49 CFR Part 195: Hazardous Liquid Pipeline Safety Regulations

49 CFR Part 195 governs the safety of hazardous liquid pipelines and carbon dioxide pipelines in the United States. The regulation covers the full lifecycle of pipeline operations — design, construction, operation, maintenance, and integrity management — for systems that transport hazardous liquids including crude oil, refined petroleum products, and highly volatile liquids. For operators and engineers working in hazardous liquid pipeline compliance, Part 195 is the foundational regulatory text. This hub organizes the key sections into a structured reading path with particular emphasis on the integrity management requirements that generate the most audit attention.

What Part 195 Covers

Part 195 applies to operators of pipelines that transport hazardous liquids or carbon dioxide in or affecting interstate or foreign commerce. The regulation establishes minimum federal safety standards across the entire pipeline lifecycle and is organized into subparts covering distinct operational domains.

The subparts most relevant to integrity management and compliance program development are:

• Subpart A — General — Scope, definitions, and applicability determinations
• Subpart B — Reporting — Annual reports, accident reports, and safety-related condition reports
• Subpart C — Design Requirements — Pipe design, components, and materials
• Subpart D — Construction — Installation, welding, and testing during construction
• Subpart E — Pressure Testing — Hydrostatic testing requirements for new and existing pipelines
• Subpart F — Operation and Maintenance — Ongoing operational safety obligations, including 195.452 integrity management
• Subpart G — Qualification of Pipeline Personnel — Operator qualification requirements
• Subpart H — Corrosion Control — Cathodic protection, coating, and corrosion monitoring

The integrity management requirements are embedded within Subpart F, with Section 195.452 serving as the central compliance obligation for any operator with covered segments near high consequence areas. It is the most audited section in Part 195.

Core Regulation Sections

195.452 — Integrity Management Program

The primary integrity management requirement for hazardous liquid pipelines. Requires operators to develop and maintain a written program for all pipeline segments that could affect high consequence areas. This section governs baseline assessments, reassessment intervals, threat identification, preventive and mitigative measure implementation, and record-keeping. Nearly every significant integrity management audit focuses substantially on this section.

Read the full 195.452 Integrity Management guide

195.404 — Maps and Records

Requires operators to maintain current maps and records sufficient to make emergency response decisions and to support the integrity management program. Record completeness and currency are foundational to defensible program execution — a program is only as good as the data underlying it.

195.406 — Maximum Operating Pressure

Establishes requirements for operating within the maximum operating pressure of the system and for maintaining records that document the basis for that operating pressure. MAOP documentation gaps are a recurring enforcement finding.

195.412 — Inspection of Rights-of-Way and Crossings

Requires operators to inspect the rights-of-way and crossings at defined intervals for evidence of construction activity, erosion, ground movement, leakage, and other conditions that could affect pipeline integrity.

195.416 — External Corrosion Control

Establishes requirements for protecting buried or submerged pipelines against external corrosion through coating systems and cathodic protection. Corrosion control program quality directly affects the integrity management threat picture.

195.440 — Public Awareness

Requires operators to conduct public awareness programs to educate the public, emergency officials, and excavators about hazards associated with pipeline releases.

Covered Segment Identification and HCA Analysis

The entire 195.452 framework rests on the operator's determination of which pipeline segments require integrity management attention. That determination flows from high consequence area identification — identifying where HCAs exist along the pipeline corridor and modeling which segments could affect those areas based on potential release scenarios.

Under Part 195, the "could affect" standard is broader than physical proximity. Segments upstream of or adjacent to an HCA may qualify as covered segments based on spill modeling outcomes. The specific modeling approach, the variables used, and the documentation of those choices are all subject to audit review.

A common implementation gap in new or rapidly growing programs is the absence of a standardized specification for how spill modeling variables are handled. Without such a specification, modeling conducted by different vendors or at different points in time may produce inconsistent results for comparable pipeline segments. Auditors may interpret that inconsistency as a program deficiency.

See the High Consequence Areas guide for detailed coverage of HCA definitions and identification methods.

