Pipeline Integrity Management 2026 — 49 CFR 192/195 Decoded

PHMSA integrity management in plain language: 49 CFR 192 Subpart O and 195.452

Short answer: PHMSA's integrity management (IM) rules require operators of gas transmission pipelines (49 CFR Part 192, Subpart O) and hazardous liquid pipelines (49 CFR 195.452) to run a written programme for segments in, or able to affect, high consequence areas (HCAs). Operators identify those segments and run baseline assessments by in-line inspection, pressure test, direct assessment or other approved methods. They then fix anomalies on set timelines and reassess at fixed intervals. For gas the maximum is 7 years. For liquid it is 5 years, not to exceed 68 months.

The overview above names the regulations. This section explains what they actually require, using the current text on eCFR and Cornell LII. It is written for plant and facility engineers, who often meet these rules at the fence line: at a terminal, a meter station, a breakout tank farm or a lateral feeding the plant. Regulatory references are to the current 49 CFR. Amendments under the 2019 hazardous liquid rule and the 2019–2022 gas transmission rules changed several requirements, so always confirm against the version in force on eCFR and against PHMSA guidance and interpretations for your system.

Who the IM rules apply to, and where the plant fence matters

Subpart O applies to gas transmission pipelines regulated under Part 192. Section 195.452 applies to each hazardous liquid or carbon dioxide pipeline that could affect a high consequence area, including segments inside an HCA, unless the operator shows through a risk assessment that the segment cannot affect it. Distribution systems have their own programme (DIMP, under Part 192 Subpart P), which this section does not cover.

For plant engineers, the practical question is where the PHMSA system ends and plant piping begins. Process piping inside a refinery or chemical plant is normally designed to ASME B31.3 and inspected under API 570 and the owner's mechanical integrity programme. It sits outside the Part 192/195 IM rules. Pipeline facilities that cross into the site are different. Incoming transmission laterals, pump and compressor stations, meter stations and breakout tanks may stay jurisdictional to PHMSA or a state pipeline safety programme up to a defined boundary. Part 195 has its own applicability and exceptions section, and PHMSA has issued interpretations on terminal and in-plant boundaries. The boundary is a legal question for each site, so document it. For the code side of that boundary see API 570 vs ASME B31.4/B31.8 pipeline boundary.

Breakout tanks are a common overlap. Under 195.432, operators must inspect in-service breakout tanks at intervals not exceeding 15 months, and at least once each calendar year. Atmospheric and low-pressure steel aboveground breakout tanks are inspected per API Standard 653, but the regulation excludes API 653's risk-based alternative for setting intervals. Tanks built to API 2510 are inspected per section 6 of API 510. So an API 653 programme on a pipeline terminal can be a federal requirement, not just good practice. See the API 653 tank inspection guide.

Intrastate pipelines are usually overseen by a state pipeline safety programme certified by PHMSA, such as the Texas Railroad Commission. These programmes enforce the same federal minimums and may add their own. Interstate lines are overseen by PHMSA directly.

Gas transmission: Subpart O step by step

1. Identify HCAs. Section 192.903 defines a high consequence area in two ways.

• Method 1 uses class location. All Class 3 and 4 locations are HCAs. So are Class 1 and 2 areas where the potential impact radius exceeds 660 feet and the circle holds 20 or more buildings intended for human occupancy, and areas with an identified site.
• Method 2 uses the potential impact circle alone. It is an HCA if it contains 20 or more such buildings or an identified site.

For natural gas, the potential impact radius in feet is 0.69 times the square root of (MAOP in psig times the nominal diameter in inches squared). Identified sites include outdoor areas or buildings occupied by 20 or more people on a regular schedule, and facilities whose occupants are hard to evacuate, such as hospitals, schools, prisons and care facilities. A pipeline segment located in an HCA is a "covered segment."

2. Build the written programme. Section 192.911 lists the required elements:

• HCA identification
• a baseline assessment plan
• threat identification and risk assessment
• direct assessment plans where used
• remediation
• continual evaluation and assessment
• confirmatory direct assessment where used
• preventive and mitigative measures
• a performance plan
• record keeping
• management of change
• quality assurance
• a communication plan

Several of these are tied to ASME B31.8S, which the regulation incorporates by reference.

3. Assess. Section 192.921 allows these baseline methods:

• in-line inspection for the threats the tools can detect (corrosion, deformation, mechanical damage, cracking)
• pressure testing under Subpart J
• spike hydrostatic testing for time-dependent threats such as stress corrosion cracking
• excavation with direct examination by visual and non-destructive methods
• guided wave ultrasonic testing
• direct assessment for external corrosion, internal corrosion and SCC
• other technology shown to give equivalent understanding, with PHMSA notification

The original baseline deadline was December 17, 2012. Newly identified HCAs must be baselined within ten years of identification.

