worked on is coated with static
suppressor.
2. Cutting Pipe—Spraying into the cut while cutting the pipe will disperse the aerosol static
suppressor inside the pipe and suppress static on any surface it contacts inside the cut. The
cutting tool shall be sprayed while in the process of cutting.
3. Open Ended Pipe and Purged Pipelines—Apply the static suppressor spray inside and outside
the open end of the pipe for added protection when working with open ended or purged pipe.
When working around open pipe ends, where there is a hazard of a combustible atmosphere
present, spray inside and outside the pipe taking care to wet the cut ends of the pipe also
(convergence zone). Hold the aerosol 1 foot away and spray into the inside open end of the pipe
and onto exposed pipe edges to eliminate static. Only after spraying the outside of the pipe and
the exposed pipe edges should you approach the pipe and spray into the pipe as far as possible
in order to eliminate static inside the pipe.
4. Surfaces to be Fused — Prior to fusing, any surface sprayed with aerosol static suppressor should
be either wiped off with either isopropyl alcohol or washed off with water before facing or scraping
to remove any residue of the spray. Proceed as you would after thoroughly drying, taking care not
to leave any water that would affect the fusion.
5. Mechanical Couplings—The aerosol static suppressor will not affect mechanical couplings if the
surface is cleaned off with alcohol wipes or washed off with water to remove any residue of the
spray.
Wet Soapy Rag Procedure
Proper use of wet soapy rags to treat pipe and tools prior to squeeze-off will reduce the risk of a static
discharge and possible ignition.
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Note: These procedures are not intended to replace the need to properly ground the squeezing tool.
1. Before employees enter an excavation or attempt to control blowing gas, spray the pipe and
surrounding area where working with a soap and water solution. Soapy water creates a better
conductor than plain water as it will coat the pipe and not bead up.
2. Wrap wet rags around entire length of exposed pipe, leaving enough room to squeeze and cut
the pipe. The wet rag should be one continuous length with a "jumper" buried in the soil under the
squeeze area. The "jumper"will provide continuity when the pipe is cut, helping to eliminate the
possibility of an arc occurring.
3. Keep the pipe and excavation wet until the squeezers are removed. This provides a continuous
discharge of static electricity on the pipe.
4. Once the pipe has been squeezed following the procedure outlined below, the pipe is ready to be
cut. During the cutting process spray soapy water solution on the area being cut. This will help
dissipate the static from the interior of the pipe by giving it a path to follow away from the edge of
the cut.
If squeezing the pipe to make a repair, complete the repair at this time. Be aware of the possibility of
combustible air/gas mixtures and static charges even after blowing gas is controlled.
If performing squeeze procedure from aboveground out of the bell hole or excavation, follow steps #1 and
#4 of the procedures outlined above.
SQUEEZING PROCEDURE
Precautions should be taken to avoid damage to the pipe. Any damage sustained could lead to eventual
failure. The location of the squeeze point, the squeezing procedure, and squeeze release procedure
below follow the guidelines defined in ASTM F1041, Standard Guide for Squeeze-off of Polyolefin Gas
Pressure Pipe and Tubing.
1. Make sure squeezing tool is properly grounded. Ensure the pipe is centered and squared in the
squeeze tool. It is important that the pipe be free to spread as it flattens. Failure to do so may
result in damage to the pipe or the tool. Also check to see that the tracer wire is not caught
between the squeeze bars and the pipe. Make sure that gap stops are set in proper position for
the size of pipe.
2. Location of the squeeze point:
• The squeeze point shall be at least 3 pipe diameters or 12 inches, whichever is greater(as
measured from the center of the squeeze point), away from the nearest edge of a fitting or
heat fusion joint or sidewall connection, saddle, or mechanical fitting, a prior squeeze-off, or
a second squeeze-off tool. Failure to do so may result in damage to the fittings or joint.
Clearances from previous squeeze points shall be visually confirmed (i.e., exposed).
Consideration should be made during construction to anticipate these situations, especially
on service stubs. This will allow adequate spacing to ensure the minimum separation can
be met on either side of the squeeze.
• On a transition fitting, the plastic pipe inside the steel sleeve does not count toward the
distance measured for squeezing, therefore start the measurement from where the plastic
pipe exits the steel sleeve.
WAC 480-93-178: Item 9 of the WAC requires that plastic pipe not be squeezed within 12 inches or 3
pipe diameters, whichever is greater, from any joint or fitting.
• Do not squeeze on pipe sections containing deep scratches (greater than 10 percent of the
pipe wall thickness).
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• Plastic pipe should only be squeezed-off in the same place one time. It is possible for scale
or other metal particles contained in the gas flow to become trapped at the squeeze point.
A second squeeze in the same area could force these particles into or through the pipe
wall.
3. Squeeze Procedure:
• The squeeze rate cannot be any faster than 2 inches per minute. Squeeze rate example for
a 4-inch IPS pipe: The outside diameter is 4.5 inches, therefore the minimum time to
squeeze the pipe is 4.5 inches/2 inches per minute = 2.25 minutes (2 min 15 sec). The
minimum time to squeeze pipe for various pipe sizes are tabulated in the table below. Note
that the minimum time to squeeze is longer when the temperature is at or below 32°F. See
the corresponding table below. Do not over squeeze the pipe. The squeeze tool should
have mechanical stops that come into contact when the pipe is at its maximum squeeze
point.
• If the squeeze rate cannot be adhered to due to an emergency situation, the pipe is
considered damaged in the squeezed area and shall be cut out and replaced.
• Do not use extension levers or cheater bars when using the squeeze tool. Damaged tools
should be repaired or replaced.
• A bubble tight flow control will not always be attainable. If more complete pressure control
is needed, a valve should be used, or additional squeeze tools used in series.
4. Squeeze Release Procedure:
• It is critical to release the squeeze very slowly. The release rate cannot be any faster than
0.5 inches per minute. Squeeze release rate example for a 4-inch IPS pipe: The outside
diameter is 4.5 inches, therefore the minimum time to release the squeeze is 4.5 inches/
0.5 inches per minute = 9 minutes. The minimum time to release a squeeze for various pipe
sizes are tabulated in the table below. Note that the minimum time to release is longer
when the temperature is at or below 32°F. See the corresponding table below.
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PE Pipe Squeeze and Release Rates (Air Temperature Over 32' F)
Minimum Minimum
Minimum Time to Time to
Pipe Wall Squeeze Release
Pipe Avg. Thickness Pipe Squeeze
Pipe Size SDR O.D. in. in. min:sec min:sec
1/2" CTS 7 0.625 0.090 00:19 01:15
3/4" IPS 11 1.050 0.095 00:32 02:06
1" IPS 11 1.315 0.120 00:40 02:38
1-1/4" IPS 10 1.660 0.166 00:50 03:20
1-1/2" IPS 11 1.900 0.173 00:57 03:48
2" IPS 11 2.375 0.216 01:12 04:45
3" IPS 11.5 3.500 0.304 01:45 07:00
4" IPS 11.5 4.500 0.391 02:15 09:00
6" IPS 11.5 6.625 0.576 03:19 13:15
*SDR-Standard dimension ratio is calculated by dividing the average O.D. of the pipe by the minimum wall
thickness in inches.
PE Pipe Squeeze and Release Rates (Air Temperature at or Below 32' F)
Minimum Minimum
Minimum Time to Time to
Pipe Wall Squeeze Release
Pipe Avg. Thickness Pipe Squeeze
Pipe Size SDR O.D. in. in. min:sec min:sec
1/2" CTS 7 0.625 0.090 00:38 02:30
3/4" IPS 11 1.050 0.095 01:04 04:12
1" IPS 11 1.315 0.120 01:20 05:16
1-1/4" IPS 10 1.660 0.166 01:40 06:40
1-1/2" IPS 11 1.900 0.173 01:54 07:36
2" IPS 11 2.375 0.216 02:24 09:30
3" IPS 11.5 3.500 0.304 03:30 14:00
4" IPS 11.5 4.500 0.391 04:30 18:00
6" IPS 11.5 6.625 0.576 06:38 26:30
For use of hydraulic squeezers follow the manufacturer's instructions and follow the squeeze and
release rates outlined above.
POST-SQUEEZE PROCEDURE
After the squeeze procedure, ensure the following steps are completed to finish the evolution.
1. Visually inspect the affected area for damage.
2. Test for leaks using a soap and water solution.
3. Wrap black electrical tape around the pipe on both sides of the squeeze point and over the
squeeze point in the shape of an "X" prior to backfilling.
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3.35 DETAILED PROCEDURES FOR USE OF "ADAMS" STYLE REPAIR CLAMPS
SCOPE:
To establish uniform procedures for the installation and use of Adams style repair clamps.
REGULATORY REQUIREMENTS:
§192.627, §192.711
CORRESPONDING STANDARDS:
Spec. 3.32, Repair of Steel Pipe
GESH Section 2— Leak and Odor Investigation
General
"Adams"style repair clamps are cylindrical sections of stainless steel that have an internal, attached lining
of rubber or other pliable material. Some models of these clamps are designed so that they may be
opened along their longitudinal axis and slipped onto a section of pipeline. Other models come in two
separate sections that have interlocking gaskets and bolts on both sides. Once in place, the bolts are
tightened resulting in a decrease in the annular area between the pipe and the clamp. The snug fit
between the rubber gasket and the pipe will usually eliminate any leakage.
These clamps are used on a temporary basis to repair leaks or mechanical damage to steel or
polyethylene pipe caused by outside forces or to reinforce small areas of corrosion damage on steel or
polyethylene pipe. Temporary leak clamps should not be used on pipelines that are badly corroded or
that are weakened due to serious damage. Refer to Specification 3.32, Repair of Damaged Pipelines,
"Steel Repair Selection Charts,"to determine when a leak clamp may be used.
The intent of this temporary repair is to make the site safe per GESH Section 2— Leak and Odor
Investigation. Thereafter, the permanent repair can be completed as soon as possible. These clamps
should not be backfilled. It is permissible to cover the trench with steel road plates, if necessary.
"Adams" style clamps shall not be tapped and may not be welded to the pipeline. Only clamps approved
by Gas Engineering may be used for temporary repairs. Employees using temporary repair clamps shall
be properly trained and qualified to install each style of clamp available on service/crew vehicles.
Precautions
The following precautions are applicable when installing all brands and styles of leak repair clamps:
1. Ensure there is sufficient space in the trench to apply the clamp and torque the bolts. Use
manual wrenches to initially tighten the clamp if there is danger of accidental ignition of a gaseous
atmosphere.
2. If installing the clamp on a pipeline that has an active leak, take precautions to prevent accidental
ignition of the gas. Use a self-contained breathing apparatus (SCBA) as outlined in Avista's
Incident Prevention Manual (Safety Handbook) if entering an oxygen deficient atmosphere.
3. Verify clamp size by checking the diameter of the pipe and the length of the damaged area.
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4. Clean the pipe to remove loose dirt and corrosion from the surface. Loose coating material
should be removed until a reasonably smooth surface remains.
5. Place marks on the pipe to reference the leak. Use these marks to assure that the clamp is
properly positioned. Use a paint stick, grease pencil, or other visible marker.
6. Applicable 360-degree leak clamps with outlets should have a nipple and valve installed prior to
installation. Install the outlet pointing outward where it will be accessible when the clamp is
tightened. The valve should be left in the open position until the clamp is fully tightened.
7. When using clamps that have a gasket that provides partial coverage ensure the gasket is
centered over the damage area before the clamp is tightened.
8. Ensure no foreign materials stick to the gasket as it is brought around the pipe. Check that no
materials become lodged between the gasket and the pipe as the nuts are tightened.
9. Use the proper wrench for the job. Use a torque wrench if specified by the manufacturer to
achieve proper bolt torque.
10. Keep bolt threads free of dirt and foreign materials.
11. Test for leaks after clamp is tightened.
Romac Style SS1 Procedures
The following procedures are applicable to 3/4-inch to 3-inch Style SS1 Stainless Steel Repair Clamps
manufactured by Romac Industries, Inc.
1. Visually inspect the clamp for damage and to ensure that no parts are missing. Clean the pipe
surface that will be covered by the clamp. Ensure the area around the damaged area is large
enough to accommodate the installation of the clamp and the torque wrench handle.
2. Place reference marks on the pipe in line with the crack or hole in the pipe, if practical. Center
the clamp over the repair area before installing it and place additional marks on the pipe at the
edges of the clamp. These marks will assist centering the gasket material over the damaged
area.
3. Back off the nuts to the end of the bolts, but do not remove them. Separate the clamp and wrap it
around the pipe at a location remote to the damage area.
4. Slide the lifter bars up the receiver lug profile and snap into place over the side-bar edge. Ensure
the gasket tails are not folded under, they must be lying flat around the pipe.
5. Using the reference marks, slide the clamp over the damaged area. Ensure the bolts are in a
position where they can be tightened properly.
6. Tighten all nuts evenly in 20 ft-lb. increments. Start in the center and work toward each end
keeping torques as evenly balance as possible. Using a torque wrench, tighten all nuts to the
following values:
Nominal Pipe Diameter in Torque MAW
4 and below 30-35
6 and above 75-85
7. Wait 10 minutes and then retighten to ensure the proper torque is maintained.
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"ADAMS" STYLE REPAIR CLAMPS DATE 01/01/18
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Adams and Mueller Style Procedure
The following procedures are applicable to repair clamps manufactured by Mueller:
1. Make sure the clamp style matches the diameter of the pipeline and the length of the repair.
2. Clean the pipe thoroughly, removing any burrs and loose material.
3. Slip the bolt head(s) out of the lug(s) and separate the clamp. On 2-piece clamps, loosen and
remove all of the bolts, nuts, and washers to separate the clamp.
4. Mark the damaged area, if practical, for alignment purposes. Ensure the gasket will cover the
damaged area by at least 1 inch when aligned. Use a longer clamp if necessary.
5. Place the clamp on the pipeline to the side of the damaged area.
6. While compressing the clamp, slip the bolt head(s) back into the lug(s). On a Full-Seal 2-piece
clamps, align the bolt holes in the side lugs and re-install the bolts, nuts, and washers. Finger-
tighten only until in final position.
7. On Full-Seal clamps, ensure the inter-locking gasket fingers are in the proper position. Gap
bridges should slide under the bank (rotate the clamp slightly as necessary to prevent any hang-
up or binding).
8. Slide the clamp carefully over the damage area and note alignment marks.
9. Tighten bolts alternately to the torque value specified below:
Adams/Mueller Series Torque (Ibs. in)
200 Servi-Seal all 500
500 5/8" 840
500 1/2" 480
520 2"-3 1/2" Diameter 420
520 4"-8" Diameter 600
520 10"-12" Diameter 780
Notes:
• Do not reuse temporary clamps unless it is determined that there is no significant damage to the
gasket material and that the bolts have not been damaged. If there is any doubt, discard the
leak clamp.
• "Adams" style repair clamps may be used on polyethylene pipe provided that the clamp is
properly sized for the pipeline O.D., it can be installed safely, and the proper precautions are
taken to prevent accidental ignition by static electricity.
• Refer to the manufacturer's instructions for installing clamps not listed in this procedure.
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3.4 MISCELLANEOUS CONSTRUCTION
3.42 CASING AND CONDUIT INSTALLATION
SCOPE:
To establish a uniform procedure for casing design to be used under roadways, railroad crossings, and
alongside or within bridge structures.
REGULATORY REQUIREMENTS:
§192.323
WAC 480-93-110, 480-93-115
CORRESPONDING STANDARDS:
Spec. 2.15, Bridge Design
Spec. 2.32, Cathodic Protection
Spec. 3.33, Repair of Plastic(Polyethylene) Pipe
DESIGN REQUIREMENTS:
General
In general, casings are used only where required by permit, ordinance, or governing agency for railroad,
highway, and bridge crossings. The principal purpose for a casing is to provide a means of installation
and replacement of a main without interrupting traffic on the traveled way. It is also to provide a conduit
for gas to escape from under the traveled way should a leak occur in the carrier pipe.
Casings shall be designed with sufficient strength to withstand anticipated stresses due to bending,
torsion, and temperature change. Gas Engineering should be consulted when installing a casing.
Gas Engineering has concluded that none of the Company's casing end seals are "...strong enough to
retain the MAOP pressure of the pipe..." and consequently, there is not a need to either add vent pipes or
run a strength calculation on unvented, post-1970 casing to prove compliance with §192.323.
WAC 480-93-115: Whenever a gas pipeline company installs a main or transmission line in a casing
or conduit of any type of material, the gas pipeline company must seal the casing ends to prevent or
slow the migration of gas in the event of a leak.
Service lines installed in a casing or conduit must be sealed at the end nearest the building to prevent
or slow the migration of gas towards the building in the event of a leak.
Link type seals and rubber boots are acceptable ways to seal the ends of casings. Conduits may be
sealed with spray foam or another suitable sealant. The requirements for end sealing services as outlined
in WAC 480-93-115 are applicable to Washington State only and is a best practice in Idaho and Oregon.
PIPE SYSTEMS REV. NO. 20
CASING & CONDUIT INSTALLATION DATE 01/01/25
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Utilities NATURAL GAS SPEC. 3.42

Casing Size
The casing shall have a minimum inside diameter sufficiently larger than the outside diameter of the
carrier pipe to accommodate placement and removal of the carrier pipe. Consideration should be given to
any possible future need to increase the carrier pipe size and the casing should be sized accordingly.
The following tables may be used as guidelines for sizing casing:
STEEL CASING PIPE SPECIFICATIONS FOR STEEL CARRIER PIPE
Nom. Dia. of Minimum Nom.
Steel Carrier Nom. Dia. of Minimum Wall Dia. of Vent Pipe
Pipe in Casing Pipe in Thickness in in
3/4 2 0.125 2
1 1/4 3 0.125 2
2 6 0.250 2
3 6 0.250 2
4 8 0.250 2
6 10 0.250 2
8 12 0.250 2
10 16 0.250 2
12 20 0.250 2
16 24 0.281 3
20 26 0.375 3
CASING PIPE SPECIFICATIONS FOR PLASTIC
(POLYETHYLENE) CARRIER PIPE
Nom. Dia. of Plastic Carrier
Pipe in Suggested Casing Size* in
1/2 2
3/4 2
1 1/4 3
2 4
3 6
4 8
6 10
*NOTES:
(1)Suggested sizes are given to prevent damage to plastic carrier pipe should water leak
into casing and freeze.
(2)Casing specifications for steel casings apply as shown in the previous table.
(3) PVC plastic casing must be Schedule 40 for size 2-inch through 6-inch and Schedule
80 for sizes 8-inch and above.
Casing Specifications
Plastic conduit shall not be used for steel carrier pipeline as it interferes with the ability to cathodically
protect the steel carrier pipeline.
Buried steel casings with steel carrier pipe shall be bare to prevent potential shielding of cathodic
protection.
PIPE SYSTEMS REV. NO. 20
CASING & CONDUIT INSTALLATION DATE 01/01/25
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Utilities NATURAL GAS SPEC. 3.42

Casing pipe should be butt welded with full circumferential welds to similar quality as the carrier pipeline.
Some governing agencies may require the use of a galvanized casing on bridges or other structures. If a
galvanized casing is required, the casing should be ordered with a galvanizing cutback on each end
(typically 3 to 4 inches in length)to accommodate welding. When a cutback is used, the weld and the
bare pipe surrounding the weld shall be painted with a galvanizing paint or other approved coating after
welding is complete. If a cutback is not used, weld fume extraction equipment and welder respiratory
protection equipment should be used. The weld shall be painted with a galvanizing paint or other
approved coating after welding is complete.
Casings shall be seamless, ERW or DSAW welds, but need not meet specifications for carrier pipe.
"Casing grade quality pipe" is preferred as it is lower in cost.
Casings designed for railroad crossings shall be per Drawing E-33947, Sheet 1 of 2. Casings designed
for state or interstate highway crossings shall be per Drawing E-33947, Sheet 2 of 2. Drawings are
located at the end of this specification.
Keep moisture from filling the casing. Normally, use of an approved end seal will keep the carrier pipeline
dry and the ends free of debris. Although crossings should not be located where a freeway or expressway
is in a depressed location, when this is unavoidable, additional measures may be taken to keep carrier
pipeline dry. Contact Gas Engineering for advice in using additional sealing methods when encountering
potential high water table areas.
INSTALLATION REQUIREMENTS:
Installing Steel Carrier Pipe in Casing
The inside wall of the casing pipe must be free of sharp or rough surfaces. When necessary, the entire
length of the casing pipe shall be cleaned to remove debris. Suggested means of cleaning include
purging with air and/or use of pigging devices.
Casings should have a minimum of one vent pipe installed and it is preferred to have a vent pipe at each
end. Vent pipes should be welded to the casing prior to inserting carrier pipe to prevent damage to the
carrier pipe. If two vents are installed, the casing vent at the lower elevation shall be attached to the
bottom of the casing and the other to the top of the casing. This provides for natural circulation through
the vents. It also allows for the ability to blow accumulated water out of the casing through the lower vent.
Vent pipes shall be constructed of carbon steel as delineated in Drawing E-33947 at the end of this
specification. Do not use factory-coated steel pipe for the below-grade portion of the vent piping, as it can
appear to be gas-carrying pipe when excavated in the future.
The above ground portion of vent pipes shall be coated with paint(tape-wrapping below ground is not
required). The vent pipe must not contact the steel carrier pipeline. The vent shall be installed to prevent
water or other debris from entering the vent opening.
The carrier pipe shall be inspected for damage prior to its installation and during the insertion operation
as the pipe enters and leaves the casing pipe.
Casing Insulators - For steel carrier pipelines, casing insulators should be installed with maximum 5 feet
separation. Close spacing prevents grounding of steel carrier pipeline to casing. Install two casing
insulators at each end of casing to assure carrier pipe does not come in contact with end of casing.
The carrier pipe shall be inspected at the leading end for damage after the installation by using a
flashlight to illuminate the interior of the casing. Any significant gouging of the pipe coating (steel carrier
pipeline) must be repaired or replaced.
PIPE SYSTEMS REV. NO. 20
CASING & CONDUIT INSTALLATION DATE 01/01/25
XV'1STa STANDARDS 3 OF 8
Utilities NATURAL GAS SPEC. 3.42

A cathodic reading should be taken immediately after installation to assure that the carrier pipeline is not
electrically shorted to the casing.
Permanent test leads shall be attached to at-least one end of the casing and the steel carrier pipe. Install
test leads at both ends of the casing whenever possible. The wire connections on the casing shall be
covered with mastic or tape wrap similar to steel pipe. Refer to Drawing E-33947 at the end of this
specification.
WAC 480-93-115: The state of Washington requires that a separate test lead shall be attached to the
casing and to the steel gas pipeline to verify that no electric short exists between the two.
End Seals— Link type seals with centering blocks shall be used to seal casing ends when steel carrier
pipe is installed. The carrier pipe shall be supported to keep the proper concentric alignment when
installing these types of seals.
The bottom of the trench adjacent to each end of the casing shall be graded to provide firm, uniform, and
continuous support for the carrier pipeline.
Installing PE Carrier Pipe in Casing
The inside wall of the casing pipe must be free of sharp or rough surfaces. When necessary, the entire
length of the casing pipe shall be cleaned to remove debris. Suggested means of cleaning include
purging with air and/or use of pigging devices.
Casings should have a minimum of one vent pipe installed and it is preferred to have a vent pipe at each
end. Vent pipes shall be welded to the casing at each end prior to inserting carrier pipe to prevent
damage to the carrier pipe. The casing vent at the lower elevation shall be attached to the bottom of the
casing and the other to the top of the casing. This provides for natural circulation through the vents. It also
allows for the ability to blow accumulated water out of the casing through the lower vent. Vent pipes shall
be constructed of carbon steel as delineated in Drawing E-33947 at the end of this specification.
The aboveground portion of vent pipes shall be coated with paint (tape-wrapping below ground is not
required). The vent shall be installed to prevent water or other debris from entering the vent opening.
Casing Insulators - For plastic carrier pipelines, install casing insulators as needed to slip pipe smoothly
into casing. Install two casing insulators at each end of casing to assure plastic carrier pipe does not
come in contact with end of casing.
The leading end of the carrier pipe shall be closed before insertion and the pipe inspected for damage at
the leading end after the installation by using a flashlight to illuminate the interior of the casing. Any
significant gouging of the pipe wall (polyethylene carrier pipeline) must be repaired or replaced as
described in Specification 3.33, Repair of Plastic (Polyethylene) Pipe.
End Seals— Boot type seals shall be used to seal casing ends when plastic carrier pipe is installed. The
carrier pipe shall be supported to keep the proper concentric alignment when installing these types of
seals.
For plastic pipe that is encased in steel, maintain continuity of the tracer by insertion of tracer wire along
with the plastic through the steel casing. Refer to Drawing B-34947 at the end of this specification.
The bottom of the trench adjacent to each end of the casing shall be graded to provide firm, uniform, and
continuous support for the carrier pipeline.
PIPE SYSTEMS REV. NO. 20
CASING & CONDUIT INSTALLATION DATE 01/01/25
X V'ISTa STANDARDS 4 OF 8
Utilities NATURAL GAS SPEC. 3.42

Casing pipe containing plastic main, or service shall not be subjected to excessive heat. As a result,
bridge casings should be hung either under or within bridge structures to avoid the heating effects of
direct sunlight.
Casing pipe containing plastic main, or service pipe shall not be squeezed or deformed except in an
emergency. If this is necessary, the casing and plastic carrier pipe shall be replaced. Refer to
Specification 3.33, Repair of Plastic(Polyethylene) Pipe.
Conduits
The use of conduits should be discouraged. Occasionally it is necessary to install a conduit to enable
road construction, etc., prior to installation of a plastic gas main or service.
Plastic conduit may only be used for polyethylene carrier pipeline if it provides sufficient strength to
withstand anticipated stresses due to overburden, bending, torsion, and temperature change and is
approved by permitting agency.
Only gray or yellow plastic conduit should be used. Conduit should be clearly marked or labeled to
indicate that a gas pipeline is housed within. One method is to wrap the conduit with yellow tape stamped
"Caution--Natural Gas" in "candy cane"fashion. No white plastic conduit shall be used as it may be
confused with water irrigation pipe.
Conduit should be sized to allow carrier pipe and tracer wire to pass easily through at the time of
insertion.
The bottom of the trench adjacent to each end of the conduit shall be graded to provide firm, uniform, and
continuous support for the carrier pipeline. Protection from sharp edges of conduit must be provided for
main and service inserts such as, but not limited to, a split piece of plastic pipe between the carrier pipe
and the edge of the conduit or use of a casing insulator. As the carrier pipe exits the conduit, ensure that
it does not scrape the end of the conduit.
Installed conduits should be properly noted on Company maps.
Inserted steel services may be referred to as a conduit, typically in regard to Avista's mapping procedures
within Avista's GIS System. This particular situation is the only non-plastic conduit for natural gas use at
the Company.
PIPE SYSTEMS REV. NO. 20
CASING & CONDUIT INSTALLATION DATE 01/01/25
XV'1STA STANDARDS 5 OF 8
utilities NATURAL GAS SPEC. 3.42

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CASING & CONDUIT INSTALLATION DATE 01/01/25
irisra STANDARDS 8 OF s
Utilities NATURAL GAS SPEC. 3.42

3.43 LAND DISTURBANCE REQUIREMENTS
SCOPE:
To establish uniform procedures related to gas construction land disturbance activities, identify permit
requirements, and establish excavation and sediment control Best Management Practices (BMP's).
REGULATORY REQUIREMENTS:
Federal—40 CFR 123.25(a), 122.26(a)(1)(v), 122.26(b)(14)(x), and 122.26(b)(15)
Idaho— Idaho Department of Environmental Quality(IDEA)
Washington —Washington State Department of Ecology (DOE)
Oregon—Oregon Department of Environmental Quality (DEQ)
Local Jurisdiction Critical Areas, Stormwater Erosion and Site Disturbance Regulations
CORRESPONDING STANDARDS:
Spec. 3.15, Trenching and Backfilling
General
Land disturbance and excavation activities require proper planning. Prior to excavation or land
disturbance associated with gas construction work, it is necessary to acquire the appropriate locates,
permits, easements, and in many cases to implement appropriate stormwater erosion control measures to
prevent inappropriate discharge of sediment off of the construction site. Additionally, some construction
areas fall within or near environmentally sensitive areas (e.g., floodplains, wetlands, streams, steep
slopes) and have prescriptive requirements regarding techniques for disturbed areas, as well as removal
and disposal of excavated material.
This specification shall apply to employees, contractors, activities, and land disturbance, directly or
indirectly associated with gas construction projects. Compliance with this specification will reduce the
potential negative impacts of construction activities and provide protection of stormwater, groundwater,
water bodies, watercourses, and wetlands consistent with the Clean Water Act requirements.
Gas related land disturbance and excavation activities shall be completed in accordance with this
specification and Specification 3.15, Trenching & Backfilling. Gas construction activity shall be performed
in a manner to minimize stormwater discharge from the construction site. Temporary erosion and
sediment control measures shall be removed after final site stabilization has occurred.
Necessary action shall be taken to minimize the depositing and tracking of mud, dirt, sand, gravel, rock,
or debris onto public or private roads, driveways, parking lots, and the like.
Acquisition and adherence to appropriate permits and implementation of sediment control best
management practices (BMP's)are necessary steps related to excavation activities. A list of land
disturbance activities, required permits, and excavation requirements is detailed in Table 2.
Definitions
BEST MANAGEMENT PRACTICES (BMPs): Acceptable techniques that can be implemented to protect
water quality caused by development or construction activities. A BMP can be a policy, practice,
procedure, technology, structure, or device that controls, prevents, or removes discharges not meeting
water quality standards.
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Utilities NATURAL GAS SPEC. 3.43

CESCL: Certified Erosion & Sediment Control Lead. A person that has been certified by the authorized
state jurisdiction to conduct construction site inspections to ensure stormwater mitigation measures are
being followed as specified in the Stormwater Pollution Prevention Plan.
CONSTRUCTION GENERAL PERMIT: A permit issued by the regulatory entity having jurisdiction in a
state that provides guidelines construction operators should follow to comply with the requirements of the
federal stormwater regulations.
DOE: Washington State Department of Ecology
EPA: United States Environmental Protection Agency
EROSION: The wearing away of the land surface by water, wind, ice, or gravity.
EROSION AND SEDIMENT CONTROL PLAN (ESC): The ESC is a drawing detailing where and what
types of Best Management Practices (BMPs)are to be used to control stormwater pollution during and
after construction, as well as methods for final stabilization. This plan is typically required as a part of the
permit process and also a subpart of a larger document known as the Stormwater Pollution Prevention
Plan (SWPPP).
IDEQ: Idaho Department of Environmental Quality
NOTICE OF INTENT (NOI): A form filed with the appropriate regulatory entity before beginning
construction when required to secure a Construction General Permit.
NOTICE OF TERMINATION (NOT): A form filed with the appropriate regulatory entity when construction
activities have ended as a requirement of the Construction General Permit.
ODEQ: Oregon State Department of Environmental Quality
SEDIMENT: Any soil particles or solid material that have been moved by erosion from the place where
they were formed.
TACKIFIER: A chemical or organic compound sprayed on loose soil to hold it in place.
STORMWATER POLLUTION PREVENTION PLAN (SWPPP): A site-specific written document that
identifies potential sources of stormwater pollution, describes best management practices to reduce
pollutants and the volume of stormwater discharges from a construction site and identifies procedures the
operator will implement to comply with the terms and conditions of a general construction permit. The
written plan describes how stormwater runoff at a construction site will be controlled, temporary erosion
control measures, final stabilization measures, monitoring requirements, and contacts.
Storm Water Permitting Requirements
The Clean Water Act and associated federal regulations require nearly all construction operators
engaged in clearing, grading, and excavating activities that disturb one acre or more and have
potential to discharge to surface waters or wetlands (including through storm drains and ditches),
including smaller sites in a common plan of development or sale, to obtain coverage under a National
Pollutant Discharge Elimination System (NPDES) permit for their stormwater discharges. Under the
NPDES program, the U.S. Environmental Protection Agency (EPA) can authorize states to implement the
federal requirements and issue stormwater permits. Washington, Idaho, and Oregon are authorized to
issue their own permits for construction activities. In Washington, NPDES permits are issued by the
CONSTRUCTION REV. NO. 6
LAND DISTURBANCE REQS DATE 01/01/22
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Utilities NATURAL GAS SPEC. 3.43

Department of Ecology (DOE), in Idaho they are issued by the Idaho Department of Environmental
Quality (IDEQ), and in Oregon they are issued by the Department of Environmental Quality (DEQ). Refer
to Table 1 for permitting requirements.
An Avista Environmental Permitting Specialist will help facilitate identification and acquisition of proper
permits related to construction activities and development of Stormwater Pollution Prevention Plan's
(SWPPP)when required. Refer to Table 1 and Table 2 in this specification for more details on permitting
requirements. Avista may construct under another developer or third party contractor's permit when the
permit specifies the inclusions of"utilities". The Avista Environmental Permitting Specialist can provide
guidance when it is appropriate and acceptable to construction under a third-party permit.
Gas construction activity undertaken in accordance with an approved Erosion and Sediment Control
(ESC) Plan or permit must comply with the conditions of the plan and relevant permits.
Table 1 —Stormwater Erosion Control Guidance If Disturbing Greater Than One Acre
SWPPP Required Yes Yes Yes
ESC Required Yes No No
NOI Required Yes Yes Yes
NOT Required Yes Yes Yes
Permit fees Yes Yes No
Certified Inspector Yes Yes Yes
Needed
Land Use Compatibility Yes No No
Statement Required
State Environmental
Policy Act (SEPA) No Yes No
Submission Required
Newspaper publication Yes, DEQ does Yes, once each week for No, after filing NOI,
the notification >5 2 weeks. Applicant does construction can start
acres notification
Permit name 1200 C Permit General Construction General Construction
Permit Permit
File online No Yes Yes
File hard copy Yes No Yes
Governing jurisdiction DEQ and the
Rogue Valley DOE IDEQ
Sewer District
Documentation stored 3 years minimum 3 years minimum Not mentioned
Processing time 30-60 days 60 days 14 days
Low Erosivity Waiver No Yes Yes
• Idaho is under the jurisdiction of IDEQ.
• Oregon is under the jurisdiction of DEQ, and Washington is under jurisdiction of DOE.
• Oregon has two jurisdictions that are the reviewing party depending on the location of the project.
• In Oregon,for projects greater than 20 acres in disturbance, an Oregon licensed professional is required to
complete the ESC.
• In Washington,field inspectors(monitors)of the SWPPP are required to have their CESCL(Certified Erosion
and Sediment Control Lead)certification.
• In Oregon, certification is required to inspect soil erosion control measures.
• Idaho has its own certification program for projects requiring a General Construction Permit. The program is
called the Stormwater and Erosion Education Program (SEEP). Typically, EPA will require monitoring personnel
in Idaho to be SEEP or CESCL certified.
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Utilities NATURAL GAS SPEC. 3.43

Best Management Practices (BMPs)
In order to enhance sediment control activities at construction sites Best Management Practices (BMPs)
shall be implemented for land disturbance construction activities regardless of land disturbance size as
described in this section and Exhibit A. If the project will disturb one acre or more, contact the Avista
Environmental Permitting Specialist as mentioned previously to get assistance with permitting and
SWPPP development. For projects where land disturbance will be less than one acre, it is still
incumbent upon the construction crew and others involved to consider all potential BMPs and to
implement those that would support good stewardship of the project site. It is particularly important
to protect drains and direct pathways that flow to a stream or water body.
Following is an overview of the four major BMP groupings and the specific individual BMPs that fall within
the groupings. The more commonly used BMPs are underlined and further detailed at the end of this
specification; however, BMPs are not limited to this list. Work in and near water typically requires
environmental permitting and strict adherence to BMPs. Temporary BMPs should be removed after sites
are stabilized. Contact the Avista Environmental Permitting Specialist and Gas Engineering for
further assistance in choosing the proper BMPs for a gas construction project.
1. Planning BMPs
• Contractor Education— Providing copies of the ESC/SWPPP/ BMPs to crew leaders.
Having discussions regarding sensitive areas to avoid during construction, reviewing spill
response procedures, setting up regular meeting times, and providing contact
information.
• Buffer Zone— Protecting existing vegetation adjacent to the project provides a stabilized
area which will help control erosion, protect water quality, and enhance aesthetic
benefits.
• Phased Construction —Scheduling the project to reduce the amount and duration of soil
exposed to erosion effects of rain, wind, etc.
• Clearing Limits—Clearing the smallest area practical for the shortest time possible to
complete the project.
• Perimeter Control— Doing prior planning and implementing any sediment or erosion
control BMP at the perimeter of the project to prevent sedimentation damage to the
construction site or nearby property.
• Source Control— Designing material storage and handling practices to prevent or
reduce the discharge of pollutants into groundwater systems. Some examples are
minimizing the storage of hazardous material on site, storing such materials in
designated areas, installing temporary secondary containment, and conducting regular
inspections.
• Stockpile Management— Designing procedures to eliminate or reduce air and
stormwater pollution from stockpiles of soil, paving materials, rubble, and the like.
Process may involve some type of perimeter sediment barrier or be as simple as
covering the stockpile with tarps or other protective means.
• Concrete Washout—Designating a containment area for washout of cement truck
delivery chutes and related equipment.
• Temporary Restrooms— Doing prior planning to order and use temporary restroom
facilities (i.e., Porta Potties).
• Stabilized Construction Entrance/ Exit— Establishing an area to minimize the tracking
of mud and dirt onto nearby roads.
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Utilities NATURAL GAS SPEC. 3.43

2. Erosion Control BMPs
• Slope Roughening—Typically involves forming horizontal depressions along a
construction slope with tracked or treaded equipment to form grooves that are
perpendicular to the slope. This method stabilizes soils and reduces runoff velocity,
encourages the growth of vegetation, and trap some sediment.
• Mulching—A temporary measure stabilizing soil and controlling erosion by placing a
material like straw, grass, hay, compost, wood chips, or wood fibers on top of or
incorporated into the soil surface.
• Hydromulching—Similar to mulching except the mixing of a tackifier is combined to the
mulch and water to form a slurry mix that is then broadcast on the soil surface to help
ensure the mulch stays in place.
• Hydroseeding—Similar to hydromulching that typically consists of applying a mixture of
mulch fiber, grass seed, fertilizer, and a stabilizing tackifier to the soil surface.
• Erosion Control Blankets— Installing a porous net or fibrous sheet mats that are then
placed over the ground surface to stabilize slopes and control erosion.
• Dust Control—Controlling dust pollution by any method such as water sprinkling,
vegetative covering, tackifier installing, or surface roughening. Water should be obtained
through an approved source and may not be withdrawn from water bodies without proper
water rights or permits.
3. Sediment Control BMPs
• Vegetative Buffer Strip— Using a living sediment barrier that consists of a gently sloping
area of vegetative cover that runoff water flows through before entering a water feature.
This buffer area may be an undisturbed strip of natural vegetation or a graded and
planted area.
• Sediment Trap/ Basin —Constructing a containment area formed by excavation and/or
embankment to intercept and retain sediment-laden runoff. The trap/ basin must be large
enough to allow most of the sediment to settle out and consequently are usually
professionally designed.
• Silt Fence— Using a temporary sediment barrier consisting of a filter fabric stretched and
attached to supporting posts. Silt fences function by impounding water and slowly
releasing it, allowing sediment to settle out and collect behind (upstream of)the fence.
• Fiber Roll /Straw Wattle— Using a temporary sediment barrier that consists of straw,
flax, coconut fiber, compost, or other similar materials bound into a biodegradable tubular
casing. When properly placed at the toe and on the face of slopes, they intercept runoff,
shorten slope length, decrease flow velocity, and trap sediment.
• Inlet Protection—Using temporary devices (wattles, sediment fences, etc.) constructed
to improve the quality of water being discharged to dry wells, drop inlets, or catch basins
by pooling sediment-laden runoff and thereby increasing settling time.
4. Run-off Control BMPs
• Swales and Dikes— Installing a temporary channel to prevent runoff from entering
disturbed areas by intercepting and diverting it to a stabilized outlet or a sediment-
trapping device.
• Grassy Swales—Designing grassed shallow depressions in the earth constructed to
hold stormwater while the grass and underlying soil and rock filter out various pollutants.
• Check Dams—Constructing a small dam of rocks, logs, or brush and located in an open
channel, swale, or drainage area in order to reduce or eliminate excessive erosion by
reducing runoff velocity.
• Slope Drains— Using a device to transport concentrated runoff from the top to the
bottom of a slope that is at elevated risk for or has already been damaged by erosion
without further damaging the slope.
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Utilities NATURAL GAS SPEC. 3.43

• Outlet Protection — Installing various forms of protection (rock, riprap, etc.) at the outlets
of pipes, culverts, catch basins, sediment basins, etc. where the velocity of water flow
may cause erosion.
• Terracing —Constructing an earth embankment or ridge-and-channel arrangement along
the face of a slope at regular intervals that serves to reduce erosion by capturing surface
runoff and directing it to a stable outlet at a speed that minimizes erosion.
Table 2—Construction Activities Tvpical Governinc Aciencies and Associated Permits
Construction Permit— Governing
Activity Category Agency Location Permit Notes
Land Erosion Control ID-IDEQ ID Lands General Required for disturbance of
Disturbance Construction land> 1 Acre and potential to
Permit SWPPP discharge to surface water or
(Storm Water wetlands. Permit will include
Pollution BMP's.
Prevention Plan
Land Erosion Control WA—DOE WA Lands General Required for disturbance of
Disturbance Construction land=/>1 Acre and potential
Permit SWPPP discharge to surface water or
(Storm Water wetlands. Permit will include
Pollution BMP's.
Prevention Plan
Land Erosion Control OR—DEQ OR Lands NPDES-1200C Required for disturbance of
Disturbance land> 1 Acre and potential to
discharge to surface water or
wetlands. Permit will include
BMP's.
Land Navigable Army Corp.of ID,OR,WA Section 10 Required to cross over or
Disturbance waters under Engineers under the navigable waters
COE jurisdiction. COE
Wetland Critical Area Army Corp.of Federal COE 404 Permit Required to disturb or
Disturbance Permit Process Engineers wetlands and discharge into a wetland
(COE) Lands
classified by
Army Corp.
Wetland Critical Area WA-Local Non-Federal Local Local jurisdictions follow WA-
Disturbance Permit Process Jurisdiction, wetlands Jurisdictional DOE guidance
City or County Permit
Wetland Critical Area OR-Division of Non-Federal Permit Work may require a permit
Disturbance Permit Process Lands and/or wetlands from Local Jurisdiction(City
Local or County)and a Division of
Jurisdiction Lands Permit. Check w/
(City or Count Local Jurisdictions.
Wetland Critical Area ID-DEQ Non-Federal Permit
Disturbance Permit Process Lands
Flood Plain Critical Area City or County City or County No-Rise City and County jurisdictions
Disturbance Permit Process Lands Certificate or implement FEMA rules
Permit
Steep Slopes Critical Area City or County City or County Permit from Governing rules follow local
Disturbance Permit Process Lands Governing ordinances. Applies to
Jurisdiction disturbance of steep slopes.
Geological Critical Area City or County City or County Permit from Governing rules follow local
Hazards Permit Process Lands Governing ordinances. Applies to
Jurisdiction disturbance of geological
formations. Ex. Hot Springs,
Earthquake Zones, Unstable
Soils,etc.
CONSTRUCTION REV. NO. 6
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�rsr�r STANDARDS 6 OF 10
Utilities NATURAL GAS SPEC. 3.43

Table 2—Construction Activities Tvpical overnina A encies and Associated Permits Cont.
Construction Permit— Governing
Activity Category Agency Location Permit Notes
Cultural Local,State or State Historic All Lands Section 106 Required for disturbance of
Resources Federal Permit Preservation Permit known sites.
Review Process Office
Grading/Filling Grading/Site City or County City or County Permit from Required when changing
Disturbance Lands Governing grade and movement of soil.
Permit and ESC Jurisdiction Governing jurisdiction
Plan determines the amount of soil
when a permit is required.
Bores-Initiated HPA or SEPA WA-Local Bores Under SEPA(State Required for work within
above High Jurisdiction Water Environmental buffer zone of waterways.
Water Mark or processes the Features Policy Act)and Buffer zone size varies on
work within SEPA. WDF HPA(Hydraulic type of waterway.
buffer zone of issues the HPA Project Approval
waterways. w/Washington
Fish and Wildlife.
Bores-Initiated ID-Dept.of Bores on Easement
above High Lands private
Water Mark property under
water bodies.
Bores-Initiated ID-Idaho Bores under Stream alteration
above High Dept.of Water land not permit.
Water Mark Resources covered by
Dept.of
Lands.
Bores-Initiated OR-No Permit No permit required. Courtesy
above High Required notification to Department of
Water Mark unless under Fish and Wildlife.
Section 10
Waters
Bores Initiated WA/ID/OR- All lands below Section 10 Permit
below High Army Corp.of high water
Water Mark, Engineers mark or
Working in Section 10
stream bed,or Waters
under Section 10
Waters
Flood Plain Critical Area City or County City or County No-Rise City and County jurisdictions
Disturbance Permit Process Lands Certificate or implement FEMA rules
Permit
Construction Fire Restrictions ID- Required on all Exemption Permit Required in hot dry weather.
Activities Department of Public and Available
Lands Private lands
Construction Fire Restrictions WA-Local fire Exemption Permit Required in hot dry weather.
Activities districts Available
Construction Fire Restrictions OR-Roseburg Exemption Permit Required in hot dry weather.
Activities Fire Protection Available
Association or
Local fire
districts
Construction Shoreline Permit WA Construct Permit Covered waters include but
Activities within 200'of are not limited to: Spokane
covered River, Latah Creek,Colville
waters River, Pend Oreille River.
Flood Plain Critical Area City or County City or County No-Rise City and County jurisdictions
Disturbance Permit Process Lands Certificate or implement FEMA rules
Permit
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Utilities NATURAL GAS SPEC. 3.43

Exhibit A—Common BMPs and How to Implement
1. Silt Fence Sediment Control BMP
4'-0" LONG WOOD POSTS
10'O.C. MAAMUM SPACING
WOVEN POLYPROPYLENE FILTER
FABRIC MATERIAL
__- _-- VLOW
FLOW-
_ - FLO+
FILTER FABRIC:ATTACH
SECURELY TO UPSTREAM
SIDE OF POST.
i
v
N
NQg: FILTER FABRIC FENCES SHALL BE RUNOFF
INSTALLED AND IN WORKING CONDITION
PRIOR TO ANY GROUND DISTURBANCE. 7 ;:•
4"TO 6" DEEP TRENCH
WITH COMPACTED NATIVE
BACKFILL.
MAINTENANCE STANDARDS:
1. SILT FENCES AND FILTER BARRIERS SHALL BE INSPECTED IMMEDIATELY AFTER EACH RAINFALL AND AT LEAST DAILY
DURING PROLONGED RAINFALL.ANY REWIRED REPAIRS SHALL BE MADE IMMEDIATELY.
2. IF CONCENTRATED FLOWS ARE EVIDENT UPHILL OF THE FENCE.THEY MUST BE INTERCEPTED AND CONVEYED TO A
SEDIMENT POND.
3. IT IS IMPORTANT TO CHECK THE UPHILL SIDE OF THE FENCE FOR SIGNS OF THE FENCE CLOGGING AND ACTING AS A
BARRIER TO FLOW AND THEN CAUSING CHANNELIZATION OF FLOWS PARALLEL TO THE FENCE. IF THIS OCCURS.
REPLACE THE FENCE OR REMOVE THE TRAPPED SEDIMENT.
4. SEDIMENT DEPOSRS SHALL EITHER BE REMOVED WHEN THE DEPOSIT REACHES APPROXIMATELY ONE-THIRD THE
HEIGHT OF THE SILT FENCE, OR A SECOND SILT FENCE SHALL BE INSTALLED.
5. IF THE FILTER FABRIC(GEOTEYTIL£) IS DAMAGED OR DETERIORATED, IT SHALL BE REPLACED IMMEDIATELY.
SILT FENCE
140T TO SCALE
CONSTRUCTION REV. NO. 6
LAND DISTURBANCE REQS DATE 01/01/22
��r�sra STANDARDS s OF 10
Utilities NATURAL GAS SPEC. 3.43

2. Fiber Roll /Straw Wattle Sediment Control BMP
50' MAX
0�
n
II t
�
I
1"xl" WOOD STAKE
18"-24" LONG i wit
SECTION
NOTES
1. STRAW WATTLES TO BE 8" DIAMETER AND 20' TO 30' LONG.
2. DIG 4"x9" TRENCH TO RECEIVE WATTLE. TRENCH SHOULD
FOLLOW CONTOUR OF SLOPE. BUTT ADJACENT WATTLES TIGHTLY.
3. STAKE TO BE SPACED 8" FROM EACH END AND NOT MORE THAN
6-FT O.C. DRIVE STAKES THROUGH THE CENTER OF THE
WATTLE AND PERPENDICULAR TO SLOPE LEAVING 2"-3" ABOVE
THE TOP OF WATTLE.
# STRAW WATTLE
NOT TO SCALE
CONSTRUCTION REV. NO. 6
LAND DISTURBANCE REQS DATE 01/01/22
��r�sra STANDARDS 9 OF 10
Utilities NATURAL GAS SPEC. 3.43

3. Rock Check Dam Run-off Control BMP
VARIADLE, DEPENDINC
UPON CHANNEL WIDTH
,.;,
co
ELEVATION
NOTE
1. USE ROCKS 3" TO 8" IN SIZE FOR CHECK DAM.
2. PLACE ROCKS SO DAM IS PERPENDICULAR TO THE FLOW . USE ROCKS OR
FILTER FABRIC TO FILL ANY GAPS AND TAMP BACKFILL MATERIAL TO
PREVENT EROSION OR FLOW AROUND DAM.
3. HEIGHT SHALL NOT EXCEED 18".
4. INSPECT AFTER EACH SIGNIFICANT STORM, MAINTAIN AND REPAIR AS
NEEDED.
ROCK CHECK DAM
NOT TO SCALE
CONSTRUCTION REV. NO. 6
LAND DISTURBANCE REQS DATE 01/01/22
��r�sra STANDARDS 10 OF 10
Utilities NATURAL GAS SPEC. 3.43

3.44 EXPOSED PIPE EVALUATION
SCOPE:
To establish uniform procedures for evaluating steel and plastic pipelines that are exposed that were
previously buried.
REGULATORY REQUIREMENTS:
§192.459, §192.475(b), §192.491, §192.1007(a)(1)(2)(3)
WAC 480-93-110(1), 480-93-110(6)(7)(8)
CORRESPONDING STANDARDS:
Spec. 3.12, Pipe Installation— Steel Mains
Spec. 3.13, Pipe Installation— Plastic (Polyethylene) Mains
Spec. 3.15, Backfilling and Trenching
Spec. 3.32, Repair of Steel Pipe
Spec. 3.33, Repair of Plastic(Polyethylene) Pipe
Spec. 4.42, Distribution Integrity Management Program
Spec. 5.11, Leak Survey
Spec. 5.14, Cathodic Protection Maintenance
General
When buried steel or plastic pipe is exposed an Exposed Piping Inspection Report(paper form N-2534 or
electronic version of this report form) shall be completed in accordance with this standard. Note: It is only
necessary to complete an Exposed Piping Inspection Report when a gas carrying pipe is exposed or a
pipe intended to carry gas in the future (i.e., dry line pipe) is exposed.
An Exposed Piping Inspection Report form is not necessary for the following conditions:
• Casings or conduits (including plastic pipe in galvanized steel with service head adapter)or
anodeless risers when no pipe is exposed.
• Pipe that has been abandoned or is actively in the process of being abandoned.
• Anodeless risers or risers with a service head adapter.
• Portions of risers that are aboveground and any other aboveground piping.
• Buried riser piping that is not exposed.
When retiring a steel service with a low cathodic read, the cathodic read recorded on the Exposed Piping
Inspection Report for the main should be taken after the service being retired has been disconnected
from the main.
The Exposed Piping Inspection Report is to be used to document both steel and plastic (PE) pipeline
facility information about each exposure of pipe that will remain a gas carrying pipe. The job-related
information and location shall be identified as detailed on the report. Applicable sections consistent with
the material exposed (Steel or Plastic)shall be completed. For electronic orders where a CP low read is
reported, field personnel should include the centerline measurements of the exposure in the comments
section.
MAINTENANCE REV. NO. 11
EXPOSED PIPE EVALUATION DATE 01/01/25
X-4, sr'a STANDARDS 1 OF 5
Utilities NATURAL GAS SPEC. 3.44

External Examination Plastic Pipe
The appropriate section of the Exposed Piping Inspection Report shall be used to capture information
about each exposure of pipe, including the external pipe information, the as-found condition of the pipe,
and the installation conditions. Specific information to be captured includes but is not limited to:
• Pipe material
• Pipe manufacturer
• Manufacture date and lot number
• Pipe color
• External pipe condition
• Internal pipe condition (as applicable)
• Products found inside pipe or on inside pipe wall
• As-found soil in contact with the pipe
• As-left soil type in contact with the pipe
• If a previous squeeze-off location is present in the exposed area for PE material
• If the pipe was squeezed during the current exposure
• If contaminated soil is present (Contaminated soil means the exposed soil smells of petroleum.)
If the print line or information is not readable, then check the appropriate boxes that indicate
"Unidentifiable". This indicates that an attempt was made to capture this information but that it was not
readable.
Note: If during the exposure, the tracer wire is found to be separated from the pipe, the tracer wire shall
be relocated next to the plastic pipe and in a straight line to facilitate accurate pipe locating.
Examining Buried Steel and Pipe Coating
When a buried steel pipeline is exposed, it must be examined for evidence of external corrosion and
coating deterioration. The inspection includes noting the type of pipe coating and the coating bond
condition upon exposure, condition of external pipe if the coating has been removed, and documentation
of rust and pitting. If pitting is found, it shall be measured with a pit gauge and the depth and width of the
pitting shall be noted in the Exposed Piping Inspection Report form. The pit depth shall be measured in
decimal inches, e.g., 0.050-inches. The width of the pit shall be recorded in fractions of inches in 161h inch
increments, for example, 1-3/16-inches.
Remedial action must be taken to the extent required, as referenced in the repair charts found in
Specification 3.32, Repair of Steel. When corrosion is found and it extends beyond what is exposed, then
the adjacent pipe must also be exposed and investigated to determine to what extent corrosion exists.
Pipe shall further be exposed until at least 3 feet of adjacent pipe is found to be corrosion-free.
A pipe-to-soil read shall be taken and recorded when the coating needs to be repaired or removed. This
information shall be recorded on the Exposed Piping Inspection Report. Refer to Pipe-to-Soil Procedures
in Specification 5.14, Cathodic Protection for details.
(Note: A pipe-to-soil read is not needed on risers if no below ground riser piping is exposed.)
(Note: A pipe-to-soil read is not needed when coating is damaged by a third-party excavator and the pipe
is not accessible for a pipe-to-soil read due to the nature of the excavation.)
MAINTENANCE REV. NO. 11
EXPOSED PIPE EVALUATION DATE 01/01/25
X-4, sr'a STANDARDS 2 OF 5
Utilities NATURAL GAS SPEC. 3.44

Examining Buried Portion of Steel Risers
When soil is removed from around a buried steel carrier riser, an Exposed Piping Inspection Report is
required. This does not include anodeless risers or risers with a service head adapter. (Note: it is not
necessary to fill out an Exposed Pipe Report for the part of the riser that is aboveground. If no buried riser
piping is exposed, no Exposed Piping Inspection Report is needed.)
Field personnel need to remove the soil around a steel carrier pipe riser where there is no wrap or poorly
bonded wrap that comes aboveground. Dig until well bonded wrap is found and then rewrap it to above
grade level per the requirements of Specification 3.12, Steel Mains, "Tape Wrap." This includes anytime
field personnel are digging up around the riser below grade level. If there is pipe wrap that comes above
grade and the field employee is only brushing back built-up dirt or debris back to grade level, then no
Exposed Piping Inspection Report or pipe-to-soil read is required.
If the riser type cannot be determined, the riser shall be dug up and exposed until the riser type is
determined. Exposed riser information to be documented on the Exposed Piping Inspection Report form
includes:
• Depth in inches that the soil was removed from around the riser.
• Length exposed will most likely be the same as the depth in inches; however, this is recorded in
feet, i.e., 1 inch = 0.08 of a foot, 2 inches = 0.17 of a foot, 3 inches = 0.25 of a foot, etc.
• Coating type for steel risers that have a painted coating; choose "Other," "Riser/gray paint," or
"Riser/green paint," etc. Otherwise, choose one of the appropriate coatings.
Coatinq Bond Condition Classifications:
(If bare pipe is noted in the "coating type"section, then no coating bond information is required since no
coating is present.)
Bonded:The coating provides a continuous barrier, and no defects are observed.
Unbonded:The coating has degraded to the point that areas of corrosion are detected on the surface,
coating holidays exist, or the coating is visibly dis-bonded from the surface of the pipe. (Note: A pipe-to-
soil read is required on the Exposed Piping Inspection Report form for unbonded conditions if bare metal
can be seen.)
Soil Type Descriptions:
Sand:A sedimentary material that is finer than granule and coarser than silt.
Loam:Soil that has no or few rocks or pebbles but has some peat or peat-like elements in the soil.
Clay:Very fine soil that becomes slimy or plastic when mixed with water and compacts tightly and is hard
to remove from the ditch and boots.
Rocky: Soil that contains rock, angular or rounded, in substantial concentration.
Concrete/Grout: Material composed of concrete as well as other cementitious materials such as fly ash,
slag cement, or aggregate materials mixed with water and allowed to harden.
Controlled-Density Fill(CDF):A self-compacting, flowable cementitious material used primarily as a
backfill in lieu of compacted backfill.
MAINTENANCE REV. NO. 11
EXPOSED PIPE EVALUATION DATE 01/01/25
X-4, sr'a STANDARDS 3 OF 5
Utilities NATURAL GAS SPEC. 3.44

Low Cathodic Protection (CP) Read Identified
If a low read is found, it shall be reported to the CP Low Field Reading Reporting Hotline as soon as
possible. If the report is not submitted via the mobile computer, then Fax or email a picture of the
completed paper Exposed Piping Inspection Report(form N-2534)to the following:
Low Read Hotline: Primary: 877-800-3770 Alternate: 509-495-2258
Fax or Email to: Fax: [phone] Email: [e-mail]
The hotline will no longer provide prompts for the required information. When calling the hotline be
prepared to provide the following information:
• First and last name
• State the cathodic protection read was taken in (ID, OR, or WA)
• The date (month, day, and year)the low cathodic protection read was taken
• Address or location where the read was taken, be as specific as possible
• City
• Pipe-to-soil read
• Any additional comments
Internal Steel Pipe Examination
When steel pipe is removed from a pipeline for any reason, the internal surface must be inspected for
evidence of corrosion (rust or pitting)and if the inside wall is clean, dirty, or oily, and if there are puddles
of water, oil, or black sludge in the pipe. If pitting is found, it shall be measured with a pit gauge and the
depth and width of the pitting shall be noted in the appropriate section of the Exposed Piping Inspection
Report form.
If internal corrosion is found refer to"Internal Corrosion Control" in Specification 5.14, Cathodic Protection
Maintenance.
Internal PE Pipe Examination
When pipe is removed from a pipeline or cut apart for any reason, the internal surface of the plastic pipe
shall be inspected to determine if the inside wall is clean, dirty, or oily, and if there are puddles of water,
oil, or black sludge in the pipe.
Pipeline Inspection Camera
If indications of internal corrosion with pitting is observed refer to"Internal Corrosion Control' in
Specification 5.14, Cathodic Protection Maintenance.
Compliance
The exposed pipe process utilizes both electronic and paper documents to capture gas pipe field data as
presented on the Exposed Piping Inspection Report form. Information captured on the paper Exposed
Piping Inspection Report form shall be recorded electronically within the Avista document retention
system.
MAINTENANCE REV. NO. 11
EXPOSED PIPE EVALUATION DATE 01/01/25
X-4, sr'a STANDARDS 4 OF 5
Utilities NATURAL GAS SPEC. 3.44

