Annual Report for Gas Transmission and Gas Gathering Pipeline Operators

Instructions (rev 3-2022) for Form PHMSA F 7100.2-1 (rev 3-2022)

ANNUAL REPORT FOR CALENDAR YEAR 20
NATURAL AND OTHER GAS TRANSMISSION AND GATHERING PIPELINE SYSTEMS

GENERAL INSTRUCTIONS
All section references are to Title 49 of the Code of Federal Regulations (49 CFR). The Natural and
Other Gas Transmission and Gathering Pipeline Systems Annual Report has been revised as of calendar
year (CY) 2012 affecting submissions due in 2013 and beyond. This Annual Report is required per
§191.17 and must be filed per §191.7. Read through the Annual Report and instructions carefully before
beginning to complete the Report. Where common data elements exist between this Report and an
operator’s NPMS submission, the data submitted by the operator on their Annual Report should be the
same as the data submitted through NPMS when possible. PHMSA encourages gas transmission
operators to send their NPMS submission to PHMSA by March 15, representing pipeline assets as of
December 31 of the previous year.
Each operator of a transmission or Type A, B, and C gathering pipeline system must submit an Annual
Report for that system on DOT Form PHMSA 7100.2-1. Type R gas gathering is reported on Form
PHMSA F 7100.2-3. This report must be submitted each year, not later than March 15, and provide
information about the pipeline system as-of December 31 of the previous year. If an operator discovers
an error in a submitted annual report, a supplemental report should be filed. Changes made to the pipeline
system after the end of the reporting year should not result in a supplemental report. However, if an
operator finds records related to documenting gas transmission MAOP after the end of the reporting year
and these records result in a change in Part Q status from incomplete records to complete records, the
operator may choose to file a supplemental report to change Part Q.
The terms “operator,” “distribution line,” “gathering line,” “Maximum Allowable Operating Pressure
(MAOP),” “offshore,” “Outer Continental Shelf,” “pipe,” “pipeline,” “pipeline facility,” “specified
minimum yield strength (SMYS),” and “transmission line” are defined in §192.3. The terms
“assessment,” “high consequence area (HCA)”, and “moderate consequence area (MCA)” are defined in
§192.903. §192.8 describes how to identify onshore gathering lines and to determine if a gathering line is
subject to regulation (i.e., is a “regulated gathering line”). If an operator determines that its pipelines fall
under the definition for distribution lines, the operator should submit Form PHMSA F 7100.1-1 rather
than this Form PHMSA F 7100.2-1.
If you need copies of the Form PHMSA F 7100.2-1 and/or instructions, they can be found on
https://www.phmsa.dot.gov/forms/pipeline-forms. The documents are included in the section titled
Accident/Incident/Annual Reporting Forms.

ONLINE REPORTING REQUIREMENTS
Annual Reports must be submitted online through the PHMSA Portal at https://portal.phmsa.dot.gov/portal,
unless an alternate method is approved (see Alternate Reporting Methods below).
You will not be able to submit reports until you have met all of the Portal registration requirements – see
https://portal.phmsa.dot.gov/PHMSAPortal2/staticContentRedesign/howto/PortalAccountCreation.pdf
Completing these registration requirements could take several weeks. Plan ahead and register well in
advance of the report due date.

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Instructions (rev 3-2022) for Form PHMSA F 7100.2-1 (rev 3-2022)

ANNUAL REPORT FOR CALENDAR YEAR 20
NATURAL AND OTHER GAS TRANSMISSION AND GATHERING PIPELINE SYSTEMS

REPORTING METHOD
Use the following procedure for online reporting:
1. Go to the PHMSA Portal at https://portal.phmsa.dot.gov/portal
2. Enter PHMSA Portal Username and Password; press enter
3. Select OPID; press “continue” button.
4. Under “Create Reports” on the left side of the screen, under Annual select “Gas
Transmission and Gathering” and proceed with entering your data. Only one annual
report by commodity for an OPID may be submitted per year.
5. To save intermediate work without formally submitting it to PHMSA, click Save. To
modify a draft of an annual report that you saved, go to Saved Reports and click on Gas
Transmission and Gathering. Locate your saved report by the date, report year, or
commodity. Select the record by clicking on it once, and then click Modify above the
record.
6. Once all sections of the form have been completed, click on Validate to ensure all
required fields have been completed and data meets all other requirements. A list of errors
will be generated that must be fixed prior to submitting an Annual Report.
7. Click Submit when you have completed the Report (for either an Initial Report or a
Supplemental Report), and are ready to initiate formal submission of your Report to
PHMSA.
8. A confirmation message will appear that confirms a record has been successfully
submitted. To save or print a copy of your submission, go to Submitted Reports on the
left hand side, and click on Gas Transmission and Gathering. Locate your submitted
report by the date, report year, or Commodity Group, and then click on the PDF icon to
either open the file and print it, or save an electronic copy.
9. To submit a Supplemental Report, go to Submitted Reports on the left hand side, and
click on Gas Transmission and Gathering. Locate your submitted report by the date,
report year, or Commodity Group. Select the record by clicking on it once, and then click
“Create Supplemental”.
Alternate Reporting Methods
Operators for whom electronic reporting imposes an undue burden and hardship may submit a written
request for an alternative reporting method. Operators must follow the requirements in §191.7(d) to request
an alternative reporting method and must comply with any conditions imposed as part of PHMSA’s
approval of an alternate reporting method.

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Instructions (rev 3-2022) for Form PHMSA F 7100.2-1 (rev 3-2022)

ANNUAL REPORT FOR CALENDAR YEAR 20
NATURAL AND OTHER GAS TRANSMISSION AND GATHERING PIPELINE SYSTEMS

SPECIFIC INSTRUCTIONS
Make an entry in each block for which data is available. Estimate data only if necessary. Avoid entering
any data as UNKNOWN or 0 (zero) except where zero is appropriate to indicate that there were no
instances or amounts of the attribute being reported.
Do not report miles of pipe, pipe segments, or pipeline in feet. When mileage for the same set of pipelines
is reported in different parts of the form, the online system will require the different parts to be consistent.
Mileage values over 60 miles must be within 0.5% of the baseline and values under 60 miles must be within
0.3 miles for each of these categories: gas transmission onshore, gas transmission offshore, gas gathering
onshore Type A, gas gathering onshore Type B, and gas gathering offshore. For example, if you report 60
miles of onshore gas transmission in Part J, the onshore gas transmission mileage by diameter in Part H
must be within 0.3 miles of 60. Use the number of decimal places needed to satisfy these consistency
checks.
Part L will serve as the baseline for gas transmission miles in HCAs. When “in HCA” data is entered in
Parts Q and R, the values must be consistent with HCA miles entered in Part L. HCA mileage values over
50 must be within 0.2% of the baseline and values under 50 miles must be within 0.1 miles.
Enter the Calendar Year for which the Report is being filed, bearing in mind that the report should reflect
the system as-of the end of that calendar year.
The Initial Report or Supplemental Report box will be populated by the online system.
For a given OPID, a separate Annual Report is required for each Commodity Group within that
OPID. The separate Annual Report is to cover all pipeline facilities – both INTERstate and
INTRAstate – included within that OPID that serve to transport that Commodity Group. As an
example, if an operator uses a single OPID and has one set of pipeline facilities transporting natural
gas and another transporting landfill gas, this operator must file two Annual Reports – one Annual
Report covering natural gas facilities and a second for the landfill gas facilities. When a pipeline
facility transports two or more Commodity Groups, the pipeline facility should be reported only once
under the predominantly transported Commodity Group.

