Pipeline Safety Regulation

The United States moves energy through more than 2.7 million miles of natural gas pipelines and 225,000 miles of hazardous liquid pipelines (crude oil, refined petroleum products, CO₂, and anhydrous ammonia) — infrastructure largely invisible to the public until something fails. The Pipeline and Hazardous Materials Safety Administration (PHMSA) within the Department of Transportation regulates this network under 49 U.S.C. Chapter 601, setting standards for design, construction, inspection, and emergency response. Approximately 600 significant pipeline incidents occur annually — those causing death, hospitalization-level injury, or property damage above PHMSA's threshold. Pipelines in High Consequence Areas (populated zones, drinking water sources, ecological sensitivity areas) face mandatory integrity management programs requiring operators to systematically assess and remediate risks on a scheduled cycle. 48 states have certified intrastate pipeline safety programs. High-profile incidents — including the 2021 Colonial Pipeline ransomware attack that disrupted fuel supplies across the Southeast, and a 2016 Alabama crude spill releasing 350,000 gallons — have driven legislative attention toward aging infrastructure, cybersecurity vulnerabilities, and methane leak detection, all active regulatory frontiers as of 2026.

Current Law (2026)

Legal Authority

• 49 U.S.C. § 60101 — Definitions (gas pipeline facility, hazardous liquid pipeline facility, interstate pipeline facility, intrastate pipeline facility, person, transporting gas/hazardous liquid)
• 49 U.S.C. § 60102 — Purpose and general authority (adequate protection of the public and environment from pipeline risks; Secretary prescribes minimum safety standards for pipeline transportation and pipeline facilities; design, installation, inspection, emergency plans, testing, construction, extension, replacement, operation, and maintenance)
• 49 U.S.C. § 60103 — Standards for LNG pipeline facilities (liquefied natural gas facilities must meet specific safety standards including siting, design, construction, operation, maintenance, and personnel qualifications)
• 49 U.S.C. § 60104 — Requirements and limitations (state standards may be more stringent; federal standards are minimum; pipeline operators must comply with all applicable standards)
• 49 U.S.C. § 60105 — State pipeline safety program certifications (states may assume responsibility for safety of intrastate pipeline facilities by certifying their programs meet federal requirements; 48 states certified)
• 49 U.S.C. § 60108 — Inspection and maintenance (pipeline operators must inspect and maintain facilities; reporting of safety conditions; records; access for federal/state inspectors)
• 49 U.S.C. § 60109 — High-density population areas and environmentally sensitive areas (integrity management programs required for transmission pipelines in High Consequence Areas — areas near populations, drinking water sources, or ecological resources)
• 49 U.S.C. § 60112 — Pipeline facilities hazardous to life and property (Secretary may declare facility hazardous if conditions create risk of rupture; order corrective action; if imminent hazard, order immediate cessation of transport)
• 49 U.S.C. § 60117 — Administrative authority (inspections, investigations, testing, records, access to pipeline facilities; cooperative agreements with states; one-call notification coordination)
• 49 U.S.C. § 60118 — Compliance and waivers (orders requiring compliance; safety orders for pipeline risk; waivers from standards if not inconsistent with pipeline safety)
• 49 U.S.C. § 60120 — Enforcement (federal district court jurisdiction; compliance orders; injunctive relief)
• 49 U.S.C. § 60121 — Actions by private persons (any person may bring civil action when a state or federal agency has failed to enforce pipeline safety standards; 60-day notice)
• 49 U.S.C. § 60122 — Civil penalties (up to $266,015 per violation per day, with a maximum of $2,660,150 for a related series of violations under the FCPIA-adjusted 2026 levels)

How It Works

PHMSA regulates the safety of nearly 3 million miles of pipelines that transport natural gas, crude oil, refined petroleum products, and other hazardous liquids across the country. PHMSA sits alongside the FRA (which handles railroad safety) within the Department of Transportation.

Pipeline safety regulations divide into two main categories: gas pipeline safety (49 CFR Parts 191–193), covering natural gas transmission, distribution, and gathering lines and LNG facilities, and hazardous liquid pipeline safety (49 CFR Part 195), covering crude oil, refined products, CO₂, and anhydrous ammonia pipelines. Both categories address pipeline design, materials, construction, pressure testing, operations, maintenance, emergency response, personnel qualifications, and integrity management. The most consequential safety development in recent decades is Integrity Management (IM): for gas transmission and hazardous liquid pipelines in High Consequence Areas (HCAs) — near populations, commercial navigable waterways, and drinking water sources — operators must implement programs that include risk assessment, baseline condition assessment (through in-line inspection tools, pressure testing, or direct assessment), remediation of discovered anomalies, and periodic reassessment. PHMSA has been expanding IM requirements beyond HCAs through its "mega rule" rulemaking. Modern assessment relies heavily on in-line inspection (ILI) tools — "smart pigs" that travel through pipelines detecting corrosion, cracks, and dents — complemented by external inspections including pipeline patrols, leak surveys, cathodic protection monitoring, and pressure monitoring.