Records Retention
Avista shall maintain the exposed pipe records for the life of the pipeline facility or 10 years whichever is
longer.
Examples of Pipe Exposures
Below are examples of when an Exposed Piping Inspection Report form is required to be filled out
(multiple Exposed Piping Inspection Report forms may be required depending on what is exposed in the
ditch or bell hole):
• Where multiple mainline coating types for steel pipe exist within the open ditch, an Exposed
Piping Inspection Report is required for each coating type and an additional Report is required if
the condition of the pipe under the coating changes. An additional Exposed Piping Inspection
Report is not required for a change in coating type for the weld joint or a fitting, only for a change
in the mainline pipe coating.
• Where pipe diameter changes within the open ditch.
• On either side of a dresser fitting or isolation fitting within the open ditch.
• On a pipeline that remains energized within the open ditch for a pipe abandonment, replacement,
or removal. (Including service stubs; no minimum length is exempt).
• Where each service lateral is exposed within the open ditch.
• Steel gas carrying risers that are uncovered below grade level.
MAINTENANCE REV. NO. 11
EXPOSED PIPE EVALUATION DATE 01/01/25
X-4, sr'a STANDARDS 5 OF 5
Utilities NATURAL GAS SPEC. 3.44

4.0 OPERATIONS
4.11 CONTINUING SURVEILLANCE
SCOPE:
To establish a procedure for continuous monitoring of Avista's pipelines and facilities in order to
determine the extent of changes in class locations, changes or trends in leakage history, changes or
trends in corrosion or cathodic protection requirements, updating and correcting mapping data, and
identification of other unusual operating or maintenance requirements.
REGULATORY REQUIREMENTS:
§192.465, §192.481, §192.605, §192.609, §192.611, §192.613, §192.619, §192.620, §192.705,
§192.706, §192.721, §192.723
WAC 480-93-017, 480-93-018, 480-93-180, 480-93-187, 480-93-188, 480-93-200
CORRESPONDING STANDARDS:
Spec. 4.14, Recurring Reporting Requirements
Spec. 4.31, Operator Qualification
Spec. 5.11, Leak Survey
Spec. 5.14, Cathodic Protection Maintenance
Spec. 5.15, Pipeline Patrolling and Pipeline Markers
General
The Maintenance (5.0) and Operations (4.0)sections of the Gas Standards Manual comprise Avista's
Continuing Surveillance program. When maintenance and operations activities are performed, it allows an
opportunity for continuous monitoring of procedures, pipelines, and facilities.
Information Analysis and Responsibilities
Operations Managers shall be responsible for making initial determinations regarding conditions or
situations on pipelines and facilities that require a special analysis or possible action. Hazardous or
potentially hazardous conditions that may affect life, property or the environment shall be corrected
immediately upon discovery or as soon as possible under regulatory code and company standards.
Employees in each construction area shall receive training to be able to recognize conditions that may be
subject to safety related reporting requirements or that may require action to prevent the formation of an
immediate hazard.
Information pertaining to potentially hazardous conditions, especially those that indicate a trend or
system-wide problem, shall be reported, and discussed with appropriate Gas Engineering personnel and
the Gas Pipeline Integrity Program Manager. An analysis shall be performed to determine if mitigating
action should be taken to forestall a hazardous situation. The review of this information should be
conducted periodically. Consideration shall be given to using centralized maps, map overlays, etc. to
visually analyze areas of corrosion, leakage, soil subsidence, failures, and other unusual conditions.
As soon as it is determined that a trend has possibly developed in such above-mentioned conditions, Gas
Engineering and/or the Gas Pipeline Integrity Program Manager shall initiate additional surveys in order
to make a final determination on what action is appropriate.
OPERATIONS REV. NO. 16
CONTINUING SURVEILLANCE DATE 01/01/25
X-4, sr'a STANDARDS 1 OF 2
Utilities SPEC. 4.11
NATURAL GAS

The required mitigation shall be communicated to the affected construction area(s) as soon as
practicable. In cases where a segment of pipeline is involved, a program to recondition or phase out the
segment shall be initiated. If the segment cannot be reconditioned or phased out, the MAOP of that
pipeline system shall be reduced per§192.619 and §192.620. In the case where other gas facilities are
involved, the appropriate repairs or replacements shall be completed as soon as possible.
Extreme Weather Event or Natural Disaster— Transmission Pipeline Facilities Inspection
Following an extreme weather event or natural disaster that has the likelihood of damaging pipeline
facilities by scouring or movement of the soil surrounding the pipeline, movement of the pipeline itself, or
induced heat or fire damage, all potentially affected transmission pipeline facilities shall be inspected to
detect conditions that could adversely affect the safe operation of the pipeline. The TIMP Program
Manager will typically trigger this inspection following a severe weather event, but it can be initiated by
Gas Engineering or local operations as well. The inspection should utilize the Gas Patrolling Report form
(N-2629). The following are situations where inspections shall be performed:
• Flood that exceeds the river or creek high-water banks in the area of the pipeline
• Landslide in the area of the pipeline
• Earthquake in the area of the pipeline
• Above ground facilities in proximity to a forest fire
The requirements for the inspection are as follows:
1. Assess the nature of the event and the physical characteristics, operating conditions, location, and
prior history of the affected pipeline in determining the appropriate method for performing the initial
inspection to determine the extent of any damage and the need for any additional assessments.
2. The inspection must commence within 72 hours after the point in time that the affected area can be
safely accessed by personnel and equipment, and the personnel and equipment required to
perform the inspection are available. If an inspection cannot be commenced within 72 hours due to
the unavailability of personnel or equipment, the PHMSA Region Director shall be notified as soon
as practicable.
3. Prompt and appropriate remedial action shall be taken to ensure the safe operation of the pipeline
based on the information obtained as a result of the inspection. Such actions might include, but are
not limited to:
a. Reducing the operating pressure or shutting down the pipeline.
b. Modifying, repairing, or replacing any damaged pipeline facilities;
c. Preventing, mitigating, or eliminating any unsafe conditions in the pipeline right-of-way;
d. Performing additional patrols, surveys, tests, or inspections;
e. Implementing emergency response activities with Federal, State, or local personnel; or
f. Notifying the affected communities of the steps that can be taken to ensure public safety.
Note: Although this guidance is required for transmission pipeline facilities, similar assessment and
inspection is recommended if similar extreme weather events or natural disasters occur in the proximity of
distribution pipeline assets.
Map and Data Corrections
Occasionally data or mapping discrepancies are identified by field personnel and construction
contractors. These discrepancies require an editor to make the map/data correction. Mapping and data
corrections shall be submitted by the individual who identified and validated the discrepancy. Request for
corrections should be submitted along with the information included on the "Map/Data Correction Form"
(Form N-2672)to the appropriate office for editing. In Washington State, map corrections shall be
completed within 6 months following the completion of field work. In Idaho and Oregon this is a best
management practice.
OPERATIONS REV. NO. 16
CONTINUING SURVEILLANCE DATE 01/01/25
X-4,15y' a STANDARDS 2 OF 2
Utilities SPEC. 4.11
NATURAL GAS

4.12 SAFETY-RELATED CONDITIONS
SCOPE:
To establish procedures to be followed in the event that safety-related conditions are found to exist on
Avista's pipelines or facilities that require action and/or reporting under State or Federal guidelines.
REGULATORY REQUIREMENTS:
§191.3, §191.23, §191.25, §192.605
WAC 480-93-180, 480-93-200
CORRESPONDING STANDARDS:
Spec. 4.11, Continuing Surveillance
Spec. 5.14, Cathodic Protection Maintenance
Spec. 5.15, Pipeline Patrolling - Pipeline Markers
General
Gas operations employees shall be familiarized through review of this section with conditions and
situations that constitute an actual or potential safety-related condition. Employees that discover such
conditions shall report all pertinent facts to their applicable Operations Manager immediately. Gas
Engineering shall then be notified so that they may make an evaluation and recommendations for
correction or repair of the condition, as appropriate.
Corrective action shall be taken to eliminate or minimize any hazardous conditions that are discovered.
Such actions shall include, but are not limited to:
• In the case of corrosion, reducing the operating pressure to a pressure commensurate with the
strength of the pipe based on the actual remaining wall thickness.
• Repairing corroded pipe if the area of general corrosion is small.
• Replacing pipeline segments with corrosion pitting or general corrosion.
• Repairing or replacing facilities that may have failed or caused a pipeline pressure to exceed the
MAOP, plus build-up.
• Shutting down any pipeline or facility where an immediate hazard exists.
Reporting of Safety-Related Conditions
Gas Engineering with the assistance of the Pipeline Safety Engineer shall assess and report (as
necessary)the conditions found to exist on company facilities or pipelines that constitute an actual or
potential safety-related condition as defined in §191.23.
OPERATIONS REV. NO. 13
SAFETY-RELATED CONDITIONS DATE 01/01/24
X-4, sr'a STANDARDS 1 OF 3
Utilities NATURAL GAS SPEC. 4.12

The following safety-related conditions discovered on pipelines and facilities shall be reported:
• In the case of a pipeline operating at a hoop stress of 20 percent or more of specified minimum
yield strength (SMYS), in which general corrosion has reduced the wall thickness to less than that
required for the maximum allowable operating pressure (MAOP), and localized corrosion pitting
exists to a degree where leakage might result.
• Unintended movement or abnormal loading by environmental causes, such as earthquake,
landslides, or flooding, which impairs the serviceability of a pipeline.
• Any material defect or physical damage that impairs the serviceability of a pipeline that operates
at a hoop stress of 20 percent or more of SMYS.
• Any malfunction or operating error of pressure limiting or control devices that causes the pressure
of a distribution pipeline to exceed its MAOP plus the allowable build-up.
• A leak in a pipeline that constitutes an emergency.
• Any safety-related condition that could lead to an imminent hazard and causes (either directly or
indirectly by remedial action of the operator), for purposes other than abandonment, a 20 percent
or more reduction in operating pressure or shutdown of operation of a pipeline.
• For transmission pipelines only, each exceedance of MAOP plus allowable build-up for operation
of pressure limiting or control devices as specified in the applicable requirements of§192.201,
§192.620(e), and §192.739.
Exceptions to Reporting Safety-Related Conditions
A report is not required for any safety-related condition that:
• Exists on a master meter system, a reporting-regulated gathering pipeline, or a customer-owned
service line.
• Is an incident or results in an incident before the deadline for filing the safety-related condition
report.
• Exists on a pipeline that is more than 220 yards (660 feet)from any building intended for human
occupancy or outdoor place of assembly. Exception: Reports are required for conditions within
the right-of-way of an active railroad, paved road, street, or highway.
• Is corrected by repair or replacement in accordance with applicable safety standards before the
deadline for filing the safety-related conditions report. Exceptions: Reports are required for
transmission pipelines where corrosion has reduced the wall thickness to less than that required
for the maximum allowable operating pressure, other than localized pitting on an effectively
coated and cathodically protected pipeline. Reports are also required for transmission pipelines
where there has been an exceedance of MAOP plus allowable build-up as discussed in the last
bulleted item of the previous section.
OPERATIONS REV. NO. 13
SAFETY-RELATED CONDITIONS DATE 01/01/24
X-4, sr'a STANDARDS 2 OF 3
Utilities NATURAL GAS SPEC. 4.12

Filing of Safety-Related Condition Report
Each report of a safety-related condition must be filed (received by the Associate Administrator) in writing
within 5 working days (not including Saturdays, Sundays, or Federal holidays)after the day a
representative of the operator first determines that the condition exists, but not later than 10 working days
after the day a representative of the operator discovers the condition. Separate conditions may be
described on a single report if they are closely related.
Each report of a gas transmission pipeline MAOP exceedance meeting the requirements of criteria in
the previous section, must be filed (received by the Associate Administrator) in writing within 5 calendar
days of the exceedance.
The report shall be headed "Safety-Related Condition Report" or"Maximum Allowable Operating
Pressure Exceedances" (as applicable) and shall include the following information:
• Company name, principal address, and operator identification number(OPID). Avista's OPID is
31232.
• Date of the report.
• Name,job title, and business telephone number of person submitting the report.
• Name,job title, and business telephone number of person who determined that the condition
exists.
• Date condition was discovered, and date condition was first determined to exist.
• Location of the condition, with reference to the State (and town, city, or county) and, as
appropriate, nearest street address, survey station number, milepost, landmark, or name of
pipeline.
• Description of the condition, including circumstances leading to its discovery, any significant
effects of the condition on safety, and the name of the commodity transported or stored.
• The corrective action taken (including reduction of pressure or shutdown) before the report is
submitted and the planned follow-up or future corrective action, including the anticipated schedule
for starting and concluding such action.
Gas Engineering with assistance of the Pipeline Safety Engineer shall email or fax a copy of the Safety-
Related Condition Report to the following email address or number:
InformationResourcesManager(c dot.gov
Fax No. 202-366-7128
Copies of the Safety-Related Condition Report shall also be sent to the appropriate state agencies.
Recordkeeping
Records of Safety-Related Condition Reports, letters, and other documentation relating to the discovery,
evaluation, and correction of safety-related conditions shall be retained for the life of the system.
OPERATIONS REV. NO. 13
SAFETY-RELATED CONDITIONS DATE 01/01/24
X-4, sr'a STANDARDS 3 OF 3
Utilities NATURAL GAS SPEC. 4.12

4.13 DAMAGE PREVENTION PROGRAM
SCOPE:
To establish uniform procedures to prevent damage to Company pipeline facilities due to excavation or
other related construction activities.
REGULATORY REQUIREMENTS:
§192.614, §192.615, §192.616, §192.707, §192.935, §196, §198
WAC 480-93-124, 480-93-200, 480-93-250
RCW 19.122
OAR 952
ID 55-22
CORRESPONDING STANDARDS:
Spec. 3.14, Pre-Check Layout and Inspection
Spec. 3.19, Trenchless Pipe Installation Methods
Spec. 3.44, Exposed Pipe Evaluation
Spec. 4.11, Continuing Surveillance
Spec. 4.14, Recurring Reporting Requirements
Spec. 5.14, Cathodic Protection Maintenance
General
Avista maintains and implements a Damage Prevention Program to educate contractors and the general
public about gas pipelines in coordination with Avista's Public Awareness Program. The Damage
Prevention Program includes procedures for:
• Notifying the public and contractors of the program's existence and purpose,
• Notifying the public and contractors as to how they can learn the location of pipeline facilities
before excavation or construction activities commence,
• Providing a means of receiving and recording notification of planned excavation and construction
activities,
• Providing the public and contractors information as to the type of temporary markings to be used
to identify underground facilities and how to identify the markings, and
• Providing actual temporary physical marking of buried pipelines in areas of excavation or
construction before activity begins.
For the purpose of this section, the term "excavation" shall include excavation, blasting, boring, tunneling,
backfilling, the removal of aboveground structures by either explosive or mechanical means, and other
earth moving operations. The term "construction" shall apply to all other activities that could affect the
integrity of Avista's gas pipelines or facilities.
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utilities NATURAL GAS SPEC. 4.13

Public Awareness Program
The Safety Department is responsible for the overall development, implementation, and maintenance of
Avista's Public Awareness Program. The program identifies stakeholder audiences and associated lists,
the message content per stakeholder, frequencies and methods of message delivery, a program
evaluation process, and additional languages into which this media information should be translated.
The focus of Avista's Public Awareness Program is to raise the awareness of the presence of natural gas
pipelines within its communities and educate stakeholders on the prevention and/or response actions to
natural gas pipeline accidents. Avista's communication methods are through various media including,
public service announcements, paid advertising, bill inserts, newspapers, magazines, mass mailings,
online marketing, presentations, and events.
One Call systems may also provide appropriate information to contractors and the public through such
means as television and radio advertising, bumper stickers, pamphlets, presentations, events, etc. The
local operations managers should endeavor to use these means in addition to the Company programs.
Additional detail is available in Avista's Public Awareness Plan, which is maintained by the Public
Awareness Specialist.
The Damage Prevention Administrator, or other designated individual, is responsible to provide
information on excavation damages to the Public Safety Specialist who manages the company's Public
Awareness Program. This information includes detailed damage reports, excavator detail, damage
trends, and other data that is beneficial to enhance Public Awareness mailing content and messaging. .
The Public Awareness Specialist uses the information provided to:
1. Evaluate the current messaging and materials for relevance and effectiveness.
2. Create new, or alter current, messaging to address changing trends.
By using stakeholder participation, the Public Awareness Program provides messaging in a variety of
methods including but not limited to brochures, mass mailings, presentations, and events. Additional
details can be found in the Public Awareness Program document.
Inspection and Protection of Pipelines after Railroad Accidents
Avista should inspect its gas pipeline facilities following railroad accidents and other significant events
occurring within railroad right-of-way. Such inspection should include but is not limited to alerting rail
operators and emergency responders of the presence, depth, and location of the pipelines to minimize
the potential of damage to the facilities during clean-up and restoration activities. Avista's Safety
Department has developed special communications materials for communication of this topic to known
railroads and their agents in the Company's service territory. The name of the brochure is "Electric and
Natural Gas Line Safety for Railroad Workers" (WA/ID) and "Natural Gas Line Safety for Railroad
Workers" (OR).
One Call Notification System
A One Call notification system is where a utility locate request center, known as a One Call Center,
receives a request from an excavator through one number(811 or www.811.com)for locating and
marking of underground utility facilities in a planned excavation site. This system eliminates the need for
duplicate calls requesting the same information from the different utilities or agencies affected. One Call
Centers may provide a platform for members to discuss damages, facilitate planning, and to further
improve the system. One Call Centers may collect information on damages and compile the results for
distribution to the members.
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utilities NATURAL GAS SPEC. 4.13

In the instance that a One Call notification system is not available in a particular service district or in the
event that such services are suspended or cancelled, the Company shall make provisions for notifying the
public and contractors of the provisions of this Damage Prevention Program through coordination with
Avista's External Communications Department and the local operations manager.
Requests for Locates Through One Call
In areas where One Call notification systems are available, a designated One Call Center will receive and
process incoming requests regarding facility locations. A minimum of two (2) business days prior notice is
required for locate requests. One Call Centers will normally retain records pertaining to locate requests,
however, written requests for locates and supporting documentation shall be retained by Avista or their
locating representative for a minimum of three (3)years. Requests for locates received by Company
personnel shall be routed through the One Call Center to assure that notification is processed and sent to
the appropriate designated Avista locator(contractor or in-house) based on the area and type of facility
identified on the utility location request also known as a locate ticket. This also assures that proper
documentation and records are kept for each locate ticket.
One Call Centers that Avista is a member of are:
• Bon ner/Boundary/Shoshone/Benewah Counties, ID— Pelican Corp.
• Kootenai County, ID— One Call Concepts
• North Central Idaho—Dig Line
• Oregon — One Call Concepts
• Washington —One Call Concepts
• Montana (electric only)—One Call Concepts
Requesting Emergency Locates
Emergencies occur which do not allow two (2)working days to mark gas facilities. Requests for
emergency locates should still be routed through the One Call system and facilities should be marked as
soon as possible after being notified.
An EMERGENCY means any condition involving a clear and present danger to life, property, or a
customer service outage. (In Oregon, the definition includes interruption of essential public services and
in Idaho the definition includes blockage of roads/transportation facilities that require immediate action).
If Avista is dealing with an emergency that requires excavation, a request for locates shall be made. If
locates cannot be expedited and an alternative method of securing the situation is not feasible, then
excavate using reasonable care.
Idaho Only
When requesting an emergency locate the excavator shall call no less than two (2) hours prior to
commencing the emergency excavation and must provide contact information to reach an individual
throughout the emergency excavation process.
Locating and Marking Avista Facilities
Individuals performing locates of Company gas facilities shall be properly trained in the use of the
appropriate locating instrument, the use of Company maps, and shall be familiar, and comply with, the
state underground dig laws, and information and procedures contained herein.
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Locating of Avista's cathodic protection facilities should only be performed by trained and qualified Avista
cathodic protection personnel.
Websites for State Underground Dig Laws:
Idaho:
https://legislature.idaho.gov/statutesrules/idstat/title55/t55ch22/
Oregon:
https://secure.sos.state.or.us/oard/displayDivisionRuIes.action?selectedDivision=4223
Washington:
https://apps.leg.wa.qov/rcw/defauIt.aspx?cite=19.122
Upon receiving notification of proposed excavation or construction activity, or upon receipt of a utility
location request, the following procedures shall be followed, in addition to the respective state's
"Underground Dig" laws:
• Avista facilities shall be located and marked prior to the valid start date and time listed on the
locate request(unless other documented arrangements have been made with the excavator)
after the excavator notifies the One Call Center.
• Marking of facilities— Use a stripe approximately 18" long by approximately 2"wide. Stripe
approximately every 10 to 15 feet and more frequently in areas where facilities turn, angle,
junction, cross, etc. to indicate the location of the facilities. Marks should be carried slightly past
the dig area. Use an arrow'5"to indicate the direction that the facility continues on and out of the
dig area.
• Dotting with locating paint is acceptable in areas of decorative rock, hardscapes, and landscaped
areas to minimize overspray on private property. Should be used in conjunction with flags if
appropriate.
• The following labeling requirements are a minimum standard and additional requirements may be
required by individual state dig laws and must be followed. Labeling for locate marks shall
indicate company identification letters "AVA"for Avista, "GAS" "CP" "ELE" 7/0"for the type of
facility. Additionally, gas facilities shall indicate the diameter and material, "STL" "PE", of the pipe
or facility if it is 2" or greater in diameter. If the pipeline is considered high pressure, it shall also
be indicated with "HP". Example:
AVA HP GAS or AVA 4" PE GAS or AVA CP
• Placement of labeling should be on every lateral and approximately 50 feet apart or at a distance
that the excavator can clearly see from one label to the next. This is extremely important where
there may be multiples of the same type of utilities in the area with the same colored marks. (If
there are short laterals off of the mainline that clearly show it is part of the gas line then labeling
may not be necessary due to the shortness of the lateral.) Labeling also aids in identifying the
utility lines for those individuals that are color blind.
• In Oregon Only: Abandoned facilities should be provided, when possible (if known), to assist the
excavator and reduce downtime when they come across an unmarked pipeline or cable. These
facilities should be marked in the appropriate utility color with a capital letter"A" inside a circle
along with the company identification letters AVA for Avista, the word GAS or CP, the pipe or
facility size if known and greater than 2" in diameter. Example:
OAVA GAS 4" STL
• If no facilities are in the area, the excavator or contractor shall be notified of this. Notification may
either be by telephone, email, in person, or by painting "NO AVA" and the appropriate facility type
(GAS, CP, F/O or ELE)on the ground surface at the proposed excavation or construction site.
OPERATIONS REV. NO. 23
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utilities NATURAL GAS SPEC. 4.13

Physically marking the ground surface is the preferred method. The employee shall document
how this information was communicated as part of the documentation above.
• Example: NO AVA GAS or NO AVA CP
• When marking underground company gas pipelines and facilities, the locator shall use the
following methods in the appropriate APWA utility color:
a) Spray paint. Using paint intended for temporary marking of underground facilities, the
locator shall indicate the presence of pipelines or other facilities using a striped line on the
ground or road surface. Care should be taken to avoid getting paint on buildings, parked
cars, sports courts, etc. Mismarks should be removed immediately by overcoating with a
neutral color.
b) Polyethylene whiskers may be used as an alternative method of marking where snow, ice,
rain, or heavy traffic could make paint marking ineffective. Examples include dirt or gravel
roadways, alleys or intersections, and parking areas or construction sites. Areas do not
include residential properties or where indications of shallow gas lines would present danger
to the facility with their use.
c) Marking pin flags should be used in addition to or as an alternative method of marking
during inclement weather, in landscaped or grassy areas and areas of dead vegetation
where visibility of paint (especially yellow) presents a problem, as necessary.
d) Marking stakes may also be used where practical. Drive stakes into the ground surface at
regular intervals so that the direction of the facility is easily discernible.
In each case of locating and marking company facilities, the locator shall take reasonable steps to assure
that the excavator or contractor can properly identify the location markings.
If the locator cannot determine where the dig site or zone is, contact the excavator for clarification. If
unable to contact the excavator, then locate the area based on the description on the locate ticket if there
are no white marking indications or if the white markings are not complete or clear.
It is beneficial to meet with the excavator at the job site to clarify the exact location where the construction
will take place. In unusual situations, some methods other than the above marking methods may be used
such as offset markings/stakes.
A visual inspection shall be completed during the facility locating process. The primary reason for the
visual inspection is to determine if there are facilities that are not on record or mapped, such as in new
areas of construction. The visual inspection includes identification of access points and potential hazards
as well as to assure that plant facilities shown on records match those of the site. Evidence of a facility
not on a record/map includes but is not limited to valves, risers, meters, and vent pipes.
The locator shall document all facilities located on the locate request ticket, in a ticket management
system, or on a daily log sheet. Documentation includes locate ticket number, name of locator, date and
time locate was completed, conversation with excavators or homeowners, notes/comments indicating any
changes to the described dig area as agreed upon by the requestor, and pictures showing Avista's utility
mapping of the proposed dig area and the locate marks in case of a dispute. Photo documentation of
utility markings should be oriented in-line with the utility path and include permanent background objects
or structures for reference. Pictures should also capture the excavator's white markings.
When a request is made for"remarking" or"refreshing"of Avista's facilities, the request shall be treated
as if it were a new locate request by connecting to the facilities and locating it out to validate whether or
not there has been a change since the last time it was located.
If in the course of locating and marking, a locating technician discovers a natural gas leak, they shall call
Avista at 1-800-227-9187 to report the leak.
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utilities NATURAL GAS SPEC. 4.13

When responding to Idaho State emergency locate requests, locators:
• Shall attempt to contact the excavator(at the number provided in the emergency excavation
notice)within one (1) hour of receiving the notice of emergency excavation and provide
information concerning underground facilities within the area of excavation or provide the
anticipated response time.
• Unless the locator informs the excavator that it is impossible to respond under the circumstances
and provides an alternate expected arrival time, the locator shall arrive at the emergency
excavation site within two (2) hours of receiving the notice of emergency excavation to locate and
mark the underground facilities.
HARD TO LOCATE FACILITIES PROCESS:
Every hard to locate pipeline situation is different. There is a difference between steel and plastic and the
success to locating and or finding them. The length of the hard to locate (or un-locatable) pipe is also a
significant factor. A steel stub or end of main are more likely to "tone" depending on the length, whereas
a plastic stub or end of main are typically extremely difficult to locate. Following is the process a locating
technician should follow to locate such facilities:
• The locating technician checks to see if a marker ball is present.
• The locating technician direct connects using the appropriate frequency and power setting to
obtain continuity. Neighboring hook up locations should be accessed if a sufficient signal cannot
be obtained at the first location. A higher frequency may need to be used to push a signal onto
the facility that is hard to locate.
• If a proper signal cannot be obtained to locate the gas facility, the locating technician should
communicate with the excavator to let them know about the hard to locate facility and to
determine if the facility will be in their dig zone. This communication should be documented with
the locate ticket.
• In WASHINGTON RCW 19.122.030 (3)(b)and (4)(b)(kiii): A locator shall provide, at a minimum,
one of the following to the excavator regarding an unlocatable facility prior to commencement of
excavation.
o A GIS map of the area showing the location of the hard to locate (un-locatable)facility
with the inclusion of Avista's disclaimer on it.
o In the proposed construction area, spray paint a yellow triangle mark on the ground
pointing in the direction where the facility is un-locatable.
o Arrange a meeting with the excavator at the worksite to provide available information.
• In IDAHO ID CODE 55-2205(2) If there are identified but un-locatable facilities, they shall be
marked using the best available information within the two (2) business days. Spray paint a
triangle mark on the ground pointing in the direction where the facility becomes un-locatable. If
there is no available information, then also include"Length ?" if it is a stub or end of main. (This
indicates that we know there is a facility here but do not know where the facility ends.)
• If the facility is in the dig zone, then the locating technician either turns the section that they
cannot locate over to a lead technician or to Avista* if there is no lead technician assigned to the
area such as in the smaller districts.
• As-built research is then conducted for the hard to locate (un-locatable)facility to determine if
there are centerline measurements that can be used to mark the facility. The facilities should be
marked with the actual measurements (i.e., 395' CL with an arrow showing the direction of which
street centerline is being referenced). The excavator should then be notified that a record was
used to locate the facility and to dig with care.
• If there is no record of the facility or the record does not provide sufficient information for a
measurement, then follow the additional actions seen below.
*When a contract locator notifies Avista's local office of a hard to locate (un-locatable)facility, the local
Avista operations office shall take additional actions to identify the location of the facilities within the
OPERATIONS REV. NO. 23
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utilities NATURAL GAS SPEC. 4.13

prescribed timeline of the locate ticket unless documented arrangements with the excavator have been
made.
Additional actions may include but are not limited to: (Contact Damage Prevention Program
Administrator for guidance if necessary)
1. Review of maps, main, service line, or stub card as-built documents.
2. Potholing the facilities to try to find and fix a broken wire.
3. Coordinate with the excavator to minimize the potential for damage to Avista's facilities by
utilizing such techniques that include but are not limited to the following:
a. Having field personnel stand-by while excavating across the facility.
b. Identify the location of the facility by assisting with hand excavating.
c. Employ other locating techniques as available and if time permits.
4. Facilities with broken wires, if not repaired through actions listed above, should have a job made
up to have the broken wire repaired when practical.
5. When facilities are located, centerline measurements should be captured and mapped in GIS for
use for future locating.
6. Installation of a marker ball to aid in future locating of facilities such as end of main, end of stub,
valves, or other locations where it makes sense at the time of an open ditch.
Tolerance Zone
A locator is required to locate to a "reasonable accuracy"which means a location within 24 inches of the
outside lateral dimensions of both sides of an underground facility (also known as a tolerance zone).
TOLERANCE ZONE/REASONABLE ACCURACY ZONE DIAGRAMS -WA/ID:
TOLERANCE TOLERANCE
ZONE ZONE
TOLERANCE ZONE TOLERANCE ZONE TOLEWE ZONE TOLEI WE ZONE
24"FROM Egg SIDE 24" FROM E&H SIDE 24" FROM LM I 24" FROM EACH
OUTSIDE EDGE OF OUTSIDE EDGE OF
DUCT8*IK DUCT RANK
I 71 ,
I �
I
SINGLE SUBSURFACE FACILITY %'l1LTIPLE SUBSURFACE FACILITIES
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utilities NATURAL GAS SPEC. 4.13

In the "reasonable accuracy zone" or"tolerance zone" an excavator is required to excavate with hand
tools or non-invasive methods (in WA it is using reasonable care)within this zone to determine the exact
or precise location of the marked utility.
TOLERANCE ZONE DIAGRAM—OREGON
Tolerance zone means the area within 24 inches surrounding the outside dimensions of all sides of an
underground facility. Employ hand tools or other non-invasive methods either to determine the exact
location of the underground facility or down to 24 inches beyond the depth of intended excavation within
24 inches of the outside dimensions of a marked underground facility.
TOLERANCE IDNE TOLERANCE ZONE
/ 24' \ /
/ I \ / _
/ \ / 24 �
,.24
1 +-24' 24'----- '
\ / 1 24' /
24' • / I /
♦ 20' • / \ I
♦♦ IARGE PPE E DUCTS // ♦♦ SINGLE FACILITY2"OR LESS
Recordkeeping
Written requests for locates and supporting documentation shall be retained by Avista or their locating
representative for a minimum of three (3) years.
APWA Uniform Color Codes for Marking
Listed below are American Public Works Association (APWA) uniform color codes used to mark utility
locations. These color codes shall be adhered to unless it conflicts with local codes or practices.
Red Electric Power Lines, Cables or Conduit, Lighting Cables, Cathodic Protection
Yellow Gas, Oil, Steam, Petroleum, Hazardous Liquid, Gaseous Materials
Orange Communications, Cable TV, Alarm or Signal Lines, Cables or Conduits, Fiber
Blue Potable Water
Green Sewers, Drainage Facilities or Other Drain Lines
Pink Temporary Survey Markings
Purple Slurry, Irrigation, and Reclaimed Water
White Proposed Excavation Area
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utilities NATURAL GAS SPEC. 4.13

Excavator Responsibilities for Safe Digging
The general responsibilities of an excavator for safe digging and prevention of excavation damages are
outlined below. (Refer to respective state dig laws for specific requirements)
• Premark the excavation site in white.
• Request locates at least two (2) business days before beginning an excavation.
• Do not begin excavation until all known utilities are marked or have been cleared (utilities are
listed on the locate ticket in some states their contact information is also included).
• Verify the locate description matches the excavation project, if not then request additional locates.
• Hand dig within tolerance zone or use other non-invasive methods to expose and determine the
exact location of underground facilities before using mechanized equipment.
• If an underground facility is discovered that is not marked, notify the owner/operator, or call 811.
• Properly support and protect the pipeline and other utilities when exposed.
• Maintain the locate markings. Marks are good for the following timeframes starting from the day
of notification to 811/One Call Center. If your project will not be completed prior to the expiration
of the locate ticket or its apparent site conditions changed substantially to invalidate the markings,
call 811/One Call Center to update the ticket at least 2 full business days prior to expiration:
o WA= 45 days, then request new locates
o ID = Four consecutive weeks (28 days), then request new locates
o OR = 45 days, then request new locates
• If an excavator damages a utility, then refer to the section on Avista Damage to Other Facility
Operators later in this specification.
• If damage occurs to a pipeline and gas is escaping, call 911.
Marking of pipe after installation is a requirement in Oregon per OAR 952-001-0070 (8). In areas of
ongoing excavation or construction (such as residential or commercial site development) in Oregon,
newly installed facilities shall be located and marked with locate paint or appropriate flagging for backfilled
facilities immediately upon placement. For shaded pipe in a ditch where Avista is not backfilling the ditch,
locate and mark using locate paint on the sand or"natural gas" caution/warning tape which may be
placed on the sand over the pipe using sand in various places to anchor the tape in place so that the
location of the pipe is still visible.
Locate Ticket Availability
Avista crews (whether company employees or contractors), should have a copy of the One Call locate
ticket on site whenever performing excavation.
On-Site Inspections- General
If company personnel are made aware there exists a possibility that company gas pipelines or facilities
could be damaged by excavation or construction activities the following procedures shall apply:
• The pipeline or other facilities shall be inspected as frequently as deemed necessary before and
after the construction or excavation activities. The employee performing the inspection shall be
properly trained to verify that the integrity of the pipeline or other gas facility has not been
compromised. Whenever a pipeline is exposed, whether steel or PE, an Exposed Piping
Inspection Report form (N-2534)shall be completed. If the pipeline is damaged (including the
coating if steel pipe), it shall be repaired per the appropriate company procedure. For steel
piping, a pipe-to-soil read shall be taken. Refer to Specification 3.44, Exposed Pipe Evaluation.
• In areas of underground utility congestion, company personnel should consider the advantages of
opening bell holes and exposing the various utilities prior to excavation. When a proposed
excavation is planned in proximity to any gas line, the line should be located by bell holing at a
number of locations necessary to determine the exact location of the pipeline.
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utilities NATURAL GAS SPEC. 4.13

• When trenchless methods are used, underground facilities that cross the bore path must be
located and protected. Those facilities that cross the bore path must be day-lighted (potholed)to
verify location and depth. This applies to those streets with a pavement cut moratorium in place
as well; if the location and depth of foreign utilities cannot be positively identified an alternate bore
path must be selected. Refer to Specification 3.19, Trenchless Pipe Installation Methods for
minimum potholing requirements.
• In the cases of major road, sewer, or construction projects consideration shall be given to
appointing an employee dedicated to assuring that company facilities are not damaged.
Blasting Near Pipelines
Blasting activities within 200 feet of any gas facility require evaluation by Avista Gas Engineering. An
Avista representative should be on site during the blasting operation. No blasting operation is allowed
that will adversely affect Avista facilities.
Following a blast performed within 200 feet of any gas pipeline, or a blast that has the potential to
damage a gas facility, a post inspection leak survey shall be completed to verify the integrity of the
pipeline system.
Blasting-Peak Particle Velocity
(PPV limited to 2 in/sec)
170
160
150
140
a
f6 130
N
y 120
E CONTACT ENGINEERING
C! 110
d
100
N
:2 90
80
70
d
60
50 SAFE TO BLAST
7E
0 40
30
20
10
0
0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 160 170 180 190 200
Charge Distance to Pipe Centerline(Ft)
For blasting operations in which the predicted Peak Particle Velocity (PPV)of the blast will exceed 2
in/sec at the pipe an engineering evaluation of the blasting operation is required (refer to chart below).
PPV is a measure of the ground vibration caused by blasting.
When blasting within 200 feet of a pipeline and the predicted PPV is less than 2 in/sec(Safe to Blast)
then the contractor shall provide seismic monitoring at a location perpendicular to the blast and over the
pipeline to verify the blaster is operating within the predetermined limits.
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utilities NATURAL GAS SPEC. 4.13

Engineering evaluations include review of the contractor submitted blasting plan. The plan shall include
the following information:
1.) Date of blast
2.) Drawing specific to the location of the blast including distance to Avista facilities
3.) Hole size, spacing, depth, and layout
4.) Type of explosive and specific energy release
5.) Total weight of explosives
6.) Delay interval
7.) Maximum charge weight/delay
Gas Engineering shall review the blasting plan for conformance with Avista's Gas Standards.
Blasting operations shall restrict the Total Combined Stress on the pipeline to no greater than 80 percent
of SMYS for all operating class locations. The total combined stress on the pipeline shall be determined
in accordance with AGA Project PR-15-109"Pipeline Response to Buried Explosive Detonations."
On-Site Inspections for Transmission Facilities
Additional preventative and mitigative measures are required for transmission pipelines that are affected
by§192, Subpart O— Pipeline Integrity Management. Avista is required to monitor all excavations near
transmission pipelines.
The following procedures shall apply:
• Locating personnel will inform the designated individual, who will be the coordinator in each
construction area that has transmission facilities (Spokane, Colville, and Klamath Falls areas),
any time they perform a locate on a transmission line. The locating personnel will provide the
locate ticket for recordkeeping purposes.
• The designated individual or company representative will do the initial screening by contacting the
One Call requestor or contractor to determine where they will be digging and if the location will
likely be within 10 feet of a transmission pipeline.
• The coordinator will arrange for an Avista representative (inspector)to be on-site during the
excavation work, if it has been determined that digging will be within 10 feet of the transmission
line. The Avista representative will indicate on the one call ticket(or on a separate form attached
to the one call ticket)their name, the date they completed the stand-by inspection, and whether
the pipe was exposed. A copy of the ticket (and form) shall be forwarded to the Damage
Prevention Administrator and a copy shall be kept in the local construction office.
• When facilities are exposed, the company representative will document the condition of the
coating and pipe on an Exposed Piping Inspection Report form (N-2534) and take a pipe-to-soil
read if the coating is compromised.
• If mechanical damage occurs to the pipeline during the excavation, whether it results in a leak or
not, data shall be collected in the same format as all other excavation damage (either through the
field computer or on a Gas Operating Order form (N-2633). The excavator information must be
filled out on the form and mapped in Avista's GIS mapping system. When damage occurs, the
Damage Prevention Administrator should be notified.
• If blasting is planned near the pipeline, refer to the previous section on Blasting Near Pipelines.
OPERATIONS REV. NO. 23
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utilities NATURAL GAS SPEC. 4.13

Excavation Identified Without a Locate Ticket(WA Transmission)
If there is evidence that excavation near a transmission pipeline was completed without a locate request
or that Avista was not made aware of, notify the Damage Prevention Administrator as a follow-up
assessment is required to determine if the pipeline sustained damage.
The Damage Prevention Administrator will in turn notify the Pipeline Integrity Program Manager and Gas
Engineering to determine the appropriate method of assessment (response).
When an Avista employee discovers an excavator digging within 35 feet of a transmission pipeline
without first obtaining utility locates, the following information shall be acquired at the time of the
discovery and provided to the Damage Prevention Administrator:
Acquire the followinq information:
• Date of Observance
• Company name
• Operator name
• Operator address
• Operator phone number
• Location of dig site/address
• Type of excavator
• Type of work being performed
• Individual who observed the digging
WAC 480-93-200(9)— Each gas pipeline company must report to the commission the details of(a)
each instance of the following when the company or its contractor observes or becomes aware of an
excavator that digs within 35 feet of a transmission pipeline without first obtaining a locate. (b)A
person intentionally damages or removes the marks indicating the location or presence of gas pipeline
facilities.
The Damage Prevention Administrator and the Pipeline Safety Engineer should coordinate the notice with
the Washington Utilities and Transportation Commission (WUTC) in accordance with the reporting rule
and as mentioned previously. The report should be completed within 45 days of discovery. Auditable
documentation of the correspondence shall be retained within the commission correspondence files in
Gas Engineering.
Intentional Damage or Removal of Locate Marks
When an Avista employee discovers that gas locate marks have been intentionally damaged or removed
in the state of Washington, notification to the Washington Utilities and Transportation Commission
(WUTC) must be made per WAC 480-93-200(9)(b). The Damage Prevention Administrator and the
Pipeline Safety Engineer should coordinate the notice and provide relevant details of the event that were
observed or that the company employee became aware of. The report should be completed within 45
days of discovery. Auditable documentation of the correspondence shall be retained within the
commission correspondence files in Gas Compliance.
Mapping Corrections
Occasionally, when locating facilities, errors will be noted on Company maps. Mapping errors and
corrections shall be completed in accordance with Specification 4.11, Continuing Surveillance.
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Response to Facility Damage
Identified dama_pe to Avista facilities shall be repaired in accordance with Avista Gas Standards.
Documentation of damage to Avista's facilities shall be captured through the existing Gas Trouble
process as detailed in Section 2 of the GESH —"Leak and Odor Investigation".
Instances of damage to other facility operators shall be captured using the Damage Information Reporting
Tool (DIRT) Field Form. Damage includes the substantial weakening of structural or lateral support of an
underground facility, penetration, impairment or destruction of any underground protective coating,
housing or other protective device, or the severance (partial or complete)of any underground facility to
the extent that the project owner or the affected facility owner or facility operator determines that repairs
are required.
Avista Damage to Other Facility Operators
When Avista personnel damage other operator's facilities the damage shall be reported to the Claims
Department and documented on the Damage Information Reporting Tool (DIRT) Field Form. Additionally,
Avista shall notify the other facility operator so appropriate repairs can be completed.
At a minimum, the following information shall be documented on the DIRT form:
• Date and time of the incident
• Avista employee involved in the incident
• Location of the incident(with enough information to be found by another individual)
• Description of the damage
• Locate information
• Whether a one-number locator service was notified before excavation commenced, and, if so, the
locate ticket number provided by a One Call locator service
• Root cause of why damage occurred
• Type of Right-of-Way where damage occurred
• Type of underground facility damaged
• Type of excavator that caused the damage
• Type of excavation equipment that caused the damage
• Type of work that was being performed when the damage occurred
• Type of locator(contract or company)
• Did damage cause interruption of service?
• Was the work area pre-marked (showing the boundary of the excavation site)?
• Did this event involve a sewer cross bore?
• Measured depth from grade
• Photographs of the damaged facility
Completed Damage Information Reporting Tool (DIRT) Field Forms shall be sent to the Damage
Prevention Administrator at MSC-6, who will review the information and submit the report information into
the respective state reporting databases.
• WA damages through the UTC Virtual DIRT database within 45 days of the incident as required
by RCW 19.122.053.
• ID damages through the Damage Prevention Board Virtual DIRT database as required by Idaho
Code Chapter 22, Section 55-2208 (5)
• OR damages through CGA DIRT
Refer to Avista Specification 4.14, Recurring Reporting Requirements. Avista excavators and their
contractors are required to call the local public safety agency (i.e., 911)when excavation damage they
have caused, results in an emergency condition.
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The following calls must also be made:
Washington: Operator of the facility that was hit and 811 One Call Center
Oregon: Operator of the facility that was hit
Idaho: Owner of the facility that was hit and 811 One Call Center
Review of Excavation Damage Incidents
Upon discovery of excavation damage to Avista's buried gas facilities, the Damage Prevention Program
Administrator, or other designated individual, reviews damage details for accuracy of information and
enters any remaining DIRT required information. The Damage Prevention Program Administrator and
Analyst periodically review the results of excavation damage investigations and provide analytic data to
the Public Awareness Program and associated Operations Offices for education and outreach to
minimize the possibility of reoccurrence.
Photograph Requirements
Photographs shall be taken of excavation damages and should include sufficient detail to represent
information related to the excavation damage. Details should include but are not limited to:
• Photographs of the damage, in-line with the damaged utility, including permanent background
objects or structures and the surrounding area from all four directions
• Locate marks or photograph representing lack of locate marks
• Excavation location
• Use of measurement devices such as a tape measure to convey dimensions, including locates
outside the tolerance zone*
• Use of a note within the photograph to convey the following:
o Date of damage event
o Location
o Work Order or Service Request Number or claim number when available.
Photographs shall be emailed to photosQavistacorp.com to assist with the determination of the root
cause, filing of excavator complaints, and for claims processing. Photos should be submitted within two
business days from the date the excavation damage is discovered.
3rd Party Excavation Damage: One Call Check
All 3rd party excavation damages shall be checked for notification to a one call center. If the status of an
associated locate request is unknown at the time of the damage, the Damage Prevention Program
Administrator, or other designated individual, will perform a search of the appropriate one call center
records to try matching the excavator, site address, date range, and work type to the excavation damage.
In areas where one call centers do not provide such searchable records, the search will be done through
Avista's locating contractor's records for the associated locate request.
WA Damage Reporting
Damaged facilities in Washington shall be reported in accordance with Specification 4.14, Recurring
Reporting Requirements.
WA Excavator Notifications
For damage to gas facilities located in Washington, Avista shall provide to the excavator the information
as required by WAC 480-93-200(8).
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WAC 480-93-200(8) Each gas pipeline company must provide, to an excavator who damages a gas
pipeline facility, the following information set forth in chapter 19.122 RCW;
(a) Notification requirements for excavators under RCW 19.122.050(1);
(b)A description of the excavator's responsibilities for reporting damages under RCW 19.122.053;
and
(c) Information concerning the safety committee referenced under RCW 19.122.130, including
committee contact information, and the process for filing a complaint with the safety committee.
Building Permits near Transmission Utility Easements or Rights of Way
When Avista is contacted by third parties regarding pipeline facilities, the following minimum information
shall be conveyed. In Washington, permitted construction activity within 100 feet of a transmission line
will require the building applicant to consult with Avista. Consultation related to transmission facilities
should be conducted by the Pipeline Integrity Program Manager. The Pipeline Integrity Program
Manager shall document information about the consultation and file that document with the IMP program
documents. The following minimum information shall be conveyed to the applicant:
• Location of pipeline facilities
• Possible future notification information
• Damage prevention requirements including 811 information
• Vegetation management requirements
• Pipeline accessibility information
• Easements, if applicable
WAC 480-93-200(7)(b) - If the damage is believed by the company to be the result of an excavation
conducted without a facilities locate first being completed, the gas pipeline company must also report
the name, address, and phone number of the person or entity that the company has reason to believe
may have caused the damage. The company must include this information in the comment section of
the web-based damage reporting tool form or sent to the commission separately. If the company
chooses to send the information separately, it must include sufficient information to allow the
commission to link the name of the party believed to have caused the damage with the damage event
reported through the damage reporting tool.
WAC 480-93-200(7)(c) - Each gas pipeline company must retain all damage and damage claim
records it creates related to damage events, including photographs and documentation supporting the
conclusion that a facilities locate was not completed, reported under subsection (b) of this section, for
a period of two years and make those records available to the commission upon request.
RCW Chapter 19.122.033(4)Any unit of local government that issues permits under codes adopted
pursuant to chapter 19.27 RCW must, when permitting construction or excavation within one hundred
feet, or greater distance if required by local ordinance, of a right-of-way or utility easement containing
a transmission pipeline: (a) Notify the pipeline company of the permitted activity when it issues the
permit; or(b) Require, as a condition of issuing the permit, that the applicant consult with the pipeline
company.
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4.14 RECURRING REPORTING REQUIREMENTS
SCOPE:
To establish procedures for the submission of federal and state reports.
REGULATORY REQUIREMENTS:
§191.7, §191.11, §191.12, §191.13, §191.15, §191.17, §191.22, §191.29, §192.945
RCW 19.122.053, 81.88.080, 81.88.160
Idaho Code §55-2208 (5)
WAC 480-93-180, 480-93-200
CORRESPONDING STANDARDS:
Spec. 4.13, Damage Prevention
General
There are annual and conditional reporting requirements by PHMSA and state commissions. This
specification covers these requirements.
Reporting Distribution Facilities
Information for Avista's distribution systems shall be reported on form PHMSA F7100.1-1. A separate
form must be filled out and filed for each state in which the system operates.
Reporting Transmission Facilities
Information for Avista's transmission facilities shall be reported on form PHMSA F7100.2-1. Only one
form submission is required as it encompasses all states within the one form.
Submission of Reports
Avista, as an intrastate pipeline operator, shall submit federal annual reports via PHMSA's online
reporting tool at their website no later than March 15 of each calendar year.
In the event the website is unavailable or inoperable, reports can be submitted via hardcopy to the
following address:
Office of Pipeline Safety
Pipeline and Hazardous Materials Safety Administration
US Department of Transportation
Information Resources Manager, PHP-20
1200 New Jersey Avenue SE.
Washington, DC 20590-0001
A copy of Form F7100.1-1 and/or F7100.2-1 shall also be submitted to each respective state commission
no later than March 15 of each calendar year.
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TIMP Performance Reporting
In accordance with §192.945 operators with transmission facilities that fall under Subpart 0 — Pipeline
Integrity Management is required to submit on an annual basis a report on the TIMP Performance
Measures. These reports are submitted as part of the Transmission Annual Report, as mentioned above.
PHMSA Conditional Reporting
The following conditional reports shall be made to PHMSA as applicable and within the specified
timeframes as shown and as discussed at§191.22.
1. Construction of or any planned rehabilitation, replacement, modification, upgrade, uprate, or
update of a facility, other than a section of line pipe that costs $10 million or more. (60 days
before the event occurs. If 60-day notice is not feasible due to an emergency, notification must be
as soon as practicable).
2. Construction of 10 or more miles of a new or replacement pipeline (60 days before the event
occurs).
3. Construction of a new LNG plant or LNG facility(60 days before the event occurs).
Note: The definition of"construction" in the previous paragraphs was amplified in Advisory Bulletin ADB-
2014-03 to include Material Purchasing/manufacturing; Right-of-Way Acquisition; Construction equipment
move-in; on-site/off-site fabrications and right-of-way clearing, grading, and ditching.
4. A change in the primary entity responsible for managing or administering a safety program
required by federal code covering pipeline facilities operated under multiple Operator
Identification Numbers (OPIDs) (Within 60 days after the event occurring).
5. A change in the name of the operator(Within 60 days after the event occurring).
6. A change in the entity responsible for an existing pipeline, pipeline, pipeline segment, pipeline
facility or LNG facility (Within 60 days after the event occurring).
7. The purchase or sale of 50 or more miles of pipeline or pipeline system (Within 60 days after the
event occurring).
8. The purchase or sale of an existing LNG plant or facility (Within 60 days after the event
occurring).
WUTC Pipeline Leaks Emissions Report
RCW 81.88.160: In the state of Washington, on an annual basis, each gas pipeline company must
submit a report to the commission that includes total number of known leaks for the calendar year
detailing if the leak was hazardous/non-hazardous, repaired/scheduled for repair, volume of gas loss,
CO2 equivalent emissions, market value of gas loss, location and date of each leak, and the failure
cause of each leak. The report is due no later than March 15 of the calendar year.
WUTC Construction Defects and Material Failures Report
WAC 480-93-200(10)(b): In the state of Washington, a report detailing all construction defects and
material failures resulting in leakage must be submitted to the Washington Utilities and Transportation
Commission no later than March 15 of each year, to include information from the preceding year.
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DOT Drug and Alcohol MIS Form Submission
WAC 480-93-200(13): In the state of Washington, when a gas pipeline company is required to file a
copy of a DOT Drug and Alcohol Testing Management Information System (MIS)form with US DOT,
Office of Pipeline Safety, the gas pipeline company must simultaneously submit a copy of the form to
the commission. The report is due no later than March 15 of the calendar year.
Plans and Procedures
WAC 480-93-180(2): Plans and Procedures—The manual must be filed with the commission forty-five
days prior to the operation of any gas pipeline. Each gas pipeline company must file revisions to the
manual with the commission annually. The commission may, after notice and opportunity for hearing,
require that a manual be revised or amended. Applicable portions of the manual related to a
procedure being performed on the pipeline must be retained on-site where the activity is being
performed.
A copy of the updated Gas Standards Manual and the Gas Emergency and Service Handbook shall be
filed annually with the Washington Utilities and Transportation Commission (WUTC). The submission
should be completed near the first of the year following standards revisions and shall be submitted
electronically. Copies of the updated documents shall also be submitted to the Idaho Public Utilities
Commission and the Oregon Public Utilities Commission. Hardcopy or electronic is acceptable to these
entities.
NPMS Updating
In accordance with §191.29,Avista shall provide the following geospatial data to PHMSA:
• Geospatial data, attributes, metadata, and transmittal letter appropriate for use in the National
Pipeline Mapping System (NPMS).
• The name and address for the operator(Avista).
• The name and contact information of a pipeline company employee to be displayed on a public
Web site, who will serve as a contact for questions from the general public about the operator's
NPMS data.
The information required above must be submitted each year, on or before March 15, representing assets
as of December 31 of the previous year. If no changes have occurred since the previous year's
submission, Avista must comply with the guidance provided in the NPMS Operator Standards manual
available at http://www.npms.phmsa.dot.gov or by contacting the PHMSA GIS Manager at 202-366-0667.
250+PSIG Pipelines Map Submission (Washington)
In accordance with RCW 81.88.080,Avista shall provide accurate maps of pipelines that operate above
250 psig to the commission. It shall be the responsibility of the Gas Integrity Management Analyst to
ensure an updated cache of all such maps are electronically forwarded to the commission annually no
later than March 15.
WA Damage Reporting
In accordance with the Washington RCW and UTC reporting requirements regarding the reporting of
damages to underground facilities, Avista shall report the following within 45 days of the damage event
using the Washington commission's virtual private damage information reporting tool (DIRT) report form
or other similar form.
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RCW Chapter 19.122.053(1) &(3) Facility operators and excavators who observe or cause damage
to an underground facility must report the damage event to the commission within forty-five days of
the damage event using DIRT.
RCW CHAPTER 19.122.053(2)A non-pipeline facility operator conducting an excavation, or a
subcontractor conducting an excavation on the facility operator's behalf, that strikes the facility
operator's own underground facility is not required to report that damage event to the commission.
Avista shall report all known instances of damage to Avista's gas facilities by others and by Avista
employees. Additionally, the report shall include instances of damage events to other facility operators by
Avista. Instances of damage shall be captured as detailed within Specification 4.13— Damage
Prevention.
WAC 480-93-200(7) In the event of damage to a gas pipeline, each gas pipeline company must
provide to the commission the following information using either the commission's web-based
damage reporting tool or its successor, or the damage reporting form located on the commission's
website: (a)The reporting requirements set forth in RCW 19.122.053(3)(a)through (n).
WA Reporting Requirements
The following elements shall be reported in accordance with WAC 480-93-200(7) and as set forth in RCW
19.122.053(3)(a)through (n):
• The name of the person submitting the report and whether the person is an excavator, a
representative of a one-number locator service or a facility operator.
• The date and time of the damage event.
• The address where the damage event occurred.
• The type of right-of-way, where the damage event occurred, including but not limited to city,
street, state highway, or utility easement.
• The type of underground facility damaged, including but not limited to pipes, transmission
pipelines, distribution lines, sewers, conduits, cables, valves, lines, wires, manholes, attachments,
or parts of poles or anchors below ground.
• The type of utility service or commodity the underground facility stores or conveys, including but
not limited to electronic, telephonic, or telegraphic communications, water, sewage, cablevision,
electric energy, petroleum products, gas, gaseous vapors, hazardous liquids, or other
substances.
• The type of excavator involved, including but not limited to contractors or facility operators.
• The excavation equipment used, including but not limited to augers, bulldozers, backhoes, or
hand tools.
• The type of excavation being performed, including but not limited to drainage, grading, or
landscaping.
• Whether a one-number locator service was notified before excavation commenced, and, if so, the
excavation confirmation code provided by a one-number locator service.
• Whether an excavator experienced interruption of work as a result of the damage event.
• A description of the damage.
• Whether the damage caused an interruption of underground facility service.
For instances in which Avista believes the facility damage was the result of an excavation without a
facilities locate the following additional information shall be reported.
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• If applicable:
o The person who located the underground facility and their employer.
o Whether underground facility marks were visible in the proposed excavation area before
excavation commenced.
o Whether underground facilities were marked correctly.
WAC 480-93-200(7)(b) - If the damage is believed by the company to be the result of an excavation
conducted without a facilities locate first being completed, the gas pipeline company must also report
the name, address, and phone number of the person or entity that the company has reason to believe
may have caused the damage. The company must include this information in the comment section of
the web-based damage reporting tool form or sent to the commission separately. If the company
chooses to send the information separately, it must include sufficient information to allow the
commission to link the name of the party believed to have caused the damage with the damage event
reported through the damage reporting tool.
ID Damage Reporting
In accordance with the Idaho Code reporting requirements regarding reporting of damages to
underground facilities, Avista shall report each damage event by no later than March 31 for the previous
year's damages. Damage events shall be reported using the Idaho Damage Prevention Board's virtual
private damage information reporting tool (DIRT) database.
Idaho Code Title 55 Chapter 22; 55-2208 (5) Underground facility owners and excavators who
observe, suffer or cause damage to an underground facility or observe, suffer, or cause excavator
downtime related to a failure of one (1) or more stakeholders to comply with applicable damage
prevention regulations shall report such information to the board in accordance with the rules
promulgated by the board.
Document Retention
Records related to damage events are auditable for 2 years under the WAC reporting requirements.
Document retention is greater than 2 years for information related to the DIMP or other code
requirements. Refer to applicable standards. Supporting documentation could include but is not limited to:
• Trouble Order Information (1St Responder Operating Order).
• Service work order contained within Maximo.
• Exposed Piping Inspection Reports.
• Photographs.
• Avista Claims documentation and investigation documents.
WAC 480-93-200(7)(c) Each gas pipeline company must retain all damage and damage claim records
it creates related to damage events, including photographs and documentation supporting the
conclusion that a facilities locate was not completed, reported under subsection (b)of this section, for
a period of two years and make those records available to the commission upon request.
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4.15 MAXIMUM ALLOWABLE OPERATING PRESSURE (MAOP)
SCOPE:
To define and explain Maximum Allowable Operating Pressure (MAOP) as it is addressed in the
applicable regulatory codes and as it applies to Avista's operations.
REGULATORY REQUIREMENTS:
§192.5, §192.14, §192.105, §192.195, §192.605, §192.607, §192.619, §192.620, §192.621, §192.623,
§192.624
WAC 480-93-018, 480-93-020, 480-93-155, 480-93-180, 480-93-200
CORRESPONDING STANDARDS:
Spec. 2.12, Pipe Design - Steel
Spec. 2.13, Pipe Design - Plastic
Spec. 2.23, Regulator Design
Spec. 4.17, Uprating
General
It is desirable to operate the gas systems near the documented MAOP. This provides for maximum
system capacity during periods of unusually cold weather or other high system demand.
The majority of Avista's intermediate pressure distribution systems have an MAOP of 60 psig, although
some systems have a lower MAOP. The intermediate pressure systems are most susceptible to pressure
loss during periods of high demand and for this reason should be operated near the system MAOP.
Determination of MAOP
The determination of the MAOP of any gas pipeline segment is made by Gas Engineering. The MAOP is
based on one or several of the following factors (with the lowest pressure being the established MAOP for
the system or segment):
• The design pressure of the weakest part of the pipeline segment as calculated by§192.105. For
steel pipe in pipelines being converted under§192.14 or uprated, if any variable necessary to
determine the design pressure under the design formula in §192.105 is unknown, one of the following
pressures is to be used as design pressure:
o 80 percent of the first test pressure that produces yield under section N5.0 of Appendix N of
ASME B31.8, reduced by the appropriate factor in §192.619 (a)(2)(ii) or if the pipe is 12.75 inches
or less in outside diameter and is not tested to yield the design pressure would be 200 psig.
• The MAOP established at the time of the pressure test by dividing the pressure to which the segment
was tested after construction as follows:
o For plastic pipe in all locations, the test pressure is divided by a factor of 1.5
o For steel pipe operated at 100 psig or more, the test pressure is divided by a factor determined in
accordance with the following table:
Factors
Class Installed before Installed after 11/11/1970 Installed on or after Converted under
Location 11/12/1970 and before 7/1/2020 7/1/2020 192.14
1 1.1 1.1 1.25 1.25
2 1.25 1.25 1.25 1.25
3 1.4 1.5 1.5 1.5
4 1.4 1.5 1.5 1.5
• The pipeline is operating in satisfactory condition and the highest actual operating pressure the
segment was subjected to during the five years preceding July 1, 1970. This restriction applies unless
the segment was pressure tested in accordance with §192.619 after July 1, 1965.
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• The pressure that is determined to be the maximum safe pressure after considering and accounting
for records of material properties, including material properties verified in accordance with §192.607,
if applicable, and the history of the segment, including known corrosion and the actual operating
pressure. However, overpressure protection must be installed on the segment in a manner that will
prevent the MAOP from being exceeded in accordance with §192.195.
WAC 480-93-020: In Washington State, there are limitations to MAOP's due to proximity to buildings
intended for human occupancy. Refer to Specification 2.12, Pipe Design - Steel.
Changing MAOP
The MAOP of a pipeline or system shall not be exceeded unless the particular facility has been uprated
according to the procedures outlined in Specification 4.17, Uprating. The MAOP of a pipeline may be
reduced based on several factors such as damage, corrosion, or operating characteristics of the pipeline
as determined by Gas Engineering.
MAOP Consideration during Startup and Shutdown
The various aspects of bringing a pipeline into or out of service are addressed in Specification 3.17
(Purging Pipelines), 3.18 (Pressure Testing), 5.16 (Abandonment or Inactivation of Facilities), 5.17
(Reinstating Abandoned Gas Pipelines and Facilities), and elsewhere in Avista's Gas Standards. In all
instances of bringing pipelines into service or shutting them down, the MAOP of these systems must not
be exceeded. In the event the MAOP is exceeded, contact the Gas Control Room. The Controller will
work with the On-Call Engineer to determine if the event is reportable in the state in which it occurred.
Gas Engineering will facilitate any downstream system investigations which may be warranted, and state
and/or any Federal notifications necessary.
Recordkeeping
Records establishing MAOP for transmission pipeline segments operating in a Class 3, Class 4, or High
Consequence Area shall be Traceable, Verifiable and Complete per§192.624. If records for these
pipeline segments are not Traceable, Verifiable and Complete, or if the MAOP for these segments is
greater than 30% of the Specified Minimum Yield Strength (SMYS) and was established using the
Grandfather Clause [§192.619(c)], they would be subject to MAOP Reconfirmation in accordance with the
Transmission Integrity Management Program (TIMP) documentation. Records for any MAOP
reconfirmation or materials verification shall be retained for the life of the pipeline. All records that could
be used to establish MAOP for transmission pipeline segments in operation as of July 1, 2020, shall be
retained for the life of the pipeline. Likewise, any records that could be used to establish MAOP for high
pressure distribution and intermediate pressure distribution should be retained for the life of the pipeline
as well.
Records pertaining to transmission and high-pressure distribution MAOP shall be centralized and kept in
Avista's Spokane Gas Engineering office for all service territories. Records for intermediate pressure
MAOP are held locally in the construction office. The MAOP of all pipelines, valves, and fittings in Avista's
system is maintained in Avista's GIS system, and it is the responsibility of Gas Engineering and GIS Edit
teams to update and maintain, as necessary. In Washington, Avista's GIS must be updated within six
months of facility construction. In other areas, this should be done as a best practice:
WAC 480-93-018 (5): Each gas pipeline company must update its records within 6 months of when it
completes any construction activity and make such records available to appropriate company
operations personnel.
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4.16 CLASS LOCATIONS
SCOPE:
To assist in determining the design criteria, construction practices, and maintenance frequencies of
Avista's gas facilities as they relate to the applicable Federal and State codes.
REGULATORY REQUIREMENTS:
§192.5, §192.179, §192.609, §192.610, §192.611, §192.613, §192.619, §192.620, §192.636
WAC 480-93-020, 480-93-155
CORRESPONDING STANDARDS:
Spec. 2.12, Pipe Design —Steel
Spec. 2.14, Valve Design
Spec. 3.12, Pipe Installation— Steel Mains
Spec. 3.18, Pressure Testing
Spec. 4.15, Maximum Allowable Operating Pressure (MAOP)
Spec. 4.17, Uprating
Spec. 5.11, Leak Survey
Spec. 5.15, Pipeline Patrolling and Pipeline Markers
Spec. 4.41, Transmission Integrity Management Program (TIMP)
General
For Avista, determinations of class locations and the subsequent monitoring of those locations applies to
pipelines with an MAOP that produces a hoop stress equal to or greater than 20 percent SMYS for the
purposes of patrolling (refer to Specification 5.15, Pipeline Patrolling and Pipeline Markers), or is
voluntarily designated as transmission in Avista's GIS.
A class location unit along a pipeline extends 220 yards on each side of the centerline of any contiguous
one-mile length of pipe. Each separate dwelling unit in a multiple dwelling unit building is counted as a
separate building intended for human occupancy.
Class Locations
Class 1 location is any class location unit that has 10 or fewer buildings intended for human occupancy.
Class 2 location is any class location unit that has more than 10, but fewer than 46 buildings intended
for human occupancy.
Class 3 location is:
• Any class location unit that has 46 or more buildings intended for human occupancy; or
• An area where the pipeline lies within 100 yards of either a building that is occupied by 20 or more
persons on at least 5 days a week for 10 weeks in any 12-month period. (The days and weeks need
not be consecutive); or
• An area where the pipeline lies within 100 yards of a small, well defined outside area (such as a
playground, recreation area, outdoor theater, or other place of public assembly), that is occupied by
at least 20 or more persons on at least 5 days a week for 10 weeks in any 12-month period. (The
days and weeks need not be consecutive.)
Class 4 location is any class location unit where buildings with 4 or more stories aboveground are
prevalent.
OPERATIONS REV. NO. 11
CLASS LOCATIONS DATE 01/01/24
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Utilities NATURAL GAS SPEC. 4.16