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Instructions (rev 3-2022) for Form PHMSA F 7100.2-1 (rev 3-2022)

ANNUAL REPORT FOR CALENDAR YEAR 20
NATURAL AND OTHER GAS TRANSMISSION AND GATHERING PIPELINE SYSTEMS

Part A is completed once for each Annual Report.
PART A – OPERATOR INFORMATION
Complete all sections of Part A before continuing to the next Part.
1. Operator’s 5-digit Identification Number (OPID)
For online entries, the OPID will automatically populate based on the selection you made when entering
the Portal. If you have log-in credentials for multiple OPID, be sure the report is being created for the
appropriate OPID. Contact PHMSA’s Information Resources Manager at 202-366-8075 if you need
assistance with an OPID.
2. Name of Operator
This is the company name associated with the OPID. For online entries, the name will be automatically
populated based on the OPID entered in A1. If the name that appears is not correct, you need to submit
an Operator Name Change (Type A) Notification.
If the company corresponding to the OPID is a subsidiary, enter the name of the parent company.
3. Reserved
4. Headquarters address
This is the headquarters address associated with the OPID. For online entries, the address will
automatically populate based on the OPID entered in A1. If the address that appears is not correct,
you need to change it in the online Contacts module.
5. This Report pertains to the following Commodity Group
It is a PHMSA requirement that operators submit separate Reports for each Commodity Group within
a particular OPID.
File a separate Annual Report for each of the following Commodity Groups:
Natural Gas
Synthetic Gas (such as manufactured gas based on naphtha)
Hydrogen Gas
Propane Gas
Landfill Gas (includes biogas)

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Instructions (rev 3-2022) for Form PHMSA F 7100.2-1 (rev 3-2022)

ANNUAL REPORT FOR CALENDAR YEAR 20
NATURAL AND OTHER GAS TRANSMISSION AND GATHERING PIPELINE SYSTEMS

Other Gas – If this Commodity Group is selected, report the name of the other gas in the space
provided.
Note: When a pipeline facility transports two or more of the above Commodity Groups, the pipeline
facility should be reported only once under the predominantly transported Commodity Group. For
example, if an operator has a pipeline segment that is used to transport natural gas during the majority of
the year and propane for a couple of weeks, that operator should only file an annual report for the natural
gas. If an operator has two pipeline segments with one pipeline segment used to transport natural gas and
the other pipeline segment transporting hydrogen gas, that operator should file two annual reports - 1
report for natural gas and 1 report for hydrogen gas.
6. Reserved
7. INTERstate and INTRAstate pipeline
For a given OPID, both INTERstate and INTRAstate pipeline facilities for a Commodity Group
can be entered in a single report. Enter each State and portion of the Outer Continental Shelf (OCS) for
both the INTERstate and INTRAstate pipeline facilities. The States and OCS options entered here create
the set of Parts H, I, J, K, L, M, P, Q, and R in the online reporting system. OCS options available for
selection are OCS – Alaska; OCS- Atlantic; OCS-Gulf of Mexico; and OCS – Pacific.
Interstate gas pipeline means a gas pipeline facility or that part of a gas pipeline facility that is used to
transport gas and is subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC)
under the Natural Gas Act (15 U.S.C. 717 et seq.).
Intrastate gas pipeline means a gas pipeline facility or that part of a gas pipeline facility that is used to
transport gas within a state and is not subject to the jurisdiction of FERC under the Natural Gas Act (15
U.S.C. 717 et seq.).
8. RESERVED

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Instructions (rev 3-2022) for Form PHMSA F 7100.2-1 (rev 3-2022)

ANNUAL REPORT FOR CALENDAR YEAR 20
NATURAL AND OTHER GAS TRANSMISSION AND GATHERING PIPELINE SYSTEMS

For the designated Commodity Group, complete Part C one time for all pipeline facilities – both
INTERstate or INTRAstate – included within this OPID. Parts B, B1, and D will be populated based
on information entered in Parts L, T, and P respectively.
PART B – TRANSMISSION PIPELINE HCA, MCA, and in neither HCA nor MCA MILES
In Part L of this report, the number of miles by category are reported by-State/OCS and by the
INTERstate/INTERstate status of the pipeline. All Part L data will be summed and displayed in Part B.
PART B1 – HCA MILES BY DETERMINATION METHOD AND RISK MODEL TYPE
In Part T of this report, the number of miles by category are reported by-State/OCS and by the
INTERstate/INTERstate status of the pipeline. All Part T data will be summed and displayed in Part B1.
PART C - VOLUME TRANSPORTED IN TRANSMISSION PIPELINES (ONLY)
IN MILLION SCF PER YEAR (excludes Transmission lines of Gas Distribution systems)
Report the volume transported in transmission pipelines during the calendar year for this Commodity
Group, in millions of standard cubic feet (60ºF and 14.73 psia). Include the annual total volume
transported for all States and for all pipelines and/or pipeline facilities – both INTERstate or INTRAstate
– included within this OPID and for this Commodity Group. Volumes of any Commodity Group
transported in addition to the Commodity Group predominately transported through these pipeline
facilities should also be reported in Part C within the proper row. For gas transmission pipelines within
storage fields, report the volume moved out of storage. Do not report the volume placed into storage.
Note: This Part does not need to be completed if the reporting OPID includes only gathering pipelines or
if the transmission line is operated by a gas distribution company as an integral part of its distribution
pipeline system. Operators whose pipelines are limited to these types should select the box to so indicate.
PART D – MILES OF PIPE BY MATERIAL AND CORROSION PREVENTION STATUS
In Part P of this report, the miles of pipeline by material type and corrosion prevention status are reported
by-State/OCS and by the INTERstate/INTRAstate status of the pipeline. All Part P data will be summed
and displayed in Part D.
PART E – RESERVED

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Instructions (rev 3-2022) for Form PHMSA F 7100.2-1 (rev 3-2022)