The pipeline safety system depends on federal-state cooperation: 48 states are certified to inspect and enforce safety standards on intrastate pipelines, and approximately 90% of all pipeline inspections are performed by state agencies. PHMSA provides grants to support state programs and retains authority over interstate pipelines and supplemental enforcement. The leading cause of pipeline incidents is excavation damage — PHMSA and all 50 states require anyone planning to dig to contact the 811 one-call notification system, which alerts pipeline and utility operators to mark buried lines before digging begins. Pipeline operators must also maintain emergency response plans, coordinate with local emergency responders, conduct regular exercises, and run public awareness programs for communities near pipelines; PHMSA's emergency order authority allows immediate shutdown of facilities posing imminent hazards.

How It Affects You

If you live near a pipeline: You should know the location of pipelines near your home (available through the National Pipeline Mapping System), recognize signs of a pipeline leak (hissing, unusual odors, dead vegetation, bubbling in water), and know your emergency response steps. Pipeline operators are required to conduct public awareness programs in your area.

If you're planning to dig on your property: Always call 811 before digging — it's required by law in all 50 states. Pipeline and utility operators will mark the location of underground lines free of charge. Hitting a gas pipeline while digging can cause explosions, injuries, and death.

If you depend on natural gas service: Your local gas distribution company's pipelines are inspected by state pipeline safety agencies under PHMSA oversight. Aging cast iron and bare steel distribution mains are being replaced under accelerated programs — your gas bill may include a surcharge for these safety improvements.

If you're a pipeline operator: You must comply with all applicable PHMSA regulations, implement integrity management programs for pipelines in HCAs, conduct regular inspections, maintain emergency response plans, report incidents and safety conditions, and participate in one-call notification systems.

If you're concerned about pipeline expansion: New pipeline construction requires federal or state permitting (FERC for interstate natural gas pipelines, State Department for cross-border pipelines, state agencies for intrastate), and NEPA environmental review for federal permits. Pipeline spills may trigger enforcement under the Clean Water Act and Clean Air Act. Pipeline routing, eminent domain, and environmental impact are active areas of public controversy.

State Variations

• 48 states are certified for intrastate pipeline safety; state inspectors conduct ~90% of all pipeline inspections
• States may adopt more stringent safety standards than federal minimums
• State programs vary in resources, inspector staffing, and enforcement aggressiveness
• Some states have their own pipeline siting and permitting requirements beyond federal rules
• Excavation damage prevention laws vary by state — enforcement ranges from strong to minimal
• California, Texas, and Louisiana — states with the most pipeline mileage — have some of the most active state pipeline safety programs
• State utility commissions often regulate the cost recovery for pipeline safety improvements through customer rates

Implementing Regulations

The PHMSA pipeline safety regulations divide into gas pipeline rules (49 CFR Parts 191–193) and hazardous liquid pipeline rules (49 CFR Part 195). The operational core is 49 CFR Part 192 — Transportation of Natural and Other Gas by Pipeline: Minimum Federal Safety Standards (259 sections across 16 subparts — the design-to-decommission rulebook for the 2.7 million miles of U.S. natural gas pipeline). Key subparts:

• Subpart C — Pipe Design (12 sections): the fundamental pipe design formula (§ 192.105) — maximum allowable operating pressure (MAOP) calculated from yield strength, wall thickness, design factor, and temperature derating; design factors range from 0.40 in Class 4 locations (dense population, high-rise buildings) to 0.72 in Class 1 (open countryside); plastic pipe design (§ 192.121) and copper pipe design (§ 192.125)

• Subpart D — Design of Pipeline Components (35 sections): valves (§ 192.145 — isolation valves at intervals along transmission lines enabling emergency sectioning); flanges and fittings; passage of internal inspection devices (§ 192.150 — transmission lines must accommodate "smart pigs" for internal inspection unless operator demonstrates alternative integrity verification); fabricated components

• Subpart E — Welding of Steel Pipelines (10 sections): all pipeline welding must meet API Standard 1104; qualified welding procedures and welder qualifications required; inspection of all welds — 100% radiographic or equivalent for crossings over railroads, navigable waterways, and highways