Class Location Boundaries
The boundaries of the above-mentioned class locations may be adjusted in accordance with the
following:
• A Class 4 location ends 220 yards from the nearest building with 4 or more stories aboveground.
• In a Class 3 location when there is a cluster of buildings intended for human occupancy that ends 220
yards from the nearest building in the cluster.
• In a Class 2 location when there is a cluster of buildings intended for human occupancy that ends 220
yards from the nearest building in the cluster.
EXAMPLE OF CLUSTERING
Continuous 1 Mile
No Dwellings
or Influencing
Factors for 1 CLASS 1 CLASS 2 CLASS 1 CLASS 3
Mile
2 Dwellings 13Dwel -- 46 Dwell-
---- --
220 xxxxxxxxxxx
K YDS x x x x x x
220 x x x xxxxxxxxxxxx
x xxxxxxxxxxxx
____________ __ _______
Pipeline
zzo 2zo zzo zzo
VDS YDS VDS YDS
Class Location Study
Determining the boundaries of class location areas is essential for implementation of Avista's
maintenance and operational programs as required by State and Federal regulations.
A review of the class locations should be done in conjunction with the third-party risk assessment as
outlined in Spec 4.41 —Transmission Integrity Management Program. This information shall be used for
confirmation or revision of MAOP's as outlined below in this specification.
Change in Class Location
When an increase in population density indicates a change in class location for a segment of an existing
steel pipeline operating at a hoop stress that is greater than 40 percent SMYS or indicates that the hoop
stress corresponding to the established maximum allowable operating pressure (MAOP)for a segment of
existing pipeline is not commensurate with the present class location; a study shall be done immediately
per the requirements of§192.609 to determine:
1) The present class location for the segment involved.
2) The design, construction, and testing procedures followed in the original construction and a
comparison of these procedures with those required for the present class location.
3) The physical condition of the segment to the extent it can be ascertained from available records.
4) The operating and maintenance history of the segment.
5) The maximum actual operating pressure and the corresponding operating hoop stress, taking
pressure gradient into account, for the segment of pipeline involved.
6) The actual area affected by the population density increase, and physical barriers or other factors
which may limit further expansion of the more densely populated area.
If a change in class location occurs after September 27, 2022, and results in pipe replacement of 2 or
more miles, in the aggregate, within any 5 contiguous miles within a 24-month period, to meet the MAOP
requirements in §192.611, §192.619 or§192.620, then the requirements for Rupture Mitigation Valves
(RMVs) in Specification 2.14 (Valve Design) apply to the new class location and RMVs shall be installed
to meet all applicable requirements.
OPERATIONS REV. NO. 11
CLASS LOCATIONS DATE 01/01/24
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Utilities NATURAL GAS SPEC. 4.16

If a change in class location occurs after September 27, 2022, and results in pipe replacement of less
than 2 miles within 5 contiguous miles during a 24-month period, to meet the MAOP requirements in
§192.611, §192.619 or§192.620, then within 24 months of the class location change, in accordance with
§192.611(d), the following requirements apply (with the exception of replacements of less than 1,000 feet
within 1 contiguous mile):
1) Comply with the valve spacing requirements of§192.179(a)for the replaced pipeline segment; or
2) Install or use existing RMVs or alternative equivalent technologies so that the entirety of the replaced
pipeline segments are between at least two RMVs or alternative equivalent technologies. The
distance between RMVs or alternative equivalent technologies for the replaced segment must not
exceed 20 miles, and the RMVs or alternative equivalent technologies must comply with the
applicable requirements of§192.636.
Confirmation or Revision of MAOP
Confirmation or revision of the Maximum Allowable Operating Pressure (MAOP)that is required as a
result of a study as outlined above must be completed within 24 months of the change in class locations
as outlined below per the requirements of§192.611. Pressure reduction under paragraph (1)or(2)of this
section within the 24-month period does not preclude establishing a maximum allowable operating
pressure under paragraph (3) of this section at a later date.
If the hoop stress corresponding to the established maximum allowable operating pressure of a segment
of pipeline is not commensurate with the present class location, and the segment is in satisfactory
physical condition, the maximum allowable operating pressure of that segment of pipeline must be
confirmed or revised according to one of the following requirements:
1) If the segment involved has been previously tested in place for a period of not less than 8 hours:
a) The maximum allowable operating pressure is 0.8 times the test pressure in Class 2 locations,
0.667 times the test pressure in Class 3 locations, or 0.555 times the test pressure in Class 4
locations. The corresponding hoop stress may not exceed 72 percent of SMYS of the pipe in
Class 2 locations, 60 percent of SMYS in Class 3 locations, or 50 percent of SMYS in Class 4
locations.
b) The alternative maximum allowable operating pressure is 0.8 times the test pressure in Class 2
locations and 0.667 times the test pressure in Class 3 locations. For pipelines operating at
alternative maximum allowable pressure per§ 192.620, the corresponding hoop stress may not
exceed 80 percent of SMYS of the pipe in Class 2 locations and 67 percent of SMYS in Class 3
locations.
2) The MAOP of the segment involved must be reduced so that the corresponding hoop stress is not
more than that allowed by this part for new segments of pipelines in the existing class location.
3) The segment involved must be tested in accordance with the applicable requirements of Part 192
Subpart J and its MAOP must then be established according to the following criteria:
a) The MAOP after the requalification test is 0.8 times the test pressure for Class 2 locations, 0.667
times the test pressure for Class 3 locations, and 0.555 times the test pressure for Class 4
locations.
b) The corresponding hoop stress may not exceed 72 percent of SMYS of the pipe in Class 2
locations, 60 percent of SMYS in Class 3 locations, or 50 percent of SMYS in Class 4 locations.
c) For a pipeline operating at an alternative maximum allowable operating pressure per§ 192.620,
the alternative maximum allowable operating pressure after the requalification test is 0.8 times
the test pressure for Class 2 locations and 0.667 times the test pressure for Class 3 locations.
The corresponding hoop stress may not exceed 80 percent of SMYS of the pipe in Class 2
locations and 67 percent of SMYS in Class 3 locations.
The MAOP confirmed or revised in accordance with this section, may not exceed the MAOP established
before the confirmation or revision.
OPERATIONS REV. NO. 11
CLASS LOCATIONS DATE 01/01/24
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Utilities NATURAL GAS SPEC. 4.16

Confirmation or revision of the MAOP of a segment of pipeline in accordance with this section does not
preclude the application of the general requirements of Uprating in §192.553 and §192.555— Uprating to
a pressure equal to or greater than 30 percent of SMYS.
MAOP Reconfirmation
Transmission pipeline segments operating in a Class 3 or 4 location, or in a High Consequence Area
(HCA) must have records necessary to establish the MAOP per 192.619(a), including requirements of
192.517(a)that are Traceable, Verifiable and Complete (TVC). If TVC records are not available, the
MAOP Reconfirmation procedure set out in the Transmission Integrity Management Program (TIMP)
document shall be followed.
For pipelines with MAOP established per 192.619(c), also known as the "grandfather clause", the MAOP
shall be reconfirmed per the TIMP document if the pipe segment operates at greater than or equal to 30
percent SMYS and is in a Class 3, Class 4, or HCA location.
Documentation of MAOP Revisions
Changes identified through the class location study and the MAOP confirmation or revision review shall
be documented and retained for the life of the asset.
Records
Records shall document the current class location of each transmission pipeline segment and how each
class location was determined. This will be kept with the document for Transmission Integrity
Management Program (TIMP) and maintained according to that document's retention policy.
OPERATIONS REV. NO. 11
CLASS LOCATIONS DATE 01/01/24
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Utilities NATURAL GAS SPEC. 4.16

4.17 UPRATING
SCOPE:
To establish procedures to be followed when increasing the maximum allowable operating pressure(s)of
Avista gas distribution and transmission pipeline facilities.
REGULATORY REQUIREMENTS:
§192.503, §192.551, §192.553, §192.555, §192.557, §192.619\
WAC 480-93-020, 480-93-155, 480-93-160
CORRESPONDING STANDARDS:
Spec. 2.12, Pipe Design - Steel
Spec. 2.13, Pipe Design — Plastic (Polyethylene)
Spec. 3.18, Pressure Testing
Spec. 4.15, Maximum Allowable Operating Pressure (MAOP)
Spec. 5.11, Leak Survey
General
Determinations relating to the raising of MAOP of a pipeline shall be made by Gas Engineering in
coordination with the local construction office. Uprating procedures in the field shall be performed by
properly trained and qualified personnel.
An uprate shall be conducted only after the system has been assessed for integrity impacts. This
assessment will be conducted by both the assigned Gas Engineer and the Pipeline Integrity Program
Manager as part of the historical records review to determine if the pipelines should be uprated. This may
include a risk analysis.
When it is determined that it is necessary to raise the MAOP of a pipeline via an uprate, the general
procedures outlined in this Specification shall be used:
Uprating Requirements
Review of Design, Operation and Maintenance History—The history of the segment to be uprated shall
be reviewed to include materials of construction and pressure ratings of valves and fittings used, cathodic
protection history, and history of exposed pipe reports including external and internal inspections of the
pipes performed in the past. The review shall include a listing of pipe footage to be uprated by size,
material, and installation year.
Previous leak survey results should be considered to ensure there is no indication the segments being
uprated are prone to leaks. Previous pressure tests should be collected for mains and services and
included in the uprate file. If there are segments of plastic pipe included in the uprate, which do not have
pressure test records showing a pressure test of 1.5X the intended MAOP after the uprate, then the
uprate shall be conducted to 1.5X the intended final MAOP.
The review shall also include a listing of all meter sets within the uprate area and an analysis of the
adequacy of regulator used for pressure rating, as well as relief capacity at the highest pressure the
regulator will be subjected to during the uprate.
OPERATIONS REV. NO. 15
UPRATING DATE 01/01/23
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Utilities NATURAL GAS SPEC. 4.17

Written Plan -A written plan shall be developed by Gas Engineering that details the procedures to be
followed before, during, and after the uprating process. Gas Engineering shall review the design,
operating, and maintenance history of the pipeline segment to assure that the pipeline can be operated
safely at the new MAOP, and that regulatory requirements are satisfied. A written plan shall schedule the
uprate procedure to assure that once the uprate procedure is started, it is completed in as short a time as
practicable, considering weather conditions, need for delay to make system repairs, etc.
Incremental Pressure Increases- Increases in operating pressure that are made in increments under the
uprating plan shall be performed gradually and at a rate that can be safely controlled.
Leak Survey-The pipeline segment shall be leak surveyed prior to the uprating procedure if it has been
more than one year since the last leak survey. At the end of each incremental increase, the pressure shall
be held constant while the entire pipeline segment is again checked for leaks. A final leak survey shall be
done at the conclusion of the uprating process.
Repairs - Each leak detected must be repaired before a further pressure increase is made. (Exception: a
leak determined not to be potentially hazardous need not be repaired, if it is monitored during the
pressure increase and it does not become potentially hazardous). Other repairs necessary to ensure the
safe operation of the pipeline segment shall be completed prior to any pressure increases.
Limitation - Except as provided for elsewhere in this standard, a new MAOP established under these
procedures shall not exceed the maximum pressure that would be allowed for a new segment of pipeline
constructed of the same materials in the same location.
Uprating Pipeline to Hoop Stress <30 Percent SMYS
Before increasing the operating pressure above the previously established MAOP, the above-mentioned
general procedures shall be adhered to with the following additions: Repairs, alterations, and
replacements in the pipeline segment, which are necessary for safe operation at the increased pressure,
shall be performed before increasing operating pressure. This includes replacing reinforcing or anchoring
offsets, bends, and end caps in pipe joined by compression couplings to prevent failure of the pipe joint if
the offset, bend, or end cap is exposed in an excavation. Service replacements or insertions, as well as
relocations of meter sets, shall also be completed prior to increasing pressure.
The segment of pipeline to be uprated should be physically separated (except through a regulator with
overpressure protection or valve)from any adjacent segment that will continue to be operated at a lower
pressure. The segment being uprated shall have pressure gauges installed (or chart recorders) and shall
be monitored before, during, and after each incremental pressure increase. In addition, any adjacent
pipeline system or segment that will continue to be operated at a lower pressure than the segment being
uprated shall be monitored with pressure gauges (or pressure recording devices) before, during, and after
the uprating process to ensure that overpressuring does not occur due to unknown pipe connections.
Increases in the MAOP shall be made in increments that are equal to 10 psig or 25 percent of the total
pressure increase (whichever produces the fewest number of increments).
Uprating Pipeline to Hoop Stress>_30 Percent SMYS
Consult Gas Engineering before considering an uprate that would produce a hoop stress of 30 percent
SMYS or higher. If the uprate moves forward, §192.555 must be followed.
OPERATIONS REV. NO. 15
UPRATING DATE 01/01/23
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Utilities NATURAL GAS SPEC. 4.17

Considerations for Uprating Steel Pipelines
When uprating steel gas pipelines, the design pressure of the weakest element shall be determined in
accordance with 192.105.
If any of the variables necessary to determine the design pressure are unknown, one of the following
pressures is to be used as the design pressure:
• Eighty percent of the first test pressure that produces yield under section N5 of Appendix N of ASME
B31.8, reduced by the appropriate factor in 192.619(a)(2)(ii)
• If the pipe is 12 1/4" or less in outside diameter and is not tested to yield, the design pressure shall be
200 psig.
Uprate in the State of Washington
Washington Administrative Code (WAC 480-93-155) requires the following reporting procedures in
addition to the above stated uprating procedures:
When increasing the MAOP of any pipeline or facility to a pressure over 60 psig, the Commission shall be
provided with a written plan and drawings at least 45 days prior to raising the pressure.
The plan shall include a review of the following:
• All affected gas facilities, including pipe, fittings, valves, and other associated equipment along with
their manufactured design operating pressure, their specified minimum yield strength (SMYS)at the
intended MAOP and any other applicable specifications or limitations.
• Original design and construction standards.
• Original pressure test records.
• Previous operating pressures, identifying the dates and lengths of time at that pressure.
• All leaks, regardless of cause, on the segment and the date and method of repair.
• Where the pipeline is being uprated to an MAOP of over 20 percent of the SMYS, records of the
original welding standards and welders.
• Maintenance records for all affected regulators and relief valves for the past 3 years or three most
recent inspections, whichever is longer.
• Where applicable, relief valve capacities compared to regulator flow capacities, with calculations.
• Cathodic protection readings of the affected pipeline and facilities, including rectifier readings, for the
past 3 years or three most recent inspections, whichever is longer.
• Any additional records that commission staff may deem necessary to evaluate the pressure increase.
Washington Administrative Code requires certain proximity considerations, which must be addressed
when planning to uprate above 250 psig. Refer to Specification 2.12, Pipe Design —Steel, "WA State
Proximity Considerations"for more information.
UPRATING PROCEDURE -TYPICAL SEQUENCE OF EVENTS:
Prior to Pressure Increase
• An integrity impact review is completed by Gas Engineering and the Pipeline Integrity Program
Manager which includes a review of the design, operating and maintenance history of the pipelines to
be uprated.
• The first page of the Written Plan for Pressure Uprating (N-2757) document shall be filled out as
completely as possible by the Gas Engineer. Include any addendum showing calculations on
regulators and relief valves, mechanical fittings in the system, pressure design ratings of valves and
other components, changes to odorization system, etc.
• A review of the uprate plan is conducted with key stakeholders.
OPERATIONS REV. NO. 15
UPRATING DATE 01/01/23
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Utilities NATURAL GAS SPEC. 4.17

• A map or drawing is prepared showing the segment to be uprated, along with any lateral connections.
Pipeline sizes should be shown as well as the physical location of valves, regulator stations,
mechanical fittings, stubs, services to be replaced, meters to be re-located, system isolation points,
MAOP's of adjacent systems, and preferred locations of pressure gauges.
• A leak survey is completed on the entire segment and related facilities operating at the current MAOP
and results are documented in the Leak Survey Map Viewer or paper maps for a special survey.
• Hazardous leaks are repaired. Grade 2 and 3 leaks are addressed as outlined in Specification 5.11,
Leak Survey. All other replacements, repairs, alterations, etc. are completed. Information is recorded
on the Written Plan for Pressure Uprating (N-2757) document or on separate work orders and
retained in the uprate file.
• Pressure monitoring gauges or recorders are installed, and pressures noted (normally done on the
day of the uprate, unless otherwise required.) Pressure gauges should be installed on adjacent
systems of lower pressures to avoid overpressuring.
During the Pressure Increases
• Field employees monitor pressure gauges or recorders as segment pressure is gradually increased to
the first increment.
• A leak survey is again conducted while the increased pressure is held constant at the first increment.
If hazardous leakage is discovered or if the pressure does not stabilize, the pressure should be
lowered, and the necessary repairs completed. Repairs should be documented on the Written Plan
for Pressure Uprating (N-2757) document or on a separate work order and retained in the uprate file.
• District regulator stations should be checked to verify the integrity of the regulators by checking the
downstream pressures.
• When a subsequent leak survey indicates no hazardous leakage, the segment pressure may then be
increased to the next incremental step. Continue to follow the above procedures until the final MAOP
is safely achieved at the last pressure that establishes it(typically 1.5 times MAOP).
• Document all work and other information on the Written Plan for Pressure Uprating (N-2757)
document.
• A final leak survey at this highest pressure is performed and hazardous leaks are repaired. Grade 2
and 3 leaks are addressed as outlined in Specification 5.11, Leak Survey.
• Each time the pressure of the system is to be increased or decreased, Pressure Controlmen must
contact the Gas Control Room (509-495-4859 or via radio)to inform them of the change.
Uprate Acceptability Criteria
A final review of all uprate information should be performed before the new MAOP is approved.
Final approval is needed by the Gas Engineering Manager and the Pipeline Integrity Program Manager.
Examples of information to be reviewed include:
• Leak data and trending—Were the number of underground leaks trending up or down?
• Material reports— Did the Exposed Piping Inspection Reports indicate any material issues?
• Processes followed—Were the processes for the uprate followed correctly? Were any critical steps
missed or not performed adequately?
If it is deemed that the uprate project has not met this final acceptability criteria, the system will be
returned to a pressure below this MAOP that is deemed safe and acceptable per this requirement which
may require returning to the original MAOP.
Following acceptance of the uprate, the first page of the Written Plan for Pressure Uprate (N-2757)
document should be stamped by a Professional Engineer as certification of the new MAOP and the
uprate package containing all pertinent information shall be retained for the life of the pipeline.
OPERATIONS REV. NO. 15
UPRATING DATE 01/01/23
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Utilities NATURAL GAS SPEC. 4.17

Consideration should be given when needed to perform additional safety measures and may include:
• Performing additional leak surveys after the final MAOP is achieved.
• Pipe or other facility replacements
• Pressure checks at meter sets
• Supplemental risk modeling
After Final MAOP is Achieved
If the project has been deemed acceptable, then:
• The new MAOP is declared, and the system is set back to its final operating pressure.
• Pressure gauges or recording devices are removed (unless required to remain in place).
• Records are noted as to the new MAOP, including the regulator station maintenance records.
Gas Engineering shall make a final review of the segment uprating file to ensure compliance with
regulatory codes and Avista standards and retain this record for the life of the pipeline segment.
Recordkeeping
Data pertaining to the uprating procedure for each pipeline segment shall be recorded on the Written Plan
for Pressure Uprating (N-2757) document located on the Gas Wiki SharePoint website, and on any
written addendum as required.
The information on the Gas Uprating Data sheet and addendum shall include the following:
• Type of work, investigations, and tests performed.
• Documentation of leak surveys performed, including maps used.
• Leaks detected and repaired.
• Pipeline or facility alterations, repairs, or replacements completed.
• Documentation of actual incremental pressure increases and type of gauge or pressure recording
devices used.
• Dates and names of persons responsible for each specific uprating task.
Gas Engineering shall retain the documents relating to any uprating procedure (including design
specifications)for the life of the pipeline segment.
OPERATIONS REV. NO. 15
UPRATING DATE 01/01/23
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Utilities NATURAL GAS SPEC. 4.17

4.18 ODORIZATION PROCEDURES
SCOPE:
To establish uniform odorant sampling procedures for Avista and to ensure that the proper concentration
of odorant exists as per applicable codes.
REGULATORY REQUIREMENTS:
§192.625
WAC 480-93-015
CORRESPONDING STANDARDS:
Spec. 2.52, Odorization of Natural Gas
Spec. 5.23, Odorization Equipment Maintenance
General
This specification details the requirements and procedures necessary to assure that the Company's
natural gas supplied to Avista's customers is odorized as required by code. Procedures for adding
odorant to the pipeline system, testing to assure even distribution and proper concentration, and
recordkeeping are also covered in this specification. Maintenance related to odorization equipment shall
be performed by personnel trained and qualified in the maintenance of such odorization equipment and
systems.
Natural gas supplied to customers by Avista will be odorized. Natural gas will generally be odorized at or
near the gate station except where such gas is adequately odorized as received from the pipeline
company.
Odorant Concentrations
Natural gas shall be odorized to a level that will enable detection by a person with a normal sense of
smell at a minimum of 20 percent LEL or a minimum of 1.0 percent gas in air. To enhance public safety, it
is Avista's intent to odorize the gas to a minimum level of 8 percent of the LEL or a minimum of 0.40
percent gas in air. These levels (often called the Readily Detectable Level)are to be measured and
recorded with a Company-approved odorometer.
When sampling odorant and the first read is higher than 0.40 percent gas in air(indicating a lesser
concentration of odorant than desired) a second read should be taken to verify the reading. If a second
read confirms low odorant levels, the read should be verified by another qualified individual to rule out the
possibility of human error. If the low read is confirmed, system changes should be made to address the
situation. This can include odorizer or regulator station adjustments. A follow-up read should be
completed to confirm adequate odorization levels. The follow-up read is typically done a day or two (or
the next business day if the adjustment is made on a Friday, weekend, or a holiday) after the system
adjustment is made to allow time for the odorant levels to change. The time required for the adjustment to
take effect may depend on the time of year, the system load, and other factors. Additional adjustments
may be required to achieve the desired odorant concentration.
When odorization is performed by an interstate pipeline, the applicable operations manager will contact
Gas Engineering to initiate odorant level adjustments.
OPERATIONS REV. NO. 18
ODORIZATION PROCEDURES DATE 01/01/25
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Utilities NATURAL GAS SPEC. 4.18

Pickling Newly Installed Piping
Newly installed steel and PE pipelines tend to absorb the odorant from the gas stream. This is especially
true for pipelines that are gassed up, but not immediately put into service. "Pickling" is a process to
address the problem of lower than adequate odorant being present in the gas stream due to pipe
absorption.
The most common way to pickle a pipe is to increase the odorant injection rate at the odorizer supplying
gas to this pipeline. This increased injection rate should stay in effect until the pipe walls are no longer
absorbing the odorant. Frequent monitoring of the downstream system for adequate odorization should
be done to determine when the odorizer can be returned to its previous setting. These actions should be
taken with the intent of accomplishing the pickling as soon as possible after putting the pipeline into
service. Contact Gas Engineering for further assistance.
Odorant Sampling
Avista shall perform monthly sampling (tests)of natural gas in the system to assure that the proper
concentration of odorant exists. These tests shall be performed in accordance with procedures outlined in
this specification and in accordance with applicable manufacturer's instructions. The determination of
odor intensity shall be made by performing an odorometer test at various customers' premises.
Odorometer tests shall be made at points in the gas distribution system and spaced so as to give an
accurate representation of odorant concentrations across the system. The Gas Planning Engineer can
assist in specifying general test point locations. New test points shall be established as necessary as
system growth occurs.
Test Point Review
Each area shall review their test points once each calendar year. This review shall be noted on the
sampling form to determine if existing test points are still valid or if test points have been moved based on
the review. Field personnel shall conduct odorometer tests as near to these locations as is practical.
Field personnel are encouraged to allow customers to help perform odorometer sniff tests.
Odorometer sniff tests shall be conducted in an odor-free environment. Persons conducting the tests
should have a normal sense of smell and should not perform the test if they have a head cold or other
illness that might affect the normal sense of smell. Breath mints, washes, or medicines that can affect the
sense of smell shall also not be used prior to conducting the test.
Odorometer test procedures shall follow the manufacturer's recommendations. The effectiveness of the
distribution of odorant shall be determined from periodic reports made by appropriate, trained field
personnel.
Locations Where Odor is Inadequate
Locations where the odorant usage is shown to be inadequate shall be re-checked immediately (refer to
the Odorant Concentrations section above). If the re-check indicates that the odorant level is indeed
inadequate, field personnel shall proceed to check other locations close to the original location for proper
odorant level until the area of inadequacy is completely defined. The cause of the inadequacy shall be
determined and addressed as soon as possible, preferably by the end of the next day. Oftentimes the
inadequacy can be corrected by odorizer or regulator station adjustments. If unable to determine the
cause of the inadequacy, contact Gas Engineering for assistance.
OPERATIONS REV. NO. 18
ODORIZATION PROCEDURES DATE 01/01/25
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Utilities NATURAL GAS SPEC. 4.18

Odorant Level Analysis
Operations personnel shall adjust odorizers as necessary to assure odorant levels remain within
specification. Gas Engineering may aid with odorizer level adjustments. If odorization is provided by the
gas supplier, the supplier shall be notified of inadequate levels so that adjustments can be made.
Periodic Odorizer Station Inspectors
Odorizer maintenance shall be performed per the requirements outlined in Specification 5.23, Odorizer
Equipment Maintenance.
Recordkeeping
Odorometer sampling results, verification results, and follow-up actions shall be recorded on the Odorizer
form (Form N-2621). Completed forms shall be retained for a minimum of 5 years.
YZ ODOROMETER (DTEX):
General
DTEX is a small, handheld instrument, which assists the user in determining the odorant intensity of
natural gas with menu-driven step-by-step instructions. The DTEX system can accept inlet pressure from
5-inches WC up to a maximum of 5 psig. This unit records the actual air/gas percentage for both
threshold detection level (TDL) and readily detectable level (RDL) and can be downloaded into a
computer to print a report. This unit is intrinsically safe for hazardous locations Class 1, Division 1,
Groups C and D.
Operating Instructions
The following procedures should be followed when testing to determine odorant level in distribution
systems using this type of odorometer:
• Always keep the instrument dry. It should be protected from water, open flames, and any other
potential source of damage.
• Avoid conducting tests in windy conditions or in closed, confined spaces.
• Operators should be selected with consideration to smoking habits, colds, and other health
conditions since these factors may affect the operator's sense of smell. It is essential to select
operators with an average sense of smell in order to obtain reasonable consistent results from the
use of the instrument.
• Connect the gas inlet hose to the test source connection and open the source isolation valve.
• Power up the system by pressing the PWR button on the keypad. The fan will begin to run
automatically as part of a system hardware check.
• Use arrow keys to scroll information in the screen up and down. Press P to purge the unit before
a test. Open the flow valve fully until you smell gas then close valve and press Enter to continue.
The gas inlet hose and internal regulator must be filled with gas prior to running a test for
accurate test results.
• Press TEST button and then follow the step-by-step instructions to sign on and enter location
information for each test site.
OPERATIONS REV. NO. 18
ODORIZATION PROCEDURES DATE 01/01/25
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Utilities NATURAL GAS SPEC. 4.18

Threshold Detection Level(TDL)
1. Position nose within 3/4-inch of the sniff chamber and with valve closed sniff exhaust. Note: If
an uncharacteristic odor is detected, allow the instrument to operate for an additional two
minutes. If uncharacteristic odor persists, perform an exhaust background evaluation test.
2. Slowly open the flow valve and sniff exhaust. Continue to open the flow valve and sniff getting
breaths of fresh air between sniffs. Continue the procedure until the first hint of a new odor is
detected. This is the threshold detection level (TDL); this is the minimum concentration of gas
in air when one detects a new or different odor.
3. Remove nose from sniff chamber.
4. Press the Record Test Level (RTL) key, this records the threshold detection level (TDL).
Readily Detectable Level(RDL)
1. Position nose within 3/4-inch of the sniff chamber.
2. Continue to open the flow valve until the readily detectable odor of gas is attained. This is the
readily detectable level (RDL), which is the determination that natural gas odor can be
positively identified.
3. Remove nose from sniff chamber.
4. Press the Record Test Level (RTL) key, this records the readily detectable level (RDL).
5. The test is completed; close valve and press Enter.
6. Add any notes such as "windy," or if there was something that affected the test such as car
exhaust then press Enter.
7. Press the PWR key. Several options will be displayed in the screen. After each test select V
to vent the unit to prevent undue saturation of inlet hose and system components and
residual smell in the unit.
• Close the source isolation valve.
• Remove the gas inlet hose from the source of connection.
• Press V to vent
• Open the flow valve fully
• Wait until prompted on screen, then close flow valve
• Press PWR to shut down
Manufacturer's instructions are necessary for proper operation of any instrument. Manufacturer's
instructions shall supersede any general instructions in these procedures.
Exhaust Background Evaluation
Approximately every 30 days the instrument should be checked for an exhaust background evaluation.
Without connecting gas to the inlet, power on the unit, open the flow valve fully and press P on the
keypad to purge the unit. Purge for two minutes before closing the valve and pressing the Enter key to
conclude the purge procedure. If after two minutes the smell persists over and above normal
background, send the unit in to be serviced.
Calibration of Instrument
The DTEX odorometer should be calibrated every two years (Note: The DTEX calibration due date is
displayed each time the unit is powered on). This calibration must be performed by the manufacturer and
the record of the calibration shall be retained for a minimum of five years. The calibration request to the
manufacturer should specifically state for them to perform a "Two Year Calibration" on the unit.
OPERATIONS REV. NO. 18
ODORIZATION PROCEDURES DATE 01/01/25
X-4, sr'a STANDARDS 4 OF 4
Utilities NATURAL GAS SPEC. 4.18

4.19 CREW ACTIVITY REPORTING -WASHINGTON
SCOPE:
To establish a uniform reporting procedure for Avista's construction areas in the state of Washington for
reporting crew activities per the applicable code.
REGULATORY REQUIREMENTS:
WAC 480-93-200
CORRESPONDING STANDARDS:
Section 3.0, Construction
Section 5.0, Maintenance
General
This section details the requirements necessary to ensure Avista's construction areas within in the state
of Washington, report construction and repair crew activities as required by the Washington Utilities and
Transportation Commission (WUTC). WUTC safety inspectors who perform random crew inspections
utilize this report and rely heavily on it to be detailed and accurate.
Daily Reporting
Each construction office or entity (including the Gas Facility Replacement Program) shall email (on a
daily basis, no later than 10:00 a.m.), a list of each crew and where they are scheduled to perform
construction and/or repair activities. The list shall be broken down by individual crews and the scheduled
work must be listed by address or at a minimum, cross streets and the town or city where the activity is
scheduled. (The term "crew" includes Avista crews as well as contract crews that are working for Avista.)
Be sure to include a phone number(s) on the report for the person(s)to call if the WUTC needs to verify a
crew location or has other questions. Contractors working on behalf of Avista (e.g., GFRP Contractor)
may be allowed to directly submit their daily construction reports to the WUTC. Consult with Avista's
Pipeline Safety Engineer prior to beginning this process.
The report should contain construction activity and repair activity scheduled for that particular day.
Submission of all planned work scheduled for the entire week is acceptable, but the report must be
updated and submitted every day and reflect applicable changes/updates to the schedule. If no
construction activities are scheduled in a particular construction area, then no report is required.
Submission of Reports
The daily report must be submitted by e-mail to the following e-mail address. (Be sure to include a
descriptor in subject line of the email as to the purpose of the email such as "Avista Gas Crew Schedule
Colville" or"Crew Notification Ritzville District".)
pipeline(a-)_utc.wa.qov
WUTC Contact
If experiencing problems submitting the daily report, call the WUTC office assistant at 360-664-1182 for
assistance and to explain the problem. The phone call notifies the WUTC of the attempt to comply with
WAC 480-93-200(12).
OPERATIONS REV. NO. 10
CREW ACTIVITY REPORTING -WA DATE 01/01/21
X-4, sr'a STANDARDS 1 OF 1
Utilities NATURAL GAS SPEC. 4.19

4.2 CUSTOMER NOTIFICATION
4.22 CUSTOMER OWNED SERVICE LINES
SCOPE:
To establish procedures for ongoing notifications to Avista's gas distribution customers regarding the
potential hazards concerning buried downstream gas piping systems and the corresponding remedies
and resources available for correction of discovered leakage, damage, or corrosion.
REGULATORY REQUIREMENTS:
§192.16
CORRESPONDING STANDARDS:
None
General
Operators of gas distribution systems are required to make certain notifications to gas customers
concerning customer owned service lines and buried customer piping systems.
This rule applies only to operators who do not maintain the customer's buried piping up to entry of the first
building downstream of the meter or if the customer's piping does not enter a building, up to the principal
gas utilization equipment or the first fence (or wall)that surrounds that equipment.
Required Information
The following items are required to be included in the written notifications:
• Avista does not maintain the customer's piping.
• If a gas customer's piping is not maintained, it may be subject to the potential hazards of corrosion
and leakage.
• Buried gas piping should be periodically inspected for leakage and corrosion, as applicable.
• Any unsafe conditions discovered on customer piping should be corrected immediately or as soon as
practical, depending on the nature of the problem.
• If customers excavate near buried gas lines, the piping should be located in advance and the
excavation should be performed by hand to avoid damage to the pipelines.
• There are resources available to assist in locating, inspecting, and repairing the customer's buried
gas lines. These resources include licensed plumbers, dealers, and heating contractors.
One-Time Notification
As required by code, an appropriate written customer notification was prepared and distributed to Avista
natural gas customers prior to August 14, 1996. The customer notification included the information
required by§192.16, as detailed above.
OPERATIONS REV. NO. 5
CUSTOMER NOTIFICATION DATE 01/01/24
X-4, sr'a STANDARDS 1 OF 2
Utilities NATURAL GAS SPEC. 4.22

Ongoing Notification
Natural gas customers shall be notified of the information required by§ 192.16 within 90 days after
establishing service at a particular location.
The written notification may be provided in the new customer information packet/communication, inserted
into the first billing, or mailed separately to the customer establishing service.
Customer Service shall be responsible for identifying each new gas customer and for ensuring that the
written notification is mailed to the customer within the 90-day time frame.
Recordkeeping
Documentation of the notifications shall be retained by the Pipeline Safety Engineer. Evidence of
notifications shall be retained for a period of 3 years.
OPERATIONS REV. NO. 5
CUSTOMER NOTIFICATION DATE 01/01/24
X-4,15y' a STANDARDS 2 OF 2
Utilities NATURAL GAS SPEC. 4.22

4.3 AVISTA UTILITIES' OPERATOR QUALIFICATION PROGRAM
4.31 OPERATOR QUALIFICATION
SCOPE:
The purpose of Avista's Operator Qualification Program (OQ Program) is to ensure individuals performing
covered tasks on Avista's gas pipelines and facilities are fully qualified in accordance with §192, Subpart
N and State regulation. The OQ Program is detailed in a separate document that is maintained by the
Manager of Operator Qualification (OQ). The OQ Program outlines accountabilities, responsibilities, and
the procedures for identifying covered tasks, evaluation intervals, span of control, recordkeeping
requirements, and other administrative practices. The goal of the OQ Program is to help ensure a
qualified work force and to reduce the probability and consequence of incidents caused by human error.
As of October 28, 2002, individuals performing covered tasks shall either be qualified or work under the
direction of a qualified individual.
REGULATORY REQUIREMENTS:
§191.3, §192.3, §192.756, §192.801, §192.803, §192.805, §192,807, §192.809
WAC 480-93-013, 480-93-999
CORRESPONDING STANDARDS:
See standards referenced by task in Appendix A of this specification.
General
Avista has established and maintains a qualified workforce in accordance with §192 Subpart N, State
regulatory requirements, and through incorporation of industry practices. A qualified employee is one that
has been evaluated and can perform assigned covered tasks and recognize and react to abnormal
operating conditions (ADCs).
OPERATIONS REV. NO. 21
OPERATOR QUALIFICATION PROGRAM DATE 01/01/22
X-4, sr'a STANDARDS 1 OF 1
Utilities SPEC. 4.31
NATURAL GAS

OPERATOR QUALIFICATION COVERED TASK LIST - APPENDIX A
TASK INDEX TABLE
TASK NO. TASK NAME PAGE NO.
221.060.010 Abandon or Inactivate Facilities 3
221.020.040 Avista Side Leak Investigation- Inside 3
221.020.035 Avista Side Leak Investigation-Outside 3
221.110.030 CP-Atmospheric Coating Maintenance 4
221.110.025 CP-Coating Maintenance for Buried Pipe 4
221.110.020 CP-Identify Atmospheric Corrosion 4
221.110.015 CP-Identify Corrosion on Buried Pipe 4
221.110.035 CP-Install Cathodic Test Leads and Stations 5
221.110.055 CP-Pipe to Soil Testing 5
221.110.050 CP-Rectifier Adjustment and Repair 5
221.110.060 CP-Rectifier Output Testing 6
221.120.070 Damage Prevention 6
221.120.090 Install and Maintain Casings 6
221.120.110 Install and Maintain Pipeline Markers 6
221.070.041 Install Gas Meters: Large Commercial 7
221.070.045 Install Gas Meters: Residential and Small Commercial 7
221.120.115 Install Gas Pipelines- Plastic 7
221.120.125 Install Gas Pipelines-Steel 8
221.120.130 Install and Repair Tracer Wire-Plastic 8
221.230.005 Leak Survey 8
221.080.045 Line Heater Maintenance 9
221.230.050 Locate Gas Pipelines 9
221.230.035 Monitoring Pipeline Pressures 9
221.080.047 Monthly Line Heater Maintenance 10
221.130.015 Non-Destructive Testing of Welds 10
221.090.025 Odorization-Odorizer Maintenance 10
221.090.035 Odorization-Odorizer Adjustment 11
221.090.030 Odorization-Periodic Odorant Testing 11
221.230.055 Operate Gas Pipeline: Local Facility Remote-Control Operations 11
OPERATIONS REV. NO. 25
APPENDIX A—QUAL. COVERED TASK LIST DATE 01/01/25
�rVISTA STANDARDS 1 OF 18
Uti►ities NATURAL GAS SPEC. 4.31 A

OPERATOR QUALIFICATION COVERED TASK LIST - APPENDIX A
221.230.001 Patrolling Gas Pipelines 12
221.030.001 PE Pipe Join ing-Electrofusion 12
221.030.010 PE Pipe Joining-Hydraulic Butt Fusion 12
221.030.005 PE Pipe Joining-Manual Butt Fusion 12
221.030.020 PE Pipe Joining-Mechanical Couplings 13
221.030.015 PE Pipe Joining-Mechanical Service Tees 13
221.030.025 PE Pipe Joining-Mechanical Spigot and Sleeve Type Fittings 13
221.120.085 Pipe Bending 13
221.100.065 Pipe Squeezing 14
221.120.120 Pipeline Cover, Clearance& Backfill 14
221.120.075 Pressure Testing Gas Pipelines 14
221.230.040 Prevention of Accidental Ignition 15
221.120.080 Purging Gas Pipelines 15
221.070.070 Recognizing Unsafe Meter Sets 15
221.080.035 Regulator Station-5/10 Year Maintenance 15
221.080.030 Regulator Station-Annual Maintenance 16
221.080.025 Regulator Station-Bypassing 16
221.060.015 Repair Gas Pipelines 16
221.070.020 Replace Service Valves 17
221.040.001 Tapping and Stopping-Mueller 4"and Smaller 17
221.040.010 Tapping and Stopping-Mueller 6"and Larger 17
221.040.005 Tapping and Stopping-TDW 4"and Smaller 18
221.040.015 Tapping and Stopping-TDW 6"and Larger 18
221.050.005 Valve Maintenance 18
221.080.020 Vault Maintenance 19
221.130.005 Visual Inspection of the Weld 19
221.130.010 Welding 19
OPERATIONS REV. NO. 25
APPENDIX A—QUAL. COVERED TASK LIST DATE 01/01/25
�� i�rrsra STANDARDS 2 OF 18
Utilities NATURAL GAS SPEC. 4.31 A

OPERATOR QUALIFICATION COVERED TASK LIST -APPENDIX A
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.060.010 Abandon or Inactivate Facilities 3 Years Knowledge 1:3
Abnormal Operating Conditions and Remedial Actions:
• Incomplete purge-re-purge and verify
• Uncontrolled release of gas-initiate immediate
Description:Abandon or inactivate gas pipelines and aboveground response
facilities. Identify the requirements for abandoning or inactivating gas 0 Corrosion-remediate and/or report
facilities including discontinuance of gas service to the customer. • Fire or explosion-evacuate and initiate immediate
Recognize and react to abnormal operating conditions. response
Standards referenced: Specification 5.13, 5.16
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.020.040 Avista Side Leak Investigation -Inside 3 Years Knowledge 1:1
Abnormal Operating Conditions and Remedial Actions:
Description: This task includes the investigation of reported or 0 Hazardous gas leak or migration inside structure-
discovered leaks of operators'gas inside a building in relation to initiate immediate response
emergency response which includes initiation of precautionary actions. 0 Gas in a duct or sewer system-implement/initiate
Utilize leak detection equipment. Complete required documentation. emergency procedures
Recognize and react to abnormal operating conditions. • MSA or upstream facilities damaged or leaking-
Note: This task DOES NOT include repairing and/or proving the Repair or initiate repair
integrity of customer piping, customer equipment, or lighting customer Standards referenced: Specification 5.11, Gas Emergency
equipment. Service Handbook Sections 2,4, 17
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.020.035 Avista Side Leak Investigation -Outside 3 Years Knowledge 1:3
Abnormal Operating Conditions and Remedial Actions:
• Hazardous gas leakage-initiate immediate response
Description: Respond and investigate a notice of gas leakage and odor 0 Probe damages/pipe coating-repair or initiate repair
calls(Avista-Side)by utilizing leak detection and bar testing equipment, • Multiple leaks-pinpoint by bar hole testing
be able to pinpoint and grade a leak. Complete required • Other gases present-contact property owner/protect
documentation. Recognize and react to abnormal operating conditions. life&property
• Gas in a duct or sewer system-implement/initiate
Completing this task also satisfies skills required for Leak Survey emergency procedures
(221.230.005)
Standards referenced: Gas Emergency&Service
Handbook, Sections 2 &4.
OPERATIONS REV. NO. 25
APPENDIX A—QUAL. COVERED TASK LIST DATE 01101/25
� i/ISTA STANDARDS 3 OF 18
Utilities NATURAL GAS SPEC. 4.31 A

OPERATOR QUALIFICATION COVERED TASK LIST -APPENDIX A
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.110.030 CP-Atmospheric Coating Maintenance 3 Years Knowledge 1:3
Abnormal Operating Conditions and Remedial Actions:
• Damaged coating-repair coating
Description: Inspect and maintain coatings for aboveground piping. Damaged pipe-repair or report
Identify the requirements for maintaining coatings on aboveground 0 Pitting-repair or report
piping. Using approved materials and procedures, maintain coatings on 0 Corrosion present-repair or report
aboveground pipe. Recognize and react to abnormal operating • Gas leak-initiate immediate response
conditions.
Standards referenced: Specification 5.14, 5.20
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.110.025 CP-Coating Maintenance for Buried Pipe 3 Years Knowledge 1:3
Abnormal Operating Conditions and Remedial Actions:
• Damaged coating-repair coating
• Inadequate coverage or contact-smooth to remove
Description: Inspect and maintain coatings for buried pipe. Identify the wrinkles,voids; re-wrap and remediate
requirements for maintaining coatings for buried pipe. Using approved • Pipe damaged, corroded or pitted-report
materials and procedures maintain coatings on buried pipelines. 0 Debris on wrap—remove debris and re-wrap
Recognize and react to abnormal operating conditions. 0 Gas leak-initiate immediate response
Standards referenced: Specification 3.12, 3.32, 5.14
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.110.020 CP-Identify Atmospheric Corrosion 3 Years Knowledge 1:3
Abnormal Operating Conditions and Remedial Actions:
Description: Monitor aboveground facilities for corrosion. Inspect • Pitting-repair or replace pipe or fitting
aboveground facilities such as regulator stations and meter set • Corrosion present-report and remediate
assemblies for signs of atmospheric corrosion. Recognize and react to Gas leak-initiate immediate response
abnormal operating conditions.
Standards referenced: Specification 5.14, 5.20
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.110.015 CP-Identify Corrosion on Buried Pipe 3 Years Knowledge 1:3
Abnormal Operating Conditions and Remedial Actions:
• Pitting-repair or replace pipe or fitting
Description: Inspect buried pipe for corrosion. Inspect for external and Corrosion present-report and remediate
internal corrosion on buried pipelines. Recognize and react to abnormal . Gas leak-initiate immediate response
operating conditions.
Standards referenced: Specification 3.32, 3.44, 5.14
OPERATIONS REV. NO. 25
APPENDIX A—QUAL. COVERED TASK LIST DATE 01101/25
'A i/ISTA STANDARDS 4 OF 18
Utilities NATURAL GAS SPEC. 4.31 A

OPERATOR QUALIFICATION COVERED TASK LIST -APPENDIX A
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.110.035 CP-Install Cathodic Test Leads and Stations 3 Years Skill 1:1
Abnormal Operating Conditions and Remedial Actions:
Description: Install Cathodic test leads and "Fink"test stations. Identify • Substandard weld-repair and replace
the requirements,tools, materials used to install Cathodic test leads. 0 Gas leak-initiate immediate response
Using a thermo-weld tool, inspect the pipe, prepare the pipe and tool, 0 Fire-evacuate and initiate immediate response
and install test wires following written procedures. Recognize and react
to abnormal operating conditions.
Standards referenced: Specification 2.32
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.110.055 CP-Pipe to Soil Testing 3 Years Skill 1:3
Description: Test pipe to soil potential. Inspect test equipment. Identify Abnormal Operating Conditions and Remedial Actions:
the requirements for performing a pipe to soil read. Perform a proper Low potential read-report to CP technician for action
pipe to soil read. Recognize and react to abnormal operating to take
conditions.
• High potential read-report to CP technician for action
Note: NACE Certification in any of the following areas meets the to take
Operator Qualification Requirements of this Task: CP1 —Cathodic 0Dry ground conditions-wet surrounding area
Protection Tester, CP-2—Cathodic Protection Technician, CP-3—
Cathodic Protection Technologist, or CP-4—Cathodic Protection Standards referenced: Specification 5.14
Specialist.
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.110.050 CP-Rectifier Adjustment and Repair 3 Years Skill 1:3
Description: Inspect and test rectifiers. Identify the requirements for
testing and inspecting a rectifier. Inspect test equipment.Adjust rectifier Abnormal Operating Conditions and Remedial Actions:
output. Troubleshoot issues and replace components Recognize and
react to abnormal operating conditions. Low potential read-investigate and initiate repair
• High potential read-investigate and initiate repair
Note: NACE Certification in any of the following areas meets the
Operator Qualification Requirements of this Task: CP-2—Cathodic
Protection Technician, CP-3—Cathodic Protection Technologist,or CP- Standards referenced: Specification 5.14
4—Cathodic Protection Specialist.
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.110.060 CP-Rectifier Output Testing 3 Years Skill 1:3
Description: Identify the requirements for testing rectifier output.
Inspect test equipment. Perform output(voltage/amperage) readings
and complete required documentation. Recognize and react to Abnormal Operating Conditions and Remedial Actions:
abnormal operating conditions. 0 Low potential read-report issue
• High potential read-report issue
Note: NACE Certification in any of the following areas meets the
Operator Qualification Requirements of this Task: CP-1 —Cathodic
Protection Tester, CP-2—Cathodic Protection Technician, CP-3—
Cathodic Protection Technologist, or CP-4—Cathodic Protection Standards referenced: Specification 5.14
Specialist.
OPERATIONS REV. NO. 25
APPENDIX A—QUAL. COVERED TASK LIST DATE 01101/25
'Advisma STANDARDS 5 OF 18
Utilities NATURAL GAS SPEC. 4.31 A

OPERATOR QUALIFICATION COVERED TASK LIST -APPENDIX A
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.120.070 Damage Prevention 3 Years Knowledge 1:3
Description: Prevent damage to pipeline facilities through public
education, physical marking,work practices, and inspections. Identify Abnormal Operating Conditions and Remedial Actions:
dig laws and requirements for excavating around buried facilities. 0 Un-marked facility-report to appropriate owner
Educate the public and contractors on the One Call System. Prevent 0 Damaged facility-report or repair
physical damage to facilities when working on or near the facility.
Provide on-site inspections of excavation activities near pipeline
facilities when necessary. Standards referenced: Specification 4.13
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.120.090 Install and Maintain Casings 3 Years Knowledge 1:3
Abnormal Operating Conditions and Remedial Actions:
Description: Install and maintain casings. Identify the requirements for 0 Shorted casing-report and remediate
installing casings, casing vents, and casing seals. Install casings in 0 Gas leak-initiate immediate response
accordance with design and written procedures including installing 0 Fire-evacuate and initiate immediate response
casing vents and seals, Cathodic test leads, and installation to prevent 0 End seals leaking-repair or replace
damage to the gas carrier pipe. Recognize and react to abnormal 0 Damaged vent pipe-repair or replace
operating conditions.
Standards referenced: Specification 2.32, 3.42, 5.14
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.120.110 Install and Maintain Pipeline Markers 3 Years Knowledge 1:3
Description: Install and maintain gas pipeline markers and signage. Abnormal Operating Conditions and Remedial Actions:
Identify the requirements for installing and maintaining various types of • Missing or damaged markers-repair or replace
pipeline markers. Install pipeline markers as close as practical over 0 Improper signage-replace
distribution and transmission lines. Maintain pipeline markers in • Signage not legible-replace signage
accordance with gas standards. Recognize and react to abnormal
operating conditions. Standards referenced: Specification 5.15
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.070.041 Install Gas Meters: Large Commercial 3 Years Skill 1:1
Description: Install, maintain,and protect large commercial meter set Abnormal Operating Conditions and Remedial Actions:
assemblies. Identify the codes and standards for meter location, MSA in an improper location-relocate or vent
installation, and protection of the large commercial meter set assembly. regulator
Purge the service riser and install and protect the meter set in MSA and piping under stress-reset or re-pipe
accordance with gas standards requirements.Verify regulator flow and . MSA unprotected-barricade, move, coat
lock up.Adjust regulator set points as needed. Recognize and react to MSA is leaking-repair or report
abnormal operating conditions.
• No lock-up-repair or replace
NOTE: Diaphragm meters (AL1400,AL2300,AL5000)and all rotary • Regulator out of adjustment-adjust set point
meters with a metering pressure of 7"WC, 2 psig, or 5 psig are covered Uncontrolled release of gas-initiate immediate
by this task. response
Completing this task also satisfies skills required for Recognizing Standards referenced: Specification 2.22, 2.23, 2.24(tables
Unsafe Meter Sets (221.070.070) and dwgs), 5.12 and GESH 6.
OPERATIONS REV. NO. 25
APPENDIX A—QUAL. COVERED TASK LIST DATE 01101/25
'Advisma STANDARDS 6 OF 18
Utilities NATURAL GAS SPEC. 4.31 A

