177 

Pipeline and Hazardous Materials Safety Administration, DOT Pt. 195 

Major rivers Nearest town and state 

White River ............................ Batesville, AR. 

White River ............................ Grand Glaise, AR. 

Wisconsin River ..................... Wisconsin Rapids, WI. 

Yukon River ........................... Fairbanks, AK. 

Other Navigable Waters 

Arthur Kill Channel, NY 

Cook Inlet, AK 

Freeport, TX 

Los Angeles/Long Beach Harbor, CA 

Port Lavaca, TX 

San Fransico/San Pablo Bay, CA 

PART 195—TRANSPORTATION OF 

HAZARDOUS LIQUIDS BY PIPELINE 

Subpart A—General 

Sec. 

195.0 Scope. 

195.1 Which pipelines are covered by this 

part? 

195.2 Definitions. 

195.3 Incorporation by reference. 

195.4 Compatibility necessary for transportation of hazardous liquids or carbon dioxide. 

195.5 Conversion to service subject to this 

part. 

195.6 Unusually Sensitive Areas (USAs). 

195.8 Transportation of hazardous liquid or 

carbon dioxide in pipelines constructed 

with other than steel pipe. 

195.9 Outer continental shelf pipelines. 

195.10 Responsibility of operator for compliance with this part. 

195.11 What is a regulated rural gathering 

line and what requirements apply? 

195.12 What requirements apply to lowstress pipelines in rural areas? 

Subpart B—Annual, Accident, and SafetyRelated Condition Reporting 

195.48 Scope. 

195.49 Annual report. 

195.50 Reporting accidents. 

195.52 Telephonic notice of certain accidents. 

195.54 Accident reports. 

195.55 Reporting safety-related conditions. 

195.56 Filing safety-related condition reports. 

195.57 Filing offshore pipeline condition reports. 

195.58 Address for written reports. 

195.59 Abandonment or deactivation of facilities. 

195.60 Operator assistance in investigation. 

195.62 Supplies of accident report DOT 

Form 7000–1. 

195.63 OMB control number assigned to information collection. 

Subpart C—Design Requirements 

195.100 Scope. 

195.101 Qualifying metallic components 

other than pipe. 

195.102 Design temperature. 

195.104 Variations in pressure. 

195.106 Internal design pressure. 

195.108 External pressure. 

195.110 External loads. 

195.111 Fracture propagation. 

195.112 New pipe. 

195.114 Used pipe. 

195.116 Valves. 

195.118 Fittings. 

195.120 Passage of internal inspection devices. 

195.122 Fabricated branch connections. 

195.124 Closures. 

195.126 Flange connection. 

195.128 Station piping. 

195.130 Fabricated assemblies. 

195.132 Design and construction of aboveground breakout tanks. 

195.134 CPM leak detection. 

Subpart D—Construction 

195.200 Scope. 

195.202 Compliance with specifications or 

standards. 

195.204 Inspection—general. 

195.205 Repair, alteration and reconstruction of aboveground breakout tanks that 

have been in service. 

195.206 Material inspection. 

195.207 Transportation of pipe. 

195.208 Welding of supports and braces. 

195.210 Pipeline location. 

195.212 Bending of pipe. 

195.214 Welding: General. 

195.216 Welding: Miter joints. 

195.222 Welders: Qualification of welders. 

195.224 Welding: Weather. 

195.226 Welding: Arc burns. 

195.228 Welds and welding inspection: 

Standards of acceptability. 

195.230 Welds: Repair or removal of defects. 

195.234 Welds: Nondestructive testing. 

195.236–195.244 [Reserved] 

195.246 Installation of pipe in a ditch. 

195.248 Cover over buried pipeline. 

195.250 Clearance between pipe and underground structures. 

195.252 Backfilling. 

195.254 Above ground components. 

195.256 Crossing of railroads and highways. 

195.258 Valves: General. 

195.260 Valves: Location. 

195.262 Pumping equipment. 

195.264 Impoundment, protection against 

entry, normal/emergency venting or 

pressure/vacuum relief for aboveground 

breakout tanks. 

195.266 Construction records. 


wwoods2 on DSK1DXX6B1PROD with CFR
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Pt. 195 49 CFR Ch. I (10–1–10 Edition) 

Subpart E—Pressure Testing 

195.300 Scope. 

195.302 General requirements. 

195.303 Risk-based alternative to pressure 

testing older hazardous liquid and carbon 

dioxide pipelines. 

195.304 Test pressure. 

195.305 Testing of components. 

195.306 Test medium. 

195.307 Pressure testing aboveground breakout tanks. 

195.308 Testing of tie-ins. 

195.310 Records. 

Subpart F—Operation and Maintenance 

195.400 Scope. 

195.401 General requirements. 

195.402 Procedural manual for operations, 

maintenance, and emergencies. 

195.403 Emergency response training. 

195.404 Maps and records. 

195.405 Protection against ignitions and safe 

access/egress involving floating roofs. 

195.406 Maximum operating pressure. 

195.408 Communications. 

195.410 Line markers. 

195.412 Inspection of rights-of-way and 

crossings under navigable waters. 

195.413 Underwater inspection and reburial 

of pipelines in the Gulf of Mexico and its 

inlets. 

195.414–195.418 [Reserved] 

195.420 Valve maintenance. 

195.422 Pipeline repairs. 

195.424 Pipe movement. 

195.426 Scraper and sphere facilities. 

195.428 Overpressure safety devices and 

overfill protection systems. 

195.430 Firefighting equipment. 

195.432 Inspection of in-service breakout 

tanks. 

195.434 Signs. 

195.436 Security of facilities. 

195.438 Smoking or open flames. 

195.440 Public awareness. 

195.442 Damage prevention program. 

195.444 CPM leak detection. 

195.446 Control room management. 

HIGH CONSEQUENCE AREAS

195.450 Definitions. 

PIPELINE INTEGRITY MANAGEMENT

195.452 Pipeline integrity management in 

high consequence areas. 

Subpart G—Qualification of Pipeline 

Personnel 

195.501 Scope. 

195.503 Definitions. 

195.505 Qualification program. 

195.507 Recordkeeping. 

195.509 General. 

Subpart H—Corrosion Control 

195.551 What do the regulations in this subpart cover? 

195.553 What special definitions apply to 

this subpart? 

195.555 What are the qualifications for supervisors? 

195.557 Which pipelines must have coating 

for external corrosion control? 

195.559 What coating material may I use for 

external corrosion control? 

195.561 When must I inspect pipe coating 

used for external corrosion control? 

195.563 Which pipelines must have cathodic 

protection? 

195.565 How do I install cathodic protection 

on breakout tanks? 

195.567 Which pipelines must have test leads 

and what must I do to install and maintain the leads? 

195.569 Do I have to examine exposed portions of buried pipelines? 

195.571 What criteria must I use to determine the adequacy of cathodic protection? 

195.573 What must I do to monitor external 

corrosion control? 

195.575 Which facilities must I electrically 

isolate and what inspections, tests, and 

safeguards are required? 

195.577 What must I do to alleviate interference currents? 

195.579 What must I do to mitigate internal 

corrosion? 

195.581 Which pipelines must I protect 

against atmospheric corrosion and what 

coating material may I use? 

195.583 What must I do to monitor atmospheric corrosion control? 

195.585 What must I do to correct corroded 

pipe? 

195.587 What methods are available to determine the strength of corroded pipe? 

195.588 What standards apply to direct assessment? 

195.589 What corrosion control information 

do I have to maintain? 

APPENDIX A TO PART 195—DELINEATION BETWEEN FEDERAL AND STATE JURISDICTION—STATEMENT OF AGENCY POLICY AND

INTERPRETATION

APPENDIX B TO PART 195—RISK-BASED ALTERNATIVE TO PRESSURE TESTING OLDER HAZARDOUS LIQUID AND CARBON DIOXIDE PIPELINES

APPENDIX C TO PART 195—GUIDANCE FOR IMPLEMENTATION OF AN INTEGRITY MANAGEMENT PROGRAM

AUTHORITY: 49 U.S.C. 5103, 60102, 60104, 

60108, 60109, 60116, 60118, and 60137; and 49 CFR 

1.53. 

SOURCE: Amdt. 195–22, 46 FR 38360, July 27, 

1981, unless otherwise noted. 


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Pipeline and Hazardous Materials Safety Administration, DOT § 195.1 

EDITORIAL NOTE: Nomenclature changes to 

part 195 appear at 71 FR 33409, June 9, 2006. 

Subpart A—General 

§ 195.0 Scope. 

This part prescribes safety standards 

and reporting requirements for pipeline 

facilities used in the transportation of 

hazardous liquids or carbon dioxide. 

[Amdt. 195–45, 56 FR 26925, June 12, 1991] 

§ 195.1 Which pipelines are covered by 

this part? 

(a) Covered. Except for the pipelines 

listed in paragraph (b) of this section, 

this part applies to pipeline facilities 

and the transportation of hazardous 

liquids or carbon dioxide associated 

with those facilities in or affecting 

interstate or foreign commerce, including pipeline facilities on the Outer 

Continental Shelf (OCS). This includes: 

(1) Any pipeline that transports a 

highly volatile liquid (HVL); 

(2) Transportation through any pipeline, other than a gathering line, that 

has a maximum operating pressure 

(MOP) greater than 20-percent of the 

specified minimum yield strength; 

(3) Any pipeline segment that crosses 

a waterway currently used for commercial navigation; 

(4) Transportation of petroleum in 

any of the following onshore gathering 

lines: 

(i) A pipeline located in a non-rural 

area; 

(ii) To the extent provided in §195.11, 

a regulated rural gathering line defined 

in §195.11; or 

(iii) To the extent provided in 

§195.413, a pipeline located in an inlet 

of the Gulf of Mexico. 

(5) Transportation of a hazardous liquid or carbon dioxide through a lowstress pipeline or segment of pipeline 

that: 

(i) Is in a non-rural area; or 

(ii) Meets the criteria defined in 

§195.12(a). 

(6) For purposes of the reporting requirements in subpart B, a rural lowstress pipeline of any diameter. 

(b) Excepted. This part does not apply 

to any of the following: 

(1) Transportation of a hazardous liquid transported in a gaseous state; 

(2) Transportation of a hazardous liquid through a pipeline by gravity; 

(3) A pipeline subject to safety regulations of the U.S. Coast Guard; 

(4) A low-stress pipeline that serves 

refining, manufacturing, or truck, rail, 

or vessel terminal facilities, if the 

pipeline is less than one mile long 

(measured outside facility grounds) and 

does not cross an offshore area or a waterway currently used for commercial 

navigation; 

(5) Transportation of hazardous liquid or carbon dioxide in an offshore 

pipeline in State waters where the 

pipeline is located upstream from the 

outlet flange of the following farthest 

downstream facility: The facility 

where hydrocarbons or carbon dioxide 

are produced or the facility where produced hydrocarbons or carbon dioxide 

are first separated, dehydrated, or otherwise processed; 

(6) Transportation of hazardous liquid or carbon dioxide in a pipeline on 

the OCS where the pipeline is located 

upstream of the point at which operating responsibility transfers from a 

producing operator to a transporting 

operator; 

(7) A pipeline segment upstream 

(generally seaward) of the last valve on 

the last production facility on the OCS 

where a pipeline on the OCS is producer-operated and crosses into State 

waters without first connecting to a 

transporting operator’s facility on the 

OCS. Safety equipment protecting 

PHMSA-regulated pipeline segments is 

not excluded. A producing operator of a 

segment falling within this exception 

may petition the Administrator, under 

§190.9 of this chapter, for approval to 

operate under PHMSA regulations governing pipeline design, construction, 

operation, and maintenance; 

(8) Transportation of a hazardous liquid or carbon dioxide through onshore 

production (including flow lines), refining, or manufacturing facilities or storage or in-plant piping systems associated with such facilities; 

(9) Transportation of a hazardous liquid or carbon dioxide: 

(i) By vessel, aircraft, tank truck, 

tank car, or other non-pipeline mode of 

transportation; or 

(ii) Through facilities located on the 

grounds of a materials transportation 


wwoods2 on DSK1DXX6B1PROD with CFR
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§ 195.2 49 CFR Ch. I (10–1–10 Edition) 

terminal if the facilities are used exclusively to transfer hazardous liquid 

or carbon dioxide between non-pipeline 

modes of transportation or between a 

non-pipeline mode and a pipeline. 

These facilities do not include any device and associated piping that are necessary to control pressure in the pipeline under §195.406(b); or 

(10) Transportation of carbon dioxide 

downstream from the applicable following point: 

(i) The inlet of a compressor used in 

the injection of carbon dioxide for oil 

recovery operations, or the point where 

recycled carbon dioxide enters the injection system, whichever is farther 

upstream; or 

(ii) The connection of the first 

branch pipeline in the production field 

where the pipeline transports carbon 

dioxide to an injection well or to a 

header or manifold from which a pipeline branches to an injection well. 

(c) Breakout tanks. Breakout tanks 

subject to this part must comply with 

requirements that apply specifically to 

breakout tanks and, to the extent applicable, with requirements that apply 

to pipeline systems and pipeline facilities. If a conflict exists between a requirement that applies specifically to 

breakout tanks and a requirement that 

applies to pipeline systems or pipeline 

facilities, the requirement that applies 

specifically to breakout tanks prevails. 

Anhydrous ammonia breakout tanks 

need not comply with §§195.132(b), 

195.205(b), 195.242 (c) and (d), 195.264(b) 

and (e), 195.307, 195.428(c) and (d), and 

195.432(b) and (c). 

[73 FR 31644, June 3, 2008] 

EDITORIAL NOTE: For FEDERAL REGISTER citations affecting §195.1, see the List of CFR 

Sections Affected, which appears in the 

Finding Aids section of the printed volume 

and on GPO Access. 

§ 195.2 Definitions. 

As used in this part— 

Abandoned means permanently removed from service. 

Administrator means the Administrator, Pipeline and Hazardous Materials Safety Administration or his or 

her delegate. 

Alarm means an audible or visible 

means of indicating to the controller 

that equipment or processes are outside operator-defined, safetyBarrel means a unit of measurement 

equal to 42 U.S. standard gallons. 

Breakout tank means a tank used to 

(a) relieve surges in a hazardous liquid 

pipeline system or (b) receive and store 

hazardous liquid transported by a pipeline for reinjection and continued 

transportation by pipeline. 

Carbon dioxide means a fluid consisting of more than 90 percent carbon 

dioxide molecules compressed to a 

supercritical state. 

Component means any part of a pipeline which may be subjected to pump 

pressure including, but not limited to, 

pipe, valves, elbows, tees, flanges, and 

closures. 

Computation Pipeline Monitoring 

(CPM) means a software-based monitoring tool that alerts the pipeline dispatcher of a possible pipeline operating 

anomaly that may be indicative of a 

commodity release. 

Control room means an operations 

center staffed by personnel charged 

with the responsibility for remotely 

monitoring and controlling a pipeline 

facility. 

Controller means a qualified individual who remotely monitors and controls the safety-related operations of a 

pipeline facility via a SCADA system 

from a control room, and who has operational authority and accountability 

for the remote operational functions of 

the pipeline facility. 

Corrosive product means ‘‘corrosive 

material’’ as defined by §173.136 Class 

8–Definitions of this chapter. 

Exposed underwater pipeline means an 

underwater pipeline where the top of 

the pipe protrudes above the underwater natural bottom (as determined 

by recognized and generally accepted 

practices) in waters less than 15 feet 

(4.6 meters) deep, as measured from 

mean low water. 

Flammable product means ‘‘flammable 

liquid’’ as defined by §173.120 Class 3– 

Definitions of this chapter. 

Gathering line means a pipeline 219.1 

mm (85⁄8 in) or less nominal outside diameter that transports petroleum from 

a production facility. 

Gulf of Mexico and its inlets means the 

waters from the mean high water mark 

of the coast of the Gulf of Mexico and 


wwoods2 on DSK1DXX6B1PROD with CFR
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Pipeline and Hazardous Materials Safety Administration, DOT § 195.2 

its inlets open to the sea (excluding 

rivers, tidal marshes, lakes, and canals) seaward to include the territorial 

sea and Outer Continental Shelf to a 

depth of 15 feet (4.6 meters), as measured from the mean low water. 

Hazard to navigation means, for the 

purposes of this part, a pipeline where 

the top of the pipe is less than 12 

inches (305 millimeters) below the underwater natural bottom (as determined by recognized and generally accepted practices) in waters less than 15 

feet (4.6 meters) deep, as measured 

from the mean low water. 

Hazardous liquid means petroleum, 

petroleum products, or anhydrous ammonia. 

Highly volatile liquid or HVL means a 

hazardous liquid which will form a 

vapor cloud when released to the atmosphere and which has a vapor pressure exceeding 276 kPa (40 psia) at 37.8 

°C (100 °F). 

In-plant piping system means piping 

that is located on the grounds of a 

plant and used to transfer hazardous 

liquid or carbon dioxide between plant 

facilities or between plant facilities 

and a pipeline or other mode of transportation, not including any device and 

associated piping that are necessary to 

control pressure in the pipeline under 

§195.406(b). 

Interstate pipeline means a pipeline or 

that part of a pipeline that is used in 

the transportation of hazardous liquids 

or carbon dioxide in interstate or foreign commerce. 

Intrastate pipeline means a pipeline or 

that part of a pipeline to which this 

part applies that is not an interstate 

pipeline. 

Line section means a continuous run 

of pipe between adjacent pressure pump 

stations, between a pressure pump station and terminal or breakout tanks, 

between a pressure pump station and a 

block valve, or between adjacent block 

valves. 

Low-stress pipeline means a hazardous 

liquid pipeline that is operated in its 

entirety at a stress level of 20 percent 

or less of the specified minimum yield 

strength of the line pipe. 

Maximum operating pressure (MOP) 

means the maximum pressure at which 

a pipeline or segment of a pipeline may 

be normally operated under this part. 

Nominal wall thickness means the wall 

thickness listed in the pipe specifications. 

Offshore means beyond the line of ordinary low water along that portion of 

the coast of the United States that is 

in direct contact with the open seas 

and beyond the line marking the seaward limit of inland waters. 

Operator means a person who owns or 

operates pipeline facilities. 

Outer Continental Shelf means all submerged lands lying seaward and outside the area of lands beneath navigable waters as defined in Section 2 of 

the Submerged Lands Act (43 U.S.C. 

1301) and of which the subsoil and seabed appertain to the United States and 

are subject to its jurisdiction and control. 

Person means any individual, firm, 

joint venture, partnership, corporation, 

association, State, municipality, cooperative association, or joint stock association, and includes any trustee, receiver, assignee, or personal representative thereof. 

Petroleum means crude oil, condensate, natural gasoline, natural gas liquids, and liquefied petroleum gas. 

Petroleum product means flammable, 

toxic, or corrosive products obtained 

from distilling and processing of crude 

oil, unfinished oils, natural gas liquids, 

blend stocks and other miscellaneous 

hydrocarbon compounds. 

Pipe or line pipe means a tube, usually cylindrical, through which a hazardous liquid or carbon dioxide flows 

from one point to another. 

Pipeline or pipeline system means all 

parts of a pipeline facility through 

which a hazardous liquid or carbon dioxide moves in transportation, including, but not limited to, line pipe, 

valves, and other appurtenances connected to line pipe, pumping units, fabricated assemblies associated with 

pumping units, metering and delivery 

stations and fabricated assemblies 

therein, and breakout tanks. 

Pipeline facility means new and existing pipe, rights-of-way and any equipment, facility, or building used in the 

transportation of hazardous liquids or 

carbon dioxide. 


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§ 195.3 49 CFR Ch. I (10–1–10 Edition) 

Production facility means piping or 

equipment used in the production, extraction, recovery, lifting, stabilization, separation or treating of petroleum or carbon dioxide, or associated 

storage or measurement. (To be a production facility under this definition, 

piping or equipment must be used in 

the process of extracting petroleum or 

carbon dioxide from the ground or from 

facilities where CO2 is produced, and 

preparing it for transportation by pipeline. This includes piping between 

treatment plants which extract carbon 

dioxide, and facilities utilized for the 

injection of carbon dioxide for recovery 

operations.) 

Rural area means outside the limits 

of any incorporated or unincorpated 

city, town, village, or any other designated residential or commercial area 

such as a subdivision, a business or 

shopping center, or community development. 

Specified minimum yield strength 

means the minimum yield strength, expressed in p.s.i. (kPa) gage, prescribed 

by the specification under which the 

material is purchased from the manufacturer. 

Stress level means the level of tangential or hoop stress, usually expressed as 

a percentage of specified minimum 

yield strength. 

Supervisory Control and Data Acquisition (SCADA) system means a computerbased system or systems used by a controller in a control room that collects 

and displays information about a pipeline facility and may have the ability 

to send commands back to the pipeline 

facility. 

Surge pressure means pressure produced by a change in velocity of the 

moving stream that results from shutting down a pump station or pumping 

unit, closure of a valve, or any other 

blockage of the moving stream. 

Toxic product means ‘‘poisonous material’’ as defined by §173.132 Class 6, 

Division 6.1–Definitions of this chapter. 

Unusually Sensitive Area (USA) means 

a drinking water or ecological resource 

area that is unusually sensitive to environmental damage from a hazardous 

liquid pipeline release, as identified 

under §195.6. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981; 47 

FR 32721, July 29, 1982, as amended by Amdt. 

195–33, 50 FR 15898, Apr. 23, 1985; 50 FR 38660, 

Sept. 24, 1985; Amdt. 195–36, 51 FR 15007, Apr. 

22, 1986; Amdt. 195–45, 56 FR 26925, June 12, 

1991; Amdt. 195–47, 56 FR 63771, Dec. 5, 1991; 

Amdt. 195–50, 59 FR 17281, Apr. 12, 1994; Amdt. 

195–52, 59 FR 33395, 33396, June 28, 1994; Amdt. 

195–53, 59 FR 35471, July 12, 1994; Amdt. 195– 

59, 62 FR 61695, Nov. 19, 1997; Amdt. 195–62, 63 

FR 36376, July 6, 1998; Amdt. 195–63, 63 FR 

37506, July 13, 1998; Amdt. 195–69, 65 FR 54444, 

Sept. 8, 2000; Amdt. 195–71, 65 FR 80544, Dec. 

21, 2000; 68 FR 11749, Mar. 12, 2003; Amdt. 195– 

81, 69 FR 32896, June 14, 2004; Amdt. 195–82, 69 

FR 48406, Aug. 10, 2004; 70 FR 11140, Mar. 8, 

2005; Amdt. 195–93, 74 FR 63328, Dec. 3, 2009] 

§ 195.3 Incorporation by reference. 

(a) Any document or portion thereof 

incorporated by reference in this part 

is included in this part as though it 

were printed in full. When only a portion of a document is referenced, then 

this part incorporates only that referenced portion of the document and 

the remainder is not incorporated. Applicable editions are listed in paragraph (c) of this section in parentheses 

following the title of the referenced 

material. Earlier editions listed in previous editions of this section may be 

used for components manufactured, designed, or installed in accordance with 

those earlier editions at the time they 

were listed. The user must refer to the 

appropriate previous edition of 49 CFR 

for a listing of the earlier editions. 

(b) All incorporated materials are 

available for inspection in the Office of 

Pipelline Safety, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, 1200 New Jersey Avenue, SE., 

Washington, DC, 20590–0001, 202–366– 

4595, or at the National Archives and 

Records Administration (NARA). For 

information on the availability of this 

material at NARA, call 202–741–6030 or 

go to: http://www.archives.gov/ 

federallregister/ 

codeloflfederallregulations/ 

ibrllocations.html. These materials 

have been approved for incorporation 

by reference by the Director of the 

Federal Register in accordance with 5 


wwoods2 on DSK1DXX6B1PROD with CFR
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Pipeline and Hazardous Materials Safety Administration, DOT § 195.3 

U.S.C. 552(a) and 1 CFR part 51. In addition, materials incorporated by reference are available as follows: 

1. Pipeline Research Council International, Inc. (PRCI), c/o Technical 

Toolboxes, 3801 Kirby Drive, Suite 520, 

Houston, TX 77098. 

2. American Petroleum Institute 

(API), 1220 L Street, NW., Washington, 

DC 20005. 

3. ASME International (ASME), 

Three Park Avenue, New York, NY 

10016–5990. 

4. Manufacturers Standardization Society of the Valve and Fittings Industry, Inc. (MSS), 127 Park Street, NE., 

Vienna, VA 22180. 

5. American Society for Testing and 

Materials (ASTM), 100 Barr Harbor 

Drive, West Conshohocken, PA 19428. 

6. National Fire Protection Association (NFPA), 1 Batterymarch Park, 

P.O. Box 9101, Quincy, MA 02269–9101. 

7. NACE International, 1440 South 

Creek Drive, Houston, TX 77084. 

(c) The full titles of publications incorporated by reference wholly or partially in this part are as follows. Numbers in parentheses indicate applicable 

editions: 


wwoods2 on DSK1DXX6B1PROD with CFR
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§ 195.3 49 CFR Ch. I (10–1–10 Edition) Source and name of referenced material 49 CFR reference A. Pipeline Research Council International, Inc. (PRCI): (1) AGA Pipeline Research Committee, Project PR–3–805, ‘‘A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe,’’ (December 22, 1989). The RSTRENG program may be used for calculating remain- ing strength. §§ 195.452(h)(4)(i)(B); 195.452(h)(4)(iii)(D); 195.587. B. American Petroleum Institute (API): (1) ANSI/API Specification 5L/ISO 3183, ‘‘Specification for Line Pipe’’ (44th edition, October 2007, including errata (January 2009) and addendum (February 2009)). §§ 195.106(b)(1)(i); 195.106(e). (2) API Recommended Practice 5L1, ‘‘Recommended Practice for Railroad Transportation of Line Pipe’’ (6th edition, July 2002). § 195.207(a). (3) API Recommended Practice 5LW, ‘‘Transportation of Line Pipe on Barges and Marine Vessels’’ (2nd edition, De- cember 1996, effective March 1, 1997). § 195.207(b). (4) ANSI/API Specification 6D, ‘‘Specification for Pipeline Valves’’ (23rd edition, April 2008, effective October 1, 2008) and errata 3 (includes 1 & 2 (2009). § 195.116(d). (5) API Specification 12F, ‘‘Specification for Shop Welded Tanks for Storage of Production Liquids’’ (11th edition, November 1, 1994, reaffirmed 2000, errata, February 2007). §§ 195.132(b)(1); 195.205(b)(2); 195.264(b)(1); 195.264(e)(1); 195.307(a); 195.565; 195.579(d). (6) API Standard 510, ‘‘Pressure Vessel Inspection Code: In-Service Inspection, Rating, Repair, and Alteration’’ (9th edition, June 2006). §§ 195.205(b)(3); 195.432(c). (7) API Standard 620, ‘‘Design and Construction of Large, Welded, Low-Pressure Storage Tanks’’ (11th edition, February 2008, addendum 1 March 2009). §§ 195.132(b)(2); 195.205(b)(2); 195.264(b)(1); 195.264(e)(3); 195.307(b). (8) API Standard 650, ‘‘Welded Steel Tanks for Oil Storage’’ (11th edition, June 2007, addendum 1, November 2008). §§ 195.132(b)(3); 195.205(b)(1); 195.264(b)(1);195.264(e)(2); 195.307(c); 195.307(d); 195.565; 195.579(d). (9) ANSI/API Recommended Practice 651, ‘‘Cathodic Protection of Aboveground Petroleum Storage Tanks’’ (3rd edition, January 2007). §§ 195.565; 195.579(d). (10) ANSI/API Recommended Practice 652, ‘‘Linings of Aboveground Petroleum Storage Tank Bottoms’’ (3rd edi- tion, October 2005). § 195.579(d). (11) API Standard 653, ‘‘Tank Inspection, Repair, Alteration, and Reconstruction’’ (3rd edition, December 2001, in- cludes addendum 1 (September 2003), addendum 2 (November 2005), addendum 3 (February 2008), and errata (April 2008)). §§ 195.205(b)(1); 195.432(b). (12) API Standard 1104, ‘‘Welding of Pipelines and Related Facilities’’ (20th edition, October 2005, errata/addendum (July 2007), and errata 2 December 2008)). §§ 195.222(a); 195.228(b); 195.214(a). (13) API Recommended Practice 1130, ‘‘Computational Pipeline Monitoring for Liquids: Pipeline Segment’’ (3rd edi- tion, September 2007). §§ 195.134; 195.444. (14) API Recommended Practice 1162, ‘‘Public Awareness Programs for Pipeline Operators’’ (1st edition, December 2003). §§ 195.440(a); 195.440(b); 195.440(c). (15) API Recommended Practice 1165, ‘‘Recommended Practice for Pipeline SCADA Displays,’’ (API RP 1165) First Edition (January 2007). § 195.446(c)(1). (16) API Standard 2000, ‘‘Venting Atmospheric and Low-Pressure Storage Tanks Nonrefrigerated and Refrigerated’’ (5th edition, April 1998, errata, November 15, 1999). §§ 195.264(e)(2); 195.264(e)(3). (17) API Recommended Practice 2003, ‘‘Protection Against Ignitions Arising Out of Static, Lightning, and Stray Cur- rents’’ (7th edition, January 2008). § 195.405(a). (18) API Publication 2026, ‘‘Safe Access/Egress Involving Floating Roofs of Storage Tanks in Petroleum Service’’ (2nd edition, April 1998, reaffirmed June 2006). § 195.405(b). (19) API Recommended Practice 2350, ‘‘Overfill Protection for Storage Tanks In Petroleum Facilities’’’ (3rd edition, January 2005). § 195.428(c). (20) API 2510, ‘‘Design and Construction of LPG Installations’’ (8th edition, 2001) ....................................................... §§ 195.132(b)(3); 195.205(b)(3); 195.264(b)(2); 195.264(e)(4); 195.307(e); 195.428(c); 195.432(c). (21) API Recommended Practice 1168 ‘‘Pipeline Control Room Management,’’ (API RP1168) First Edition (Sep- tember 2008). § 195.446(c)(5), (f)(1). 