• Subpart G — General Construction Requirements for Transmission Lines and Mains (16 sections): cover depth minimums — 30 inches in normal soil, 24 inches in consolidated rock, 48 inches under roadways and railroads; valve location requirements for transmission lines; river and water crossing construction standards

• Subpart I — Requirements for Corrosion Control (25 sections): cathodic protection required for all buried or submerged steel pipelines (§ 192.461 — external corrosion control); impressed current or sacrificial anode systems; electrical isolation from foreign structures; atmospheric corrosion prevention for above-ground piping; internal corrosion control where conditions warrant

• Subpart L — Operations (26 sections): Operator Qualification (OQ) — individuals performing covered tasks must demonstrate the knowledge and skills to do them safely (§ 192.801–809); emergency plans required covering gas leak detection and repair, fires, pressure failures, and natural disasters; public awareness programs informing people along pipeline rights-of-way about pipeline hazards; odorization of gas in distribution systems

• Subpart M — Maintenance (34 sections): transmission pipeline patrol — aerial or ground patrol to check for leaks, unauthorized encroachments, and soil movement; leak survey requirements (§ 192.706) for distribution mains; pressure testing after construction; valve inspection and lubrication; corrosion monitoring — close interval surveys, rectifier checks; emergency valve response time requirements

• Subpart O — Gas Transmission Pipeline Integrity Management (25 sections): the core integrity management framework for transmission pipelines in High Consequence Areas (HCAs). Operators must: (1) identify all HCA segments; (2) conduct baseline assessment using internal inspection (smart pig), pressure testing, or direct assessment within 10 years of HCA designation; (3) evaluate all anomalies; (4) remediate within response timeframes tied to severity; (5) reassess every 10 years (or 7 for certain high-consequence segments); (6) implement preventive and mitigative measures including automatic/remote control shut-off valves near HCA segments; anomaly response timeframes — imminent hazard: immediate; 60% SMYS metal loss: 60 days

• Subpart P — Gas Distribution Pipeline Integrity Management (7 sections): integrity management plans for distribution operators (§ 192.1005 — 9-element written plan covering threat identification, risk assessment, performance measures, communication, emergency response, record-keeping); small LPG operators (fewer than 100 customers) have streamlined requirements

• 49 CFR Part 195 — Transportation of Hazardous Liquids by Pipeline: the design-to-decommission safety standard for crude oil, refined petroleum products, CO₂, and anhydrous ammonia pipelines (146 sections across 8 subparts). Key provisions:

  • § 195.1 — Coverage: Part 195 covers pipelines used in the transportation of hazardous liquids or carbon dioxide in interstate or foreign commerce, or pipelines that may affect interstate commerce; major exclusions include gathering lines below specified pressures, pipelines not in a building or populated area, and farm and industrial pipelines operating below 20 PSI
  • § 195.50 — Reportable accidents: operators must report any release of hazardous liquid or CO₂ resulting in (a) explosion or fire not intentionally set, (b) release of 5 gallons or more (except releases under 5 barrels on cropland or dryland with no water contamination that are remediated and reported annually), (c) death or hospitalization-level injury, or (d) property damage of $50,000 or more
  • § 195.52 — Immediate notification: within 1 hour of confirmed discovery of a reportable accident, the operator must notify the National Response Center (NRC) by telephone; the operator must also notify local emergency responders (911 or equivalent); the 1-hour notification requirement is among the strictest in transportation safety regulation
  • § 195.54 — Written accident report: within 30 days of discovery, a written accident report (DOT Form 7000-1 or 7000-2) must be filed electronically with PHMSA
  • § 195.55–195.56 — Safety-related condition reports: operators must report safety-related conditions — corrosion reducing wall thickness below design minimum, manufacturing defects discovered in service, and conditions revealing inadequate design — within 5 working days of determining the condition exists
  • § 195.134 — Leak detection: each hazardous liquid pipeline must have a leak detection system capable of detecting and locating liquid releases; operators must periodically test and verify the performance of the leak detection system; leak detection requirements were significantly expanded by PHMSA's 2023 hazardous liquid integrity management rule
  • § 195.402 — Operations, maintenance, and emergency manual: each operator must prepare and follow a written procedural manual for normal operations, abnormal operations, and emergencies; the manual must be reviewed at 15-month intervals and updated as needed; the manual must address failure recognition, abnormal operating conditions, and emergency actions including isolation of failed segments
  • § 195.403 — Emergency response training: operators must establish and conduct a continuing training program for emergency response personnel, including characteristics and hazards of transported materials, use of emergency equipment, and emergency shutdown procedures; training drills must be conducted annually
  • § 195.406 — Maximum operating pressure: operators may not operate pipelines above the maximum allowable operating pressure (MAOP) based on the pipe's design pressure, pressure testing, or yield strength; no exceptions for surge pressures except temporary allowances up to 110% of MAOP for not more than 2 hours in any 24-hour period
  • Subpart H (§§ 195.551–195.589) — Corrosion control: all buried or submerged steel pipelines must be protected by cathodic protection (external corrosion control) and must meet coating, electrical isolation, and interference current requirements; above-ground surfaces must be protected against atmospheric corrosion; operators must maintain monitoring records and inspection intervals not exceeding 3 years for cathodic protection systems