OPERATOR QUALIFICATION COVERED TASK LIST -APPENDIX A
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.070.045 Install Gas Meters: Residential and Small 3 Years Skill 1:1
Commercial
Abnormal Operating Conditions and Remedial Actions:
Description: Install, maintain, and protect residential and small • MSA in an improper location-relocate or vent
commercial gas meter set assemblies. Identify the codes and standards regulator
for meter location, installation, and protection of the residential and • MSA and piping under stress-reset or re-pipe
small commercial meter set assembly. Purge the service riser and 0 MSA unprotected-barricade, move, coat
install and protect the meter set in accordance with gas standards • MSA is leaking-repair or report
requirements.Verify regulator flow and lock up.Adjust regulator set • No lock-up-repair or replace
points as needed. Recognize and react to abnormal operating 0 Regulator out of adjustment-adjust set point
conditions. . Uncontrolled release of gas-initiate immediate
response
Completing this task also satisfies skills required for Recognizing
Unsafe Meter Sets (221.070.070) Standards referenced: Specification 2.22, 2.23, 2.24(tables
and dwgs), 5.12 and GESH 6
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.120.115 Install Gas Pipelines-Plastic 3 Years Knowledge 1:3
Description: Install plastic gas pipelines. Identify the requirements for Abnormal Operating Conditions and Remedial Actions:
storing, handling, and installing plastic gas pipelines.This includes . Pipe exceeds expiry date-discard pipe
(including setting tracer Finks and anodes), trench requirements, 0 Pipe damaged during handling-cut out or replace
plowing and trenching, and various other installation requirements. . Pulling force exceeded-replace pipe section
Install plastic gas pipelines in accordance with gas standards. 0 Construction standards not met-initiate immediate
Recognize and react to abnormal operating conditions. response to correct.
Note:This DOES NOT include tracer wire connections. See Task Standards referenced: Specification 3.13, 3.15, 3.16
Install Tracer Wire 221.120.130
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.120.125 Install Gas Pipelines-Steel 3 Years Knowledge 1:3
Description: Install steel gas pipelines. Identify the requirements for Abnormal Operating Conditions and Remedial Actions:
storing, handling, and installing steel gas pipelines.This includes trench . Pipe damaged during handling-cut out or replace
requirements and various other installation requirements. Pipe 0 Pipe coating damaged-replace or repair coating
inspections prior to installation or backfilling. Install steel gas pipelines Construction standards not met-initiate immediate
in accordance with gas standards. Recognize and react to abnormal response to correct.
operating conditions.
Note:This DOES NOT include cathodic test leads or fink test stations.
See Task CP-Install Cathodic Test Leads and Stations 221.110.035 Standards referenced: Specification 3.12, 3.15, 3.16
OPERATIONS REV. NO. 25
APPENDIX A—QUAL. COVERED TASK LIST DATE 01101/25
� i/ISTA STANDARDS 7 OF 18
Utilities NATURAL GAS SPEC. 4.31 A

OPERATOR QUALIFICATION COVERED TASK LIST -APPENDIX A
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.120.130 Install and Repair Tracer Wire-Plastic 3 Years Skill 1:3
Abnormal Operating Conditions and Remedial Actions:
• Wire connector fails-replace connector
• Fink missing wire-replace wire
Description: This task includes installation of tracer wire on plastic pipe 0 Construction standards not met-initiate immediate
and connections to anodes and fink test station. Recognize and react to response to correct.
abnormal operating conditions. 0 Damaged coating on tracer wire-repair or replace
Standards referenced: Specification 3.13, 3.16
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.230.005 Leak Survey 3 Years Skill 1:1
Abnormal Operating Conditions and Remedial Actions:
Description: Leak survey gas pipelines by walking or driving. Identify 0 Hazardous gas leak-immediately report to 1-800#to
the requirements for performing leak survey. Inspect,test, and calibrate initiate response
leak survey instruments as applicable. Perform a walking/mobile leak • Gas leak-document and/or report
survey in accordance with gas standards. Recognize and react to
abnormal operating conditions. Standards referenced: Specification 5.11, 5.19
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.080.045 Line Heater Maintenance 3 Years Knowledge 1:1
Abnormal Operating Conditions and Remedial Actions:
• Line heater leaking—Repair or replace as required
Description: Identify the requirements and procedures for Set points out of specification—Adjust as required
maintaining line heaters. Identify the requirements for annual and . Water/Glycol solution low—Fill according to
ten-year maintenance. Recognize and react to abnormal operating instructions
conditions.
Standards referenced: Specification 5.22
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.230.050 Locate Gas Pipelines 3 Years Skill 1:1
Description: Locate and mark gas pipelines. Identify the
requirements for locating and marking gas pipelines. Inspect the Abnormal Operating Conditions and Remedial Actions:
locating equipment prior to locating gas pipelines. Perform a gas 0 Broken tracer wire-report or remediate
locate using proper tools and techniques. Accurately mark gas 0 Equipment out of specs-repair or replace
facilities by appropriate methods. Recognize and react to 0 Pipeline un-locatable-report for verification/notify
abnormal operating conditions. excavator
• Gas leak-initiate immediate response
Note: NACE Certification in any of the following areas meets the 0 Fire-evacuate and initiate immediate response
Operator Qualification Requirements of this Task: CP1 —Cathodic
Protection Tester, CP-2—Cathodic Protection Technician, CP-3—
Cathodic Protection Technologist, or CP-4—Cathodic Protection Standards referenced: Specification 4.13
Specialist.
OPERATIONS REV. NO. 25
APPENDIX A—QUAL. COVERED TASK LIST DATE 01101/25
'A i/ISTA STANDARDS s OF 18
Utilities NATURAL GAS SPEC. 4.31 A

OPERATOR QUALIFICATION COVERED TASK LIST -APPENDIX A
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.230.035 Monitoring Pipeline Pressures 3 Years Knowledge 1:3
Description: Monitor gas pipeline pressures. Identify the requirements Abnormal Operating Conditions and Remedial Actions:
for monitoring pipeline pressures. Using chart recorders,telemetry, and Abnormal pipeline pressures-initiate immediate
other equipment; monitor,gas pipeline pressure to check for abnormal response
conditions in the gas system. (Does not include upstream/downstream Standards referenced: Specification 2.23, 2.25, 3.12, 3.13,
monitoring done during pipe installations.) Recognize and react to 3.32, 3.33, 3.34,4.17, 5.12, 5.21
abnormal operating conditions.
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.080.047 Monthly Line Heater Maintenance 3 Years Knowledge 1:1
Abnormal Operating Conditions and Remedial Actions:
• Line heater leaking—Repair or replace as required
• Set points out of specification—Adjust as required
Description: Inspect the line heater for gas and fluid leaks. Inspect set 0 Water/Glycol solution low—Fill according to
points,fluid levels,temperatures, and pilot light operability. Adjust or instructions
repair as required. Recognize and react to abnormal operating . Pilot light inoperable—initiate inspection and repairs
conditions. by qualified personnel
Standards referenced: Specification 5.22
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.130.015 Non-Destructive Testing of Welds Per API 1104 Knowledge Non-Observable*
Abnormal Operating Conditions and Remedial Actions:
Description: Non-destructive testing personnel shall be certified to Level • Rejected weld—notify company of reject for
I, Il, or III in accordance with ASNT(American Society for remedial action
Nondestructive Testing or equivalent. Only a Level II or III shall interpret 0 *An NDT technician may be under a 1:1 span of
the test results. Includes radiographic, magnetic particle, ultrasonic test, control for pipeline facility AOC's relating to
and liquid penetrant.Acceptance standards for non-destructive testing prevention of accidental ignition
shall meet the requirements of Section 9 of API 1104.
Standards referenced: Specification 3.12
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.090.025 Odorization-Odorizer Maintenance 3 Years Knowledge 1:1
Abnormal Operating Conditions and Remedial Actions:
• Uncontrolled release of gas-initiate immediate
Description: Maintain odorizers. Identify the requirements and response
procedures for maintaining odorizers. Maintain,fill, and adjust gas Odorant spill-report and initiate immediate response
odorizers following manufacturers and standards requirements. • Gas leak-initiate immediate response
Recognize and react to abnormal operating conditions. This task also 0Fire-evacuate and initiate immediate response
covers adjusting injection-style odorizers. 0Over/under odorization-adjust set points
Standards referenced: Specification 5.23,4.18, 2.52
OPERATIONS REV. NO. 25
APPENDIX A—QUAL. COVERED TASK LIST DATE 01101/25
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Utilities NATURAL GAS SPEC. 4.31 A

OPERATOR QUALIFICATION COVERED TASK LIST -APPENDIX A
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.090.035 Odorization-Odorizer Adjustment 3 Years Skill 1:1
Abnormal Operating Conditions and Remedial Actions:
• Uncontrolled release of gas-initiate immediate
Description: Identify the requirements and procedures for adjusting response
odorizers. Recognize and react to abnormal operating conditions.This Odorant spill-report and initiate immediate response
task covers the adjustment of wick and bypass type of odorizers, not 0Gas leak-initiate immediate response
injection type. • Fire-evacuate and initiate immediate response
Standards referenced: Specification 4.18
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.090.030 Odorization-Periodic Odorant Testing 1 Years Skill 1:3
Abnormal Operating Conditions and Remedial Actions:
• Odorant level low-report or remediate
Description: Identify the requirements and procedures for periodic Odorant level high-report or remediate
odorant sampling and perform the test using the proper equipment. Equipment out of specs-repair or replace
Recognize and react to abnormal operating conditions.
Standards referenced: Specification 4.18
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.230.055 Operate Gas Pipeline—Local Facility Remote- 3 Years Skill 1:1
Control Operations
Abnormal Operating Conditions and Remedial Actions:
• Loss of SCADA Communications-Notify field
technician and monitor
• High/Low Pressure-Notify field technician and
monitor
• High/Low Temperature-Notify field technician and
monitor
• Improper Odorizer Operation-Notify field technician
Description: Gas Controller monitoring system operations using Indication of Safety-Related Condition-Notify field
telemetry and/or pressure devices. Direct manual operations of technician
pressure regulating equipment and valves. Recognize and . High Flow-Notify field technician and monitor
respond to abnormal operating conditions(alarms)by notifying Possible Rupture-Monitor status of surrounding
field personnel to respond and take action. system, Notify appropriate field personnel, Confirm
location of event and if conditions exist, Create
WMS Order, Send order to field personnel, Email
event log, Call local 911
• Verified dig-in on 6"or greater-Call local 911
• Verified dig-in on High Pressure-Call local 911
Standards referenced: Specification 4.51
OPERATIONS REV. NO. 25
APPENDIX A—QUAL. COVERED TASK LIST DATE 01/01/25
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Utilities NATURAL GAS SPEC. 4.31 A

OPERATOR QUALIFICATION COVERED TASK LIST -APPENDIX A
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.230.001 Patrolling Gas Pipelines 3 Years Knowledge 1:1
Description: Patrol as pipelines b walking, driving, or flying for the Abnormal Operating Conditions and Remedial Actions:
p g p p y y g Encroachment-report for follow up
specific purpose of observing conditions that may affect the safety and • Washouts-report for follow up
operation of transmission pipeline and selected distribution facilities.
Identify the requirements for patrolling gas pipelines. Patrol gas Gas Missing/daleaks-repormaged
for follow up
pipelines inspecting for signs of soil subsidence, encroachment, gas • Missing/damaged markers-report for follow up
leaks, and missing or damaged pipeline markers and signage.
Recognize and react to abnormal operating conditions. Standards referenced: Specification 5.11, 5.15
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.030.001 PE Pipe Joining -Electrofusion 1 Year Skill Non-
Observable
Description: Electro fuse PE pipe and fittings. Properly inspect pipe Abnormal Operating Conditions and Remedial Actions:
p p p g n y p n p Inclement weather-shield or cover joining process
joining equipment and associated tools prior to joining. Clean, inspect, ,
and prepare pipe and fittings for joining. Using an electro fusion Equipment out of specs-repair or replace equipment
processor, properly join and inspect an electrofusion coupling and Visual inspection unacceptable-replace bad joint
electrofusion tee on PE pipe. Recognize and react to abnormal
operating conditions. Standards referenced: Specification 3.24
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.030.010 PE Pipe Joining -Hydraulic Butt Fusion 1 Year Skill Non-
Observable
Abnormal Operating Conditions and Remedial Actions:
Description: Hydraulically butt fuse PE pipe. Properly inspect pipe Inclement weather-shield or cover joining process
p y y p p p y p p p
joining equipment and associated tools prior to joining. Clean, inspect, Equipment out of specs-repair or replace equipment
and prepare the pipe for joining. Using hydraulic butt fusion equipment, • Visual inspection unacceptable-replace bad joint
properly perform and visually inspect a butt fusion. Recognize and react 0See troubleshooting table in Spec 3.23
to abnormal operating conditions.
Standards referenced: Specification 3.23
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.030.005 PE Pipe Joining -Manual Butt Fusion 1 Year Skill Non-
Observable
Abnormal Operating Conditions and Remedial Actions:
Description: Manually butt fuse PE pipe. Properly inspect pipe Inclement weather-shield or cover joining process
p y p p p y . p p Equipment out of specs-repair or replace equipment
joining equipment and associated tools prior to joining. Clean,
inspect, and prepare the pipe for joining. Using mechanical butt 0Visual inspection unacceptable-replace bad joint
fusion equipment, properly perform and visually inspect a butt • See troubleshooting table in Spec 3.23
fusion. Recognize and react to abnormal operating conditions.
Standards referenced: Specification 3.23
OPERATIONS REV. NO. 25
APPENDIX A—QUAL. COVERED TASK LIST DATE 01/01/25
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Utilities NATURAL GAS SPEC. 4.31 A

OPERATOR QUALIFICATION COVERED TASK LIST -APPENDIX A
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.030.020 PE Pipe Joining -Mechanical Couplings 1 Year Skill Non-
Observable
Abnormal Operating Conditions and Remedial Actions:
Description: Install mechanical slip-lock or compression fittings. Clean, • Damaged fitting-replace fitting
inspect, and prepare the pipe and slip-lock or compression fitting prior Damaged pipe-repair or replace pipe
to joining. Properly install and visually inspect the mechanical fitting. 0Pipe joint leaks-replace fitting
Recognize and react to abnormal operating conditions.
Standards referenced: Specification 3.25
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.030.015 PE Pipe Joining -Mechanical Service Tees 1 Year Skill Non-
Observable
Abnormal Operating Conditions and Remedial Actions:
Description: Install bolted mechanical service tees to PE pipe. Clean, • Damaged fitting-replace fitting
inspect, and prepare the pipe and fitting prior to joining. Properly install Damaged pipe-repair or replace pipe
and visually inspect a mechanical service tee on PE pipe. Recognize 0Pipe joint leaks-replace fitting
and react to abnormal operating conditions.
Standards referenced: Specification 3.25
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.030.025 PE Pipe Joining -Mechanical Spigot and Sleeve 1 Year Skill Non-
Type Fittings Observable
Abnormal Operating Conditions and Remedial Actions:
•Description: Install spigot and sleeve type mechanical fittings. Clean, Damaged fitting-replace fitting
Damaged pipe-repair or replace pipe
inspect, and prepare the pipe fitting prior to joining. Properly install and Pipe joint leaks-replace fitting
visually inspect a spigot and sleeve type mechanical fitting. Recognize
and react to abnormal operating conditions. Standards referenced: Gas Standards Manual
Specification 3.25
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.120.085 Pipe Bending 3 Years Knowledge 1:3
Abnormal Operating Conditions and Remedial Actions:
Description: Bend steel or PE pipe. Identify the requirements and • Bending radius exceeded--replace pipe section
procedures for performing pipe bends in the field. Describe procedures 0Mechanical damage such as wrinkle bends,
for bending pipe using appropriate methods so as to avoid damage to cracks—replace pipe section
the pipe. Recognize and react to abnormal operating conditions.
Standards referenced: Specification 3.12, 3.13
OPERATIONS REV. NO. 25
APPENDIX A—QUAL. COVERED TASK LIST DATE 01/01/25
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OPERATOR QUALIFICATION COVERED TASK LIST -APPENDIX A
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.100.065 Pipe Squeezing 3 Years Skill 1:1
Abnormal Operating Conditions and Remedial Actions:
• Pipe damage-replace section of pipe
• Loss of pressure or overpressure(failure to monitor
Description: Squeeze off PE pipe. Using the proper squeeze tool, pressure)-initiate emergency shutdown procedure
squeeze off PE pipe following the procedure for squeezing and follow 0 Incomplete shutdown-move squeezers and squeeze
written static electricity grounding procedures. Recognize and react to again or use second squeezer
abnormal operating conditions. 0 Gas leak-initiate immediate response
• Fire-evacuate and initiate immediate response
Standards referenced: Specification 3.34
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.120.120 Pipeline Cover, Clearance,&Backfill 3 Years Knowledge 1:3
Abnormal Operating Conditions and Remedial Actions:
• Minimum cover not met-provide protection to pipe or
contact gas engineering for remedial action
Description: Provide proper depth for gas pipelines. Identify pipeline 0 Clearances not met—provide protection or move
cover, clearance, and backfill requirements. Install gas pipelines with facility
the minimum requirements established by code. Recognize and react to 0 Backfill material not suitable-remove and replace
abnormal operating conditions. • Trench bottom not suitable-pad trench bottom
• Settlement-provide proper compaction
Standards referenced: Specification 3.15
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.120.075 Pressure Testing Gas Pipelines 3 Years Knowledge 1:1
Abnormal Operating Conditions and Remedial Actions:
Description: Pressure test gas pipelines for leakage. Identify the 0 Overpressure the pipeline-report and retest
requirements for pressure testing gas pipelines. Describe testing • Pressure drop-investigate, remediate, and re-test
procedures for gas lines using gas,air, and inert gas for indications of 0 Pipeline failure-repair or replace and retest
leakage. Recognize and react to abnormal operating conditions.
Standards referenced: Specification 3.18
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.230.040 Prevention of Accidental Ignition 3 Years Knowledge 1:3
Abnormal Operating Conditions and Remedial Actions:
• Fire-initiate immediate response
Description: Prevent accidental ignition. Identify, recognize, and 0 Combustible atmosphere—secure the area and
remove potential ignition sources common to the job site. monitor levels, implement EOP plan
Recognize and react to abnormal operating conditions.
Standards referenced: Specification 3.17, GESH Section 4
OPERATIONS REV. NO. 25
APPENDIX A—QUAL. COVERED TASK LIST DATE 01/01/25
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Utilities NATURAL GAS SPEC. 4.31 A

OPERATOR QUALIFICATION COVERED TASK LIST -APPENDIX A
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.120.080 Purging Gas Pipelines 3 Years Knowledge 1:3
Description: Purge gas pipelines. Identify the requirements,tools, Abnormal Operating Conditions and Remedial Actions:
equipment, and techniques that are needed to safely purge a gas Incomplete purge-purge and re-test
pipeline. Purge the gas pipeline in a manner so as to achieve 93 Gas leak-initiate immediate response
percent or greater of gas in air when purging air out of facilities to be Fire-evacuate and initiate immediate response
placed in service or 0 percent gas in air when purging gas from existing
facilities. Recognize and react to abnormal operating conditions. Standards referenced: Specification 3.17
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.070.070 Recognizing Unsafe Meter Sets 3 Years Knowledge 1:3
Abnormal Operating Conditions and Remedial Actions:
Description: Recognize meter sets that may be subject to safety-related • Identification of non-safety-related risk—report for
and other risks,such as possible leaks,foreign wire, stresses to piping follow up action
or other physical damage, inoperable(obscured)service valves, 0Identification of safety-related risk—initiate
overbuilds, unauthorized attachments to meters, and diversion of gas immediate response.
service. Recognize and react to abnormal operating conditions.
Standards referenced: Specification 2.22, 5.14
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.080.035 Regulator Station -5/10 Year Maintenance 3 Years Skill 1:1
Abnormal Operating Conditions and Remedial Actions:
• Uncontrolled release of gas-initiate immediate
response
Description: Identify the maintenance requirements for 5/10 year Gas leak-initiate immediate response
maintenance and perform maintenance. Recognize and react to Overpressure of the system-report and investigate
abnormal operating conditions. downstream system
• Fire-evacuate and initiate immediate response
Standards referenced: Specification 5.12
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.080.030 Regulator Station -Annual Maintenance 3 Years Skill 1:1
Abnormal Operating Conditions and Remedial Actions:
• Uncontrolled release of gas-initiate immediate
Description: Identify the maintenance requirements and perform annual response
maintenance on all configurations of regulator stations. Recognize and • Gas leak-initiate immediate response
react to abnormal operating conditions. 0Overpressure of the system-report and investigate
downstream system
Note: Pilot heater maintenance is included in this task. 0Fire-evacuate and initiate immediate response
Standards referenced: Specification 5.12
OPERATIONS REV. NO. 25
APPENDIX A—QUAL. COVERED TASK LIST DATE 01/01/25
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Utilities NATURAL GAS SPEC. 4.31 A

OPERATOR QUALIFICATION COVERED TASK LIST -APPENDIX A
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.080.025 Regulator Station -Bypassing 3 Years Skill 1:1
Abnormal Operating Conditions and Remedial Actions:
• Overpressure the system-report and investigate
downstream system
Description: Bypass a regulator station. Bypass a regulator station or • Gas pressure loss-initiate immediate response
industrial meter set with like equipment for maintenance and Uncontrolled release of gas-initiate immediate
emergency situations following written procedures. Recognize and response
react to abnormal operating conditions. 0Gas leak-initiate immediate response
• Fire-evacuate and initiate immediate response
Standards referenced: Specification 5.12
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.060.015 Repair Gas Pipelines 3 Year Knowledge 1:3
Abnormal Operating Conditions and Remedial Actions:
• Mechanical damage-refer to pipe repair chart
• Corrosion damage-refer to pipe repair chart
• Leaks in welds-refer to pipe repair chart
•Description: Repair gas pipelines. Identify the requirements and Non-leaking cracks or defects-refer to pipe repairchart
methods for repairing gas pipelines including the use of permanent Leaks in body of fittings or clamps-refer to pipe
repair leak clamps and sleeves such as the"PLIDCO"and "Clock repair chart
Spring". Recognize and react to abnormal operating conditions. • Uncontrolled release of gas-initiate immediate
response
Standards referenced: Specification 3.32, 3.32A, 3.32A,
3.33
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.070.020 Replace Service Valves 3 Years Skill 1:1
Abnormal Operating Conditions and Remedial Actions:
• Equipment out of specs.-repair or replace as needed
•Description: Replace broken, damaged,or other non-compliant Equipment failure during operation-assess situationand take appropriate action
gas service valves. Using the Mueller"No-Blo"service valve 0 Defective riser-report or repair
changing equipment, remove the broken, damaged, or non- • Incomplete shutdown-remove, inspect, and repeat
compliant valve and replace with a new valve. Includes operation • Hazardous gas leakage-initiate immediate response
and lubrication of service valves. Recognize and react to abnormal
operating conditions. Fire or explosion-initiate immediate response
Standards referenced: Specification 2.14, 2.24, 3.16, 5.13,
5.17, GESH Section 9
OPERATIONS REV. NO. 25
APPENDIX A—QUAL. COVERED TASK LIST DATE 01/01/25
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OPERATOR QUALIFICATION COVERED TASK LIST -APPENDIX A
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.040.001 Tapping and Stopping-Mueller 4"and Smaller 3 Years Skill 1:1
Abnormal Operating Conditions and Remedial Actions:
• Equipment out of specs-repair or replace
• Incomplete shut down-remove stopper and inspect
Description: Inspect tapping and stopping equipment prior to operation. or re-sweep
Review manufacturer's instruction for using tapping and stopping 0 Hazardous gas leak-initiate immediate response
equipment prior to operation. Using Mueller tapping and stopping 0 Line pressure drops-remove stopper plug and
equipment, properly tap and stop steel gas fittings 4 inches in diameter evaluate.
and smaller following manufacturer's written procedures. Recognize 0 Line pressure loss-initiate emergency shutdown and
and react to abnormal operating conditions. restoration procedure.
Standards referenced: Specification 3.32
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.040.010 Tapping and Stopping-Mueller 6"and Larger 3 Years Skill 1:1
Abnormal Operating Conditions and Remedial Actions:
• Equipment out of specs-repair or replace
• Incomplete shut down-remove stopper and inspect
Description: Inspect tapping and stopping equipment prior to operation. or re-sweep
Review manufacturer's instruction for using tapping and stopping • Hazardous gas leak-initiate immediate response
equipment prior to operation. Using Mueller tapping and stopping 0 Line pressure drops-remove stopper plug and
equipment, properly tap and stop steel gas fittings 6 inches in diameter evaluate.
and larger following manufacturer's written procedures. Recognize and • Line pressure loss-initiate emergency shutdown and
react to abnormal operating conditions. restoration procedure
Standards referenced: Specification 3.32
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.040.005 Tapping and Stopping-TDW 4"and Smaller 3 Years Skill 1:1
Abnormal Operating Conditions and Remedial Actions:
• Equipment out of specs-repair or replace
• Incomplete shut down-remove stopper and inspect
Description: Inspect tapping and stopping equipment prior to operation. or re-sweep
Review manufacturer's instruction for using tapping and stopping 0 Hazardous gas leak-initiate immediate response
equipment prior to operation. Using TD Williamson tapping and • Line pressure drops-remove stopper plug and
stopping equipment, properly tap and stop steel gas fittings 4 inches in evaluate
diameter and smaller following manufacturer's written procedures. 0 Line pressure loss-initiate emergency shutdown and
Recognize and react to abnormal operating conditions. restoration procedure
Standards referenced: Specification 3.32
OPERATIONS REV. NO. 25
APPENDIX A—QUAL. COVERED TASK LIST DATE 01/01/25
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Utilities NATURAL GAS SPEC. 4.31 A

OPERATOR QUALIFICATION COVERED TASK LIST -APPENDIX A
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.040.015 Tapping and Stopping-TDW 6"and Larger 3 Years Skill 1:1
Abnormal Operating Conditions and Remedial Actions:
• Equipment out of specs-repair or replace
• Incomplete shut down-remove stopper and inspect
Description: Inspect tapping and stopping equipment prior to operation. or re-sweep
Review manufacturer's instruction for using tapping and stopping • Hazardous gas leak-initiate immediate response
equipment prior to operation. Using TD Williamson tapping and 0 Line pressure drops-remove stopper plug and
stopping equipment, properly tap and stop steel gas fittings 6 inches in evaluate
diameter and larger following manufacturer's written procedures. 0 Line pressure loss-initiate emergency shutdown and
Recognize and react to abnormal operating conditions. restoration procedure
Standards referenced: Specification 3.32
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.050.005 Valve Maintenance 3 Years Knowledge 1:1
Abnormal Operating Conditions and Remedial Actions:
Description: Maintain distribution and transmission valves.Accurately • Valve box out of alignment-excavate and repair
locate and identify the valve to be maintained. Inspect the valve box Valve inoperable-repair or replace
and valve for signs of damage or leakage. Partially operate the valve. 0Valve leaking-repair or replace
Lubricate the valve as needed.Verify documentation is accurate. • Hazardous gas leakage-initiate immediate response
Recognize and react to abnormal operating conditions.
Standards referenced: Specification 2.14, 5.13
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.080.020 Vault Maintenance 3 Years Knowledge 1:3
Abnormal Operating Conditions and Remedial Actions:
• Gas leak-initiate immediate response
Description: Inspect and maintain vaults. Identify the requirements for • Fire-evacuate and initiate immediate response
vault inspection and maintenance. Inspect vaults for damage and 0 Poor physical condition-initiate repairs
repair as needed. Recognize and react to abnormal operating 0 Plugged drains or vents-clear obstructions
conditions.
Standards referenced: Specification 2.22, 2.42, 3.12, 5.18
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.130.005 Visual Inspection of the Weld 3 Years Knowledge 1:1
Description: Visually inspect weld joints.Verify the weld procedure is Abnormal Operating Conditions and Remedial Actions:
being followed this includes checking the joint and alignment, preheat Weld defects(porosity overlap, undercut, cracking,
requirements, amp and voltage settings, measure and calculate speed contaminants)—repair or cut out weld
of travel, look for visual weld defects. Recognize and react to abnormal
operating conditions. Standards referenced: Specification 3.22
OPERATIONS REV. NO. 25
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OPERATOR QUALIFICATION COVERED TASK LIST - APPENDIX A
TASK EVALUATION EVALUATION SPAN OF
INTERVAL METHOD CONTROL
221.130.010 Welding 6 Months Skill Non-Observable
Description: Joining of steel pipe by welding. Perform fit up and weld of Abnormal Operating Conditions and Remedial Actions:
joint in accordance with applicable company welding procedure and 0 Correct procedure not followed—cut out weld
process which includes the use of the appropriate electrode,voltage, 0 Defects in weld—repair or cut out weld
amperage, and speed of travel. Recognize and react to abnormal
operating conditions. Individuals qualified to this standard also satisfy [Standards referenced: Specification 3.22
the skills required for Visual Inspection of the Weld (221.130.005).
COVERED TASKS ASSOCIATED WITH INTEGRITY MANAGEMENT, SUBPART O
TASK EVALUATION INTERVAL
Excavation and Assessment of Pipelines As Necessary
Hydrostatic Testing As Necessary
Metal Loss Assessment As Necessary
Dent Assessment As Necessary
Grinding Repairs As Necessary
Repair of Leaking Defects As Necessary
Installation of Steel Pressure Containing Sleeves As Necessary
Installation of Composite Sleeves As Necessary
Assessment of Arc Burns and Hard Spots As Necessary
In-Line Inspection As Necessary
OPERATIONS REV. NO. 25
APPENDIX A—QUAL. COVERED TASK LIST DATE 01/01/25
�� �rlsra STANDARDS 18 OF 18
Utilities NATURAL GAS SPEC. 4.31 A

APPENDIX B
EVALUATION GUIDELINES
Preparation:
(1) Acquiring and developing evaluation skills.
(2) Reviewing applicable performance Criteria Guide(s).
(3) Reviewing applicable performance criteria documents, i.e.:
(a) Operation and maintenance procedures.
(b) Engineering specifications.
(c) Manufacturer's instructions.
(4) Coordinate with individuals on timeframe and location of evaluation.
(5) If utilizing a simulation, make sure all props and necessary equipment are available and ready.
Evaluation:
(1) Select correct documents.
(a) Criteria Guide(s).
(b) Record of Evaluation (ROE)
(2) Prepare the individual.
(a) Explain scope and process of evaluation(s).
(b) Answer any administrative questions.
(c) Remind individual to verbalize and demonstrate.
(d) Be careful how you ask questions—you want to probe not coach.
(e) Remind individual to identify Abnormal Operating Conditions (AOC).
(f) Performance evaluation —not memory test.
(g) Give examples of what"verbalization" means.
(h) Not a timed test.
(3) Assess individual.
(a) Monitor safety.
(b) Evaluate individual's performance in accordance with establish criteria.
(c) Question individual without giving away information.
(d) Verify ability to recognize and react to AOCs.
(e) Mark the ROE as the evaluation progresses.
(f) Indicate reason(s) unsatisfactory performance.
(g) Mark successful or unsuccessful completion of each step.
(h) Mark successful or unsuccessful completion of the evaluation(s).
(i) Review results with individual.
After Evaluation:
(1) Complete required documentation.
(2) Submit for entry in record keeping system.
(3) If required, take action to schedule individual for re-evaluation or remedial training.
(4) If unable to pass evaluation after remedial training, the individual's manager will be contacted to
determine subsequent action.
OPERATIONS REV. NO. 3
APPENDIX B -EVALUATION DATE 01/01/22
�risra STANDARDS 1 OF 1
utilities NATURAL GAS SPEC. 4.31 B

APPENDIX C
OPERATOR QUALIFICATION
REVIEW FORM
Individual Qualification
Mutual Assistance Qualification
Name of Individual(whose qualifications are being reviewed):
Company OQ Program/Criteria being reviewed:
Compare the evaluation criteria and procedures for any listed covered tasks and associated abnormal operating
conditions(AOCs)to ascertain if they are comparable to Avista's OQ Program and O&M Plan.
List of Covered Tasks Acceptable
(and AOC's)/Procedures Avista Tasks yes No
Comments:
Proof of qualifications available:
Reviewed by(name, title, date):
(Attach any documents to support the decision for acceptance)
�IIIIrISM
Utilities Rev 2
12/12/15

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4.4 INTEGRITY MANAGEMENT PROGRAM
4.41 TRANSMISSION INTEGRITY MANAGEMENT PROGRAM (TIMP)
The Transmission Integrity Management Program (TIMP) is a separate document that is maintained by the
TIMP Program Manager. This document is accessible on the Company's Gas Wiki SharePoint website.
The following standard provides a general overview of what is contained within that document.
SCOPE:
The purpose of Avista's Transmission Integrity Management Program (TIMP) is to ensure safe, reliable,
and cost-effective transportation of natural gas for our customers without adverse effects on the public,
customers, employees, and the environment.
The TIMP is specifically intended to apply only to segments of transmission pipelines subject to the
requirements of§192, Subpart O. This program provides for the comprehensive, integrated, and
systematic management of pipeline integrity in High Consequence Areas (HCA), Moderate Consequence
Areas (MCA), and Class 3 or Class 4 areas operating at a hoop stress of 30% SMYS or more, as a means
to improve the safety of these pipeline systems.
This program provides the necessary framework for Avista to effectively allocate resources for appropriate
prevention, detection, and mitigation activities that will result in improved safety. This program provides a
process to assess and mitigate risks in order to reduce both the likelihood and consequences of pipeline
failures and incidents.
REGULATORY REQUIREMENTS:
§192, Subpart O
CORRESPONDING STANDARDS:
Spec. 4.13, Damage Prevention Program
Spec. 4.14, Recurring Reporting Requirements
Spec. 4.31, Operator Qualification
Spec. 5.11, Leak Survey
INTEGRITY MANAGEMENT PRINCIPLES:
Avista has adopted a set of principles as the basis for the intent and specific details of this program. The
principles are presented below:
• Functional requirements for integrity management shall be engineered into new pipeline systems from
initial planning, design, material selection, installation, and initial inspection/testing. Avista follows
applicable laws and regulations as well as uses numerous consensus codes and standards in order to
meet this requirement. Policies, plans, and procedures have been developed which are also used to
meet this requirement.
• System integrity requires commitment by operating personnel using systematic, comprehensive, and
integrated processes in order to safely operate and maintain the pipeline systems.
OPERATIONS REV. NO. 9
INTEGRITY MANAGEMENT PROGRAM DATE 01/01/24
X-4, sr'a STANDARDS 1 OF 2
Utilities SPEC. 4.41
NATURAL GAS

• The TIMP will be continuously evolving and improving and is therefore intended to be flexible.
Periodic evaluation is conducted to ensure that the program takes appropriate advantage in
improvements in technologies and that the program utilizes the appropriate prevention, detection, and
mitigation activities. The effectiveness of the various activities will be reassessed and modified to
ensure the continuing effectiveness of the program and its activities. The integration of information is
recognized as a key component for managing system integrity. Information that can impact the
understanding of the important risks to a pipeline system comes from a variety of sources. Avista is
committed to analyzing pertinent information in order to effectively manage pipeline integrity.
• Avista has developed a risk assessment methodology and will use that methodology to determine the
types of adverse events or conditions that may impact pipeline integrity. The process is also used to
prioritize the pipeline segments for further assessment by considering the likelihood and consequence
of an adverse event. The model employs a risk algorithm that was custom-designed to accommodate
Avista's unique system configuration and data resources.
• Avista will continually gather new and/or additional information pertaining to system configuration and
system experience. The Integrity Management Plan will be reviewed on a regular basis to ensure that
new information becomes integrated into the Integrity Management Plan.
• Avista is committed to keeping abreast of new knowledge and technologies affecting pipeline integrity
and evaluating those technologies and implementing them where appropriate. Avista personnel will
attend meetings and conferences and will perform literature searches in order to investigate and then
evaluate the use of new technologies for specific use in the TIMP. New technologies and knowledge
will be gathered and integrated into the Integrity Management Plan as appropriate.
• Avista has determined the set of performance measures that will best serve the need for monitoring
and evaluating the effectiveness of the TIMP. Reports, based on these performance measures, will be
generated on an annual basis.
• Avista is committed to communicating the results of its integrity management activities to its
stakeholders.
OPERATIONS REV. NO. 9
INTEGRITY MANAGEMENT PROGRAM DATE 01/01/24
X-4,15y' a STANDARDS 2 OF 2
Utilities SPEC. 4.41
NATURAL GAS

4.42 DISTRIBUTION INTEGRITY MANAGEMENT PROGRAM
The Distribution Integrity Management Program (DIMP) is a separate document that is maintained by the
Pipeline Integrity Program Manager. This document is accessible on the Company's Gas Wiki
SharePoint website.
The following standard gives a general overview of what is contained within this document.
SCOPE:
The purpose of Avista's DIMP program is to enhance safety by identifying and reducing gas distribution
pipeline integrity risks to the public, customers, employees, and the environment. The effective date of
Avista's DIMP program was August 2, 2011.
The program outlined in the DIMP document applies to distribution facilities subject to the requirements of
§192, Subpart P.
REGULATORY REQUIREMENTS:
§192, Subpart P
CORRESPONDING STANDARDS:
Spec. 3.44, Exposed Pipe Evaluation
Spec. 4.11, Continuing Surveillance
Spec. 4.14, Recurring Reporting Requirements
Spec. 4.31, Operator Qualification
Spec. 5.11, Leak Survey
GESH Section 2, Leak and Odor Investigation
General
Operators must integrate reasonably available information about their pipelines to be used in their risk
decisions. The rule requires that operators identify risks to their pipelines where an incident could cause
serious consequences and focus priority attention in those areas. The rule also requires that operators
implement a program to provide greater assurance of the integrity of their pipeline.
The integrity management approach was designed to promote continuous improvement in pipeline safety
by requiring operators to identify and invest in risk control measures beyond previously established
regulatory requirements.
DISTRIBUTION INTEGRITY MANAGEMENT ELEMENTS:
The DIMP Plan addresses the following elements:
1. Written Distribution Integrity Management Plan document.
OPERATIONS REV. NO. 6
DISTRIBUTION INTEGRITY DATE 01/01/22
MANAGEMENTPROGRAM
Xv sm a STANDARDS 1 OF 2
utilities NATURAL GAS SPEC. 4.42

2. Knowledge of the System— Demonstrate an understanding of Avista's infrastructure using
reasonably available information from past and ongoing design, operations, and maintenance
activities. Identify additional information necessary and develop a plan to obtain that information
over time through normal activities.
3. Identify Threats— Identify existing gas distribution pipeline threats through available data
including leak repair, incident data, material failure reports, operational and maintenance history,
excavation damages, and exposed piping inspection reports. Identify potential threats that have
not occurred but based on geographical location may occur such as earthquakes, flooding, and
other natural hazards, or have been identified by other organizations such as National
Transportation Safety Board, Pipeline and Hazardous Material and Safety Administration, or
industry associations.
4. Evaluate and Rank Risks— Develop a process to identify what factors affect the risk posed by the
threats identified and where they are relatively more important than others based on likelihood of
failure and the potential consequences of the failure.
5. Identify and Implement Measures to Address Risks— Develop risk control measures to address
the risks that have been evaluated and prioritized.
6. Measure Performance, Monitor Results, and Evaluate Effectiveness— Establish performance
measures that are monitored from an established baseline in order to evaluate the effectiveness
of the DIMP program. There are four performance metrics that are required to be monitored to
evaluate the effectiveness of the program.
• Number of Hazardous Leaks either Eliminated or Repaired, Categorized by Cause
• Number of Hazardous Leaks Eliminated or Repaired, Categorized by Material
• Total Number of Leaks Eliminated or Repaired, Categorized by Cause
Number of Excavation Damages, Locate Tickets, and the Ratio of Excavation Damages
per 1000 Locate Tickets
7. Reporting of Results—The annual report which includes the four above mentioned performance
metrics is required to be completed and submitted to PHMSA each calendar year.
8. Periodic Evaluation and Improvement— Periodically re-evaluate threats and risks on the entire
pipeline and periodically evaluate the effectiveness of the program. A complete program re-
evaluation shall be completed every five (5)years.
OPERATIONS REV. NO. 6
DISTRIBUTION INTEGRITY DATE 01/01/22
MANAGEMENTPROGRAM
XvISTA STANDARDS 2 OF 2
utilities NATURAL GAS SPEC. 4.42

4.51 GAS CONTROL ROOM MANAGEMENT PLAN
The Gas Control Room Management Plan is a separate document maintained by the Manager of
Operations Support and Gas Control. This document is accessible on the Gas Control Room SharePoint
site.
The following information gives a general overview of what is contained within this document.
SCOPE:
The requirements in the Gas Control Room Management Plan apply to Avista's Gas Control Room in
Spokane, Washington, which monitors the pipelines/systems in the states of Idaho, Oregon, and
Washington.
REGULATORY REQUIREMENTS:
§192.619, §192.631
WAC 480-93-018, 480-93-180
CORRESPONDING STANDARDS:
Spec. 2.25, Telemetry Design
Spec. 4.15, Maximum Allowable Operating Pressure (MAOP)
Spec. 4.31, Operator Qualification
CONTROL ROOM MAJOR ELEMENTS:
The Gas Control Room Management Plan includes the following sections, as applied to Gas Control:
• Control Room Management Plan Introduction
• Roles, Responsibilities, Accountability, and Authority of Gas Control Personnel
• Providing Adequate Information to Gas Control Room Personnel —SCADA Processes
• Providing Adequate Information to Gas Control Room Personnel —Shift Change and Other
Procedures
• Fatigue Risk Management System
• Alarm Management Plan
• Change Management Plan
• Operating Experience Program
• Control Room Training Program
• Compliance and Deviations
• Activity Review Process
MAINTENANCE REV. NO. 8
GAS SYSTEM MONITORING &ALARM DATE 01/01/25
MANAGEMENT
Xv sm a STANDARDS 1 OF 2
I i►ities SPEC. 4.51
NATURAL GAS

Control Room Notifications
Field personnel shall contact Gas Control when emergency conditions exist or when working on location
as described below at a gate station, regulator station, meter set, or other facility known to have
telemetry.
Before performing maintenance, operations, or construction activities that may affect Control
Room operations, Gas Control must be called at 509-495-4859 or via radio to notify them of the
work. This includes valve operations including sensing lines to instrumentation and regulators, set point
changes, work on or testing of regulators, instrument calibrations, piping configuration changes,
increasing or decreasing the pressure of the system, and other activities that may result in an alarm or
alert condition being sensed and transmitted. This will minimize false alarm/alert notifications and
associated personnel call outs.
Activities that do not potentially affect gas pressures, gas temperatures, or alarms, such as site
maintenance, reading of odorizer levels, fencing construction and/or vegetation management, etc., do not
require notification.
When work is complete, Gas Control must be called again to ensure alarms and alerts have cleared
before leaving the site.
MAINTENANCE REV. NO. 8
GAS SYSTEM MONITORING &ALARM DATE 01/01/25
MANAGEMENT
Xvism a STANDARDS 2 OF 2
I i►ities SPEC. 4.51
NATURAL GAS

4.61 QUALITY ASSURANCE/QUALITY CONTROL (QA/QC) PROGRAM
SCOPE:
The purpose of Avista's QA/QC Program is to enhance the quality of gas field activities and improve
standardization and efficiency of these activities. The QA/QC Program is designed to audit field activities
and not to direct work in the field which is the function of Company inspectors.
REGULATORY REQUIREMENTS:
§192.605(b)(8)
CORRESPONDING STANDARDS:
Spec. 3.12, Pipe Installation—Steel Mains
Spec. 3.13, Pipe Installation— Plastic Mains
Spec. 3.15, Trenching & Backfilling
Spec. 3.16, Pipe Installation— Services
Spec. 3.17, Purging of Pipelines
Spec. 3.18, Pressure Testing
Spec. 3.22, Joining of Pipe-Steel
Spec. 3.23, Joining of Pipe— Plastic Heat Fusion
Spec. 3.24, Joining of Pipe— Electrofusion
Spec. 3.25, Joining of Pipe— Mechanical
General
The Quality Assurance Program is a separate document that is maintained by the QA/QC Manager.
Quality Assurance (QA) comprises those actions necessary to provide adequate confidence that products,
processes, or systems comply with applicable specifications and standards. The focus is on providing
assurance that processes are adequate and effective.
Quality Control (QC)comprises operational techniques and activities, including audits, necessary to control
the characteristics of a product or service (i.e., characteristics that can be measured against codes,
drawings, or specifications). The focus is on preventing defective products or services.
Objectives of the QA/QC Program
The QA/QC Program is structured to meet the following objectives:
1. Ensuring adherence to Federal, State, and company requirements, standards, policies, and
procedures.
2. Identifying areas in which the company's standards may need to be updated or clarified and
submitting recommended changes (where appropriate).
3. Evaluating the transfer of training/qualifying to the field and identifying training/qualification needs.
4. Providing support to Field Supervisors, Trainers, and Operator Qualification (OQ) Specialists.
5. Presenting recommendations by Avista Utilities Gas Managers and Supervisors to the QA Committee
and applicable groups.
6. Facilitating and driving change through direction from the QA Advisory Committee.
OPERATIONS REV. NO. 6
QUALITY ASSURANCE/QUALITY DATE 01/01/25
CONTROLPROGRAM
Xv sm a STANDARDS 1 OF 2
I i►ities SPEC. 4.61
NATURAL GAS

Program Applicability
The QA/QC Program applies to the following categories of activities:
Construction
• New construction
• Reconstruction
• Conversions
• Extensions
• Other work (e.g., relocations, cut offs, grading, replacements, maintenance, etc.)
• Pre and Post Paperwork
Gas Service
• Meter work
• Service calls (Inside service work)
• Odor calls
• Maintenance
• Gas Emergencies
Leak Survey
• Surveys
• Odor calls
• Leak re-checks
• Leak resolution
Locating
• One Call locates
• Standbys
• Pipe Ids
• Damage Prevention
Pipeline Marker Program
• Survey
Atmospheric Corrosion (AC)
• Survey
• Follow up on write up
Additionally, the QA/QC Program applies to the following employees:
1. Avista natural gas employees
2. Avista gas construction and contract construction crews, including those working with Avista gas
crews.
3. Avista contractors performing leak survey, atmospheric corrosion, and pipeline marker survey
inspections.
4. Avista field support employees and contract employees who perform natural gas locating activities.
OPERATIONS REV. NO. 6
QUALITY ASSURANCE/QUALITY DATE 01/01/25
CONTROLPROGRAM
Xvism a STANDARDS 2 OF 2
I i►ities SPEC. 4.61
NATURAL GAS

4.62 INCIDENT ASSESSMENT, FAILURE ASSESSMENT AND LESSONS LEARNED
SCOPE:
Establish a framework for assessment of incidents, failures and near misses, and address findings by
identifying corrective action recommendations to prevent or minimize the consequences of a future
incident and communication of lessons learned.
REGULATORY REQUIREMENTS:
§192.617
CORRESPONDING STANDARDS:
Spec. 4.31, Appendix D, Post-Reportable OQ Assessment Guideline Flowchart
GESH 17., Incident Investigation
General
Incidents and failures resulting from materials, procedures, and operations should be reviewed for the
benefit of determining causation /contributing factors and organizational learning to prevent similar
occurrences in the future. This specification provides a framework of how Avista conducts incident
assessments and develops, implements, and incorporates lessons learned into Avista written procedures.
These procedures include personnel training, qualification, design, construction, testing, maintenance,
operations, and emergency procedure manuals and specifications. The words "assessment" and
"investigation" can be used interchangeably at times by various people and entities. See the Glossary for
definitions of Incident Assessment and Field Investigation.
SITUATIONS THAT TRIGGER ASSESSMENTS
Assessments can be performed for any of the following situations.
1. Material Failures
2. DOT Reportable Incidents
3. Noticeable trends (Multiple Occurrences)
4. Gas related fires and/or explosions
5. Non-gas related fires and/or explosions
6. Personnel Injury
7. Third-Party Damages
8. Pipeline Ruptures and/or Rupture Mitigation Valve (RMV) Closures
9. Near Misses
10. Other management-directed reasons
Material Failure Assessment
A leak marked as a material failure should have a Gas Material Failure Report (Form N-2614)filled out
and sent to the Gas Materials Engineer in Gas Engineering. The failed material or component should also
be sent to the Gas Materials Engineer for failure analysis. If the failed item is large, heavy, difficult to ship,
or to remove from the system, field personnel should contact the Gas Materials Engineer for further
guidance. If the failed material or component need not be removed from the system, the field person
should take a picture of the failed material or component and send it to the Gas Materials Engineer. A
Gas Material Failure Report should be filled out for other non-leak material failures as well. The Gas
Materials Engineer will then take the steps below to determine to what extent the material is to be
analyzed to determine the failure cause. (Submission of Gas Material Failure Reports are not required for
failures involving the stab fitting connections on plastic Continental fittings, Aldyl-A service tee caps, or
slow crack growth failures on Aldyl-A pipe as these failures have already been well documented.)
OPERATIONS REV. NO. 2
INCIDENT AND FAILURE ASSESSMENT DATE 01/01/25
X-4, sr'a STANDARDS 1 OF 4
Utilities NATURAL GAS SPEC. 4.62

The three levels of failure analysis include:
1. Internal Analysis: The Gas Materials Engineer will first examine the failure report and material to
determine if the failure cause is readily identifiable as a known failure type, typically because it has
been observed and confirmed previously by either a manufacturer or independent lab analysis. The
Gas Materials Engineer may seek input from other gas materials experts including Gas Engineers,
the Gas Pipeline Integrity Program Manager, or others to make this determination.
2. Manufacturer Analysis: If there is uncertainty in the failure cause using internal analysis, the
material may be sent to the manufacturer for additional analysis. This is often done when suspected
failure cause is a manufactured material defect or an installation error. The Gas Materials Engineer
will confirm with Gas Engineering before sending the material to the manufacturer.
3. Independent Laboratory Analysis: The Gas Engineering Manager and the Manager of Pipeline
Integrity and Gas Compliance will collaborate on any request or recommendation for an independent
laboratory analysis. The Gas Engineering Manager is responsible for the creation of the lab analysis
specifications and for approving any laboratories to be utilized. An independent laboratory analysis
may be sought for the following reasons:
• The failure cause appears unique, i.e., the failure cause is not a known material defect, installation
error, or other known failure cause.
• The material is no longer being manufactured and it has a suspected manufacturing defect.
• It is deemed prudent to acquire an independent analysis to confirm a failure cause, to dispute a
failure cause, or to gain additional information.
• Avista has been required to conduct an independent analysis.
• The material is involved in or results in a major gas incident.
If it is determined by either internal or external analyses that the material failure was caused by an
installation error, then an internal assessment should be performed when required per GESH, Section 17
—Gas Incident Field Investigation, or Gas Standards Manual, Specification 4.31, Operator Qualification.
Once the failure cause has been determined by one of the three analysis methods above, the Gas
Materials Engineer will document the failure cause and notify the Gas Pipeline Integrity Program Manager
of the results. The Gas Pipeline Integrity Program Manager will record and trend material failures. Reports
required by state or federal pipeline safety entities shall be submitted by the Gas Pipeline Integrity
Program Manager and approved by the Manager of Pipeline Integrity and Gas Compliance.
The Gas Pipeline Integrity Program Manager works with the Gas Materials Engineer throughout this
process to track and trend material failures as applicable in order to meet the requirements of Avista's
DIMP and TIMP programs and to facilitate the submission of PHMSA Forms F7100.1-1 and/or F7100.2-1
as delineated in Gas Standards Manual, Specification 4.14, Recurring Reporting Requirements.
WAC 480-93-200 (6): In the state of Washington, when laboratory analysis is used to determine that a
material or construction defect has resulted in an incident or hazardous condition, Avista must supply
the WUTC a copy of the failure analysis report within 5 days of receiving it.
DOT Reportable Incidents
Incident assessments shall be conducted when a DOT Reportable incident occurs. The Pipeline Safety
Engineer shall notify the Gas Quality Assurance (QA) Manager and the Safety Manager of such
occurrences. The QA Manager and the Safety Manager will mutually determine who shall be responsible
for coordinating and overseeing the process. These assessments shall be completed for incidents
involving a federally defined incident per§191.3 as follows:
A release of gas from a pipeline and.
• A death; or
• Personal injury necessitating in-patient hospitalization; or
• Estimated property damage of the operator and/or others of$145,400 or more (excluding cost of gas
lost); or
• The release of gas exceeding 3,000 MCF; or
OPERATIONS REV. NO. 2
INCIDENT AND FAILURE ASSESSMENT DATE 01/01/25
X-4, sr'a STANDARDS 2 OF 4
Utilities NATURAL GAS SPEC. 4.62

• An event that is significant, in the judgment of Avista, even though it does not meet the criteria listed
above.
Noticeable Trends (Multiple Occurrences)
Repeated events or noticeable trends of safety, material or other situations may be cause for an
assessment to be completed. Some past examples of such "multiple occurrence" events have been:
• Valves installed and left in the closed position
• Failure to monitor downstream pressure when required
Gas Related Fires and/or Explosions
Oftentimes gas related fires and/or explosions will become DOT Reportable Incidents and require
assessment as noted above. Lesser instances of such occurrences may merit assessment as well. The
Senior Manager of Gas Operations and Gas Operations Managers are the gatekeepers to request an
assessment of these "lesser"fires/explosions as applicable when they occur in their areas of
responsibility.
Non-gas Related Fires and/or Explosions
In addition to gas related fires and explosions, there may be a need to assess non-gas related fires or
explosions to provide lessons learned and to provide information for Avista stakeholders (Legal, Claims,
External Communications, etc.)as applicable. The Senior Manager of Gas Operations and Gas
Operations Managers are the gatekeepers to request an assessment of these situations as applicable
when they occur in their areas of responsibility.
Employee Injury
This area of assessment is complicated as other entities such as Avista Safety, Occupational Health,
Labor and Industries, OSHA, etc. may be involved. These incident assessments are facilitated by the
Safety Department and in conjunction with the Gas Quality Assurance Department, where necessary, to
address gas related considerations.
Third-Party Damages
Third-Party Damage is a situation where damage occurs to Avista facilities by entities other than Avista
and its contractors. Third-Party Damage costs thousands of dollars of impact to Avista facilities every
year. Typically, these types of assessments will be facilitated by the Underground Facility Damage
Prevention Administrator, and consequently will usually fall outside the scope of this specification.
Pipeline Ruptures and/or Rupture Mitigation Valve (RMI� Closures (Transmission Facilities Only)
As discussed in §192.617 (c), if an incident on an inshore gas transmission pipeline involves the closure
of a RMV, Avista must conduct a post-incident analysis of all the factors that may have impacted the
release volume (of gas) and consequences of the incident and identify and implement operations and
maintenance measures to prevent or minimize the consequences of a future incident. Until the time
Avista installs RMVs, this portion of code is not applicable, however, once RMV(s) are installed, the
assessment of any RMV closure will be conducted in accordance with §192.617 (c).
If the failure or incident on an onshore gas transmission pipeline involves the identification of a rupture
following a notification of potential rupture, or the closure of an RMV, or the closure of an alternative
equivalent technology, the operator of the pipeline must complete a summary of the post-failure or
incident review required by paragraph (c)of this section within 90 days of the incident, and while the
investigation is pending, conduct quarterly status reviews until the investigation is complete and a final
post-incident summary is prepared. See additional detail at§192.617 (d).
OPERATIONS REV. NO. 2
INCIDENT AND FAILURE ASSESSMENT DATE 01/01/25
X-4, sr'a STANDARDS 3 OF 4
Utilities NATURAL GAS SPEC. 4.62

Near Misses
Near misses are unplanned incidents or events that did not result in injury, illness, or damage, but had the
potential to do so. Near misses provide an opportunity to conduct an assessment and identify and
develop recommendations to prevent or minimize consequences of a future event. Process Safety near
miss assessments are conducted by the Gas Quality Assurance Department and in conjunction with the
Avista Safety Department when a potential employee severe injury or fatality is involved.
Other Management Directed Reasons for Conducting An Assessment
There is really no limit to the criteria or reasons for conducting an assessment. When in doubt, an
assessment should be undertaken.
INCORPORATION AND COMMUNICATION OF LESSONS LEARNED
Procedures Updating(Includes Design, Construction, Testing, Maintenance, Operations,
Emergency Response, Training, and Operator Qualification)
Once an assessment has been completed the recommended corrective actions identified by the
assessment team are reviewed. Corrective actions focused on preventing or minimizing the
consequences of a future incident are entered into the Avista Intelex Safety Data Management System.
The corrective actions within Intelex are assigned an owner and a due date to ensure items are tracked to
completion. If the corrective actions identify gaps in the GSM or GESH, they are reviewed by the
respective committee and changes incorporated, as appropriate. The lessons learned are communicated
to pertinent employees.
OPERATIONS REV. NO. 2
INCIDENT AND FAILURE ASSESSMENT DATE 01/01/25
X-4, sr'a STANDARDS 4 OF 4
Utilities NATURAL GAS SPEC. 4.62

5.10 GAS MAINTENANCE TIMEFRAMES AND MATRIX
SCOPE:
To define the various maintenance timeframes as required by state and federal regulations for gas
pipeline systems.
REGULATORY REQUIREMENTS:
§192
WAC 480-93
The timeframes identified in this manual are defined as follows:
Definitions
Monthly— Means any time within the calendar month.
Annually—Means any time within the calendar year.
Calendar Year— Means twelve consecutive months beginning January 1 and ending December 31.
2-1/2 months—Means the same calendar date of the second consecutive month plus an additional 15
days.
4-1/2 months—Means the same calendar date of the fourth consecutive month plus an additional 15
days.
6 months— Means the same calendar date of the sixth consecutive month.
7-1/2 months—Means the same calendar date of the seventh consecutive month plus an additional 15
days.
15 months— Means the same calendar date of the fifteenth consecutive month.
3 years— Means the same calendar date of the third consecutive year.
39 months— Means the same calendar date of the thirty-ninth consecutive month.
5 years— Means the same calendar date of the fifth consecutive year.
63 months— Means the same calendar date of the sixty-third consecutive month.
10 years— Means the same calendar date of the tenth consecutive year.
For calendar dates that end on a weekend or holiday, the next business day shall be considered the
timeframe end date.
The following pages include Gas Maintenance Matrix tables which outline the tasks and
timeframes for each type of ongoing maintenance activity.
MAINTENANCE REV. NO. 14
MAINTENANCE TIMEFRAMES & MATRIX DATE 01/01/25
XvIST'r STANDARDS 1 OF 6
utilities NATURAL GAS SPEC. 5.10