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Pipeline and Hazardous Materials Safety Administration, DOT § 195.3 C. ASME International (ASME): (1) ASME/ANSI B16.9–2007, ‘‘Factory-Made Wrought Buttwelding Fittings’’ (December 7, 2007) ................................ § 195.118(a). (2) ASME/ANSI B31.4–2006, ‘‘Pipeline Transportation Systems for Liquid Hydrocarbons and Other Liquids’’ (Octo- ber 20, 2006). § 195.452(h)(4)(i). (3) ASME/ANSI B31G–1991 (Reaffirmed; 2004), ‘‘Manual for Determining the Remaining Strength of Corroded Pipe- lines.’’. §§ 195.452(h)(4)(i)(B); 195.452(h)(4)(iii)(D). (4) ASME/ANSI B31.8–2007, ‘‘Gas Transmission and Distribution Piping Systems’’ (November 30, 2007) .................. § 195.5(a)(1)(i); 195.406(a)(1)(i). (5) 2007 ASME Boiler & Pressure Vessel Code, Section VIII, Division 1 ‘‘Rules for Construction of Pressure Ves- sels’’ (2007 edition, July 1, 2007). § 195.124; 195.307(e). (6) 2007 ASME Boiler & Pressure Vessel Code, Section VIII, Division 2 ‘‘Alternate Rules, Rules for Construction of Pressure Vessels’’ (2007 edition, July 1, 2007). § 195.307(e). (7) 2007 ASME Boiler & Pressure Vessel Code, Section IX: ‘‘Qualification Standard for Welding and Brazing Proce- dures, Welders, Brazers, and Welding and Brazing Operators,’’ (2007 edition, July 1, 2007). § 195.222(a). D. Manufacturers Standardization Society of the Valve and Fittings Industry, Inc. (MSS): (1) MSS SP–75–2004, ‘‘Specification for High Test Wrought Butt Welding Fittings.’’ ..................................................... § 195.118(a). (2) [Reserved] ................................................................................................................................................................... E. American Society for Testing and Materials (ASTM): (1) ASTM A53/A53M–07, ‘‘Standard Specification for Pipe, Steel, Black and Hot-Dipped, Zinc-Coated Welded and Seamless’’ (September 1, 2007). § 195.106(e). (2) ASTM A106/A106M–08, ‘‘Standard Specification for Seamless Carbon Steel Pipe for High-Temperature Service’’ (July 15, 2008). § 195.106(e). (3) ASTM A333/A 333M–05, ‘‘Standard Specification for Seamless and Welded Steel Pipe for Low-Temperature Service.’’. § 195.106(e). (4) ASTM A381–96 (Reapproved 2005), ‘‘Standard Specification for Metal-Arc-Welded Steel Pipe for Use With High- Pressure Transmission Systems’’ (October 1, 2005). § 195.106(e). (5) ASTM A671–06, ‘‘Standard Specification for Electric-Fusion-Welded Steel Pipe for Atmospheric and Lower Tem- peratures’’ (May 1, 2006). § 195.106(e). (6) ASTM A672–08, ‘‘Standard Specification for Electric-Fusion-Welded Steel Pipe for High-Pressure Service at Moderate Temperatures’’ (May 1, 2008). § 195.106(e). (7) ASTM A691–98 (reapproved 2007), ‘‘Standard Specification for Carbon and Alloy Steel Pipe Electric-Fusion- Welded for High-Pressure Service at High Temperatures.’’. § 195.106(e). F. National Fire Protection Association (NFPA): (1) NFPA 30, ‘‘Flammable and Combustible Liquids Code’’ (2008 edition, approved August 15, 2007) ........................ § 195.264(b)(1). (2) [Reserved] ................................................................................................................................................................... G. NACE International (NACE): (1) NACE SP0169–2007, Standard Practice, ‘‘Control of External Corrosion on Underground or Submerged Metallic Piping Systems’’ (reaffirmed March 15, 2007). §§ 195.571; 195.573(a)(2). (2) NACE SP0502–2008, Standard Practice, ‘‘Pipeline External Corrosion Direct Assessment Methodology’’ (re- affirmed March 20, 2008). § 195.588. 


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§ 195.4 49 CFR Ch. I (10–1–10 Edition) 

[Amdt. 195–22, 46 FR 38360, July 27, 1981; 47 

FR 32721, July 29, 1982] 

EDITORIAL NOTE: For FEDERAL REGISTER citations affecting §195.3, see the List of CFR 

Sections Affected, which appears in the 

Finding Aids section of the printed volume 

and on GPO Access. 

§ 195.4 Compatibility necessary for 

transportation of hazardous liquids 

or carbon dioxide. 

No person may transport any hazardous liquid or carbon dioxide unless 

the hazardous liquid or carbon dioxide 

is chemically compatible with both the 

pipeline, including all components, and 

any other commodity that it may come 

into contact with while in the pipeline. 

[Amdt. 195–45, 56 FR 26925, June 12, 1991] 

§ 195.5 Conversion to service subject 

to this part. 

(a) A steel pipeline previously used in 

service not subject to this part qualifies for use under this part if the operator prepares and follows a written 

procedure to accomplish the following: 

(1) The design, construction, operation, and maintenance history of the 

pipeline must be reviewed and, where 

sufficient historical records are not 

available, appropriate tests must be 

performed to determine if the pipeline 

is in satisfactory condition for safe operation. If one or more of the variables 

necessary to verify the design pressure 

under §195.106 or to perform the testing 

under paragraph (a)(4) of this section is 

unknown, the design pressure may be 

verified and the maximum operating 

pressure determined by— 

(i) Testing the pipeline in accordance 

with ASME B31.8, Appendix N, to 

produce a stress equal to the yield 

strength; and 

(ii) Applying, to not more than 80 

percent of the first pressure that produces a yielding, the design factor F in 

§195.106(a) and the appropriate factors 

in §195.106(e). 

(2) The pipeline right-of-way, all 

aboveground segments of the pipeline, 

and appropriately selected underground segments must be visually inspected for physical defects and operating conditions which reasonably 

could be expected to impair the 

strength or tightness of the pipeline. 

(3) All known unsafe defects and conditions must be corrected in accordance with this part. 

(4) The pipeline must be tested in accordance with subpart E of this part to 

substantiate the maximum operating 

pressure permitted by §195.406. 

(b) A pipeline that qualifies for use 

under this section need not comply 

with the corrosion control requirements of subpart H of this part until 12 

months after it is placed into service, 

notwithstanding any previous deadlines for compliance. 

(c) Each operator must keep for the 

life of the pipeline a record of the investigations, tests, repairs, replacements, and alterations made under the 

requirements of paragraph (a) of this 

section. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as 

amended by Amdt. 195–52, 59 FR 33396, June 

28, 1994; Amdt. 195–173, 66 FR 67004, Dec. 27, 

2001] 

§ 195.6 Unusually Sensitive Areas 

(USAs). 

As used in this part, a USA means a 

drinking water or ecological resource 

area that is unusually sensitive to environmental damage from a hazardous 

liquid pipeline release. 

(a) An USA drinking water resource 

is: 

(1) The water intake for a Community Water System (CWS) or a Nontransient Non-community Water System (NTNCWS) that obtains its water 

supply primarily from a surface water 

source and does not have an adequate 

alternative drinking water source; 

(2) The Source Water Protection Area 

(SWPA) for a CWS or a NTNCWS that 

obtains its water supply from a Class I 

or Class IIA aquifer and does not have 

an adequate alternative drinking water 

source. Where a state has not yet identified the SWPA, the Wellhead Protection Area (WHPA) will be used until 

the state has identified the SWPA; or 

(3) The sole source aquifer recharge 

area where the sole source aquifer is a 

karst aquifer in nature. 

(b) An USA ecological resource is: 

(1) An area containing a critically 

imperiled species or ecological community; 

(2) A multi-species assemblage area; 


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Pipeline and Hazardous Materials Safety Administration, DOT § 195.6 

(3) A migratory waterbird concentration area; 

(4) An area containing an imperiled 

species, threatened or endangered species, depleted marine mammal species, 

or an imperiled ecological community 

where the species or community is 

aquatic, aquatic dependent, or terrestrial with a limited range; or 

(5) An area containing an imperiled 

species, threatened or endangered species, depleted marine mammal species, 

or imperiled ecological community 

where the species or community occurrence is considered to be one of the 

most viable, highest quality, or in the 

best condition, as identified by an element occurrence ranking (EORANK) of 

A (excellent quality) or B (good quality). 

(c) As used in this part— 

Adequate Alternative Drinking Water 

Source means a source of water that 

currently exists, can be used almost 

immediately with a minimal amount of 

effort and cost, involves no decline in 

water quality, and will meet the consumptive, hygiene, and fire fighting requirements of the existing population 

of impacted customers for at least one 

month for a surface water source of 

water and at least six months for a 

groundwater source. 

Aquatic or Aquatic Dependent Species 

or Community means a species or community that primarily occurs in aquatic, marine, or wetland habitats, as well 

as species that may use terrestrial 

habitats during all or some portion of 

their life cycle, but that are still closely associated with or dependent upon 

aquatic, marine, or wetland habitats 

for some critical component or portion 

of their life-history (i.e., reproduction, 

rearing and development, feeding, etc). 

Class I Aquifer means an aquifer that 

is surficial or shallow, permeable, and 

is highly vulnerable to contamination. 

Class I aquifers include: 

(1) Unconsolidated Aquifers (Class Ia) 

that consist of surficial, unconsolidated, and permeable alluvial, terrace, 

outwash, beach, dune and other similar 

deposits. These aquifers generally contain layers of sand and gravel that, 

commonly, are interbedded to some degree with silt and clay. Not all Class Ia 

aquifers are important water-bearing 

units, but they are likely to be both 

permeable and vulnerable. The only 

natural protection of these aquifers is 

the thickness of the unsaturated zone 

and the presence of fine-grained material; 

(2) Soluble and Fractured Bedrock 

Aquifers (Class Ib). Lithologies in this 

class include limestone, dolomite, and, 

locally, evaporitic units that contain 

documented karst features or solution 

channels, regardless of size. Generally 

these aquifers have a wide range of permeability. Also included in this class 

are sedimentary strata, and metamorphic and igneous (intrusive and extrusive) rocks that are significantly 

faulted, fractured, or jointed. In all 

cases groundwater movement is largely 

controlled by secondary openings. Well 

yields range widely, but the important 

feature is the potential for rapid 

vertical and lateral ground water 

movement along preferred pathways, 

which result in a high degree of vulnerability; 

(3) Semiconsolidated Aquifers (Class 

Ic) that generally contain poorly to 

moderately indurated sand and gravel 

that is interbedded with clay and silt. 

This group is intermediate to the unconsolidated and consolidated end 

members. These systems are common 

in the Tertiary age rocks that are exposed throughout the Gulf and Atlantic 

coastal states. Semiconsolidated conditions also arise from the presence of 

intercalated clay and caliche within 

primarily unconsolidated to poorly 

consolidated units, such as occurs in 

parts of the High Plains Aquifer; or 

(4) Covered Aquifers (Class Id) that 

are any Class I aquifer overlain by less 

than 50 feet of low permeability, unconsolidated material, such as glacial 

till, lacustrian, and loess deposits. 

Class IIa aquifer means a Higher Yield 

Bedrock Aquifer that is consolidated 

and is moderately vulnerable to contamination. These aquifers generally 

consist of fairly permeable sandstone 

or conglomerate that contain lesser 

amounts of interbedded fine grained 

clastics (shale, siltstone, mudstone) 

and occasionally carbonate units. In 

general, well yields must exceed 50 gallons per minute to be included in this 

class. Local fracturing may contribute 

to the dominant primary porosity and 

permeability of these systems. 


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§ 195.6 49 CFR Ch. I (10–1–10 Edition) 

Community Water System (CWS) means 

a public water system that serves at 

least 15 service connections used by 

year-round residents of the area or regularly serves at least 25 year-round 

residents. 

Critically imperiled species or ecological 

community (habitat) means an animal or 

plant species or an ecological community of extreme rarity, based on The 

Nature Conservancy’s Global Conservation Status Rank. There are generally 

5 or fewer occurrences, or very few remaining individuals (less than 1,000) or 

acres (less than 2,000). These species 

and ecological communities are extremely vulnerable to extinction due to 

some natural or man-made factor. 

Depleted marine mammal species means 

a species that has been identified and is 

protected under the Marine Mammal 

Protection Act of 1972, as amended 

(MMPA) (16 U.S.C. 1361 et seq.). The 

term ‘‘depleted’’ refers to marine mammal species that are listed as threatened or endangered, or are below their 

optimum sustainable populations (16 

U.S.C. 1362). The term ‘‘marine mammal’’ means ‘‘any mammal which is 

morphologically adapted to the marine 

environment (including sea otters and 

members of the orders Sirenia, 

Pinnipedia, and Cetacea), or primarily 

inhabits the marine environment (such 

as the polar bear)’’ (16 U.S.C. 1362). The 

order Sirenia includes manatees, the 

order Pinnipedia includes seals, sea 

lions, and walruses, and the order Cetacea includes dolphins, porpoises, and 

whales. 

Ecological community means an interacting assemblage of plants and animals that recur under similar environmental conditions across the landscape. 

Element occurrence rank (EORANK) 

means the condition or viability of a 

species or ecological community occurrence, based on a population’s size, 

condition, and landscape context. 

EORANKs are assigned by the Natural 

Heritage Programs. An EORANK of A 

means an excellent quality and an 

EORANK of B means good quality. 

Imperiled species or ecological community (habitat) means a rare species or 

ecological community, based on The 

Nature Conservancy’s Global Conservation Status Rank. There are generally 

6 to 20 occurrences, or few remaining 

individuals (1,000 to 3,000) or acres 

(2,000 to 10,000). These species and ecological communities are vulnerable to 

extinction due to some natural or manmade factor. 

Karst aquifer means an aquifer that is 

composed of limestone or dolomite 

where the porosity is derived from connected solution cavities. Karst aquifers 

are often cavernous with high rates of 

flow. 

Migratory waterbird concentration area 

means a designated Ramsar site or a 

Western Hemisphere Shorebird Reserve 

Network site. 

Multi-species assemblage area means 

an area where three or more different 

critically imperiled or imperiled species or ecological communities, threatened or endangered species, depleted 

marine mammals, or migratory 

waterbird concentrations co-occur. 

Non-transient Non-community Water 

System (NTNCWS) means a public water 

system that regularly serves at least 25 

of the same persons over six months 

per year. Examples of these systems include schools, factories, and hospitals 

that have their own water supplies. 

Public Water System (PWS) means a 

system that provides the public water 

for human consumption through pipes 

or other constructed conveyances, if 

such system has at least 15 service connections or regularly serves an average 

of at least 25 individuals daily at least 

60 days out of the year. These systems 

include the sources of the water supplies—i.e., surface or ground. PWS can 

be community, non-transient non-community, or transient non-community 

systems. 

Ramsar site means a site that has 

been designated under The Convention 

on Wetlands of International Importance Especially as Waterfowl Habitat 

program. Ramsar sites are globally 

critical wetland areas that support migratory waterfowl. These include wetland areas that regularly support 20,000 

waterfowl; wetland areas that regularly support substantial numbers of 

individuals from particular groups of 

waterfowl, indicative of wetland values, productivity, or diversity; and 

wetland areas that regularly support 

1% of the individuals in a population of 

one species or subspecies of waterfowl. 


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Pipeline and Hazardous Materials Safety Administration, DOT § 195.8 

Sole source aquifer (SSA) means an 

area designated by the U.S. Environmental Protection Agency under the 

Sole Source Aquifer program as the 

‘‘sole or principal’’ source of drinking 

water for an area. Such designations 

are made if the aquifer’s ground water 

supplies 50% or more of the drinking 

water for an area, and if that aquifer 

were to become contaminated, it would 

pose a public health hazard. A sole 

source aquifer that is karst in nature is 

one composed of limestone where the 

porosity is derived from connected solution cavities. They are often cavernous, with high rates of flow. 

Source Water Protection Area (SWPA) 

means the area delineated by the state 

for a public water supply system (PWS) 

or including numerous PWSs, whether 

the source is ground water or surface 

water or both, as part of the state 

source water assessment program 

(SWAP) approved by EPA under section 1453 of the Safe Drinking Water 

Act. 

Species means species, subspecies, 

population stocks, or distinct 

vertebrate populations. 

Terrestrial ecological community with a 

limited range means a non-aquatic or 

non-aquatic dependent ecological community that covers less than five (5) 

acres. 

Terrestrial species with a limited range 

means a non-aquatic or non-aquatic dependent animal or plant species that 

has a range of no more than five (5) 

acres. 

Threatened and endangered species 

(T&E) means an animal or plant species that has been listed and is protected under the Endangered Species 

Act of 1973, as amended (ESA73) (16 

U.S.C. 1531 et seq.). ‘‘Endangered species’’ is defined as ‘‘any species which 

is in danger of extinction throughout 

all or a significant portion of its 

range’’ (16 U.S.C. 1532). ‘‘Threatened 

species’’ is defined as ‘‘any species 

which is likely to become an endangered species within the foreseeable future throughout all or a significant 

portion of its range’’ (16 U.S.C. 1532). 

Transient Non-community Water System 

(TNCWS) means a public water system 

that does not regularly serve at least 

25 of the same persons over six months 

per year. This type of water system 

serves a transient population found at 

rest stops, campgrounds, restaurants, 

and parks with their own source of 

water. 

Wellhead Protection Area (WHPA) 

means the surface and subsurface area 

surrounding a well or well field that 

supplies a public water system through 

which contaminants are likely to pass 

and eventually reach the water well or 

well field. 

Western Hemisphere Shorebird Reserve 

Network (WHSRN) site means an area 

that contains migratory shorebird concentrations and has been designated as 

a hemispheric reserve, international 

reserve, regional reserve, or endangered species reserve. Hemispheric reserves host at least 500,000 shorebirds 

annually or 30% of a species flyway 

population. International reserves host 

100,000 shorebirds annually or 15% of a 

species flyway population. Regional reserves host 20,000 shorebirds annually 

or 5% of a species flyway population. 

Endangered species reserves are critical to the survival of endangered species and no minimum number of birds 

is required. 

[Amdt. 195–71, 65 FR 80544, Dec. 21, 2000] 

§ 195.8 Transportation of hazardous 

liquid or carbon dioxide in pipelines constructed with other than 

steel pipe. 

No person may transport any hazardous liquid or carbon dioxide through 

a pipe that is constructed after October 

1, 1970, for hazardous liquids or after 

July 12, 1991 for carbon dioxide of material other than steel unless the person has notified the Administrator in 

writing at least 90 days before the 

transportation is to begin. The notice 

must state whether carbon dioxide or a 

hazardous liquid is to be transported 

and the chemical name, common name, 

properties and characteristics of the 

hazardous liquid to be transported and 

the material used in construction of 

the pipeline. If the Administrator determines that the transportation of the 

hazardous liquid or carbon dioxide in 

the manner proposed would be unduly 

hazardous, he will, within 90 days after 

receipt of the notice, order the person 

that gave the notice, in writing, not to 


wwoods2 on DSK1DXX6B1PROD with CFR
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§ 195.9 49 CFR Ch. I (10–1–10 Edition) 

transport the hazardous liquid or carbon dioxide in the proposed manner 

until further notice. 

[Amdt. 195–45, 56 FR 26925, June 12, 1991, as 

amended by Amdt. 195–50, 59 FR 17281, Apr. 

12, 1994] 

§ 195.9 Outer continental shelf pipelines. 

Operators of transportation pipelines 

on the Outer Continental Shelf must 

identify on all their respective pipelines the specific points at which operating responsibility transfers to a producing operator. For those instances in 

which the transfer points are not identifiable by a durable marking, each operator will have until September 15, 

1998 to identify the transfer points. If it 

is not practicable to durably mark a 

transfer point and the transfer point is 

located above water, the operator must 

depict the transfer point on a schematic maintained near the transfer 

point. If a transfer point is located 

subsea, the operator must identify the 

transfer point on a schematic which 

must be maintained at the nearest upstream facility and provided to PHMSA 

upon request. For those cases in which 

adjoining operators have not agreed on 

a transfer point by September 15, 1998 

the Regional Director and the MMS 

Regional Supervisor will make a joint 

determination of the transfer point. 

[Amdt. 195–59, 62 FR 61695, Nov. 19, 1997, as 

amended at 70 11140, Mar. 8, 2005] 

§ 195.10 Responsibility of operator for 

compliance with this part. 

An operator may make arrangements 

with another person for the performance of any action required by this 

part. However, the operator is not 

thereby relieved from the responsibility for compliance with any requirement of this part. 

§ 195.11 What is a regulated rural 

gathering line and what requirements apply? 

Each operator of a regulated rural 

gathering line, as defined in paragraph 

(a) of this section, must comply with 

the safety requirements described in 

paragraph (b) of this section. 

(a) Definition. As used in this section, 

a regulated rural gathering line means 

an onshore gathering line in a rural 

area that meets all of the following criteria— 

(1) Has a nominal diameter from 65⁄8

inches (168 mm) to 85⁄8 inches (219.1 

mm); 

(2) Is located in or within one-quarter 

mile (.40 km) of an unusually sensitive 

area as defined in §195.6; and 

(3) Operates at a maximum pressure 

established under §195.406 corresponding to— 

(i) A stress level greater than 20-percent of the specified minimum yield 

strength of the line pipe; or 

(ii) If the stress level is unknown or 

the pipeline is not constructed with 

steel pipe, a pressure of more than 125 

psi (861 kPa) gage. 

(b) Safety requirements. Each operator 

must prepare, follow, and maintain 

written procedures to carry out the requirements of this section. Except for 

the requirements in paragraphs (b)(2), 

(b)(3), (b)(9) and (b)(10) of this section, 

the safety requirements apply to all 

materials of construction. 

(1) Identify all segments of pipeline 

meeting the criteria in paragraph (a) of 

this section before April 3, 2009. 

(2) For steel pipelines constructed, 

replaced, relocated, or otherwise 

changed after July 3, 2009, design, install, construct, initially inspect, and 

initially test the pipeline in compliance with this part, unless the pipeline 

is converted under §195.5. 

(3) For non-steel pipelines constructed after July 3, 2009, notify the 

Administrator according to §195.8. 

(4) Beginning no later than January 

3, 2009, comply with the reporting requirements in subpart B of this part. 

(5) Establish the maximum operating 

pressure of the pipeline according to 

§195.406 before transportation begins, 

or if the pipeline exists on July 3, 2008, 

before July 3, 2009. 

(6) Install line markers according to 

§195.410 before transportation begins, 

or if the pipeline exists on July 3, 2008, 

before July 3, 2009. Continue to maintain line markers in compliance with 

§195.410. 

(7) Establish a continuing public education program in compliance with 

§195.440 before transportation begins, 

or if the pipeline exists on July 3, 2008, 

before January 3, 2010. Continue to 


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Pipeline and Hazardous Materials Safety Administration, DOT § 195.12 

carry out such program in compliance 

with §195.440. 

(8) Establish a damage prevention 

program in compliance with §195.442 

before transportation begins, or if the 

pipeline exists on July 3, 2008, before 

July 3, 2009. Continue to carry out such 

program in compliance with §195.442. 

(9) For steel pipelines, comply with 

subpart H of this part, except corrosion 

control is not required for pipelines existing on July 3, 2008 before July 3, 

2011. 

(10) For steel pipelines, establish and 

follow a comprehensive and effective 

program to continuously identify operating conditions that could contribute 

to internal corrosion. The program 

must include measures to prevent and 

mitigate internal corrosion, such as 

cleaning the pipeline and using inhibitors. This program must be established 

before transportation begins or if the 

pipeline exists on July 3, 2008, before 

July 3, 2009. 

(11) To comply with the Operator 

Qualification program requirements in 

subpart G of this part, have a written 

description of the processes used to 

carry out the requirements in §195.505 

to determine the qualification of persons performing operations and maintenance tasks. These processes must be 

established before transportation begins or if the pipeline exists on July 3, 

2008, before July 3, 2009. 

(c) New unusually sensitive areas. If, 

after July 3, 2008, a new unusually sensitive area is identified and a segment 

of pipeline becomes regulated as a result, except for the requirements of 

paragraphs (b)(9) and (b)(10) of this section, the operator must implement the 

requirements in paragraphs (b)(2) 

through (b)(11) of this section for the 

affected segment within 6 months of 

identification. For steel pipelines, comply with the deadlines in paragraph 

(b)(9) and (b)(10). 

(d) Record Retention. An operator 

must maintain records demonstrating 

compliance with each requirement according to the following schedule. 

(1) An operator must maintain the 

segment identification records required 

in paragraph (b)(1) of this section and 

the records required to comply with 

(b)(10) of this section, for the life of the 

pipe. 

(2) An operator must maintain the 

records necessary to demonstrate compliance with each requirement in paragraphs (b)(2) through (b)(9), and (b)(11) 

of this section according to the record 

retention requirements of the referenced section or subpart. 

[73 FR 31644, June 3, 2008] 

§ 195.12 What requirements apply to 

low-stress pipelines in rural areas? 

(a) General. This section does not 

apply to a rural low-stress pipeline regulated under this part as a low-stress 

pipeline that crosses a waterway currently used for commercial navigation. 

An operator of a rural low-stress pipeline meeting the following criteria 

must comply with the safety requirements described in paragraph (b) of 

this section. The pipeline: 

(1) Has a nominal diameter of 85⁄8

inches (219.1 mm) or more; 

(2) Is located in or within a half mile 

(.80 km) of an unusually sensitive area 

(USA) as defined in §195.6; and 

(3) Operates at a maximum pressure 

established under §195.406 corresponding to: 

(i) A stress level equal to or less than 

20-percent of the specified minimum 

yield strength of the line pipe; or 

(ii) If the stress level is unknown or 

the pipeline is not constructed with 

steel pipe, a pressure equal to or less 

than 125 psi (861 kPa) gage. 

(b) Requirements. An operator of a 

pipeline meeting the criteria in paragraph (a) of this section must comply 

with the following safety requirements 

and compliance deadlines. 

(1) Identify all segments of pipeline 

meeting the criteria in paragraph (a) of 

this section before April 3, 2009. 

(2) Beginning no later than January 

3, 2009, comply with the reporting requirements of subpart B for the identified segments. 

(3)(i) Establish a written program in 

compliance with §195.452 before July 3, 

2009, to assure the integrity of the lowstress pipeline segments. Continue to 

carry out such program in compliance 

with §195.452. 

(ii) To carry out the integrity management requirements in §195.452, an 

operator may conduct a determination 

per §195.452(a) in lieu of the half mile 

buffer. 


wwoods2 on DSK1DXX6B1PROD with CFR
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§ 195.48 49 CFR Ch. I (10–1–10 Edition) 

(iii) Complete the baseline assessment of all segments in accordance 

with §195.452(c) before July 3, 2015, and 

complete at least 50-percent of the assessments, beginning with the highest 

risk pipe, before January 3, 2012. 