4. Remediate. Under 192.933, the operator must obtain enough information about a condition to decide whether it threatens integrity. This must be done within 180 days of the assessment unless the operator can show that is impracticable. Conditions fall into three groups:

• Immediate repair conditions. These require a pressure reduction or shutdown until repaired. Examples in the current text include metal loss where predicted failure pressure is at or below 1.1 times MAOP, metal loss greater than 80 percent of nominal wall, top-side dents with metal loss, cracking or a stress riser, and certain crack-like anomalies.
• One-year conditions. These must be remediated within one year of discovery.
• Monitored conditions. These are tracked through later assessments.

Where a response deadline cannot be met, the rule sets temporary pressure-reduction options.

5. Reassess. Section 192.939 sets the maximum reassessment interval at 7 calendar years. Operators may request a short extension with justification. Longer intervals by pressure test, ILI or direct assessment (10, 15 or 20 years, depending on operating stress level) are allowed only with confirmatory direct assessment, or low-stress reassessment where applicable, inside the 7-year window.

6. Look beyond HCAs. The 2019 gas rule added 192.710. Onshore steel transmission lines at 30 percent of SMYS or more, in Class 3 or 4 locations, or in piggable moderate consequence areas, need assessments even outside HCAs. Initial assessments are due by July 3, 2034. Reassessment follows at least every 10 years, not to exceed 126 months. Allowed methods are similar and include direct examination with NDE and guided wave UT.

Hazardous liquid: 195.452 step by step

Applicability and segments. The rule covers segments that could affect an HCA. It requires annual verification of HCA segment identification, at intervals not exceeding 15 months. Newly identified HCA segments must be added to the programme within one year and baselined within five years.

Baseline methods. These are in-line inspection tools that can detect corrosion and deformation anomalies (and cracks where applicable), pressure testing under Subpart E, external corrosion direct assessment under 195.588, or other technology shown to be equivalent, with 90 days' notice to PHMSA.

Programme elements. The operator needs:

• a process to identify could-affect segments
• a baseline plan
• an integrity analysis that brings all available information together
• remedial action criteria
• continual assessment and evaluation
• preventive and mitigative measures
• methods to measure programme effectiveness
• a qualified review process

Risk factors for scheduling include prior results, pipe specifications, leak and repair history, cathodic protection history, product, operating stress, local activity, environmental and geotechnical hazards, and supports.

Remediation. The operator must obtain enough information about a condition promptly, and no later than 180 days after the assessment. Immediate repair conditions include:

• metal loss greater than 80 percent of nominal wall
• predicted burst pressure below maximum operating pressure
• top-side dents with metal loss, cracking or a stress riser, or above a set depth
• any anomaly the operator judges to need immediate action

The current text also sets 60-day and 180-day conditions. These cover dents of various depths and positions, metal loss above set fractions of the wall, crack indications, seam-weld corrosion, and gouges or grooves. Read these from the eCFR text for your assessment date, because the categories were revised in recent rulemakings.

Preventive and mitigative measures. These include damage prevention, cathodic protection monitoring, shorter inspection intervals, evaluation and upgrading of leak detection, and emergency flow restricting devices where the operator's analysis calls for them. Newer onshore lines of 6-inch diameter and above have specific EFRD-related requirements.

Reassessment and records. Continual assessment follows at five-year intervals, not to exceed 68 months. Records demonstrating compliance are kept for the useful life of the pipeline. Separately, 195.416 requires piggable onshore lines outside the IM rule to be assessed. The initial assessment is due by October 1, 2029, with reassessment at least every 10 calendar years.

Dig verification: where NDE meets the IM programme

ILI results drive most IM decisions, and the rules expect operators to account for tool uncertainty. That is why excavations matter. An operator excavates to remediate an anomaly, to validate tool performance, or to examine a segment directly. The dig site is where NDE gives the measured answer the remediation decision depends on. Typical in-ditch scopes include:

• UT wall thickness and corrosion mapping over the reported anomaly and the surrounding pipe, to measure remaining wall and the length of the corroded area for the operator's burst-pressure assessment. See corrosion mapping.
• Phased array UT to detect and size cracking, including SCC colonies and seam-weld anomalies, and to examine girth and long-seam welds near dents. See phased array inspection services.
• Magnetic particle testing (often wet fluorescent) to find surface-breaking cracks, especially SCC under disbonded coating. See MT for pipelines.
• Guided wave screening of road crossings, casings and other uninspectable sections, with follow-up UT. Gas rules list GWUT as an assessment method when it is carried out within the regulation's conditions. See guided wave testing.
• Dent and coating documentation, and visual examination of the coating and pipe surface, recorded so results can be compared with the ILI call.