Category Sub-Category Maintenance Frequencies DOT Ref Other References GSM Ref.
Regulator Stations
Regulator Station Relief Once Each Calendar Year, 192.739 5.12
Inspection Not to Exceed 15 months 192.743
Regulator Station Overhaul Approx.20%Per Year Avista Internal Standard 5.12
Rebuild All In 5 Years
Master Meter Once Each Calendar Year, 192.739 5.12
Regulator Stations Not to Exceed 15 months 192.743
Regulator Station, Once Each Calendar Year, 192.743 5.12
Relief Capacity Review Not to Exceed 15 months
Gate Stations,Supplier's Once Each Calendar Year, 192.743 5.12
Relief Set Point Review Not to Exceed 15 months
Regulator Stations Once Each Calendar Year, 192.479 WAC 480-93-110 5.12
Atmospheric Corrosion Not to Exceed 15 months 192.481
Regulator Stations, Once Every 3 Years,
operating on permanent Not to Exceed 39 months Avista Internal Standard 5.12
bypass
Portable Regulator Stations Each time the station is Avista Internal Standard 5.12
placed into service
Portable CNG Trailers Once Each Calendar Year, Avista Internal Standard 5.12
Not to Exceed 15 Months
Flexible Element and Boot Once Every 5 years Avista Internal Standard 5.12
Type Regulators(Overhaul)
Diaphragm Type Regulators Once Every 10 years Avista Internal Standard 5.12
and Pilot(Overhaul)
Farm Taps
Farm Taps Atmospheric Once Every 3 Years, 192.479 WAC 480-93-110 5.12
Corrosion Not to Exceed 39 months 192.481
Farm Taps(Upstream
Source fed from a Once Every 3 Years, 192.740 5.12
Transmission Line-Full Not to Exceed 39 months
Inspection)
MAINTENANCE REV. NO. 14
MAINTENANCE TIMEFRAMES & MATRIX DATE 01/01/25
Xv sm a STANDARDS 2 OF 6
utilities NATURAL GAS SPEC. 5.10

Category Sub-Category Maintenance Frequencies DOT Ref Other References GSM Ref
Heaters
Regulator and Gate
Stations, Line Monthly Avista Internal Standard 5.22
Heaters Leak
Inspection
Regulator and Gate
Stations, Line Monthly Avista Internal Standard 5.22
Heaters Operation
Regulator and Gate
Stations, Line Monthly Avista Internal Standard 5.22
Heaters Water/
Glycol Level
Regulator and Gate
Stations, Line Sample Annually or Avista Internal Standard 5.22
Heaters,Water/ Replace Every 3 Years
Glycol Constituents
Regulator and Gate
Stations, Line Once Each Calendar Year, 192.739 5.22
Heaters Pilot Safety Not to Exceed 15 months
Test
Regulator and Gate
Stations, Line
Heaters High Once Each Calendar Year, 192.739 5.22
Temperature Not to Exceed 15 months
Shutdown
Thermostat Test
Regulator and Gate
Stations, Line Once Each Calendar Year,
Heaters Flame Not to Exceed 15 months 192.739 5.22
Arrestor Clean/
Inspect
Regulator and Gate
Stations, Line Once Every 10 years Avista Internal Standard 5.22
Heaters Heating
Coil Inspection
Regulator Stations, Once Each Calendar Year,
Pilot Heaters Leak Not to Exceed 15 months 192.739 5.22
Inspection
Regulator Stations, Once Each Calendar Year,
Pilot Heaters Not to Exceed 15 months 192.739 5.22
Operation
Valves
Emergency Valves Once Each Calendar Year, 192.747 WAC 480-93-100 5.13
(Distribution) Not to Exceed 15 months
Emergency Valves Once Each Calendar Year, 192.745 WAC 480-93-100 5.13
(Transmission) Not to Exceed 15 months
Emergency Curb Once Each Calendar Year WAC 480-93-100 5.13
Valves Not to Exceed 15 months
Blow Down Valves Once Each Calendar Year, 192.745
and Associated Not to Exceed 15 months 192.747 WAC 480-93-100 5.13
Appurtenances
Once Every 5 years Not to Avista Internal Standard
Secondary Valves Exceed 63 months (Best Practice) 5.13
(Recommended)
MAINTENANCE REV. NO. 14
MAINTENANCE TIMEFRAMES & MATRIX DATE 01/01/25
XvIST'r STANDARDS 3 OF 6
utilities NATURAL GAS SPEC. 5.10

Category Sub-Category Maintenance Frequencies DOT Ref Other References GSM Ref
Line Patrols
Transmission" Once Each Calendar Year, 192.705 5.15
Class 1 &2 Locations Not to Exceed 15 months
Transmission` Twice Each Calendar Year
Class1 &2; Highway& Not to Exceed 7-1/2 months 192.705 5.15
RR Crossings
Transmission" Twice Each Calendar Year 192.705 5.15
Class 3 Locations Not to Exceed 7-1/2 months
Transmission` Four Times Each Calendar Year
Class 3; Highway&RR Not to Exceed 4-1/2 months 192.705 5.15
Crossings
Transmission" Four Times Each Calendar Year 192.705 5.15
Class 4 Locations(All) Not to Exceed 4-1/2 months
Once Each Calendar Year,
HP Distribution Pipelines Not to Exceed 15 months(Should 192.721 5.15
occur as a Best Practice)
Water Crossings and
Other Pipelines where Four Times Each Calendar Year 192.721 5.15
External Loading/ Not to Exceed 4-1/2 months
Movement Likely
Major River Crossings Once Every 5 Years, Not to 192.721 5.15
Exceed 63 months.
Distribution Lines Annually in Conjunction With 192.721 5.15
20%Leak Survey
Line Markers Once Every 5 years Not to 192.707 WAC 480-93-124 5.15
Exceed 63 months
Cathodic
Annual Survey of Once Each Calendar Year,
Cathodic Protection Not to Exceed 15 months 192.465 5.14
Areas
Isolated Short Section
Survey Main<100 ft. 10%Per Year(Entire System 192.465 5.14
or Service Lines every ten years)
Protected isolated risers
Rectifiers Six Times Each Calendar Year 192.465 5.14
Not to Exceed 2-1/2 months
Critical Bonds,Critical Six Times Each Calendar Year 192.465 5.14
Diodes Not to Exceed 2-1/2 months
Other Bonds Other Once Each Calendar Year, 192.465 5.14
Diodes Not to Exceed 15 months
Unprotected Pipelines Within 1 yr.of Installation 192.465 WAC 480-93-110 5.14
(90 Days,Washington)
Casings with Steel Once Each Calendar Year, WAC 480-93-115 5.14
Carrier Pipe Not to Exceed 15 months
Shorted Casing(Confirm 90 Days after initial determination WAC 480-93-110 5.14
Short) of a possible short
Atmospheric Corrosion, Once Every 5 Years, Not to 192.479 WAC 480-93-110 5.20
aboveground services Exceed 63 months 192.481
Atmospheric Corrosion, Once Every 3 Years, Not to 192.479
aboveground pipelines Exceed 39 months 192.481 WAC-480-93-110 5.20
other than services
May be different per Transmission Integrity Management Plan
MAINTENANCE REV. NO. 14
MAINTENANCE TIMEFRAMES & MATRIX DATE 01/01/25
XvIST'r STANDARDS 4 OF 6
utilities NATURAL GAS SPEC. 5.10

Category Sub-Category Maintenance Frequencies DOT Ref Other References GSM Ref
Leak Survey
Business District Once Each Calendar Year, Not to 192.723 WAC 480-93-188 5.11
Exceed 15 months
High Occupancy Once Each Calendar Year, Not to
Structures High Exceed 15 months WAC 480-93-188 5.11
Occupancy Areas
20%Per Year,Complete System
20%Survey In 5-Year Period Not to Exceed 192.723 5.11
63 months
Transmission Pipelines Once Each Calendar Year, Not to 192.706 5.11
Exceed 15 months
Pipelines Operating Once Each Calendar Year, Not to
greater than or equal to Exceed 15 months(Washington WAC 480-93-188 5.11
250 psig Only)
<30%SMYS Semi-annually as outlined
Transmission in Class 3 Avista's Transmission Integrity 192.935 5.11
or 4 Location with no Management Plan
HCA's
Non-Cathodically Twice Each Calendar Year Not to
Protected Steel Pipe& Exceed 7-1/2 months WAC 480-93-188 5.11
Non-Cathodically (Washington Only)
Protected Isolated Risers
Initially within 90 days of
Shorted Casings confirmed shorted condition and WAC 480-93-110 5.11
then 2 times each year not to
exceed 7-1/2 months
Road Resurfacing Jobs Prior to Paving or resurfacing WAC 480-93-188 5.11
Underground Leak Within 30 days of making repair WAC 480-93-186 5.11
Residual Re-Check
Grade 2A Leak Response Less than 30 days Avista Internal Standard 5.11
(Best Practice)
Grade 2 and Grade 2A Every 6 Months until cleared— WAC 480-93-18601 5.11
Re-Evaluation Repair within 15 months
Grade 2 Repair Within 1 Yr.Of Detection Not to WAC 480-93-18601 5.11
Exceed 15 months
Grade 3 Re-Evaluation Next Leak Survey or Not to WAC 480-93-18601 5.11
Exceed 15 months
Within 24 months(not to exceed
27 months)but can be extended
Grade 3 Repair to 33 months if the segment is 5.11
due for replacement.Note: This
is a best practice in all states
Program Self Audit Every 3 Years(Washington Only) WAC 480-93-188 5.11
Third party damage As needed WAC 480-93-188 5.11
In areas and times of
unusual activity such as As needed WAC 480-93-188 5.11
earthquake,floods,
landslides,fires,etc.
MAINTENANCE REV. NO. 14
MAINTENANCE TIMEFRAMES & MATRIX DATE 01/01/25
XvIST'r STANDARDS 5 OF 6
utilities NATURAL GAS SPEC. 5.10

Category Sub-Category Maintenance Frequencies DOT Ref Other References GSM Ref
Odorization
Odorization Test Monthly-All Test Points 192.625 WAC 480-93-015 5.23
Test Point Review Once Each Calendar Year Avista Internal Standard 4.18
Odorizer Maintenance By type, per Specification WAC 480-93-015 5.23
5.23
Vaults
Vault Maintenance Once Each Calendar Year, 192.749 5.18
Not to Exceed 15 Months
Certifications
Weld Retest Twice each
Welder Certification calendar year Not to Exceed 192.227 WAC 480-93-080 3.22
7-1/2 months
Re-Qualify,Annually Not to
Plastic Certification Exceed 15 months between 192.285 WAC 480-93-080 3.23
qualifications
Emergency Plan
Emergency Training Annually 192.615 GESH 13
Fire, Police,&Public Official Periodically 192.615 GESH 13
Liaison 192.616
O&M Manuals
O&M Manual Review Once Each Calendar Year, 192.605 WAC 480-93-180 1.4
Not to Exceed 15 months
O&M Procedure Review Periodically 192.605 WAC 480-93-180 1.4
Instruments
Monthly not to exceed
CGI Calibration 45 days and 12 times per WAC 480-93-188 5.19
year
Leak Survey Equipment Per Manufacturer's WAC 480-93-188 5.11
Calibrations recommendation
Per Manufacturer's
Odorometer Calibration recommendation. (YZ WAC 480-93-015 4.18
recommends every two
years for DTEX units)
Pressure Gauges and Once Each Calendar Year, WAC 480-93-170 5.21
Calibration Standards Not to Exceed 15 months
Once Each Calendar Year,
Telemetry Devices(i.e., Not exceed 15 months,or in 5.12
transmitters)&Pressure accordance with the WAC 480-93-170 5.21
Recorders manufacturer's
recommendations
Meter Provers Every 2nd Calendar Year Avista Internal Standard 2.22
Cathodic Instruments Annually WAC 480-93-110 5.14
(Voltmeters, Electrodes,etc.)
Customer Notification
Notification to Customer of Letter to Customer Within
Responsibility for Buried g0 Days of Service 192.16 4.22
Downstream Service
MAINTENANCE REV. NO. 14
MAINTENANCE TIMEFRAMES & MATRIX DATE 01/01/25
Xv sm a STANDARDS 6 OF 6
utilities NATURAL GAS SPEC. 5.10

5.11 LEAK SURVEY
SCOPE:
To establish procedures to be followed in detecting, classifying, and reporting natural gas leakage in
Avista's pipeline systems and facilities. Included in this section are leak survey types and methods, leak
classification criteria, leak investigation and follow-up procedures, and recordkeeping requirements.
REGULATORY REQUIREMENTS:
§191.12, §192.503, §192.703, §192.706, §192.709, §192.721, §192.723, §192.1009
WAC 480-93-110, 480-93-115, 480-93-175, 480-93-185, 480-93-186, 480-93-18601, 480-93-187, 480-
93-188
CORRESPONDING STANDARDS:
Spec. 3.18, Pressure Testing
Spec. 3.44, Exposed Pipe Evaluation
Spec. 5.15, Pipeline Patrolling - Pipeline Markers
GESH Section 2, Leak Investigation
GESH Section 4, Emergency Procedures
GESH Section 17, Incident Investigation
LEAK SURVEY
General
Only properly trained and qualified employees and contractors shall perform leakage surveys, leak
centering procedures, and calibration of leak detection equipment. Avista shall perform gas leak surveys
in which a gas detection instrument is passed over the transmission and distribution pipelines, as well as
other gas facilities. The frequencies and types of surveys are specified in this specification and shall
conform to applicable regulatory codes. While performing leakage surveys, personnel will typically also
perform distribution patrolling functions as noted in Specification 5.15, "Maintenance Frequencies".
Specific detail on this accomplishment and supplemental information regarding the Leak Survey Program
are covered in the Leak Survey Program Orientation Manual.
Relation of PPM, Percent Gas, and Percent LEL
PPM RELATION TABLE
PPM % Gas % LEL*
100 .01% .2%
500 .05% 1%
1,000 .10% 2%
5,000 .5% 10%
7,500 .75% 15%
10,000 1% 20%
40,000 4% 80%
50,000 5% 100%
100,000 10%
250,000 25%
*-The percent LEL figures are based on 1% Gas being equal to 20% LEL for Avista gas
MAINTENANCE REV. NO. 24
LEAK SURVEY DATE 01/01/25
Xv sm a STANDARDS 1 OF 22
I i►ities SPEC. 5.11
NATURAL GAS

Gas Leak Detection Instruments
Instruments utilized to detect concentrations of natural gas shall be used according to manufacturer's
instructions. These instructions shall be on-site when the equipment is in use for all surface gas detection
surveys. Approved instruments utilized by Avista and its Contractors to detect concentrations of natural
gas during leak surveys are as follows:
Infrared (IR) Leak Detector: An intrinsically safe, portable device that uses infrared (IR)technology to
detect the presence of natural gas leaks. The detector functions by identifying specific infrared light
wavelengths and absorption characteristics for methane gas. IR devices are extremely sensitive and can
detect very small leaks with a sensitivity down to 1 PPM. The IR device technology is currently the
primary detector tool used by Contractor leak survey patrols (Other equivalent instruments may be used
as technological advances are made). Note: Take caution when using pump driven leak survey devices
during wet weather events or when sampling near standing water. Moisture that is drawn into the tool
may damage or adversely affect functionality.
Detecto-Pak Infrared Detector(DP-IR): The DP-IR is one type of IR detector that utilizes infrared
controlled interference polarization spectrometry (CIPS). This translates to having a low-end sensitivity of
1 ppm that can auto-scale up to 100 percent gas by volume. The DP-IR is basically the combination of a
"search" instrument and a CGI in one device that does not require external fuel gas. The DP-IR is also
selective to methane only and thus prevents false positives that can be detected with other units.
Additional features include a built-in self-test and zero function which helps assure the instrument is
working properly. These self-tests are internally stored by the instrument which has sufficient memory to
hold up to 2,000 logs.
Laser Methane Detector: A laser methane detector is an intrinsically safe detector that is capable of
detecting methane from a remote distance and can be used to check for the presence of gas prior to
entry or in hard to reach or not easily accessible areas. The instrument does not have to be within the gas
plume because it uses laser technology known as Tunable Diode Laser Absorption Spectroscopy. As the
laser passes through the gas plume, the methane absorbs a portion of the light, which the instrument
then detects. There are many conditions that can impact a laser detector's reading; therefore, these
instruments shall not be used to record gas concentration, grade, or classify a leak. The intent of these
instruments is to provide other means of checking for the presence of gas.
Remote Methane Leak Detector(RMLD): The RMLD is a type of laser methane detector that is often
used when leak survey personnel cannot gain entry to a property but can complete the leak survey from a
remote distance. It is an intrinsically safe detector that is capable of detecting leaks from a remote
distance (approximately 100 feet maximum)and consequently, it is possible to survey areas that are hard
to reach or are not easily accessible (i.e., river/stream/canal crossings and secured facilities). The RMLD
makes it possible to detect leaks along the sight line without needing to walk the full length of the service
line. It is designed to be selective to detecting methane only and will not false alarm on other hydrocarbon
gases. The RMLD has a built-in function to perform a self-test and calibration of the laser wavelength.
The self-test feature should be used daily to ensure the instrument is operating properly. This tool is often
used when leak survey personnel cannot gain entry to a property but can complete the leak survey from a
remote distance.
Sensit Gas Trac LZ30: The Sensit Gas Trac LZ30 is an intrinsically safe compact laser methane detector
that can be used to check for the presence of gas up to 100 feet away. The instrument can be used
through windows, around door frames and in hard-to-reach areas such as high ceiling, soffit vents, crawl
spaces. The instrument has adjustable visual, audible, and tactile alarms and features a target laser
which is used to aim it in the desired direction. The instrument has a calibration cell inside its case.
MAINTENANCE REV. NO. 24
LEAK SURVEY DATE 01/01/25
Xvism a STANDARDS 2 OF 22
I i►ities SPEC. 5.11
NATURAL GAS

Combustible Gas Indicator(CGI)—A Combustible Gas Indicator is an intrinsically safe leak detector that
employs either a permeable membrane, catalytic or thermal filament to detect the presence of
combustible gases. The Lower Explosive Limit(LEL) is measured using the membrane or filament. The
membrane/filament is heated, combustible gases burn and then cool on the membrane/filament. The
changes in temperature are then converted to a reading in percent Gas Range (0 to 100 percent gas in
air)that is shown on a digital display.
Most modern CGI units are electronic and have a motorized pump system that is used to draw in an air
sample. Older model CGIs used a hand aspirator pump for this purpose. CGIs are mainly used to obtain
readings of combustible gases drawn from bar holes, inside structures, or in other confined areas. These
detectors are not normally used in the system leak surveys due to the fact that bar holes would have to
be drilled along all pipeline routes in order to effectively sample buried facilities. CGIs are, however,
essential in centering leaks and obtaining accurate percentage gas in air readings.
Bascom Turner Gas Rover& Gas Explorer(ethane option)-The Gas RoverTM and Gas Explorer are
both a type of CGI that can be used for handheld or mobile surveys and for responding to indoor or
outdoor leak calls. The Gas-RoverTM and Gas Explorer are used to locate leaks, grade them, perform
safety checks and, in the process, greatly reduce the number of bar-holes needed to be placed on the
property. What makes both the Gas-RoverTM and Gas Explorer so versatile are their calibrated accuracy
in the PPM range of gas, intrinsic safety, optional carbon monoxide and oxygen sensors, and their
extensive and automatic data collection and storage.
The Bascom Turner Gas Rover and Explorer with ethane option allow the user to take an air sample from
a site suspected to be non-pipeline gas, similar to the Sensit IRed (see below). These devices analyze
the sample and give the user a result of ethane detected or not detected. Some units use a combination
of the above technologies.
Note: There are some CGI detectors that do not indicate percentages of gas but simply have a visual or
audible alarm. Detectors that have the capability of displaying percentage readings may be used to center
leaks, determine the extent of underground leakage using bar holes, and to obtain readings in structures
or other confined areas. Detectors without percentage indication shall not be used in leakage surveys or
in centering and classifying leakage.
Note: Take caution when using pump driven leak survey devices during wet weather events or when
sampling near standing water. Moisture that is drawn into the tool may damage or adversely affect
functionality.
Sensit IRed Portable Infrared Ethane Detector(IRed): The Sensit IRed is designed to detect the presence
of ethane in a methane sample. The IRed can detect 250 parts per billion (ppb) up to 500 ppm ethane.
The IRed is used to determine if methane detected in the range of 50 to 2,400 ppm is of similar make-up
to that of pipeline gas, which contains ethane or is naturally occurring methane from other sources such
as organic decay. The IRed is not designed for high concentrations or determining actual ethane content
from within a pipeline.
The IRed senses gas using Infrared Absorption Spectroscopy in combination with an electronic narrow
band pass filter. This technology utilizes an infrared light source with an output that is changed when
certain gases absorb the light output. The filter only allows specific light wavelengths to be monitored and
measured. The concentration of gas is proportional to the amount of specific Infrared light absorbed and
is displayed in parts per billion (ppb) or parts per million (ppm).
An IRed is currently housed with Avista's Leak Survey Administrator and others are dispersed in at least
one construction office in each state. They are to be used when the result of a leak/odor investigation is
inconclusive and foreign gas is suspected. Contact the local Lead Service Foreman Tor Leak Survey
Program Administrator if further information is required.
MAINTENANCE REV. NO. 24
LEAK SURVEY DATE 01/01/25
XvISTA STANDARDS 3 OF 22
I i►ities SPEC. 5.11
NATURAL GAS

Other instruments historically utilized by Contractor and Avista personnel to detect concentrations of
natural gas during leak surveys are as follows:
Flame Ionization Detector(F.I.)—This electronic instrument detects the presence of methane gas by
measuring the ions produced in a hydrogen flame when gas is burned. The ions conduct electricity, which
is in turn measured by the electronic circuitry in the instrument to produce a reading, normally in parts-
per-million (ppm) of gas in air. Most modern flame ionization detectors are capable of detecting
concentrations of gas 1 ppm or less. Air samples are drawn into the detector by a pump. If the sample is
diluted the readings may be inaccurate, thus it is not advisable to use this type of detector in wet or windy
weather. Flame ionization detectors were at one time the primary instrument used in leak surveys to
detect the presence of gas, however infrared and laser detectors have become the preferred technology
for leak survey.
Maintenance of Instruments
Each instrument used for leak detection and evaluation shall be operated and maintained in accordance
with the manufacturer's instructions. Instruments shall be calibrated monthly or in accordance with the
manufacturer's instructions. Calibrations shall be performed on a regular schedule using certified test
gases. Calibrations shall also be performed after any repairs or replacements of parts. Records of
instrument calibrations shall either be affixed to the instrument and maintained in the local construction
office or maintained within the Leak Survey Mobile Application as applicable. Dust filters on detectors
shall be checked at least daily and more frequently if conditions are dusty. Filters should be changed or
cleaned, as necessary.
Batteries shall be checked daily and changed if the instrument will not zero or if it appears to not be
functioning properly. Rechargeable batteries should be cycled periodically. Remove batteries if the unit is
to be stored for a long period of time.
Detectors shall be checked for leakage in the sampling system before each use. Instrument leaks shall be
repaired immediately (leaks in the sampling system can cause the sample to be diluted or may allow dirt
to enter the instrument).
GAS LEAK SURVEY METHODS:
The following gas leakage survey methods and procedures shall be employed in locating leaks in gas
piping systems and other related facilities:
Surface Gas Detection Survey
This survey involves continuous sampling of the atmosphere at or near surface level over buried or
submerged gas pipelines and facilities with an instrument capable of detecting a concentration of at least
50 ppm or more of gas in air(gas detector) at any sampling point. For below ground facilities, any
concentration of gas in air found in ppm shall be investigated, leak classified per this Specification and
then documented for follow-up repair, as necessary. Aboveground facilities are also to be checked with
gas detectors during the survey and gas in air concentrations registering at or above 7,500 ppm shall be
leak classified and then documented for follow-up repair. The exception is when an above ground leak is
found on an indoor facility.
The gas detector used in surface surveys shall be one of the approved leak detection instruments listed in
the "Leak Detection Instruments" section of this Specification and one that is applicable. Sampling of the
atmosphere over buried piping should be in accordance with the manufacturer's specifications for the
specific instrument, but not more than 2-inches above the ground surface as applicable.
MAINTENANCE REV. NO. 24
LEAK SURVEY DATE 01/01/25
Xv sm a STANDARDS 4 OF 22
I i►ities SPEC. 5.11
NATURAL GAS

Foot Survey- Survey of gas pipelines and facilities conducted on foot shall be conducted using an
approved and applicable gas detector. The gas detector shall be passed over all portions of each main,
service, and other facilities that are buffered for survey each year. In addition, the atmosphere shall be
tested at accessible gas, electric, telephone, sewer, water, and other underground structures. The gas
detector shall also be passed over cracks in pavement, in wall-to-wall paved areas, and over the cracks in
the sidewalk. Building walls adjacent to the pipelines or facilities and other locations where there may be
the possibility of migrating gas shall also be surveyed. Dead vegetation over the top of gas lines may be
an indicator of an underground leak. The individual performing the survey shall determine the locations of
underground pipelines or facilities when necessary to accurately complete the survey. Pipelines and other
facilities that are inaccessible by foot shall be surveyed using remote leak detection technology or other
means of survey.
Mobile Survey-A vehicle mounted gas detector(one of the approved and applicable leak detection
instruments listed in the "Leak Detection Instruments" section of this specification) may be used to
perform the surface gas detection survey. This method may be used where it is practical in surveying long
stretches of buried pipeline that are accessible to a vehicle. Care shall be exercised not to exceed speeds
specified in manufacturer's instructions. Pipelines and other facilities that are inaccessible to vehicles
shall be surveyed by foot or by boat.
Diver or Remote Submersible Survey (Underwater)—This is an underwater survey of gas pipelines using
a qualified diver or a remote submersible vehicle with an inspection camera. This type of inspection is
limited to very few locations in Avista's system where a foot survey is not possible due to the size and
depth of the water crossing. During the survey, the diver inspects for signs of leakage (bubbles) on the
pipeline facility. Underwater surveys are the preferred method of survey for major river crossings and are
completed in accordance with Specification 5.15, Pipeline Patrolling. Individuals performing the survey
shall document conditions found and shall schedule required repairs or follow-up.
Boat Survey (Overwater)—This is a surface survey of gas pipelines using an approved and applicable
gas detector. A boat survey is conducted overwater using an Avista approved procedure which shall
consider current/water flow, water depth and wind conditions. A bubble ascent calculation program is
required to determine the appropriate size and location of the survey area. This type of survey is typically
used to supplement a diver or submergible survey is limited to pipelines where a foot survey is not
possible due to the size and depth of the water crossing. There are very few of these locations within
Avista's system. During the survey, technicians should be performing a visual scan of the water surface
over and downstream of the pipeline looking for bubbles and/or turbulence in the water that may indicate
a leak. Individuals performing the survey shall document conditions found and shall schedule required
repairs or follow-up.
Survey Documentation & Follow-up— Individuals performing surface gas detection surveys shall evaluate
and classify any leaks found (refer to Classifying Leaks within this specification). Document the leaks
using the Leak Survey Location Report, N-2511, or electronic record and forward the information as
applicable for the scheduling of required repairs or follow-up.
Survey Limitations— Leak survey should not be conducted during periods of high winds, heavy rain,
excessive soil moisture, wavy conditions or if the surface is sealed by ice or water as these conditions
may prevent leaking gas from rising directly to the surface. Additional precautions must be considered
when leak investigations are required under these conditions. Refer to the "Underground Leak
Investigation" section of this specification for additional information.
MAINTENANCE REV. NO. 24
LEAK SURVEY DATE 01/01/25
Xv sm a STANDARDS 5 OF 22
I i►ities SPEC. 5.11
NATURAL GAS

Soap/Bubble Leak Test
Soap/Bubble leak tests involve the application of a soap and water solution or other leak detection
solution to exposed piping or facilities to determine the existence of a leak. The pipe or facilities to be
tested should be reasonably clean and free of debris. The piping is then coated with the solution and
monitored for signs of leakage (active bubbles).
This method is used to test exposed or aboveground portions of a system such as meter set assemblies,
exposed piping at regulator stations, service valves, etc. It is also used to test any fittings or taps not
included in a pressure test. Bubble tests are also used for detection of leaks on customer house
(downstream) piping and equipment. Soap/Bubble leak tests shall only be used as a supplement to the
other methods of surface leak detection on exposed or above ground facilities in Avista's gas system.
Employees performing soap/bubble leak tests shall document conditions found and shall schedule
required repairs or follow-up.
Pressure Drop Test
This test is used to determine if an isolated segment of pipeline loses pressure due to a leak. The pipeline
or facility must first be isolated in order to perform the test. Pressure drop tests conducted solely to
determine if leakage exists should be performed at a pressure at least equal to operating pressure.
Testing procedures shall conform to Specification 3.18, Pressure Testing. Pressure drop tests have
limited application in the scope of leak detection in a pipeline system. They will only establish whether a
leak exists; the leak will then need to be located and evaluated. The employee performing pressure drop
tests shall document conditions found and shall schedule required follow-up or repairs.
Detection of Other Combustible Gases
Most leak detection equipment will also register a reading for other combustible gases even though they
are calibrated for methane. In the case where leak indications are found that originate from a source other
than natural gas, the employee performing the investigation shall take prompt action at the time of
discovery to protect life and property and the environment. The property owner or other adult person on
the premises shall be notified that leak indications were found, and that the source is other than natural
gas. The customer shall be advised to contact the proper authorities for determination of the exact cause
of the indication, and for correction of the problem. Examples of foreign sources of leak indications
include gasoline vapors, sewer or marsh gases, propane vapors, landfill gases, etc.
WAC 480-93-185: In the state of Washington, the above procedures shall be followed, and the
company shall take appropriate action regarding its own facilities to protect life and property. In
addition, if an indication is found to originate from a foreign source and the situation is ongoing and
potentially hazardous, the employee on site shall so inform the property owner or the adult occupying
the premises, and where appropriate, shall inform the police department, fire department, or other
appropriate governmental agency. If the property owner or an adult person is not available, the
company shall, within 24 hours of the leak investigation, send out a letter to the person occupying the
premises explaining the results of the investigation. A record of each letter sent must be kept for 5
years.
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Can't Gain Entry/Can't Find
In the course of performing leak survey operations, survey technicians may encounter situations where
they Can't Gain Entry (CGE)to the customer's property (because of a locked gate or an aggressive dog,
etc.) or they Can't Find (CF)the gas meter to successfully complete the survey. Specific processes for
CGE and CF follow up attempts by the survey contractor are detailed in the Leak Survey Orientation
Manual (updated annually). If the follow up attempts required by the contractor are unsuccessful a
Service Request is then generated, and Avista Gas Operations completes the survey.
LEAK SURVEY PLANS:
At the end of each year, the Leak Survey Program staff(in conjunction with the appropriate construction
offices) shall determine the proposed Leak Survey Program scope for the coming year. Such proposals
shall include:
• Mobile devices and/or maps showing the areas to be surveyed
• Methods of survey to be used
• Estimates of total footage of main, number of services, and/or total hours for the survey
• A brief summary and training plan for seasonal employees (as applicable)
Gas leakage surveys shall be conducted according to the following frequencies:
Annual Distribution System Surveys
Business Districts and Buildings of Public Assembly
Leak surveys shall be made once each calendar year not to exceed 15 months of all gas facilities within
business districts and/or places of public congregation (high occupancy structures or areas). The surface
survey shall be conducted using an approved gas detector in accordance with the procedures outlined in
this specification.
Business District—An area where the public regularly congregates or where the majority of the buildings
on either side of the street are regularly utilized for financial, commercial, industrial, religious, educational,
health, or recreational purposes. Mains and gas facilities in the right-of-way adjoining a business district
must also be included in the survey.
High Occupancy Structure (HOS)or High Occupancy Area (HOA)—A structure or area that is normally
occupied by 20 or more persons on at least 5 days a week for 10 weeks in any 12-month period. (The
days and weeks need not be consecutive.) Structures and areas include churches, hospitals, schools,
and may include assembly buildings, outdoor theaters, outdoor recreation areas, etc.
Where gas service lines exist, a survey shall be conducted at the building wall where the service enters
the building. A permanent bar hole shall be drilled if deemed necessary by the employee conducting the
survey.
If leakage is detected at the outside wall of a building, a survey shall be conducted on the inside of the
building at points where migrating gas could be expected to enter and accumulate. Service piping, service
risers and valves, and the entire meter set assembly shall be checked with a leak detector or with a soapy
solution.
Leaks detected shall be reported on an individually numbered leak survey report. Each underground leak
detected shall also be noted on the appropriate map or electronic record, as applicable. Leak survey
reports shall be forwarded to the local construction office for the appropriate action or follow-up.
MAINTENANCE REV. NO. 24
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Identifying High Occupancy Structures, High Occupancy Areas, and Business Districts
Annually, prior to the next leak survey season, Leak Survey Program staff will conduct reviews using
approved updates to the current season's map buffer layers to confirm any changes and make any
necessary updates to the next season's survey maps. At this time, the addition of high occupancy
structures/areas are noted for inclusion on the annual survey program.
The records of this annual process are the red-lined maps/mobile device updates; no separate record of
this review is required. Refer to Avista's Leak Survey Map Update Process SOP for specific procedures
on updating High Occupancy Structures, High Occupancy Areas, and Business Districts.
Transmission and Other High-Pressure Pipelines
Transmission pipelines shall be leak surveyed once each calendar year not to exceed 15 months. The
survey shall be conducted using an approved leak detection instrument. The exception is a transmission
pipeline that meets the following criteria which shall be leak surveyed on a semi-annual basis:
• Pipelines and facilities that operate at less than 30 percent SMYS in a Class 3 or Class 4 location
where no high consequence areas have been identified per Avista's Transmission Integrity
Management Program
As a best practice starting in 2018, high pressure distribution pipelines in all states should be leak
surveyed annually. The exception to this are pipelines and facilities, in Washington State, which operate
at 250 psig, or above which shall be surveyed as noted below.
250+ psig Pipelines (Washington Only)
WAC 480-93-188: In the state of Washington pipelines operating at or above 250 psig must be leak
surveyed at least once annually, but not to exceed 15 months between surveys.
Each leak detected shall be reported on an individually numbered leak survey report. Each underground
leak detected shall also be noted on the appropriate map. Leak survey reports shall be forwarded to the
local construction office for action and include Gas Engineering if the leak is on a High-Pressure facility.
5 Year Distribution System Survey
Residential areas shall be surveyed with an approved leak detection instrument so that the entire
distribution system is surveyed in a 5-year period not to exceed 63 months. (Approximately 20 percent of
the system shall be surveyed each calendar year).
Mains, services, meter set assemblies, and all other gas facilities shall be included in these surveys.
Meter sets may be checked with a leak detector or tested with a soapy solution. Each leak detected shall
be reported on an individually numbered leak survey report. Each underground leak detected shall also
be noted on the appropriate map or electronic record. Leak survey reports shall be forwarded to the local
construction office for action or follow-up.
Special Surveys
The following special surveys are required in the state of Washington. Avista's operating districts in other
states should also perform these special surveys as a best practice.
When special surveys are required, and leak survey resources are needed, the respective operation's
area representative should notify the Leak Survey Program Administrator or Program Manager and
provide schedule requirements as well as delineation of the extent of the area requiring the special
survey. Special surveys performed by the local operating district shall be documented and maintained at
the local level.
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Information that documents the survey should be sent to the Leak Survey Program Administrator or sent
to#[e-mail] to facilitate availability for records audits. Special surveys shall be
surveyed with an approved leak detection instrument in the following instances:
• Prior to any paving or resurfacing, following street alterations or repairs where there are gas facilities
under the area to be paved and when damage could have occurred to these facilities. This survey
shall be completed to check the pipeline or facilities, and to check for gas at manholes and other
street openings for the presence of natural gas. (Note: chip sealing of roadways is not considered
paving or resurfacing to the extent that a special survey is required.)
• In areas of sewer, water, or other substructure construction adjacent to underground gas facilities
where damage could have occurred to the gas pipelines.
• In areas with shifting or unstable soil conditions where active gas pipelines or facilities could be
damaged or otherwise affected.
• In areas and at times of unusual activity, including, but not limited to, foreign construction,
earthquake, flooding, explosions (including blasting operations), fires, or other natural disasters.
(Note: In the case of an earthquake, first priority areas should be those where there has been
noticeable damage to roadways, land distortion such as buckling and heaving of the ground, and
places where there are known unstable soils and/or where landslides have occurred.)
• In cases where it is determined that additional survey methods are required to identify the source or
location of a suspected gas leak or odor, or in cases where a company employee specifically
requests a special survey.
• During pressure uprating procedures. Refer to Specification 4.17, Uprating.
• Shorted Casings—When a steel casing becomes electrically shorted to a steel gas pipeline and the
short cannot be cleared in 90 days, a leak survey test shall be conducted within 90 days of discovery
and at least 2 times annually thereafter, but not to exceed 7-1/2 months until the condition is
corrected.
WAC 480-93-188 (3)(d): Where the gas system has non-cathodically protected steel piping. This
survey must be conducted on all such segments of piping (including non-cathodically protected
isolated risers) 2 times each calendar year not to exceed 7-1/2 months in the state of Washington.
In Washington State where a steel gas pipeline is being lowered or moved (i.e., "roped"). Refer to Spec
3.12— Pipe Installation Steel Mains for additional information. This should also be a best practice in Idaho
and Oregon service areas.
WAC 480-93-175: Lowering or Moving Metallic Gas Pipelines—A leak survey must be conducted
within 30 days from the date a steel pipeline has been moved or lowered that is 2 inches in diameter
and smaller that operates at 60 psig or less and that did not have a study performed prior to moving in
the State of Washington. [For other states and facilities, this is considered a best management
practice.]
• DIMP Identified Surveys—A special survey shall be conducted when a trend is identified through
Avista's Distribution Integrity Management Program, where a leakage survey has been identified as
an additional action to minimize high risk facilities. The Pipeline Integrity Program Manager shall
coordinate with the Leak Survey Program staff to determine the parameters of the survey.
MAINTENANCE REV. NO. 24
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CLASSIFYING LEAKS:
The following procedure establishes criteria by which leakage indications of natural gas can be classified.
Each indication of gas leakage shall be evaluated by the employee performing the survey. Evaluation
includes establishing the area limits or perimeter of the leak, determining if immediate action is necessary
to protect life, property, and the environment. Evaluation also includes assignment of a Grade or Class to
the leak in conformance with this specification. Leakage monitoring, classification, and repairs shall be
based on the following factors:
• Potential or actual danger to the public or property
• The volume of escaping gas and the percentage readings on a Combustible Gas Indicator(or
equivalent instrument).
• The area limits of the leak and the proximity to structures both above and below ground
• The possibility or presence of any type of channel or other means whereby gas may accumulate or
migrate below ground
• Soil and surface conditions that may affect migration
• Proximity of the leakage to sources of ignition
• Public and media awareness, apprehension, and reaction to the leakage
• Earth movement, flooding, or other natural disaster where external stresses on pipelines or facilities
may cause or accentuate leakage
When all the above factors have been considered, the employee performing the survey shall classify
each leak using one of the following leak grades, thereby establishing the leak repair priority. With regard
to the following leak grade criteria, the definition of"reading" means a repeatable (sustained)
representation on a combustible gas indicator or other similar instrument.
Grade 1 Leak
A Grade 1 leak is any leak that represents an existing or probable hazard to persons or property. It
requires immediate repair or prompt continuous action until the conditions are no longer a hazard. Grade
1 leaks are responded to immediately by company personnel. Refer to"Re-classification of Leaks"
subsection in this specification for further guidance on acceptable temporary repairs and if they meet the
requirements of"prompt continuous action" noted here.
Examples of Grade 1 Leak Situations:
1. Any leak which, in the judgment of personnel on the scene, is regarded as an immediate hazard to
life, property, or the environment
2. Escaping gas that can be seen, felt, or heard which is in a location where it may endanger the
general public, property, or the environment
3. Escaping gas that has ignited
4. Any indication of gas which has migrated into or under a building or tunnel
5. Any reading at the outside wall of a building where the gas could potentially migrate to the inside
wall of a building
6. Any reading of 80 percent LEL or greater in a confined space
7. Any reading of 80 percent LEL or greater in small substructures not associated with gas facilities
where the gas could potentially migrate to the outside wall of a building
8. Any leaks involving construction damage to our pipelines or facilities
9. Any leaks where the police, fire department, other governmental authority, or media has responded
and Avista has been notified as such
Note: The Avista First Responder can leave once the investigation is complete, the scene is safe, and a
crew is on location making repairs.
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Action to Be Taken:
Immediate and prompt action until the leak is considered non-hazardous may include one or more of the
following:
A. Implementation of the company Emergency Operating Plan (EOP)
B. Evacuation of the premises involved, and any adjacent structures as needed
C. Blocking off an area
D. Re-routing traffic (vehicle or pedestrian)
E. Removal of all sources of ignition
F. Venting of the leak
G. Stopping the flow of gas by closing valves or by other means
H. Notifying the police and fire departments
I. After making safe, repair the leak
Grade 2A Leak
A Grade 2A leak is assigned only by Avista's Leak Survey Contractor and defined as: Any leak that is
recognized as being non-hazardous at the time of detection, but that justifies scheduled repair based on
probable future hazard and is in a location that would benefit from a response sooner than the standard
Grade 2 timeframe.
Examples of Grade 2A Leak Situations:
1. Any leak discovered greater than 5 feet from a building foundation, but may have the potential to
migrate to the building foundation
2. Any leak discovered in a high use hardscape area, such as a street intersection
3. Any readings between 20 percent and 80 percent LEL in a confined space
Grade 2 Leak
A Grade 2 leak is any leak that is recognized as being non-hazardous at the time of detection but justifies
a scheduled repair based on probable future hazard. Underground leaks that are classified as Grade 2 by
the individual performing leak surveys shall be followed up with a subsurface survey(pinpointing of the
leak) and a verification of the grading by obtaining percentage reads with a Combustible Gas Indicator.
Examples of Grade 2 Leak Situations:
Leaks requiring action prior to ground freezing or other adverse changes in venting conditions (any leak
that could potentially migrate to the outside wall of a building under frozen or adverse soil conditions).
Leaks requiring action within 6 months include the following:
1. Any reading of 40 percent LEL or greater under a sidewalk in a wall-to-wall paved area that could
potentially migrate to the outside wall of a building
2. Any reading of 100 percent LEL or greater under a street in a wall-to-wall paved area that would
probably migrate to the outside wall of a building
3. Any reading less than 80 percent LEL in small substructures not associated with gas facilities where
gas could potentially migrate creating a probable future hazard
4. Any reading between 20 percent and 80 percent LEL in a confined space (See also "Grade 2A Leak"
earlier in this specification. Leak Survey Contractor shall report these as a Grade 2A.)
5. Any reading on a pipeline operating at 30 percent SMYS or greater in Class 3 or 4 locations.
6. Any leak which in the judgment of operating personnel at the scene is of sufficient magnitude to
justify scheduled repair
It should be recognized that Grade 2 leaks will vary greatly in degree of potential hazard. Some Grade 2
leaks, which when evaluated by the above criteria, may justify scheduled repair within the next 5 working
days. Others may lustify repair within 30 days. These situations should be brought to the attention of the
individual responsible for scheduling leakage repair.
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Action to Be Taken:
Grade 2 leaks shall be reevaluated at least once every 6 months until cleared. The frequency of re-
evaluation should be determined by the location and magnitude of the leakage condition. Leaks should be
repaired or cleared within one year, not to exceed 15 months, from the date reported. If a Grade 2 leak
occurs in a segment of pipeline due for replacement, an additional 6 months may be added to the 15
months maximum time for repair. The following factors shall be considered in assigning a priority of
repair: Amount and migration of gas, proximity to buildings and subsurface structures, extent of any
paving, soil type and conditions (frost caps, moisture, natural venting, etc.).
In addition to the above requirements, the judgment of experienced field personnel shall be enlisted in
determining the scheduling of repairs on Grade 2 leaks. These leaks shall be repaired under a time
schedule that provides safety to the public, while remaining practical to company operations.
Grade 3 Leak
A Grade 3 leak is any leak that is non-hazardous at the time of detection and can reasonably be expected
to remain non-hazardous. Underground leaks coded Grade 3 by the individual performing leak survey
shall be followed up with a subsurface survey(pinpointing of the leak) and a verification of the
classification by obtaining percentage reads with a Combustible Gas Indicator.
Examples of Grade 3 Leak Situations:
1. Any reading of less than 80 percent LEL in small gas associated substructures such as small meter
boxes or gas valve boxes
2. Any reading under a street in areas without wall to wall paving where it is unlikely the gas could
migrate to the outside wall of a building
3. Any reading of less than 20 percent LEL in a confined space
Action to Be Taken:
Grade 3 leaks shall be re-evaluated at least once every 12 months, not to exceed 15 months, until
cleared. The frequency of re-evaluation should be determined based upon the location and magnitude of
the leak condition. Leaks should be repaired or cleared within 24 months, not to exceed 27 months, from
the date the leak was originally reported. If a Grade 3 leak occurs in a segment of pipeline due for
replacement, an additional 6 months may be added to the 27-month maximum time for repair.
Aboveground Outside Leak Classification
If a leak is found on aboveground facilities it should be graded in accordance with the following:
Grade 1 —A Grade 1 leak is any leak that represents an existing or probable hazard to persons or
property—(Hazardous.) Refer to Grade 1 Leak subsection in this specification.
Grade 2—Any leak that is recognized as being non-hazardous at the time of detection, but that justifies
scheduled repair based on probable future hazard. Any leak registering on a CGI (percent gas mode) 5
percent or greater gas in air.
Grade 3—Any leak that is non-hazardous at the time of detection and can reasonably be expected to
remain non-hazardous. Any leak registering on a CGI (percent gas mode)0.75 to 4.99 percent gas in air.
Note: A leak found on aboveground facilities does not require documentation and classification until it can
be detected at a minimum of 7,500 ppm gas in air.
Aboveground Inside Leak Classification
Any inside leak on Avista piping should be treated as a Grade 1 leak by Avista's Leak Survey Contractor
for subsequent evaluation and grading by an Avista Gas Serviceman. The Avista First Responder should
evaluate the potential hazard posed by the leak, and if appropriate in their judgment, may downgrade the
leak one time to a Grade 2 or a Grade 3.
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Underground Leak Determination
The presence or absence of underground leakage shall be determined by performing a bar hole survey
utilizing a CGI unit in "percent gas mode" or a ppm survey utilizing approved leak detection instrument in
"ppm mode"that is capable of detecting a concentration of 50 ppm or less. Should any concentration in
the "ppm mode" be found, a bar hole survey using a CGI in the "percent gas mode" is required to be used
to pinpoint and grade the leak. For a ppm survey, describe the area surveyed (refer to GESH 2, Leak and
Odor Investigation, "Investigation at Aboveground Avista Facilities"for examples of descriptions) and
document the results found. For a bar hole survey, the location and results of each bar hole shall be
documented. Checks shall be made at the following locations to determine the extent of the leakage:
• The point of entry of all underground utilities to a building or structure (gas service riser, water
service, sewer, conduits, etc.)
• At cracks in exterior basement walls and around the perimeter of the building foundation.
• Over the service line and out to the main, as necessary.
• At street openings such as curb boxes, drains, vaults, manholes, etc. in the immediate area.
• In the interior atmosphere of the basement of any building or structure involved in the investigation.
• At any other location where, natural gas may accumulate or migrate.
Underground Leak Investigation
The Avista First Responder/ Leak Survey Technician (as applicable) shall investigate for the presence of
underground leakage by taking underground samples, using bar hole sampling in percent gas mode,
when any of the following conditions exist:
• When leakage on a meter set assembly or outside customer house piping is repaired and gas odors
persist.
• When an Avista-side or customer-side odor investigation is intermittent or inconclusive as to the
source of the odor.
• When it is determined that we have previously responded to a leak or odor call at the same premise
location within the past 30 days.
• When a fire department(or other emergency responder) has requested our response to check our
gas facilities (example: close a meter due to fire, continue a leak investigation begun by the fire
department, etc.). Refer to GESH Section 17, Gas Incident Field Investigation.
• In all cases of failures of gas facilities or when our gas facilities are involved in fires or explosions.
Refer to GESH Section 17, Gas Incident Field Investigation.
• In any other situation where it is suspected that natural gas may be leaking or migrating underground.
• When there is suspected damage beyond a break in a main or the possibility of multiple leaks.
• When a service line has been pulled, broken, or damaged (even without apparent leakage) by a third-
party excavation. (Refer to "Service Line Leak Survey", later in this section for further details).
Note: Bar holes over 12-inches in depth require notification to the One Call Center.
Survey Limitations: To determine which type of survey or survey equipment to use above, consider
limitations such as frost, rain, high winds, surface sealed by ice/water, paving, concrete, or other issues
that would prevent an effective survey.
Leak investigations required under these conditions may require the following additional considerations:
• Bar holing at additional depths to obtain proper sampling.
• Visually observing bar holes and puddles for evidence of bubbles or blowing water.
• Expanding the leak investigation to viable locations where gas is more likely to migrate, vent and
provide usable readings. This may include foundation walls, areas of higher ground, the extents of
saturated soils, subsurface structures (both gas and non-gas).
• Focusing investigations on known locations of 3rd party work that may have resulted in damage to gas
facilities.
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Pinpointing/Centering
Pinpointing is the process of tracing a detected gas leak source. It should follow an orderly systematic
process to minimize excavation. When underground leakage is detected, a ppm-only survey is not
sufficient. A percent gas-in-air survey must be combined with a bar hole survey. The following procedure
for centering or pinpointing the leak shall be followed.
A subsurface survey or leak centering procedure shall be conducted by taking samples with a
combustible gas indicator in a series of available openings (sewer manholes, electric or telephone
substructures, etc.)or bar holes over or adjacent to the pipeline or facility. The location of the gas facility
and its proximity to buildings and other structures should be considered when determining the spacing of
sample points. Spacing of sample points along the main or service will depend on soil and surface
conditions but should never be more than 20 feet apart. Where a pipeline passes under a paved area,
samples should be taken at the entrance and exit points of the paved area. In areas of extensive paving,
consideration shall be given to drilling permanent test holes.
When conducting the survey, bar holes should penetrate to approximately the same depth. Readings
taken at the same depth will enable a meaningful comparison between samples. The reading should be
taken at the bottom of the test hole. Care shall be taken not to aspirate water into the instrument.
Combustible gas indicator probes shall be equipped with a device to prevent the drawing in of fluids.
Refer to Specification 5.19 on how to measure the concentration of methane in a bar hole or other
confined area.
When taking each sample reading, the employee performing the survey shall use the most sensitive scale
on the instrument. Any indications shall be investigated to determine the source of the gas. Care should
be taken when probing, especially around plastic pipe. Sample patterns should include points as close as
possible to the main or pipeline, and adjacent to service taps, known branch connections, Dresser fittings,
or other compression couplings. Risers and buried piping near building walls should also be sampled.
Samples shall continue to be taken until the area limit of the leak is determined, and until the readings
have been sufficiently analyzed so that the suspected center or source of the leak is determined.
Locations with the highest readings will normally indicate that they are closest to the center of the leak;
however, other factors may preclude this. In instances where readings of 100 percent gas are obtained in
several bar holes, it may be necessary to use an ejector aerator to purge each bar hole. In no case
should air ever be infected into a bar hole, as this could result in the gas being driven through the soil into
a structure. Remember when analyzing readings that there is a potential for multiple leaks.
The locations and percentage of gas in air readings obtained with the combustible gas indicator shall be
documented on the appropriate gas operating order. Indicate the approximate locations where the
samples were taken and the corresponding gas-in-air percentage readings in relation to the involved
structure or other physical landmarks in the area.
If a hazardous gas leak is suspected, but the exact source of the leak cannot be pinpointed due to
weather conditions, flooding, or other limiting factors, then Avista First Responder should consider the
following as necessary:
• Evacuation of the area to protect life and property.
• Work with the local electric utility and the Fire Department to eliminate potential ignition sources
in the suspected leak area.
• Shut down the local gas system to minimize the threat of gas migration until readings can be
taken to prove that no hazard exists.
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Venting Underground Leakage
All underground leaks shall be vented to the atmosphere as soon as possible. Underground samples
shall be taken at practical time intervals to determine the extent of migration during repairs and to
determine when such concentrations have reached a safe level. If excavations cannot be left open, for
example, due to traffic, the excavation should be filled with a granular material such as gravel until the
gas is completely vented.
Gas Present in Sewer or Duct System
If gas is found to be migrating to or accumulating in sewer or other duct systems, the Avista First
Responder shall make a complete survey of the affected system to determine the area limits of the
leakage. All buildings or structures served by the system or adjacent to it shall also be checked for the
migration and/or accumulation of natural gas. Emergency procedures shall be followed to protect people
and property in the event that gas is found to be migrating in sewer or duct systems. Manhole covers and
other lids should also be removed, and the open manhole barricaded to aid in venting.
Underground leaks shall be pinpointed and classified per the Leak Classification criteria noted in this
Specification. Leaks classified Grade 1 shall be repaired immediately. Grade 2 and 3 leaks shall be
scheduled for repair per the judgment of trained, qualified field persons on the scene. In all cases,
leakage that is found to be migrating to a building foundation, accumulating in an enclosed area
or tunnel, or that may pose a hazard to the public or property shall be repaired immediately.
Gas Control Room Notification
The Gas Control Room shall be notified at [phone] or via radio as to the conditions found and
whether a construction crew or other assistance is needed to make permanent repairs.
Remaining-on-the-Job
In all cases, the Avista First Responder shall remain on the job site until the situation is safe and poses no
hazard to the public or until relieved by a supervisor or other trained and qualified gas employee.
UNDERGROUND LEAK REPAIR
Leak Repair and Residual Gas Checks
After any leak is repaired it shall be checked for residual gas while the excavation is still open by a person
qualified in Avista Side Leak Investigation. The perimeter of the leak area shall be bar holed and checked
with a combustible gas indicator in percent gas mode to determine if repairs were adequate and if there is
any migration from a secondary leak. A minimum of four(4) bar hole readings shall be taken at equally
spaced points at the perimeter of the excavation or from within the bell hole prior to backfill to fulfill this
requirement. If readings indicate the presence of gas, the perimeter shall be expanded, and additional bar
hole readings taken until the extent of the leak is found and documented down to less than 0.05 percent
gas in air. If the discovery of gas is determined to be a second leak, a new order shall be established by
contacting the Avista Call Center by calling 800-227-9187. Bar hole locations shall be mapped as
appropriate.
EXCEPTION: When a leak is found in a valve box and the leak is repaired by performing maintenance on
the valve, a reading from a combustible gas indicator shall be taken near the bottom of the valve box after
the repair is made. If the reading is zero percent gas in air, bar holes are not required, and the reading
shall be documented on the order. If the reading indicates the presence of gas, bar holes shall be taken
around the perimeter of the leak area as described above. Repairs to damaged service lines require
additional leak survey actions. Refer to the "Service Line Leak Survey" subsection below.
MAINTENANCE REV. NO. 24
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Whenever a pipeline is exposed, whether steel or PE, an Exposed Pipe Inspection Report form (Form N-
2534) shall be completed. Further detail regarding the use of the Exposed Pipe Inspection Report form is
detailed in Specification 3.44, Exposed Pipe Evaluation.
Pressure test information is required if a section of pipe is replaced. It can either be tested in the field or
by using pretested pipe. Refer to Specification 3.18, Pressure Testing.
When exposed, underground Dresser-style or other steel mechanical compression fittings shall be cut out
or canned (barreled). A Cathodic Protection Technician shall be contacted to verify that the fitting is not
being used as an isolation point. Cutting out or barreling may inadvertently create a problem between two
separated cathodic protection systems so additional steps may be necessary before removing or
barreling the fitting.
Pressure Testing Replaced Segments
Pressure test information is required if a section of pipe is replaced. It can either be tested in the field or
by using pretested pipe. Refer to Specification 3.18, Pressure Testing, for further information.
Reinstating a Damaged Service Line
A service line that has been broken, pulled, or damaged resulting in the interruption of gas supply to the
customer shall be pressure tested from the break back to the meter location for the same duration and to
the pressure required for a new service. See Specification 3.18, Pressure Testing, "Reinstating Service"
for further information.
Service Line Leak Survey
When a service line has sustained excavation damage (even without apparent leakage) by a third-party
excavation, a bar hole survey or a ppm survey shall be performed from the point of the damage to the
service tie-in at the main or after the branch. Should any concentration in the ppm mode be found, a bar
hole survey using a CGI in the percent gas mode is required to pinpoint and grade the leak. Broken tracer
wires and nicked coatings do not require the leak survey to occur.
Follow-up Inspections for Residual Gas
In the case of a repaired underground leak where residual gas remains below ground within 1-foot of a
building wall, the employee shall remain on scene to actively monitor and lower the degree of hazard until
the gas concentration within 1 foot of the wall is <1 percent gas-in-air and falling as determined by 3
successive reads, no sooner than 20 minutes apart. (Reference the GESH, Sections 2 and 4.)The
employee shall find the perimeter of the readings by bar holing until less than 0.05 percent gas-in-air is
detected.
In cases away from structures, where there is residual gas in the ground after a repair, regardless of the
grade of the leak, a follow-up inspection with an approved leak survey instrument or CGI, in the percent
gas mode, shall be made as soon as practical, but in no case later than 30 days after the repair. The
repair shall continue to be rechecked until a reading of less than 0.05 percent gas-in-air is obtained by
taking bar hole readings and the leak repair order is closed. Bar hole readings should be taken as close
as possible to the previous reading locations.
If any residual gas exists, the employee shall find the perimeter of the readings by bar holing until less
than 0.05 percent gas-in-air is detected, to assure a new leak source from outside the original site is not
occurring. If a new leak is discovered, this must be treated as a new investigation and must be
documented separately on a new leak order. This will allow for proper documentation of the cause of
the new leak and for filling out an Exposed Pipe Inspection Report as applicable. Bar hole locations shall
be mapped as appropriate.
MAINTENANCE REV. NO. 24
LEAK SURVEY DATE 01/01/25
Xv sm a STANDARDS 16 OF 22
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NATURAL GAS

Large amounts of gas that have saturated the ground may take additional time to completely vent.
Successive readings should indicate a consistent drop in gas-in-air concentrations over time. If a reading
of less than 0.05 percent is not obtained after a reasonable time allowance for venting, the leak repair
shall be excavated and visually examined for defects, and the adjoining pipeline checked for additional
leakage.
If a defect in the leak repair is found or if additional leakage is indicated, the leak shall be graded, and
repairs made.
Re-Classification of Leaks
Leaks shall be re-inspected using the same criteria and guidelines used to classify leaks when they are
first detected. A Grade 1 or 2 leak can only be downgraded once to a Grade 3 leak without a physical
repair. After a leak has been downgraded once, the maximum repair time for that leak is 21 months from
the date of the downgrade. (The downgrading of a Grade 1 leak classification to a Grade 2 or Grade 3
classification should only occur when the leak has been misclassified.)
Maximum effort should be implemented to fix Grade 1 leaks when discovered. A temporary repair,
however, may be authorized in cases where an immediate repair is not feasible. A Grade 1 leak that has
had temporary repair action taken so that it is no longer hazardous may be left to fix when conditions
allow if after three consecutive reads, 20 minutes apart, the reads demonstrate that the gas in air levels
are not rising to hazardous levels. A Grade 1 leak that has had temporary repair and is no longer
hazardous, should not be left longer than one week in this state without the approval of the operations
manager and the Manager of Gas Engineering. Combustible Gas Indicator readings in percent gas mode
via bar hole shall be taken DAILY to ensure gas levels are staying non-hazardous until the final repair is
complete. These leaks will remain classified as Grade 1 leaks.
Self-Audits
Audits shall be performed as frequently as necessary, but in any case, at intervals not exceeding three
years to determine the following as discussed in WAC 480-93-188(6). (These self-audits are required in
Washington and are a best management practice in other states.)
• That the leak survey schedule is commensurate with the requirements in the applicable State and
Federal codes.
• That the survey program is effective and that a consistent evaluation of leaks is being made
throughout the system.
• That required repairs and follow-ups are being made within the time limits specified.
• That leak repairs are effective; and
• That the records being kept are adequate and complete.
Self-Audit Records
To align with the Distribution Integrity Management Program (DIMP), Leak Survey Self-Audit records shall
be retained for 10 years.
MAINTENANCE REV. NO. 24
LEAK SURVEY DATE 01/01/25
XvISTA STANDARDS 17 OF 22
I i►ities SPEC. 5.11
NATURAL GAS