(4) Comply with all other safety requirements of this part, except subpart 

H, before July 3, 2009. Comply with subpart H before July 3, 2011. 

(c) Economic compliance burden. (1) An 

operator may notify PHMSA in accordance with §195.452(m) of a situation 

meeting the following criteria: 

(i) The pipeline meets the criteria in 

paragraph (a) of this section; 

(ii) The pipeline carries crude oil 

from a production facility; 

(iii) The pipeline, when in operation, 

operates at a flow rate less than or 

equal to 14,000 barrels per day; and 

(iv) The operator determines it would 

abandon or shut-down the pipeline as a 

result of the economic burden to comply with the assessment requirements 

in §§195.452(d) or 195.452(j). 

(2) A notification submitted under 

this provision must include, at minimum, the following information about 

the pipeline: Its operating, maintenance and leak history; the estimated 

cost to comply with the integrity assessment requirements (with a brief description of the basis for the estimate); 

the estimated amount of production 

from affected wells per year, whether 

wells will be shut in or alternate transportation used, and if alternate transportation will be used, the estimated 

cost to do so. 

(3) When an operator notifies PHMSA 

in accordance with paragraph (c)(1) of 

this section, PHMSA will stay compliant with §§195.452(d) and 195.452(j)(3) 

until it has completed an analysis of 

the notification. PHMSA will consult 

the Department of Energy (DOE), as 

appropriate, to help analyze the potential energy impact of loss of the pipeline. Based on the analysis, PHMSA 

may grant the operator a special permit to allow continued operation of the 

pipeline subject to alternative safety 

requirements. 

(d) New unusually sensitive areas. If, 

after July 3, 2008, an operator identifies 

a new unusually sensitive area and a 

segment of pipeline meets the criteria 

in paragraph (a) of this section, the operator must take the following actions: 

(1) Except for paragraph (b)(2) of this 

section and the requirements of subpart H, comply with all other safety requirements of this part before July 3, 

2009. Comply with subpart H before 

July 3, 2011. 

(2) Establish the program required in 

paragraph (b)(2)(i) within 12 months 

following the date the area is identified. Continue to carry out such program in compliance with §195.452; and 

(3) Complete the baseline assessment 

required by paragraph (b)(2)(ii) of this 

section according to the schedule in 

§195.452(d)(3). 

(e) Record Retention. An operator 

must maintain records demonstrating 

compliance with each requirement according to the following schedule. 

(1) An operator must maintain the 

segment identification records required 

in paragraph (b)(1) of this section for 

the life of the pipe. 

(2) An operator must maintain the 

records necessary to demonstrate compliance with each requirement in paragraphs (b)(2) through (b)(4) of this section according to the record retention 

requirements of the referenced section 

or subpart. 

[73 FR 31644, June 3, 2008, as amended by 

Amdt. 195–92, 74 FR 62506, Nov. 30, 2009] 

Subpart B—Annual, Accident, and 

Safety-Related Condition Reporting 

§ 195.48 Scope. 

This subpart prescribes requirements 

for periodic reporting and for reporting 

of accidents and safety-related conditions. This subpart applies to all pipelines subject to this part and, beginning January 5, 2009, applies to all 

rural low-stress hazardous liquid pipelines. An operator of a rural low-stress 

pipeline not otherwise subject to this 

part is not required to complete Parts 

J and K of the hazardous liquid annual 

report form (PHMSA F 7000–1.1) required by §195.49 or to provide the estimate of total miles that could affect 

high consequence areas in Part B of 

that form. 

[73 FR 31646, June 3, 2008] 


wwoods2 on DSK1DXX6B1PROD with CFR
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Pipeline and Hazardous Materials Safety Administration, DOT § 195.54 

§ 195.49 Annual report. 

Beginning no later than June 15, 2005, 

each operator must annually complete 

and submit DOT form RSPA F 7000–1.1 

for each type of hazardous liquid pipeline facility operated at the end of the 

previous year. A separate report is required for crude oil, HVL (including anhydrous ammonia), petroleum products, and carbon dioxide pipelines. Operators are encouraged, but not required, to file an annual report by June 

15, 2004, for calendar year 2003. 

[Amdt. 195–80, 69 FR 541, Jan. 6, 2004] 

§ 195.50 Reporting accidents. 

An accident report is required for 

each failure in a pipeline system subject to this part in which there is a release of the hazardous liquid or carbon 

dioxide transported resulting in any of 

the following: 

(a) Explosion or fire not intentionally set by the operator. 

(b) Release of 5 gallons (19 liters) or 

more of hazardous liquid or carbon dioxide, except that no report is required 

for a release of less than 5 barrels (0.8 

cubic meters) resulting from a pipeline 

maintenance activity if the release is: 

(1) Not otherwise reportable under 

this section; 

(2) Not one described in §195.52(a)(4); 

(3) Confined to company property or 

pipeline right-of-way; and 

(4) Cleaned up promptly; 

(c) Death of any person; 

(d) Personal injury necessitating hospitalization; 

(e) Estimated property damage, including cost of clean-up and recovery, 

value of lost product, and damage to 

the property of the operator or others, 

or both, exceeding $50,000. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as 

amended by Amdt. 195–39, 53 FR 24950, July 1, 

1988; Amdt. 195–45, 56 FR 26925, June 12, 1991; 

Amdt. 195–52, 59 FR 33396, June 28, 1994; 

Amdt. 195–63, 63 FR 37506, July 13, 1998; 

Amdt. 195–75, 67 FR 836, Jan. 8, 2002] 

§ 195.52 Telephonic notice of certain 

accidents. 

(a) At the earliest practicable moment following discovery of a release 

of the hazardous liquid or carbon dioxide transported resulting in an event 

described in §195.50, the operator of the 

system shall give notice, in accordance 

with paragraph (b) of this section, of 

any failure that: 

(1) Caused a death or a personal injury requiring hospitalization; 

(2) Resulted in either a fire or explosion not intentionally set by the operator; 

(3) Caused estimated property damage, including cost of cleanup and recovery, value of lost product, and damage to the property of the operator or 

others, or both, exceeding $50,000; 

(4) Resulted in pollution of any 

stream, river, lake, reservoir, or other 

similar body of water that violated applicable water quality standards, 

caused a discoloration of the surface of 

the water or adjoining shoreline, or deposited a sludge or emulsion beneath 

the surface of the water or upon adjoining shorelines; or 

(5) In the judgment of the operator 

was significant even though it did not 

meet the criteria of any other paragraph of this section. 

(b) Reports made under paragraph (a) 

of this section are made by telephone 

to 800–424–8802 (in Washington, DC, 

20590–0001 (202) 372–2428) and must include the following information: 

(1) Name and address of the operator. 

(2) Name and telephone number of 

the reporter. 

(3) The location of the failure. 

(4) The time of the failure. 

(5) The fatalities and personal injuries, if any. 

(6) All other significant facts known 

by the operator that are relevant to 

the cause of the failure or extent of the 

damages. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as 

amended by Amdt. 195–23, 47 FR 32720, July 

29, 1982; Amdt. 195–44, 54 FR 40878, Oct. 4, 

1989; Amdt. 195–45, 56 FR 26925, June 12, 1991; 

Amdt. 195–52, 59 FR 33396, June 28, 1994; 74 FR 

2894, Jan. 16, 2009] 

§ 195.54 Accident reports. 

(a) Each operator that experiences an 

accident that is required to be reported 

under §195.50 shall as soon as practicable, but not later than 30 days after 

discovery of the accident, prepare and 

file an accident report on DOT Form 

7000–1, or a facsimile. 


wwoods2 on DSK1DXX6B1PROD with CFR
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§ 195.55 49 CFR Ch. I (10–1–10 Edition) 

(b) Whenever an operator receives 

any changes in the information reported or additions to the original report on DOT Form 7000–1, it shall file a 

supplemental report within 30 days. 

[Amdt. 195–39, 53 FR 24950, July 1, 1988] 

§ 195.55 Reporting safety-related conditions. 

(a) Except as provided in paragraph 

(b) of this section, each operator shall 

report in accordance with §195.56 the 

existence of any of the following safety-related conditions involving pipelines in service: 

(1) General corrosion that has reduced the wall thickness to less than 

that required for the maximum operating pressure, and localized corrosion 

pitting to a degree where leakage 

might result. 

(2) Unintended movement or abnormal loading of a pipeline by environmental causes, such as an earthquake, 

landslide, or flood, that impairs its 

serviceability. 

(3) Any material defect or physical 

damage that impairs the serviceability 

of a pipeline. 

(4) Any malfunction or operating 

error that causes the pressure of a 

pipeline to rise above 110 percent of its 

maximum operating pressure. 

(5) A leak in a pipeline that constitutes an emergency. 

(6) Any safety-related condition that 

could lead to an imminent hazard and 

causes (either directly or indirectly by 

remedial action of the operator), for 

purposes other than abandonment, a 20 

percent or more reduction in operating 

pressure or shutdown of operation of a 

pipeline. 

(b) A report is not required for any 

safety-related condition that— 

(1) Exists on a pipeline that is more 

than 220 yards (200 meters) from any 

building intended for human occupancy 

or outdoor place of assembly, except 

that reports are required for conditions 

within the right-of-way of an active 

railroad, paved road, street, or highway, or that occur offshore or at onshore locations where a loss of hazardous liquid could reasonably be expected to pollute any stream, river, 

lake, reservoir, or other body of water; 

(2) Is an accident that is required to 

be reported under §195.50 or results in 

such an accident before the deadline 

for filing the safety-related condition 

report; or 

(3) Is corrected by repair or replacement in accordance with applicable 

safety standards before the deadline for 

filing the safety-related condition report, except that reports are required 

for all conditions under paragraph 

(a)(1) of this section other than localized corrosion pitting on an effectively 

coated and cathodically protected pipeline. 

[Amdt. 195–39, 53 FR 24950, July 1, 1988; 53 FR 

29800, Aug. 8, 1988, as amended by Amdt. 195– 

63, 63 FR 37506, July 13, 1998] 

§ 195.56 Filing safety-related condition 

reports. 

(a) Each report of a safety-related 

condition under §195.55(a) must be filed 

(received by the Administrator) in 

writing within 5 working days (not including Saturdays, Sundays, or Federal 

holidays) after the day a representative 

of the operator first determines that 

the condition exists, but not later than 

10 working days after the day a representative of the operator discovers 

the condition. Separate conditions may 

be described in a single report if they 

are closely related. To file a report by 

facsimile (fax), dial (202) 366–7128. 

(b) The report must be headed ‘‘Safety-Related Condition Report’’ and provide the following information: 

(1) Name and principal address of operator. 

(2) Date of report. 

(3) Name, job title, and business telephone number of person submitting the 

report. 

(4) Name, job title, and business telephone number of person who determined that the condition exists. 

(5) Date condition was discovered and 

date condition was first determined to 

exist. 

(6) Location of condition, with reference to the State (and town, city, or 

county) or offshore site, and as appropriate nearest street address, offshore 

platform, survey station number, milepost, landmark, or name of pipeline. 

(7) Description of the condition, including circumstances leading to its 

discovery, any significant effects of the 

condition on safety, and the name of 

the commodity transported or stored. 


wwoods2 on DSK1DXX6B1PROD with CFR
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Pipeline and Hazardous Materials Safety Administration, DOT § 195.59 

(8) The corrective action taken (including reduction of pressure or shutdown) before the report is submitted 

and the planned follow-up or future 

corrective action, including the anticipated schedule for starting and concluding such action. 

[Amdt. 195–39, 53 FR 24950, July 1, 1988; 53 FR 

29800, Aug. 8, 1988, as amended by Amdt. 195– 

42, 54 FR 32344, Aug. 7, 1989; Amdt. 195–44, 54 

FR 40878, Oct. 4, 1989; Amdt. 195–50, 59 FR 

17281, Apr. 12, 1994; Amdt. 195–61, 63 FR 7723, 

Feb. 17, 1998] 

§ 195.57 Filing offshore pipeline condition reports. 

(a) Each operator shall, within 60 

days after completion of the inspection 

of all its underwater pipelines subject 

to §195.413(a), report the following information: 

(1) Name and principal address of operator. 

(2) Date of report. 

(3) Name, job title, and business telephone number of person submitting the 

report. 

(4) Total number of miles (kilometers) of pipeline inspected. 

(5) Length and date of installation of 

each exposed pipeline segment, and location; including, if available, the location according to the Minerals Management Service or state offshore area and 

block number tract. 

(6) Length and date of installation of 

each pipeline segment, if different from 

a pipeline segment identified under 

paragraph (a)(5) of this section, that is 

a hazard to navigation, and the location; including, if available, the location according to the Minerals Management Service or state offshore area and 

block number tract. 

(b) The report shall be mailed to the 

Office of Pipeline Safety, Pipeline and 

Hazardous Materials Safety Administration, Department of Transportation, 

Information Resources Manager, PHP– 

10, 1200 New Jersey Avenue, SE., Washington, DC 20590. 

[Amdt. 195–47, 56 FR 63771, Dec. 5, 1991, as 

amended by Amdt. 195–63, 63 FR 37506, July 

13, 1998; 70 FR 11140, Mar. 8, 2005; 73 FR 16570, 

Mar. 28, 2008; 74 FR 2894, Jan. 16, 2009] 

§ 195.58 Address for written reports. 

Each written report required by this 

subpart must be made to the Office of 

Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, Information Resources Manager, PHP–10, 1200 New Jersey Avenue, 

SE., Washington, DC 20590-0001. However, accident reports for intrastate 

pipelines subject to the jurisdiction of 

a State agency pursuant to a certification under the pipeline safety laws 

(49 U.S.C. 60101 et seq.) may be submitted in duplicate to that State agency if the regulations of that agency require submission of these reports and 

provide for further transmittal of one 

copy within 10 days of receipt to the 

Information Resources Manager. Safety-related condition reports required 

by §195.55 for intrastate pipelines must 

be submitted concurrently to the State 

agency, and if that agency acts as an 

agent of the Secretary with respect to 

interstate pipelines, safety-related condition reports for these pipelines must 

be submitted concurrently to that 

agency. 

[Amdt. 195–55, 61 FR 18518, Apr. 26, 1996, as 

amended by Amdt. 195–81, 69 FR 32897, June 

14, 2004; 70 FR 11140, Mar. 8, 2005; 74 FR 2894, 

Jan. 16, 2009] 

§ 195.59 Abandonment or deactivation 

of facilities. 

For each abandoned offshore pipeline 

facility or each abandoned onshore 

pipeline facility that crosses over, 

under or through a commercially navigable waterway, the last operator of 

that facility must file a report upon 

abandonment of that facility. 

(a) The preferred method to submit 

data on pipeline facilities abandoned 

after October 10, 2000 is to the National 

Pipeline Mapping System (NPMS) in 

accordance with the NPMS ‘‘Standards 

for Pipeline and Liquefied Natural Gas 

Operator Submissions.’’ To obtain a 

copy of the NPMS Standards, please 

refer to the NPMS homepage at http:// 

www.npms.phmsa.dot.gov or contact the 

NPMS National Repository at 703–317– 

3073. A digital data format is preferred, 

but hard copy submissions are acceptable if they comply with the NPMS 


wwoods2 on DSK1DXX6B1PROD with CFR
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§ 195.60 49 CFR Ch. I (10–1–10 Edition) 

Standards. In addition to the NPMS-required attributes, operators must submit the date of abandonment, diameter, method of abandonment, and certification that, to the best of the operator’s knowledge, all of the reasonably 

available information requested was 

provided and, to the best of the operator’s knowledge, the abandonment was 

completed in accordance with applicable laws. Refer to the NPMS Standards 

for details in preparing your data for 

submission. The NPMS Standards also 

include details of how to submit data. 

Alternatively, operators may submit 

reports by mail, fax or e-mail to the Office of Pipeline Safety, Pipeline and 

Hazardous Materials Safety Administration, U.S. Department of Transportation, Information Resources Manager, PHP–10, 1200 New Jersey Avenue, 

SE., Washington, DC 20590-0001; fax 

(202) 366–4566; e-mail, 

‘‘InformationResourcesManager@phmsa. 

dot.gov. The information in the report 

must contain all reasonably available 

information related to the facility, including information in the possession 

of a third party. The report must contain the location, size, date, method of 

abandonment, and a certification that 

the facility has been abandoned in accordance with all applicable laws. 

(b) [Reserved] 

[Amdt. 195–69, 65 FR 54444, Sept. 8, 2000, as 

amended at 70 FR 11140, Mar. 8, 2005; Amdt. 

195–86, 72 FR 4657, Feb. 1, 2007; 73 FR 16570, 

Mar. 28, 2008; 74 FR 2894, Jan. 16, 2009] 

§ 195.60 Operator assistance in investigation. 

If the Department of Transportation 

investigates an accident, the operator 

involved shall make available to the 

representative of the Department all 

records and information that in any 

way pertain to the accident, and shall 

afford all reasonable assistance in the 

investigation of the accident. 

§ 195.62 Supplies of accident report 

DOT Form 7000–1. 

Each operator shall maintain an adequate supply of forms that are a facsimile of DOT Form 7000–1 to enable it 

to promptly report accidents. The Department will, upon request, furnish 

specimen copies of the form. Requests 

should be addressed to the Office of 

Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, Information Resources Manager, PHP–10, 1200 New Jersey Avenue, 

SE., Washington, DC 20590–0001. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as 

amended at 47 FR 32720, July 29, 1982; 74 FR 

2894, Jan. 16, 2009] 

§ 195.63 OMB control number assigned 

to information collection. 

The control number assigned by the 

Office of Management and Budget to 

the hazardous liquid pipeline information collection requirements of this 

part pursuant to the Paperwork Reduction Act of 1980 is 2137–0047. 

[Amdt. 195–34, 50 FR 34474, Aug. 26, 1985] 

Subpart C—Design Requirements 

§ 195.100 Scope. 

This subpart prescribes minimum design requirements for new pipeline systems constructed with steel pipe and 

for relocating, replacing, or otherwise 

changing existing systems constructed 

with steel pipe. However, it does not 

apply to the movement of line pipe 

covered by §195.424. 

§ 195.101 Qualifying metallic components other than pipe. 

Notwithstanding any requirement of 

the subpart which incorporates by reference an edition of a document listed 

in §195.3, a metallic component other 

than pipe manufactured in accordance 

with any other edition of that document is qualified for use if— 

(a) It can be shown through visual inspection of the cleaned component that 

no defect exists which might impair 

the strength or tightness of the component: and 

(b) The edition of the document 

under which the component was manufactured has equal or more stringent 

requirements for the following as an 

edition of that document currently or 

previously listed in §195.3: 

(1) Pressure testing; 

(2) Materials; and 

(3) Pressure and temperature ratings. 

[Amdt. 195–28, 48 FR 30639, July 5, 1983] 


wwoods2 on DSK1DXX6B1PROD with CFR
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Pipeline and Hazardous Materials Safety Administration, DOT § 195.106 

§ 195.102 Design temperature. 

(a) Material for components of the 

system must be chosen for the temperature environment in which the 

components will be used so that the 

pipeline will maintain its structural 

integrity. 

(b) Components of carbon dioxide 

pipelines that are subject to low temperatures during normal operation because of rapid pressure reduction or 

during the initial fill of the line must 

be made of materials that are suitable 

for those low temperatures. 

[Admt. 195–45, 56 FR 26925, June 12, 1991] 

§ 195.104 Variations in pressure. 

If, within a pipeline system, two or 

more components are to be connected 

at a place where one will operate at a 

higher pressure than another, the system must be designed so that any component operating at the lower pressure 

will not be overstressed. 

§ 195.106 Internal design pressure. 

(a) Internal design pressure for the 

pipe in a pipeline is determined in accordance with the following formula: 

P=(2St/D)×E×F 

P=Internal design pressure in p.s.i. (kPa) 

gage. 

S=Yield strength in pounds per square inch 

(kPa) determined in accordance with paragraph (b) of this section. 

t=Nominal wall thickness of the pipe in 

inches (millimeters). If this is unknown, it 

is determined in accordance with paragraph (c) of this section. 

D=Nominal outside diameter of the pipe in 

inches (millimeters). 

E=Seam joint factor determined in accordance with paragraph (e) of this section. 

F=A design factor of 0.72, except that a design factor of 0.60 is used for pipe, including risers, on a platform located offshore 

or on a platform in inland navigable waters, and 0.54 is used for pipe that has been 

subjected to cold expansion to meet the 

specified minimum yield strength and is 

subsequently heated, other than by welding or stress relieving as a part of welding, 

to a temperature higher than 900 °F (482 °C) 

for any period of time or over 600 °F (316 

°C) for more than 1 hour. 

(b) The yield strength to be used in 

determining the internal design pressure under paragraph (a) of this section 

is the specified minimum yield 

strength. If the specified minimum 

yield strength is not known, the yield 

strength to be used in the design formula is one of the following: 

(1)(i) The yield strength determined 

by performing all of the tensile tests of 

API Specification 5L on randomly selected specimens with the following 

number of tests: 

Pipe size No. of tests 

Less than 65⁄8 in (168 mm) nominal outside diameter.One test for each 200 

lengths. 

65⁄8 in through 123⁄4 in (168 mm 

through 324 mm) nominal outside diameter.

One test for each 100 

lengths. 

Larger than 123⁄4 in (324 mm) 

nominal outside diameter.

One test for each 50 

lengths. 

(ii) If the average yield-tensile ratio 

exceeds 0.85, the yield strength shall be 

taken as 24,000 p.s.i. (165,474 kPa). If the 

average yield-tensile ratio is 0.85 or 

less, the yield strength of the pipe is 

taken as the lower of the following: 

(A) Eighty percent of the average 

yield strength determined by the tensile tests. 

(B) The lowest yield strength determined by the tensile tests. 

(2) If the pipe is not tensile tested as 

provided in paragraph (b) of this section, the yield strength shall be taken 

as 24,000 p.s.i. (165,474 kPa). 

(c) If the nominal wall thickness to 

be used in determining internal design 

pressure under paragraph (a) of this 

section is not known, it is determined 

by measuring the thickness of each 

piece of pipe at quarter points on one 

end. However, if the pipe is of uniform 

grade, size, and thickness, only 10 individual lengths or 5 percent of all 

lengths, whichever is greater, need be 

measured. The thickness of the lengths 

that are not measured must be verified 

by applying a gage set to the minimum 

thickness found by the measurement. 

The nominal wall thickness to be used 

is the next wall thickness found in 

commercial specifications that is 

below the average of all the measurements taken. However, the nominal 

wall thickness may not be more than 

1.14 times the smallest measurement 

taken on pipe that is less than 20 

inches (508 mm) nominal outside diameter, nor more than 1.11 times the 

smallest measurement taken on pipe 

that is 20 inches (508 mm) or more in 

nominal outside diameter. 


wwoods2 on DSK1DXX6B1PROD with CFR
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§ 195.108 49 CFR Ch. I (10–1–10 Edition) 

(d) The minimum wall thickness of 

the pipe may not be less than 87.5 percent of the value used for nominal wall 

thickness in determining the internal 

design pressure under paragraph (a) of 

this section. In addition, the anticipated external loads and external pressures that are concurrent with internal 

pressure must be considered in accordance with §§195.108 and 195.110 and, 

after determining the internal design 

pressure, the nominal wall thickness 

must be increased as necessary to compensate for these concurrent loads and 

pressures. 

(e) The seam joint factor used in 

paragraph (a) of this section is determined in accordance with the following 

table: 

Specification Pipe class 

Seam 

joint 

factor 

ASTM A53 .... Seamless .......................................... 1.00 

Electric resistance welded ................ 1.00 

Furnace lap welded .......................... 0.80 

Furnace butt welded ......................... 0.60 

ASTM A106 .. Seamless .......................................... 1.00 

ASTM A 333/ 

A 333M.

Seamless .......................................... 1.00 

Welded .............................................. 1.00 

ASTM A381 .. Double submerged arc welded ......... 1.00 

ASTM A671 .. Electric-fusion-welded ....................... 1.00 

ASTM A672 .. Electric-fusion-welded ....................... 1.00 

ASTM A691 .. Electric-fusion-welded ....................... 1.00 

API 5L ........... Seamless .......................................... 1.00 

Electric resistance welded ................ 1.00 

Electric flash welded ......................... 1.00 

Submerged arc welded ..................... 1.00 

Furnace lap welded .......................... 0.80 

Furnace butt welded ......................... 0.60 

The seam joint factor for pipe which is 

not covered by this paragraph must be 

approved by the Administrator. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981; 47 

FR 32721, July 29, 1982, as amended by Amdt. 

195–30, 49 FR 7569, Mar. 1, 1984; Amdt 195–37, 

51 FR 15335, Apr. 23, 1986; Amdt 195–40, 54 FR 

5628, Feb. 6, 1989; 58 FR 14524, Mar. 18, 1993; 

Amdt. 195–50, 59 FR 17281, Apr. 12, 1994; Amdt. 

195–52, 59 FR 33396, 33397, June 28, 1994; Amdt. 

195–63, 63 FR 37506, July 13, 1998] 

§ 195.108 External pressure. 

Any external pressure that will be 

exerted on the pipe must be provided 

for in designing a pipeline system. 

§ 195.110 External loads. 

(a) Anticipated external loads (e.g.), 

earthquakes, vibration, thermal expansion, and contraction must be provided 

for in designing a pipeline system. In 

providing for expansion and flexibility, 

section 419 of ASME/ANSI B31.4 must 

be followed. 

(b) The pipe and other components 

must be supported in such a way that 

the support does not cause excess localized stresses. In designing attachments 

to pipe, the added stress to the wall of 

the pipe must be computed and compensated for. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as 

amended at 58 FR 14524, Mar. 18, 1993] 

§ 195.111 Fracture propagation. 

A carbon dioxide pipeline system 

must be designed to mitigate the effects of fracture propagation. 

[Amdt. 195–45, 56 FR 26926, June 12, 1991] 

§ 195.112 New pipe. 

Any new pipe installed in a pipeline 

system must comply with the following: 

(a) The pipe must be made of steel of 

the carbon, low alloy-high strength, or 

alloy type that is able to withstand the 

internal pressures and external loads 

and pressures anticipated for the pipeline system. 

(b) The pipe must be made in accordance with a written pipe specification 

that sets forth the chemical requirements for the pipe steel and mechanical tests for the pipe to provide pipe 

suitable for the use intended. 

(c) Each length of pipe with a nominal outside diameter of 4 1⁄2 in (114.3 

mm) or more must be marked on the 

pipe or pipe coating with the specification to which it was made, the specified minimum yield strength or grade, 

and the pipe size. The marking must be 

applied in a manner that does not damage the pipe or pipe coating and must 

remain visible until the pipe is installed. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as 

amended by Amdt. 195–52, 59 FR 33396, June 

28, 1994; Amdt. 195–63, 63 FR 37506, July 13, 

1998] 

§ 195.114 Used pipe. 

Any used pipe installed in a pipeline 

system must comply with §195.112 (a) 

and (b) and the following: 

(a) The pipe must be of a known specification and the seam joint factor 

must be determined in accordance with 


wwoods2 on DSK1DXX6B1PROD with CFR
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Pipeline and Hazardous Materials Safety Administration, DOT § 195.120 

§195.106(e). If the specified minimum 

yield strength or the wall thickness is 

not known, it is determined in accordance with §195.106 (b) or (c) as appropriate. 

(b) There may not be any: 

(1) Buckles; 

(2) Cracks, grooves, gouges, dents, or 

other surface defects that exceed the 

maximum depth of such a defect permitted by the specification to which 

the pipe was manufactured; or 

(3) Corroded areas where the remaining wall thickness is less than the minimum thickness required by the tolerances in the specification to which the 

pipe was manufactured. 

However, pipe that does not meet the 

requirements of paragraph (b)(3) of this 

section may be used if the operating 

pressure is reduced to be commensurate with the remaining wall thickness. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981; 47 

FR 32721, July 29, 1982] 

§ 195.116 Valves. 

Each valve installed in a pipeline 

system must comply with the following: 

(a) The valve must be of a sound engineering design. 

(b) Materials subject to the internal 

pressure of the pipeline system, including welded and flanged ends, must be 

compatible with the pipe or fittings to 

which the valve is attached. 

(c) Each part of the valve that will be 

in contact with the carbon dioxide or 

hazardous liquid stream must be made 

of materials that are compatible with 

carbon dioxide or each hazardous liquid 

that it is anticipated will flow through 

the pipeline system. 