The comparison between field and tool results is called a unity check. It feeds back into the operator's ILI validation under API 1163, and through that into later assessment intervals. Field NDE must therefore use calibrated equipment and qualified procedures, and must record locations precisely: girth weld references, odometer distance and clock position. The ILI, dig verification and API 1163 guide covers that loop in more depth.

Records PHMSA and state inspectors ask for

IM audits are document-heavy. An operator should be able to produce:

• the written programme and its revision history
• HCA and could-affect analyses with their annual verification
• baseline and reassessment plans with completion evidence
• ILI reports and the integrity analysis that integrated them
• discovery-of-condition dates and remediation records against each deadline
• any pressure reductions taken
• preventive and mitigative measure evaluations
• performance measures

For every dig, keep NDE reports that trace to the pipe location, the procedure, the instrument calibration and the qualified technician. The liquid rule requires records for the useful life of the pipeline. Operator qualification records for covered tasks (Part 192 Subpart N and Part 195 Subpart G) are a separate requirement. See PHMSA 49 CFR 192 records retention.

Canada: CER, CSA Z662 and provincial regulators

In Canada, federally regulated interprovincial and international pipelines fall under the Canada Energy Regulator (CER). Its Onshore Pipeline Regulations require an integrity management programme as part of the operator's management system. CSA Z662, Oil and gas pipeline systems, gives the technical basis, and its Annex N gives guidance on pipeline integrity management programmes. Provincially regulated lines follow provincial regulators. In Alberta that is the Alberta Energy Regulator under its Pipeline Rules. Canadian rules do not use the US HCA framework. Confirm requirements with the regulator for your system.

Common misunderstandings

• "IM only matters inside HCAs." 192.710 and 195.416 now require periodic assessments well beyond HCAs for many lines.
• "The 7-year gas interval is the only clock." The clock is per segment and per threat. Remediation deadlines start at the discovery of the condition, not when the ILI report arrives.
• "Plant piping is covered by PHMSA." Usually not. In-plant process piping is managed under B31.3 and API 570, but jurisdictional boundaries at terminals and stations must be documented.
• "Breakout tanks can use API 653 RBI intervals." 195.432 excludes API 653's risk-based interval alternative for breakout tanks.
• "A dig report is just a thickness number." Without location referencing, procedure, calibration and qualification records, a dig cannot validate ILI performance or support an audit.

How Atlantis supports PHMSA IM programmes

Atlantis NDT provides in-ditch and dig-verification NDE that supports an operator's IM programme. This covers UT thickness and corrosion mapping, PAUT for crack detection and sizing, MT for SCC, guided-wave screening with UT follow-up, and API 653 NDE on breakout tanks. The work is done by ASNT-certified technicians under ASNT Level III oversight, with reports tied to the operator's location references. Atlantis does not run in-line inspection tools, does not select assessment methods, and does not make remediation or reassessment decisions. Those stay with the operator under its written programme. See pipeline inspection services. Request a dig-verification NDE quote within 24 hours, or ask about API 653 NDE for breakout tanks.

PHMSA integrity management FAQs

What is 49 CFR 192 Subpart O?

It is PHMSA's gas transmission pipeline integrity management rule. It covers HCA identification, a written programme, baseline and periodic assessments, remediation and records for covered segments.

What does 195.452 require?

A written integrity management programme for hazardous liquid and CO2 pipeline segments that could affect an HCA. It requires baseline assessment, remediation on set timelines and continual assessment at five-year intervals, not to exceed 68 months.

What is the PHMSA reassessment interval for gas transmission?

A maximum of 7 calendar years under 192.939. Longer intervals by certain methods require confirmatory direct assessment inside 7 years.

How is a gas transmission high consequence area determined?

By class location (Method 1) or by potential impact circle (Method 2), using building counts and identified sites. The potential impact radius depends on MAOP and diameter.

How long does an operator have to evaluate an ILI anomaly?

Both rules require enough information to decide on the condition within 180 days of the assessment. The gas rule allows an exception where the operator shows this is impracticable.

Does PHMSA integrity management apply to refinery piping?

Generally no. In-plant process piping falls under the owner's API 570/B31.3 programme. Jurisdictional pipeline facilities entering the site may be covered up to a documented boundary.

What NDE is used in dig verification?

UT thickness and corrosion mapping, phased array UT for cracks, MT for SCC, and visual and coating documentation. Guided wave is used for screening inaccessible sections.

Next step

Atlantis performs the NDE this work needs and reports to your inspector of record. To go further, request an inspection quote. We reply within 24 hours.