ANNUAL REPORT FOR CALENDAR YEAR 20
NATURAL AND OTHER GAS TRANSMISSION AND GATHERING PIPELINE SYSTEMS

Parts F and G are reported one time for INTERstate transmission assets and once for each State with
INTRAstate transmission.
PART F includes inspection, assessment, and repair data both within and outside HCAs and segments
subject to assessment under §192.710s. In Part L, the number of HCA and §192.710 miles is collected
by-State/OCS portion and by INTERstate/INTRAstate. The online system will provide Part F for
INTERSTATE assets only after an INTERstate Part L with transmission miles is created. Until HCA
or §192.710 miles are entered in an INTERstate Part L, the “within HCA” and “within §192.710”
portions of Part F will remain locked. For INTRAstate assets, a similar process is followed but Part
F will be created for each State with INTRAstate transmission.
Part G includes assessment data within an HCA or §192.710. Until HCA or §192.710 miles are
entered in the applicable Part L, these sections will remain locked.
PART F – INTEGRITY INSPECTIONS CONDUCTED AND ACTIONS TAKEN
BASED ON INSPECTION
This Part incorporates transmission pipeline integrity management performance measure reporting required
by §192.945 and ASME/ANSI B31.8S, Section 9.4(b) (incorporated into the regulations by reference),
items 1-3. Report all integrity assessments (inspections) required by PHMSA’s IM regulations which were
conducted and actions which were taken during the calendar year based on inspection results. Include all
inspections conducted in the reporting period calendar year including baseline assessments and reassessments. When Part F specifies “WITHIN AN HCA SEGMENT”, report only on transmission
miles within HCA segments. Do not report on transmission pipelines included in an IM Program as a
result of Alternative MAOP under 192.620 or a PHMSA directive such as Corrective Action Order,
Compliance Order, or Special Permit. Part F is subdivided into six (6) sections.
Section 1 - Mileage inspected in calendar year using the following In-Line Inspection (ILI)
tools.
Report the mileage inspected using each of the listed tool types. Include total miles
inspected, not just the mileage in HCA or §192.710. Where multiple ILI tools are used (e.g.,
a metal loss tool and a deformation tool), report the mileage in both categories. Where a
combination tool is used (i.e., a single tool with multiple capabilities), report the mileage
separately in each category included as part of the combination. Thus, the total mileage
inspected during the calendar year (the sum of the mileage reported for individual tools) may
be greater than the actual number of physical pipeline miles on which ILI inspections were
run.
Section 2 - Actions taken in calendar year based on In-Line Inspections.
Include all actions taken during the calendar year that resulted from information obtained
during an ILI inspection, including actions taken as a result of ILI inspections conducted
during prior years. Do not include actions which are anticipated based on review of ILI
results but which did not actually occur during the reporting year.

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Instructions (rev 3-2022) for Form PHMSA F 7100.2-1 (rev 3-2022)

ANNUAL REPORT FOR CALENDAR YEAR 20
NATURAL AND OTHER GAS TRANSMISSION AND GATHERING PIPELINE SYSTEMS

Report in items a. and b. the total number of anomalies excavated and repaired based on the
operator’s repair criteria even if those criteria are different from (i.e., require repair of
damage more or less significant than) the repair criteria in IM regulations.
Anomalies not excavated and eliminated by pipe replacement are reported in Parts F6.
Report in a. the total number of anomalies excavated, recognizing that multiple anomalies
may be exposed in a single excavation.
Report in b. only those anomalies actually repaired, not those for which other mitigative
actions, such as recoating, were taken.
Report in c. only the anomalies in HCA pipeline segments that were repaired and were
considered conditions under the repair criteria in the IM regulations. Scheduled conditions,
as used in c.4, refers to anomalies that are required to be repaired in accordance with the
schedule in ASME/ANSI B31.8S, section 7, Figure 4 (see §193.933(c)).
Report in d. only the conditions in §192.710 pipeline segments that were repaired.
Report in e. only the conditions WITHIN A CLASS LOCATION 3 OR 4 and neither HCA
nor §192.710.
Report in f. only the conditions WITHIN A CLASS LOCATION 1 OR 2 and neither HCA
nor §192.710.
The total of repaired conditions reported in items c, d, e, and f may not exceed the total
number of repaired anomalies reported in item b.
Enter a value in each row, using zero (0) as appropriate. Leave no rows blank.
Section 3 – Mileage inspected and actions taken in calendar year based on Pressure Testing.
In Section 3, report pressure tests and failures for pressure tests.
Report in a. total miles inspected by pressure testing.
b. will auto-populate with the sum of c, e, f, and g.
Report in c. the test failures (ruptures and leaks) repaired ONLY in HCA segments.
d. is not used.
Report in e. only the test failures (ruptures and leaks) repaired ONLY in §192.710 pipeline
segments.

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Instructions (rev 3-2022) for Form PHMSA F 7100.2-1 (rev 3-2022)

ANNUAL REPORT FOR CALENDAR YEAR 20
NATURAL AND OTHER GAS TRANSMISSION AND GATHERING PIPELINE SYSTEMS

Report in f. only the test failures (ruptures and leaks) repaired WITHIN A CLASS
LOCATION 3 OR 4 and neither HCA nor §192.710.
Report in g. only the test failures (ruptures and leaks) repaired WITHIN A CLASS
LOCATION 1 OR 2 and neither HCA nor §192.710.
Sections 4, 4.1, and 4.2
In section 4, report mileage inspected and actions taken in calendar year based on DA (Direct
Assessment).
Include all actions taken during the calendar year that resulted from information obtained
through external corrosion direct assessment, internal corrosion direct assessment, and stress
corrosion cracking direct assessment inspections. Include all actions taken during the
calendar year that resulted from information obtained during a DA inspection, including
actions taken as a result of DA inspections conducted during prior years. Do not include
actions which are anticipated based on DA inspection results but which did not actually
occur during the reporting year.
In section 4.1 report mileage inspected and actions taken based on Guided Wave
Ultrasonic Testing (GWUT).
Include all actions taken during the calendar year that resulted from information obtained
through GWUT. Include all actions taken during the calendar year that resulted from
information obtained during GWUT, including actions taken as a result of GWUT conducted
during prior years. Do not include actions which are anticipated based on GWUT results but
which did not actually occur during the reporting year.
In section 4.2, report mileage inspected and actions taken in calendar year based on
Direct Examination.
Include all actions taken during the calendar year that resulted from information obtained
through Direct Examination. Include all actions taken during the calendar year that resulted
from information obtained during Direct Examination, including actions taken as a result of
Direct Examination conducted during prior years. Do not include actions which are
anticipated based on Direct Examination results but which did not actually occur during the
reporting year.
The following instructions apply to sections 4, 4.1, and 4.2.
Report in b. the total number of anomalies excavated and repaired, not those for which other
mitigative actions, such as recoating, were taken, within an HCA or §192.710 segment and
outside an HCA or §192.710 segment based on the operator’s repair criteria even if those
criteria are different from (i.e., require repair of damage more or less significant than) the
repair criteria in IM regulations.