(d) Each valve must be both 

hydrostatically shell tested and 

hydrostatically seat tested without 

leakage to at least the requirements 

set forth in Section 11 of API Standard 

6D (incorporated by reference, see 

§195.3). 

(e) Each valve other than a check 

valve must be equipped with a means 

for clearly indicating the position of 

the valve (open, closed, etc.). 

(f) Each valve must be marked on the 

body or the nameplate, with at least 

the following: 

(1) Manufacturer’s name or trademark. 

(2) Class designation or the maximum 

working pressure to which the valve 

may be subjected. 

(3) Body material designation (the 

end connection material, if more than 

one type is used). 

(4) Nominal valve size. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981 as 

amended by Amdt. 195–45, 56 FR 26926, June 

12, 1991; Amdt. 195–86, 71 FR 33410, June 9, 

2006; Amdt. 195–94, 75 FR 48606, Aug. 11, 2010] 

§ 195.118 Fittings. 

(a) Butt-welding type fittings must 

meet the marking, end preparation, 

and the bursting strength requirements 

of ASME/ANSI B16.9 or MSS Standard 

Practice SP–75. 

(b) There may not be any buckles, 

dents, cracks, gouges, or other defects 

in the fitting that might reduce the 

strength of the fitting. 

(c) The fitting must be suitable for 

the intended service and be at least as 

strong as the pipe and other fittings in 

the pipeline system to which it is attached. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981; 47 

FR 32721, July 29, 1982, as amended at 58 FR 

14524, Mar. 18, 1993] 

§ 195.120 Passage of internal inspection devices. 

(a) Except as provided in paragraphs 

(b) and (c) of this section, each new 

pipeline and each line section of a pipeline where the line pipe, valve, fitting 

or other line component is replaced; 

must be designed and constructed to 

accommodate the passage of instrumented internal inspection devices. 

(b) This section does not apply to: 

(1) Manifolds; 

(2) Station piping such as at pump 

stations, meter stations, or pressure 

reducing stations; 

(3) Piping associated with tank farms 

and other storage facilities; 

(4) Cross-overs; 

(5) Sizes of pipe for which an instrumented internal inspection device is 

not commercially available; 

(6) Offshore pipelines, other than 

main lines 10 inches (254 millimeters) 

or greater in nominal diameter, that 

transport liquids to onshore facilities; 

and 


wwoods2 on DSK1DXX6B1PROD with CFR
200 

§ 195.122 49 CFR Ch. I (10–1–10 Edition) 

(7) Other piping that the Administrator under §190.9 of this chapter, 

finds in a particular case would be impracticable to design and construct to 

accommodate the passage of instrumented internal inspection devices. 

(c) An operator encountering emergencies, construction time constraints 

and other unforeseen construction 

problems need not construct a new or 

replacement segment of a pipeline to 

meet paragraph (a) of this section, if 

the operator determines and documents why an impracticability prohibits compliance with paragraph (a) of 

this section. Within 30 days after discovering the emergency or construction problem the operator must petition, under §190.9 of this chapter, for 

approval that design and construction 

to accommodate passage of instrumented internal inspection devices 

would be impracticable. If the petition 

is denied, within 1 year after the date 

of the notice of the denial, the operator 

must modify that segment to allow 

passage of instrumented internal inspection devices. 

[Amdt. 195–50, 59 FR 17281, Apr. 12, 1994, as 

amended by Amdt. 195–63, 63 FR 37506, July 

13, 1998] 

§ 195.122 Fabricated branch connections. 

Each pipeline system must be designed so that the addition of any fabricated branch connections will not reduce the strength of the pipeline system. 

§ 195.124 Closures. 

Each closure to be installed in a pipeline system must comply with the 

ASME Boiler and Pressure Vessel Code, 

section VIII, Pressure Vessels, Division 

1, and must have pressure and temperature ratings at least equal to those of 

the pipe to which the closure is attached. 

§ 195.126 Flange connection. 

Each component of a flange connection must be compatible with each 

other component and the connection as 

a unit must be suitable for the service 

in which it is to be used. 

§ 195.128 Station piping. 

Any pipe to be installed in a station 

that is subject to system pressure must 

meet the applicable requirements of 

this subpart. 

§ 195.130 Fabricated assemblies. 

Each fabricated assembly to be installed in a pipeline system must meet 

the applicable requirements of this 

subpart. 

§ 195.132 Design and construction of 

aboveground breakout tanks. 

(a) Each aboveground breakout tank 

must be designed and constructed to 

withstand the internal pressure produced by the hazardous liquid to be 

stored therein and any anticipated external loads. 

(b) For aboveground breakout tanks 

first placed in service after October 2, 

2000, compliance with paragraph (a) of 

this section requires one of the following: 

(1) Shop-fabricated, vertical, cylindrical, closed top, welded steel tanks 

with nominal capacities of 90 to 750 

barrels (14.3 to 119.2 m3) and with internal vapor space pressures that are approximately atmospheric must be designed and constructed in accordance 

with API Specification 12F. 

(2) Welded, low-pressure (i.e., internal vapor space pressure not greater 

than 15 psig (103.4 kPa)), carbon steel 

tanks that have wall shapes that can 

be generated by a single vertical axis of 

revolution must be designed and constructed in accordance with API Standard 620. 

(3) Vertical, cylindrical, welded steel 

tanks with internal pressures at the 

tank top approximating atmospheric 

pressures (i.e., internal vapor space 

pressures not greater than 2.5 psig (17.2 

kPa), or not greater than the pressure 

developed by the weight of the tank 

roof) must be designed and constructed 

in accordance with API Standard 650. 

(4) High pressure steel tanks (i.e., internal gas or vapor space pressures 

greater than 15 psig (103.4 kPa)) with a 

nominal capacity of 2000 gallons (7571 

liters) or more of liquefied petroleum 


wwoods2 on DSK1DXX6B1PROD with CFR
201 

Pipeline and Hazardous Materials Safety Administration, DOT § 195.207 

gas (LPG) must be designed and constructed in accordance with API Standard 2510. 

[Amdt. 195–66, 64 FR 15935, Apr. 2, 1999] 

§ 195.134 CPM leak detection. 

This section applies to each hazardous liquid pipeline transporting liquid in single phase (without gas in the 

liquid). On such systems, each new 

computational pipeline monitoring 

(CPM) leak detection system and each 

replaced component of an existing CPM 

system must comply with section 4.2 of 

API 1130 in its design and with any 

other design criteria addressed in API 

1130 for components of the CPM leak 

detection system. 

[Amdt. 195–62, 63 FR 36376, July 6, 1998] 

Subpart D—Construction 

§ 195.200 Scope. 

This subpart prescribes minimum requirements for constructing new pipeline systems with steel pipe, and for relocating, replacing, or otherwise 

changing existing pipeline systems 

that are constructed with steel pipe. 

However, this subpart does not apply 

to the movement of pipe covered by 

§195.424. 

§ 195.202 Compliance with specifications or standards. 

Each pipeline system must be constructed in accordance with comprehensive written specifications or 

standards that are consistent with the 

requirements of this part. 

§ 195.204 Inspection—general. 

Inspection must be provided to ensure the installation of pipe or pipeline 

systems in accordance with the requirements of this subpart. No person 

may be used to perform inspections unless that person has been trained and is 

qualified in the phase of construction 

to be inspected. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as 

amended by Amdt. 195–52, 59 FR 33397, June 

28, 1994] 

§ 195.205 Repair, alteration and reconstruction of aboveground breakout 

tanks that have been in service. 

(a) Aboveground breakout tanks that 

have been repaired, altered, or reconstructed and returned to service must 

be capable of withstanding the internal 

pressure produced by the hazardous liquid to be stored therein and any anticipated external loads. 

(b) After October 2, 2000, compliance 

with paragraph (a) of this section requires the following for the tanks specified: 

(1) For tanks designed for approximately atmospheric pressure constructed of carbon and low alloy steel, 

welded or riveted, and non-refrigerated 

and tanks built to API Standard 650 or 

its predecessor Standard 12C, repair, alteration, and reconstruction must be in 

accordance with API Standard 653. 

(2) For tanks built to API Specification 12F or API Standard 620, the repair, alteration, and reconstruction 

must be in accordance with the design, 

welding, examination, and material requirements of those respective standards. 

(3) For high pressure tanks built to 

API Standard 2510, repairs, alterations, 

and reconstruction must be in accordance with API 510. 

[Amdt. 195–66, 64 FR 15935, Apr. 2, 1999] 

§ 195.206 Material inspection. 

No pipe or other component may be 

installed in a pipeline system unless it 

has been visually inspected at the site 

of installation to ensure that it is not 

damaged in a manner that could impair 

its strength or reduce its serviceability. 

§ 195.207 Transportation of pipe. 

(a) Railroad. In a pipeline operated at 

a hoop stress of 20 percent or more of 

SMYS, an operator may not use pipe 

having an outer diameter to wall 

thickness ratio of 70 to 1, or more, that 

is transported by railroad unless the 

transportation is performed in accordance with API Recommended Practice 

5L1 (incorporated by reference, see 

§195.3). 

(b) Ship or barge. In a pipeline operated at a hoop stress of 20 percent or 

more of SMYS, an operator may not 


wwoods2 on DSK1DXX6B1PROD with CFR
202 

§ 195.208 49 CFR Ch. I (10–1–10 Edition) 

use pipe having an outer diameter to 

wall thickness ratio of 70 to 1, or more, 

that is transported by ship or barge on 

both inland and marine waterways, unless the transportation is performed in 

accordance with API Recommended 

Practice 5LW (incorporated by reference, see §195.3). 

[ Amdt. 195–94, 75 FR 48606, Aug. 11, 2010] 

§ 195.208 Welding of supports and 

braces. 

Supports or braces may not be welded directly to pipe that will be operated at a pressure of more than 100 

p.s.i. (689 kPa) gage. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as 

amended by Amdt. 195–63, 63 FR 37506, July 

13, 1998] 

§ 195.210 Pipeline location. 

(a) Pipeline right-of-way must be selected to avoid, as far as practicable, 

areas containing private dwellings, industrial buildings, and places of public 

assembly. 

(b) No pipeline may be located within 

50 feet (15 meters) of any private dwelling, or any industrial building or place 

of public assembly in which persons 

work, congregate, or assemble, unless 

it is provided with at least 12 inches 

(305 millimeters) of cover in addition to 

that prescribed in §195.248. 

[Amdt. 195–22, 46 FR 39360, July 27, 1981, as 

amended by Amdt. 195–63, 63 FR 37506, July 

13, 1998] 

§ 195.212 Bending of pipe. 

(a) Pipe must not have a wrinkle 

bend. 

(b) Each field bend must comply with 

the following: 

(1) A bend must not impair the serviceability of the pipe. 

(2) Each bend must have a smooth 

contour and be free from buckling, 

cracks, or any other mechanical damage. 

(3) On pipe containing a longitudinal 

weld, the longitudinal weld must be as 

near as practicable to the neutral axis 

of the bend unless— 

(i) The bend is made with an internal 

bending mandrel; or 

(ii) The pipe is 123⁄4 in (324 mm) or 

less nominal outside diameter or has a 

diameter to wall thickness ratio less 

than 70. 

(c) Each circumferential weld which 

is located where the stress during bending causes a permanent deformation in 

the pipe must be nondestructively tested either before or after the bending 

process. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as 

amended by Amdt. 195–52, 59 FR 33396, June 

28, 1994; Amdt. 195–63, 63 FR 37506, July 13, 

1998] 

§ 195.214 Welding procedures. 

(a) Welding must be performed by a 

qualified welder in accordance with 

welding procedures qualified under 

Section 5 of API 1104 or Section IX of 

the ASME Boiler and Pressure Vessel 

Code (incorporated by reference, see 

§195.3) . The quality of the test welds 

used to qualify the welding procedure 

shall be determined by destructive 

testing. 

(b) Each welding procedure must be 

recorded in detail, including the results 

of the qualifying tests. This record 

must be retained and followed whenever the procedure is used. 

[Amdt. 195–38, 51 FR 20297, June 4, 1986, as 

amended at Amdt. 195–81, 69 FR 32897, June 

14, 2004] 

§ 195.216 Welding: Miter joints. 

A miter joint is not permitted (not 

including deflections up to 3 degrees 

that are caused by misalignment). 

§ 195.222 Welders: Qualification of 

welders. 

(a) Each welder must be qualified in 

accordance with section 6 of API 1104 

(incorporated by reference, see §195.3) 

or section IX of the ASME Boiler and 

Pressure Vessel Code, (incorporated by 

reference, see §195.3) except that a 

welder qualified under an earlier edition than listed in §195.3 may weld but 

may not re-qualify under that earlier 

edition. 

(b) No welder may weld with a welding process unless, within the preceding 6 calendar months, the welder 

has— 

(1) Engaged in welding with that 

process; and 


wwoods2 on DSK1DXX6B1PROD with CFR
203 

Pipeline and Hazardous Materials Safety Administration, DOT § 195.234 

(2) Had one welded tested and found 

acceptable under section 9 of API 1104 

(incorporated by reference, see §195.3). 

[Amdt. 195–81, 69 FR 54593, Sept. 9, 2004, as 

amended by Amdt. 195–86, 71 FR 33409, June 

9, 2006] 

§ 195.224 Welding: Weather. 

Welding must be protected from 

weather conditions that would impair 

the quality of the completed weld. 

§ 195.226 Welding: Arc burns. 

(a) Each arc burn must be repaired. 

(b) An arc burn may be repaired by 

completely removing the notch by 

grinding, if the grinding does not reduce the remaining wall thickness to 

less than the minimum thickness required by the tolerances in the specification to which the pipe is manufactured. If a notch is not repairable by 

grinding, a cylinder of the pipe containing the entire notch must be removed. 

(c) A ground may not be welded to 

the pipe or fitting that is being welded. 

§ 195.228 Welds and welding inspection: Standards of acceptability. 

(a) Each weld and welding must be 

inspected to insure compliance with 

the requirements of this subpart. Visual inspection must be supplemented 

by nondestructive testing. 

(b) The acceptability of a weld is determined according to the standards in 

Section 9 of API 1104. However, if a 

girth weld is unacceptable under those 

standards for a reason other than a 

crack, and if Appendix A to API 1104 

(incorporated by reference, see §195.3) 

applies to the weld, the acceptability 

of the weld may be determined under 

that appendix. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as 

amended by Amdt. 195–52, 59 FR 33397, June 

28, 1994; Amdt. 195–81, 69 FR 32898, June 14, 

2004] 

§ 195.230 Welds: Repair or removal of 

defects. 

(a) Each weld that is unacceptable 

under §195.228 must be removed or repaired. Except for welds on an offshore 

pipeline being installed from a pipelay 

vessel, a weld must be removed if it has 

a crack that is more than 8 percent of 

the weld length. 

(b) Each weld that is repaired must 

have the defect removed down to sound 

metal and the segment to be repaired 

must be preheated if conditions exist 

which would adversely affect the quality of the weld repair. After repair, the 

segment of the weld that was repaired 

must be inspected to ensure its acceptability. 

(c) Repair of a crack, or of any defect 

in a previously repaired area must be 

in accordance with written weld repair 

procedures that have been qualified 

under §195.214. Repair procedures must 

provide that the minimum mechanical 

properties specified for the welding 

procedure used to make the original 

weld are met upon completion of the 

final weld repair. 

[Amdt. 195–29, 48 FR 48674, Oct. 20, 1983] 

§ 195.234 Welds: Nondestructive testing. 

(a) A weld may be nondestructively 

tested by any process that will clearly 

indicate any defects that may affect 

the integrity of the weld. 

(b) Any nondestructive testing of 

welds must be performed— 

(1) In accordance with a written set 

of procedures for nondestructive testing; and 

(2) With personnel that have been 

trained in the established procedures 

and in the use of the equipment employed in the testing. 

(c) Procedures for the proper interpretation of each weld inspection must 

be established to ensure the acceptability of the weld under §195.228. 

(d) During construction, at least 10 

percent of the girth welds made by 

each welder during each welding day 

must be nondestructively tested over 

the entire circumference of the weld. 

(e) All girth welds installed each day 

in the following locations must be nondestructively tested over their entire 

circumference, except that when nondestructive testing is impracticable for 

a girth weld, it need not be tested if 

the number of girth welds for which 

testing is impracticable does not exceed 10 percent of the girth welds installed that day: 

(1) At any onshore location where a 

loss of hazardous liquid could reasonably be expected to pollute any stream, 


wwoods2 on DSK1DXX6B1PROD with CFR
204 

§§ 195.236–195.244 49 CFR Ch. I (10–1–10 Edition) 

river, lake, reservoir, or other body of 

water, and any offshore area; 

(2) Within railroad or public road 

rights-of-way; 

(3) At overhead road crossings and 

within tunnels; 

(4) Within the limits of any incorporated subdivision of a State government; and 

(5) Within populated areas, including, 

but not limited to, residential subdivisions, shopping centers, schools, designated commercial areas, industrial 

facilities, public institutions, and 

places of public assembly. 

(f) When installing used pipe, 100 percent of the old girth welds must be 

nondestructively tested. 

(g) At pipeline tie-ins, including tieins of replacement sections, 100 percent 

of the girth welds must be nondestructively tested. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as 

amended by Amdt. 195–35, 50 FR 37192, Sept. 

21, 1985; Amdt. 195–52, 59 FR 33397, June 28, 

1994] 

§§ 195.236–195.244 [Reserved] 

§ 195.246 Installation of pipe in a 

ditch. 

(a) All pipe installed in a ditch must 

be installed in a manner that minimizes the introduction of secondary 

stresses and the possibility of damage 

to the pipe. 

(b) Except for pipe in the Gulf of 

Mexico and its inlets in waters less 

than 15 feet deep, all offshore pipe in 

water at least 12 feet deep (3.7 meters) 

but not more than 200 feet deep (61 meters) deep as measured from the mean 

low water must be installed so that the 

top of the pipe is below the underwater 

natural bottom (as determined by recognized and generally accepted practices) unless the pipe is supported by 

stanchions held in place by anchors or 

heavy concrete coating or protected by 

an equivalent means. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as 

amended by Amdt. 195–52, 59 FR 33397, June 

28, 1994; 59 FR 36256, July 15, 1994; Amdt. 195– 

85, 69 FR 48407, Aug. 10, 2004] 

§ 195.248 Cover over buried pipeline. 

(a) Unless specifically exempted in 

this subpart, all pipe must be buried so 

that it is below the level of cultivation. 

Except as provided in paragraph (b) of 

this section, the pipe must be installed 

so that the cover between the top of 

the pipe and the ground level, road bed, 

river bottom, or underwater natural 

bottom (as determined by recognized 

and generally accepted practices), as 

applicable, complies with the following 

table: 

Location 

Cover inches (millimeters) 

For normal 

excavation 

For rock 

excavation 1

Industrial, commercial, and residential areas ............................................................................... 36 (914) 30 (762) 

Crossing of inland bodies of water with a width of at least 100 feet (30 millimeters) from high 

water mark to high water mark .................................................................................................. 48 (1219) 18 (457) 

Drainage ditches at public roads and railroads ............................................................................ 36 (914) 36 (914) 

Deepwater port safety zones ........................................................................................................ 48 (1219) 24 (610) 

Gulf of Mexico and its inlets in waters less than 15 feet (4.6 meters) deep as measured from 

mean low water ......................................................................................................................... 36 (914) 18 (457) 

Other offshore areas under water less than 12 ft (3.7 meters) deep as measured from mean 

low water .................................................................................................................................... 36 (914) 18 (457) 

Any other area ............................................................................................................................... 30 (762) 18 (457) 

1 Rock excavation is any excavation that requires blasting or removal by equivalent means. 

(b) Except for the Gulf of Mexico and 

its inlets in waters less than 15 feet (4.6 

meters) deep, less cover than the minimum required by paragraph (a) of this 

section and §195.210 may be used if— 

(1) It is impracticable to comply with 

the minimum cover requirements; and 

(2) Additional protection is provided 

that is equivalent to the minimum required cover. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981; 47 

FR 32721, July 29, 1982 as amended by Amdt. 

195–52, 59 FR 33397, June 28, 1994; 59 FR 36256, 

July 15, 1994; Amdt. 195–63, 63 FR 37506, July 

13, 1998; Amdt. 195–95, 69 FR 48407, Aug. 10, 

2004] 


wwoods2 on DSK1DXX6B1PROD with CFR
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Pipeline and Hazardous Materials Safety Administration, DOT § 195.262 

§ 195.250 Clearance between pipe and 

underground structures. 

Any pipe installed underground must 

have at least 12 inches (305 millimeters) of clearance between the outside 

of the pipe and the extremity of any 

other underground structure, except 

that for drainage tile the minimum 

clearance may be less than 12 inches 

(305 millimeters) but not less than 2 

inches (51 millimeters). However, 

where 12 inches (305 millimeters) of 

clearance is impracticable, the clearance may be reduced if adequate provisions are made for corrosion control. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as 

amended by Amdt. 195–63, 63 FR 37506, July 

13, 1998] 

§ 195.252 Backfilling. 

When a ditch for a pipeline is 

backfilled, it must be backfilled in a 

manner that: 

(a) Provides firm support under the 

pipe; and 

(b) Prevents damage to the pipe and 

pipe coating from equipment or from 

the backfill material. 

[Amdt. 195–78, 68 FR 53528, Sept. 11, 2003] 

§ 195.254 Above ground components. 

(a) Any component may be installed 

above ground in the following situations, if the other applicable requirements of this part are complied with: 

(1) Overhead crossings of highways, 

railroads, or a body of water. 

(2) Spans over ditches and gullies. 

(3) Scraper traps or block valves. 

(4) Areas under the direct control of 

the operator. 

(5) In any area inaccessible to the 

public. 

(b) Each component covered by this 

section must be protected from the 

forces exerted by the anticipated loads. 

§ 195.256 Crossing of railroads and 

highways. 

The pipe at each railroad or highway 

crossing must be installed so as to adequately withstand the dynamic forces 

exerted by anticipated traffic loads. 

§ 195.258 Valves: General. 

(a) Each valve must be installed in a 

location that is accessible to authorized employees and that is protected 

from damage or tampering. 

(b) Each submerged valve located offshore or in inland navigable waters 

must be marked, or located by conventional survey techniques, to facilitate 

quick location when operation of the 

valve is required. 

§ 195.260 Valves: Location. 

A valve must be installed at each of 

the following locations: 

(a) On the suction end and the discharge end of a pump station in a manner that permits isolation of the pump 

station equipment in the event of an 

emergency. 

(b) On each line entering or leaving a 

breakout storage tank area in a manner that permits isolation of the tank 

area from other facilities. 

(c) On each mainline at locations 

along the pipeline system that will 

minimize damage or pollution from accidental hazardous liquid discharge, as 

appropriate for the terrain in open 

country, for offshore areas, or for populated areas. 

(d) On each lateral takeoff from a 

trunk line in a manner that permits 

shutting off the lateral without interrupting the flow in the trunk line. 

(e) On each side of a water crossing 

that is more than 100 feet (30 meters) 

wide from high-water mark to highwater mark unless the Administrator 

finds in a particular case that valves 

are not justified. 

(f) On each side of a reservoir holding 

water for human consumption. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981; 47 

FR 32721, July 29, 1982; Amdt. 195–50, 59 FR 

17281, Apr. 12, 1994; Amdt. 195–63, 63 FR 37506, 

July 13, 1998] 

§ 195.262 Pumping equipment. 

(a) Adequate ventilation must be provided in pump station buildings to prevent the accumulation of hazardous vapors. Warning devices must be installed 

to warn of the presence of hazardous 

vapors in the pumping station building. 

(b) The following must be provided in 

each pump station: 

(1) Safety devices that prevent overpressuring of pumping equipment, including the auxiliary pumping equipment within the pumping station. 


wwoods2 on DSK1DXX6B1PROD with CFR
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§ 195.264 49 CFR Ch. I (10–1–10 Edition) 

(2) A device for the emergency shutdown of each pumping station. 

(3) If power is necessary to actuate 

the safety devices, an auxiliary power 

supply. 

(c) Each safety device must be tested 

under conditions approximating actual 

operations and found to function properly before the pumping station may be 

used. 

(d) Except for offshore pipelines, 

pumping equipment must be installed 

on property that is under the control of 

the operator and at least 15.2 m (50 ft) 

from the boundary of the pump station. 

(e) Adequate fire protection must be 

installed at each pump station. If the 

fire protection system installed requires the use of pumps, motive power 

must be provided for those pumps that 

is separate from the power that operates the station. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as 

amended by Amdt. 195–52, 59 FR 33397, June 

28, 1994] 

§ 195.264 Impoundment, protection 

against entry, normal/emergency 

venting or pressure/vacuum relief 

for aboveground breakout tanks. 

(a) A means must be provided for 

containing hazardous liquids in the 

event of spillage or failure of an aboveground breakout tank. 

(b) After October 2, 2000, compliance 

with paragraph (a) of this section requires the following for the aboveground breakout tanks specified: 

(1) For tanks built to API Specification 12F, API Standard 620, and others 

(such as API Standard 650 or its predecessor Standard 12C), the installation 

of impoundment must be in accordance 

with the following sections of NFPA 30: 

(i) Impoundment around a breakout 

tank must be installed in accordance 

with section 4.3.2.3.2; and 

(ii) Impoundment by drainage to a remote impounding area must be installed in accordance with section 

4.3.2.3.1. 

(2) For tanks built to API 2510, the 

installation of impoundment must be 

in accordance with section 5 or 11 of 

API 2510 (incorporated by reference, see 

§195.3). 

(c) Aboveground breakout tank areas 

must be adequately protected against 

unauthorized entry. 

(d) Normal/emergency relief venting 

must be provided for each atmospheric 

pressure breakout tank. Pressure/vacuum-relieving devices must be provided 

for each low-pressure and high-pressure 

breakout tank. 

(e) For normal/emergency relief venting and pressure/vacuum-relieving devices installed on aboveground breakout tanks after October 2, 2000, compliance with paragraph (d) of this section 

requires the following for the tanks 

specified: 

(1) Normal/emergency relief venting 

installed on atmospheric pressure 

tanks built to API Specification 12F 

(incorporated by reference, see §195.3) 

must be in accordance with Section 4, 

and Appendices B and C, of API Specification 12F (incorporated by reference, 

see §195.3). 

(2) Normal/emergency relief venting 

installed on atmospheric pressure 

tanks (such as those built to API 

Standard 650 or its predecessor Standard 12C) must be in accordance with 

API Standard 2000 (incorporated by reference, see §195.3). 

(3) Pressure-relieving and emergency 

vacuum-relieving devices installed on 

low pressure tanks built to API Standard 620 (incorporated by reference, see 

§195.3) must be in accordance with section 9 of API Standard 620 (incorporated by reference, see §195.3) and its 

references to the normal and emergency venting requirements in API 

Standard 2000 (incorporated by reference, see §195.3). 

(4) Pressure and vacuum-relieving devices installed on high pressure tanks 

built to API Standard 2510 (incorporated by reference, see §195.3) must 

be in accordance with sections 7 or 11 

of API Standard 2510 (incorporated by 

reference, see §195.3). 

[Amdt. 195–66, 64 FR 15935, Apr. 2, 1999, as 

amended by 195–86, 71 FR 33410, June 9, 2006; 

195–94, 75 FR 48606, Aug. 11, 2010] 

§ 195.266 Construction records. 

A complete record that shows the following must be maintained by the operator involved for the life of each 

pipeline facility: 

(a) The total number of girth welds 

and the number nondestructively tested, including the number rejected and 

the disposition of each rejected weld. 


wwoods2 on DSK1DXX6B1PROD with CFR
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Pipeline and Hazardous Materials Safety Administration, DOT § 195.303 

(b) The amount, location; and cover 

of each size of pipe installed. 

(c) The location of each crossing of 

another pipeline. 

(d) The location of each buried utility crossing. 

(e) The location of each overhead 

crossing. 

(f) The location of each valve and 

corrosion test station. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as 

amended by Amdt. 195–34, 50 FR 34474, Aug. 

26, 1985] 

Subpart E—Pressure Testing 

§ 195.300 Scope. 

This subpart prescribes minimum requirements for the pressure testing of 

steel pipelines. However, this subpart 

does not apply to the movement of pipe 

under §195.424. 

[Amdt. 195–51, 59 FR 29384, June 7, 1994] 

§ 195.302 General requirements. 