  The Part 195 integrity management framework (within Subpart F) parallels the Part 192 gas pipeline integrity management program — hazardous liquid pipeline operators must identify High Consequence Areas (HCAs), conduct baseline assessments using internal inspection tools (smart pigs), direct assessment, or pressure testing, remediate anomalies within severity-based timeframes, and reassess every 5 years (more frequently for certain high-risk segments). PHMSA's 2023 amendments to Part 195 expanded integrity management requirements to non-HCA segments and tightened leak detection requirements — the most significant update to the hazardous liquid pipeline safety rules in years.

• 49 CFR Part 191 — Annual reports, incident reports, and safety-related condition reports for gas pipeline operators (reportable incidents — death, hospitalization-level injury, $50,000+ property damage, or unintentional gas ignition; 24-hour notification to NRC)

• 49 CFR Part 193 — Liquefied Natural Gas (LNG) Facilities (78 sections across 8 subparts — PHMSA's comprehensive safety standards for LNG facilities used in natural gas pipeline transportation, implementing 49 U.S.C. § 60103 and incorporating NFPA-59A-2001 by reference; applies to LNG plants, peakshaving facilities, import/export terminals, and LNG storage facilities connected to the pipeline system):

  • § 193.2001 — Scope: Part 193 applies to LNG facilities that are used in natural gas transportation subject to PHMSA's pipeline safety jurisdiction (49 U.S.C. § 60101 et seq.); the Part's key safety standards — siting, design, and construction — apply to facilities built or significantly altered after March 31, 2000; pre-2000 facilities must comply with the siting standards and all operations, maintenance, and security requirements; mobile and temporary LNG facilities for peakshaving applications (§ 193.2019) operate under modified requirements tailored to their portable character
  • Subpart B — Siting Requirements (§§ 193.2051–193.2067): § 193.2051 — all post-2000 LNG facilities must be sited in accordance with NFPA-59A-2001 Section 2.2; the siting analysis establishes two mandatory exclusion zones: (1) thermal exclusion zone (§ 193.2057) — the area around each LNG container and transfer system where thermal radiation from a pool fire would exceed the limits specified in NFPA-59A Section 2.2.3.2; the thermal exclusion zone must be entirely within the facility's property boundary unless an agreement with the neighboring property owner is in place; (2) flammable vapor-gas dispersion zone (§ 193.2059) — the area in which a vapor cloud from an LNG spill would reach a concentration above 50% of the Lower Flammability Limit (LFL); both zones must be free of ignition sources and structures occupied by the public; § 193.2067 — LNG facilities must be designed to withstand wind forces and the indirect effects of wind pressure without loss of structural or functional integrity
  • Subpart C — Design Requirements (§§ 193.2101–193.2119): all LNG facilities designed after March 31, 2000, must comply with NFPA-59A-2001 design requirements as adopted by reference; § 193.2119 — operators must keep records of all materials for components, buildings, foundations, and support systems to verify material properties meet specifications; material records are required because LNG at -260°F (-162°C) places extreme demands on metallic materials — low-temperature carbon steel can become brittle at LNG temperatures, and only specially alloyed steels (9% nickel, aluminum, austenitic stainless) and concrete are acceptable for primary containment
  • Subpart D — Impoundment Requirements (§§ 193.2155–193.2187): every LNG storage tank and transfer system must have an impoundment system — a secondary containment structure that captures LNG spills before they can spread and form an ignitable vapor cloud; § 193.2155 — impoundment structural members must prevent performance impairment in the event of a spill; § 193.2161 — outer walls of LNG containers may serve as dikes only if constructed of concrete; § 193.2167 — covered impounding systems are prohibited except for concrete-wall tanks where the wall itself serves as the dike (full containment tank concept); § 193.2181 — each impoundment serving an LNG storage tank must have volumetric capacity of at least 110% of the tank's capacity — ensuring that even a catastrophic tank failure can be fully captured; § 193.2187 — flammable nonmetallic membrane liners are prohibited as inner tank containers
  • Subpart E — Construction Requirements: installation of LNG storage tanks, piping, and associated equipment must comply with NFPA-59A and ASME standards; welding procedures and operator qualifications must be documented
  • Subpart F — Operations and Maintenance (§§ 193.2601–193.2643): operations plans and procedures must be maintained at each LNG plant; operators must conduct inspections at specified frequencies; leak detection equipment must be installed and tested; emergency shutdown systems must be tested at intervals not exceeding 15 months; personnel must be qualified under §§ 193.2701–193.2703 before performing covered tasks
  • Subpart G — Personnel Qualifications: workers who perform covered tasks (operations, maintenance, emergency response) must be trained and evaluated for qualification before performing tasks unsupervised; qualification records must be maintained and updated when covered tasks change