MAINTENANCE FREQUENCIES:
Avista leak survey programs shall be performed according to the following schedules:
Type of Survey Frequency
Business Districts and High Once each calendar year,
Occupancy Structures /Areas not to exceed 15 months
Residential Areas 5 Years, not to exceed 63 months
5 Year Survey (20 percent Survey) 20 percent of system each calendar year
Non-Cathodically Protected Isolated Twice each calendar year, not to exceed 7-
Risers 1/2 months (Washington only) until protected
Other Non-Cathodically Protected Twice each calendar year, not to exceed 7-
Steel Pipelines 1/2 months (Washington only) until protected
Within 90 days from date of discovery then
Shorted Steel Casing twice each calendar year not to exceed 7-1/2
months) until cleared or repaired
Transmission Lines Once each calendar year, not to exceed 15
months
<30 percent SMYS Transmission Lines Semi-annually as outlined in IMP Plan
in Class 3 or 4 Location with No HCA's
Paving and Utility Construction Jobs Prior to paving, after construction is
completed
High Pressure Pipelines (Oregon, Annually (best practice)
Idaho, and Washington < 250 psi
High Pressure Pipelines Operating Once each calendar year, not to exceed 15
>=250 psig months (Washington Only but a best practice
in Idaho and Oregon))
Lowering or Moving of Steel Pipe =< 2" Within 30 days of moving pipe (Washington
& < 60 psig, no roping calculations Only but a best practice in Idaho and
needed Oregon)
Type of Repair or Follow-Up Frequency
Grade 1 Leak Repair Immediate Response - Continuous Action
Until Non-Hazardous
Grade 2A Leak Less than 30 days
Recommended Response
Grade 2 Leak Repair Within 1 year, not to exceed 15 months
Grade 2 and 2A Re-Evaluation At least once every 6 months until cleared
(repair within 15 months)
Within 24 months (not to exceed 27 months)
Grade 3 Leak Repair but can be extended to 33 months if the
segment is due for replacement. Note: This
is a best practice in all states.
Grade 3 Re-Evaluation Once each calendar year, not to exceed 15
months until cleared
Underground Leak Repair Follow-Up Immediately after repair, and not later than
(regardless of thegrade) 30 days after where residual gas is present
Self-Audit of Leak Survey Program Not to exceed 3 years. (Washington Only)
MAINTENANCE REV. NO. 24
LEAK SURVEY DATE 01/01/25
X VIST' a STANDARDS 18 OF 22
Utilities SPEC. 5.11
NATURAL GAS

Recordkeeping
Records and maps of leak surveys performed shall be retained for the life of the facilities.
Each leak survey performed and/or leak discovered shall be recorded on an individually numbered leak
survey report. The report shall be filled out as completely as possible and shall indicate the following
information:
LEAK SURVEY FORMS:
Special information required for leak surveys performed:
• Date of survey and a description of the area surveyed (include maps and any logs kept)
• Survey method (DP-IR, RMLD, IRED, CGI, etc. including instrument number)and name of
person(s) performing the survey
• Results of the survey, including the number of services checked, the footages of mains surveyed,
number of leaks found and locations of leaks, the leak grades as they were classified by the
surveyor, as well as references to individual reported leaks and map reference numbers
Special information required for leaks discovered:
• Address and complete location of the leakage (include drawing as necessary)
• Leak Survey Map reference number
• Time and date leak found
• Leak classification grade and percentage gas-in-air reading
• Leak data such as type of detector and instrument identification number, probable source of
leakage, soil type, surface conditions, pipe size and type, vegetation damage, etc.
Special information required for leaks repaired:
• Bar holing information, if required
• Leak detection instrument identification number and percent of gas in each bar hole
• Leak cause* (Refer to end of this specification for definitions of causes)
• Component leaking
• System facility (main, service, valve, etc.)
• Pipe size and material type
• Location
• Repair Date
• Exposed Piping Inspection Report
• Pressure test info (tested in the field or pretested pipe)
• Repair materials
• Post-repair perimeter of excavation readings with type of approved leak detection instrument and
ID number.
Leak repair work orders shall be retained with the leak survey report and the report shall be noted as to
the disposition of the repairs and/or follow-ups. (When exposing pipe, an Exposed Piping Inspection
Report Form (Form N-2534)shall be completed. Reference Specification 3.44, Exposed Pipe Evaluation,
for further guidance.)
Special information required for rechecks:
• Date of the recheck.
• Percentage gas-in-air readings found for each bar hole location.
• Type of combustible gas indicator used and ID number.
o If additional readings of gas are found, additional follow up and documentation is required
until the residual gas is cleared.
MAINTENANCE REV. NO. 24
LEAK SURVEY DATE 01/01/25
XvISTA STANDARDS 19 OF 22
I i►ities SPEC. 5.11
NATURAL GAS

Closing Leak Reports
A leak report shall be considered closed when one or more of the following conditions have been
established:
• The cause of the leak report has been corrected by the completion of necessary repairs, or
• Where evidence indicates that materials other than natural gas caused the leak report, and this
information has been directed to the appropriate parties for action, or
• When required, a follow-up inspection has been conducted which shows the absence of natural
gas
Blowing Gas and Odor Calls
For information on recording the appropriate information on blowing gas and odor calls refer to the Gas
Emergency and Service Handbook, Section 2.
Leak Incident Reporting
When an individual decides that a leak condition indicates a hazardous or potentially hazardous situation,
the individual shall immediately notify the Call Center by calling 800-227-9187 and request
assistance as needed. In the case of major construction damage or any situation that is indicated as
reportable in GESH Section 13, Emergency Planning, Training and Incident Notification, the Gas
Controller shall immediately notify the following persons or departments:
• Emergency services (as necessary)
• Appropriate crews or servicemen to control the situation and effect repairs
• Claims Department
• On-call construction supervisor
• On-call Gas Engineer
• Applicable operations manager
• Corporate Communications
The On-Call Gas Engineer shall evaluate the situation and determine if a telephonic report to the
appropriate agency is required and shall make the report within the specified time limits. Field employees
and the Gas Control Room shall provide the necessary information to complete the required reports as
soon as such information is known. Reports and related information shall be recorded on the appropriate
forms and retained in Gas Engineering. In addition, written follow-up reports shall be completed by the
On-Call Gas Engineer and forwarded to the appropriate agency within the specified time limits.
LEAK FAILURE CAUSE DEFINITIONS
The following are definitions and examples for leak failure causes:
CORROSION: Leak resulting from a hole in the pipe or other component that galvanic, bacterial,
chemical, stray current, or other corrosive action causes (corrosion is not limited to a hole in the pipe).
• Pitting
• Dog urine
• Leaks from components that broke due to corrosion such as bolts
NATURAL FORCES: Leaks not attributable to humans such as:
• Earth movements-earthquakes, landslides, subsidence
• Lightning
• Heavy rains/floods -washouts, flotation, mudslide, scouring
• Temperature-frost heave, frozen components, snow related (Refer to snow removal under"other
outside force damage")
• High winds or similar natural causes
• Leaks attributable to animals (gophers, moles, etc.)
MAINTENANCE REV. NO. 24
LEAK SURVEY DATE 01/01/25
Xvism a STANDARDS 20 OF 22
I i►ities SPEC. 5.11
NATURAL GAS

EXCAVATION: Leak resulting from excavation damage caused by:
• Earth moving or other equipment, tools, or vehicles
• Operator's personnel or contractor
• People not associated with the operator
• Unknown previous damage by excavators such as backhoe damage, stakes, ground rods, etc.
• Ground settlement due to excavation disturbance of original compacted backfill
OTHER OUTSIDE FORCE DAMAGE: Include leaks attributed to humans:
• Fire or explosion
• Deliberate or willful acts, such as vandalism
• Vehicular or other machinery(i.e., lawn mower)damage to aboveground facilities
• Animals chained to meter set assembly (MSA)
• Snow removal (shovel, plowing, roof clearing)
• Electrical arcing
MATERIAL*:
Material - include leaks resulting from a defect in the pipe material or component due to faulty
manufacturing procedures.
• Any type of material failure (i.e., cracks/breaks) in plastic pipe or the body of plastic fittings (Aldyl
A service tee crack in tower, cracked service tee caps, rock impingement)
• Failure in steel pipe or the body of steel fittings (not including corrosion)
• Failure in longitudinal weld or seam
• Deterioration of original sound material
• Pipe failure due to bending stress
*Any leak marked as a material failure should also have a Gas Material Failure Report (Form N-2614)
filled out and sent to the Gas Materials Engineer along with the failed component per Specification 4.62,
Material Failure Assessment. Submission of Gas Material Failure Reports are not required for failures
involving the compression fittings on Continental fittings or Aldyl-A service tee caps as these failures have
already been well documented.
WELDS/JOINTS-This includes leaks due to:
• Faulty wrinkle bends
• Faulty field welds
• Plastic joints
• Mechanical fittings (Refer to further guidance at end of this section for Hazardous Mechanical
Fitting Failures)
• Underground leaks on threaded fittings that cannot be tightened
EQUIPMENT: Leaks resulting from:
• Failure or malfunction of fittings and equipment with internal components
o Malfunction of regulator/relief equipment (weeping regulators/relieving
regulators/debris in regulators), remote control valves, instrumentation
o Seal failures on gaskets, O-rings, seal/pump packing, or similar leaks (fittings with 0-
rings in caps)
• Stripped or cracked threads on nipples, valves, or other threaded fittings
• ERT leaking/degradation
WAC 480-93-200 (6): In the state of Washington, when laboratory analysis is used to determine that a
material or construction defect has resulted in an incident or hazardous condition, Avista must supply
the WUTC a copy of the failure analysis report within 5 days of receiving it.
MAINTENANCE REV. NO. 24
LEAK SURVEY DATE 01/01/25
Xv sm a STANDARDS 21 OF 22
I i►ities SPEC. 5.11
NATURAL GAS

OPERATION: Leaks resulting from:
• Inadequate procedures or safety practices, or
• Failure to follow correct procedures, or other operator error
o Stab fittings not chamfered correctly or inadequate stab depth
o Debris found in cap of fitting
• MSA settlement failures
• Damage sustained in transportation to the construction or fabrication site
• Failure of original sound material from force applied during construction that caused a:
o Dent
o Gouge
o Other defect that eventually resulted in a leak
LOOSE/ NEEDS GREASE: Leaks fixed by:
• Tightening of fitting (MSA fittings, service tee caps, stopper fitting caps)
• Applying new pipe dope
• Lubrication such as valves both underground and aboveground
OTHER: Leaks resulting from any other cause, such as exceeding the service life, not attributable to any
of the above causes or inability to determine the cause of the leak.
If you are unsure how to categorize the cause of the leak, contact the Pipeline Integrity Program Manager
or local Gas Operations Manager for assistance.
Hazardous Mechanical Fitting Failures
Mechanical fittings that result in a hazardous leak (Grade 1) are reportable to PHMSA, regardless of the
leak failure cause including excavation damage. This also includes leaks that were originally graded as
Grade 1 and downgraded prior to repairs being conducted.
Mechanical Fitting (Definition): Fittings that consist of specifically designed components including
elastomer seals, O-rings, or gaskets and a gripping device to affect pressure sealing and/or pull-out
resistance capabilities such as stab type, nut follower, and bolted type mechanical fittings.
This applies to both steel and plastic fittings. Some examples of mechanical fittings are as follows:
• Bolt-on service tees
• Bolt-on service tees with stab outlet or with a compression nut
• Steel welded service tees with compression outlet(if leak was in the compression outlet.
• Dresser couplings
• Service head adapters
• Couplings, tees, elbows, three-ways, caps, and stop-n-go fittings with stab connections
• Couplings, tees, elbows, three-ways, and caps with compression connections to include nut
• Repair clamps
Until further notice, cut out the fitting and send it to the Gas Materials Engineer(MSC-6 or email the form
to [e-mail]. Make sure to provide the appropriate service order number or work
order number as applicable for the leak order the fitting represents). If you are unable to cut out or send in
the component, contact the Gas Materials Engineer for direction.
MAINTENANCE REV. NO. 24
LEAK SURVEY DATE 01/01/25
XvISTA STANDARDS 22 OF 22
I i►ities SPEC. 5.11
NATURAL GAS

5.12 REGULATOR AND RELIEF INSPECTION
SCOPE:
To establish an inspection and maintenance program for Avista's gas service regulators, district regulator
stations, gate stations, and farm tap regulator stations. Also covered in this specification is inspection and
maintenance on associated relief valves, safety shutoffs, monitors, and permanent blow down facilities
(overpressure protective devices).
REGULATORY REQUIREMENTS:
§192.195, §192.197, §192.199, §192.201, §192.203, §192.619, §192.739, §192.741, §192.743
WAC 480-93-130, 480-93-140, 480-93-200
OTHER REFERENCES:
National Electric Code (NEC), Article 500 for Hazardous (classified) locations
CORRESPONDING STANDARDS:
Spec. 2.22, Meter Design
Spec. 2.23, Regulator Design
Spec. 2.24, Meter& Regulator Tables & Drawings
Spec. 2.25, Telemetry Design
Spec. 3.32, Repair of Steel Pipe
Spec. 5.13, Valve Maintenance
General
The information and procedures contained in this specification shall constitute the regulator and relief
inspection and maintenance program for Avista. Only qualified, properly trained employees shall perform
inspections and maintenance on company pressure regulating and pressure safety systems.
Before performing maintenance or construction activities at a gate station, regulator station, meter set, or
other facility known to have telemetry, Gas Control must be called to notify them of the work. This will
keep false alarm and alert notifications from being distributed. When work is complete, Gas Control must
be called (509-495-4859 or via radio) again to ensure alarms and alerts have cleared before leaving the
site.
Pressures Precaution
When performing maintenance that involves any regulator, regulating station, meter set, or overpressure
protective device, the inlet and outlet pressures shall be continuously monitored on site using accurate
pressure gauges if the device configuration allows this. If the device is not configured to allow on site
monitoring, an alternate nearby location may be used, and Gas Engineering shall be contacted regarding
revising the existing configuration to allow future on site monitoring. Care shall be taken when performing
operations such as bypasses and stop-offs, so as not to allow the downstream or supply pressure to drop
below normal operating limits. Any loss of pressure that may have extinguished pilots or that may have
affected the normal operation of the customer's gas equipment shall be treated as an outage and the
procedures followed as outlined in the GESH, Section 5, Emergency Shutdown and Restoration of
Service.
Care shall also be taken not to allow the operating pressure to exceed the MAOP plus allowable buildup
(or MOP)of the associated system. If it is determined that a system has exceeded the MAOP (or MOP),
the employee shall immediately attempt to correct the situation and normalize the pressure. Downstream
pressure checks shall be initiated to verify if any damage was caused by the over pressurization of the
system. Gas Engineering shall be notified if either of the above-mentioned situations occurs as this may
necessitate notification of the regulatory agencies.
MAINTENANCE REV. NO. 20
REGULATOR & RELIEF INSPECTION DATE 01/01/25
Xv sm a STANDARDS 1 OF 13
utilities NATURAL GAS SPEC. 5.12

SERVICE REGULATORS:
General Maintenance of all Service Pressures
Service regulators normally reduce distribution pressure to a pressure that is specified as the delivery
pressure or utilization pressure. Utilization pressure for most residential customers in Avista's gas system
is 7—inches WC (1/4 psig). Utilization pressure for some residential, commercial, and industrial customers
may be 7—inches WC, 2 psig, 5 psig, or up to line pressure depending on load and other factors. Service
regulators are normally inspected or tested under the following circumstances:
• When a complaint is received from a customer regarding a suspected pressure problem, a noisy
meter set, odors that may be resulting from a relieving regulator, a damaged meter set, or other
related mechanical problems; or
• When a field employee notices a functional problem during the normal course of operations or
when a related condition is made known by another employee. This includes problems apparent
during the course of performing service orders, turn-ons, relights, new meter installations and
inspections, etc.; or
• When meters and/or regulators are changed out or inspected under a company change out
program (planned meter changes, recalls, retrofits, etc.).
The following should be checked by the field employee when performing an inspection on a service
regulator:
• The general physical condition of the meter set should be checked. Attention should be paid to
rust, meter sets in a bind due to settling, need for meter protection, tamper seals in place, index
readable, etc.
• The regulator and/or relief vents should be clear and free from obstruction, the vent screen
should be in place, and the vents should be oriented in a direction that will not allow water to
enter. In the winter, care should be taken to keep ice and snow from enveloping the regulator
vent as the vent may be frozen over and result in pressure problems.
• Flow and lockup pressure settings shall be checked and adjusted when installed and as
necessary thereafter using a water manometer or a pressure gauge that is known to be accurate.
• The service regulator has overpressure protection.
• The age of the service regulator. Regulators on existing residential and commercial meter sets
should be replaced when nearing 25 years and when an opportunity exists related to
maintenance activities such as a Gas Periodic Meter Changeout(PMC). When an obsolete
regulator is identified as detailed in Gas Standards Manual, Specification 2.22, Meter Design and
Specification 2.24, Meter& Regulator Tables & Drawings, the regulator shall be replaced.
The field employee shall correct any abnormal conditions found on incidental inspections. The
appropriate records should be noted if the meter set is under a maintenance program to avoid duplication
of efforts.
Maintenance of Elevated Service Pressure Accounts
Elevated service pressure accounts that are not classified as industrial shall be maintained as follows:
Two and five psig metering pressure meter sets (residential and commercial) shall have the set pressure
checked 180 days after initial installation and then as noted under"General Maintenance of All Service
Pressures" in this specification. The filter/strainer should be checked if the pressure requires adjustment
at the 180-day check. In addition, these 5-psig metering pressure meter sets shall be checked during the
regular testing cycle of diaphragm meters sized AL1400 and above, rotaries, and turbines. At the time the
meter is due for periodic testing per testing requirements in Specification 2.22, Meter Design, and the
meter is either tested or changed out, maintenance should be conducted on the meter set per the
requirements for"General Station Inspection" and "Annual Regulator Station Maintenance," as applicable.
MAINTENANCE REV. NO. 20
REGULATOR & RELIEF INSPECTION DATE 01/01/25
Xv sm a STANDARDS 2 OF 13
utilities NATURAL GAS SPEC. 5.12

180-Day Inspection Criteria
New meter sets metering at greater than 7-inches WC and all rotary meter sets (regardless of metering
pressure), require a one-time inspection at approximately 180 days of operation (no sooner than 150
days). Diaphragm meters will be inspected by Gas Service Persons; rotary meters will be inspected by
the Gas Meter Shop. The following shall be verified and remediated as appropriate during the 180-day
inspection:
• Flow and lockup pressures are in accordance with the customer billing code and applicable pressure.
• Verify meter configuration matches CC&B (Billing System) Correction Code
• Verify AMR device is operating
• Verify AMR device reading is tracking with CC&B (Billing System) read
• Check and adjust flow and lockup pressure as necessary
• Check overall condition (labeling, settling, paint, etc.)
• Check strainer, as necessary. Clean strainer if necessary.
• For rotary meters, complete the initial differential test.
In some cases, the customer piping may not be connected, or the meter may not have been used at the
180-day check. In this situation, an additional order shall be requested for a subsequent 180-day check to
be completed.
Maintenance of Industrial Meter Sets
A meter set that meets any of the following conditions is considered an industrial set:
1) A set metering at pressures above 5 psig (Note: metering pressure, not delivery pressure)
2) A turbine meter
3) Meter correction code of 3 or P
Elevated service pressure accounts classified as industrial shall be maintained annually per the
requirements under"General Station Inspection" and "Annual Regulator Station Maintenance" as
described within this specification. In addition, industrial meters (diaphragm meters sized AL1400 and
above, rotaries, and turbines) shall be performance tested per Specification 2.22.
REGULATOR STATIONS AND ELEVATED PRESSURE METER SETS:
Farm Taps
A Farm Tap (sometimes referred to as a Single Service Farm Tap—SSFT) is a pressure regulating
station that controls pressure to a service line. Pressures will normally be reduced from pressures over 60
psig down to an intermediate pressure that is commensurate with the load (typically 25 -45 psig).
Normally, an overpressure protection device is provided by a relief valve or safety shutoff. A Farm Tap
style pressure regulating station is considered a district regulator station if it serves downstream main
piping and must be maintained as such.
Farm Taps with an upstream source of gas being fed from a transmission line (Interstate or Avista)
without other pressure regulation upstream shall be maintained as a district regulator station once every
three years not to exceed every 39 months. Refer to Specification 2.24, Meter& Regulator Tables &
Drawings for an example drawing of a Farm Tap regulator station design.
District Regulator Stations
A District Regulator Station is a pressure regulating station that controls pressure to high-pressure or low-
pressure distribution main. It does not include pressure regulation whose sole function is to control
pressure to a manifold serving multiple customers. Master meter stations and bypass customer stations
are treated like district regulator stations and are maintained accordingly.
MAINTENANCE REV. NO. 20
REGULATOR & RELIEF INSPECTION DATE 01/01/25
Xv sm a STANDARDS 3 OF 13
utilities NATURAL GAS SPEC. 5.12

District Regulator Stations vary in design depending on the load demands and size of the system,
physical location, construction limitations, availability of parts, etc. These stations will typically reduce high
pressure gas (over 60 psig)and they will normally use either a relief valve or a monitor valve for
overpressure protection. Refer to Specification 2.24, Meter& Regulator Tables & Drawings for examples
of drawings of typical regulator station designs.
District Regulator Station Relief Capacity Review
Gas Engineering is responsible for reviewing district regulator stations which utilize relief valves as the
overpressure protection device to assure that the relief valve has adequate relief capacity (refer to
Specification 2.23, Regulator Design). If the relief does not have adequate capacity based upon the
calculation, it shall be replaced, or restrictors installed on the regulator(s) based on the recommendation
of Gas Engineering. System deficiencies that could potentially result in the overpressure of the
downstream system should be modified within 30-days. Other deficiencies that do not pose an immediate
threat to system operation should be modified during annual regulator station maintenance or prior to the
end of the calendar year, whichever occurs first. This review must be conducted once every calendar
year, not to exceed 15 months. Relief capacity review records shall be kept for minimum of 5 years.
The relief capacity calculations must be compared to the rated or experimentally determined relieving
capacity of each device for the conditions under which it operates. After the initial calculations are made/
reviewed, subsequent calculations do not need to be performed if the annual review documents the fact
that parameters have not changed to cause the previous relief capacity calculations to no longer be valid.
Gate Station Regulator and Relief Set Point Review
At each gate station where the interstate pipeline is responsible for pressure reduction, Gas Engineering
is responsible for gathering the current regulator and relief valve set point information. Gas Engineering
shall review set points for regulators (worker and monitor) and relief valves to ensure an appropriate
delivery pressure and overpressure protection. Set points must not exceed the MAOP (+10 percent) of
the downstream Avista facilities. If set points exceed MAOP (+10 percent), Gas Engineering shall notify
the respective interstate company to have the set points revised. This review must be conducted once
every calendar year, not to exceed 15 months.
Regulator Station Numbering
Refer to Specification 2.23, Metering and Regulation, "Regulator Station Numbering, "for guidance on
numbering of regulator stations.
Control Room Notifications
Field personnel shall contact Gas Control when emergency conditions exist or when working on location
as described below at a gate station, regulator station, meter set, or other facility known to have telemetry
Before performing maintenance, operations, or construction activities that may affect Control
Room operations, Gas Control must be called at 509-495-4859 or via radio to notify them of the
work.
This includes valve operations including sensing lines to instrumentation and regulators, set point
changes, work on or testing of regulators, instrument calibrations, piping configuration changes,
increasing, or decreasing the pressure of the system, and other activities that may result in an alarm or
alert condition being sensed and transmitted. This will minimize false alarm/alert notifications and
associated personnel call outs. Activities that do not potentially affect gas pressures, gas temperatures, or
alarms, such as site maintenance, reading of odorizer levels, fencing construction and/or vegetation
management, etc., do not require notification. When work is complete, Gas Control must be called again
to ensure alarms and alerts have cleared before leaving the site.
MAINTENANCE REV. NO. 20
REGULATOR & RELIEF INSPECTION DATE 01/01/25
Xv sm a STANDARDS 4 OF 13
utilities NATURAL GAS SPEC. 5.12

General Station Inspection
A station inspection should be performed each time a district regulator station, city gate station, elevated
pressure meter set, or farm tap is visited. (If bypassing of the station is required, the Station Bypassing
Procedure within this specification should be followed.)The field employee should note the following and
take appropriate action to resolve any deficiencies:
• The general condition of the station. It should be free of debris and weeds. Access to the station
should not be impaired, and all station entry doors, locks, and gates shall operate freely. It shall be
verified that the station is properly barricaded or protected from damage. Necessary warning signs
and station identification signs shall be in place and in good condition. In addition, the signs shall
have the correct phone number and other pertinent information and be properly mounted.
• Ventilating equipment installed in station buildings or vaults should be checked for proper operation.
Electrically operated ventilating equipment shall not be operated until it is determined that it
conforms to the applicable requirements of the National Electric Code (NEC), Article 500 for
Hazardous (classified) locations. A check should be done for accumulations that may prevent proper
venting to atmosphere.
• In cases where the station pressure is being adjusted or verified, the inlet and outlet flow pressures
shall be checked with a pressure gauge known to be in calibration.
• The relief(or safety shutoff) shall be checked to verify that the shutoff valve isolating it from the
system is locked in the open position. The vent stack cap on the relief should also be checked for
free operation.
• Security fences and cages (where present)shall be locked for security purposes when access to the
facility is not required.
• Station valves and locking devices shall be checked to ascertain that they are functioning, and that
the valves are locked, or handles removed to prevent tampering, and that they are in the correct
position. (Both above and below ground station valves with the exception of inlet and outlet
emergency valves already being maintained shall be serviced at this time.)
• The station should be leak tested if a gas odor is present.
• Cathodic protection wires and fittings shall be checked and repaired, as necessary.
• Station equipment that is abandoned or not in use shall be removed so as not to create a hazard.
• As the last step before exiting a station, a visual inspection shall be performed to verify all equipment
and valves are in the correct operating positions before locking devices are installed.
Conditions found that are not up to operating standards should either be corrected upon discovery or
scheduled for repair as soon as possible. Hazardous conditions shall be corrected immediately.
Farm Taps and HP Services
Farm Taps (SSFTs) and High-Pressure Services are visited every three years (not to exceed 39 months)
for an Atmospheric Corrosion Inspection. Additionally, a "General Station Inspection" as noted above
shall be performed. A flow and lockup test may be performed if the site is appropriately configured;
however, this action is not required. See"Farm Taps" subsection in this Specification for an exception to
these stated maintenance requirements for farm taps with an upstream source of gas being fed from a
transmission line.
ANNUAL REGULATOR STATION MAINTENANCE
In addition to the general station maintenance items listed above, the district regulator stations shall
receive the following attention under the annual regulator station inspection. If bypassing of the station is
required, the Station Bypassing Procedure within this specification should be followed. The
Manufacturer's Operating Instructions shall be consulted as applicable.
MAINTENANCE REV. NO. 20
REGULATOR & RELIEF INSPECTION DATE 01/01/25
Xv sm a STANDARDS 5 OF 13
utilities NATURAL GAS SPEC. 5.12

Maintenance Procedure
The station outlet flow pressure as found and as left at the station shall be checked and recorded on the
Regulator Station Inspection and Maintenance Record (form N-2527). If the regulator is pulsating or
otherwise acting abnormally, it should be readjusted or disassembled and inspected internally. The outlet
station pressure shall be set to the value shown on the regulator inspection record. A suitable, accurate
pressure gauge shall be used for all pressure checks. MAOP's and MOP's may differ from one district
regulator station to another, so it is important to check the records before performing maintenance or
setting pressures on a station.
• The station lockup pressure shall be verified, if readily allowed by existing station design, and noted
on the inspection record.
• If the regulator is disassembled, the orifice, seat, diaphragm, or boot shall be inspected and
replaced, as necessary.
• Pilot filters should be cleaned or replaced, as necessary. Pilot loading lines shall be inspected for
debris or flaking and cleaned as needed.
• Regulator and pilot vents shall be leak tested. Leakage usually indicates a defective diaphragm or
other malfunction. The regulator or pilot shall be repaired or replaced, as necessary. Replace
cracked or broken regulator or pilot vent caps. Check to make sure that regulator vents are
positioned in the downward position or has a vent elbow installed. Check to make sure any vent
screens are in place and are not damaged.
• Replace damaged gaskets or 0-ring seals on regulator or pilot, as necessary.
• Replace items on a regulator or pilot if subject to manufacturer's recall or update.
• Check the condition of the downstream sensing or control lines. Assure control lines are not
damaged or bent. Check the operation of any line valves. Repair or replace as needed.
• The responsiveness of the regulator shall be verified by checking stroke or by placing the regulator
back into service and observing downstream pressure.
• Flange bolts shall be checked to make sure that they extend fully through the nuts and that no flange
bolts are missing. If a flange bolt-hole is threaded and no nut is required, make sure that the bolts
are long enough to thread through both flanges.
• The station shall be visually inspected for signs of atmospheric corrosion (rusting or pitting). Special
care should be taken to inspect for pitting around fittings that could result in a failure. Adjustable pipe
supports shall be repositioned, and the pipe surface inspected for the evidence of corrosion. Non-
adjustable pipe supports should be visually inspected at the pipe interface for any evidence of
corrosion.
• Insulating material should be in place and in good condition between the carrier pipe and the
support. Risers in the station shall be inspected to ensure the coating is appropriate for above
ground installation and is above the soil-to-air interface and not disbonded. Above ground wax tape
is the preferred coating for steel risers at the soil-to-air interface. X-Tru coating shall not be used for
new installations but may be left in the field on existing stations if the coating is not cracked or
degraded and covered with a well bonded gray enamel paint. Cracked or degrading X-Tru coating
must be repaired with above ground wax tape. In addition to station piping, supporting members
shall be inspected for corrosion and/or damage. If there is evidence of significant corrosion per
Specification 3.32, Repair of Steel Pipe, contact Gas Engineering.
Information pertaining to the inspection of the regulator shall be recorded on the appropriate regulator
station inspection and maintenance record.
MAINTENANCE REV. NO. 20
REGULATOR & RELIEF INSPECTION DATE 01/01/25
Xv sm a STANDARDS 6 OF 13
utilities NATURAL GAS SPEC. 5.12

Maintenance of Overpressure Protection Devices
Overpressure protection devices (including relief valves, monitor regulators, and safety shutoff valves)
shall be inspected and tested once each calendar year.
Overpressure protection devices shall be inspected to ensure the following:
• They are in good mechanical condition.
• They have a vent stack that is not restricted and is positioned away from sources of ignition. Vent
caps and screens shall be checked for obstructions, for proper operation, and to determine that the
screens are intact. Replace or repair any defects.
• They are set to function at the correct pressure by using an accurate test gauge. The regulator
inspection and maintenance record shall be consulted to determine the relief maximum set point as
specified by Gas Engineering. In some cases, the relief set point may be less than the MAOP due to
operating restrictions.
• They are properly installed and protected from dirt, liquids, and other conditions that might affect
proper operation.
• Sensing lines, control lines, filters, restrictors, etc. on relief valves have been inspected and repaired,
as necessary.
Relief and Safety
Bottled nitrogen or bottled CNG should be used, when possible, to pressurize and test relief and safety
shutoff valves. This procedure avoids the unnecessary release of natural gas into the atmosphere and is
also safer than allowing full relief of natural gas at the station (refer to the Nitrogen or CNG Relief Testing
Procedure within this specification).
Precautions should be taken to isolate the relief or safety shutoff valve from the system before testing to
avoid over pressurization, or contamination of the downstream system with nitrogen.
If the relief or safety shutoff does not operate within the specified parameters (maximum set point), it shall
be adjusted to conform to the required set point. If adjustment does not provide the desired results, then
the relief or safety shutoff must be repaired or replaced.
Monitor Testing
Monitor regulators shall be isolated from the system and operated to confirm that they will control
pressure at the proper set point and that they will lockup. Any deviation from normal operation shall be
corrected by repair or replacement. Service monitor regulators according to the guidelines for"Regulator
Maintenance" or according to procedures for"Regulator and Relief Overhaul".
Strainer/Filter Inspection
Station filters or strainers should be either visually inspected or tested by differential flow test. They
should be cleaned or replaced as necessary per manufacturer's instructions.
Station Valves
Valves shall be checked for proper operation and lubricated as necessary per Specification 5.13, Valve
Maintenance.
MAINTENANCE REV. NO. 20
REGULATOR & RELIEF INSPECTION DATE 01/01/25
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utilities NATURAL GAS SPEC. 5.12

Maintenance of Blow Down Facilities
Blow down facilities located on transmission pipelines, at regulator stations or at gate station facilities
shall be inspected once each calendar year, not to exceed 15 months. Valves on blow down facilities
shall be checked for proper operation and lubrication as necessary per Section 5.13, Valve Maintenance.
Purge any excess pressure that may exist between the normally-closed blow down valve and the stack
closure fitting as necessary prior to the start of and at completion of maintenance.
Changes in Station Design
Modifications to existing regulator station designs must be approved by Gas Engineering.
Maintenance of Regulator Stations Operating on Permanent Bypass
Annual regulator station maintenance is not required on stations currently operating on permanent
bypass. These stations shall be visited every 3 years (not to exceed 39 months)for an Atmospheric
Corrosion Patrol. If a station is to be reinstated from permanent bypass the regulator station shall receive
the inspection and maintenance items listed under"Annual Regulator Station Maintenance" prior to being
placed back into service in the field. Information pertaining to the inspection of the station shall be
recorded on the appropriate Regulator Station Inspection and Maintenance Record.
Portable Regulator Station Maintenance
A portable regulator station shall receive the inspection and maintenance items listed under"Annual
Regulator Station Maintenance" every time the station is placed into service in the field. There is not an
additional requirement to conduct inspection and maintenance on portable regulator stations annually not
to exceed 15 months. Information pertaining to the inspection of the station shall be recorded on the
appropriate Regulator Station Inspection and Maintenance Record.
Portable CNG Trailer Maintenance
Portable CNG trailers shall receive the inspection and maintenance items listed under"Annual Regulator
Station Maintenance" once each calendar year not to exceed 15 months. Information pertaining to the
inspection of CNG trailers will be recorded on the appropriate Regulator Station/ Industrial Meter
Inspection and Maintenance Record form (N-2527). The Fleet Department is responsible for inspecting
and maintaining the CNG tanks, CNG tank valves, and all vehicle related items.
In addition to annual maintenance, CNG trailers should be inspected before each use to ensure the
regulators are set appropriately and that the trailer is functioning safely. A CNG Trailer Regulator
Inspection form (N-2711) should be filled out each time the trailer is placed into service. A single form
should be kept with each trailer, so all users of the trailer are filling out the same form. The Pressure
Controlmen responsible for performing annual maintenance on the trailer should replace the form
annually and keep the form in case the document is asked for during an audit.
Regulator Stations— Special Inspections
If there are indications of abnormally high or abnormally low pressures in a system, regulators and
applicable auxiliary equipment within the regulator station must be inspected and necessary measures
employed to correct the unsatisfactory operating condition.
MAINTENANCE REV. NO. 20
REGULATOR & RELIEF INSPECTION DATE 01/01/25
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utilities NATURAL GAS SPEC. 5.12

5 YEAR OVERHAUL— FLEXIBLE ELEMENT & BOOT TYPE REGULATORS AND RELIEF VALVES:
Maintenance Procedures
In addition to the annual station maintenance and portable regulator station maintenance, every 5 years
each flexible element or boot type regulator(to include portable regulator stations as applicable)shall
include the following internal inspection:
• Flexible elements or boots shall be visually checked for cracks, wear, etc., and replaced, as
necessary.
• Gaskets, O-rings, discs, seals, etc. should be replaced, as necessary.
The overhaul procedure may be performed in the field or in the shop. It may prove to be convenient to
have the regulator or relief device overhauled in the shop and have it ready so that it may simply be
exchanged in the field.
10 YEAR OVERHAUL— DIAPHRAGM TYPE REGULATORS, RELIEF VALVES & PILOTS:
Maintenance Procedures
In addition to the annual station maintenance and portable regulator station maintenance, every 10 years
each diaphragm type regulator and pilot(to include portable regulator stations as applicable)shall include
the following internal inspection:
• Diaphragms shall be visually checked for cracks, wear, etc., and replaced, as necessary.
• Orifices and seats shall be visually inspected for scoring, pitting or other damage and replaced, as
necessary.
• Pilot filters shall be replaced.
• The pilot valve and seat shall be inspected for wear and repaired per manufacturer's
recommendations.
• Gaskets, O-rings, discs, seals, etc. should be replaced, as necessary.
The overhaul procedure may be performed in the field or in the shop. It may prove to be convenient to
have the regulator or relief device overhauled in the shop and have it ready so that it may simply be
exchanged in the field.
Exclusion: Small diaphragm type regulators and relief valves used in farm tap regulator stations or meter
sets would not need to be overhauled unless the regulator or relief valve does not function properly during
the general station inspection or annual regulator station inspection. However, it may prove more
convenient to replace the regulator or relief valve rather than to perform the internal overhaul in the field.
GATE STATIONS:
Avista-owned facilities in gate stations shall be serviced under the same annual maintenance schedule as
district regulator stations. Maintenance procedures shall be the same for the station, pressure regulators,
and overpressure protective devices.
Field employees performing maintenance on gate stations shall be properly trained on such maintenance
and shall be familiar with the layout of the station, including the locations of all shutoff valves, feeds,
odorizers, charts, telemetry devices, etc. Consideration should be given to notifying Gas Supply and/or
the System Operator, as well as the transmission pipeline supplier when maintenance is to be performed
at gate stations.
MAINTENANCE REV. NO. 20
REGULATOR & RELIEF INSPECTION DATE 01/01/25
Xv sm a STANDARDS 9 OF 13
utilities NATURAL GAS SPEC. 5.12

Chart Recorders and Telemetry
When a mechanical chart recorder is used at a district regulator station, it should be inspected on a
monthly basis. The chart should be changed at this time and the pens should be checked and changed,
as necessary. The downstream operating pressure should also be checked with a calibrated pressure
gauge and cross checked against the chart reading. If any discrepancy is detected, the chart recorder
should be repaired or replaced. If a chart recorder is being utilized, it shall also be inspected during the
annual regulator station inspection and maintenance.
Inspections and calibrations on telemetry devices (i.e. transmitters) and electronic pressure recorders at
gate stations and multi-fed distribution systems shall be performed at regular intervals in accordance with
Specification 5.10 to verify high-and low-pressure alarms are functioning properly. This can be
accomplished by checking information relayed to the System Operator or Gas Supply with actual
pressures at the gate station or telemetry location. Problems with telemetry equipment shall be referred to
the appropriate department for repair as soon as they are detected. If the telemetry system is not
functioning properly, a pressure recorder should be set at the same location site to validate functionality
of the equipment or if the telemetry system is down for repair for an extended length of time. Refer to
Specification 2.25, Telemetry Design for additional information on the design and installation of telemetry
devices.
Company field personnel shall respond to all alarms generated by telemetry equipment that may indicate
a potential safety problem. If there are indications of abnormally high or low pressure, the regulator and
the auxiliary equipment must be inspected, and the necessary measures employed to correct any
unsatisfactory operating conditions.
MAINTENANCE FREQUENCIES:
Avista's gas distribution regulator stations and gate stations shall be inspected and maintained according
to the following schedule:
Station Type Interval
District Regulator Station Once each calendar year(Not to exceed 15 months)
Gate Stations Once each calendar year(Not to exceed 15 months)
Farm Taps (AC and General Inspection at Once every 3 years (Not to exceed 39 months)
minimum
Farm Taps (Upstream source fed from a Once every 3 years (Not to exceed 39 months)
transmission line
Portable CNG Trailers Once each calendar year(Not to exceed 15
months.)
Portable Regulator Stations Every time the station is placed into service.
Industrial Meter Sets Annually
Maintenance shall be based on the anniversary date established and required maintenance shall
be completed before expiration of the grace period.
On existing stations, the last date serviced establishes the anniversary date.
MAINTENANCE REV. NO. 20
REGULATOR & RELIEF INSPECTION DATE 01/01/25
XvIST'r STANDARDS 10 OF 13
utilities NATURAL GAS SPEC. 5.12

Recordkeeping
Maintenance performed on district regulator stations, gate stations, and farm taps shall be recorded on
the appropriate Regulator Station Inspection and Maintenance Record (form N-2527) (electronic or paper)
and retained for the life of the facility. Relief Capacity Review records shall be kept for a minimum of 5
years. When identifying regulators on the Inspection form, use the following identification sequence for
the various configurations shown:
� z
R
3 4
R R
1 2
LRR R
3 4
R
1 2
R R
3
R
R
1
R
3
R
I.
1 R'
R
2
R
3
R
MAINTENANCE REV. NO. 20
REGULATOR & RELIEF INSPECTION DATE 01/01/25
XvIST'r STANDARDS 11 OF 13
utilities NATURAL GAS SPEC. 5.12

PROCEDURE FOR REGULATOR STATION AND METER SET BYPASSING:
The following procedure should be adhered to when placing regulator stations and meter sets that have a
non-regulated, hard-piped bypass installed. Care shall be exercised during all phases of the bypass
operation in order to ensure that the system pressure is adequately maintained. Gas Supply, as well as
the applicable pipeline transportation company, shall be advised whenever a gate station is put on
bypass. (NOTE: The following procedures are applicable only to regulator stations with fixed bypasses.) If
utilizing this procedure for low pressure situations (cold weather actions), skip steps#5, #7, #8, and #12.
These steps are used to take the regulators out of service for maintenance purposes.
1. Make sure that necessary tools, parts, and safety equipment are available at the job site before
proceeding with the bypass procedure.
2. Take an accurate upstream pressure reading. It is not necessary to continuously monitor the
upstream pressure during the bypass operation.
3. Install an accurate pressure gauge on the downstream side of the station. Note the outlet
pressure. Leave this gauge in place during the entire bypassing operation.
4. Unlock all station valves. If required by design, install temporary soft bypass hose. Test valves by
partially operating them.
5. Crack open the station bypass valve. Close the downstream station valve, and then check the
downstream pressure. It may be necessary to also close the sensing line valve to achieve lockup,
depending on station design. Modulate the bypass valve as required to maintain system
pressure. Use caution not to open the bypass valve too much as you may run the risk of
overpressuring the system.
6. Close the upstream station valve to complete the isolation of the regulator(s). The station is now
on bypass.
7. Continue to note the downstream pressure readings. Adjust bypass valve to maintain but not
exceed downstream system pressure.
8. Blow down isolated section to atmosphere and perform station maintenance as required.
9. To put regulator(s) back into operation, start by opening the upstream station valve slowly until it
fully pressurizes the regulator and loads the pilot (if applicable). Regulator adjustment screw
should be backed off before placing regulator back into operation to avoid possible
overpressuring of downstream prior to final pressure adjustments.
10. Open the downstream valve slowly.
11. If applicable, open the control line slowly. The regulator should now begin to control pressure.
12. Close the bypass valve. The station is now off bypass. Remove temporary soft bypass if one was
used. Cap and plug all appropriate valves and fittings.
13. Adjust the regulator(s)to the proper set point(s)while observing the downstream pressure gauge.
Allow sufficient time for pressures to equalize while making adjustments. Tighten locking nuts in
place when done.
14. Check all valves used during operation for leakage. Adjust or lubricate, as necessary. Double
check the positions of all valves and locks are in place.
MAINTENANCE REV. NO. 20
REGULATOR & RELIEF INSPECTION DATE 01/01/25
XvIST'r STANDARDS 12 OF 13
utilities NATURAL GAS SPEC. 5.12

PROCEDURE FOR TESTING RELIEF VALVES WITH NITROGEN OR BOTTLED CNG:
This procedure is suggested for use in testing the performance of relief valves in the field. It is recognized
that this procedure will not be applicable in all cases due to difference in relief and regulator design. The
following procedure does, however, provide for pressurization and testing of certain relief valves without
the possibility of overpressuring the downstream pipe.
1. Install an accurate pressure gauge on the downstream side of the station to monitor system
pressure while the relief is shut down.
2. Temporarily isolate the relief from the system by unlocking and closing the manual relief isolation
valve.
3. Proceed with the testing and pressure setting of the relief, as found. Should it be necessary to
perform maintenance on the relief valve de-pressurize the relief valve and piping prior to proceeding
with the necessary repair.
4. Install a field fabricated device into a port that will pressurize the appropriate section of the relief
valve. The device should consist of a pressure gauge of range appropriate to the relief setting, a
section of pipe nipple that will allow it to be screwed into the body of the relief, and a valve rated for
the pressure being used. It is also convenient to install a quick connect fitting on one end so as to
facilitate easy connection.
5. Make sure that the control valve on the device is in the "off' position. Connect the device with a hose
(rated for the appropriate pressures)to a supply tank of nitrogen. The supply tank should have its
regulator set at a pressure that will allow the relief to be tested fully.
6. Slowly turn on the valve on the supply tank until the hose is pressurized.
7. Slowly open the control valve on the device to begin pressurizing the relief. Observe the pressure
gauge while gradually increasing pressure with the control valve (throttling). Note the pressure at
which the relief opens and make adjustments, as necessary. Repeat the pressurization process
several times to eliminate the possibility of the relief sticking.
8. Adjust the relief set point as specified by Gas Engineering on the appropriate records.
9. When the proper setting is achieved, turn off the supply valve on the nitrogen bottle and the control
valve on the device. Disconnect the hose and de-pressurize the relief.
10. Remove the relief testing device from the relief and re-install the fitting or plug removed to install the
device.
11. Open the manual relief isolation valve to put the relief back in service.
12. Lock valve in open position.
In some instances, such as in the case of smaller sized relief valves, the relief valve may temporarily be
removed from the station and "bench tested" on the service vehicle using bottled nitrogen. The field
employee performing such testing should exercise good judgment in the test methods and equipment
used.
MAINTENANCE REV. NO. 20
REGULATOR & RELIEF INSPECTION DATE 01/01/25
Xv sm a STANDARDS 13 OF 13
utilities NATURAL GAS SPEC. 5.12

5.13 VALVE MAINTENANCE
SCOPE:
To establish an inspection and maintenance program for Avista's gas distribution and transmission
pipeline valves.
REGULATORY REQUIREMENTS:
§192.145, §192.179, §192.181, §192.363, §192.365, §192.745, §192.747
WAC 480-93-018, 480-93-100
CORRESPONDING STANDARDS:
Spec. 2.14, Valve Design
Spec. 3.32, Repair of Steel Pipe
General
The information and procedures contained in this section shall constitute the valve maintenance program
for Avista. Only personnel trained and qualified in maintenance of various valve types and designs shall
perform maintenance on Company valves. Included in this section are procedures for proper valve
maintenance, basic installation and operating requirements, valve maintenance categories and
frequencies, and recordkeeping. The individuals performing valve maintenance will notify Gas Control of
the area they will be performing maintenance for the day. If part way through the day the work moves to a
different area, update Gas Control. When finished, or at the end of the day, notify Gas Control that the
crew has completed valve maintenance work for the day.
VALVE TYPES:
Steel Plug Valves
Many of the existing steel valves used in Avista's systems are of the Rockwell-Nordstrom plug valve
design. The basic design of the Nordstrom valve consists of a body, plug, cover, resilient adjustment
member, and the sealant.
The function of each component part is detailed below:
The Body- Its purpose is to connect the valve to the pipeline and mate with the plug to form a pressure
vessel capable of operation under various pressures depending on the end connections and the cover
design.
The Plug -The plug is the only moving part. It has a tapered surface designed to mate with the body to
provide a tight seal between the body and plug. The plug has a machined port through which gas flows
when the valve is in the open position.
The Cover-The cover retains the resilient adjustment member and prevents external leakage.
The Resilient Adjustment Member-This consists of a diaphragm to allow plug movement without
leakage, a self-energizing packing ring to maintain force against the plug and a gland to set tension
against the resilient packing. The resilient adjustment member varies according to design. For instance, in
the Rockwell Hyperseal valve (with an inverted plug), it is a spring disc or bottom cover.
MAINTENANCE REV. NO. 19
VALVE MAINTENANCE DATE 01/01/25
XvIST'r STANDARDS 1 OF 7
utilities NATURAL GAS SPEC. 5.13

The Sealant-The sealant functions as a seal against leakage and also hydraulically lifts the plug from its
seat in the body to provide ease of operation and to prevent sticking. The lubricated plug valve operates
on a closed hydraulic system, utilizing the hydraulic force of the lubricant to lift the plug from its locking
taper seat for operation. The resilient member reseats the plug to prevent leakage.
Nordstrom plug valves will normally require 1/4 turn to close or open the valve. Valves are turned
CLOCKWISE to CLOSE and are turned COUNTERCLOCKWISE to OPEN. Standard Rockwell-
Nordstrom valves turn clockwise to close, unless otherwise specified. Plug valves designed by other
manufacturers will normally have the same design features as the Rockwell-Nordstrom type valves;
however, manufacturer's instructions and specifications should be consulted before installing or
maintaining such valves.
Steel Gate Valves
Gate valves are steel valves designed so that a threaded stem with a steel gate or conical end screws
down and seats in a receptacle so as to shut off the flow of gas. Shut-off is achieved without use of a
lubricating sealant. Valve design enables the gate or conical end to seal with either elastomers or metal-
to-metal contact. Valve stem seals are maintained by use of elastomer"O" rings. Gate valves require
multiple turns to open or close the valve. Valves are turned CLOCKWISE to CLOSE and are turned
COUNTERCLOCKWISE to OPEN.
Steel Ball Valves
Steel ball valves are designed so that a ball inserted in the valve has a cylindrical bore in it through which
gas flows when the valve is in the open position. When the valve is operated, the ball rotates, and the
flow is stopped due to the bore being perpendicular to the flow. Ball valves require 1/4 turn to open or
close the valve. Valves are turned CLOCKWISE to CLOSE and are turned COUNTERCLOCKWISE to
OPEN. Leakage is controlled through the use of nylon or Teflon seals around the ball and O-ring seals
around the operating stem.
Gear Valves
The term "gear valve" normally applies to a larger plug or ball valve that uses a worm gear and other
reduction gears for operation. The gear system may either be exposed or concealed depending on the
particular valve design and application. Each type and size of gear valve will take a varying number of
turns on the operating handle to open or close the valve.
Polyethylene Valves
Valves constructed of polyethylene plastic are available and used in plastic distribution systems. These
valves are either of the ball or plug design. These valves will require 1/4 turn to open or close the valve.
Valves are turned CLOCKWISE to CLOSE and are turned COUNTERCLOCKWISE to OPEN. Less
torque is required to open and close these valves. Due to their plastic design, these valves can be easily
over-torqued, and valve stops damaged. Particular care needs to be taken when operating and the use of
a cheater bar is prohibited.
Valve Turns
The table below lists the approximate number of turns for each valve type. (The information is meant to
be for reference only and should be verified as applicable.)
MAINTENANCE REV. NO. 19
VALVE MAINTENANCE DATE 01/01/25
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utilities NATURAL GAS SPEC. 5.13

Size (in) # of Turns I Notes
Plug Valve—Spur Gear Reduction
6 1-9/16
8 1-9/16
10 2 3 Rockwell/Nordstrom part number
12 3-/16 ending in 7.
16 4-'/2
20 7-9/16
24 9-'/4
Plug Valve—Worm Gear Reduction
6 12-'/2, 15 Rockwell/Nordstrom part number
8 12-'/2, 15, 17 ending in 9. There are several
10 16, 17, 22 models available depending on class
12 19-'/2, 22, 62-'/2 rating, etc.
Plug Valve— Non-geared
2-6 '/4 Turn
Gate Valve— Kerotest
2 7-'/4
3 10
4 13-'/4
6 19-3/4
8 26-'/4
10 21-3/4
12 25-3/4
Mueller Inline Curb Valve and Tee
1 7-'/4
1 '/4 8-'/4
2 10-3/4
Mueller Curb Valve Tee w/Autosafe PHUSE EFV
1 =4-3/4
Polyethylene Ball Valve
All Sizes '/4 Turn Minimal Torque Required
MAINTENANCE REQUIREMENTS FOR VALVE TYPES:
Steel Plug Valves
These valves require a periodic injection of sealant to provide enough pressure in the valve to provide
positive shut-off. Plug valves shall be turned and should be lubricated, as needed at the time of their
scheduled maintenance. Other valve adjustments should be performed as necessary by trained field
personnel. Refer to the "Plug Valve Lubrication Procedures" for detailed lubricating instructions.
Lubrication risers may be installed on plug valves as needed. Half-inch schedule 80 pipe should be used
to bring the lubrication fitting close to the surface. The riser should be packed with fresh lubricant before
installation. Field personnel qualified to operate valves shall have a hollow valve key to allow operation of
valves with risers installed. Local construction offices are encouraged to standardize valve key sizes.
Extreme care should be exercised when installing risers, installing, or replacing lubrication fittings, and
when lubricating valves so that foreign debris does not get inside the valve or its lubricant. The
introduction of any foreign material in the valve may plug the lubrication ports and channels, and may
result in leakage, binding, or scoring of the plug.
MAINTENANCE REV. NO. 19
VALVE MAINTENANCE DATE 01/01/25
X IVIST'aa STANDARDS 3 OF 7
Utilities NATURAL GAS SPEC. 5.13

Steel Gate Valves
Gate valves shall be checked for leakage and ease of operation on an as needed basis (annually if they
are Emergency valves). They do not require field lubrication as 0-ring seals control leakage. After it is
verified that the valve turns acceptably, field personnel should open the valve fully to seat the stem
against the O-ring seal. If the valve leaks, the valve should be scheduled for replacement or overhaul.
Steel Ball Valves
Modern ball valves normally do not require any maintenance other than verifying they turn properly and
are not leaking.
Some ball valves (new or old) are fitted with external grease fittings to be used if the valve fails to give
tight shut-off. These ball valves should NOT be greased unless they fail to seal tightly. If greasing is
required to obtain shut-off, the valve may need to be greased as part of its normal maintenance. Use a
valve lubricant that is specified by the ball valve manufacturer.
Ball valves that are designated Emergency valves shall be turned and inspected on an annual basis.
Other ball valves shall be inspected on an as needed basis. Ball valves that are leaking or that do not turn
properly should be greased (if possible), repaired, or replaced.
Steel Gear Valves
Gear valves that are of the Nordstrom plug design shall also be injected with sealant to provide ease of
operation and positive shut-off. Gear operated ball valves shall be maintained as mentioned above when
they fail to turn properly. The worm gear and other gearing mechanisms shall also be lubricated and
adjusted to achieve acceptable operation. Emergency gear valves shall be lubricated and adjusted on an
annual basis. All other gear valves shall be lubricated and adjusted on an as needed basis if they are
found leaking or hard to turn. Enclosed gear valves should be packed with an appropriate grease to
prevent water accumulation and corrosion.
Polyethylene Valves
Plug and ball valves constructed of polyethylene normally do not require any maintenance other than
verifying that they turn properly and that they are not leaking. Polyethylene valves that are designated
Emergency valves shall be turned and inspected on an annual basis. Other polyethylene valves shall be
inspected on an as needed basis. Polyethylene valves that are leaking or that do not turn properly should
be replaced.
GENERAL VALVE MAINTENANCE AND INSTALLATION NOTES:
General
Prompt remedial action shall be taken to correct any emergency valve that is found inoperable, unless an
alternative valve has been designated as a replacement. As part of the maintenance activity,
documentation regarding the valve shall be verified, including valve number, mapping, status (open or
closed), and valve attributes if known.
For the purpose of maintenance, a valve shall be considered operable if the valve can be "broken loose"
from its normal operating position and turned slightly. It is recommended to close a valve at least 25
percent of the way to test its operation. It is acceptable to operate valves up to 100 percent where
practical and there is a reduced risk of outage. The direction of the pipeline and the position of the valve
should be verified by utilizing the valve stops and the position indicator on the valve itself. If this cannot be
MAINTENANCE REV. NO. 19
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utilities NATURAL GAS SPEC. 5.13

verified, notify the local gas manager to discuss next steps before attempting to perform maintenance.
Mark your starting point so that there is an indication of where to reposition the valve after turning. This
may be accomplished using temporary marking such as white paint if weather conditions allow. Ensure
that the valve is being turned in the proper direction.
For normally closed valves separating two distinct pressure zones, it is recommended that these valves
be evaluated and considered for removal. If removal is not practical, it is recommended during
maintenance that these valves be serviced, cleaned, and lubricated as necessary, but do not operate
the valve. To"crack" a valve (turn the stem must enough to move it off the stops) is not considered
operating. Operating these valves could result in an uncontrolled overpressure condition on the
downstream system. If the valves must be operated, system pressures downstream of these valves must
be monitored closely and significant care taken not to overpressure the downstream system.
Use care when operating valves. A single serviceperson should be capable of operating any valve during
an emergency. If operation of the valve requires more force than a reasonable person can apply, the
valve should be considered for maintenance or replacement. Hard to turn plug valves should be
lubricated if possible before attempting to turn them again. For hard to turn valves, the use of a valve
flush may help in freeing up the valve. For hard to operate steel valves, if alternative methods of
lubrication are not possible or successful, it is acceptable to apply a lubricant or a penetrating oil (external
use only)to aid in the operation of the valve.
Forcing valves could result in damage to worm gearing, shearing of the stem, cracked or distorted bodies,
broken locking devices, etc. Use the proper wrench for the valve being worked on. Damaged or
compromised valves shall be replaced.
Pipe alignment and support is particularly critical in large above ground valve installations. During valve
maintenance on above ground valves, care should be taken to ensure necessary supports are in place.
Maintaining Valve Boxes
Valves boxes should be thoroughly cleaned out when servicing valves to prevent corrosion and for ease
of operation. If a valve box regularly fills with sediment or debris, consideration should be given to moving
the valve. Lids should be easily removable and should be identified by painting the outside of the lid
yellow.
To allow for quick field verification of emergency and secondary valves, a short section of small diameter
polyethylene pipe, or something similar made of a non-corrodible material, should be placed in the valve
box with the valve number either written in permanent marker or tagged to it.
Valve Disable/ Abandonment
When it is determined that a valve will no longer be used in the gas distribution system, it shall be either
disabled or abandoned. Disabled Valve: A valve that has gas flowing through it but is no longer operable.
Valves can be disabled in the following ways:
1. Made inoperable by canning/barreling or capping
2. Is inaccessible (i.e., under pavement)
Abandoned Valve: A valve that has been physically removed or disconnected from the piping system
such that gas will no longer flow through it. If the valve is to be disabled, the valve is identified as
"Disabled" on the maintenance record and on Company maps. Valve maintenance is no longer performed
on the valve, but the past maintenance records should be kept until the valve is abandoned (removed)
from the system.
MAINTENANCE REV. NO. 19
VALVE MAINTENANCE DATE 01/01/25
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utilities NATURAL GAS SPEC. 5.13