(a) Except as otherwise provided in 

this section and in §195.305(b), no operator may operate a pipeline unless it 

has been pressure tested under this 

subpart without leakage. In addition, 

no operator may return to service a 

segment of pipeline that has been replaced, relocated, or otherwise changed 

until it has been pressure tested under 

this subpart without leakage. 

(b) Except for pipelines converted 

under §195.5, the following pipelines 

may be operated without pressure testing under this subpart: 

(1) Any hazardous liquid pipeline 

whose maximum operating pressure is 

established under §195.406(a)(5) that 

is— 

(i) An interstate pipeline constructed 

before January 8, 1971; 

(ii) An interstate offshore gathering 

line constructed before August 1, 1977; 

(iii) An intrastate pipeline constructed before October 21, 1985; or 

(iv) A low-stress pipeline constructed 

before August 11, 1994 that transports 

HVL. 

(2) Any carbon dioxide pipeline constructed before July 12, 1991, that— 

(i) Has its maximum operating pressure established under §195.406(a)(5); or 

(ii) Is located in a rural area as part 

of a production field distribution system. 

(3) Any low-stress pipeline constructed before August 11, 1994 that 

does not transport HVL. 

(4) Those portions of older hazardous 

liquid and carbon dioxide pipelines for 

which an operator has elected the riskbased alternative under §195.303 and 

which are not required to be tested 

based on the risk-based criteria. 

(c) Except for pipelines that transport HVL onshore, low-stress pipelines, 

and pipelines covered under §195.303, 

the following compliance deadlines 

apply to pipelines under paragraphs 

(b)(1) and (b)(2)(i) of this section that 

have not been pressure tested under 

this subpart: 

(1) Before December 7, 1998, for each 

pipeline each operator shall— 

(i) Plan and schedule testing according to this paragraph; or 

(ii) Establish the pipeline’s maximum 

operating pressure under §195.406(a)(5). 

(2) For pipelines scheduled for testing, each operator shall— 

(i) Before December 7, 2000, pressure 

test— 

(A) Each pipeline identified by name, 

symbol, or otherwise that existing 

records show contains more than 50 

percent by mileage (length) of electric 

resistance welded pipe manufactured 

before 1970; and 

(B) At least 50 percent of the mileage 

(length) of all other pipelines; and 

(ii) Before December 7, 2003, pressure 

test the remainder of the pipeline mileage (length). 

[Amdt. 195–51, 59 FR 29384, June 7, 1994, as 

amended by Amdt. 195–53, 59 FR 35471, July 

12, 1994; Amdt. 195–51B, 61 FR 43027, Aug. 20, 

1996; Amdt. 195–58, 62 FR 54592, Oct. 21, 1997; 

Amdt. 195–63, 63 FR 37506, July 13, 1998; 

Amdt. 195–65, 63 FR 59479, Nov. 4, 1998] 

§ 195.303 Risk-based alternative to 

pressure testing older hazardous 

liquid and carbon dioxide pipelines. 

(a) An operator may elect to follow a 

program for testing a pipeline on riskbased criteria as an alternative to the 

pressure testing in §195.302(b)(1)(i)–(iii) 

and §195.302(b)(2)(i) of this subpart. Appendix B provides guidance on how this 

program will work. An operator electing such a program shall assign a risk 

classification to each pipeline segment 


wwoods2 on DSK1DXX6B1PROD with CFR
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§ 195.303 49 CFR Ch. I (10–1–10 Edition) 

1 (See Appendix B, Table C). 

according to the indicators described in 

paragraph (b) of this section as follows: 

(1) Risk Classification A if the location indicator is ranked as low or medium risk, the product and volume indicators are ranked as low risk, and 

the probability of failure indicator is 

ranked as low risk; 

(2) Risk Classification C if the location indicator is ranked as high risk; or 

(3) Risk Classification B. 

(b) An operator shall evaluate each 

pipeline segment in the program according to the following indicators of 

risk: 

(1) The location indicator is— 

(i) High risk if an area is non-rural or 

environmentally sensitive 1; or 

(ii) Medium risk; or 

(iii) Low risk if an area is not high or 

medium risk. 

(2) The product indicator is 1

(i) High risk if the product transported is highly toxic or is both highly 

volatile and flammable; 

(ii) Medium risk if the product transported is flammable with a flashpoint 

of less than 100 °F, but not highly volatile; or 

(iii) Low risk if the product transported is not high or medium risk. 

(3) The volume indicator is— 

(i) High risk if the line is at least 18 

inches in nominal diameter; 

(ii) Medium risk if the line is at least 

10 inches, but less than 18 inches, in 

nominal diameter; or 

(iii) Low risk if the line is not high or 

medium risk. 

(4) The probability of failure indicator is— 

(i) High risk if the segment has experienced more than three failures in the 

last 10 years due to time-dependent defects (e.g., corrosion, gouges, or problems developed during manufacture, 

construction or operation, etc.); or 

(ii) Low risk if the segment has experienced three failures or less in the last 

10 years due to time-dependent defects. 

(c) The program under paragraph (a) 

of this section shall provide for pressure testing for a segment constructed 

of electric resistance-welded (ERW) 

pipe and lapwelded pipe manufactured 

prior to 1970 susceptible to longitudinal 

seam failures as determined through 

paragraph (d) of this section. The timing of such pressure test may be determined based on risk classifications discussed under paragraph (b) of this section. For other segments, the program 

may provide for use of a magnetic flux 

leakage or ultrasonic internal inspection survey as an alternative to pressure testing and, in the case of such 

segments in Risk Classification A, may 

provide for no additional measures 

under this subpart. 

(d) All pre-1970 ERW pipe and 

lapwelded pipe is deemed susceptible to 

longitudinal seam failures unless an 

engineering analysis shows otherwise. 

In conducting an engineering analysis 

an operator must consider the seam-related leak history of the pipe and pipe 

manufacturing information as available, which may include the pipe 

steel’s mechanical properties, including fracture toughness; the manufacturing process and controls related to 

seam properties, including whether the 

ERW process was high-frequency or 

low-frequency, whether the weld seam 

was heat treated, whether the seam 

was inspected, the test pressure and 

duration during mill hydrotest; the 

quality control of the steel-making 

process; and other factors pertinent to 

seam properties and quality. 

(e) Pressure testing done under this 

section must be conducted in accordance with this subpart. Except for segments in Risk Classification B which 

are not constructed with pre-1970 ERW 

pipe, water must be the test medium. 

(f) An operator electing to follow a 

program under paragraph (a) must develop plans that include the method of 

testing and a schedule for the testing 

by December 7, 1998. The compliance 

deadlines for completion of testing are 

as shown in the table below: 

§ 195.303—TEST DEADLINES

Pipeline Segment Risk classification Test deadline 

Pre-1970 Pipe susceptible to longitudinal seam failures [defined in 

§ 195.303(c) & 

(d)].

C or B ...................

A ...........................

12/7/2000 

12/7/2002 

All Other Pipeline 

Segments.

C ...........................

B ...........................

A ...........................

12/7/2002 

12/7//2004 

Additional testing 

not required 


wwoods2 on DSK1DXX6B1PROD with CFR
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Pipeline and Hazardous Materials Safety Administration, DOT § 195.306 

(g) An operator must review the risk 

classifications for those pipeline segments which have not yet been tested 

under paragraph (a) of this section or 

otherwise inspected under paragraph 

(c) of this section at intervals not to 

exceed 15 months. If the risk classification of an untested or uninspected segment changes, an operator must take 

appropriate action within two years, or 

establish the maximum operating pressure under §195.406(a)(5). 

(h) An operator must maintain 

records establishing compliance with 

this section, including records 

verifying the risk classifications, the 

plans and schedule for testing, the conduct of the testing, and the review of 

the risk classifications. 

(i) An operator may discontinue a 

program under this section only after 

written notification to the Administrator and approval, if needed, of a 

schedule for pressure testing. 

[Amdt. 195–65, 63 FR 59480, Nov. 4, 1998] 

§ 195.304 Test pressure. 

The test pressure for each pressure 

test conducted under this subpart must 

be maintained throughout the part of 

the system being tested for at least 4 

continuous hours at a pressure equal to 

125 percent, or more, of the maximum 

operating pressure and, in the case of a 

pipeline that is not visually inspected 

for leakage during the test, for at least 

an additional 4 continuous hours at a 

pressure equal to 110 percent, or more, 

of the maximum operating pressure. 

[Amdt. 195–51, 59 FR 29384, June 7, 1994. Redesignated by Amdt. 195–65, 63 FR 59480, Nov. 

4, 1998] 

§ 195.305 Testing of components. 

(a) Each pressure test under §195.302 

must test all pipe and attached fittings, including components, unless 

otherwise permitted by paragraph (b) 

of this section. 

(b) A component, other than pipe, 

that is the only item being replaced or 

added to the pipeline system need not 

be hydrostatically tested under paragraph (a) of this section if the manufacturer certifies that either— 

(1) The component was 

hydrostatically tested at the factory; 

or 

(2) The component was manufactured 

under a quality control system that ensures each component is at least equal 

in strength to a prototype that was 

hydrostatically tested at the factory. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as 

amended by Amdt. 195–51, 59 FR 29385, June 

7, 1994; Amdt. 195–52, 59 FR 33397, June 28, 

1994. Redesignated by Amdt. 195–65, 63 FR 

59480, Nov. 4, 1998] 

§ 195.306 Test medium. 

(a) Except as provided in paragraphs 

(b), (c), and (d) of this section, water 

must be used as the test medium. 

(b) Except for offshore pipelines, liquid petroleum that does not vaporize 

rapidly may be used as the test medium if— 

(1) The entire pipeline section under 

test is outside of cities and other populated areas; 

(2) Each building within 300 feet (91 

meters) of the test section is unoccupied while the test pressure is equal to 

or greater than a pressure which produces a hoop stress of 50 percent of 

specified minimum yield strength; 

(3) The test section is kept under surveillance by regular patrols during the 

test; and 

(4) Continuous communication is 

maintained along entire test section. 

(c) Carbon dioxide pipelines may use 

inert gas or carbon dioxide as the test 

medium if— 

(1) The entire pipeline section under 

test is outside of cities and other populated areas; 

(2) Each building within 300 feet (91 

meters) of the test section is unoccupied while the test pressure is equal to 

or greater than a pressure that produces a hoop stress of 50 percent of 

specified minimum yield strength; 

(3) The maximum hoop stress during 

the test does not exceed 80 percent of 

specified minimum yield strength; 

(4) Continuous communication is 

maintained along entire test section; 

and 

(5) The pipe involved is new pipe having a longitudinal joint factor of 1.00. 


wwoods2 on DSK1DXX6B1PROD with CFR
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§ 195.307 49 CFR Ch. I (10–1–10 Edition) 

(d) Air or inert gas may be used as 

the test medium in low-stress pipelines. 

[Amdt. 195–22, 46 FR 38360, July 27, 1991, as 

amended by Amdt. 195–45, 56 FR 26926, June 

12, 1991; Amdt. 195–51, 59 FR 29385, June 7, 

1994; Amdt. 195–53, 59 FR 35471, July 12, 1994; 

Amdt. 195–51A, 59 FR 41260, Aug. 11, 1994; 

Amdt. 195–63, 63 FR 37506, July 13, 1998] 

§ 195.307 Pressure testing aboveground breakout tanks. 

(a) For aboveground breakout tanks 

built into API Specification 12F and 

first placed in service after October 2, 

2000, pneumatic testing must be in accordance with section 5.3 of API Specification 12 F (incorporated by reference, see §195.3). 

(b) For aboveground breakout tanks 

built to API Standard 620 and first 

placed in service after October 2, 2000, 

hydrostatic and pneumatic testing 

must be in accordance with section 7.18 

of API Standard 620 (incorporated by 

reference, see §195.3). 

(c) For aboveground breakout tanks 

built to API Standard 650 (incorporated 

by reference, see §195.3) and first placed 

in service after October 2, 2000, testing 

must be in accordance with Section 5.2 

of API Standard 650 (incorporated by 

reference, see §195.3). 

(d) For aboveground atmospheric 

pressure breakout tanks constructed of 

carbon and low alloy steel, welded or 

riveted, and non-refrigerated and tanks 

built to API Standard 650 or its predecessor Standard 12C that are returned 

to service after October 2, 2000, the necessity for the hydrostatic testing of 

repair, alteration, and reconstruction 

is covered in section 10.3 of API Standard 653. 

(e) For aboveground breakout tanks 

built to API Standard 2510 and first 

placed in service after October 2, 2000, 

pressure testing must be in accordance 

with ASME Boiler and Pressure Vessel 

Code, Section VIII, Division 1 or 2. 

[Amdt. 195–66, 64 FR 15936, Apr. 2, 1999, as 

amended by Amdt. 195–86, 71 FR 33410, June 

9, 2006; Amdt. 195–94, 75 FR 48607, Aug. 11, 

2010] 

§ 195.308 Testing of tie-ins. 

Pipe associated with tie-ins must be 

pressure tested, either with the section 

to be tied in or separately. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as 

amended by 195–51, 59 FR 29385, June 7, 1994] 

§ 195.310 Records. 

(a) A record must be made of each 

pressure test required by this subpart, 

and the record of the latest test must 

be retained as long as the facility tested is in use. 

(b) The record required by paragraph 

(a) of this section must include: 

(1) The pressure recording charts; 

(2) Test instrument calibration data; 

(3) The name of the operator, the 

name of the person responsible for 

making the test, and the name of the 

test company used, if any; 

(4) The date and time of the test; 

(5) The minimum test pressure; 

(6) The test medium; 

(7) A description of the facility tested 

and the test apparatus; 

(8) An explanation of any pressure 

discontinuities, including test failures, 

that appear on the pressure recording 

charts; 

(9) Where elevation differences in the 

section under test exceed 100 feet (30 

meters), a profile of the pipeline that 

shows the elevation and test sites over 

the entire length of the test section; 

and 

(10) Temperature of the test medium 

or pipe during the test period. 

[Amdt. 195–34, 50 FR 34474, Aug. 26, 1985, as 

amended by Amdt. 195–51, 59 FR 29385, June 

7, 1994; Amdt. 195–63, 63 FR 37506, July 13, 

1998; Amdt. 195–78, 68 FR 53528, Sept. 11, 2003] 

Subpart F—Operation and 

Maintenance 

§ 195.400 Scope. 

This subpart prescribes minimum requirements for operating and maintaining pipeline systems constructed 

with steel pipe. 

§ 195.401 General requirements. 

(a) No operator may operate or maintain its pipeline systems at a level of 

safety lower than that required by this 


wwoods2 on DSK1DXX6B1PROD with CFR
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Pipeline and Hazardous Materials Safety Administration, DOT § 195.402 

subpart and the procedures it is required to establish under §195.402(a) of 

this subpart. 

(b) An operator must make repairs on 

its pipeline system according to the 

following requirements: 

(1) Non Integrity management repairs. 

Whenever an operator discovers any 

condition that could adversely affect 

the safe operation of its pipeline system, it must correct the condition 

within a reasonable time. However, if 

the condition is of such a nature that 

it presents an immediate hazard to persons or property, the operator may not 

operate the affected part of the system 

until it has corrected the unsafe condition. 

(2) Integrity management repairs. When 

an operator discovers a condition on a 

pipeline covered under §195.452, the operator must correct the condition as 

prescribed in §195.452(h). 

(c) Except as provided in §195.5, no 

operator may operate any part of any 

of the following pipelines unless it was 

designed and constructed as required 

by this part: 

(1) An interstate pipeline, other than 

a low-stress pipeline, on which construction was begun after March 31, 

1970, that transports hazardous liquid. 

(2) An interstate offshore gathering 

line, other than a low-stress pipeline, 

on which construction was begun after 

July 31, 1977, that transports hazardous 

liquid. 

(3) An intrastate pipeline, other than 

a low-stress pipeline, on which construction was begun after October 20, 

1985, that transports hazardous liquid. 

(4) A pipeline on which construction 

was begun after July 11, 1991, that 

transports carbon dioxide. 

(5) A low-stress pipeline on which 

construction was begun after August 

10, 1994. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as 

amended by Amdt. 195–33, 50 FR 15899, Apr. 

23, 1985; Amdt. 195–33A, 50 FR 39008, Sept. 26, 

1985; Amdt. 195–36, 51 FR 15008, Apr. 22, 1986; 

Amdt. 195–45, 56 FR 26926, June 12, 1991; 

Amdt. 195–53, 59 FR 35471, July 12, 1994; 

Amdt. 195–94, 75 FR 48607, Aug. 11, 2010] 

§ 195.402 Procedural manual for operations, maintenance, and emergencies. 

(a) General. Each operator shall prepare and follow for each pipeline system a manual of written procedures for 

conducting normal operations and 

maintenance activities and handling 

abnormal operations and emergencies. 

This manual shall be reviewed at intervals not exceeding 15 months, but at 

least once each calendar year, and appropriate changes made as necessary to 

insure that the manual is effective. 

This manual shall be prepared before 

initial operations of a pipeline system 

commence, and appropriate parts shall 

be kept at locations where operations 

and maintenance activities are conducted. 

(b) The Administrator or the State 

Agency that has submitted a current 

certification under the pipeline safety 

laws (49 U.S.C. 60101 et seq.) with respect to the pipeline facility governed 

by an operator’s plans and procedures 

may, after notice and opportunity for 

hearing as provided in 49 CFR 190.237 or 

the relevant State procedures, require 

the operator to amend its plans and 

procedures as necessary to provide a 

reasonable level of safety. 

(c) Maintenance and normal operations. 

The manual required by paragraph (a) 

of this section must include procedures 

for the following to provide safety during maintenance and normal operations: 

(1) Making construction records, 

maps, and operating history available 

as necessary for safe operation and 

maintenance. 

(2) Gathering of data needed for reporting accidents under subpart B of 

this part in a timely and effective manner. 

(3) Operating, maintaining, and repairing the pipeline system in accordance with each of the requirements of 

this subpart and subpart H of this part. 

(4) Determining which pipeline facilities are located in areas that would require an immediate response by the operator to prevent hazards to the public 

if the facilities failed or malfunctioned. 

(5) Analyzing pipeline accidents to 

determine their causes. 

(6) Minimizing the potential for hazards identified under paragraph (c)(4) 

of this section and the possibility of recurrence of accidents analyzed under 

paragraph (c)(5) of this section. 

(7) Starting up and shutting down 

any part of the pipeline system in a 


wwoods2 on DSK1DXX6B1PROD with CFR
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§ 195.402 49 CFR Ch. I (10–1–10 Edition) 

manner designed to assure operation 

within the limits prescribed by 

§195.406, consider the hazardous liquid 

or carbon dioxide in transportation, 

variations in altitude along the pipeline, and pressure monitoring and control devices. 

(8) In the case of a pipeline that is 

not equipped to fail safe, monitoring 

from an attended location pipeline 

pressure during startup until steady 

state pressure and flow conditions are 

reached and during shut-in to assure 

operation within limits prescribed by 

§195.406. 

(9) In the case of facilities not 

equipped to fail safe that are identified 

under paragraph 195.402(c)(4) or that 

control receipt and delivery of the hazardous liquid or carbon dioxide, detecting abnormal operating conditions by 

monitoring pressure, temperature, flow 

or other appropriate operational data 

and transmitting this data to an attended location. 

(10) Abandoning pipeline facilities, 

including safe disconnection from an 

operating pipeline system, purging of 

combustibles, and sealing abandoned 

facilities left in place to minimize safety and environmental hazards. For 

each abandoned offshore pipeline facility or each abandoned onshore pipeline 

facility that crosses over, under or 

through commercially navigable waterways the last operator of that facility must file a report upon abandonment of that facility in accordance 

with §195.59 of this part. 

(11) Minimizing the likelihood of accidental ignition of vapors in areas 

near facilities identified under paragraph (c)(4) of this section where the 

potential exists for the presence of 

flammable liquids or gases. 

(12) Establishing and maintaining liaison with fire, police, and other appropriate public officials to learn the responsibility and resources of each government organization that may respond to a hazardous liquid or carbon 

dioxide pipeline emergency and acquaint the officials with the operator’s 

ability in responding to a hazardous 

liquid or carbon dioxide pipeline emergency and means of communication. 

(13) Periodically reviewing the work 

done by operator personnel to determine the effectiveness of the procedures used in normal operation and 

maintenance and taking corrective action where deficiencies are found. 

(14) Taking adequate precautions in 

excavated trenches to protect personnel from the hazards of unsafe accumulations of vapor or gas, and making 

available when needed at the excavation, emergency rescue equipment, 

including a breathing apparatus and, a 

rescue harness and line. 

(15) Implementing the applicable control room management procedures required by §195.446. 

(d) Abnormal operation. The manual 

required by paragraph (a) of this section must include procedures for the 

following to provide safety when operating design limits have been exceeded: 

(1) Responding to, investigating, and 

correcting the cause of: 

(i) Unintended closure of valves or 

shutdowns; 

(ii) Increase or decrease in pressure 

or flow rate outside normal operating 

limits; 

(iii) Loss of communications; 

(iv) Operation of any safety device; 

(v) Any other malfunction of a component, deviation from normal operation, or personnel error which could 

cause a hazard to persons or property. 

(2) Checking variations from normal 

operation after abnormal operation has 

ended at sufficient critical locations in 

the system to determine continued integrity and safe operation. 

(3) Correcting variations from normal 

operation of pressure and flow equipment and controls. 

(4) Notifying responsible operator 

personnel when notice of an abnormal 

operation is received. 

(5) Periodically reviewing the response of operator personnel to determine the effectiveness of the procedures controlling abnormal operation 

and taking corrective action where deficiencies are found. 

(e) Emergencies. The manual required 

by paragraph (a) of this section must 

include procedures for the following to 

provide safety when an emergency condition occurs: 

(1) Receiving, identifying, and 

classifying notices of events which 

need immediate response by the operator or notice to fire, police, or other 


wwoods2 on DSK1DXX6B1PROD with CFR
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Pipeline and Hazardous Materials Safety Administration, DOT § 195.403 

appropriate public officials and communicating this information to appropriate operator personnel for corrective action. 

(2) Prompt and effective response to a 

notice of each type emergency, including fire or explosion occurring near or 

directly involving a pipeline facility, 

accidental release of hazardous liquid 

or carbon dioxide from a pipeline facility, operational failure causing a hazardous condition, and natural disaster 

affecting pipeline facilities. 

(3) Having personnel, equipment, instruments, tools, and material available as needed at the scene of an emergency. 

(4) Taking necessary action, such as 

emergency shutdown or pressure reduction, to minimize the volume of hazardous liquid or carbon dioxide that is 

released from any section of a pipeline 

system in the event of a failure. 

(5) Control of released hazardous liquid or carbon dioxide at an accident 

scene to minimize the hazards, including possible intentional ignition in the 

cases of flammable highly volatile liquid. 

(6) Minimization of public exposure 

to injury and probability of accidental 

ignition by assisting with evacuation 

of residents and assisting with halting 

traffic on roads and railroads in the affected area, or taking other appropriate action. 

(7) Notifying fire, police, and other 

appropriate public officials of hazardous liquid or carbon dioxide pipeline 

emergencies and coordinating with 

them preplanned and actual responses 

during an emergency, including additional precautions necessary for an 

emergency involving a pipeline system 

transporting a highly volatile liquid. 

(8) In the case of failure of a pipeline 

system transporting a highly volatile 

liquid, use of appropriate instruments 

to assess the extent and coverage of 

the vapor cloud and determine the hazardous areas. 

(9) Providing for a post accident review of employee activities to determine whether the procedures were effective in each emergency and taking 

corrective action where deficiencies 

are found. 

(10) Actions required to be taken by a 

controller during an emergency, in accordance with §195.446. 

(f) Safety-related condition reports. The 

manual required by paragraph (a) of 

this section must include instructions 

enabling personnel who perform operation and maintenance activities to 

recognize conditions that potentially 

may be safety-related conditions that 

are subject to the reporting requirements of §195.55. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981; 47 

FR 32721, July 29, 1982, as amended by Amdt. 

195–24, 47 FR 46852, Oct. 21, 1982; Amdt. 195–39, 

53 FR 24951, July 1, 1988; Amdt. 195–45, 56 FR 

26926, June 12, 1991; Amdt. 195–46, 56 FR 31090, 

July 9, 1991; Amdt. 195–49, 59 FR 6585, Feb. 11, 

1994; Amdt. 195–55, 61 FR 18518, Apr. 26, 1996; 

Amdt. 195–69, 65 FR 54444, Sept. 8, 2000; Amdt. 

195–173, 66 FR 67004, Dec. 27, 2001; Amdt. 195– 

93, 74 FR 63329, Dec. 3, 2009] 

§ 195.403 Emergency response training. 

(a) Each operator shall establish and 

conduct a continuing training program 

to instruct emergency response personnel to: 

(1) Carry out the emergency procedures established under 195.402 that relate to their assignments; 

(2) Know the characteristics and hazards of the hazardous liquids or carbon 

dioxide transported, including, in case 

of flammable HVL, flammability of 

mixtures with air, odorless vapors, and 

water reactions; 

(3) Recognize conditions that are 

likely to cause emergencies, predict 

the consequences of facility malfunctions or failures and hazardous liquids 

or carbon dioxide spills, and take appropriate corrective action; 

(4) Take steps necessary to control 

any accidental release of hazardous liquid or carbon dioxide and to minimize 

the potential for fire, explosion, toxicity, or environmental damage; and 

(5) Learn the potential causes, types, 

sizes, and consequences of fire and the 

appropriate use of portable fire extinguishers and other on-site fire control 

equipment, involving, where feasible, a 

simulated pipeline emergency condition. 

(b) At the intervals not exceeding 15 

months, but at least once each calendar year, each operator shall: 


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§ 195.404 49 CFR Ch. I (10–1–10 Edition) 

(1) Review with personnel their performance in meeting the objectives of 

the emergency response training program set forth in paragraph (a) of this 

section; and 

(2) Make appropriate changes to the 

emergency response training program 

as necessary to ensure that it is effective. 

(c) Each operator shall require and 

verify that its supervisors maintain a 

thorough knowledge of that portion of 

the emergency response procedures established under 195.402 for which they 

are responsible to ensure compliance. 

[Amdt. 195–67, 64 FR 46866, Aug. 27, 1999, as 

amended at Amdt. 195–78, 68 FR 53528, Sept. 

11, 2003] 

§ 195.404 Maps and records. 

(a) Each operator shall maintain current maps and records of its pipeline 

systems that include at least the following information: 

(1) Location and identification of the 

following pipeline facilities: 

(i) Breakout tanks; 

(ii) Pump stations; 

(iii) Scraper and sphere facilities; 

(iv) Pipeline valves; 

(v) Facilities to which §195.402(c)(9) 

applies; 

(vi) Rights-of-way; and 

(vii) Safety devices to which §195.428 

applies. 

(2) All crossings of public roads, railroads, rivers, buried utilities, and foreign pipelines. 

(3) The maximum operating pressure 

of each pipeline. 

(4) The diameter, grade, type, and 

nominal wall thickness of all pipe. 

(b) Each operator shall maintain for 

at least 3 years daily operating records 

that indicate— 

(1) The discharge pressure at each 

pump station; and 

(2) Any emergency or abnormal operation to which the procedures under 

§195.402 apply. 

(c) Each operator shall maintain the 

following records for the periods specified: 

(1) The date, location, and description of each repair made to pipe shall 

be maintained for the useful life of the 

pipe. 

(2) The date, location, and description of each repair made to parts of the 

pipeline system other than pipe shall 

be maintained for at least 1 year. 

(3) A record of each inspection and 

test required by this subpart shall be 

maintained for at least 2 years or until 

the next inspection or test is performed, whichever is longer. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as 

amended by Amdt. 195–34, 50 FR 34474, Aug. 

26, 1985; Amdt. 195–173, 66 FR 67004, Dec. 27, 

2001] 

§ 195.405 Protection against ignitions 

and safe access/egress involving 

floating roofs. 

(a) After October 2, 2000, protection 

provided against ignitions arising out 

of static electricity, lightning, and 

stray currents during operation and 

maintenance activities involving 

aboveground breakout tanks must be 

in accordance with API Recommended 

Practice 2003, unless the operator notes 

in the procedural manual (§195.402(c)) 

why compliance with all or certain provisions of API Recommended Practice 

2003 is not necessary for the safety of a 

particular breakout tank. 

(b) The hazards associated with access/egress onto floating roofs of inservice aboveground breakout tanks to 

perform inspection, service, maintenance or repair activities (other than 

specified general considerations, specified routine tasks or entering tanks removed from service for cleaning) are 

addressed in API Publication 2026. 