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Instructions (rev 3-2022) for Form PHMSA F 7100.2-1 (rev 3-2022)

ANNUAL REPORT FOR CALENDAR YEAR 20
NATURAL AND OTHER GAS TRANSMISSION AND GATHERING PIPELINE SYSTEMS

Report in c. only the anomalies in HCA pipeline segments that were repaired and were
considered conditions under the repair criteria in the IM regulations. Scheduled conditions,
as used in c.4, refers to anomalies that are required to be repaired in accordance with the
schedule in ASME/ANSI B31.8S, section 7, Figure 4 (see §193.933(c)).
Report in d. only the conditions in §192.710 pipeline segments that were repaired.
Report in e. only the conditions WITHIN A CLASS LOCATION 3 OR 4 and neither HCA
nor §192.710.
Report in f. only the conditions WITHIN A CLASS LOCATION 1 OR 2 and neither HCA
nor §192.710.
The total of repaired conditions reported in items c, d, e, and f may not exceed the total
number of repaired anomalies reported in item b.
Section 5 - Mileage inspected and actions taken in calendar year based on Other Inspection
Techniques.
IM regulations allow operators to use other assessment techniques provided that they notify
PHMSA (or states exercising regulatory jurisdiction) in advance. Report here the mileage
inspected and actions taken as a result of inspections conducted using any technique other
than those covered in Sections 1-4 of Part F. Describe the other technique(s) in the “specify”
field.
Include all actions taken during the calendar year that resulted from information obtained
during an inspection using an other technique including, actions taken as a result of
inspections conducted during prior years. Do not include actions which are anticipated based
on inspection results but which did not actually occur during the reporting year.
Report in b. only those anomalies actually repaired, not those for which other mitigative
actions, such as recoating, were undertaken.
Report in c. only the anomalies in HCA pipeline segments that were repaired and were
considered conditions under the repair criteria in the IM regulations. Scheduled conditions,
as used in c.4, refers to anomalies that are required to be repaired in accordance with the
schedule in ASME/ANSI B31.8S, section 7, Figure 4 (see §193.933(c)).
Report in d. only the conditions in §192.710 pipeline segments that were repaired.
Report in e. only the conditions WITHIN A CLASS LOCATION 3 OR 4 and neither HCA
nor §192.710.
Report in f. only the conditions WITHIN A CLASS LOCATION 1 OR 2 and neither HCA

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Instructions (rev 3-2022) for Form PHMSA F 7100.2-1 (rev 3-2022)

ANNUAL REPORT FOR CALENDAR YEAR 20
NATURAL AND OTHER GAS TRANSMISSION AND GATHERING PIPELINE SYSTEMS

nor §192.710.
The total of repaired conditions reported in items c, d, e, and f may not exceed the total
number of repaired anomalies reported in item b.
Section 6 - Total Mileage Inspected (all Methods) and Actions Taken.
Items a, b, c, f, i, and l will be calculated automatically based on data entered in sections 15.
Items d, e, g, h, j, k, m, and n require information about actionable anomalies eliminated by
pipe replacement and abandonment. An anomaly is considered actionable if it may exceed
acceptable limits, based on the operator’s anomaly and pipeline data analysis. Any anomaly
excavated and repaired should be reported in section 2 through 5. Do not report these
anomalies again in section 6. If pipeline facilities were abandoned and the operator replaced
the transportation functionality with new pipeline facilities, enter the anomalies in
replacement. If the transportation functionality of the abandoned facility was NOT replaced
by the operator, enter the anomalies in abandonment.
PART G – MILES OF BASELINE ASSESSMENTS AND REASSESSMENTS COMPLETED IN
CALENDAR YEAR (HCA, §192.710, and Outside HCA or §192.710 Segment miles)
Report the number of miles of pipeline that were assessed during the calendar year. Report separately the
number of miles inspected for baseline assessments (e.g., initial baseline assessments and new baseline
assessments, including those which occur due to new pipelines or facilities, new HCA, etc.) and miles for
which a reassessment was conducted. For segments outside both HCA and §192.710, assessment miles are
reported on a single line and are not characterized as baseline or reassessment. For the “in HCA” portions,
do not include pipelines or portions of pipelines that are not in an HCA but which are included in an IM
Program as a result of Alternative MAOP under 192.620 or a PHMSA directive such as Corrective Action
Order, Compliance Order, or Special Permit.
Report only assessments that were completed during the calendar year. An assessment is considered
complete on the date on which final field activities related to that assessment are performed, not including
repair activities. That is when a hydrostatic test is completed, when the last in-line inspection tool run of a
scheduled series of tool runs is performed, when the last direct examination associated with direct
assessment is made, or the date on which "other technology" for which an operator has provided timely
notification is conducted.
Operators should report in Part G the total number of miles actually assessed. This differs from Part F
where operators report the number of miles inspected by individual inspection methods and where some
mileage may be reported multiple times.

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Instructions (rev 3-2022) for Form PHMSA F 7100.2-1 (rev 3-2022)

ANNUAL REPORT FOR CALENDAR YEAR 20
NATURAL AND OTHER GAS TRANSMISSION AND GATHERING PIPELINE SYSTEMS

For the designated Commodity Group, complete PARTs H, I, J, K, L, M, P, Q, R, S, and T covering
INTERstate pipeline facilities for each State and each Outer Continental Shelf (OCS) option in which
INTERstate systems exist within this OPID. Report offshore pipelines in state waters in the State
portion. Separately report offshore pipelines on the OCS under one of the four OCS options; Alaska,
Atlantic, Gulf of Mexico, and Pacific. Complete all of these Parts again for INTRAstate pipeline
facilities in each State in which INTRAstate systems exist within this OPID.
For example: Consider a gas pipeline system that includes INTERstate pipeline facilities in six states
and the Gulf of Mexico OCS and INTRAstate pipeline facilities in three states. These Parts will be
completed ten times; – seven times for INTERstate assets (once for each state and once for OCS) and
once for the INTRAstate assets in three states.
Each time these Parts are completed, the online reporting
INTERstate/INTRAstate and State/OCS portion for the data.

system

will

show

the

When mileage for the same set of pipelines is reported in different parts of the form, the online system
will require the different parts to be consistent for each of these categories: gas transmission onshore,
gas transmission offshore, gas gathering onshore Type A, gas gathering onshore Type B, gas
gathering onshore Type C, and gas gathering offshore. Mileage values over 60 miles must be within
0.5% of the baseline and values under 60 miles must be within 0.3 miles. For example, if you report 60
miles of offshore gas gathering by decade of installation in Part J, the offshore gas gathering mileage by
diameter in Part I must be within 0.3 miles of 60.
Part K will serve as the baseline for gas transmission miles by class location. When class location miles are
entered in Parts Q and R, the values must be consistent with those entered in Part K.
Part L will serve as the baseline for gas transmission miles in HCAs. When “in HCA” data is entered in
Parts Q, R, and T, the values must be consistent with HCA miles entered in Part L. When “in MCA” data
is entered in Parts Q and R, the baseline is Part Q. HCA or MCA mileage values over 50 must be within
0.2% of the baseline and values under 50 miles must be within 0.1 miles.
PART H – MILES OF TRANSMISSION PIPE BY NOMINAL PIPE SIZE (NPS)
Report the miles of transmission pipe by Nominal Pipe Size (NPS) and location for both Onshore and
Offshore. Enter the appropriate mileage in the corresponding nominal size blocks. Only integers are used
for NPS. For example, report 6.625” diameter pipe in the NPS 6 category.
Pipe size which does not correspond to NPS measurements should be included in the “Other Pipe Sizes Not
Listed” columns. Include both the pipe size and the corresponding mileage.