Maintenance
Avista gas distribution and transmission valves, based on the criteria established in Specification 2.14,
Valve Design, shall be maintained to make operable and serviced according to the following schedule:
CategoryValve
Emergency Distribution &Transmission
Valves (Valves as specified in §192.179 and Once each calendar year, not
§192.181)that are necessary for Emergency to exceed 15 months
Operations
Emergency Curb Valves (Inaccessible meter Once each calendar year, not
sets, churches, schools, hospitals,jails, to exceed 15 months
convalescent homes, etc.)
Regulator Station Isolation Valve(s) (isolation Once each calendar year, not
valves as specified by§192.181(b)) to exceed 15 months
Every five years not to exceed
Secondary Valves 63 months (This is a Best
Practice but not a requirement)
WAC 480-93-100 (2): In the state of Washington, Emergency Curb Valves newly installed or pre-
existing that meet the criteria identified in Specification 2.14, Valve Design, "Emergency Curb Valves,"
shall be maintained once each calendar year, not to exceed 15 months.
As part of the initial installation of a valve, the valve will be viewed as receiving the required maintenance.
During road projects, both Emergency and Secondary valves should be maintained during the process of
the temporary lowering of the elevation of the valve box. Ensure the maintenance activity is appropriately
documented to avoid duplication of the maintenance effort at a later date.
A compliance date shall be assigned to all newly installed emergency valves. Subsequent maintenance
shall be based on the date established and required maintenance shall be completed before expiration of
the grace period (as long as the grace period is within the calendar year).
Above ground gas carrying portions of valves shall receive an atmospheric corrosion (AC) inspection and
applicable AC maintenance as required by§192.479 and §192.481 during required valve maintenance
actions.
Secondary Valves Maintenance
As a best practice, approximately 20 percent of the secondary valves in Idaho, Oregon, and Washington
should be maintained to ensure operability each calendar year. Secondary valves within the entire gas
system should be maintained in a 5-year period, not to exceed 63 months.
Recordkeeping
Valve maintenance information shall be recorded on the appropriate valve inspection and maintenance
record. These forms become a permanent record of valve maintenance performed and shall be retained
for the life of the facility. Records may be electronic or paper format and shall be available to the local
Construction Office.
Emergency Valves and Emergency Curb Valves should be identified on the card or electronic record.
MAINTENANCE REV. NO. 19
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PLUG VALVE LUBRICATION PROCEDURES:
Consult manufacturer's installation and maintenance instructions before performing valve lubrication or
maintenance. Manufacturer's instructions will normally have detailed procedures for troubleshooting,
maintaining, and repairing a specific valve. Contact Gas Engineering for assistance in locating manuals
when required.
There are normally two methods used to lubricate the plug valves. Lubricant sticks may be manually
injected into the valve, or a pressure gun (Rockwell 400C, VAL-TEX, or similar) may be employed to
inject lubricant into the valve under pressure.
Most buried valves will require the use of the handgun as it simplifies the lubrication procedure.
Manual Injection
To inject lubricant(sealant) manually:
1. Assure valve is in the full open or full closed position.
2. Remove the Rockwell lubrication fitting or lubricant screw.
3. Insert the appropriate sealant from the tube or choose the correct size stick and place it into the stem.
4. Replace the fitting and screw it down with a wrench until the sealant system is filled completely. This
is determined by the resistance produced by the sealant pressure. Larger valves will require several
sticks or tubes of sealant.
5. Add sealant and screw down the fitting until sealant back pressure builds up, making the fitting hard
to turn. Then continue to add sealant until the plug lifts (sometimes with a hissing sound) and relieves
itself indicating that the system is full. Stop adding sealant and operate the valve. If the plug does not
turn easily, add sealant until it is free or consult the manufacturer's instructions.
Sealant Gun
To inject sealant with the Rockwell 400C, VAL-TEX, or similar sealant gun:
1. Assure valve is in the full open or full closed position.
2. Insert proper lubricant/sealant into the gun. Check that there is sufficient hydraulic fluid in the gun
reservoir. (Refer to manufacturer's instructions for procedures).
3. Fit the gun's button head coupler over the lubrication fitting on the valve. Start the coupler onto the
fitting until the fitting head stops at the check valve (approx. halfway).
4. Lift up gently on the back end of the coupler and pull the coupler onto the fitting with a gentle sliding
movement.
5. Inject sealant by pumping the gun as long as the needle on the pressure gauge climbs steadily. At
some high pressure point on the gauge, the needle will drop back when the plug un-seats indicating a
fully pressurized system. This point can also be felt when the pumping effort falls off. Additional
pumping will not hold the gauge needle and injecting should be stopped at this point. The plug should
then be turned to check the ease of operation. Additional sealant can then be injected, if needed.
6. If the valve will not hold internal pressure and the needle on the gun's gauge falls to line pressure
after each stroke, consult the valve instruction manual. If the needle on the gauge pumps up into the
red zone, then bypasses, there may be a restriction in the valve, or the gun may need repair. The
manufacturer's instruction manual should be consulted in trouble shooting valve or gun problems.
7. Put a dab of sealant on the top portion of the Rockwell fitting to prevent corrosion after the lubrication
procedure is completed.
SERVICE VALVE LUBRICATION PROCEDURES:
Consult manufacturer's installation and maintenance instructions before performing service valve
lubrication or maintenance.
MAINTENANCE REV. NO. 19
VALVE MAINTENANCE DATE 01/01/25
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utilities NATURAL GAS SPEC. 5.13

5.14 CATHODIC PROTECTION MAINTENANCE
SCOPE:
To establish uniform procedures for the monitoring of metallic pipelines for external and internal corrosion.
REGULATORY REQUIREMENTS:
§192.451, §192.465, §192.473, §192.491, §192 Appendix D
WAC 480-93-110, 480-93-115, 480-93-188(3)(d)
CORRESPONDING STANDARDS:
Spec. 2.12, Pipe Design —Steel
Spec. 2.22, Meter Design
Spec. 2.32, Cathodic Protection Design
Spec. 3.42, Casing and Conduit Installation
Spec. 3.12, Pipe Installation - Steel
Spec. 3.32, Repair for Steel Pipe
Spec. 3.44, Exposed Pipe Evaluation
Spec. 5.11, Leak Survey
CATHODIC PROTECTION MONITORING
General
Cathodic protection (CP) monitoring and repair shall only be performed by properly trained and qualified
personnel. As a minimum qualification, Cathodic Protection Technicians will be NACE Level 1 Certified, or
in the process of working to obtain this certification and working under the direction of a NACE Level 2 or
greater Certified Technician, or a Cathodic Protection Specialist. Special conditions in which CP is
ineffective or only partially effective sometimes exist. Deviation from this specification might be warranted
in specific situations provided that corrosion control personnel in responsible charge demonstrate that the
objectives of reference standards are being achieved.
Cathodic Protection Criteria
External corrosion control of steel pipelines can be achieved at various levels of cathodic polarization
depending on the environmental conditions. However, in order to demonstrate that adequate cathodic
protection (CP) has been achieved, one or more of the following shall apply:
1. A negative (cathodic)voltage potential of at least 850 mV (-0.850 mV)with the CP applied. The
potential is measured with respect to a saturated copper/copper sulfate reference electrode
contacting the electrolyte. Voltage drops (IR drops)other than those across the structure-to-
electrolyte boundary must be considered for valid interpretation of this voltage measurement.
2. A minimum negative polarized potential of at least 850 mV relative to a saturated copper/copper
sulfate reference electrode.
3. A minimum of 100 mV of cathodic polarization between the structure surface and a stable
reference electrode contacting the electrolyte. The formation or decay of polarization can be
measured to satisfy this criterion.
Monitoring Cathodic Protection Areas
Each cathodic protection area or system must be tested at least once each calendar year, but with
intervals not exceeding 15 months to determine if the requirements are met. Each system shall maintain a
level of cathodic protection as to not cause damage to the coating system or pipeline.
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The level of protection should not exceed -1.200 VDC "Instant Off Potential" in reference to a CSE
(CuCuSO4) reference electrode. Each system or area must have sufficient enough test stations/locations
to determine that the overall system or area has adequate levels of cathodic protection.
Monitoring Isolated Main Less than 100ft or Service Lines
For separately protected short sections of pipe not in excess of 100 feet or separately protected service
lines, risers, and isolated steel valves within PE service areas these isolated sections of steel may be
surveyed on a sample basis. At least 10 percent of these protected structures, distributed over the entire
system, must be surveyed, or replaced each calendar year, with a different 10 percent checked each
subsequent year, so the entire system is tested in a 10-year period.
MONITORING RECTIFIERS
General
Before performing rectifier maintenance, the Cathodic Protection Technician must first verify that no
electric shock hazard exists, (such as"touch potential hazard"), by utilizing a multi-meter or inductive AC
gauge to measure AC activity on the rectifier case.
Bi-monthly Rectifier Monitoring
Each CP rectifier or impressed current power supply must be inspected six times each calendar year, but
with intervals not exceeding 2-1/2 months to ensure it is operating as required. The following data is
required during a bi-monthly inspection:
1. Tap Settings*
2. Voltage Read
3. Amp Read
4. Name of CP Technician
5. Date
*The tap settings are not required for rectifiers with remote monitoring systems.
At least once per year, each CP rectifier or impressed current power supply must be visually inspected for
physical damage or deficiencies, such as rectifier damage, blown fuses, wire deterioration, and missing
red color coding on anode wires.
Voltage Reads:
Unless relayed by a remote monitoring system, the voltage at the rectifier shall be taken by using an Avista
approved multi-meter by the following method. Connect the common or(-) lead of the multimeter to the
structure or(-)output lug of the rectifier. Connect the volt or(+) lead of the multimeter to the anode or(+)
output lug of the rectifier. Select the DC volts on the multimeter and record the volt reading as shown on
the meter.
Amp Reads:
Unless relayed by a remote monitoring system, the current output of the rectifier shall be determined by
utilizing the shunt located on the inside of the front panel and calculated using one of the two following
methods:
1. Ohm's Law:
Find the rating of the shunt, (i.e., 15-amp, 50 mV). Using the multi-meter, take, and record the mV read
across the shunt terminals. Using Ohm's Law, calculate the current output.
Ohm's Law: V= IR or 1=R
Where: V(volts)= mV X 0.001; 1 =amps; R=ohms =V/1=volts/amps
Example: Shunt rating of 15 amps, 50 mV with a measured voltage drop across the shunt of 35 mV
(convert millivolts to volts by multiplying millivolts by 0.001).
A. R= (50mV X 0.001)/15amps= 0.00333 ohms
B. V= 35mV X 0.001 = 0.035 V
C. I =V/R= 0.035V/.00333 (ohms) = I(currentout) 10.51 Amps
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2. Calibration Factor:
This is Ohm's Law stated in another way. Using the rating of the shunt, determine the "calibration factor"
by dividing the amps by the mV. Multiple the voltage reading measured across the shunt in millivolts by
this calibration factor to determine the current output of the rectifier.
Example: Using the same information from the example above:
Calibration Factor= Shunt Rating = amps/mV= 15/50 = 0.3 (in this example)
Current Output= 1 = 0.3 X 35 = 10.5 amps
Detecting Stray Current
Cathodic Interference: When a voltage gradient overlaps a foreign structure and is negative with respect to
remote earth, it promotes current discharge from the foreign structure in the area of influence.
Anodic Interference: If a foreign structure crosses a voltage gradient that is positive with respect to the
remote earth. It promotes current pick-up within the area of influence and current discharge outside the
area of influence. Current span testing is a method that can be used to test for stray current. Interference
problems are individual in nature, resolving interference problems can be mitigated utilizing one of the
following methods:
• Removal of detrimental effects of interfering current by installing a metallic path.
• Counteracting the effect by applying cathodic current
• Removal of the interfering current source
• Coating or shielding at current pick-up points
• Resistance bond with foreign cathodic structure
For transmission systems, §192.473 outlines the steps that must be followed when interference current is
discovered on a system, or it is expected to occur due to the construction of nearby structures that could
cause stray current on the gas facility. An interference survey must be completed, and remediation must
be completed within 15 months of the completion of the survey, but not to exceed 6 months after obtaining
necessary permits.
Monitoring Critical Bonds and Diodes
Each reverse current switch, each diode, and each interference bond whose failure would jeopardize
Avista's cathodic protection system must be checked at least six times each calendar year, but with
intervals not exceeding 2-1/2 months. Other interference bonds or diodes that are considered non-critical
must be checked at least once each calendar year not to exceed 15 months.
Monitoring Steel in Steel Casings
Underground steel casing installations with steel carrier pipe shall be tested at least once each calendar
year, not to exceed 15 months, to determine that the casing is electrically insulated from the carrier pipe
and the carrier pipe is cathodically protected. Potential measurements will be made with the reference
electrode in a single location as determined by the Cathodic Protection Technician. Refer to the Pipe-to-
Soil Procedures at the end of this specification.
A shorted casing may exist if a potential difference of less than 10 mV exists between the casing and the
carrier pipe. CP current sources must be off when taking the potential read. If all sources cannot be turned
off, any potential within 100mV between casing and pipe will require additional testing.
New casings require test leads connected to the pipe and casing per Specification 3.12, "Test Leads". Any
existing casing without test leads will be retrofitted with test leads unless installation is infeasible.
If there are no tests leads or close contact points, one of the procedures outlined at the end of this
specification should be utilized to determine if the casing is shorted.
MAINTENANCE REV. NO. 22
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CATHODIC PROTECTION MAINTENANCE:
Facilities Under Restoration of Cathodic Protection
When facilities under cathodic protection are found with pipe-to-soil (P/S) potentials below adequate levels,
the facilities must be scheduled for restoration. Areas shall be restored within 90 days from the date they
are found below adequate levels of protection on all transmission pipelines and also on distribution
pipelines in Washington and should be restored within 90 days on distribution pipelines in Idaho and
Oregon as a best management practice. An additional 30 days may be allowed in all states for remedial
action if there are circumstances beyond Avista's control. Remedial action must have started in a timely
manner with an effort to complete remedial within the 90-day timeframe. Examples of extenuating
circumstances are permitting issues, the availability of repair materials, and unusually long
investigation/repair requirements.
For transmission systems, §192.465 outlines the steps that must be followed when cathodic deficiencies
are noted. To address systemic causes, a close interval survey must be conducted on the pipeline to
determine the extent of the system deficiency.
WAC 480-93-110(2): Each gas pipeline company must complete remedial action within ninety days to
correct any cathodic protection deficiencies known and indicated by any test, survey, or inspection. An
additional thirty days may be allowed for remedial action if due to circumstances beyond the gas
pipeline company's control the company cannot complete remedial action within ninety days. Each
gas pipeline company must be able to provide documentation to the commission indicating that
remedial action was started in a timely manner and that all efforts were made to complete remedial
action within ninety days.
Shorted Casings
If testing indicates that there is a possible shorted casing, the following actions, or equivalent actions,
developed by Gas Engineering should be employed:
• Clear the metallic contact, if possible, through a construction method that will resolve the problem.
• If metallic contact is not cleared immediately, schedule the possible shorted condition for a follow-up
inspection within 90 days to confirm the short still exists. (Note: this is accomplished immediately
following discovery of a potentially shorted casing by the Cathodic Technician by performing a battery
test, a diode test, or a casing isolation tester analysis. Documenting the completion of this follow-up
inspection should be accomplished on an applicable Cathodic Protection Workorder.)
• Leak survey within 90 days of confirmed shorted condition. Coordinate survey locally with a Gas
Serviceman or contact the Leak Survey Program Administrator to schedule a special survey.
• Fill the annular space with a high dielectric casing filler or other material, which provides a corrosion-
inhibiting environment.
• If the above options are impractical and the risk of corrosion is minimized by conditions including the
location, pipe condition, risk of overpressure, and safety considerations, the casing can be monitored
by leak survey. Report the casing location to Gas Programs and the Leak Survey Program
Administrator(#[e-mail])to document and track. A leak survey must be
performed on an ongoing basis at least twice annually but not to exceed 7-1/2 months between leak
surveys with leak detection equipment until either of the above options becomes practical or conditions
change which render this option inadequate to minimize the risk of corrosion. See Spec 5.11 for
additional information on leak survey of shorted casings.
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Electrical Shorts
Electrical shorts affecting a cathodic protection system (i.e., non-insulated meter set, crossed insulator,
etc.) shall be located, and repaired, as necessary. Whenever exposed, underground Dresser-style or other
steel mechanical compression fittings shall be cut out or canned (barreled). A Cathodic Protection
Technician shall be contacted to verify that the fitting is not being used as an isolation point. Cutting out or
barreling may inadvertently create a problem between two separated cathodic protection systems so
additional steps may be necessary before removing or barreling the fitting.
Isolated Steel
When isolated sections of steel piping (including isolated steel services/risers) are found, they shall be
cathodically protected within 90 days from the date they are found barring extenuating circumstances.
These sections must then be reported to the respective Compliance Technician, the Cathodic Protection
Foreman, and to the Gas Isolated Steel Project Manager as applicable to be monitored and evaluated for
further action.
WAC 480-93-188(3)(d): In the state of Washington, isolated sections of steel pipe that are not
cathodically protected within 90 days from being found must be leak surveyed twice each calendar
year, not exceeding 7-1/2 months until properly protected.
Isolated Steel Risers
Isolated steel risers shall be replaced with new anodeless steel risers or protected with the appropriate
size and type of anode as specified by the Cathodic Protection Technician. If an anode is utilized, it shall
be placed on the isolated service monitoring list and replaced within 1 year of discovery.
Isolated Steel Services
Isolated steel services shall be replaced from the main to the meter and a new anodeless riser shall be
installed or at the discretion of a Cathodic Protection Technician, a 17-lb anode may be installed and
connected to the service as a temporary repair to reestablish adequate cathodic protection on the service
pipe. Dresser fittings found on isolated steel services shall not be bonded across or barreled. Neither shall
they be removed and replaced with steel pipe or fittings. If a Dresser fitting is found on the isolated service,
and the service pipe upstream or downstream of the dresser does not have a good cathodic protection
read, a 17-lb anode may be installed to reestablish adequate cathodic protection on the entire service pipe
as a temporary repair.
If an anode is installed on an isolated service, it shall have a means for taking cathodic reads on the
service pipe, be added to the 10% Isolated Steel Master List, and be prioritized for full-service replacement
in the future. If an anode is not installed, the entire steel service shall be replaced with new pipe. Refer to
Specification 2.32, Cathodic Protection Design, "Replacing Steel Services"for guidance on converting
steel services to PE services.
Examining Buried Steel Pipe and Coating
Whenever a buried steel pipeline is exposed, it must be examined for evidence of external corrosion and
coating deterioration. Refer to Specification 3.44, Exposed Pipe Evaluation.
Repair and Wrapping of Pipe
If external corrosion is found, replacement must be made to the extent required. Refer to Specification
3.32, Repair for Steel Pipe, or consult Gas Engineering for proper repair of corroded pipe. Pipe exposed
for examination and/or repair must be cleaned and recoated. Refer to Specification 3.12, Pipe Installation
—Steel Mains, for requirements on coating pipe.
MAINTENANCE REV. NO. 22
CATHODIC PROTECTION MAINTENANCE DATE 01/01/25
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INTERNAL CORROSION CONTROL:
Examining Internal Pipe
When steel pipe is removed from a pipeline for any reason, the internal surface must be inspected for
evidence of corrosion (rust or pitting)and if the inside wall is clean, dirty, or oily, and if there are puddles of
water or oil, or black smudge in the pipe.
If pitting is found, it shall be measured with a pit gauge and the depth and width of the pitting shall be
noted in the appropriate section of the Exposed Piping Inspection Report form. Refer to Specification 3.44,
Exposed Pipe Evaluation. If internal corrosion is found:
• When internal corrosion is found and it extends beyond what is exposed, the adjacent internal pipe
must also be exposed and investigated to determine the extent to which internal corrosion exists.
• Replacement must be made to the extent required. Refer to Specification 3.32, Repair for Steel Pipe,
or consult Gas Engineering for proper repair of corroded pipe.
• Steps must be taken to minimize the cause of the internal corrosion such as use of a corrosion
inhibitor.
• Notify Gas Engineering of the location and extent of internal corrosion and send a pipe sample to the
Gas Materials Engineer(MSC-6).
Corrosion cells formed on the internal surfaces of pipelines are confined to the internal metal surface and
electrolyte and function completely independent from external cells. Scale formations, such as calcium and
magnesium carbonates and adherent corrosion products on metal surfaces are important in the internal
corrosion process. The beneficial effects of the scale and oxide, which act as protective coatings, are
dependent upon their formation, thickness, grain structure, and adherence.
Cavitation and impingement are common forms of corrosion in fluid systems in and near pumps. The
hammer-like effect of collapsing entrained gas or air bubbles breaks through protective films or oxides.
Turbulent flow created by constrictions or by rapid changes in direction of flow and excessive velocities
also removes the protective films formed. When the oxide and scale are repeatedly removed, there is no
normal reduction of the corrosion process. Cavitation and impingement produce a characteristically pitted
surface at selective locations and is accelerated by the presence of oxygen, carbon dioxide, and hydrogen
sulfide. When entrained solids such as dirt and sand are present, a combination of erosion-corrosion can
take place.
CP Equipment Accuracy Check
Voltmeters and electrodes used for cathodic protection shall be tested and documented for accuracy
annually.
ELECTRODES - Electrodes shall be checked for accuracy by preparing a new electrode which is the
standard electrode to be compared against. This electrode should not be used in the field. Set LC-4
voltmeter to DC voltage scale to 200 my and input impedance to 200 as well. Attach the standard
reference electrode to the negative side of the meter and electrode to be tested to the positive DC side.
Place the two electrodes end to end, contacting each plug assembly. If the electrodes are evenly matched,
the LC-4 voltmeter should read zero. The difference between the two should have a reading of no more
than +/- 10mV. If results are out of tolerance, the electrode should be rejuvenated per manufacturer's
recommendations.
VOLTMETERS—Voltmeter shall be checked for accuracy using the Tinker and Rasor VC-1 Verifier and
procedure. The tolerance level of the voltmeter should be +/-0.05 V. Connect the voltmeter to be tested to
the Verifier terminals labeled "Positive" and "Negative", observe polarity. Turn the "Voltage Select" knob on
the Verifier to the position marked 1.0v. Display on the voltmeter under test will read 1.000 +/-0.002 volts.
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Continue to turn the "Voltage Select" knob to the 1.5v and 2.Ov positions. In each case, the voltmeter
under test will read the selected voltage within +/-0.05 volts. To test the polarity indicator on the voltmeter
under test, reverse the positive and negative leads connected to the voltmeter. The voltmeter should
display a minus (-) sign, and the voltage selected on the "Voltage Select' knob of the Verifier. If the
voltmeter is out of tolerance, it shall be repaired or replaced.
MAINTENANCE AND REMEDIATION TIMEFRAMES AND FREQUENCIES:
Monitoring Function Frequency
Cathodically Protect New Steel Pipelines Within 12 months of installation (WA not to exceed 90
days)
Testing of Cathodic Protection Areas and Isolated
Sections Greater than 100 Ft.
(Note: If such isolated sections of steel reside within a Once each calendar year(Not to exceed 15 months)
casing,they only need to be visited once per calendar
year not to exceed fifteen months and this will satisfy
both inspection requirements.)
Testing of Isolated Sections of Main Less Than 100 Ft., 10 percent Sample Annually, (entire system sampled in
or Isolated Services/Risers 10-year period)
Cathodic Protection Rectifiers 6 times per year(Not to exceed 2-1/2 months)
Testing of Critical Interference Bonds, Reverse Current 6 times per year(Not to exceed 2-1/2 months)
Switches, Diodes
Testing of Other Interference Bonds Once each calendar year(Not to exceed 15 months)
Monitoring Function Frequency
Testing of Steel Casings with Steel Carrier Pipe
(Note: If such steel in steel casings are also an isolated
section of steel greater than 100 feet in length,they Once each calendar year
only need to be visited once per calendar year not to (Not to exceed 15 months)
exceed fifteen months and this will satisfy both
inspection requirements.)
Leak Survey of Isolated Steel Pipe Not Cathodically Two times per year(Not to exceed 7-1/2 months)(State
Protected of Washington only)until protected
External Surface, Steel Buried Piping-Visual Inspection Whenever buried piping is exposed
Internal Surface, Steel Buried Piping-Visual Inspection When pipe cut apart or coupon removed
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Construction/Repair Function Repair/Remediation Completion By
90 days from date of discovery(Requirement on all
Existing Cathodic Protection Areas Where Protection is transmission and also on distribution in WA and a best
Inadequate practice on distribution in Oregon and Idaho). If
extenuating circumstances exist, another 30 days to
restore to adequate level of CP may be granted.
Cathodically Protect Isolated Steel Sections of Piping 90 days from date of discovery. Conduct leak survey
(including services and risers) prior to 90 days and then leak survey 2 times per year.
(Not to exceed 7-1/2 months(Cathodically Protect))
Possible Shorted Casings 90 days from date of discovery conduct a follow-up test
to confirm the shorted condition.
90 days from date of discovery leak survey(or repair)
Confirmed Shorted Casings and continue leak survey thereafter two times per year
(Not to exceed 7-1/2 months)until cleared or repaired
Existing Cathodic Protection Areas Where Protection is If extenuating circumstances allow another 30 days to
Inadequate restore to adequate level of CP.
Recordkeeping
Cathodic protection maintenance records shall be retained for as long as the pipeline or facility remains in
service. Records and/or maps showing the location of cathodically protected piping, cathodic protection
facilities, galvanic anodes, and neighboring structures bonded to the cathodic protection system shall also
be maintained.
STRUCTURE-TO-ELECTROLYE POTENTIAL (PIPE-TO-SOIL POTENTIAL)
General
A structure-to-electrolyte potential is the voltage difference between the surface of a buried metallic
structure (pipe or other metallic pipeline component)and the electrolyte (soil) measured with reference to
an electrode in contact with the electrolyte. (Examples of structures include steel gas pipelines, service
risers, regulator station risers, casing vents, tracer wires, test stations, etc.)
Potential Test Equipment
The approved equipment for taking structure-to-electrolyte potentials includes a high input impedance
voltmeter in conjunction with a copper/copper sulfate reference electrode.
The common or(-) lead of the multi-meter will be connected to the reference electrode. The volt or(+) lead
will be connected to the structure being protected by CP current. A negative potential should be indicated
on the meter in this configuration. IF A POSITIVE POTENTIAL READING IS INDICATED, CONTACT A
CATHODIC PROTECTION TECHNICIAN OR SPECIALIST IMMEDIATELY.
Potential Requirements
Each potential will have the following information recorded:
• Magnitude of potential reading
• Polarity of the reading (+ or-)
• Date of reading
• Name of person taking the reading
• ON and OFF potential reads (Note: Off reads are not required on exposed pipe evaluations)
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Maintenance of Equipment
Reference Electrode:
• Verify that the copper/copper sulfate electrode's solution is at an adequate level (1/2- 3/4 full)
• Verify solution is clear, not cloudy. If cloudy, contact a Cathodic Protection Technician to replace the
solution and recalibrate.
• The porous plug should be kept clean, capped, and stored in a vertical position to prevent from drying
out.
Multi-meter:
• Store in a dry, moisture-free location
• Replace batteries as needed per manufacturer's instructions.
Test Leads:
• Check for broken leads. Broken test leads will cause a potential reading to drift. To test for broken test
leads, use a 9-volt battery and place the (-) lead of multi-meter on (-)terminal of the battery and the (+)
lead to the positive terminal of the battery. The voltage read should be close to 9 V (DC). If read is not
steady, the leads may be broken. Contact a CP Technician or CP Specialist if leads are broken.
Calibration and/or Verification of Equipment
Calibration and/or verification of equipment shall be performed annually by a Cathodic Protection
Technician. High input impedance multimeters shall have a serial number sticker or plate adhered to them
(for ID purposes) and a sticker or label affixed and updated annually during maintenance to enable
tracking of the calibration or verification.
Equipment Setup
The reference cell is connected to the negative or common terminal (usually black) of the voltmeter and
the lead to the structure to be tested is connected to the positive terminal (usually red). Turn multi-meter to
volts DC setting.
Aboveground Potential Reads
Connect the reference cell to the negative or common terminal of the voltmeter or multi-meter. Make sure
that the porous plug of the reference cell is in good contact with the soil and is not contacting stones,
vegetation, and landscaping plastics. (You may get false readings if the reference cell contacts materials
other than soil). If dry or frozen ground is encountered, water may be necessary at the point where you
place the electrode in the ground.
If the ground has very dry soil conditions, dig a small hole, such as with a screwdriver and pour an
abundant amount of water into the hole. This will help to get a more accurate pipe-to-soil read. If the
ground is already wet, this step may not be necessary.
Connect the positive lead of the voltmeter or multi-meter to the structure to be tested, make sure that you
are taking a read on the appropriate side of an insulated fitting. When taking a read at surface levels on
aboveground facilities, it is best to place the electrode in the ground directly above the underground pipe
and at approximately 6 to 12 inches on either side of where the pipe rises out of the ground.
Exposed Pipe Reads
When a steel pipeline is exposed and the coating needs to be repaired, a pipe-to-soil read shall be taken
and documented on the Exposed Piping Inspection Report form (Form N-2534). It is best to place the
electrode in the soil directly above or at the same level and as close as possible to the soil surrounding the
exposed pipe. The closer the electrode is to the soil that contacts the pipe, the more accurate the read will
be. (This may not be possible in all cases, so take the read at the closest location that is possible.)
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Ensure the porous plug of the reference cell is in good contact with the soil and is not contacting stones,
vegetation, and landscaping plastics. (You may get false readings if the reference cell contacts materials
other than soil.) If dry or frozen ground is encountered, water may be necessary at the point where you
place the electrode in the ground.
If the ground has very dry soil conditions, dig a small hole, such as with a screwdriver and pour an
abundant amount of water into the hole. This will help to get a more accurate pipe-to-soil read. If the
ground is already wet, this step may not be necessary.
Recordkeeping
Record pipe-to-soil reads and other required information on the Exposed Piping Inspection Report form
(Form N-2534)as required in Specification 3.44, Exposed Pipe Evaluation. The local Cathodic Protection
Technician will follow up on reads that do not meet the required voltage criteria.
Requesting Assistance
While taking pipe-to-soil reads, if results are questionable, check the equipment to make sure that all
equipment is functioning properly. If the problem cannot be resolved, contact your local Cathodic
Protection Technician for assistance.
If a pipe-to-soil reading results in a positive voltage potential, a local Cathodic Protection
Technician should be contacted immediately. A positive read, if read correctly, will indicate that the
cathodic protection system is not functioning properly. This may result in metal loss of the pipe if
not corrected immediately.
Monitoring Electrical Isolation of Steel Encased Pipeline
When monitoring electrical isolation of a casing from a steel pipeline, follow the same requirements for
aboveground Potential Reads; however, a potential read is taken on the casing vent (or designated test
lead) and on the pipeline (or designated test lead) and compared to see if the potential difference between
the two indicates isolation if there is more than a 100-mV difference. The electrode shall be placed on the
ground directly over the pipeline and near the end of the casing for both reads.
PROCEDURE FOR TESTING A CASING WITHOUT TEST LEADS:
The following procedure is a method for testing for electrical isolation on casings for which there are no
test leads or close contact points:
A current source transmitter and receiver(such as a Radio detection Model PDL2 receiver and RD433
HCTX-2 transmitter or equivalent) used in conductive mode is used. The positive output of the transmitter
is connected to an electrically continuous portion of the natural gas piping that traverses through the
casing, preferably at a distance of at least 100 feet from the casing.
The transmitter's negative connection is made to a convenient electrical ground. The transmitter is set to
low frequency and low current output. The low frequency and output levels reduce the chance of
transmitted current"jumping"to unintended nearby structures.
The receiver is then set to the low frequency level and the underground piping route is traced along its
path, beyond the suspected location of the casing. Transmitter current output is then measured by the
receiver at appropriate locations and recorded on a sketch of the casing and pipe.
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Current output from the transmitter will travel along the electrically continuous section of the piping. The
current will leave the pipe at coating holidays, entering the earth, and returning to the transmitter through
the negative connection. Depending upon the transmitter output setting and the coating condition of the
pipe, current will travel along the pipe a substantial distance before it is all returned back to the transmitter.
The better the coating condition, the longer the distance the current will travel. In the instance of a bare
casing shorted to the pipe, much of the current will be returned back to the transmitter along the length of
the casing with a substantially reduced percentage of the current continuing on along the pipe.
With a non-shorted casing, the amount of current measured on the downstream side of the pipe just
beyond the casing should be nearly the same as the current measured on the upstream portion of the pipe
prior to the pipe entering the casing. At locations where the pipe T's, a proportionate amount of the current
will travel to each side of the T depending upon the amount and condition of pipe on that particular branch.
Example of Non-shorted Casing: Example of Shorted Casing:
20 20 19 Short
20 19 4 20 t3 2
14 6
Direction of Current Direction of Current
Flow Flow
ALTERNATIVE PROCEDURE FOR TESTING A CASING WITHOUT TEST LEADS:
The following is an approved method of testing for electrical isolation on casings for which there are no test
leads or close contact points.
1. A current source transmitter(such as Tinker and Rasor Mark 3 PD short locator equipment or
equivalent) is attached to a nearby gas facility and to a ground source.
2. The transmitter output is set to no more than 2 amps and then interrupted. (The set point is based
on the distance between the current source and the casing being tested. The closer you are to the
casing, the fewer amps that are needed.)
3. The receiver is adjusted to 70 percent sensitivity.
• The signal produced by the transmitter will only flow toward holidays in the pipe coating or
grounded structures in contact with the coated pipe.
• A shorted casing, which is not coated, shows a huge holiday or ground. The signal is
dissipated almost in its entirety by the size of the holiday. Unless the receiver sensitivity is
increased, pipe locating is not possible past the casing if it is in a shorted condition. If the
casing is determined to be shorted, refer to the"Shorted Casings" of this specification for
remedial actions.
• If no short or contact exists between the casing and the steel carrier pipe, the signal continues
past the casing as normal and pipe locating is possible beyond the casing.
The casing length and diameter are not a concern when using this method. Any contact between a coated
carrier pipe and a bare casing reacts the same. In addition, the surrounding soil makeup has little or no
effect on this type of inspection.
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5.15 PIPELINE PATROLLING AND PIPELINE MARKERS
SCOPE:
To establish procedures for patrolling of Avista's gas transmission pipelines and distribution facilities for
the purpose of observing conditions that may affect the safety and operation of the lines or other
company facilities. This specification also specifies where, when, and in what manner company pipelines
and facilities require marking or identification.
REGULATORY REQUIREMENTS:
§192.603, §192.613, §192.705, §192.707, §192.721, §192.935
WAC 480-93-124
CORRESPONDING STANDARDS:
Spec. 3.15, Trenching and Backfilling
Spec. 4.13, Damage Prevention Program
Spec. 4.16, Class Locations
Spec. 4.31, Operator Qualification
Spec. 5.11, Leak Survey
General
Gas Engineering, Gas Compliance, and local construction offices shall identify transmission lines, high
pressure distribution mains, and other distribution lines that may require patrolling or marking under
existing regulations. Pipelines that require patrolling include:
• Transmission Lines:
• High Pressure Distribution Mains.
• Intermediate Pressure Distribution Mains and Services (in conjunction with Leak Survey); and
• Any distribution line subject to abnormal movement or external loading which may result in leakage or
failure.
Mains located in places or on structures where anticipated physical movement or external loading could
cause a failure or leakage shall be patrolled four times each calendar year, but at intervals not exceeding
4-1/2 months and documented on Bridge Crossing and Other Piping Quarterly Checklist(Form N-2630).
Documentation of conditions found during any patrolling activity should include not only potential safety
and integrity issues observed, but also detail as to whether the observed conditions are an immediate
concern and what steps are being taken to further investigate and /or resolve the issue.
Included in this category of inspections are exposed facilities that are designed for movement(having
expansion loops or joints and otherwise lacking rigid restraint), bridge crossings (regardless of pipeline
classification), frost heaving problem areas, and other areas where possible earth movement or land
subsidence (including rivers, creeks, and irrigation canals) is a distinct probability. For areas near a gas
pipeline where land movement has been identified, further investigation may be warranted to determine
whether the pipeline is moving and is under stress. Gas Engineering shall be contacted to determine the
appropriate method of investigation and monitoring for the specific situation.
For new installations, Gas Engineering and/or local operations managers should determine if the facilities
are at risk of physical movement in order to establish a maintenance requirement for patrolling.
Aboveground facilities that are rigidly restrained and are not expected to experience physical movement
shall be inspected for atmospheric corrosion every 3 years, not to exceed 39 months. If during this
inspection it is noted that the pipe has experienced movement, then the facility shall be identified as an
"anticipated movement"facility which shall be inspected four times per calendar year, not exceeding 4-1/2
months.
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Employees performing patrolling and marking functions shall be properly trained and qualified. This
includes being familiar with the locations of the pipelines being patrolled, locations of other company
facilities, locations of bridge, highway and railroad crossings, stream, and river crossings, etc.
Designated buried pipelines shall be patrolled by an appropriate method in order to observe surface
conditions on and adjacent to the pipeline right-of-way for indications of leaks (vegetation or leak detector
survey), construction or excavation activity, washouts, land subsidence or other earth movement, stream
erosion, vegetation management needs and encroachments on the right-of-way by structures, roads, etc.
Missing or damaged pipeline markers shall also be identified during patrols and fixed/ replaced as
applicable.
Designated aboveground pipelines and facilities shall be patrolled in order to observe conditions such as
missing supports, broken pipe hangers, active corrosion, damaged or compromised structural barricades,
and other integrity concerns. Missing or damaged pipeline markers and warning signs shall be identified
during patrols and remediated as soon as possible (within 45 days in Washington).
Atmospheric corrosion can occur in many places such as where the pipe penetrates through bridge
structures, where the pipe is installed close to the bridge structure, between pipe and hangers/rollers,
and in spans over water. If evidence of corrosion is noticed, it shall be noted on the inspection form,
Bridge Crossing and Other Piping Quarterly Checklist(Form N-2630), so that it may be referred to Gas
Engineering or the local Cathodic Protection Technician for further evaluation as applicable.
For long spans on bridges, binoculars or drones can be used; however, where vision is limited or when
the entire pipe span cannot be seen in detail, the inspector may need to get access under the span to be
able to observe conditions of the pipe. (If access under the span is a problem for example where boating
ramps are closed seasonally, what is visible from the ends or shorelines should be checked quarterly and
closer inspections done semi-annually not to exceed 7-1/2 months.)
Methods of Patrolling
Pipeline patrols may be accomplished by either ground (foot or vehicle patrols) or by air(the preferred
aerial method is by helicopter but as drone technology improves, this may be an equally good option).
Ground patrols may be performed in conjunction with other work such as leak surveys, valve
maintenance, meter inspection and maintenance, etc. Ground patrols allow for close observation of
conditions that may affect company facilities or pipelines.
Evidence of gas leakage such as odors and bubbles in surface water can only be adequately detected
and assessed on the ground. Other factors such as survey marks (indicating possible future construction)
atmospheric corrosion, damaged casing vents and cathodic test points, etc., will also only be readily
apparent during a ground patrol. Aerial (helicopter) patrols are often more effective to cover long
distances and/or rugged terrain. Field personnel performing aerial patrolling shall be provided with the
appropriate equipment(such as binoculars, aerial maps, etc.) so that the patrol is effective. Aerial patrols
shall be supplemented by ground patrols whenever the pipeline route or any other unusual condition
cannot be accurately discerned from the air.
Highway and railroad crossings shall be carefully observed for evidence of leakage during aerial and
ground surveys. Major river crossings under which the pipeline might be subject to scouring, dredging, or
other physical damage shall be examined by qualified divers every 5 years, not to exceed 63 months. The
diver or remote submergible vehicle shall inspect for signs of leakage (bubbles— Refer to Section 5.11,
Leak Survey), exposure, scouring, or any other condition that may affect the safety or integrity of the
pipeline. Other underwater crossings (streams, creeks, etc.)shall be patrolled during the course of the 5-
year(20 percent) leak survey or during other more frequent patrols as deemed necessary. Refer to
Specification 5.11, Leak Survey
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Clearance
The following shall apply to pipeline facilities on Avista owned property or within easements where the
terms of the easement allow for such restrictions:
1. No trees are permitted within 10 feet (20-foot clear zone) of an Avista pipeline. The canopy of trees
adjacent to easements should not extend into the easement when mature. Branches extending into
the easement may be trimmed and side cut by Avista at its discretion.
2. With prior approval from Avista, some types of low growing, shallow-rooted shrubs may be permitted
outside 5 feet (1 0-footclear zone)of the pipeline centerline. Avista requires that the mature plantings
will not prevent Avista personnel or vehicles from accessing the easement for emergency purposes,
seeing down the easement during routine patrols, or walking down the easement directly over the
pipeline as they perform required inspections. (Note: The intent is to allow shallow rooted plants
(shrubs, flowers, etc.)to grow outside of the 10-foot clear zone and deeper-rooted plants/trees may
be permitted outside the 20-foot clear zone but vegetation should not block access or visual line of
sight). Mechanical equipment shall not be used during the planting of shrubs or other vegetation.
3. Avista reserves the right to cut and/or remove vegetation within the easement as required for safe
and efficient access, operation, inspection, and maintenance of its pipeline facilities. Avista will
assume no responsibility for the costs associated with the replacement of cut and/or removed
landscape plantings that do not meet these criteria.
The following shall apply to pipeline facilities within right-of-way where vegetation restrictions are not
within Avista control or within existing easements where the terms of vegetation restriction within the
easement are not clearly defined:
1. When vegetation is determined to prevent safe and efficient access, operation, inspection, and
maintenance of pipeline facilities or there is potential that tree roots may cause damage to pipe
facilities, the property owner or controlling entity shall be contacted to determine if the vegetation can
be removed or cut back.
2. In certain cases, Avista may be required to relocate pipeline facilities at its own expense to
appropriately mitigate these conflicts.
MAINTENANCE FREQUENCIES
Distribution Line Patrols Frequency
High Pressure Mains (over 60 psig MAOP) Should occur once each calendar year as a "Best
Practice" (Not to exceed 15 months)
Bridge Crossings and lines subject to possible 4 Times each calendar year(Not to exceed 4-1/2 months)
movement
Underwater Inspections major river crossings) Once every 5 years Not to exceed 63 months
Other Distribution Lines (includes stream and creek Once every 5 years in conjunction with leak survey
crossings)
Transmission Line Patrols Frequency
Population Class 1 &2 Locations Once each calendar year Not to exceed 15 months
Population Class 1 &2 Locations at Highway and 2 Times each calendar year(Not to exceed 7-1/2 months)
Railroad Crossings
Population Class 3 Locations 2 Times each calendar year(Not to exceed 7-1/2 months)
Population Class 3 Locations at Highway and Railroad 4 Times each calendar year(Not to exceed 4-1/2 months)
Crossings
Population Class 4 Locations 4 Times each calendar year(Not to exceed 4 1/2 months)
Population Class 4 Locations at Highway and Railroad 4 Times each calendar year(Not to exceed 4-1/2 months)
Crossings
Refer to Specification 4.16, Class Locations, for the definition of each population class location in regard
to transmission line patrols.
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Recordkeeping
Patrols of transmission and distribution lines should be documented on the Gas Patrolling Report (Form
N-2629) or otherwise as applicable. This includes aerial as well as ground patrols. Employees performing
patrols shall list the conditions found, as well as repairs needed. Required repairs shall be forwarded to
the appropriate construction personnel for follow-up action.
Records pertaining to major underwater river crossing inspections shall be retained in Gas Engineering in
a file specific to the crossing itself or at the local construction office where the crossing exists. Normally, a
dive team or other specialized individual(s)will be contracted to inspect the pipeline and prepare a report
of its condition. Records pertaining to pipeline patrols and inspections shall be retained for the life of the
facility.
TIMP— Transmission Patrolling
There are additional patrolling and documentation requirements in regard to Avista's transmission
facilities. Excavations near Avista's transmission lines are to be monitored as outlined in Specification
4.13, Damage Prevention Program, "On Site Inspections for Transmission Facilities." Other requirements
are outlined in Avista's Transmission Integrity Management Program, which is a separate document
accessible on Avista's intranet website.
PIPELINE MARKERS
Pipeline Markers for Buried Pipe
Pipeline markers may be round, single, double, or tri-faced signs and shall be a distinctive yellow color
and written legibly on with a sharply contrasting color. New and existing gas warning and pipeline marker
signs shall include the word "Warning", "Caution", or"Danger"followed by the words "Gas Pipeline" in
letters at least one inch high with a one-quarter inch stroke. Information posted on the signs or markers
must list the current operator(Avista)and a 24-hour telephone number(including the area code).
Outdated information on the markers must be updated when found.
Pipeline markers shall be installed and maintained, where practical, over each distribution and
transmission pipeline to indicate a potential hazard and/or to designate the location and route of such
buried pipelines or underground facilities. Round markers are preferred for new installations of high-
pressure gas mains to enhance visibility. Flat or tri-faced markers are typically used for intermediate
pressure pipelines. Flat markers should be placed perpendicular to the pipeline. Pipeline marker adhesive
stickers may be placed directly on above ground company facilities (e.g., CP Big Finks, CP Small Finks,
vent pipes, etc.)where doing so would enhance safety notification.
If installing tracer wire with a pipeline marker(i.e. end of main), refer to Specification 3.13 Pipe Installation
Plastic Mains— Tracer Wire for recommended installation practice.
Pipeline markers shall be placed approximately 500 yards (1500 feet) apart, where practical, and at
points of inflection of the pipeline. An effort should be made to place pipeline markers in such a manner
that the route of the pipeline is easily discernible and so that the markers are not obscured, to the extent
possible, by natural or man-made features. When multiple mains exist in a common right-of-way, each
pipeline should be individually marked.
Off-set pipeline markers may be used. If an off-set is required on a marker it shall be written in a UV
resistant permanent pen or other permanent means (e.g., brass tag or weather resistant sticker) on two
sides of the marker(as applicable) and indicate the distance from the pipeline in feet as well as the
cardinal direction to the pipeline, valve, end of main, deflection point or other appurtenance.
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Pipeline markers shall also be placed at the following locations:
• Railroad crossings (both sides if practical);
• Aboveground or suspended pipelines (on both ends if practical) in areas accessible to the public
(except service risers, meter set assemblies, and gas pipeline company owned piping downstream
of the meter set assembly);
• Public road and highway crossings (both sides if practical); (The exception being public roads or
highways in Class 3 or Class 4 areas.)
• Irrigation and drainage ditch crossings (both sides if practical)where hydraulic scouring, dredging, or
other activities could pose a risk to the facility;
• Fence lines (In Class 1 /Class 2 areas)where a pipeline crosses private property;
• Stream and river crossings (both sides if practical);
• Any other location where it is determined the pipeline may be subjected to damage (In Class 1 /
Class 2 areas)
Exceptions for Marking
Pipeline markers for buried lines are not generally required for mains in Class 3 or 4 locations (refer to
Specification 4.16, Class Locations)where placement of a marker is impractical or where a damage
prevention program is in effect. Refer to Specification 4.13, Damage Prevention Program.
Washington Pipeline Marker Location Requirements
WAC 480-93-124 - Pipeline Marker Location Requirements
The following pipelines must have pipeline markers installed in Washington:
• Over mains located in Class 1 and 2 locations.
• Over transmission lines in Class 1 and 2 locations, and where practical, over transmission lines
in Class 3 and 4 locations.
• On aboveground gas pipelines except service risers, meter set assemblies, and Avista-owned
piping downstream of the meter set assembly.
• At both ends of suspended pipelines.
In the state of Washington, the following main and transmission pipelines must have pipeline markers
installed regardless of the population class location:
• Where practical, over pipelines operating above 250 psig (this includes Avista's transmission
lines).
• At crossings of navigable waterways, on both sides if practical (custom signage may be required
to ensure visibility).
• At river, creek, irrigation canal, and drainage ditch crossings where hydraulic scouring, dredging,
or other activity could pose a risk to the pipeline. Mark both sides of the crossing if practical
(custom signage may be required to ensure visibility).
• At railroad crossings, on both sides if practical. (Note: Additional markers may be warranted
within the railroad right-of-way in addition to those typically installed on casing vent pipes,
particularly in the case of wide rights-of-way and where the vent pipes are located at the extreme
edges of the right-of-way.)
• Where practical, when mains and transmission lines cross interstate highway, U.S. highway, and
state highway routes. (Mark both sides of the crossing if possible.)
MAINTENANCE REV. NO. 21
PIPELINE PATROLLING AND DATE 01/01/25
PIPELINE MARKERS
XvIST'r STANDARDS 5 OF 6
utilities NATURAL GAS SPEC. 5.15

Vegetation Guidelines
Vegetation shall be controlled so pipeline markers and signage are visible during an inspection or line
patrol. If mileage markers are installed along the pipeline, vegetation shall be controlled so that these
markers are visible during an aerial inspection of the facility.
Markers for Aboveground Pipelines
Line markers and/or warning signs shall be placed at any point where gas distribution or transmission
pipelines are exposed. Markers should not be placed where they are likely to be damaged, destroyed, or
where they will interfere with land uses such as cultivation of fields. Markers should not be placed in
landscaped areas or areas where the marker may have a negative visual impact without obtaining the
permission of the property owner or authority involved. Markers shall not be placed in the right-of-way of a
road where they could interfere with or present a hazard to traffic.
Gas pipelines attached to bridges or otherwise spanning an area shall have proper markers or warning
signs at both ends of the suspended pipeline. Markers or signs should be installed in the ground at each
end of the bridge and stickers/signage directly affixed on the exposed pipeline at both ends near the
abutments. These signs/ markers shall be kept visible and readable and shall be inspected in conjunction
with pipeline patrols. Signs or markers reported damaged or missing shall be replaced as soon as
practical. In Washington, this shall be done within 45 days per the requirements of WAC 480-93-124.
District regulator stations, gate stations, farm taps, and block valves shall have warning signs in place.
Washington Pipeline Marker Surveys
WAC 480-93-124—Survey of Pipeline Markers:
In the state of Washington, a survey of pipeline markers must be conducted every 5 years not to
exceed 63 months to ensure they are located where required and are visible and legible.
Markers that are reported damaged or missing must be replaced within 45 days.
Survey records must include a description of the system and area surveyed.
The documented survey record may be maps, drawings, electronic records, or other documents that
sufficiently indicate class locations and other areas where pipeline markers are required in the state of
Washington.
The documented survey records must be kept for a minimum of 10 years.
MAINTENANCE REV. NO. 21
PIPELINE PATROLLING AND DATE 01/01/25
PIPELINE MARKERS
XvIST'r STANDARDS 6 OF 6
utilities NATURAL GAS SPEC. 5.15

5.16 ABANDONMENT OR INACTIVATION OF FACILITIES
SCOPE:
To establish procedures for abandoning Avista's natural gas pipeline mains and services. Also included
herein, are procedures for inactivation of other gas facilities.
REGULATORY REQUIREMENTS:
§192.727
CORRESPONDING STANDARDS:
Spec. 2.22, Meter Design
Spec. 3.16, Services
Spec. 3.17, Purging
Spec. 5.13, Valve Maintenance
Spec. 5.14, Cathodic Protection Maintenance
Spec. 5.20, Atmospheric Corrosion Control
General
Transmission and distribution pipelines, and services should be abandoned when it is determined they
are no longer required for immediate or future use. To enhance public safety and eliminate ongoing
maintenance related to inactive above grade facilities, services should be considered for abandonment if
they are not expected to be used in the next three years or the service location will substantially change
in the future. They shall be disconnected from the pipeline system.
Procedures relating to abandonment of pipelines and facilities and purging operations shall only be
performed by properly trained and qualified personnel.
The abandoned pipeline shall be blown down and purged until it is substantially free of gas in accordance
with Specification 3.17, Purging Pipelines. If air is used, the employee performing the purging operation
shall verify that a combustible gas mixture is not present after purging.
Abandoning Gas Facilities
Pipeline sections to be abandoned in place or that are no longer subject to gas pressure, shall be
disconnected from all sources and supplies of gas. The following procedures shall be followed when
abandoning gas pipelines:
• Gas Engineering shall be consulted when abandoning pipelines longer than 1,000 feet as additional
plugging or sealing points may be required. Segments longer than 1,000 feet should be cut into
lengths of 1,000 feet or less. The ends of each section shall be sealed.
• Removal of the pipeline section from the ground or filling the pipeline with solid materials are other
options that may be appropriate depending on the circumstances. These options tend to be more
costly and normally not needed unless required by local agreements or governing agencies.
• Except as noted in the two paragraphs below, capping of live facilities shall only be by use of
fusion/weld caps or approved mechanical fittings.
• For 2-inch and smaller curb tees, curb valve tees and high-pressure service tees operating at 1175
PSIG or less it is acceptable to seal the outlet of the tee during abandonment using a plug or disk cut
from steel bar stock provided the following conditions are met:
MAINTENANCE REV. NO. 17
ABANDONMENT OR INACTIVATION OF DATE 01/01/25
FACILITIES
Xv sm a STANDARDS 1 OF 4
utilities NATURAL GAS SPEC. 5.16

o Use a steel plug or disk with minimum thickness based upon the following service tee size:
■ 3/4" service tee/outlet— minimum 1/4" thick
■ >3/4" service tee/outlet— minimum 1/2" thick
o Use a 1/4" minimum thickness circumferential fillet weld either internally or externally to the outlet
of the service tee. If welded externally then the thickness of the disk should be at least 1/4"
thicker than the minimum in order to ensure that the minimum thickness shown is maintained on
the internal side of the tee and for the welding surface of the parent metal
o In high pressure retirement applications (MAOP > 60 PSIG) use a minimum Grade B, A36 hot
rolled steel bar-stock material with a minimum yield strength of 36,000 PSIG, not to exceed a
yield strength of 52,000 PSIG in order to accommodate current existing weld procedures
■ For high pressure facilities use only material that can be tracked via a Material Test Report
(MTR). Provide the material Heat#information to Gas Engineering for all high-pressure
retirements.
• For 2-inch and smaller steel pipe operating at 60 psig or less, where space limitations make it
impractical to seal the live end with a fitting, it is permissible to seal the end utilizing a coupon (disk)
cut from bar stock. The disk must be at least 1/4-inch thick and fit within the piping so as to be fillet
welded circumferentially.
• Pinching the active end of a steel pipe for isolation and abandonment is not an approved method.
• Use of a blind flange as a sealing method of the live facilities is not permitted other than for an above
ground application.
• When a cut is required (whether mains or services), a piece of pipe at least 18 inches in length
should be removed so that the termination points are as discernible as possible. Excavations shall
be backfilled and thoroughly compacted.
• Sections of pipeline that are still in operation shall be inspected for corrosion and coating condition.
These conditions shall be documented on the Exposed Piping Inspection Report(Form N-2534).
Pipe coating that is removed from pipe that is to remain in service shall be repaired at the conclusion
of the sealing procedure.
• When abandoning a lateral (main or service), it should be disconnected as close to the mainline as
possible to reduce the potential for future excavation damage. If there is a valve on the lateral to be
abandoned, the valve should also be abandoned to eliminate potential underground leaks occurring
on the valve stem in the future.
Services to be abandoned in place are subject to the following procedures:
• The preferred method for abandoning a service is to isolate the service using the service tee located
at the main, cutting the service line as close as practical to the main, and installing a cap on the
active end of the service line.
• For 2-inch and smaller steel services operating at 60 psig or less, it is permissible to cut the service
line at the outlet of the tee, remove the compression nut from a compression tee, or cut the service
pipe as close as practical to the main, and seal the end of the tee or pipe utilizing a coupon (disk) cut
from bar stock. The disk must be at least 1/4-inch thick and fit within the service tee or pipe so as to
be fillet welded circumferentially. If a Continental compression service tee is used for a PE service
off of a steel main, an abandonment cap should be used at the service tee. The open end of the
abandoned pipe shall be sealed.
• The service riser shall be removed to below ground level and the remaining pipe sealed. If the
service passes through or under a building foundation, the pipe shall be cut outside the building, and
both ends sealed.
• Prior to demolition of buildings, services should be disconnected at the main or at a point that will
prevent damage to the service. A service found to be supplying a riser without an accompanying
building shall be cut off and sealed at or outside the property line as soon as possible after
discovery.
MAINTENANCE REV. NO. 17
ABANDONMENT OR INACTIVATION OF DATE 01/01/25
FACILITIES
Xv sm a STANDARDS 2 OF 4
utilities NATURAL GAS SPEC. 5.16

The ends of the abandoned pipeline shall be sealed to prevent migration of any foreign gas or other
materials through the abandoned line. Sealing shall be done by one of the following methods:
• Crushing or flattening the pipe end and welding the opening
• Welding a plate or a weld cap over the opening
• Using expandable foam insulation
• Utilizing a plastic pipe cap on the OD or plastic plug on the ID. The cap or plug should be sized
appropriately for the pipe and be in a satisfactory condition to seal the end of the pipe (i.e., no cuts,
cracks, etc.)
Casings
Casings to be abandoned in place shall have their vent pipes and finks cut off(or entirely removed) below
grade. The cut-off ends shall be filled with expandable foam. Carrier pipe within casings shall be
abandoned in accordance with the above guidelines for Abandonment of Gas Facilities.
Disabling a Curb Valve Tee
When disabling a curb valve tee, the preferred method is the same as discussed above in "Abandoning
Gas Facilities". In addition, a Mueller H-17800 steel abandonment cap should be installed onto the top of
the tee and seal welded to prevent leakage.
Valve Abandonment
In pipeline systems that are still operational, gas distribution valves and curb valves may be abandoned
only if they are not deemed necessary for the safe operation of the gas system involved. Disabled valves
(i.e., no longer operational, but gas still runs through it) shall comply with Specification 5.13, Valve
Maintenance, "Valve Disable/Abandonment."
Valve Box Abandonment
When abandoning a valve, the valve box may be removed or, if it cannot be easily removed, it may be
abandoned in place by filling the valve box with sand and capping with 4 inches of concrete flush with
grade. For a valve that has been `Disabled' per Specification 5.13, Valve Maintenance, a marker ball
should be left at the valve prior to making it inaccessible.
Regulator Station Abandonment
Gas piping or other related equipment in regulator and other stations that are no longer in use should be
removed in order to minimize hazards.
Vault Abandonment
Each gas regulator vault that is being abandoned shall be filled with suitable compacted material or
completely removed, as applicable.
Commercially Navigable Waterways
When abandoning a pipeline facility that crosses over, under or through a commercially navigable
waterway, a report must be filed by the operator when the facility is abandoned as delineated at
§192.727(g)(1).
MAINTENANCE REV. NO. 17
ABANDONMENT OR INACTIVATION OF DATE 01/01/25
FACILITIES
Xv sm a STANDARDS 3 OF 4
utilities NATURAL GAS SPEC. 5.16