After October 2, 2000, the operator must 

review and consider the potentially 

hazardous conditions, safety practices 

and procedures in API Publication 2026 

for inclusion in the procedure manual 

(§195.402(c)). 

[Amdt. 195–66, 64 FR 15936, Apr. 2, 1999] 

§ 195.406 Maximum operating pressure. 

(a) Except for surge pressures and 

other variations from normal operations, no operator may operate a pipeline at a pressure that exceeds any of 

the following: 

(1) The internal design pressure of 

the pipe determined in accordance with 

§195.106. However, for steel pipe in pipelines being converted under §195.5, if 

one or more factors of the design formula (§195.106) are unknown, one of the 


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Pipeline and Hazardous Materials Safety Administration, DOT § 195.410 

following pressures is to be used as design pressure: 

(i) Eighty percent of the first test 

pressure that produces yield under section N5.0 of appendix N of ASME B31.8, 

reduced by the appropriate factors in 

§§195.106 (a) and (e); or 

(ii) If the pipe is 12 3⁄4 inch (324 mm) 

or less outside diameter and is not 

tested to yield under this paragraph, 

200 p.s.i. (1379 kPa) gage. 

(2) The design pressure of any other 

component of the pipeline. 

(3) Eighty percent of the test pressure for any part of the pipeline which 

has been pressure tested under subpart 

E of this part. 

(4) Eighty percent of the factory test 

pressure or of the prototype test pressure for any individually installed 

component which is excepted from 

testing under §195.305. 

(5) For pipelines under §§195.302(b)(1) 

and (b)(2)(i) that have not been pressure tested under subpart E of this 

part, 80 percent of the test pressure or 

highest operating pressure to which 

the pipeline was subjected for 4 or more 

continuous hours that can be demonstrated by recording charts or logs 

made at the time the test or operations 

were conducted. 

(b) No operator may permit the pressure in a pipeline during surges or 

other variations from normal operations to exceed 110 percent of the operating pressure limit established 

under paragraph (a) of this section. 

Each operator must provide adequate 

controls and protective equipment to 

control the pressure within this limit. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as 

amended by Amdt. 195–33, 50 FR 15899, Apr. 

23, 1985; 50 FR 38660, Sept. 24, 1985; Amdt. 195– 

51, 59 FR 29385, June 7, 1994; Amdt. 195–52, 59 

FR 33397, June 28, 1994; Amdt. 195–63, 63 FR 

37506, July 13, 1998; Amdt. 195–65, 63 FR 59480, 

Nov. 4, 1998] 

§ 195.408 Communications. 

(a) Each operator must have a communication system to provide for the 

transmission of information needed for 

the safe operation of its pipeline system. 

(b) The communication system required by paragraph (a) of this section 

must, as a minimum, include means 

for: 

(1) Monitoring operational data as required by §195.402(c)(9); 

(2) Receiving notices from operator 

personnel, the public, and public authorities of abnormal or emergency 

conditions and sending this information to appropriate personnel or government agencies for corrective action; 

(3) Conducting two-way vocal communication between a control center 

and the scene of abnormal operations 

and emergencies; and 

(4) Providing communication with 

fire, police, and other appropriate public officials during emergency conditions, including a natural disaster. 

§ 195.410 Line markers. 

(a) Except as provided in paragraph 

(b) of this section, each operator shall 

place and maintain line markers over 

each buried pipeline in accordance with 

the following: 

(1) Markers must be located at each 

public road crossing, at each railroad 

crossing, and in sufficient number 

along the remainder of each buried line 

so that its location is accurately 

known. 

(2) The marker must state at least 

the following on a background of 

sharply contrasting color: 

(i) The word ‘‘Warning,’’ ‘‘Caution,’’ 

or ‘‘Danger’’ followed by the words 

‘‘Petroleum (or the name of the hazardous liquid transported) Pipeline’’, or 

‘‘Carbon Dioxide Pipeline,’’ all of 

which, except for markers in heavily 

developed urban areas, must be in letters at least 1 inch (25 millimeters) 

high with an approximate stroke of 1⁄4

inch (6.4 millimeters). 

(ii) The name of the operator and a 

telephone number (including area code) 

where the operator can be reached at 

all times. 

(b) Line markers are not required for 

buried pipelines located— 

(1) Offshore or at crossings of or 

under waterways and other bodies of 

water; or 

(2) In heavily developed urban areas 

such as downtown business centers 

where— 

(i) The placement of markers is impractical and would not serve the purpose for which markers are intended; 

and 


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§ 195.412 49 CFR Ch. I (10–1–10 Edition) 

(ii) The local government maintains 

current substructure records. 

(c) Each operator shall provide line 

marking at locations where the line is 

above ground in areas that are accessible to the public. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as 

amended by Amdt. 195–27, 48 FR 25208, June 

6, 1983; Amdt. 195–54, 60 FR 14650, Mar. 20, 

1995; Amdt. 195–63, 63 FR 37506, July 13, 1998] 

§ 195.412 Inspection of rights-of-way 

and crossings under navigable waters. 

(a) Each operator shall, at intervals 

not exceeding 3 weeks, but at least 26 

times each calendar year, inspect the 

surface conditions on or adjacent to 

each pipeline right-of-way. Methods of 

inspection include walking, driving, 

flying or other appropriate means of 

traversing the right-of-way. 

(b) Except for offshore pipelines, each 

operator shall, at intervals not exceeding 5 years, inspect each crossing under 

a navigable waterway to determine the 

condition of the crossing. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as 

amended by Amdt. 195–24, 47 FR 46852, Oct. 

21, 1982; Amdt. 195–52, 59 FR 33397, June 28, 

1994] 

§ 195.413 Underwater inspection and 

reburial of pipelines in the Gulf of 

Mexico and its inlets. 

(a) Except for gathering lines of 41⁄2

inches (114mm) nominal outside diameter or smaller, each operator shall prepare and follow a procedure to identify 

its pipelines in the Gulf of Mexico and 

its inlets in waters less than 15 feet (4.6 

meters) deep as measured from mean 

low water that are at risk of being an 

exposed underwater pipeline or a hazard to navigation. The procedures must 

be in effect August 10, 2005. 

(b) Each operator shall conduct appropriate periodic underwater inspections of its pipelines in the Gulf of 

Mexico and its inlets in waters less 

than 15 feet (4.6 meters) deep as measured from mean low water based on the 

identified risk. 

(c) If an operator discovers that its 

pipeline is an exposed underwater pipeline or poses a hazard to navigation, 

the operator shall— 

(1) Promptly, but not later than 24 

hours after discovery, notify the National Response Center, telephone: 1– 

800–424–8802, of the location and, if 

available, the geographic coordinates 

of that pipeline. 

(2) Promptly, but not later than 7 

days after discovery, mark the location 

of the pipeline in accordance with 33 

CFR Part 64 at the ends of the pipeline 

segment and at intervals of not over 

500 yards (457 meters) long, except that 

a pipeline segment less than 200 yards 

(183 meters) long need only be marked 

at the center; and 

(3) Within 6 months after discovery, 

or not later than November 1 of the following year if the 6 month period is 

later than November 1 of the year of 

discovery, bury the pipeline so that the 

top of the pipe is 36 inches (914 millimeters) below the underwater natural 

bottom (as determined by recognized 

and generally accepted practices) for 

normal excavation or 18 inches (457 

millimeters) for rock excavation. 

(i) An operator may employ engineered alternatives to burial that meet 

or exceed the level of protection provided by burial. 

(ii) If an operator cannot obtain required state or Federal permits in time 

to comply with this section, it must 

notify OPS; specify whether the required permit is State or Federal; and, 

justify the delay. 

[Amdt. 195–82, 69 FR 48407, Aug. 10, 2004] 

§§ 195.414–195.418 [Reserved] 

§ 195.420 Valve maintenance. 

(a) Each operator shall maintain 

each valve that is necessary for the 

safe operation of its pipeline systems 

in good working order at all times. 

(b) Each operator shall, at intervals 

not exceeding 71⁄2 months, but at least 

twice each calendar year, inspect each 

mainline valve to determine that it is 

functioning properly. 

(c) Each operator shall provide protection for each valve from unauthorized operation and from vandalism. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981; 47 

FR 32721, July 29, 1982, as amended by Amdt. 

195–24, 47 FR 46852, Oct. 21, 1982] 

§ 195.422 Pipeline repairs. 

(a) Each operator shall, in repairing 

its pipeline systems, insure that the repairs are made in a safe manner and 


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Pipeline and Hazardous Materials Safety Administration, DOT § 195.428 

are made so as to prevent damage to 

persons or property. 

(b) No operator may use any pipe, 

valve, or fitting, for replacement in repairing pipeline facilities, unless it is 

designed and constructed as required 

by this part. 

§ 195.424 Pipe movement. 

(a) No operator may move any line 

pipe, unless the pressure in the line 

section involved is reduced to not more 

than 50 percent of the maximum operating pressure. 

(b) No operator may move any pipeline containing highly volatile liquids 

where materials in the line section involved are joined by welding unless— 

(1) Movement when the pipeline does 

not contain highly volatile liquids is 

impractical; 

(2) The procedures of the operator 

under §195.402 contain precautions to 

protect the public against the hazard 

in moving pipelines containing highly 

volatile liquids, including the use of 

warnings, where necessary, to evacuate 

the area close to the pipeline; and 

(3) The pressure in that line section 

is reduced to the lower of the following: 

(i) Fifty percent or less of the maximum operating pressure; or 

(ii) The lowest practical level that 

will maintain the highly volatile liquid 

in a liquid state with continuous flow, 

but not less than 50 p.s.i. (345 kPa) gage 

above the vapor pressure of the commodity. 

(c) No operator may move any pipeline containing highly volatile liquids 

where materials in the line section involved are not joined by welding unless— 

(1) The operator complies with paragraphs (b) (1) and (2) of this section; 

and 

(2) That line section is isolated to 

prevent the flow of highly volatile liquid. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981; 46 

FR 38922, July 30, 1981, as amended by Amdt. 

195–63, 63 FR 37506, July 13, 1998] 

§ 195.426 Scraper and sphere facilities. 

No operator may use a launcher or 

receiver that is not equipped with a relief device capable of safely relieving 

pressure in the barrel before insertion 

or removal of scrapers or spheres. The 

operator must use a suitable device to 

indicate that pressure has been relieved in the barrel or must provide a 

means to prevent insertion or removal 

of scrapers or spheres if pressure has 

not been relieved in the barrel. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981; 47 

FR 32721, July 29, 1982] 

§ 195.428 Overpressure safety devices 

and overfill protection systems. 

(a) Except as provided in paragraph 

(b) of this section, each operator shall, 

at intervals not exceeding 15 months, 

but at least once each calendar year, or 

in the case of pipelines used to carry 

highly volatile liquids, at intervals not 

to exceed 71⁄2 months, but at least twice 

each calendar year, inspect and test 

each pressure limiting device, relief 

valve, pressure regulator, or other item 

of pressure control equipment to determine that it is functioning properly, is 

in good mechanical condition, and is 

adequate from the standpoint of capacity and reliability of operation for the 

service in which it is used. 

(b) In the case of relief valves on 

pressure breakout tanks containing 

highly volatile liquids, each operator 

shall test each valve at intervals not 

exceeding 5 years. 

(c) Aboveground breakout tanks that 

are constructed or significantly altered 

according to API Standard 2510 after 

October 2, 2000, must have an overfill 

protection system installed according 

to section 5.1.2 of API Standard 2510. 

Other aboveground breakout tanks 

with 600 gallons (2271 liters) or more of 

storage capacity that are constructed 

or significantly altered after October 2, 

2000, must have an overfill protection 

system installed according to API Recommended Practice 2350. However, operators need not comply with any part 

of API Recommended Practice 2350 for 

a particular breakout tank if the operator notes in the manual required by 

§195.402 why compliance with that part 

is not necessary for safety of the tank. 

(d) After October 2, 2000, the requirements of paragraphs (a) and (b) of this 

section for inspection and testing of 

pressure control equipment apply to 


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§ 195.430 49 CFR Ch. I (10–1–10 Edition) 

the inspection and testing of overfill 

protection systems. 

[Amdt. 195–22, 46 FR 38360, July 27, 1981, as 

amended by Amdt. 195–24, 47 FR 46852, Oct. 

21, 1982; Amdt. 195–66, 64 FR 15936, Apr. 2, 

1999] 

§ 195.430 Firefighting equipment. 

Each operator shall maintain adequate firefighting equipment at each 

pump station and breakout tank area. 

The equipment must be— 

(a) In proper operating condition at 

all times; 

(b) Plainly marked so that its identity as firefighting equipment is clear; 

and 

(c) Located so that it is easily accessible during a fire. 

§ 195.432 Inspection of in-service 

breakout tanks. 

(a) Except for breakout tanks inspected under paragraphs (b) and (c) of 

this section, each operator shall, at intervals not exceeding 15 months, but at 

least once each calendar year, inspect 

each in-service breakout tank. 

(b) Each operator must inspect the 

physical integrity of in-service atmospheric and low-pressure steel aboveground breakout tanks according to 

API Standard 653 (incorporated by reference, see §195.3). However, if structural conditions prevent access to the 

tank bottom, the bottom integrity 

may be assessed according to a plan included in the operations and maintenance manual under §195.402(c)(3). 

(c) Each operator shall inspect the 

physical integrity of in-service steel 

aboveground breakout tanks built to 

API Standard 2510 according to section 

6 of API 510. 

(d) The intervals of inspection specified by documents referenced in paragraphs (b) and (c) of this section begin 

on May 3, 1999, or on the operator’s last 

recorded date of the inspection, whichever is earlier. 

[Amdt. 195–66, 64 FR 15936, Apr. 2, 1999, as 

amended by 195–94, 75 FR 48607, Aug. 11, 2010] 

§ 195.434 Signs. 

Each operator must maintain signs 

visible to the public around each pumping station and breakout tank area. 

Each sign must contain the name of 

the operator and a telephone number 

(including area code) where the operator can be reached at all times. 

[Amdt. 195–78, 68 FR 53528, Sept. 11, 2003] 

§ 195.436 Security of facilities. 

Each operator shall provide protection for each pumping station and 

breakout tank area and other exposed 

facility (such as scraper traps) from 

vandalism and unauthorized entry. 

§ 195.438 Smoking or open flames. 

Each operator shall prohibit smoking 

and open flames in each pump station 

area and each breakout tank area 

where there is a possibility of the leakage of a flammable hazardous liquid or 

of the presence of flammable vapors. 

§ 195.440 Public awareness. 

(a) Each pipeline operator must develop and implement a written continuing public education program that 

follows the guidance provided in the 

American Petroleum Institute’s (API) 

Recommended Practice (RP) 1162 (incorporated by reference, see §195.3). 

(b) The operator’s program must follow the general program recommendations of API RP 1162 and assess the 

unique attributes and characteristics 

of the operator’s pipeline and facilities. 

(c) The operator must follow the general program recommendations, including baseline and supplemental requirements of API RP 1162, unless the operator provides justification in its program or procedural manual as to why 

compliance with all or certain provisions of the recommended practice is 

not practicable and not necessary for 

safety. 

(d) The operator’s program must specifically include provisions to educate 

the public, appropriate government organizations, and persons engaged in excavation related activities on: 

(1) Use of a one-call notification system prior to excavation and other damage prevention activities; 

(2) Possible hazards associated with 

unintended releases from a hazardous 

liquid or carbon dioxide pipeline facility; 

(3) Physical indications that such a 

release may have occurred; 


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Pipeline and Hazardous Materials Safety Administration, DOT § 195.442 

(4) Steps that should be taken for 

public safety in the event of a hazardous liquid or carbon dioxide pipeline 

release; and 

(5) Procedures to report such an 

event. 

(e) The program must include activities to advise affected municipalities, 

school districts, businesses, and residents of pipeline facility locations. 

(f) The program and the media used 

must be as comprehensive as necessary 

to reach all areas in which the operator 

transports hazardous liquid or carbon 

dioxide. 

(g) The program must be conducted 

in English and in other languages commonly understood by a significant 

number and concentration of the nonEnglish speaking population in the operator’s area. 

(h) Operators in existence on June 20, 

2005, must have completed their written programs no later than June 20, 

2006. Upon request, operators must submit their completed programs to 

PHMSA or, in the case of an intrastate 

pipeline facility operator, the appropriate State agency. 

(i) The operator’s program documentation and evaluation results must 

be available for periodic review by appropriate regulatory agencies. 

[Amdt. 195–84, 70 FR 28843, May 19, 2005] 

§ 195.442 Damage prevention program. 

(a) Except as provided in paragraph 

(d) of this section, each operator of a 

buried pipeline must carry out, in accordance with this section, a written 

program to prevent damage to that 

pipeline from excavation activities. 

For the purpose of this section, the 

term ‘‘excavation activities’’ includes 

excavation, blasting, boring, tunneling, 

backfilling, the removal of aboveground structures by either explosive 

or mechanical means, and other 

earthmoving operations. 

(b) An operator may comply with any 

of the requirements of paragraph (c) of 

this section through participation in a 

public service program, such as a onecall system, but such participation 

does not relieve the operator of the responsibility for compliance with this 

section. However, an operator must 

perform the duties of paragraph (c)(3) 

of this section through participation in 

a one-call system, if that one-call system is a qualified one-call system. In 

areas that are covered by more than 

one qualified one-call system, an operator need only join one of the qualified 

one-call systems if there is a central 

telephone number for excavators to 

call for excavation activities, or if the 

one-call systems in those areas communicate with one another. An operator’s pipeline system must be covered 

by a qualified one-call system where 

there is one in place. For the purpose 

of this section, a one-call system is 

considered a ‘‘qualified one-call system’’ if it meets the requirements of 

section (b)(1) or (b)(2) or this section. 

(1) The state has adopted a one-call 

damage prevention program under 

§198.37 of this chapter; or 

(2) The one-call system: 

(i) Is operated in accordance with 

§198.39 of this chapter; 

(ii) Provides a pipeline operator an 

opportunity similar to a voluntary participant to have a part in management 

responsibilities; and 

(iii) Assesses a participating pipeline 

operator a fee that is proportionate to 

the costs of the one-call system’s coverage of the operator’s pipeline. 

(c) The damage prevention program 

required by paragraph (a) of this section must, at a minimum: 

(1) Include the identity, on a current 

basis, of persons who normally engage 

in excavation activities in the area in 

which the pipeline is located. 

(2) Provides for notification of the 

public in the vicinity of the pipeline 

and actual notification of persons identified in paragraph (c)(1) of this section 

of the following as often as needed to 

make them aware of the damage prevention program: 

(i) The program’s existence and purpose; and 

(ii) How to learn the location of underground pipelines before excavation 

activities are begun. 

(3) Provide a means of receiving and 

recording notification of planned excavation activities. 

(4) If the operator has buried pipelines in the area of excavation activity, 

provide for actual notification of persons who give notice of their intent to 

excavate of the type of temporary 


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§ 195.444 49 CFR Ch. I (10–1–10 Edition) 

marking to be provided and how to 

identify the markings. 

(5) Provide for temporary marking of 

buried pipelines in the area of excavation activity before, as far as practical, the activity begins. 

(6) Provide as follows for inspection 

of pipelines that an operator has reason to believe could be damaged by excavation activities: 

(i) The inspection must be done as 

frequently as necessary during and 

after the activities to verify the integrity of the pipeline; and 

(ii) In the case of blasting, any inspection must include leakage surveys. 

(d) A damage prevention program 

under this section is not required for 

the following pipelines: 

(1) Pipelines located offshore. 

(2) Pipelines to which access is physically controlled by the operator. 

[Amdt. 195–54, 60 FR 14651, Mar. 20, 1995, as 

amended by Amdt. 195–60, 62 FR 61699, Nov. 

19, 1997] 

§ 195.444 CPM leak detection. 

Each computational pipeline monitoring (CPM) leak detection system installed on a hazardous liquid pipeline 

transporting liquid in single phase 

(without gas in the liquid) must comply with API 1130 in operating, maintaining, testing, record keeping, and 

dispatcher training of the system. 

[Amdt. 195–62, 63 FR 36376, July 6, 1998] 

§ 195.446 Control room management. 

(a) General. This section applies to 

each operator of a pipeline facility 

with a controller working in a control 

room who monitors and controls all or 

part of a pipeline facility through a 

SCADA system. Each operator must 

have and follow written control room 

management procedures that implement the requirements of this section. 

The procedures required by this section 

must be integrated, as appropriate, 

with the operator’s written procedures 

required by §195.402. An operator must 

develop the procedures no later than 

August 1, 2011 and implement the procedures no later than February 1, 2013. 

(b) Roles and responsibilities. Each operator must define the roles and responsibilities of a controller during 

normal, abnormal, and emergency operating conditions. To provide for a 

controller’s prompt and appropriate response to operating conditions, an operator must define each of the following: 

(1) A controller’s authority and responsibility to make decisions and 

take actions during normal operations; 

(2) A controller’s role when an abnormal operating condition is detected, 

even if the controller is not the first to 

detect the condition, including the controller’s responsibility to take specific 

actions and to communicate with others; 

(3) A controller’s role during an 

emergency, even if the controller is not 

the first to detect the emergency, including the controller’s responsibility 

to take specific actions and to communicate with others; and 

(4) A method of recording controller 

shift-changes and any hand-over of responsibility between controllers. 

(c) Provide adequate information. Each 

operator must provide its controllers 

with the information, tools, processes 

and procedures necessary for the controllers to carry out the roles and responsibilities the operator has defined 

by performing each of the following: 

(1) Implement API RP 1165 (incorporated by reference, see §195.3) whenever a SCADA system is added, expanded or replaced, unless the operator 

demonstrates that certain provisions of 

API RP 1165 are not practical for the 

SCADA system used; 

(2) Conduct a point-to-point 

verification between SCADA displays 

and related field equipment when field 

equipment is added or moved and when 

other changes that affect pipeline safety are made to field equipment or 

SCADA displays; 

(3) Test and verify an internal communication plan to provide adequate 

means for manual operation of the 

pipeline safely, at least once each calendar year, but at intervals not to exceed 15 months; 

(4) Test any backup SCADA systems 

at least once each calendar year, but at 

intervals not to exceed 15 months; and 

(5) Implement section 5 of API RP 

1168 (incorporated by reference, see 

§195.3) to establish procedures for when 


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Pipeline and Hazardous Materials Safety Administration, DOT § 195.446 

a different controller assumes responsibility, including the content of information to be exchanged. 

(d) Fatigue mitigation. Each operator 

must implement the following methods 

to reduce the risk associated with controller fatigue that could inhibit a controller’s ability to carry out the roles 

and responsibilities the operator has 

defined: 

(1) Establish shift lengths and schedule rotations that provide controllers 

off-duty time sufficient to achieve 

eight hours of continuous sleep; 

(2) Educate controllers and supervisors in fatigue mitigation strategies 

and how off-duty activities contribute 

to fatigue; 

(3) Train controllers and supervisors 

to recognize the effects of fatigue; and 

(4) Establish a maximum limit on 

controller hours-of-service, which may 

provide for an emergency deviation 

from the maximum limit if necessary 

for the safe operation of a pipeline facility. 

(e) Alarm management. Each operator 

using a SCADA system must have a 

written alarm management plan to 

provide for effective controller response to alarms. An operator’s plan 

must include provisions to: 

(1) Review SCADA safety-related 

alarm operations using a process that 

ensures alarms are accurate and support safe pipeline operations; 

(2) Identify at least once each calendar month points affecting safety 

that have been taken off scan in the 

SCADA host, have had alarms inhibited, generated false alarms, or that 

have had forced or manual values for 

periods of time exceeding that required 

for associated maintenance or operating activities; 

(3) Verify the correct safety-related 

alarm set-point values and alarm descriptions when associated field instruments are calibrated or changed and at 

least once each calendar year, but at 

intervals not to exceed 15 months; 

(4) Review the alarm management 

plan required by this paragraph at 

least once each calendar year, but at 

intervals not exceeding 15 months, to 

determine the effectiveness of the plan; 

(5) Monitor the content and volume 

of general activity being directed to 

and required of each controller at least 

once each calendar year, but at intervals not exceeding 15 months, that will 

assure controllers have sufficient time 

to analyze and react to incoming 

alarms; and 

(6) Address deficiencies identified 

through the implementation of paragraphs (e)(1) through (e)(5) of this section. 

(f) Change management. Each operator 

must assure that changes that could 

affect control room operations are coordinated with the control room personnel by performing each of the following: 

(1) Implement section 7 of API RP 

1168 (incorporated by reference, see 

§195.3) for control room management 

change and require coordination between control room representatives, 

operator’s management, and associated 

field personnel when planning and implementing physical changes to pipeline equipment or configuration; and 

(2) Require its field personnel to contact the control room when emergency 

conditions exist and when making field 

changes that affect control room operations. 

(g) Operating experience. Each operator must assure that lessons learned 

from its operating experience are incorporated, as appropriate, into its 

control room management procedures 

by performing each of the following: 

(1) Review accidents that must be reported pursuant to §195.50 and 195.52 to 

determine if control room actions contributed to the event and, if so, correct, where necessary, deficiencies related to: 

(i) Controller fatigue; 

(ii) Field equipment; 

(iii) The operation of any relief device; 

(iv) Procedures; 

(v) SCADA system configuration; and 

(vi) SCADA system performance. 

(2) Include lessons learned from the 

operator’s experience in the training 

program required by this section. 

(h) Training. Each operator must establish a controller training program 

and review the training program content to identify potential improvements at least once each calendar year, 

but at intervals not to exceed 15 

months. An operator’s program must 

provide for training each controller to 


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§ 195.450 49 CFR Ch. I (10–1–10 Edition) 

carry out the roles and responsibilities 

defined by the operator. In addition, 

the training program must include the 

following elements: 

(1) Responding to abnormal operating 

conditions likely to occur simultaneously or in sequence; 

(2) Use of a computerized simulator 

or non-computerized (tabletop) method 

for training controllers to recognize 

abnormal operating conditions; 

(3) Training controllers on their responsibilities for communication under 

the operator’s emergency response procedures; 

(4) Training that will provide a controller a working knowledge of the 

pipeline system, especially during the 

development of abnormal operating 

conditions; and 

(5) For pipeline operating setups that 

are periodically, but infrequently used, 

providing an opportunity for controllers to review relevant procedures in 

advance of their application. 

(i) Compliance validation. Upon request, operators must submit their procedures to PHMSA or, in the case of an 

intrastate pipeline facility regulated 

by a State, to the appropriate State 

agency. 

(j) Compliance and deviations. An operator must maintain for review during 

inspection: 

(1) Records that demonstrate compliance with the requirements of this section; and 

(2) Documentation to demonstrate 

that any deviation from the procedures 

required by this section was necessary 

for the safe operation of the pipeline 

facility. 

[Amdt. 195–93, 74 FR 63329, Dec. 3, 2009, as 

amended at 75 FR 5537, Feb. 3, 2010] 

HIGH CONSEQUENCE AREAS

§ 195.450 Definitions. 

The following definitions apply to 

this section and §195.452: 

Emergency flow restricting device or 

EFRD means a check valve or remote 

control valve as follows: 

(1) Check valve means a valve that 

permits fluid to flow freely in one direction and contains a mechanism to 

automatically prevent flow in the 

other direction. 

(2) Remote control valve or RCV means 

any valve that is operated from a location remote from where the valve is installed. The RCV is usually operated by 

the supervisory control and data acquisition (SCADA) system. The linkage 

between the pipeline control center and 

the RCV may be by fiber optics, microwave, telephone lines, or satellite. 

High consequence area means: 

(1) A commercially navigable waterway, 

which means a waterway where a substantial likelihood of commercial navigation exists; 

(2) A high population area, which 

means an urbanized area, as defined 

and delineated by the Census Bureau, 

that contains 50,000 or more people and 

has a population density of at least 

1,000 people per square mile; 

(3) An other populated area, which 

means a place, as defined and delineated by the Census Bureau, that contains a concentrated population, such 

as an incorporated or unincorporated 

city, town, village, or other designated 

residential or commercial area; 

(4) An unusually sensitive area, as defined in §195.6. 

[Amdt. 195–70, 65 FR 75405, Dec. 1, 2000] 

PIPELINE INTEGRITY MANAGEMENT

§ 195.452 Pipeline integrity management in high consequence areas. 