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Instructions (rev 3-2022) for Form PHMSA F 7100.2-1 (rev 3-2022)

ANNUAL REPORT FOR CALENDAR YEAR 20
NATURAL AND OTHER GAS TRANSMISSION AND GATHERING PIPELINE SYSTEMS

PART I – MILES OF GATHERING PIPE BY NOMINAL PIPE SIZE (NPS)
Report the miles of gathering pipe by Nominal Pipe Size (NPS) and location for both Onshore and Offshore.
Report onshore Type A, Type B, and Type C gathering lines (§192.8) separately. Enter the appropriate
mileage in the corresponding nominal size blocks. Only integers are used for NPS. For example, report
6.625” diameter pipe in the NPS 6 category.
Pipe size which does not correspond to NPS measurements should be included in the “Other Pipe Sizes Not
Listed” columns. Include both the pipe size and the corresponding mileage.
PART J – MILES OF PIPE BY DECADE INSTALLED
Report the miles of pipe by decade installed. When the decade of construction is unknown, enter estimates
of the totals of such mileage in the “Unknown” section of Part J.
PART K – MILES OF TRANSMISSION PIPE BY SPECIFIED MINIMUM YIELD STRENGTH
Class locations are defined in §192.5. Report the total miles of gas transmission pipe by hoop stress (as
percent of SMYS) for pipe onshore and offshore by stress range and Class Location. Report pipe for
which hoop stress is unknown and all non-steel pipe, regardless of operating pressure, in the rows
indicated.
Pay close attention to the classification of each pipeline. Short segments of pipeline operated by distribution
systems at less than or equal to 20 percent SMYS have sometimes been inaccurately reported as
transmission lines. Unless such pipelines meet the definition of transmission lines in §192.3, they should
be reported as distribution pipelines (Form PHMSA F 7100.1-1). If pipelines operating at less than or equal
to 20 percent SMYS meet the definition of transmission lines, they should be reported here.
Miles by class locations from this part must be consistent with class location miles entered in Parts Q and
R.
PART L – MILES OF PIPE BY CLASS LOCATION
Gas transmission miles will be populated based on data entered in Part K. Report the number of Onshore
and Offshore miles of gas gathering pipe in each Class Location available on the form.
Report the number of HCA miles, §192.710 miles, Class Location 3 or 4 miles that are neither in HCA nor
in §192.710, and Class Location 1 or 2 miles that are neither in HCA nor in §192.710 for both Onshore and
Offshore transmission pipe. For HCA miles, do not include pipelines or portions of pipelines that are not
in an HCA but which are included in an IM Program as a result of Alternative MAOP under 192.620 or a
PHMSA directive such as Corrective Action Order, Compliance Order, or Special Permit.
Mile data entered in this Part will be summarized in Part B and affects the ability to enter data in Parts F
and G. HCA miles entered here must be consistent with HCA miles entered in Parts Q, R, and T.
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ANNUAL REPORT FOR CALENDAR YEAR 20
NATURAL AND OTHER GAS TRANSMISSION AND GATHERING PIPELINE SYSTEMS

PART M – FAILURES, LEAKS, AND REPAIRS
For the designated Commodity Group, this Part includes reporting for both pipeline facilities covered by
this OPID which are in HCAs, MCAs, as well as pipeline facilities that are not.
A “leak” is defined as a “leak or hazardous leak” as defined in 49 CFR 192.3, meaning any release of gas
from a pipeline that is uncontrolled at the time of discovery and is an existing, probable, or future hazard to
persons, property, or the environment, or any uncontrolled release of gas from a pipeline that is or can be
discovered using equipment, sight, sound, smell, or touch.
Grade 1, Grade 2, and Grade 3 leaks are defined in accordance with the criteria in § 192.760. Operators who
do not grade leaks for hazard, but rather promptly repair all leaks when found, need not grade repaired leaks
solely for the purpose of this report. Such operators treat all leaks as if grade 1. Operators who do not grade
leaks must report the same values for both total and grade 1 leaks for each cause.
Additional instructions are provided below.
PART M1 – ALL LEAKS ELIMINATED/REPAIRED IN CALENDAR YEAR; FAILURES IN
HCA IN CALENDAR YEAR
This Part incorporates transmission pipeline integrity management performance measure reporting required
by §192.945 and ASME/ANSI B31.8S, Section 9.4(b)(4) (incorporated into the regulations by reference),
along with reporting of all leaks that has historically been part of the Annual Report.
Include all leaks repaired or eliminated including by replaced pipe or other component during the calendar
year. Operators with pipe segments in HCA should report separately the number of leaks repaired or
eliminated in HCA in the appropriate columns. All operators should report onshore leaks for non-HCA
pipe segments in the appropriate column; either MCA, Class 3 & 4 non-HCA & non-MCA, or Class 1 & 2
non-HCA & non-MCA including all leaks on pipelines that contain no HCAs and all leaks in non-HCA
locations on pipelines in which HCAs exist. Do not include test failures.
Operators with pipe segments in HCA should also report the number of failures in HCAs, as required by
§192.945 and ASME/ANSI B31.8S, Section 9.4(b)(4).
Integrity management performance measures are not required for gathering pipelines. For gathering
pipelines, report only leaks. Report separately the number of leaks in Type A, Type B, and offshore
gathering pipelines.
Leaks are unintentional escapes of gas from the pipeline that are not reportable as Incidents under
§191.3. A non-hazardous release that can be eliminated by lubrication, adjustment, or tightening is not a
leak. Operators should report the number of leaks repaired based on the best data they have available. For
sections replaced and retired in place, operators should consider leak survey information to determine, to
the extent practical, the number of leaks in the replaced section.
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ANNUAL REPORT FOR CALENDAR YEAR 20
NATURAL AND OTHER GAS TRANSMISSION AND GATHERING PIPELINE SYSTEMS

Failure is defined in ASME/ANSI B31.8S as a general term used to imply that a part in service: has become
completely inoperable, is still operable but is incapable of satisfactorily performing its intended function;
or has deteriorated seriously, to the point that it has become unreliable or unsafe for continued use. Failures
that result in an unintentional release of gas should be reported as leaks.
Incidents are defined in §191.3 and are reported on Form PHMSA F 7100.2.
For the purposes of this Part M1, Leaks and Failures are to be classified as one of the following:
EXTERNAL CORROSION: includes releases or failures in the pipe or other component due to galvanic,
bacterial, chemical, stray current, or other corrosive action initiating on the outside surface of the pipe. This
includes the “External Corrosion” sub-cause on the PHMSA Gas Transmission/Gathering Incident Report
form.
INTERNAL CORROSION: includes releases or failures in the pipe or other component due to galvanic,
bacterial, chemical, stray current, or other corrosive action initiating on the inside surface of the pipe. This
includes the “Internal Corrosion” sub-cause on the PHMSA Gas Transmission/Gathering Incident Report
form.
STRESS CORROSION CRACKING: includes releases or failures resulting from a form of
environmental attack of the pipe metal involving an interaction of a local corrosive environment and tensile
stresses in the metal resulting in formation and growth of cracks. This includes the “Environmental
Cracking-related” sub-cause on the PHMSA Gas Transmission/Gathering Incident Report form.
MANUFACTURING: includes releases or failures caused by a defect or anomaly introduced during the
process of manufacturing the pipe, including seam defects and defects in the pipe body or pipe girth weld.
This includes the “Original Manufacturing Defect-related” sub-cause on the PHMSA Gas
Transmission/Gathering Incident Report form.
CONSTRUCTION: includes releases or failures caused by a dent, gouge, excessive stress, or some other
defect or anomaly introduced during the process of constructing, installing, or fabricating pipe (or welds
which are an integral part of pipe), including welding or other activities performed at the facility. This
includes the “Construction-, Installation-, or Fabrication-related” sub-cause on the PHMSA Gas
Transmission/Gathering Incident Report form.
EQUIPMENT: includes releases from or failures of items other than pipe or welds, and includes releases
or failures resulting from: malfunction of control/relief equipment including valves, regulators, or other
instrumentation; compressors or compressor-related equipment; various types of connectors, connections,
and appurtenances; the body of equipment, vessel plate, or other material (including those caused by:
construction-, installation-, or fabrication-related and original manufacturing-related defects or anomalies;
and low temperature embrittlement); and, all other equipment-related releases or failures. This includes all
of the sub-causes under G6, Equipment Failure, on the PHMSA Gas Transmission/Gathering Incident
Report form.
INCORRECT OPERATIONS: includes releases or failures resulting from operating, maintenance, repair,
or other errors by operator or operator contractor personnel, including, but not limited to improper valve
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ANNUAL REPORT FOR CALENDAR YEAR 20
NATURAL AND OTHER GAS TRANSMISSION AND GATHERING PIPELINE SYSTEMS