  LNG facilities represent some of the highest-consequence natural gas infrastructure in the United States — large LNG storage tanks at peakshaving facilities in the Northeast hold enough gas to heat cities through winter demand peaks, while the growing fleet of LNG export terminals (Sabine Pass, Freeport, Corpus Christi, Calcasieu Pass) handles millions of tons per year of product loaded onto LNG tankers for global export. The thermal and vapor-gas exclusion zone requirements are the most consequential siting constraints: a large LNG facility typically requires hundreds of feet of exclusion zone, limiting the sites where new LNG infrastructure can be built near population centers. NFPA 59A — incorporated by reference into Part 193 — is the private standards document that contains most of the technical substance of LNG facility safety requirements; the 2001 version was the current reference standard as of this writing but PHMSA has been working on updating the incorporated reference to more recent editions.

• 49 CFR Part 196 — Protection of Underground Pipelines from Excavation Activity (13 sections — the federal "call before you dig" rule mandating one-call notification before any excavation near underground pipelines subject to PHMSA or state pipeline safety regulation):

  • § 196.103 — Excavator obligations: before and during excavation activity, any excavator must: (1) use an available one-call system to notify operators of all underground pipelines in the area (the national 811 system connects callers to state notification centers, which alert all member pipeline and utility operators); (2) allow the pipeline operator a reasonable time to locate and mark the pipeline; (3) dig hand-expose holes in the tolerance zone (within 18–24 inches of the markings, depending on state) before using power excavation equipment; (4) support, protect, and maintain the pipeline against movement or damage during excavation; (5) comply with any state one-call requirements in addition to these federal minimums
  • § 196.107 — Damage reporting: if any excavation activity damages a pipeline in any way — including coating damage, gouging, or denting — the excavator must promptly notify the pipeline operator and PHMSA; even cosmetic damage that does not cause a release must be reported because delayed failure from mechanical damage is a leading cause of pipeline incidents; the excavator may not backfill over damaged pipe until the operator has assessed it
  • § 196.109 — Release reporting: if excavation damage causes a product release — gas, oil, or liquid chemical — the excavator must immediately notify the pipeline operator and, if the product release creates a hazard, call 911; the excavator may not resume excavation until the operator clears the area and assesses the damage
  • § 196.111 — Pipeline operator failures: if a pipeline operator fails to respond to a locate request or fails to accurately mark its pipeline, PHMSA may enforce existing pipeline operator requirements; operators who do not maintain a current record of their pipelines' locations (geographic information system records) face enforcement exposure under this section and under the general integrity management rules
  • §§ 196.201–196.211 — Enforcement: PHMSA may assess civil penalties for violations of Part 196 under the same authority as other pipeline safety violations — up to $266,015 per violation per day (49 U.S.C. § 60122); criminal penalties are available for willful and knowing violations under 49 U.S.C. § 60123; excavators, pipeline operators, and one-call system operators each have independent compliance obligations under Part 196

  The federal one-call rule is a floor — every state has its own "call before you dig" law, and many states impose stricter requirements (shorter response times, smaller tolerance zones, additional documentation). PHMSA's Part 196 covers excavation near PHMSA-regulated pipelines; state laws typically cover all buried utilities (electric, gas, water, sewer, telecommunications). The Common Ground Alliance publishes annual damage prevention statistics — excavation damage remains the leading cause of pipeline incidents in distribution systems, causing roughly 30–35% of all reported pipeline incidents.