(a) Which pipelines are covered by this 

section? This section applies to each 

hazardous liquid pipeline and carbon 

dioxide pipeline that could affect a 

high consequence area, including any 

pipeline located in a high consequence 

area unless the operator effectively 

demonstrates by risk assessment that 

the pipeline could not affect the area. 

(Appendix C of this part provides guidance on determining if a pipeline could 

affect a high consequence area.) Covered pipelines are categorized as follows: 

(1) Category 1 includes pipelines existing on May 29, 2001, that were owned 

or operated by an operator who owned 

or operated a total of 500 or more miles 

of pipeline subject to this part. 

(2) Category 2 includes pipelines existing on May 29, 2001, that were owned 

or operated by an operator who owned 

or operated less than 500 miles of pipeline subject to this part. 


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Pipeline and Hazardous Materials Safety Administration, DOT § 195.452 

(3) Category 3 includes pipelines constructed or converted after May 29, 

2001. 

(b) What program and practices must 

operators use to manage pipeline integrity? Each operator of a pipeline covered by this section must: 

(1) Develop a written integrity management program that addresses the 

risks on each segment of pipeline in 

the first column of the following table 

not later than the date in the second 

column: 

Pipeline Date 

Category 1 ............................. March 31, 2002. 

Category 2 ............................. February 18, 2003. 

Category 3 ............................. 1 year after the date the 

pipeline begins operation. 

(2) Include in the program an identification of each pipeline or pipeline 

segment in the first column of the following table not later than the date in 

the second column: 

Pipeline Date 

Category 1 ............................. December 31, 2001. 

Category 2 ............................. November 18, 2002. 

Category 3 ............................. Date the pipeline begins operation. 

(3) Include in the program a plan to 

carry out baseline assessments of line 

pipe as required by paragraph (c) of 

this section. 

(4) Include in the program a framework that— 

(i) Addresses each element of the integrity management program under 

paragraph (f) of this section, including 

continual integrity assessment and 

evaluation under paragraph (j) of this 

section; and 

(ii) Initially indicates how decisions 

will be made to implement each element. 

(5) Implement and follow the program. 

(6) Follow recognized industry practices in carrying out this section, unless— 

(i) This section specifies otherwise; 

or 

(ii) The operator demonstrates that 

an alternative practice is supported by 

a reliable engineering evaluation and 

provides an equivalent level of public 

safety and environmental protection. 

(c) What must be in the baseline assessment plan? (1) An operator must include 

each of the following elements in its 

written baseline assessment plan: 

(i) The methods selected to assess the 

integrity of the line pipe. An operator 

must assess the integrity of the line 

pipe by any of the following methods. 

The methods an operator selects to assess low frequency electric resistance 

welded pipe or lap welded pipe susceptible to longitudinal seam failure must 

be capable of assessing seam integrity 

and of detecting corrosion and deformation anomalies. 

(A) Internal inspection tool or tools 

capable of detecting corrosion and deformation anomalies including dents, 

gouges and grooves; 

(B) Pressure test conducted in accordance with subpart E of this part; 

(C) External corrosion direct assessment in accordance with §195.588; or 

(D) Other technology that the operator demonstrates can provide an 

equivalent understanding of the condition of the line pipe. An operator 

choosing this option must notify the 

Office of Pipeline Safety (OPS) 90 days 

before conducting the assessment, by 

sending a notice to the address or facsimile number specified in paragraph 

(m) of this section. 

(ii) A schedule for completing the integrity assessment; 

(iii) An explanation of the assessment methods selected and evaluation 

of risk factors considered in establishing the assessment schedule. 

(2) An operator must document, prior 

to implementing any changes to the 

plan, any modification to the plan, and 

reasons for the modification. 

(d) When must operators complete baseline assessments? Operators must complete baseline assessments as follows: 

(1) Time periods. Complete assessments before the following deadlines: 

If the pipeline is: 

Then complete baseline assessments not 

later than the following date according to a 

schedule that prioritizes assessments: 

And assess at least 50 percent of the line 

pipe on an expedited basis, beginning with 

the highest risk pipe, not later than: 

Category 1 ................................ March 31, 2008 ................................................ September 30, 2004. 

Category 2 ................................ February 17, 2009 ........................................... August 16, 2005. 


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§ 195.452 49 CFR Ch. I (10–1–10 Edition) 

If the pipeline is: 

Then complete baseline assessments not 

later than the following date according to a 

schedule that prioritizes assessments: 

And assess at least 50 percent of the line 

pipe on an expedited basis, beginning with 

the highest risk pipe, not later than: 

Category 3 ................................ Date the pipeline begins operation .................. Not applicable. 

(2) Prior assessment. To satisfy the requirements of paragraph (c)(1)(i) of this 

section for pipelines in the first column of the following table, operators 

may use integrity assessments conducted after the date in the second column, if the integrity assessment method complies with this section. However, 

if an operator uses this prior assessment as its baseline assessment, the 

operator must reassess the line pipe according to paragraph (j)(3) of this section. The table follows: 

Pipeline Date 

Category 1 ............................. January 1, 1996. 

Category 2 ............................. February 15, 1997. 

(3) Newly-identified areas. (i) When information is available from the information analysis (see paragraph (g) of 

this section), or from Census Bureau 

maps, that the population density 

around a pipeline segment has changed 

so as to fall within the definition in 

§195.450 of a high population area or 

other populated area, the operator 

must incorporate the area into its 

baseline assessment plan as a high consequence area within one year from the 

date the area is identified. An operator 

must complete the baseline assessment 

of any line pipe that could affect the 

newly-identified high consequence area 

within five years from the date the 

area is identified. 

(ii) An operator must incorporate a 

new unusually sensitive area into its 

baseline assessment plan within one 

year from the date the area is identified. An operator must complete the 

baseline assessment of any line pipe 

that could affect the newly-identified 

high consequence area within five 

years from the date the area is identified. 

(e) What are the risk factors for establishing an assessment schedule (for both 

the baseline and continual integrity assessments)? (1) An operator must establish an integrity assessment schedule 

that prioritizes pipeline segments for 

assessment (see paragraphs (d)(1) and 

(j)(3) of this section). An operator must 

base the assessment schedule on all 

risk factors that reflect the risk conditions on the pipeline segment. The factors an operator must consider include, 

but are not limited to: 

(i) Results of the previous integrity 

assessment, defect type and size that 

the assessment method can detect, and 

defect growth rate; 

(ii) Pipe size, material, manufacturing information, coating type and 

condition, and seam type; 

(iii) Leak history, repair history and 

cathodic protection history; 

(iv) Product transported; 

(v) Operating stress level; 

(vi) Existing or projected activities 

in the area; 

(vii) Local environmental factors 

that could affect the pipeline (e.g., 

corrosivity of soil, subsidence, climatic); 

(viii) geo-technical hazards; and 

(ix) Physical support of the segment 

such as by a cable suspension bridge. 

(2) Appendix C of this part provides 

further guidance on risk factors. 

(f) What are the elements of an integrity 

management program? An integrity 

management program begins with the 

initial framework. An operator must 

continually change the program to reflect operating experience, conclusions 

drawn from results of the integrity assessments, and other maintenance and 

surveillance data, and evaluation of 

consequences of a failure on the high 

consequence area. An operator must include, at minimum, each of the following elements in its written integrity management program: 

(1) A process for identifying which 

pipeline segments could affect a high 

consequence area; 

(2) A baseline assessment plan meeting the requirements of paragraph (c) 

of this section; 

(3) An analysis that integrates all 

available information about the integrity of the entire pipeline and the consequences of a failure (see paragraph 

(g) of this section); 


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Pipeline and Hazardous Materials Safety Administration, DOT § 195.452 

(4) Criteria for remedial actions to 

address integrity issues raised by the 

assessment methods and information 

analysis (see paragraph (h) of this section); 

(5) A continual process of assessment 

and evaluation to maintain a pipeline’s 

integrity (see paragraph (j) of this section); 

(6) Identification of preventive and 

mitigative measures to protect the 

high consequence area (see paragraph 

(i) of this section); 

(7) Methods to measure the program’s 

effectiveness (see paragraph (k) of this 

section); 

(8) A process for review of integrity 

assessment results and information 

analysis by a person qualified to evaluate the results and information (see 

paragraph (h)(2) of this section). 

(g) What is an information analysis? In 

periodically evaluating the integrity of 

each pipeline segment (paragraph (j) of 

this section), an operator must analyze 

all available information about the integrity of the entire pipeline and the 

consequences of a failure. This information includes: 

(1) Information critical to determining the potential for, and preventing, damage due to excavation, including current and planned damage 

prevention activities, and development 

or planned development along the pipeline segment; 

(2) Data gathered through the integrity assessment required under this 

section; 

(3) Data gathered in conjunction with 

other inspections, tests, surveillance 

and patrols required by this Part, including, corrosion control monitoring 

and cathodic protection surveys; and 

(4) Information about how a failure 

would affect the high consequence 

area, such as location of the water intake. 

(h) What actions must an operator take 

to address integrity issues?—(1) General 

requirements. An operator must take 

prompt action to address all anomalous 

conditions the operator discovers 

through the integrity assessment or information analysis. In addressing all 

conditions, an operator must evaluate 

all anomalous conditions and remediate those that could reduce a pipeline’s integrity. An operator must be 

able to demonstrate that the remediation of the condition will ensure the 

condition is unlikely to pose a threat 

to the long-term integrity of the pipeline. An operator must comply with 

§195.422 when making a repair. 

(i) Temporary pressure reduction. An 

operator must notify PHMSA, in accordance with paragraph (m) of this 

section, if the operator cannot meet 

the schedule for evaluation and remediation required under paragraph (h)(3) 

of this section and cannot provide safety through a temporary reduction in 

operating pressure. 

(ii) Long-term pressure reduction. When 

a pressure reduction exceeds 365 days, 

the operator must notify PHMSA in accordance with paragraph (m) of this 

section and explain the reasons for the 

delay. An operator must also take further remedial action to ensure the safety of the pipeline. 

(2) Discovery of condition. Discovery of 

a condition occurs when an operator 

has adequate information about the 

condition to determine that the condition presents a potential threat to the 

integrity of the pipeline. An operator 

must promptly, but no later than 180 

days after an integrity assessment, obtain sufficient information about a 

condition to make that determination, 

unless the operator can demonstrate 

that the 180-day period is impracticable. 

(3) Schedule for evaluation and remediation. An operator must complete remediation of a condition according to a 

schedule prioritizing the conditions for 

evaluation and remediation. If an operator cannot meet the schedule for any 

condition, the operator must explain 

the reasons why it cannot meet the 

schedule and how the changed schedule 

will not jeopardize public safety or environmental protection. 

(4) Special requirements for scheduling 

remediation— (i) Immediate repair conditions. An operator’s evaluation and remediation schedule must provide for 

immediate repair conditions. To maintain safety, an operator must temporarily reduce operating pressure or 

shut down the pipeline until the operator completes the repair of these conditions. An operator must calculate the 

temporary reduction in operating pressure using the formula in Section 


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§ 195.452 49 CFR Ch. I (10–1–10 Edition) 

451.6.2.2 (b) of ANSI/ASME B31.4 (incorporated by reference, see §195.3). An operator must treat the following conditions as immediate repair conditions: 

(A) Metal loss greater than 80% of 

nominal wall regardless of dimensions. 

(B) A calculation of the remaining 

strength of the pipe shows a predicted 

burst pressure less than the established 

maximum operating pressure at the location of the anomaly. Suitable remaining strength calculation methods 

include, but are not limited to, ASME/ 

ANSI B31G (‘‘Manual for Determining 

the Remaining Strength of Corroded 

Pipelines’’ (1991) or AGA Pipeline Research Committee Project PR–3–805 

(‘‘A Modified Criterion for Evaluating 

the Remaining Strength of Corroded 

Pipe’’ (December 1989)). These documents are incorporated by reference 

and are available at the addresses listed in §195.3. 

(C) A dent located on the top of the 

pipeline (above the 4 and 8 o’clock positions) that has any indication of metal 

loss, cracking or a stress riser. 

(D) A dent located on the top of the 

pipeline (above the 4 and 8 o’clock positions) with a depth greater than 6% of 

the nominal pipe diameter. 

(E) An anomaly that in the judgment 

of the person designated by the operator to evaluate the assessment results 

requires immediate action. 

(ii) 60-day conditions. Except for conditions listed in paragraph (h)(4)(i) of 

this section, an operator must schedule 

evaluation and remediation of the following conditions within 60 days of discovery of condition. 

(A) A dent located on the top of the 

pipeline (above the 4 and 8 o’clock positions) with a depth greater than 3% of 

the pipeline diameter (greater than 

0.250 inches in depth for a pipeline diameter less than Nominal Pipe Size 

(NPS) 12). 

(B) A dent located on the bottom of 

the pipeline that has any indication of 

metal loss, cracking or a stress riser. 

(iii) 180-day conditions. Except for 

conditions listed in paragraph (h)(4)(i) 

or (ii) of this section, an operator must 

schedule evaluation and remediation of 

the following within 180 days of discovery of the condition: 

(A) A dent with a depth greater than 

2% of the pipeline’s diameter (0.250 

inches in depth for a pipeline diameter 

less than NPS 12) that affects pipe curvature at a girth weld or a longitudinal 

seam weld. 

(B) A dent located on the top of the 

pipeline (above 4 and 8 o’clock position) with a depth greater than 2% of 

the pipeline’s diameter (0.250 inches in 

depth for a pipeline diameter less than 

NPS 12). 

(C) A dent located on the bottom of 

the pipeline with a depth greater than 

6% of the pipeline’s diameter. 

(D) A calculation of the remaining 

strength of the pipe shows an operating 

pressure that is less than the current 

established maximum operating pressure at the location of the anomaly. 

Suitable remaining strength calculation methods include, but are not limited to, ASME/ANSI B31G (‘‘Manual for 

Determining the Remaining Strength 

of Corroded Pipelines’’ (1991)) or AGA 

Pipeline Research Committee Project 

PR–3–805 (‘‘A Modified Criterion for 

Evaluating the Remaining Strength of 

Corroded Pipe’’ (December 1989)). These 

documents are incorporated by reference and are available at the addresses listed in §195.3. 

(E) An area of general corrosion with 

a predicted metal loss greater than 50% 

of nominal wall. 

(F) Predicted metal loss greater than 

50% of nominal wall that is located at 

a crossing of another pipeline, or is in 

an area with widespread circumferential corrosion, or is in an area that 

could affect a girth weld. 

(G) A potential crack indication that 

when excavated is determined to be a 

crack. 

(H) Corrosion of or along a longitudinal seam weld. 

(I) A gouge or groove greater than 

12.5% of nominal wall. 

(iv) Other conditions. In addition to 

the conditions listed in paragraphs 

(h)(4)(i) through (iii) of this section, an 

operator must evaluate any condition 

identified by an integrity assessment 

or information analysis that could impair the integrity of the pipeline, and 

as appropriate, schedule the condition 

for remediation. Appendix C of this 

part contains guidance concerning 

other conditions that an operator 

should evaluate. 


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Pipeline and Hazardous Materials Safety Administration, DOT § 195.452 

(i) What preventive and mitigative 

measures must an operator take to protect 

the high consequence area?—(1) General 

requirements. An operator must take 

measures to prevent and mitigate the 

consequences of a pipeline failure that 

could affect a high consequence area. 

These measures include conducting a 

risk analysis of the pipeline segment to 

identify additional actions to enhance 

public safety or environmental protection. Such actions may include, but are 

not limited to, implementing damage 

prevention best practices, better monitoring of cathodic protection where 

corrosion is a concern, establishing 

shorter inspection intervals, installing 

EFRDs on the pipeline segment, modifying the systems that monitor pressure and detect leaks, providing additional training to personnel on response procedures, conducting drills 

with local emergency responders and 

adopting other management controls. 

(2) Risk analysis criteria. In identifying the need for additional preventive and mitigative measures, an operator must evaluate the likelihood of a 

pipeline release occurring and how a 

release could affect the high consequence area. This determination 

must consider all relevant risk factors, 

including, but not limited to: 

(i) Terrain surrounding the pipeline 

segment, including drainage systems 

such as small streams and other smaller waterways that could act as a conduit to the high consequence area; 

(ii) Elevation profile; 

(iii) Characteristics of the product 

transported; 

(iv) Amount of product that could be 

released; 

(v) Possibility of a spillage in a farm 

field following the drain tile into a waterway; 

(vi) Ditches along side a roadway the 

pipeline crosses; 

(vii) Physical support of the pipeline 

segment such as by a cable suspension 

bridge; 

(viii) Exposure of the pipeline to operating pressure exceeding established 

maximum operating pressure. 

(3) Leak detection. An operator must 

have a means to detect leaks on its 

pipeline system. An operator must 

evaluate the capability of its leak detection means and modify, as necessary, to protect the high consequence 

area. An operator’s evaluation must, at 

least, consider, the following factors— 

length and size of the pipeline, type of 

product carried, the pipeline’s proximity to the high consequence area, 

the swiftness of leak detection, location of nearest response personnel, leak 

history, and risk assessment results. 

(4) Emergency Flow Restricting Devices 

(EFRD). If an operator determines that 

an EFRD is needed on a pipeline segment to protect a high consequence 

area in the event of a hazardous liquid 

pipeline release, an operator must install the EFRD. In making this determination, an operator must, at least, 

consider the following factors—the 

swiftness of leak detection and pipeline 

shutdown capabilities, the type of commodity carried, the rate of potential 

leakage, the volume that can be released, topography or pipeline profile, 

the potential for ignition, proximity to 

power sources, location of nearest response personnel, specific terrain between the pipeline segment and the 

high consequence area, and benefits expected by reducing the spill size. 

(j) What is a continual process of evaluation and assessment to maintain a pipeline’s integrity?—(1) General. After completing the baseline integrity assessment, an operator must continue to assess the line pipe at specified intervals 

and periodically evaluate the integrity 

of each pipeline segment that could affect a high consequence area. 

(2) Evaluation. An operator must conduct a periodic evaluation as frequently as needed to assure pipeline integrity. An operator must base the frequency of evaluation on risk factors 

specific to its pipeline, including the 

factors specified in paragraph (e) of 

this section. The evaluation must consider the results of the baseline and 

periodic integrity assessments, information analysis (paragraph (g) of this 

section), and decisions about remediation, and preventive and mitigative 

actions (paragraphs (h) and (i) of this 

section). 

(3) Assessment intervals. An operator 

must establish five-year intervals, not 

to exceed 68 months, for continually 

assessing the line pipe’s integrity. An 

operator must base the assessment intervals on the risk the line pipe poses 


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§ 195.452 49 CFR Ch. I (10–1–10 Edition) 

to the high consequence area to determine the priority for assessing the 

pipeline segments. An operator must 

establish the assessment intervals 

based on the factors specified in paragraph (e) of this section, the analysis of 

the results from the last integrity assessment, and the information analysis 

required by paragraph (g) of this section. 

(4) Variance from the 5-year intervals in 

limited situations—(i) Engineering basis. 

An operator may be able to justify an 

engineering basis for a longer assessment interval on a segment of line 

pipe. The justification must be supported by a reliable engineering evaluation combined with the use of other 

technology, such as external monitoring technology, that provides an understanding of the condition of the line 

pipe equivalent to that which can be 

obtained from the assessment methods 

allowed in paragraph (j)(5) of this section. An operator must notify OPS 270 

days before the end of the five-year (or 

less) interval of the justification for a 

longer interval, and propose an alternative interval. An operator must send 

the notice to the address specified in 

paragraph (m) of this section. 

(ii) Unavailable technology. An operator may require a longer assessment 

period for a segment of line pipe (for 

example, because sophisticated internal inspection technology is not available). An operator must justify the reasons why it cannot comply with the required assessment period and must also 

demonstrate the actions it is taking to 

evaluate the integrity of the pipeline 

segment in the interim. An operator 

must notify OPS 180 days before the 

end of the five-year (or less) interval 

that the operator may require a longer 

assessment interval, and provide an estimate of when the assessment can be 

completed. An operator must send a 

notice to the address specified in paragraph (m) of this section. 

(5) Assessment methods. An operator 

must assess the integrity of the line 

pipe by any of the following methods. 

The methods an operator selects to assess low frequency electric resistance 

welded pipe or lap welded pipe susceptible to longitudinal seam failure must 

be capable of assessing seam integrity 

and of detecting corrosion and deformation anomalies. 

(i) Internal inspection tool or tools 

capable of detecting corrosion and deformation anomalies including dents, 

gouges and grooves; 

(ii) Pressure test conducted in accordance with subpart E of this part; 

(iii) External corrosion direct assessment in accordance with §195.588; or 

(iv) Other technology that the operator demonstrates can provide an 

equivalent understanding of the condition of the line pipe. An operator 

choosing this option must notify OPS 

90 days before conducting the assessment, by sending a notice to the address or facsimile number specified in 

paragraph (m) of this section. 

(k) What methods to measure program 

effectiveness must be used? An operator’s 

program must include methods to 

measure whether the program is effective in assessing and evaluating the integrity of each pipeline segment and in 

protecting the high consequence areas. 

See Appendix C of this part for guidance on methods that can be used to 

evaluate a program’s effectiveness. 

(l) What records must be kept? (1) An 

operator must maintain for review during an inspection: 

(i) A written integrity management 

program in accordance with paragraph 

(b) of this section. 

(ii) Documents to support the decisions and analyses, including any 

modifications, justifications, 

variances, deviations and determinations made, and actions taken, to implement and evaluate each element of 

the integrity management program 

listed in paragraph (f) of this section. 

(2) See Appendix C of this part for examples of records an operator would be 

required to keep. 

(m) How does an operator notify 

PHMSA? An operator must provide any 

notification required by this section 

by: 

(1) Entering the information directly 

on the Integrity Management Database 

Web site at http://primis.phmsa.dot.gov/ 

imdb/; 

(2) Sending the notification to the Information Resources Manager, Office of 


wwoods2 on DSK1DXX6B1PROD with CFR
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Pipeline and Hazardous Materials Safety Administration, DOT § 195.505 

Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue, SE., 

Washington, DC 20590; or 

(3) Sending the notification to the Information Resources Manager by facsimile to (202) 366–7128. 

[Amdt. 195–70, 65 FR 75406, Dec. 1, 2000, as 

amended by Amdt. 195–74, 67 FR 1660, 1661, 

Jan. 14, 2002; Amdt. 195–76, 67 FR 2143, Jan. 

16, 2002; 67 FR 46911, July 17, 2002; 70 FR 11140, 

Mar. 8, 2005; Amdt. 195–85, 70 FR 61576, Oct. 

25, 2005; Amdt. 195–87, 72 FR 39017, July 17, 

2007; 73 FR 16571, Mar. 28, 2008; 73 FR 31646, 

June 3, 2008; Amdt. 195–94, 75 FR 48607, Aug. 

11, 2010] 

Subpart G—Qualification of 

Pipeline Personnel 

SOURCE: Amdt. 195–67, 64 FR 46866, Aug. 27, 

1999, unless otherwise noted. 

§ 195.501 Scope. 

(a) This subpart prescribes the minimum requirements for operator qualification of individuals performing covered tasks on a pipeline facility. 

(b) For the purpose of this subpart, a 

covered task is an activity, identified 

by the operator, that: 

(1) Is performed on a pipeline facility; 

(2) Is an operations or maintenance 

task; 

(3) Is performed as a requirement of 

this part; and 

(4) Affects the operation or integrity 

of the pipeline. 

§ 195.503 Definitions. 

Abnormal operating condition means a 

condition identified by the operator 

that may indicate a malfunction of a 

component or deviation from normal 

operations that may: 

(a) Indicate a condition exceeding design limits; or 

(b) Result in a hazard(s) to persons, 

property, or the environment. 

Evaluation means a process, established and documented by the operator, 

to determine an individual’s ability to 

perform a covered task by any of the 

following: 

(a) Written examination; 

(b) Oral examination; 

(c) Work performance history review; 

(d) Observation during: 

(1) performance on the job, 

(2) on the job training, or 

(3) simulations; 

(e) Other forms of assessment. 

Qualified means that an individual 

has been evaluated and can: 

(a) Perform assigned covered tasks 

and 

(b) Recognize and react to abnormal 

operating conditions. 

[Amdt. 195–67, 64 FR 46866, Aug. 27, 1999, as 

amended by Amdt. 195–72, 66 FR 43524, Aug. 

20, 2001] 

§ 195.505 Qualification program. 

Each operator shall have and follow a 

written qualification program. The 

program shall include provisions to: 

(a) Identify covered tasks; 

(b) Ensure through evaluation that 

individuals performing covered tasks 

are qualified; 

(c) Allow individuals that are not 

qualified pursuant to this subpart to 

perform a covered task if directed and 

observed by an individual that is qualified; 

(d) Evaluate an individual if the operator has reason to believe that the individual’s performance of a covered 

task contributed to an accident as defined in Part 195; 

(e) Evaluate an individual if the operator has reason to believe that the individual is no longer qualified to perform a covered task; 

(f) Communicate changes that affect 

covered tasks to individuals performing those covered tasks; 

(g) Identify those covered tasks and 

the intervals at which evaluation of 

the individual’s qualifications is needed; 

(h) After December 16, 2004, provide 

training, as appropriate, to ensure that 

individuals performing covered tasks 

have the necessary knowledge and 

skills to perform the tasks in a manner 

that ensures the safe operation of pipeline facilities; and 

(i) After December 16, 2004, notify the 

Administrator or a state agency participating under 49 U.S.C. Chapter 601 

if the operator significantly modifies 

the program after the Administrator or 

state agency has verified that it complies with this section. 

[Amdt. 195–67, 64 FR 46866, Aug. 27, 1999, as 

amended by Amdt. 195–84, 70 FR 10336, Mar. 3, 

2005] 


wwoods2 on DSK1DXX6B1PROD with CFR
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§ 195.507 49 CFR Ch. I (10–1–10 Edition) 

§ 195.507 Recordkeeping. 

Each operator shall maintain records 

that demonstrate compliance with this 

subpart. 

(a) Qualification records shall include: 

(1) Identification of qualified individual(s); 

(2) Identification of the covered tasks 

the individual is qualified to perform; 

(3) Date(s) of current qualification; 

and 

(4) Qualification method(s). 

(b) Records supporting an individual’s current qualification shall be 

maintained while the individual is performing the covered task. Records of 

prior qualification and records of individuals no longer performing covered 

tasks shall be retained for a period of 

five years. 

§ 195.509 General. 

(a) Operators must have a written 

qualification program by April 27, 2001. 

The program must be available for review by the Administrator or by a 

state agency participating under 49 

U.S.C. Chapter 601 if the program is 

under the authority of that state agency. 

(b) Operators must complete the 

qualification of individuals performing 

covered tasks by October 28, 2002. 

(c) Work performance history review 

may be used as a sole evaluation method for individuals who were performing 

a covered task prior to October 26, 1999. 

(d) After October 28, 2002, work performance history may not be used as a 

sole evaluation method. 

(e) After December 16, 2004, observation of on-the-job performance may not 

be used as the sole method of evaluation. 

[Amdt. 195–67, 64 FR 46866, Aug. 27, 1999, as 

amended by Amdt. 195–72, 66 FR 43524, Aug. 

20, 2001; Amdt. 195–84, 70 FR 10336, Mar. 3, 

2005] 

Subpart H—Corrosion Control 

SOURCE: Amdt. 195–73, 66 FR 67004, Dec. 27, 

2001, unless otherwise noted. 

§ 195.551 What do the regulations in 

this subpart cover? 

This subpart prescribes minimum requirements for protecting steel pipelines against corrosion. 

§ 195.553 What special definitions 

apply to this subpart? 

As used in this subpart— 

Active corrosion means continuing 

corrosion which, unless controlled, 

could result in a condition that is detrimental to public safety or the environment. 

Buried means covered or in contact 

with soil. 

Direct assessment means an integrity 

assessment method that utilizes a 

process to evaluate certain threats 

(i.e., external corrosion, internal corrosion and stress corrosion cracking) to a 

pipeline segment’s integrity. The process includes the gathering and integration of risk factor data, indirect examination or analysis to identify areas of 

suspected corrosion, direct examination of the pipeline in these areas, and 

post assessment evaluation. 

Electrical survey means a series of 

closely spaced pipe-to-soil readings 

over a pipeline that are subsequently 

analyzed to identify locations where a 

corrosive current is leaving the pipeline. 

External corrosion direct assessment 

(ECDA) means a four-step process that 

combines pre-assessment, indirect inspection, direct examination, and postassessment to evaluate the threat of 

external corrosion to the integrity of a 

pipeline. 