selection or operation, inadvertent overpressurization, or improper selection or installation of equipment.
This includes all of the sub-causes under G7, Incorrect Operations, on the PHMSA Gas
Transmission/Gathering Incident Report form.
THIRD PARTY DAMAGE/MECHANICAL DAMAGE: includes releases or failures resulting from
damage caused by earth moving or other equipment, tools, or vehicles which occurs as a result of excavation
activities or a release caused by vandalism or other similar intentional damage. Report separately, as
indicated:
Excavation Damage - includes releases or failures resulting directly from excavation
damage by operator's personnel (oftentimes referred to as “first party” excavation damage)
or by the operator’s contractor (oftentimes referred to as “second party” excavation damage)
or by people or contractors not associated with the operator (oftentimes referred to as “third
party” excavation damage) This includes the Excavation Damage by Operator (First Party),
Excavation Damage by Operator’s Contractor (Second Party), and Excavation Damage by
Third Party sub-causes on the PHMSA Gas Transmission/Gathering Incident Report form.
•

Previous Damage (due to Excavation Activity) - includes releases or failures that are
determined to have resulted from previous damage due to excavation activity. This includes
only the Previous Damage due to Excavation Activity sub-cause on the PHMSA Gas
Transmission/Gathering Incident Report form.

•

Vandalism (includes all Intentional Damage) – includes releases or failures due to willful
or malicious destruction of the operator’s pipeline facility or equipment. This includes only
the “Intentional Damage” sub-cause on the PHMSA Gas Transmission/Gathering Incident
Report form.

WEATHER RELATED/OTHER OUTSIDE FORCE DAMAGE: includes releases or failures resulting
from earth movement, earthquakes, landslides, subsidence, lightning, heavy rains/floods, washouts,
flotation, mudslide, scouring, temperature, frost heave, frozen components, high winds, or similar natural
causes, or a release from other, non-excavation-related outside forces, such as nearby industrial, man-made,
or other fire or explosion; damage by vehicles, boats, fishing or maritime vessels or equipment; and,
electrical arcing. Report separately, as indicated:
•

Natural Force Damage (all) - This includes all of the sub-causes under G2, Natural Force
Damage, on the PHMSA Gas Transmission/Gathering Incident Report form.

•

Other Outside Force Damage (excluding Vandalism and all Intentional Damage) - This
includes all of the sub-causes under G4 – Other Outside Force Damage except Intentional
Damage, on the PHMSA Gas Transmission/Gathering Incident Report form.

OTHER: includes releases or failures resulting from any other cause not listed above, including those of
a miscellaneous or unknown or unknowable nature. This includes both of the two sub-causes under G8,
Other Incident Cause, on the PHMSA Gas Transmission/Gathering Incident Report form.

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ANNUAL REPORT FOR CALENDAR YEAR 20
NATURAL AND OTHER GAS TRANSMISSION AND GATHERING PIPELINE SYSTEMS

PART M2 –KNOWN SYSTEM LEAKS AT END OF YEAR SCHEDULED FOR REPAIR
Include all known leaks scheduled for elimination by repairing or by replacing pipe or some other
component, indicating separately for transmission lines and gathering lines.
PART M3 –LEAKS ON FEDERAL LAND OR OCS REPAIRED OR SCHEDULED FOR
REPAIR
FEDERAL LANDS means all lands owned by the United States except lands in the National Park System,
lands held in trust for an Indian or Indian tribe, and lands on the Outer Continental Shelf (OCS), as defined
in 30 USC 185.
Enter all leaks repaired, eliminated, or scheduled for repair during the reporting year, excluding those
reported as incidents on Form PHMSA F 7100.2.

PART M3PART M4 –LEAKS DISCOVERED ON THE PIPELINE DUE TO CORROSION
OR MATERIAL/WELD FAILURE BY MATERIAL
Report the number of leaks discovered on piping, including welds, caused by external corrosion, internal
corrosion, stress-corrosion cracking, manufacturing, or construction. See the instructions for Part M1 for
guidance on classifying these causes.
See the instructions in part P for guidance on classifying pipe material.
Do not include leaks from equipment failure or leaks from causes other than those listed above.
PART M5 – GAS TRANSMISSION LEAKS DISCOVERED DURING CALENDAR YEAR

For gas transmission pipelines, report the number of leaks discovered during the calendar year by grade and
by cause. See the instructions for Part M1 for guidance on classifying these causes.
PART M6 GAS GATHERING LEAKS DISCOVERED DURING CALENDAR YEAR

For regulated gas gathering pipelines, report the number of leaks discovered during the calendar year by
grade and by cause. Do not report leaks discovered on Type R gathering lines. See the instructions for Part
M1 for guidance on classifying these causes.
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ANNUAL REPORT FOR CALENDAR YEAR 20
NATURAL AND OTHER GAS TRANSMISSION AND GATHERING PIPELINE SYSTEMS

PART M7 – GAS TRANSMISSION LEAKS REPAIRED DURING CALENDAR YEAR

For gas transmission pipelines, report the number of leaks repaired during the calendar year by grade and
by cause. See the instructions for Part M1 for guidance on classifying these causes.
A leak discovered and repaired in the same calendar year must be reported in both parts M5 and M7. A leak
has been repaired following a successful post-repair inspection in accordance with § 192.760(e)(1). If a
repair has been done but the inspection has not been completed or gas was detected during the inspection
do not report the leak on M7 and instead report the leak under part M2 as a leak scheduled for repair.
PART M8 GAS GATHERING LEAKS REPAIRED DURING CALENDAR YEAR