• 49 CFR Part 198 — Grants to aid state pipeline safety programs (certification requirements, matching fund rules, inspection authority delegation)

• 49 CFR Part 190 — PHMSA Pipeline Safety Enforcement and Regulatory Procedures (61 sections across 5 subparts — PHMSA's end-to-end enforcement framework from inspection authority through criminal referral):

  • § 190.203 — PHMSA inspectors may enter any pipeline facility, inspect records and equipment, and take measurements or photographs; operators must allow access and must not obstruct inspections; PHMSA coordinates with state pipeline safety programs on joint inspections of intrastate pipelines
  • § 190.207 — Enforcement begins with a Notice of Probable Violation served by a Regional Director; the notice identifies the specific regulatory provision allegedly violated, the proposed civil penalty amount or compliance action required, and the basis for the finding
  • § 190.208 — Respondent has 30 days to answer: may pay the proposed penalty, contest the violation or penalty amount in writing, or request a hearing; failure to respond results in the proposed penalty becoming final
  • § 190.223 — Civil penalty maximums (adjusted annually for inflation under the Federal Civil Penalties Inflation Adjustment Act): $266,015 per violation per day for most pipeline safety violations; $2,660,150 maximum per incident involving a series of violations; separate per-violation maximums apply for safety regulations vs. intentional wrongdoing; a series of daily violations (e.g., operating over pressure for 30 days) can reach tens of millions
  • § 190.225 — Penalty assessment factors: PHMSA weighs (1) nature, circumstances, and gravity of the violation; (2) the hazard to public safety; (3) history of prior violations; (4) culpability; (5) good faith compliance efforts after discovery; (6) ability to continue as a going concern if penalty is assessed; PHMSA regularly negotiates consent orders (§190.219) that combine civil penalties with mandated corrective measures
  • § 190.233 — Corrective action orders: if PHMSA determines that a pipeline facility or practice poses a risk to life or property, PHMSA may order the operator to take corrective action including pressure reduction, physical inspection, repair, or suspension of operations; corrective action orders may include cost recovery for PHMSA oversight activities
  • § 190.236 — Emergency orders: when the PHMSA Administrator determines an unsafe condition or practice creates an imminent hazard, PHMSA may issue an emergency order without prior notice or hearing, immediately effective; the operator may petition for review (§190.237) but the order stays in effect pending review; PHMSA used emergency authority extensively after the Colonial Pipeline attack (2021) and after the Marshall, Minnesota crude oil spill
  • § 190.239 — Safety orders: for pipeline facilities with conditions adversely affecting safety that are less urgent than an imminent hazard — PHMSA can issue safety orders after notice and opportunity for hearing; safety orders can require pipeline replacement, enhanced monitoring, or operational restrictions
  • § 190.291 — Criminal penalties: any person who willfully and knowingly violates a pipeline safety regulation is subject to criminal fines under 18 U.S.C. and up to 5 years imprisonment; violations that knowingly and willfully cause death or serious bodily harm are punishable by up to 10 years imprisonment; PHMSA's criminal referrals go to DOJ for prosecution under 49 U.S.C. § 60123

  PHMSA issued approximately $85–100 million in civil penalties in recent years across gas and hazardous liquid pipeline cases. The largest penalties involve operators that fail to implement mandatory integrity management programs, inadequately respond to corrosion or crack indications from in-line inspections, or operate facilities without required safety records. Enforcement actions since the 2010 San Bruno gas explosion (8 deaths, 38 injured) have focused particularly on distribution companies' inadequate records of older unprotected steel and cast iron pipe, and on natural gas pipeline operators' failure to remediate pipeline integrity anomalies within required timelines.

• 49 CFR Part 194 — Response Plans for Onshore Oil Pipelines (15 sections — PHMSA's oil spill response planning requirements implementing the Oil Pollution Act of 1990; applies to hazardous liquid pipeline operators whose facilities could cause significant and substantial harm to the environment):