Inactivating Gas Meter Facilities
When service to a customer is discontinued (shut off or account closed), one of the following procedures
must be followed:
• The valve that is closed to prevent the flow of gas to the customer(service valve) must be provided
with a locking device or other means designed to prevent the opening of the valve by persons other
than those authorized by Avista.
• A mechanical device or fitting that will prevent the flow of gas must be installed in the meter
assembly (i.e., blank tin disc in the meter outlet, blank swivels, plugs, etc.).
• The customer's piping must be physically disconnected from the gas supply and the open ends
sealed.
• If the meter set assembly(meter and service regulator) is removed, the service valve shall be locked
off and an 8-inch idle riser nipple and cap assembly shall be installed. An approved gas warning
sticker(Stock Item Number 662-0426 or 662-0428) shall be applied to the 8-inch nipple and cap
assembly to help prevent future damage to the service riser. The outlet swivel shall be removed, and
the customer's house piping shall be plugged or capped as appropriate.
Idle Meters and Idle Services
An idle meter is a meter installation on a service where the account is closed but the meter remains in
place. Idle meters shall be removed when it is apparent gas will not be used in the near future. Local
construction offices should investigate customer accounts idle over 12 months to determine if the meter
set should be removed.
An idle meter may remain if the customer opens the account and maintains payment of the basic monthly
charge.
An idle meter on a rental property may remain if the marketing representative determines that another
tenant may use the gas in the future. An idle service or riser is where the meter has been removed and
the service valve has been locked.
Maintenance Requirements
Maintenance is not required on abandoned pipelines. Idle risers should have idle riser markers with
warning signs installed as detailed in "Inactivating Gas Meter Facilities" in this specification. Idle risers
and idle meters shall be inspected for atmospheric corrosion and general condition the same as
aboveground facilities as outlined in Specification 5.20, Atmospheric Corrosion Control.
MAINTENANCE REV. NO. 17
ABANDONMENT OR INACTIVATION OF DATE 01/01/25
FACILITIES
Xv sm a STANDARDS 4 OF 4
utilities NATURAL GAS SPEC. 5.16

5.17 REINSTATING ABANDONED GAS PIPELINES AND FACILITIES
SCOPE:
To establish procedures to be used when reinstating or re-activating abandoned gas pipelines or other
gas facilities in Avista's gas systems.
REGULATORY REQUIREMENTS:
§192.725
WAC 480-93-170
CORRESPONDING STANDARDS:
Spec. 2.12, Pipe Design - Steel
Spec. 2.13, Pipe Design - Plastic
Spec. 3.16, Services
Spec. 3.17, Purging
Spec. 3.18, Pressure Testing
Spec. 3.32, Repair of Steel Pipe
Spec. 3.33, Repair of Plastic(Polyethylene) Pipe
General
Each abandoned or disconnected gas pipeline or other facility must be tested in the same manner as a
new gas pipeline or facility before it is reinstated.
Reinstatement or reactivation of gas pipelines and facilities shall only be performed by properly trained
and qualified employees.
Reinstating Gas Mains and Services
Each pipeline section that is to be reinstated shall be tested according to the procedures outlined in
Specification 3.18, Pressure Testing.
Gas Engineering shall review and approve gas pipelines and facilities prior to reinstatement to verify that
reinstating this pipe does not affect the integrity of the system.
Leaks detected through the testing procedure shall be located and corrected (refer to Specification 3.32,
Repair of Damaged Pipelines—Steel, and Specification 3.33, Repair of Plastic (Polyethylene) Pipe).
Each pipeline shall be re-tested until no pressure drop or leakage is detected.
Each abandoned gas service line disconnected from the main must be tested from the point of disconnect
to the meter valve in the same manner as a new service line before reconnecting. Refer to "Reinstating
Service" in Specification 3.18, Pressure Testing for additional information.
Steel pipelines exposed for reinstatement shall be examined for corrosion and the existing coating
examined before proceeding. Reinstated steel pipelines shall be tied into the existing cathodic protection
system and coatings shall be restored where necessary.
MAINTENANCE REV. NO. 9
REINSTATING ABANDONED GAS DATE 01/01/21
PIPELINES & FACILITIES
Xv sm a STANDARDS 1 OF 2
utilities NATURAL GAS SPEC. 5.17

Reinstating Gas Facilities
Valves exposed during the reinstatement procedure should be serviced, lubricated, and/or repaired, as
necessary.
Regulator stations, odorizers, or other facilities shall be brought up to current Company standards before
reactivation. Testing and adjustments shall be performed per Company standards.
Insulated, locking meter valves with lubrication ports shall be installed on reinstated services.
Meter set assemblies on reactivated lines shall be built to standard design and/or brought up to Company
standards (including relief and bypass capabilities).
No steel service or main that has been disconnected for longer than 90 days may be reinstated without
approval from Gas Engineering and the Cathodic Protection General Foreman. Plastic services or mains
that have been disconnected for longer than 6 months without being pressurized with air or nitrogen
should not be reinstated without approval from Gas Engineering.
MAINTENANCE REV. NO. 9
REINSTATING ABANDONED GAS DATE 01/01/21
PIPELINES & FACILITIES
XvISTA STANDARDS 2 OF 2
utilities NATURAL GAS SPEC. 5.17

5.18 VAULT MAINTENANCE
SCOPE:
To establish an inspection and maintenance program for vaults that house natural gas facilities in Avista's
construction areas.
REGULATORY REQUIREMENTS:
§192.749
WAC 296-809
CORRESPONDING STANDARDS:
Spec. 2.42, Vault Design
General
Vaults shall be inspected each time the enclosed facilities are opened and serviced.
Vault Inspection
Inspection of vaults shall include the following procedures:
• The atmosphere of the vault shall be tested with a Combustible Gas Indicator(CGI). If the vault
qualifies as a confined space, the atmosphere shall be tested and monitored in accordance with
confined space entry guidelines. (Refer to the Avista Incident Prevention Manual (Safety Handbook),
Part 2, Section 15—Confined/Enclosed Spaces, for additional guidance). Gas leaks discovered shall
be repaired.
• The physical condition of the vault must be observed. The walls and roof shall be checked for signs of
caving in, crumbling, rusting, or other deterioration. Note the less than adequate conditions found on
the Regulator Station Inspection and Maintenance Record (Form N-2527) (paper or electronic as
applicable)so that the conditions found may be scheduled for repair, as necessary.
• Ventilating appurtenances (as applicable)shall be inspected to determine that they are functioning
properly. Check vents, pipes, and floor drains to ensure they are not plugged. Clear or repair, as
necessary.
• The vault cover shall be checked to make certain that it opens or operates properly, that it is not bent
or broken, and that it seats properly. Schedule repairs as needed.
MAINTENANCE FREQUENCY:
Avista's gas distribution vaults shall be inspected and maintained according to the following schedule:
Type Frequency
Vaults Once each calendar year(Not to exceed 15 months)
An anniversary date shall be assigned to newly installed vaults. Subsequent maintenance shall be based
on the anniversary date established and required maintenance shall be completed before expiration of
the grace period. On existing vaults, the last date serviced establishes the anniversary date.
Recordkeeping
Records pertaining to vault maintenance should be recorded on the Regulator Station Inspection and
Maintenance Record (Form N-2527), whether on paper or electronic format. Records on vault
maintenance shall be retained for the life of the vault.
MAINTENANCE REV. NO. 5
VAULT MAINTENANCE DATE 01/01/24
XvIST'r STANDARDS 1 OF 1
utilities NATURAL GAS SPEC. 5.18

5.19 COMBUSTIBLE GAS INDICATOR TESTING AND CALIBRATION
SCOPE:
To establish procedures for operation, testing, and calibration of combustible gas indicators used to
detect and classify leakage from Avista's pipelines and facilities.
REGULATORY REQUIREMENTS:
§192.706, §192.723
WAC 480-93-186, 480-93-18601, 480-93-187, 480-93-188
CORRESPONDING STANDARDS:
Spec. 5.11, Leak Survey
GESH Section 2, Leak Investigation
GESH Section 4, Emergency Procedures
GESH Section 17, Incident Investigation
General
Combustible gas indicators (CGIs)that are used for leak survey, leak classification, leak centering or
pinpointing, or leak detection shall be tested and calibrated monthly (12 times a year) not to exceed 45
days. Calibration and maintenance performed on these instruments shall be according to the
manufacturer's instructions.
Each instrument used shall be designed to detect natural gas (methane - CH4) and shall indicate by
analog or digital method the percentage gas in an air mixture. Some models also indicate the percentage
of Lower Explosive Limit(LEL). The instrument shall be intrinsically safe and rated for operation in a
Class I, Division I, Group C, and D atmospheres as defined by the National Electrical Code (NEC).
Instruments calibrated after a gas incident shall have the readings recorded and checked against the
previous calibration record to verify a change, if any, in the instruments' performance.
Batteries shall be checked before utilization and changed if the instrument will not zero or if it appears to
not be functioning properly.
Test gases shall be used in the concentrations recommended by the equipment manufacturer and shall
be certified as accurate within +/-2 percent of the indicated concentration of methane in air. An
appropriate test apparatus such as an "on demand" regulator or equivalent shall be used to provide a
sampling atmosphere of the required concentration.
Calibration Procedures
Combustible gas indicators (CGIs)that are used for leak survey, leak classification, leak centering or
pinpointing, or leak detection shall be calibrated according to the manufacturer's instructions and specific
to the docking station (if used) used for each device.
MAINTENANCE REV. NO. 10
CGI TESTING AND CALIBRATION DATE 01/01/25
Xv sm a STANDARDS 1 OF 2
utilities NATURAL GAS SPEC. 5.19

MAINTENANCE FREQUENCIES:
Avista's combustible gas indicators shall be tested and calibrated according to the following schedule:
Instrument Interval
Monthly* (12 times a year and not to exceed 45
Bascom Turner(all models)or equivalent days) Note: If the CGI has been shipped off for
repair and is gone the entire month, it does not
need to be calibrated that month.
*Monthly means every calendar month. A late in the month calibration does not allow waiting the full
45 days and skipping a calibration the next calendar month. An early in the month calibration (ex. the
first day of the month)will be out of calibration after the 16th day of the next month.
Recordkeeping
Instrument test and calibration results shall be recorded on the appropriate instrument test form (Form N-
2605) and retained in the local construction office (Avista CGIs) and in the respective contractor office
(contractor CGIs)for a minimum of 5 years. Electronic copies of the forms should be forwarded via email
monthly by the last day of the calendar month to#GasComplianceTechs(LDavistacorg.com.
MAINTENANCE REV. NO. 10
CGI TESTING AND CALIBRATION DATE 01/01/25
XvISTA STANDARDS 2 OF 2
utilities NATURAL GAS SPEC. 5.19

5.20 ATMOSPHERIC CORROSION CONTROL
SCOPE:
To establish uniform procedures for the monitoring of metallic pipelines for atmospheric corrosion.
REGULATORY REQUIREMENTS:
§192.479, §192.481, §192.491
WAC 480-93-110
CORRESPONDING STANDARDS:
Spec. 2.12, Pipe Design —Steel
Spec. 2.22, Meter Design
Spec. 3.42, Casing and Conduit Installation
Spec. 3.12, Pipe Installation - Steel
Spec. 3.32, Repair of Steel Pipe
Spec. 3.44, Exposed Pipe Evaluation
ATMOSPHERIC CORROSION CONTROL:
General
Atmospheric Corrosion is the steady and gradual deterioration of the exposed surface of steel by
oxidation or chemical reaction with elements of the atmosphere or environment.
Oxidation of metal is the chemical process known as rusting. Rust is the first symptom of atmospheric
corrosion. If not treated, it may lead to further deterioration of the pipe depending on local atmospheric
conditions. In Avista's service territories, (which are for the most part dry climate environments), a certain
level of oxidation that discolors the pipe -- without the presence of metal loss-- is common and
generally does not require immediate remediation as allowed by§192.481. Facilities showing heavy
oxidation without metal loss are repaired on an as-needed basis to prevent further deterioration.
Pitting is a severe form of corrosion that occurs when a pipe becomes marked with small indentations, or
pits, in its surface. Pitting involves an actual loss in pipe wall thickness. Pitting can be caused by rust or
by reaction with other chemicals in the environment that attack the base metal of pipe and fittings.
Additional detail and supplemental information regarding the Atmospheric Corrosion Inspection Program
are covered in the Atmospheric Corrosion and Continuing Surveillance Program Orientation Manual.
Causes of Atmospheric Corrosion
Atmospheric corrosion (AC)occurs from exposure to natural forces that attack the base metal and
weaken the pipe.
It is caused by a chemical reaction between the pipe and its surrounding elements, such as:
• Air
• Moisture (rain, sleet, snow, fog, or condensation)
• Chemicals or pollutants in the environment
MAINTENANCE REV. NO. 6
ATMOSPHERIC CORROSION CONTROL DATE 01/01/24
XvIST'r STANDARDS 1 OF 4
utilities NATURAL GAS SPEC. 5.20

Inspection Requirements
Federal Code requires aboveground service piping shall be inspected at least once every 5 years not to
exceed 63 months, for evidence of atmospheric corrosion. The inspection can be accomplished by meter
readers, gas atmospheric corrosion/leak survey personnel, and other qualified gas field personnel. Most
typical aboveground piping includes meter sets and idle risers which are both found on services and
applicable to these inspection timeframes.
Single service farm taps, bridge crossings, regulator stations, and aboveground pipelines not susceptible
to movement are other examples of pipelines that require an atmospheric corrosion inspection. These
inspections occur at the frequencies described in Specification 5.10, Gas Maintenance Timeframes and
Matrix, and are completed by other qualified individuals outside of the Atmospheric Corrosion Inspection
Program that is administered by Avista's Gas Programs Department.
Besides the aboveground piping, other areas of concern to investigate during inspection are as follows:
• Piping/risers at ground surface levels (soil-to-air interface, especially tape wrap)
• Where meters are buried in soil (i.e., meter is in contact with underlying soil and/or landscape
materials). This excludes diaphragm meters AL 1400 and larger that are supported on non-
combustible material.
• Riser valves or threads that are below grade.
• Where coating is dis-bonded.
• Under pipe supports, particularly when evidence of corrosion (staining) is apparent.
• Where piping penetrates through bridge structures/deck penetrations.
• In spans over water and splash zones
Additionally, while the atmospheric corrosion inspection is being conducted, other areas of potential
concern can be observed that are outside the scope of the requirements of the §192.479 and §192.481
atmospheric corrosion inspections.
These include but are not limited to:
• Settling of facilities (Settled)
• Barricades lacking (Protection needed)
• Damage to facilities
• Overbuilds
• Service regulator vents not oriented downward
• Overgrown vegetation
• Other items that may eventually pose a hazard if not corrected
Can't Gain Entry/Can't Find
In the course of performing atmospheric corrosion inspections, survey technicians may encounter
situations where they Can't Gain Entry (CGE)to the customer's property (because of a locked gate or an
aggressive dog, etc.) or they Can't Find (CF)the gas meter to successfully complete the survey. Specific
processes for CGE and CF follow up attempts by the survey contractor are detailed in the Atmospheric
Corrosion Orientation Manual (updated annually). If the follow up attempts required by the contractor are
unsuccessful a service order is then generated, and Avista Gas Operations completes the survey.
MAINTENANCE REV. NO. 6
ATMOSPHERIC CORROSION CONTROL DATE 01/01/24
Xv sm a STANDARDS 2 OF 4
utilities NATURAL GAS SPEC. 5.20

Remediation
Aboveground facilities that require repainting or recoating should have remedial action completed
according to the AC Corrective Order Types and Remediation Time Guidelines Table 5 within this
Specification.
Facilities reported for metal-loss corrosion shall be followed up to determine the remedial requirements.
Refer to Specification 3.32, Repair of Steel Pipe, or consult Gas Engineering for proper repair of corroded
pipe.
Sites that bear a light level of oxidation (orange/brown or white discoloration without metal loss) do not
require repainting. Sites that show heavy oxidation without metal loss should be repainted, as needed, to
prevent further deterioration.
Repainting is accomplished by cleaning the surface with mechanical means such as a wire brush and
then applying one coat of industrial grade spray primer/enamel paint. Care should be exercised to
perform painting in accordance with manufacturer's instructions, paying attention to guidance on ambient
temperature and when it is too cold to perform painting operations. This procedure is suitable for the
prevention of atmospheric corrosion.
Aboveground facilities such as bridge crossings that require permits or necessitate special coordination
shall be remediated as soon as practical.
For all other concerns found, remedial actions should be completed as indicated in the AC Corrective
Order Types and Remediation Time Guidelines Table. Refer to the Program Manager for questions
regarding the urgency of questionable situations.
Insufficient Wrap on Steel Risers
The wrap on steel risers should be visible above grade level and be well bonded to the steel riser. If
insufficient wrap is discovered, the riser shall be excavated down until well bonded wrap can be found /
adhered to, and then rewrapped to the above grade level per the requirements in Specification 3.12, Pipe
Installation —Steel Mains, Tape Wrap.
MAINTENANCE REV. NO. 6
ATMOSPHERIC CORROSION CONTROL DATE 01/01/24
Xv sm a STANDARDS 3 OF 4
utilities NATURAL GAS SPEC. 5.20

AC Corrective Order Types and Remediation Time Guidelines
Table 1
The order/job types in Table 1 should be completed within 30 days of the inspection date to facilitate
meeting future Not to Exceed (NTE) inspection/compliance dates.
Order Type Order Routing
Atmospheric Corrosion—Can't Gain Entry Service A071
Atmospheric Corrosion—Can't Find Service A069
Atmospheric Corrosion—Unins ected Overbuilt, Overgrown, Debris Service A086
Atmospheric Corrosion—Damaged Riser Job K082
Table 2
The order/job types in Table 2 shall be completed within 1 year in ID and OR and 90 days in WA.
A best practice in ID and OR is to manage completion of the order to the 90-day WA standard.
Order Type Order Routing
Atmospheric Corrosion—Buried Meter Service A080
Atmospheric Corrosion—Buried Riser Service A084
Atmospheric Corrosion—Buried Riser Job K080
Atmospheric Corrosion—Corroded metal loss Service A052
Atmospheric Corrosion—Corroded metal loss Job(K064)
Table 3
The order/job types in Table 3 should be completed end of year following ins ection year Year 2
Order Type Order Routing
Atmospheric Corrosion—Needs Wrap Service A070
Atmospheric Corrosion—Riser in Concrete/Needs Wrap Job K055
Table 4
The order/job types in Table 4 are pant of the A/C-Continuing Surveillance program. A best practice is to
complete these order types end of year preceding next inspection year(Year 3)
Order Type Order Routing
A/C—Continuing Surveillance—Other Service A051
A/C—Continuing Surveillance—Settled Service A046
A/C—Continuing Surveillance—Overgrown Service A056
A/C—Continuing Surveillance—Other Job K062
A/C—Continuing Surveillance—Protection Needed Job K054
A/C—Continuing Surveillance—Overbuilt/Inspected Job K051
Table 5
The order/job types in Table 5 should be completed,as needed,or end of year preceding next inspection
year(Year3)
Order Type Order Routing
Repainting heavily oxidized facilities without metal loss Service
Recordkeeping
Since 2008, the Atmospheric Corrosion Program records, electronic or paper, are maintained at the
Avista corporate headquarters or Jimmie Dean Center. Historical records may be held at each local
construction office. The last two surveys covering a minimum of five years shall be retained. All corrosion
repair documentation shall be retained for the life of the facility.
Blowing Gas and Odor Calls
For information on recording the appropriate information on blowing gas and odor calls refer to the Gas
Emergency and Service Handbook, Section 2—Leak and Odor Investigation.
MAINTENANCE REV. NO. 6
ATMOSPHERIC CORROSION CONTROL DATE 01/01/24
XvIST'r STANDARDS 4 OF 4
utilities NATURAL GAS SPEC. 5.20

5.21 MAINTENANCE OF PRESSURE GAUGES AND RECORDERS
SCOPE:
To establish procedures and specifications for the maintenance and calibration/verification of pressure
testing and gauging devices used by Avista's field personnel and contractors.
REGULATORY REQUIREMENTS:
§192.501, §192.503, §192.505, §192.507, §192.509, §192.511, §192.513, §192.515, §192.517, §192.741
WAC 480-93-170
OAR 860-023-0035, OAR 860-023-0040
OTHER REFERENCES:
ANSI B40.1
NEC Article 500
CORRESPONDING STANDARDS:
Spec. 2.22, Meter Design
Spec. 3.18, Pressure Testing
Spec. 5.10, Gas Maintenance Timeframes & Matrix
Spec. 5.12, Regulator and Relief Inspection
General
Pressure gauges and pressure recorders are used to determine existing distribution system pressures,
pressure testing of facilities and to assist in making proper adjustments to customer meter sets, district
regulator stations, farm taps, and other gas facilities or systems. Only qualified and properly trained
individuals shall use pressure gauges or pressure recorders to make determinations or adjustments on
Avista's facilities.
Pressure gauges are typically handheld units that are designed to be portable and allow instant checking
of pressures. Pressure recorders are designed to be temporarily or permanently installed at a gas meter or
facility to provide graphic or electronic documentation of instantaneous pressure of pressure changes over
a pre-determined period of time. Both pressure gauges and pressure recorders may be installed by the
use of fittings or by the temporary use of"Pete's Plug" style pressure taps.
Applicable personnel have the option of testing (verifying) pressure gauges on a test apparatus (Test
Bench) in the construction office or sending the gauges to a certified testing lab. Preference is for the
verification to occur at the test bench in the construction office nearest their home base for the cost
savings it will afford. Pressure recorders are typically calibrated at the Gas Meter Shops in Spokane or
Medford.
Types of Pressure Gauges
Digital Pressure Gauge - Modern digital pressure gauges combine electronic pressure transducers with
microprocessors to determine the pressure being measured. Incremental changes in the position of the
transducer diaphragm are converted to electrical signals which are processed and displayed on a LCD
display. The gauges are normally battery powered.
Minimum display increments (resolution) shall either be in one-tenth (0.1) or one-half(0.5) psig (or inches
of water column as applicable) increments.
MAINTENANCE REV. NO. 15
PRESSURE GAUGES AND RECORDERS DATE 01/01/25
Xv sm a STANDARDS 1 OF 9
I i►ities SPEC. 5.21
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Some examples of digital pressure gauges being used by Avista are the Crystal XP2i for psig and the UEI
EM201 B for inches of water column.
If a Crystal digital psig gauge is over pressured beyond 200 percent of its rated pressure range, it is
recommended that the gauge be verified to ensure there was not a shift in calibration. Consult other
manufacturers for their recommendations regarding over pressurization of their gauges.
The UEI EM201 B digital manometer can only tolerate extremely minor over pressures of 2 inches water
column (WC) above its 60-inch WC range and damage occurs at 64 inches WC.
Typical operating temperature ranges for digital gauges such as the Crystal XP2i are 140F to 122°F. The
UEI EM201 B digital manometer's operating temperature is 320F to 104°F. Common practice is to keep the
gauge in the heated space in a vehicle.
Bourdon Tube Pressure Gauge— Bourdon Tube gauges uses a thin-walled tube that is normally made
from a copper alloy(brass) or stainless steel, depending on the application. This tube is called the
element. The element is either bent into a semicircle (C-shaped tube)or spirally wound (coiled safety
tube). When pressure is applied to the inside of the tube via the pressure port, the pressure tends to make
the Bourdon Tube straighten itself, causing the end piece to move upward. The movement of the end
piece is transmitted via the link to the movement. The movement converts the linear motion of the end of
the Bourdon Tube into rotational movement. The rotational movement is what causes the pointer to
indicate the measured pressure.
Accuracy should be to ANSI B40.1 Grade B or better. ANSI B40.1 — 1974 indicates that the permissible
error shall not exceed 2 percent of span at any point between 25 percent and 75 percent of span; in the
rest of the scale, 3 percent error is permissible. Bourdon Tube gauges shall indicate pressure in minimum
1 psig increments for psig gauges and shall indicate in 1-inch WC increments for inches water column
scales.
Bourdon Tube gauges, as well as other mechanical gauges, can be adversely affected by vibration and
oscillation.
The normal ambient temperature range for the Bourdon Tube gauges that Avista uses is-40F to +140°F.
The error caused by temperature changes is +0.3 percent or—0.3 percent per 180F rise or fall,
respectively. The reference temperature is 70°F. This means that at the colder end of the temperature
range (401F), the gauge may have a negative error of approximately 1.23 percent in addition to its normal
percent error rating. This fact should be kept in mind when performing inspections and adjustments in cold
weather.
Some examples of bourdon tube gauges being used by Avista are those manufactured by Perma-Cal,
typically their"Test Gauge" series with 0.25 percent of full-scale accuracy.
Spring and Diaphragm Gauges—Spring and diaphragm gauge purchases are not planned in the future as
they are being phased out. They often have a user-accessible screwdriver adjust for zeroing the gauge.
Some examples of diaphragm gauges being used by Avista are the Ashcroft 0-10 psig or 0-10 inches WC.
Manometers -Water manometers consist of a U-shaped tube that is mounted on a rigid base that is
delineated in inches. There is a valve on one end of the tube and an apparatus for connecting to the
pressure source on the other tube end. The tube is filled with water so that both sides of the tube line up
with the zero mark on the base. As pressure is applied to one end of the tube, the water level changes
correspondingly. A reading is taken from both sides and the sum of the readings (the difference between
the high side and low side) equals the pressure measurement in "inches of water column" or WC.
MAINTENANCE REV. NO. 15
PRESSURE GAUGES AND RECORDERS DATE 01/01/25
Xv sm a STANDARDS 2 OF 9
I i►ities SPEC. 5.21
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Since this is a direct physical measurement, no field calibrations are required aside from verifying the
water level is correct. Care must be taken to ensure that the manometer is upright and level before taking
the readings.
Electronic manometers combine a very sensitive electronic differential pressure sensor and
microprocessor to provide a very accurate (±1 percent of reading) and high resolution (> 0.01")
measurement in inches of water column (WC).
Manometer pressure measurements shall only be used when inspecting or adjusting meter set installations
that operate at inches of water column pressure.
Some examples of manometers being used by Avista are the water-based Alta-Robbins G211 U-tube and
the digital UEI EM201 B dual input differential manometer.
Types of Pressure Recorders
Electronic Pressure Recorders- Electronic pressure recorders combine pressure transducers with
microprocessors to convert the pressure being recorded into digital information.
Electronic pressure recorders typical temperature operating ranges are-40OF to 150OF with an overall
accuracy typically around±0.50 percent of span. They typically display the current pressure via an LCD
display. They may also record case temperature which is fairly close to ambient temperature and other
information such as maximum, minimum, and average pressures in their internal memory (audit trail)for
downloading to a computer or, when equipped with a modem, telemetering to our PI data historian or
SCADA system.
Examples of electronic pressure recorders used by Avista are the Mercury (now Honeywell) model ERX in
both portable and fixed versions.
Paper Chart Recorders - Paper chart recorders utilize an ink pen that creates a line on a circular chart,
thus indicating pressure with respect to time. A battery powered chart drive moves the circular paper chart
according to the timeframe specified (i.e., 1 hour, 24-hour, 7 day, 30 day, etc.). The ink pen is connected to
an arm that is attached to an element. Elements may normally be copper bellows (low pressure, up to 30
psig)or a stainless steel helical coil (for pressures over 30 psig). The elements expand or contract as
pressure fluctuates thus moving the arm and pen on the chart with a typical accuracy of±1/2 chart
graduation. The elements can normally withstand a 50 percent over-range and still retain accuracy. The
recorder is normally connected to the pressure source by a flexible hose and fittings. "Pete's Plug" style
quick check fittings can also be used for connection.
Paper chart recorders are in process of being phased out due to the inherent challenges with older
mechanical devices and the paper charts being exposed to the elements and being rendered unreadable.
CalibrationNerification Standard Device
The pressure standard is a high accuracy piece of test equipment that shall be used to verify the accuracy
of each construction office test bench gauges. It may also be used for calibration of field instrumentation
such as electronic pressure recorders and electronic volume correctors. It reduces pressure from an
internal or external high pressure nitrogen cylinder via adjustable regulation and an adjustable chamber to
provide a finely adjustable and stable outlet pressure measured by an internal digital pressure gauge.
Avista typically utilizes a Condec (previously Eaton) UPC5000 with three pressure ranges such as
2,000/1,000/400 psig or 1000/500/200 psig with an accuracy of 0.05 percent of full scale for the individual
range selected.
MAINTENANCE REV. NO. 15
PRESSURE GAUGES AND RECORDERS DATE 01/01/25
Xv sm a STANDARDS 3 OF 9
I i►ities SPEC. 5.21
NATURAL GAS

Test Benches
Test benches are an apparatus where annual verification of company and contractor gauges will take
place. Test bench design should be standardized across all applicable construction offices and will have a
sufficient number of high accuracy digital gauges to verify most pressure gauges being used by Avista
employees and contractors. The annual gauge verification of all pressure gauges will occur at the test
bench and will follow a documented process to include entry of essential gauge information in the
compliance data repository (Maximo).
Required Gauges by Job Type
Company and contractor personnel have need to use specific gauges based on their job responsibilities.
Following is a list of individual job descriptions and the typical minimum complement of pressure gauges
that are needed to do that job. (Note: There is not a firm requirement for individuals to purge their inventory
of gauges to achieve these minimum inventory values, rather these lists provide Operations Managers and
their personnel a reference of typical needs for the various company-wide positions).
Gas Serviceman:
. (1) 0-300 PSIG, Digital
• (1)Water Manometer
• (1) UEI Digital Manometer
• (1) 0-150 PSIG Perma-Cal Gauge
• (1) 0-600 PSIG Perma-Cal Gauge
Pressure Controlman:
• (1)Water Manometer
. (1) 0-300 PSIG, Digital
. (1) 0-1000 PSIG, Digital
. (1) 0-2000 PSIG, Digital
• (1) 0-15 PSIG, Digital
• (2) 0-10"WC (Ashcroft, Yellow Jacket or similar)
. (2) Differential Pressure Gauges
Gas Meterman:
• (2) 0-500 PSIG, Digital
• (1) UEI Digital Manometer
• (1)Water Manometer
• (1) 0-150 PSIG Perma-Cal Gauges
Company Gas Crew:
. (2) 0-150 PSIG Perma-Cal Gauges
• (1)Water Manometer
• (1) UEI Digital Manometer
Contract Gas Crew:
. (2) 0-150 PSIG Perma-Cal Gauges
• (1)Water Manometer
. (1) UEI Digital Manometer
Telemetry Technician:
• (1) Condec(Eaton) Portable Pressure Calibration Unit, UPC 5000
• (1) Crystal XP2i 0-1000 PSIG, Digital
• (1) Fluke 10OG Pressure Calibrator
• (1) Fluke 30G Pressure Calibrator
Inspector:
. (1) 0-150 PSIG Perma-Cal Gauges
List of Acceptable Gauges
MAINTENANCE REV. NO. 15
PRESSURE GAUGES AND RECORDERS DATE 01/01/25
XvISTA STANDARDS 4 OF 9
I i►ities SPEC. 5.21
NATURAL GAS

Following is the current list of recommended gauges for purchase by Company and contractor personnel:
• Perma-Cal "Test" gauges, full scale ranges to 2000 psig, accuracy: 0.25 percent full scale (bourdon
tube)
• Crystal XP2i, full scale ranges to 2000 psig, accuracy: 0-20 percent of range: 0.02 percent, 20-100
percent of range: 0.1 percent of reading (digital)
• UEI EM201 B for inches of water column (digital)
• Water manometer
• Others as approved by the Gauge Verification Process Owner, Design Manager. (Often as
recommended by the Capital Tools Committee)
The Gauge ID and Verification Sticker
Following is the procedure to uniquely identify each pressure gauge and to document the current
calibration status of the gauge:
• Each gauge shall have a self-adhesive long-life label affixed with Avista's name and the unique Avista
gauge ID number. The size should be as small as practical based on label printer capabilities and
space on the gauges. Numbering shall follow the convention of a GPG prefix which stands for Gas
Pressure Gauge, followed by a 5-digit number. (Example: GPG00171).
• Each gauge shall also have a self-adhesive long-life label (measuring approximately one inch square)
affixed to show the verification expiration date and the initials of the person that performed the
verification.
Responsibilities by Job Type
Following are the key roles and responsibilities of personnel supporting the gauge calibration and
verification program at Avista:
Meter Shop Foreman:
• Ensure calibration of the pressure calibration equipment such as the Condec/ Eaton pressure
calibrators as required in "Maintenance Frequencies" subsection below.
• Coordinate calibration of district test benches by Meter Technicians.
• Be available as a subject matter expert to the Test Bench Lead and Back-up Technicians.
Meter Technician:
• Visit each test bench annually, typically during first few weeks of the calendar year, to:
o Verify each reference pressure gauge on the test bench
o Document the pressure verifications in Maximo.
o Affix applicable calibration sticker/label to test bench gauges
o Train Test Bench Leads and Back-up Technicians
• Be available as a subject matter expert to the Test Bench Lead and Back-up Technicians.
Gauge Verification Process Owner:
• Act as the customer advocate for the gauge verification process by helping collaborate management
and stakeholder engagement.
• Work as applicable with management to ensure training, communication, and process execution
occurs.
• Facilitate "service level agreements" as applicable to focus efforts to improve the gauge verification
process.
• Serve as the primary point of contact for future proposed process changes including gauge inventory
change decisions.
• Ensure appropriate creation and maintenance of process documentation. Audit this documentation as
applicable.
• Escalate improvements that need to be made to the gauge verification process to applicable
management for resolution.
MAINTENANCE REV. NO. 15
PRESSURE GAUGES AND RECORDERS DATE 01/01/25
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utilities SPEC. 5.21
NATURAL GAS

• Collaborate with identified stakeholders to create, track, manage, and review gauge verification
metrics for process evaluation and improvement.
• If required, gather a cross-functional team to problem solve, complete root cause analysis, and
implement corrective actions.
Operations Managers:
• Designate the Lead and Back-up Gauge Verification Technicians for respective test bench in their
office.
• Ensure Test Bench Lead Technician, Back-up Technician, and Responsible Owners of gauges are
fulfilling their responsibilities under the program.
Test Bench Gauge Verification Lead Technician:
• Ensure test bench gauges are verified prior to verification of any gauges.
• Verify gauges of personnel /contractors in operations district.
• Ensure gauges have unique identification number affixed via stickers or labels.
• Document applicable information in Maximo.
• Affix applicable date verification sticker to gauges.
Test Bench Gauge Verification Back-up Technician:
• Fulfill the duties of the Test Bench Gauge Verification Lead Technician when that person is not
available.
Responsible Owner of the Gauge:
• Ensure annual verification of all assigned gauges is completed as required.
• Take responsible care of assigned gauges.
Test Bench Locations
Test benches are located at the following Avista operations sites:
• Jimmy Dean Center in Spokane, Washington
• Coeur d'Alene, Idaho
• Pullman, Washington
• Clarkston, Washington
• La Grande, Oregon
• Roseburg, Oregon
• Medford, Oregon
• Klamath Falls, Oregon
Test Bench Gauge Verification
Annual Test Bench Verification Procedure (i.e., the Test Bench's gauges): The Pressure Calibration
Standards (such as the Condec/ Eaton UPC5000 or approved equal) shall be sent to the manufacturer or
an approved instrumentation calibration facility annually for testing /calibration and documentation
including a certificate of calibration. Once calibrated, the Calibration Standard can be used to perform
verification of the reference pressure gauges on the Avista Test Benches.
Gas Meter Shop personnel shall visit each test bench and perform a verification of each reference
pressure gauge on the test bench. Alternatively, test bench gauges may be sent to an approved calibration
vendor. The serial number of the calibration standard device (as applicable) used to verify the test bench
gauges shall be noted in the records repository system (Maximo).
Each test bench reference pressure gauge shall be zeroed and then tested at 25, 50, 75, and 100 percent
of full scale gauge range. Perform these tests on the ascending pressure to 100 percent and descending
pressure back to zero. Acceptable tolerance is +/- 0.25 percent of full scale for the high accuracy digital
pressure gauges with a full-scale range greater than 15 psig. Pressure gauges with a full-scale range of 15
psig or less, shall be compared to a high accuracy digital pressure gauge of equal or better accuracy.
Acceptable tolerance is +/- 1.0 percent of full scale.
MAINTENANCE REV. NO. 15
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utilities SPEC. 5.21
NATURAL GAS

If a gauge is not within tolerance, it will either be calibrated to Avista's acceptable tolerance, or it will be
removed from service and replaced by a similar gauge already verified as acceptable.
Maximo information will be updated by Gas Meter Shop personnel to reflect either Pass or Fail for each
reference pressure gauge. If a gauge fails, notation should be made as to why it failed, and actions taken.
(Example: "gauge sent to vendor for repairs" or"gauge retired and removed from service".)
Each verified or calibrated reference pressure gauge shall receive a sticker identifying a one-year
validation date. Example: a gauge calibrated on 1/4/16 will have a 1/4/17 date on the verification sticker.
(Note: The date on the calibration sticker will reflect the"compliance due date" but in actuality, there will
still be three months until the grace date has been exceeded and the gauge has gone out of compliance.)
A unique Maximo Identification Number will be created and assigned to each reference pressure gauge by
the qualified individual. A sticker will be attached to the gauge showing this unique identifying number.
Manufacturer, pressure range, type, pass/fail status, and other pertinent information such as
manufacturer's serial number(as applicable)will be determined and recorded in Maximo by the qualified
individual.
Field Gauge Verification at Test Benches
Following is the procedure for annual verification of Company and contractor field gauges at the test
bench: Pressure gauges held by Company and contractor personnel should be verified once each
calendar year not to exceed 15 months at the Avista Test Bench located nearest to their primary work
location. Gauges may, however, be tested at any of the test bench locations noted above. Alternatively,
test bench gauges may be sent to an approved calibration vendor.
The verification of the pressure gauges shall be performed by trained and qualified individuals who are
familiar with the testing apparatus, procedures, and recordkeeping in Maximo. The primary individual
responsible for these duties at each site will be the Test Bench Gauge Verification Lead Technician. This
person's back-up will be the Test Bench Gauge Verification Back-Up Technician.
Each field pressure gauge shall be zeroed (if manually adjustable, corrected to read as close to zero as
possible) and then tested at 25, 50, 75, and 100 percent of full-scale gauge range. Perform these tests on
the ascending pressure to 100 percent and descending pressure back to zero. Acceptable tolerance is +/-
1 percent of full scale for psig gauges and +/- 5 percent of full scale for inches WC gauges.
If a gauge is not within tolerance, it will either be calibrated to Avista's acceptable tolerance, or it will be
removed from service and replaced by a similar gauge already verified as acceptable.
Maximo records will be updated to reflect either Pass or Fail for each gauge tested. If a gauge fails,
notation should be made as to why it failed, and actions taken. (Example: "gauge sent to vendor for
repairs"or"gauge retired and removed from service".) Updated information and status shall be made when
repairs are completed, or retirement of the pressure gauge is decided.
Each calibrated or verified reference pressure gauge shall receive a sticker/label identifying a one-year
validation date. Example: a gauge calibrated on 1/4/21 will have a 1/4/22 date on the verification sticker.
(Note: The date on the calibration sticker will reflect the "compliance due date" but in actuality, there will
still be three months until the grace date has been exceeded and the gauge has gone out of compliance.)
A unique Maximo Identification Number will be created and assigned to each pressure gauge by the
qualified individual. A sticker will be attached to the gauge showing this unique identifying number.
Manufacturer, pressure range, type, pass/fail status, and other pertinent information (such as
manufacturer's serial number) as applicable will be determined and recorded in Maximo by the qualified
individual.
MAINTENANCE REV. NO. 15
PRESSURE GAUGES AND RECORDERS DATE 01/01/25
Xv sm a STANDARDS 7 OF 9
I i►ities SPEC. 5.21
NATURAL GAS

Field Operating Guidelines for Pressure Gauges
Electrically powered portable digital psig gauges shall be rated as "Intrinsically Safe" or suitable for use in
Class I Division 1 areas and shall conform to applicable requirements of the National Electric Code (NEC)
Article 500 for Hazardous (Classified) Locations or the equivalent. Electronic pressure recorders shall be
rated for at least a Class I Division 2 location.
A water manometer or digital low pressure gauge approved by Gas Engineering shall be used on inches
water column (WC) meter sets.
Accurate pressure gauges shall be used whenever performing any type of pressure inspections on
customer meter installations, district regulator stations, distribution and transmission pipelines, or any other
gas facility. Pressures may be monitored or tested using the following methods of connection:
• "Pete's Plug"type pressure taps;
• Solid pipe fitting connections (pipe fittings shall match pressure rating of the facility being tested);
• Tapered rubber cone (used for inches water column checks only);
• Custom made meter outlet test apparatus.
"Pete's Plug" pressure taps shall have a gasket installed in the seal cap and shall be checked for leakage
after testing. Defective taps shall be replaced.
Permanent pressure taps that utilize valves shall also be plugged or capped off when the pressure gauge
or recorder is removed.
Pressure gauges or recorders should be installed in a manner as to prevent damage to the gauge or
recorder. Recorders should not be placed in areas where there are corrosive chemicals, where there is a
high risk of vehicular damage, or where there could be an accumulation of ice or snow.
Pressure gauges and recorders should be properly stored in a protective case (or other means)to prevent
damage due to vibration, shock, exposure to the elements, etc.
"Pete's Plug" insertion male probes and other test apparatus orifices shall be inspected periodically to
determine if there is a blockage that could affect accurate pressure readings. Any defective fittings or
probes shall be replaced.
Protective covers, caps, or inserts shall be replaced in the probe or instrument to prevent damage or entry
of foreign materials.
Pressure gauges shall be inspected prior to use for any apparent physical damage and to determine that
the pointer or digital display is at zero. Gauges that show signs of physical damage or have been
mishandled (dropped)shall be removed from service until a pressure verification can be performed to
validate accuracy of the device. If checked and found accurate, it need not be re-tagged with a new date
and may continue to be tested on the original cycle.
Gauges that do not read zero shall be removed from service until a pressure verification is performed to
validate their accuracy which will include a zero adjustment by test bench personnel during verification.
Field adjustment back to zero without test bench full range verification is not acceptable.
Liquid filled pressure gauges that have lost liquid or are damaged shall be replaced. Liquid filled gauges
should not be purchased in the future as they are being phased out.
Field Operating Guidelines for Pressure Recorders
MAINTENANCE REV. NO. 15
PRESSURE GAUGES AND RECORDERS DATE 01/01/25
Xv sm a STANDARDS 8 OF 9
I i►ities SPEC. 5.21
NATURAL GAS

Employees shall verify the circular paper chart is of the correct pressure range and that the brand is
compatible with the pressure recorder(as applicable). This shall be done prior to setting the recorder.
Batteries shall be checked on the pressure recorder chart drive prior to installation. The batteries are
typically replaced annually. The chart drive shall be checked to verify the period selector coincides with the
time period required, as well as with the time period indicated on the circular paper chart.
Pressure recorder pens shall be checked for sufficient ink prior to use and typically shall be refilled or
replaced. Pressure recorders shall be transported in a secure manner and shall be protected from
damage.
Pressure recorders shall be inspected prior to use for any apparent physical damage and to determine that
the pointer or digital display is at zero. Recorders that show signs of physical damage or have been
mishandled (dropped)shall be removed from service until a pressure verification can be performed to
validate accuracy of the device. If checked and found accurate, it need not be re-tagged with a new date
and may continue to be tested on the original cycle.
Employees shall inspect pressure recorder hoses and fittings after installation in order to determine if there
are any leaks. Leaks shall be repaired prior to leaving the premises.
MAINTENANCE FREQUENCIES:
Pressure gauges, standards, and pressure recorders shall be calibrated or verified for accuracy according
to the following schedule:
Type of Instrument Frequency
Pressure Gauges Once each calendar year Not to exceed 15 months
Pressure Recorders Once each calendar year(Not to exceed 15 months), or in
accordance with manufacturer's recommendations
Pressure Calibration Standards Once each calendar year Not to exceed 15 months
Recordkeeping
Verification /calibration of pressure standards, gauges, and pressure recorders should be first
documented at the main test bench workbook in the construction office where used. The applicable
information will then be transferred to the electronic data repository (Maximo).
State utility commissions require a calibration /verification sticker or label on the pressure gauge or
recorder. Care shall be exercised to ensure that gauge stickers remain affixed to the gauge and in
readable condition. Gauges with missing or unreadable calibration stickers shall no longer be used until
the sticker is replaced / updated or the gauge is re-verified as applicable.
Pressure gauges, recorders, and calibration standards shall be tagged with the verification expiration date
which is subject to the grace periods offered by the definition of timeframes noted in Specification 5.10,
Gas Maintenance Timeframes & Matrix.
MAINTENANCE REV. NO. 15
PRESSURE GAUGES AND RECORDERS DATE 01/01/25
XvISTA STANDARDS 9 OF 9
I i►ities SPEC. 5.21
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5.22 HEATER MAINTENANCE
SCOPE:
To establish uniform procedures for maintaining gas line and pilot line heaters to ensure safe and reliable
operation.
REGULATORY REQUIREMENTS:
§192.605, §192.739
CORRESPONDING STANDARDS:
None
General
Avista operates two types of gas heaters. "Line Heaters"that heat the entire gas stream and "Pilot Line
Heaters"which heat a secondary stream used to operate regulator pilots. Gas heaters are required to
prevent external ice buildup on gas piping and/or hydrate formation inside the piping. Ice or hydrates will
typically form when the gas temperature is less than 32 degrees F and liquid, or moisture is present.
Heaters counter the Joule-Thomson effect that lowers the gas temperature incrementally with a decrease
in gas pressure. The Joule-Thomson effect will lower the temperature of natural gas approximately
7 degrees F for every 100 psi reduction in pressure.
Proper operation of heating equipment is important to prevent hydrate and ice buildup which can lead to
excessive pipe strain, ground freezing, and improper operation of regulator pilots.
LINE HEATERS
Operation
Line heaters should be operated and maintained in accordance with the manufacturer's instructions and
this specification. Flame management systems should not be modified without concurrence with Gas
Engineering.
Avista's current line heaters are indirect water-glycol fire tube heaters. The gas stream enters the heater
through the inlet connection located on the opposite end from the firebox. The gas stream flows back and
forth in a serpentine fashion through a pipe coil mounted in the upper half of the unit. The water-glycol
bath is heated by a direct fired firebox located in the lower half of the unit. This firebox is heated by
feeding a fuel gas stream to the natural draft burners in the firebox. The firebox heats the glycol to
approximately 150-180 degrees F. The water then exchanges heat with the gas passing through the coil
in the upper half of the unit.
The gas temperature is controlled by one of two temperature controllers. The first temperature controller
measures the glycol/water bath temperature in the line heater. The second controller measures the
temperature of the gas in the downstream piping. The temperature controllers will turn on and off the high
fire within the firebox of the heater, which in turn warms the glycol and transfers additional heat to the gas
stream.
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Typical Set Points:
• Glycol/Water bath — 180 degrees F Max
• Downstream gas temperature - 120-140 degrees F
• Regulators— Per manufacturer's instructions
Maintenance
The following items should be checked at the intervals specified.
Maintenance Item Maintenance Interval Corrective Action
Leak Ins ection Monthly Repair any leaking equipment or fittings.
Operation Monthly Verify proper set points and unit is
operating ro erl —Adjust as required
Water/Glycol Level Monthly Fill with Water/Glycol 50/50 solution.
Water/Glycol Constituents Sample Annually or If sampling, make chemistry corrections.
Replace every 3 years Always sample when the heater is hot.
Pilot Safety Test Annually, not to Repair/Adjust.
exceed 15 months
High Temperature Annually, not to Verify proper operation. Repair/Adjust, as
Shutdown Thermostat Test exceed 15 months necessary.
Flame Arrestor Annually, not to Remove cover and blow Air through Flame
Clean/Inspection exceed 15 months Cell to clean.
Heating Coil Inspection 10 years Remove heating coil and inspect for
corrosion. Replace if necessary.
Indirect gas fired heaters should be filled with a 50/50 water/glycol solution. The water/glycol solution is
the heat transfer medium between the firebox and the line gas. Either Ethylene or Propylene Glycol may
be used, although Propylene Glycol should be used in all new installations because of its lower toxicity.
The solutions should not be mixed to ensure proper chemical analysis. The preferred solution is Dow
Ambitrol NTF 50.
The heat transfer medium should be present in the sight glass. If low, additional fluid consisting of 50/50
water/glycol should be added. The heat transfer medium should be replaced every 3 years or sampled
annually to ensure it has the proper level of corrosion inhibitor. Chemistry corrections should be made as
indicated by the analysis.
FLUID SAMPLING PROCEDURES:
1) Ensure that the system is warm. The system must be heated to get a representative sample since
the heat in the unit allows thermal mixing of the fluid.
2) When acquiring the sample run the fluid until the fluid trapped in the sampling point has been
cleared to ensure a representative sample. Protect yourself from the heated fluid.
3) Follow the sampling procedure contained with the kit. Fill the sampling bottle, leaving
approximately 1-inch of air space.
4) Sampling kits can be acquired from Dow Chemical at 800-447-4369.
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PILOT LINE HEATERS
Avista's existing pilot line heaters are a catalytic style. The pilot line heaters are used to heat the gas that
is supplied to pilot regulators. Heating the pilot gas reduces the likelihood of improper pilot regulator
operation due to icing or hydrate formation in the pilots. Pilot line heaters are typically used at stations
with pressure drops in excess of 250 psig.
Theory of Operation
Catalytic pilot line heaters work on the principle of oxidation with a catalyst which allows the reaction of
natural gas to occur at a lower temperature. Under normal conditions, natural gas will not burn unless its
temperature has been raised to approximately 1200 degrees F to 1400 degrees F. By forcing the gas to
pass through a bed impregnated with a platinum-based catalyst, catalytic heaters cause natural gas to
oxidize at approximately 250 degrees F. Once the catalytic heater is initiated, the heat of reaction
continues to build and stabilize between 650 degrees F to 900 degrees F.
Operation/Maintenance
Pilot line heaters should be operated and maintained in accordance with the manufacturer's instructions
and this specification.
The following items should be checked at the intervals specified:
Maintenance Item Maintenance Interval Corrective Action
Leak Inspection Annually, not to exceed Repair any leaking equipment or fittings.
15 months
Operation Annually, not to exceed Verify proper regulator set points and unit
15 months is operating proper) —adjust as required.
Recordkeeping
Maintenance activities for heaters shall be noted on the Heater Inspection and Maintenance Record
(Form N-2615), whether paper or electronic, and shall be retained for the life of the facility.
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5.23 ODORIZATION EQUIPMENT MAINTENANCE
SCOPE:
To establish uniform procedures for maintaining gas odorization equipment to ensure safe and reliable
operation.
REGULATORY REQUIREMENTS:
§192.625, §192.739
WAC 480-93-015
CORRESPONDING STANDARDS:
Spec. 4.18, Odorization Procedures
General
Avista operates three types of odorization equipment. The first type of odorizer is an "Injection Odorizer"
which injects odorant into the flowing gas in proportion to the gas flow rate. The second is a "By-Pass
Odorizer"that odorizes a portion of the gas stream to a high concentration that is then mixed with the
flowing gas to produce an acceptable odorant level. The third is a "Wick Odorizer" that is used on smaller
capacity systems or single services and incorporates a wick that odorizes the entire gas stream. Proper
operation of odorization equipment is important to ensure appropriate odorant concentrations and to
prevent odorant leaks within the odorization facilities.
INJECTION ODORIZERS (YZ Type)
Operation/Maintenance
Injection odorizers should be operated and maintained in accordance with the manufacturer's instructions
and this specification. Odorant systems should not be modified without concurrence with Gas Engineering.
Avista's current injection odorizers operate by injecting odorant into the main gas stream in proportion to
the gas flow rate. The equipment uses a pump to inject the odorant into the gas. A central processor unit
controls the operation of the injection system and determines the output of the pump based on a corrected
flow control signal from the mainline gas meter.
Typical Set Points:
• Expansion Tank Pressure—25 psig
• Gas Supply Pressure—70 psig
• Blanket Gas Pressure—30 to 35 psig
• Odorant Level— Maximum Capacity 90 Percent Full
• Injection Rate—0.36-0.72 Ibs/MMCF (Adjust as necessary based on odorometer testing)
Note: Variations may occur depending upon operating conditions that may lead to acceptable alternate set
points.
Maintenance
The following items should be checked at the intervals specified. Equipment shall be maintained in
accordance with manufacturer's recommendations. The manufacturer recommends that the preventative
maintenance schedules consider the application of the odorizer. Considerations related to preventative
maintenance intervals include weather/environment, the condition of the actuation gas, the odorant, the
odorant bulk storage tank, and the pump stroke frequency.
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Maintenance Item Maintenance Interval Corrective Action
Verify proper set points and unit is operating
Operation/Leak Monthly properly. Check system controller for alarms—
Inspection Adjust as required. Repair any leaking equipment
or fittings.
Odorant Level Monthly Inspect and fill, as necessary.
Bulk and Expansion Monthly Inspect expansion tank fluid level and pressure.
Tank Operation Service, as necessary.
Bulk and Expansion Inspect expansion tank and overflow protection
Tank Overflow Monthly regulators and relief for proper pressures.
Protection
Replace Filters As needed Replace as needed the "Bulk Odorant' and "Gas
Supply"filters. Replace based on unit operation.
Monthly Inspect Pump Oil Level, Fill, as necessary.
Injection Pump Once every calendar
Inspect and/or Rebuild Injection Pump.
year
Pump Solenoid - Once
Solenoids every calendar year Inspect and replace operational solenoids, as
Verometer Solenoid— necessary.
Once Every 2 years
Pneumatic Relay Onace every calendar Clean and service pneumatic relay.
ye
Once every calendar Test and service as necessary the "Expansion
Relief Valves Tank Low Pressure Relief' and the "Bulk Tank
year Relief Valve."
Supply Gas Farm Tap Once every calendar Inspect and repair gas supply regulator and relief
Regulator/ Relief year valve, as necessary. (Typically, this is a farm tap
style regulator and relief.)
Inject Pump - Once
every calendar year
Charcoal Scrubber Expansion Tank Replace, as necessary.
Overflow—Once every
2 years
Battery Once every 2 years Replace system controller battery.
Pneumatic Valve Once every 2 years Inspect and/or Replace "Pneumatic Relay Valve".
BY-PASS ODORIZERS
By-pass odorizers are used to odorize medium sized gas systems. The odorizers are typically installed
below grade at gate stations.
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Theory of Operation
A very small amount of the mainstream natural gas is by-passed through the odorizing unit. The resulting
odorant-laden gas is returned to the gas main to mix with the major portion of the gas flow. As the by-
passed gas passes through the odorizer it absorbs enough odorant to provide the desired odor intensity
for the entire gas stream when the gas is reintroduced and mixes with the main gas supply.
Typically, a partially closed valve is used to develop the differential pressure required to operate the
odorizer and maintain a direct relationship between the volume by-passed and the total volume flowing in
the main. Precision Control Valves are used to adjust and accurately control the odorization rate.
Operation/Maintenance
By-pass odorizers should be operated and maintained in accordance with the manufacturer's instructions
and this specification.
Typical Set Points:
Differential Pressure: 30-80 inches water column (WC). The following items should be checked at the
intervals specified.
Maintenance Item Maintenance Interval Corrective Action
Leak Inspection/Operation Monthly Repair any leaking equipment or fittings. Verify unit is
operating properly.Adjust or repair, as necessary.
Odorant Level Monthly Inspect and fill, as necessary.
WICK ODORIZERS
Wick odorizers are used to odorize small gas flows or single customers. The odorizers are installed on
above grade piping.
Theory of Operation
The entire gas stream flows past an odorant saturated wick that odorizes the gas stream. The wick
extends from a reservoir full of odorant to the gas pipeline.
The capillary action of the odorant continuously feeds odorant through the wick system from the reservoir
to the gas stream. The concentration of odorant within the gas stream is adjusted by modifying the amount
of wick that extends within the flowing gas.
Operation/Maintenance
Wick odorizers should be operated and maintained in accordance with the manufacturer's instructions and
this specification.
Typical Set Points:
Adjust wick length as necessary to achieve desired odorant level. The following items should be checked
at the intervals specified.
Maintenance Item Maintenance Interval Corrective Action
Leak Inspection/Operation Monthly Repair any leaking equipment or fittings.Verify unit is
operating properly.Adjust or repair, as necessary.
Odorant Level Monthly Inspect and fill, as necessary.
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Odorant Transport
Odorant is transported to the bulk delivery sites by Avista's designated contractor. Avista personnel may
transport odorant from these bulk sites in the contractor's sealed containers or in Avista's DOT approved
portable odorant tanks.
When transporting odorant via Avista's DOT approved portable odorant tanks, the vehicle towing the
trailers must have a hazardous material certification. In addition, because the trailers weigh over 1000
pounds they must be placarded with "3336" Flammable Liquids, along with the vehicle towing the trailer.
The appropriate Safety Data Sheets (SDS), bill of lading, tank test and inspection report, certificate of
registration, and vehicle inspection sheet shall be in the vehicle being used, additionally the bill of lading is
good for two years. Drivers of the vehicle must maintain a current CDL with hazmat and tank
endorsements. Contact the Avista Safety & Health Department for proper labels and SDS sheets.
Odorant Spills
Odorant spills shall be controlled and corrected immediately. An Avista-approved non-flammable, non-toxic
neutralizing agent shall be used.
Ground spills and indoor spills should be sprayed with the neutralizing agent as soon as possible. The
chemical will normally begin neutralizing mercaptan-based odorants upon contact. The solution should be
mixed according to manufacturer's instructions and can normally be applied using a spray bottle or with a
weed type garden sprayer in the case of larger spills. Care should be taken when cleaning spills as a
flammable atmosphere may exist as odorant is flammable. The atmosphere in an indoor spill situation
should be vented as you would with a natural gas leak.
Parts, equipment, clothing, and personnel may also be de-odorized using various solutions of neutralizing
agents. Consult the manufacturer's instructions before applying the agent to avoid possible risks to health.
Personal protective equipment(PPE) shall be used when indicated.
Safety and Health Department Notification
The Avista Safety and Health Department shall be notified in all cases in which odorant comes in
direct contact with Company personnel. In cases of large spills requiring disposal of contaminated
around, clothing, and other items, call Avista's 24 hour emergency contact number: [phone].
Spills may also be reported via radio through Avista's Gas Control Room in areas that do not have
cell phone coverage.
Mercaptan based odorants require respiratory, skin, and eye protection, and are listed as Hazardous
Materials in the Company SDS reference. Safety and/or Environmental Coordinators shall coordinate the
necessary reporting, referral for medical services, and disposal relating to odorants. The SDS data sheets
shall be immediately available to the field employee filling or maintaining odorization equipment.
Recordkeeping
A monthly volume odorization report shall be made on the Odorizer Inspection and Maintenance Record
(Form N-2621) as necessary for use in planning the re-filling or repair of odorizers. Copies of these records
(electronic or paper) shall be retained for a period of 5 years. The following information should be recorded
for each odorization station (except for farm tap installations):
• Manufacturer's designation of the odorant used
• Pounds of odorant used
Other maintenance activities for odorizers shall be recorded on the Odorizer Inspection and Maintenance
Record (Form N-2621). Copies of these records (electronic or paper) and retained for the life of the facility.
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