For gas gathering pipelines, report the number of leaks repaired during the calendar year by grade and by
cause. Do not report leaks discovered on Type R gathering lines. See the instructions for Part M1 for
guidance on classifying these causes.
A leak discovered and repaired in the same calendar year should be reported in both parts M6 and M8. A
leak has been repaired following a successful post-repair inspection in accordance with § 192.760(e)(1). If a
repair has been done but the inspection has not been completed or gas was detected during the inspection
do not report the leak on M8 and instead report the leak under part M2 as a leak scheduled for repair.
PART P – MILES OF PIPE BY MATERIAL AND CORROSION PREVENTION STATUS
For steel pipe, report the total miles of onshore and offshore transmission and gathering pipe that is
cathodically protected and cathodically unprotected subdivided, in each case, into the amount that is bare
and the amount that is coated pipe. COATED means pipe coated with an effective hot or cold applied
dielectric coating or wrapper. For non-steel pipe, report the total miles of onshore and offshore pipe for
each type listed.
Composite means pipe consists of two or more dissimilar materials layered together to be stronger than
the individual materials. Use of composite pipe requires a PHMSA Special Permit or waiver from a State.
Examples include, but are not limited to, fiber reinforced thermoplastic composite pipe, fiber reinforced
thermosetting plastic pipe, steel reinforced thermoplastic pipe, and metallic composite pipe. If a
dissimilar material has been inserted into older pipe, report the pipe as the material that contains the
pressure.
Other means a pipe made of a material not specifically designated on the form, such as copper,
aluminum, etc. Describe the other material(s) in the “specify” field.

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ANNUAL REPORT FOR CALENDAR YEAR 20
NATURAL AND OTHER GAS TRANSMISSION AND GATHERING PIPELINE SYSTEMS

PART Q – Gas Transmission Miles by MAOP Determination Method
In the “Total” columns, operators report transmission pipeline miles by the MAOP determination method
and by each combination of class location and HCA/MCA/Neither status.
A short explanation of each § 192.619 MAOP determination method and Other is:
§ 192.619
(paragraph)

(a)(1)
(a)(2)
(a)(3)

(a)(4)
(c)
(d)
Other

Method Description
Design Pressure
Post-Construction Pressure Test
Highest Actual Operating Pressure during 5 years preceding July 1, 1970 – this is
NOT the Grandfather Clause
History of Pipe (primarily corrosion and actual operating pressure)
Grandfather Clause - Highest Actual Operating Pressure during 5 years preceding
1970, even if this MAOP is higher than pressures determined by other (a) methods
Alternative MAOP under § 192.620(a) and Alternative MAOP Special Permits
Use this category if you did not base your MAOP on any of the paragraphs within
§ 192.619 or § 192.624.

A short explanation of each Class Location and HCA is:
Location
Class 1
Class 2
Class 3
Class 4
High
Consequence
Area (HCA)

Short Description (full detail in § 192.5)
≤10 buildings intended for human occupants.
<46 and >10 buildings intended for human occupants.
≥46 buildings or an area within 100 yards of building/well defined area
occupied by at least 20 persons at designated intervals.
Any location where buildings with four or more stories above ground are
prevalent.
A location which is specifically defined in § 192.903. In general, a HCA is
an area where a pipeline release could have greater consequence to human
health and safety or the environment.

MCA is defined in Part 192. Transmission miles may only be entered under one of the MAOP
determination methods. For each combination of class location and HCA/MCA/Neither shown on the
form, report a segment of pipeline under only one MAOP determination method. The sum of all “Total”
columns for each class location must be consistent with the class location data reported in Parts K and R.
The sum of all “Total” columns in HCA must be consistent with HCA miles entered in Part L. The sum
of all “Total” columns in HCA and MCA for each class location must be consistent with HCA and MCA
miles for each class location entered in Part R. If miles are entered in any row of the Other column, enter
text describing the Other method(s) used to establish MAOP.
For each combination of class location and HCA/MCA/Neither, except Classes 1 and 2 Neither, report the
transmission miles for which the operator lacks complete records to verify the MAOP determination

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ANNUAL REPORT FOR CALENDAR YEAR 20
NATURAL AND OTHER GAS TRANSMISSION AND GATHERING PIPELINE SYSTEMS

method in the “Incomplete Records” column. The value in the “Incomplete Records” column must be
less than or equal to the value in the “Total” column for each combination of class location and
HCA/MCA/Neither. For the purpose of this part, “verification records” can include traceable, verifiable,
and complete records demonstrating that the criteria of the MAOP determination have been met. For
619(a)(1), the “verification records” can include pipe mill tests (mechanical and chemical properties), asbuilt drawings, alignment sheets, specifications, and design, construction, inspection, and maintenance
documents. For 619(a)(2), the “verification records” are pressure test records. For miles of transmission
pipeline for which the operator has not completed the records review, include these miles in the
“Incomplete Records” column. See PHMSA Advisory Bulletin (ADB) 2012-06 for additional details:
https://www.phmsa.dot.gov/sites/phmsa.dot.gov/files/2020-03/2012-10866.pdf
When reporting transmission miles for which 192.619(d) was used to establish MAOP, include miles of
pipeline installed pursuant to a PHMSA Alternative MAOP Special Permit allowing operation up to 80%
SMYS in Class 1 areas. From 2006 through 2010, PHMSA issued fifteen of these special permits with
conditions equivalent to pipeline installed under 192.619(d). Alternative MAOP pipelines with MAOP
determined by the limitations in 192.611(a)(1)(ii) or (a)(3)(iii) are to be reported as 619(d).
For pipeline systems placed in operation after July 1, 1970, selecting the MAOP determination method is
fairly simple. Neither 619(a)(3) nor 619(c) are viable options. When the pressures calculated under (a)(1)
and (a)(2) are identical, report the miles under (a)(2).
The MAOP for certain gas transmission pipelines placed in operation after July 1, 1970 may have been
affected by a class location study under 192.609. The relevant limitations on MAOP after these studies
are in Part 192.611. Any gas transmission pipeline with MAOP reduced pursuant to Part 192.611 should
be reported under the appropriate 619(a) section. For segments of gas transmission pipeline where the
reductions in 192.611 were not implemented due to a waiver/special permit from PHMSA or a
predecessor agency, report the miles under the MAOP determination method used prior to the
waiver/special permit.
For pipeline systems placed in operation before July 1, 1970, the situation is more complicated.
Operators could either implement 619(c) or determine a pressure under each of the 619(a) options and
choose the lowest value as MAOP. For segments of pipe operating at more than 72% SMYS in class one
locations, 192.619(c) is the only viable option. 192.619(c) is referred to as the Grandfather Clause and
can be the MAOP determination method for pipe operated before July 1, 1970 regardless of the ability to
determine pressure values under 192.619(a)(1) and (a)(2).

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ANNUAL REPORT FOR CALENDAR YEAR 20
NATURAL AND OTHER GAS TRANSMISSION AND GATHERING PIPELINE SYSTEMS

After the original effective date of Part 192, gas pipeline operators established MAOP under the 192.619
options in the original regulations. Some of these 619 options are no longer in Part 192 or have a
different section designation. The table below provides instruction for proper reporting of these original
code sections:
Original Part
192 Section
619(a)(4)
619(a)(5)
619(a)(6)

Original 619 Text
For furnace butt welded steel pipe, a pressure equal to 60 percent of the
mill test pressure to which the pipe was subjected.
For steel pipe other than furnace butt welded pipe, a pressure equal to 85
percent of the highest test pressure to which the pipe has been subjected,
whether by mill test or by the post installation test.
The pressure determined by the operator to be the maximum safe
pressure after considering the history of the segment, particularly known
corrosion and the actual operating pressure.