  • § 194.1 — Purpose: operators must have plans that enable them to respond to a worst-case discharge and to a substantial threat of a worst-case discharge — the requirement forces advance contracting for cleanup resources rather than improvised response after a spill
  • § 194.101 — Covered operators: applies to operators of onshore pipeline facilities that could reasonably cause significant and substantial harm to the environment; PHMSA makes this threshold determination based on proximity to navigable waters, drinking water sources, ecologically sensitive areas, pipeline diameter, and throughput; operators meeting the threshold must submit a response plan within 60 days of notification
  • § 194.103 — Threshold factors: PHMSA evaluates the same risk factors that define High Consequence Areas under Part 195 — most large-diameter hazardous liquid pipelines in HCAs are also subject to Part 194; the two programs are complementary rather than redundant (Part 195 governs pipeline design, integrity, and operations; Part 194 governs spill response)
  • § 194.105 — Worst-case discharge calculation: the plan must quantify the worst-case discharge volume as the largest possible release from the pipeline segment between isolation valves, accounting for: (1) maximum release volume from the break point; (2) drainage volume from the pipeline above and below the break; (3) maximum time to detect the release through monitoring systems; (4) maximum time to isolate the segment through valve operation; (5) additional volume released during shutdown — the result must be expressed in barrels and drives all downstream resource planning
  • § 194.107 — Plan contents: every plan must designate a Qualified Individual (QI) — a specific named person (or backup) with full authority to commit response resources and incur response costs, reachable 24 hours/day; notification procedures for the National Response Center (1-800-424-8802), state emergency response commissions, and local emergency planning committees; a list of contracted response resources (boom, skimmers, vacuum trucks, storage) pre-positioned or contractually available within the planning distance; and a schedule of drills
  • § 194.109 — State plan alternative: operators may submit plans to a state agency if the state program has been approved by EPA as providing equivalent protections; approved state programs currently include Alaska, California, and several others with active coastal spill response requirements
  • § 194.111 — Plan retention: the response plan must be kept at the operator's principal place of business and at each field office supervising the covered segment; field-level copies are required because actual spill response begins at the field level — the person on scene needs immediate access to notification procedures and resource contacts
  • § 194.113 — Information summary: a condensed one-page summary — QI name and phone number, response organization contacts, nearest response equipment location, NRC notification number — must be posted or immediately accessible at each pump station; this summary must be current at all times
  • § 194.115 — Response resources: contractors must be able to mobilize to the planning distance within required timeframes; contracts must be in place before the plan is submitted to PHMSA — identifying a contractor "to be secured" is not sufficient; PHMSA audits contractor availability during plan reviews
  • § 194.117 — Training: all personnel with response responsibilities must be trained annually on their specific role, the location of response equipment, and how to reach the QI; drills (tabletop and field) must be conducted on a cycle that tests all plan components over a rolling 3-year period

  Part 194's Qualified Individual requirement mirrors the parallel system for maritime facilities under 33 U.S.C. § 1228 (OPA 90): someone with decision authority must be reachable immediately after a discharge begins. The worst-case discharge calculation methodology — combining valve spacing, pipeline diameter, flow rate, detection time, and shutdown time — is intentionally conservative: it forces operators to contract for resources sized to the worst plausible event, not the most likely one. PHMSA reviews response plans every 5 years and after significant pipeline incidents. Operators who cannot produce evidence of current contractor agreements, functional QI contacts, or up-to-date inundation analyses face civil penalties under 49 U.S.C. § 60122 and potential operating restrictions.

• 49 CFR Part 199 — Drug and Alcohol Testing for Pipeline Operators (36 sections — PHMSA's anti-drug and anti-alcohol program requirements for operators of pipelines regulated under 49 CFR Parts 192, 193, and 195; implements the DOT-wide drug and alcohol testing framework under 49 U.S.C. § 5103, operating in coordination with DOT's umbrella testing procedures in 49 CFR Part 40):