Assessment Methods Under Part 195

Part 195 accepts multiple assessment technologies, and the selection must align with the threats identified for each covered segment. The primary methods used in hazardous liquid programs are:

In-line inspection (ILI) is the most widely used assessment method for pipelines that are piggable. Tool selection must be matched to identified threats — magnetic flux leakage (MFL) tools for metal loss, ultrasonic (UT) tools for wall thickness measurement or crack detection, and electromagnetic acoustic transducer (EMAT) tools for stress corrosion cracking on liquid lines. A tool that cannot detect the primary identified threat does not satisfy the assessment requirement for that threat.

Pressure testing confirms the pipeline's ability to sustain a defined test pressure but provides a pass/fail result rather than a quantitative condition assessment. It remains the assessment method of record for certain older pipelines without adequate inspection history.

Direct assessment protocols (ECDA for external corrosion, ICDA for internal corrosion) are structured four-phase processes applicable when ILI is not feasible or as supplemental methods. Each protocol has specific applicability criteria that must be met for the approach to be technically defensible.

See the Pipeline Integrity Assessment Methods guide for method selection guidance.

Reassessment Intervals Under Part 195

Covered segments must be reassessed at intervals not exceeding five years unless the operator justifies a different interval with documented technical analysis. In practice, this five-year maximum is one of the most scrutinized elements in Part 195 audit programs.

The regulation does not prohibit using the maximum interval, but it requires that any interval — including the maximum — be supported by documented technical reasoning specific to each segment. Boilerplate language reused across segments, intervals that do not account for known threats or recent assessment findings, and the absence of a process for re-evaluating intervals when new information arrives are all common enforcement targets.

Interval extension beyond five years is possible but requires a technically rigorous justification that accounts for all identified threats, prior inspection results, and current pipe condition data.

Frequently Asked Questions

What is the difference between a covered segment and the full pipeline system?

A covered segment is the specific portion of the pipeline that could affect a high consequence area based on spill modeling or geographic proximity. Only covered segments are subject to 195.452 integrity management requirements. However, the program must clearly document which segments are covered, why, and what the analytical basis for that determination was — including updates when system changes or new modeling results change the picture.

How does the five-year reassessment interval work?

Five years is the maximum interval between integrity assessments for covered segments. An operator who uses the five-year interval must be able to demonstrate why that interval is technically appropriate for each segment — not just that it is the regulatory maximum. Segments with active corrosion, prior findings, or elevated threat profiles may warrant shorter intervals.

Does a hydrostatic pressure test satisfy the 195.452 assessment requirement?

Yes, pressure testing is an acceptable assessment method under 195.452. However, it provides a pass/fail result at a point in time — it does not produce the quantitative anomaly data that ILI provides. For segments with active corrosion or other time-dependent threats, pressure testing alone may leave significant uncertainty about current pipe condition, which affects the defensibility of downstream interval and risk decisions.

Are there integrity management requirements for gathering lines under Part 195?

Part 195 includes some gathering line provisions, but the applicability depends on the specific system configuration, commodity, and operating characteristics. Regulatory applicability determinations for gathering systems can be complex, particularly for systems that have grown through acquisition or expansion. Operators should confirm the applicability of specific sections against the definitions and scope provisions in Subpart A.

Related Regulations and Resources

• Pipeline Regulations Hub (parent hub)
• 49 CFR Part 192 — Natural Gas Pipeline Regulations
• 195.452 — Integrity Management for Hazardous Liquid Pipelines
• High Consequence Areas — Definitions and Identification
• PHMSA Enforcement Trends

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Matthew Brown, PE Licensed Professional Engineer | 15+ years pipeline integrity and compliance experience

Matthew Brown is a pipeline integrity engineer specializing in integrity management program development, regulatory compliance, threat assessment, and audit preparation. He has supported operators across transmission, distribution, and hazardous liquid systems with program development, documentation review, and PHMSA audit support.

This content is for informational and educational purposes only. It does not constitute engineering services, legal advice, or a professional engineering opinion. Operators should consult qualified professionals for system-specific compliance decisions.