Report in
Part Q
619(a)(1)
619(a)(2)
619(a)(4)

The original Part 192 also required class location studies under 192.607 for certain pipelines in service
before July 1, 1970. When a class location study, under either 192.607 or 192.609, finds that MAOP
needs to be reduced, Part 192.611 provides guidance for determining the MAOP. Proper reporting of the
MAOP determination method depends on whether the pipe was replaced with new pipe or the MAOP was
reduced for existing pipe. Report any portion of new pipe under the appropriate 619(a) section, but (a)(3)
is no longer a viable option. No change in MAOP determination method occurs for pipe within the class
location study area whose MAOP was not reduced. When MAOP is reduced on existing pipe, report the
miles under the appropriate 619(a) section, but (a)(3) is no longer a viable option.
PART R - Gas Transmission Miles by Pressure Test (PT) Range and Internal Inspection
For Part R, enter miles of gas transmission pipe in each of the five pressure test ranges with each range
divided into miles able to be internally inspected and miles unable to be internally inspected. All gas
transmission miles must be reported in this part. The miles entered for each class location must be
consistent with the class location data entered in Parts K and Q. The sum of HCA miles must be
consistent with HCA miles entered in Part L. The HCA and MCA miles in each class location must be
consistent with HCA and MCA miles for each class location entered in Part Q.
If an operator is uncertain whether a gas transmission pipeline has been subjected to a post-construction
pressure test, report the miles in the “1.1 MAOP > PT or No PT” section. Operators may consider
elevation changes when deciding on the appropriate pressure test range and report the miles in the
appropriate pressure range. During a hydrostatic pressure test, the recorded test pressure is the lowest
pressure during the test calculated at the highest elevation point. This test pressure may put the bulk of
the mileage in the 1.1 to 1.25 times MAOP range. Some pipeline at lower elevations could have
experienced test pressures higher than 1.25 times MAOP and could be reported in the between 1.25 and
1.39 times MAOP range.

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ANNUAL REPORT FOR CALENDAR YEAR 20
NATURAL AND OTHER GAS TRANSMISSION AND GATHERING PIPELINE SYSTEMS

“Miles Internal Inspection ABLE” means a length of pipeline through which commercially available
devices can travel, inspect the entire circumference and wall thickness of the pipe, and record or transmit
inspection data in sufficient detail for further evaluation of anomalies. If an operator is uncertain whether
a gas transmission pipeline is able to be internally inspected, report the miles in the “Miles Internal
Inspection NOT ABLE” column.
PART S – Gas Transmission Verification of Materials (192.607)
For Part S, enter miles of gas transmission pipe for which the material was verified as described in
192.607 during the year. Report the miles by Class Location and HCA/MCA/Neither. Report the number
of 192.607 test locations for the year by Class Location and HCA/MCA/Neither.
PART T – HCA Miles by Determination Method and Risk Model Type
HCA Method 1 and HCA Method 2 are defined in 49 CFR Part 192.903.
Descriptions of each Risk Model Type:
Subject Matter Expert (SME) models combine opinions and observations with information obtained from
technical literature to provide a relative numeric value describing the likelihood of failure for each threat
and the resulting consequences (Unit-less measure of risk). The SMEs analyze each pipeline segment,
assign relative likelihood and consequence values, and calculate a relative risk score that can be compared
to other assets modelled in the same manner.
Relative Risk models build on pipeline-specific experience and data, and include the development
of risk models addressing the known threats that have historically impacted pipeline operations. Such
relative or data-based methods identify and quantitatively sum values representing the threats and
consequences relevant to past pipeline operations (Unit-less measure of risk). These approaches are
considered relative risk models since the risk results are compared with results generated from
the same model.
Quantitative models are expressed in terms of numerical quantity or involving the numerical
measurement of quantity or amount. Quantitative models contain input that is quantitative and output that
is quantitative and measured in units. Model logic may or may not conform to laws of probability or to
represent physical and logical relationships of risk factors. A quantitative risk model may use an
algorithm that models the physical and logical relationships of risk factors to estimate quantitative outputs
for likelihood and consequences and represents the outputs in standard units such as frequency,
probability, and expected loss. These approaches are considered quantitative models since the risk
results are in quantified units and may be directly compared with results generated from other
assets using the same model.
Probabilistic models contain inputs that are quantities or probability distributions and produce outputs
that are probability distributions. Model logic attempts to adhere to laws of probability. These models

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provide risk output in a format that is compared to identified risk probabilities or criteria established by
the operator, rather than using a comparative basis.
Scenario-Based models generate a description of an event or series of events leading to a level of risk,
and includes both the likelihood and consequences of such events. This method usually includes
construction of event trees, decision trees, and fault trees. From these constructs, risk mitigation strategies
are identified and risk reduction values are determined.
For the designated Commodity Group, complete Part N one time for all of the pipeline facilities
included within this OPID. Complete Part O one time for all the pipeline facilities included within
this OPID if any Part L HCA mile value is greater than zero.
PART U – ESTIMATED EMISSIONS
Report estimated volume of natural gas and other commodities predominately composed of methane released
to the atmosphere in million cubic feet (MMCF). Do not include releases of commodities that are not
predominately composed of methane. Include both unintentional and intentional releases. Report emissions
from gas transmission pipelines in Part U1 and emissions from regulated gathering lines in Part U2. Do not
include estimated emissions from Type R gathering lines.
Separately report total emissions from reported incidents in the first row.
Releases from compressor stations includes both fugitive emissions from leaks and venting from equipment
inside compressor stations. However, releases from pressure relief devices and from blowdowns should
instead be included under those categories.
Releases from pressure relief devices includes unintentional leaks and releases from the device operating as
intended to provide overpressure protection. Do not double count releases from pressure relief devices in other
categories.
Blowdowns, Venting, Purging, and Flares includes unintended leaks from flares, emissions from flares that are
unlit during operation, and emissions from incomplete combustion during flaring.
PART N – PREPARER SIGNATURE
The Preparer is the person who compiled the information and prepared the responses to the Report. Enter
the Preparer’s name, title, e-mail address, phone number. PHMSA will contact the Preparer if data quality
checks raise questions about the report.
PART O – CERTIFYING SIGNATURE
CERTIFYING SIGNATURE must be a senior executive officer of the operator. The Pipeline Inspection,
Protection, Enforcement and Safety Act (49 U.S.C. 60109(f)) requires pipeline operators to have a senior
executive officer of the company sign and certify annual pipeline Integrity Management Program (IMP)
performance reports - portions of Parts M1, F, G, and L. By this signature, the senior executive officer is
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certifying that he or she has (1) reviewed the Report and (2) to the best of his or her knowledge, believes
the Report is true and complete. Entering the senior executive officer’s name onto the electronic Report is
equivalent to a paper submission and has the same legal authenticity and requirements.

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