  • § 199.1 — Scope: applies to operators of natural gas pipeline systems (Part 192), LNG facilities (Part 193), and hazardous liquid pipelines (Part 195); covers covered employees — any person who performs pipeline safety-sensitive functions including operations, maintenance, or emergency response; contractors performing covered functions are treated as employees for program purposes under § 199.115
  • § 199.105 — Drug tests required: operators must conduct the following tests for the presence of marijuana, cocaine, opioids, amphetamines, phencyclidine (PCP), and MDMA: (1) pre-employment (before performing any safety-sensitive function); (2) random (annualized minimum rate of 50% of covered employees — the same rate as DOT's aviation and FMCSA programs; selected through scientifically valid random selection); (3) reasonable suspicion (when a trained supervisor observes specific, contemporaneous behavior indicating drug use or influence); (4) post-accident (when a pipeline incident results in death, injury requiring medical treatment beyond first aid, or property damage above a specified threshold; testing must occur within 32 hours for drugs and 8 hours for alcohol); (5) return-to-duty (after a policy violation, before resuming safety-sensitive functions); (6) follow-up (6 unannounced tests in the first 12 months after return to duty, continuing up to 60 months)
  • § 199.107 — Testing laboratory: all drug tests must be analyzed by a laboratory certified by HHS/SAMHSA; operators may not use clinic-based or point-of-care testing for the formal program (those may be used for pre-employment screening but cannot substitute for the DOT-regulated confirmation test at a certified lab); chain-of-custody documentation is required from collection through laboratory analysis
  • § 199.109 — Medical Review Officer (MRO): each operator must designate or contract with a licensed physician serving as MRO; the MRO reviews all laboratory results before reporting them to the employer — a non-negative result goes to the MRO, who contacts the donor to determine if there is a legitimate medical explanation (valid prescription) before reporting a confirmed positive; only after MRO review does a positive test result trigger any employment action
  • § 199.113 — Employee Assistance Program (EAP): each operator must maintain an EAP providing self-referral resources and information for employees and their supervisors; the EAP must explain the effects and consequences of substance use on personal health, safety, and the work environment; employees who self-refer before being tested receive access to treatment resources; however, self-referral does not prevent or delay required testing
  • § 199.117 — Recordkeeping: operators must retain records documenting all aspects of the testing program for specified periods — 5 years for positive test results and refusals, 1 year for negative test results, and documentation of MRO reviews; records must be made available to PHMSA upon request and protected from unauthorized disclosure; the substance abuse professional (SAP) determination records must be retained for 3 years after the employee leaves the operator
  • § 199.119 — Reporting (large operators): operators with more than 50 covered employees must submit annual Management Information System (MIS) reports to PHMSA by March 15 covering the prior calendar year's testing statistics — number of tests conducted by category, positive rates, refusals, and SAP referrals; these aggregate data let PHMSA track industry-wide substance use trends and compare program compliance across operators
  • §§ 199.200–199.240 — Alcohol misuse program: parallel requirements for alcohol — operators must maintain a written alcohol misuse plan; conduct pre-employment, reasonable suspicion, post-accident, return-to-duty, and follow-up alcohol tests; prohibit a covered employee from performing safety-sensitive functions if they have a breath alcohol concentration of 0.04 or above (confirmed by a second test); removal from safety-sensitive duties is required for results of 0.02–0.039 until a subsequent test below 0.02 (a 24-hour minimum out-of-service period)

  PHMSA's Part 199 program operates within the DOT-wide testing framework in 49 CFR Part 40, which governs the mechanics of collection, specimen handling, MRO functions, and SAP evaluation — Part 199 sets the pipeline-specific scope and thresholds while Part 40 controls how every federally mandated transportation industry drug and alcohol test is actually conducted. The pipeline industry's safety-sensitive workforce includes control room operators who monitor and control pressure and flow in real time, field technicians who perform valve operations and maintenance on pressurized systems, and emergency responders who must be fully functional when called upon. PHMSA conducts compliance reviews of pipeline operator drug and alcohol programs as part of its standard facility inspection cycle; deficiencies can result in civil penalties and required corrective actions.

Pending Legislation

• HR 6187 — Wojnovich Pipeline Safety Act of 2025: grant program, stronger notices, penalties, and trust fund for pipeline safety. Status: Introduced.
• S 2975 (Sen. Cruz, R-TX) — PIPELINE Safety Act of 2025: modernizes pipeline safety, raises PHMSA funding, creates confidential data-sharing. Status: In Committee.
• HR 5368 (Rep. Strickland, D-WA) — Pipeline Safety Engagement Act: creates Office of Public Engagement at PHMSA. Status: In Committee.

Recent Developments

• PHMSA's gas transmission pipeline "mega rule" expanded safety requirements beyond High Consequence Areas, representing the most comprehensive update to gas pipeline safety rules in decades
• Increasing focus on methane leak detection and repair as both a safety and climate priority — methane is a potent greenhouse gas
• Infrastructure Investment and Jobs Act (2021) provided funding for pipeline safety technology, state grant programs, and orphaned well plugging
• Colonial Pipeline cyberattack (2021) prompted new cybersecurity requirements for pipeline operators through TSA security directives
• Aging infrastructure replacement remains a multi-decade, multi-billion dollar challenge — estimated 50,000+ miles of distribution mains need replacement
• In March 2026, FERC opened an environmental scoping period for the proposed Viola Project by Southern Star Central Gas Pipeline and the Line 31 Expansion by Texas Eastern Transmission, soliciting public comments on environmental issues for both natural gas pipeline projects.
• In February 2026, PHMSA published a request for special permit from Sable Offshore Corp., seeking relief from certain pipeline safety compliance requirements for offshore operations.