Pipeline environment includes soil resistivity (high or low), soil moisture 

(wet or dry), soil contaminants that 

may promote corrosive activity, and 

other known conditions that could affect the probability of active corrosion. 

You means operator. 

[Amdt. 195–73, 66 FR 67004, Dec. 27, 2001, as 

amended by Amdt. 195–85, 70 FR 61576, Oct. 

25, 2005] 

§ 195.555 What are the qualifications 

for supervisors? 

You must require and verify that supervisors maintain a thorough knowledge of that portion of the corrosion 

control procedures established under 


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Pipeline and Hazardous Materials Safety Administration, DOT § 195.565 

1 A pipeline does not have an effective external coating material if the current required to cathodically protect the pipeline is 

substantially the same as if the pipeline 

were bare. 

§195.402(c)(3) for which they are responsible for insuring compliance. 

§ 195.557 Which pipelines must have 

coating for external corrosion control? 

Except bottoms of aboveground 

breakout tanks, each buried or submerged pipeline must have an external 

coating for external corrosion control 

if the pipeline is— 

(a) Constructed, relocated, replaced, 

or otherwise changed after the applicable date in §195.401(c), not including 

the movement of pipe covered by 

§195.424; or 

(b) Converted under §195.5 and— 

(1) Has an external coating that substantially meets §195.559 before the 

pipeline is placed in service; or 

(2) Is a segment that is relocated, replaced, or substantially altered. 

§ 195.559 What coating material may I 

use for external corrosion control? 

Coating material for external corrosion control under §195.557 must— 

(a) Be designed to mitigate corrosion 

of the buried or submerged pipeline; 

(b) Have sufficient adhesion to the 

metal surface to prevent under film 

migration of moisture; 

(c) Be sufficiently ductile to resist 

cracking; 

(d) Have enough strength to resist 

damage due to handling and soil stress; 

(e) Support any supplemental cathodic protection; and 

(f) If the coating is an insulating 

type, have low moisture absorption and 

provide high electrical resistance. 

§ 195.561 When must I inspect pipe 

coating used for external corrosion 

control? 

(a) You must inspect all external pipe 

coating required by §195.557 just prior 

to lowering the pipe into the ditch or 

submerging the pipe. 

(b) You must repair any coating damage discovered. 

§ 195.563 Which pipelines must have 

cathodic protection? 

(a) Each buried or submerged pipeline that is constructed, relocated, replaced, or otherwise changed after the 

applicable date in §195.401(c) must have 

cathodic protection. The cathodic protection must be in operation not later 

than 1 year after the pipeline is constructed, relocated, replaced, or otherwise changed, as applicable. 

(b) Each buried or submerged pipeline converted under §195.5 must have 

cathodic protection if the pipeline— 

(1) Has cathodic protection that substantially meets §195.571 before the 

pipeline is placed in service; or 

(2) Is a segment that is relocated, replaced, or substantially altered. 

(c) All other buried or submerged 

pipelines that have an effective external coating must have cathodic protection. 1 Except as provided by paragraph 

(d) of this section, this requirement 

does not apply to breakout tanks and 

does not apply to buried piping in 

breakout tank areas and pumping stations until December 29, 2003. 

(d) Bare pipelines, breakout tank 

areas, and buried pumping station piping must have cathodic protection in 

places where regulations in effect before January 28, 2002 required cathodic 

protection as a result of electrical inspections. See previous editions of this 

part in 49 CFR, parts 186 to 199. 

(e) Unprotected pipe must have cathodic protection if required by 

§195.573(b). 

§ 195.565 How do I install cathodic 

protection on breakout tanks? 

After October 2, 2000, when you install cathodic protection under 

§195.563(a) to protect the bottom of an 

aboveground breakout tank of more 

than 500 barrels (79.5m3) capacity built 

to API Specification 12F, API Standard 

620, or API Standard 650 (or its predecessor Standard 12C), you must install 

the system in accordance with API 

Recommended Practice 651. However, 

installation of the system need not 

comply with API Recommended Practice 651 on any tank for which you note 

in the corrosion control procedures established under §195.402(c)(3) why compliance with all or certain provisions of 

API Recommended Practice 651 is not 

necessary for the safety of the tank. 


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§ 195.567 49 CFR Ch. I (10–1–10 Edition) 

§ 195.567 Which pipelines must have 

test leads and what must I do to install and maintain the leads? 

(a) General. Except for offshore pipelines, each buried or submerged pipeline or segment of pipeline under cathodic protection required by this subpart must have electrical test leads for 

external corrosion control. However, 

this requirement does not apply until 

December 27, 2004 to pipelines or pipeline segments on which test leads were 

not required by regulations in effect 

before January 28, 2002. 

(b) Installation. You must install test 

leads as follows: 

(1) Locate the leads at intervals frequent enough to obtain electrical 

measurements indicating the adequacy 

of cathodic protection. 

(2) Provide enough looping or slack 

so backfilling will not unduly stress or 

break the lead and the lead will otherwise remain mechanically secure and 

electrically conductive. 

(3) Prevent lead attachments from 

causing stress concentrations on pipe. 

(4) For leads installed in conduits, 

suitably insulate the lead from the 

conduit. 

(5) At the connection to the pipeline, 

coat each bared test lead wire and 

bared metallic area with an electrical 

insulating material compatible with 

the pipe coating and the insulation on 

the wire. 

(c) Maintenance. You must maintain 

the test lead wires in a condition that 

enables you to obtain electrical measurements to determine whether cathodic protection complies with 

§195.571. 

§ 195.569 Do I have to examine exposed portions of buried pipelines? 

Whenever you have knowledge that 

any portion of a buried pipeline is exposed, you must examine the exposed 

portion for evidence of external corrosion if the pipe is bare, or if the coating 

is deteriorated. If you find external 

corrosion requiring corrective action 

under §195.585, you must investigate 

circumferentially and longitudinally 

beyond the exposed portion (by visual 

examination, indirect method, or both) 

to determine whether additional corrosion requiring remedial action exists in 

the vicinity of the exposed portion. 

§ 195.571 What criteria must I use to 

determine the adequacy of cathodic 

protection? 

Cathodic protection required by this 

Subpart must comply with one or more 

of the applicable criteria and other 

considerations for cathodic protection 

contained in paragraphs 6.2 and 6.3 of 

NACE SP 0169 (incorporated by reference, see §195.3). 

[Amdt. 195–94, 75 FR 48607, Aug. 11, 2010] 

§ 195.573 What must I do to monitor 

external corrosion control? 

(a) Protected pipelines. You must do 

the following to determine whether cathodic protection required by this subpart complies with §195.571: 

(1) Conduct tests on the protected 

pipeline at least once each calendar 

year, but with intervals not exceeding 

15 months. However, if tests at those 

intervals are impractical for separately 

protected short sections of bare or ineffectively coated pipelines, testing may 

be done at least once every 3 calendar 

years, but with intervals not exceeding 

39 months. 

(2) Identify not more than 2 years 

after cathodic protection is installed, 

the circumstances in which a close-interval survey or comparable technology is practicable and necessary to 

accomplish the objectives of paragraph 

10.1.1.3 of NACE SP 0169 (incorporated 

by reference, see §195.3). 

(b) Unprotected pipe. You must reevaluate your unprotected buried or 

submerged pipe and cathodically protect the pipe in areas in which active 

corrosion is found, as follows: 

(1) Determine the areas of active corrosion by electrical survey, or where an 

electrical survey is impractical, by 

other means that include review and 

analysis of leak repair and inspection 

records, corrosion monitoring records, 

exposed pipe inspection records, and 

the pipeline environment. 

(2) For the period in the first column, 

the second column prescribes the frequency of evaluation. 

Period Evaluation frequency 

Before December 29, 2003 ... At least once every 5 calendar years, but with intervals not exceeding 63 

months. 


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Pipeline and Hazardous Materials Safety Administration, DOT § 195.579 

Period Evaluation frequency 

Beginning December 29, 

2003.

At least once every 3 calendar years, but with intervals not exceeding 39 

months. 

(c) Rectifiers and other devices. You 

must electrically check for proper performance each device in the first column at the frequency stated in the second column. 

Device Check frequency 

Rectifier .................................. At least six times each calendar year, but with intervals not exceeding 21⁄2

months. 

Reverse current switch.

Diode.

Interference bond whose failure would jeopardize structural protection.

Other interference bond ........ At least once each calendar 

year, but with intervals not 

exceeding 15 months. 

(d) Breakout tanks. You must inspect 

each cathodic protection system used 

to control corrosion on the bottom of 

an aboveground breakout tank to ensure that operation and maintenance of 

the system are in accordance with API 

Recommended Practice 651. However, 

this inspection is not required if you 

note in the corrosion control procedures established under §195.402(c)(3) 

why compliance with all or certain operation and maintenance provisions of 

API Recommended Practice 651 is not 

necessary for the safety of the tank. 

(e) Corrective action. You must correct 

any identified deficiency in corrosion 

control as required by §195.401(b). However, if the deficiency involves a pipeline in an integrity management program under §195.452, you must correct 

the deficiency as required by 

§195.452(h). 

[Amdt. 195–73, 66 FR 67004, Dec. 27, 2001; 67 FR 

70118, Nov. 20, 2002, as amended by Amdt. 195– 

86, 71 FR 33411, June 9, 2006; Amdt. 195–94, 75 

FR 48607, Aug. 11, 2010] 

§ 195.575 Which facilities must I electrically isolate and what inspections, tests, and safeguards are required? 

(a) You must electrically isolate each 

buried or submerged pipeline from 

other metallic structures, unless you 

electrically interconnect and cathodically protect the pipeline and the other 

structures as a single unit. 

(b) You must install one or more insulating devices where electrical isolation of a portion of a pipeline is necessary to facilitate the application of 

corrosion control. 

(c) You must inspect and electrically 

test each electrical isolation to assure 

the isolation is adequate. 

(d) If you install an insulating device 

in an area where a combustible atmosphere is reasonable to foresee, you 

must take precautions to prevent arcing. 

(e) If a pipeline is in close proximity 

to electrical transmission tower footings, ground cables, or counterpoise, or 

in other areas where it is reasonable to 

foresee fault currents or an unusual 

risk of lightning, you must protect the 

pipeline against damage from fault 

currents or lightning and take protective measures at insulating devices. 

§ 195.577 What must I do to alleviate 

interference currents? 

(a) For pipelines exposed to stray 

currents, you must have a program to 

identify, test for, and minimize the 

detrimental effects of such currents. 

(b) You must design and install each 

impressed current or galvanic anode 

system to minimize any adverse effects 

on existing adjacent metallic structures. 

§ 195.579 What must I do to mitigate 

internal corrosion? 

(a) General. If you transport any hazardous liquid or carbon dioxide that 

would corrode the pipeline, you must 

investigate the corrosive effect of the 

hazardous liquid or carbon dioxide on 

the pipeline and take adequate steps to 

mitigate internal corrosion. 

(b) Inhibitors. If you use corrosion inhibitors to mitigate internal corrosion, 

you must— 

(1) Use inhibitors in sufficient quantity to protect the entire part of the 

pipeline system that the inhibitors are 

designed to protect; 

(2) Use coupons or other monitoring 

equipment to determine the effectiveness of the inhibitors in mitigating internal corrosion; and 

(3) Examine the coupons or other 

monitoring equipment at least twice 


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§ 195.581 49 CFR Ch. I (10–1–10 Edition) 

each calendar year, but with intervals 

not exceeding 71⁄2 months. 

(c) Removing pipe. Whenever you remove pipe from a pipeline, you must 

inspect the internal surface of the pipe 

for evidence of corrosion. If you find internal corrosion requiring corrective 

action under §195.585, you must investigate circumferentially and longitudinally beyond the removed pipe (by 

visual examination, indirect method, 

or both) to determine whether additional corrosion requiring remedial action exists in the vicinity of the removed pipe. 

(d) Breakout tanks. After October 2, 

2000, when you install a tank bottom 

lining in an aboveground breakout 

tank built to API Specification 12F, 

API Standard 620, or API Standard 650 

(or its predecessor Standard 12C), you 

must install the lining in accordance 

with API Recommended Practice 652. 

However, installation of the lining 

need not comply with API Recommended Practice 652 on any tank for 

which you note in the corrosion control procedures established under 

§195.402(c)(3) why compliance with all 

or certain provisions of API Recommended Practice 652 is not necessary for the safety of the tank. 

§ 195.581 Which pipelines must I protect against atmospheric corrosion 

and what coating material may I 

use? 

(a) You must clean and coat each 

pipeline or portion of pipeline that is 

exposed to the atmosphere, except 

pipelines under paragraph (c) of this 

section. 

(b) Coating material must be suitable 

for the prevention of atmospheric corrosion. 

(c) Except portions of pipelines in offshore splash zones or soil-to-air interfaces, you need not protect against atmospheric corrosion any pipeline for 

which you demonstrate by test, investigation, or experience appropriate to 

the environment of the pipeline that 

corrosion will— 

(1) Only be a light surface oxide; or 

(2) Not affect the safe operation of 

the pipeline before the next scheduled 

inspection. 

§ 195.583 What must I do to monitor atmospheric corrosion control? 

(a) You must inspect each pipeline or 

portion of pipeline that is exposed to 

the atmosphere for evidence of atmospheric corrosion, as follows: 

If the pipeline is 

located: 

Then the frequency of inspection is: 

Onshore ................................. At least once every 3 calendar years, but with intervals not exceeding 39 

months. 

Offshore ................................. At least once each calendar 

year, but with intervals not 

exceeding 15 months. 

(b) During inspections you must give 

particular attention to pipe at soil-toair interfaces, under thermal insulation, under disbonded coatings, at pipe 

supports, in splash zones, at deck penetrations, and in spans over water. 

(c) If you find atmospheric corrosion 

during an inspection, you must provide 

protection against the corrosion as required by §195.581. 

§ 195.585 What must I do to correct 

corroded pipe? 

(a) General corrosion. If you find pipe 

so generally corroded that the remaining wall thickness is less than that required for the maximum operating 

pressure of the pipeline, you must replace the pipe. However, you need not 

replace the pipe if you— 

(1) Reduce the maximum operating 

pressure commensurate with the 

strength of the pipe needed for serviceability based on actual remaining wall 

thickness; or 

(2) Repair the pipe by a method that 

reliable engineering tests and analyses 

show can permanently restore the serviceability of the pipe. 

(b) Localized corrosion pitting. If you 

find pipe that has localized corrosion 

pitting to a degree that leakage might 

result, you must replace or repair the 

pipe, unless you reduce the maximum 

operating pressure commensurate with 

the strength of the pipe based on actual remaining wall thickness in the 

pits. 


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Pipeline and Hazardous Materials Safety Administration, DOT § 195.588 

§ 195.587 What methods are available 

to determine the strength of corroded pipe? 

Under §195.585, you may use the procedure in ASME B31G, ‘‘Manual for Determining the Remaining Strength of 

Corroded Pipelines,’’ or the procedure 

developed by AGA/Battelle, ‘‘A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe 

(with RSTRENG disk),’’ to determine 

the strength of corroded pipe based on 

actual remaining wall thickness. These 

procedures apply to corroded regions 

that do not penetrate the pipe wall, 

subject to the limitations set out in 

the respective procedures. 

§ 195.588 What standards apply to direct assessment? 

(a) If you use direct assessment on an 

onshore pipeline to evaluate the effects 

of external corrosion, you must follow 

the requirements of this section for 

performing external corrosion direct 

assessment. This section does not 

apply to methods associated with direct assessment, such as close interval 

surveys, voltage gradient surveys, or 

examination of exposed pipelines, when 

used separately from the direct assessment process. 

(b) The requirements for performing 

external corrosion direct assessment 

are as follows: 

(1) General. You must follow the requirements of NACE SP0502 (incorporated by reference, see §195.3). Also, 

you must develop and implement a External Corrosion Direct Assessment 

(ECDA) plan that includes procedures 

addressing pre-assessment, indirect examination, direct examination, and 

post-assessment. 

(2) Pre-assessment. In addition to the 

requirements in Section 3 of NACE 

SP0502 (incorporated by reference, see 

§195.3), the ECDA plan procedures for 

pre-assessment must include— 

(i) Provisions for applying more restrictive criteria when conducting 

ECDA for the first time on a pipeline 

segment; 

(ii) The basis on which you select at 

least two different, but complementary, indirect assessment tools to assess each ECDA region; and 

(iii) If you utilize an indirect inspection method not described in Appendix 

A of NACE SP0502 (incorporated by reference, see §195.3), you must demonstrate the applicability, validation 

basis, equipment used, application procedure, and utilization of data for the 

inspection method. 

(3) Indirect examination. In addition to 

the requirements in Section 4 of NACE 

SP0502 (incorporated by reference, see 

§195.3), the procedures for indirect examination of the ECDA regions must 

include— 

(i) Provisions for applying more restrictive criteria when conducting 

ECDA for the first time on a pipeline 

segment; 

(ii) Criteria for identifying and documenting those indications that must be 

considered for excavation and direct 

examination, including at least the following: 

(A) The known sensitivities of assessment tools; 

(B) The procedures for using each 

tool; and 

(C) The approach to be used for decreasing the physical spacing of indirect assessment tool readings when the 

presence of a defect is suspected; 

(iii) For each indication identified 

during the indirect examination, criteria for— 

(A) Defining the urgency of excavation and direct examination of the 

indication; and 

(B) Defining the excavation urgency 

as immediate, scheduled, or monitored; 

and 

(iv) Criteria for scheduling excavations of indications in each urgency 

level. 

(4) Direct examination. In addition to 

the requirements in Section 5 of NACE 

SP0502 (incorporated by reference, see 

§195.3), the procedures for direct examination of indications from the indirect 

examination must include— 

(i) Provisions for applying more restrictive criteria when conducting 

ECDA for the first time on a pipeline 

segment; 

(ii) Criteria for deciding what action 

should be taken if either: 

(A) Corrosion defects are discovered 

that exceed allowable limits (Section 

5.5.2.2 of NACE SP0502 (incorporated by 

reference, see §195.3) provides guidance 

for criteria); or 


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§ 195.589 49 CFR Ch. I (10–1–10 Edition) 

(B) Root cause analysis reveals conditions for which ECDA is not suitable 

(Section 5.6.2 of NACE SP0502 (incorporated by reference, see §195.3) provides guidance for criteria); 

(iii) Criteria and notification procedures for any changes in the ECDA 

plan, including changes that affect the 

severity classification, the priority of 

direct examination, and the time frame 

for direct examination of indications; 

and 

(iv) Criteria that describe how and on 

what basis you will reclassify and reprioritize any of the provisions specified in Section 5.9 of NACE SP0502 (incorporated by reference, see §195.3). 

(5) Post assessment and continuing 

evaluation. In addition to the requirements in Section 6 of NACE SP 0502 

(incorporated by reference, see §195.3), 

the procedures for post assessment of 

the effectiveness of the ECDA process 

must include— 

(i) Measures for evaluating the longterm effectiveness of ECDA in addressing external corrosion in pipeline segments; and 

(ii) Criteria for evaluating whether 

conditions discovered by direct examination of indications in each ECDA region indicate a need for reassessment 

of the pipeline segment at an interval 

less than that specified in Sections 6.2 

and 6.3 of NACE SP0502 (see appendix D 

of NACE SP0502) (incorporated by reference, see §195.3). 

[Amdt. 195–85, 70 FR 61576, Oct. 25, 2005, as 

amended by Amdt. 195–94, 75 FR 48607, Aug. 

11, 2010] 

§ 195.589 What corrosion control information do I have to maintain? 

(a) You must maintain current 

records or maps to show the location 

of— 

(1) Cathodically protected pipelines; 

(2) Cathodic protection facilities, including galvanic anodes, installed after 

January 28, 2002; and 

(3) Neighboring structures bonded to 

cathodic protection systems. 

(b) Records or maps showing a stated 

number of anodes, installed in a stated 

manner or spacing, need not show specific distances to each buried anode. 

(c) You must maintain a record of 

each analysis, check, demonstration, 

examination, inspection, investigation, 

review, survey, and test required by 

this subpart in sufficient detail to demonstrate the adequacy of corrosion control measures or that corrosion requiring control measures does not exist. 

You must retain these records for at 

least 5 years, except that records related to §§195.569, 195.573(a) and (b), and 

195.579(b)(3) and (c) must be retained 

for as long as the pipeline remains in 

service. 

APPENDIX A TO PART 195—DELINEATION

BETWEEN FEDERAL AND STATE JURISDICTION—STATEMENT OF AGENCY

POLICY AND INTERPRETATION

In 1979, Congress enacted comprehensive 

safety legislation governing the transportation of hazardous liquids by pipeline, the 

Hazardous Liquids Pipeline Safety Act of 

1979, 49 U.S.C. 2001 et seq. (HLPSA). The 

HLPSA expanded the existing statutory authority for safety regulation, which was limited to transportation by common carriers in 

interstate and foreign commerce, to transportation through facilities used in or affecting interstate or foreign commerce. It also 

added civil penalty, compliance order, and 

injunctive enforcement authorities to the 

existing criminal sanctions. Modeled largely 

on the Natural Gas Pipeline Safety Act of 

1968, 49 U.S.C. 1671 et seq. (NGPSA), the 

HLPSA provides for a national hazardous 

liquid pipeline safety program with nationally uniform minimal standards and with enforcement administered through a FederalState partnership. The HLPSA leaves to exclusive Federal regulation and enforcement 

the ‘‘interstate pipeline facilities,’’ those 

used for the pipeline transportation of hazardous liquids in interstate or foreign commerce. For the remainder of the pipeline facilities, denominated ‘‘intrastate pipeline facilities,’’ the HLPSA provides that the same 

Federal regulation and enforcement will 

apply unless a State certifies that it will assume those responsibilities. A certified State 

must adopt the same minimal standards but 

may adopt additional more stringent standards so long as they are compatible. Therefore, in States which participate in the hazardous liquid pipeline safety program 

through certification, it is necessary to distinguish the interstate from the intrastate 

pipeline facilities. 

In deciding that an administratively practical approach was necessary in distinguishing between interstate and intrastate 

liquid pipeline facilities and in determining 

how best to accomplish this, DOT has logically examined the approach used in the 

NGPSA. The NGPSA defines the interstate 

gas pipeline facilities subject to exclusive 

Federal jurisdiction as those subject to the 


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Pipeline and Hazardous Materials Safety Administration, DOT Pt. 195, App. A 

economic regulatory jurisdiction of the Federal Energy Regulatory Commission (FERC). 

Experience has proven this approach practical. Unlike the NGPSA however, the 

HLPSA has no specific reference to FERC jurisdiction, but instead defines interstate liquid pipeline facilities by the more commonly 

used means of specifying the end points of 

the transportation involved. For example, 

the economic regulatory jurisdiction of 

FERC over the transportation of both gas 

and liquids by pipeline is defined in much the 

same way. In implementing the HLPSA DOT 

has sought a practicable means of distinguishing between interstate and intrastate 

pipeline facilities that provide the requisite 

degree of certainty to Federal and State enforcement personnel and to the regulated entities. DOT intends that this statement of 

agency policy and interpretation provide 

that certainty. 

In 1981, DOT decided that the inventory of 

liquid pipeline facilities identified as subject 

to the jurisdiction of FERC approximates 

the HLPSA category of ‘‘interstate pipeline 

facilities.’’ Administrative use of the FERC 

inventory has the added benefit of avoiding 

the creation of a separate Federal scheme for 

determination of jurisdiction over the same 

regulated entities. DOT recognizes that the 

FERC inventory is only an approximation 

and may not be totally satisfactory without 

some modification. The difficulties stem 

from some significant differences in the economic regulation of liquid and of natural gas 

pipelines. There is an affirmative assertion 

of jurisdiction by FERC over natural gas 

pipelines through the issuance of certificates 

of public convenience and necessity prior to 

commencing operations. With liquid pipelines, there is only a rebuttable presumption 

of jurisdiction created by the filing by pipeline operators of tariffs (or concurrences) for 

movement of liquids through existing facilities. Although FERC does police the filings 

for such matters as compliance with the general duties of common carriers, the question 

of jurisdiction is normally only aired upon 

complaint. While any person, including 

State or Federal agencies, can avail themselves of the FERC forum by use of the complaint process, that process has only been 

rarely used to review jurisdictional matters 

(probably because of the infrequency of real 

disputes on the issue). Where the issue has 

arisen, the reviewing body has noted the 

need to examine various criteria primarily of 

an economic nature. DOT believes that, in 

most cases, the formal FERC forum can better receive and evaluate the type of information that is needed to make decisions of this 

nature than can DOT. 

In delineating which liquid pipeline facilities are interstate pipeline facilities within 

the meaning of the HLPSA, DOT will generally rely on the FERC filings; that is, if 

there is a tariff or concurrence filed with 

FERC governing the transportation of hazardous liquids over a pipeline facility or if 

there has been an exemption from the obligation to file tariffs obtained from FERC, then 

DOT will, as a general rule, consider the facility to be an interstate pipeline facility 

within the meaning of the HLPSA. The types 

of situations in which DOT will ignore the 

existence or non-existence of a filing with 

FERC will be limited to those cases in which 

it appears obvious that a complaint filed 

with FERC would be successful or in which 

blind reliance on a FERC filing would result 

in a situation clearly not intended by the 

HLPSA such as a pipeline facility not being 

subject to either State or Federal safety regulation. DOT anticipates that the situations 

in which there is any question about the validity of the FERC filings as a ready reference will be few and that the actual variations from reliance on those filings will be 

rare. The following examples indicate the 

types of facilities which DOT believes are 

interstate pipeline facilities subject to the 

HLPSA despite the lack of a filing with 

FERC and the types of facilities over which 

DOT will generally defer to the jurisdiction 

of a certifying state despite the existence of 

a filing with FERC. 

Example 1. Pipeline company P operates a 

pipeline from ‘‘Point A’’ located in State X 

to ‘‘Point B’’ (also in X). The physical facilities never cross a state line and do not connect with any other pipeline which does 

cross a state line. Pipeline company P also 

operates another pipeline between ‘‘Point C’’ 

in State X and ‘‘Point D’’ in an adjoining 

State Y. Pipeline company P files a tariff 

with FERC for transportation from ‘‘Point 

A’’ to ‘‘Point B’’ as well as for transportation from ‘‘Point C’’ to ‘‘Point D.’’ DOT 

will ignore filing for the line from ‘‘Point A’’ 

to ‘‘Point B’’ and consider the line to be 

intrastate. 

Example 2. Same as in example 1 except 

that P does not file any tariffs with FERC. 

DOT will assume jurisdiction of the line between ‘‘Point C’’ and ‘‘Point D.’’ 

Example 3. Same as in example 1 except 

that P files its tariff for the line between 

‘‘Point C’’ and ‘‘Point D’’ not only with 

FERC but also with State X. DOT will rely 

on the FERC filing as indication of interstate commerce. 

Example 4. Same as in example 1 except 

that the pipeline from ‘‘Point A’’ to ‘‘Point 

B’’ (in State X) connects with a pipeline operated by another company transports liquid 

between ‘‘Point B’’ (in State X) and ‘‘Point 

D’’ (in State Y). DOT will rely on the FERC 

filing as indication of interstate commerce. 

Example 5. Same as in example 1 except 

that the line between ‘‘Point C’’ and ‘‘Point 

D’’ has a lateral line connected to it. The 

lateral is located entirely with State X. DOT 

will rely on the existence or non-existence of 

a FERC filing covering transportation over 


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Pt. 195, App. B 49 CFR Ch. I (10–1–10 Edition) 

that lateral as determinative of interstate 

commerce. 

Example 6. Same as in example 1 except 

that the certified agency in State X has 

brought an enforcement action (under the 

pipeline safety laws) against P because of its 

operation of the line between ‘‘Point A’’ and 

‘‘Point B’’. P has successfully defended 

against the action on jurisdictional grounds. 

DOT will assume jurisdiction if necessary to 

avoid the anomaly of a pipeline subject to 

neither State or Federal safety enforcement. 

DOT’s assertion of jurisdiction in such a case 

would be based on the gap in the state’s enforcement authority rather than a DOT decision that the pipeline is an interstate pipeline facility. 

Example 7. Pipeline Company P operates a 

pipeline that originates on the Outer Continental Shelf. P does not file any tariff for 

that line with FERC. DOT will consider the 

pipeline to be an interstate pipeline facility. 

Example 8. Pipeline Company P is constructing a pipeline from ‘‘Point C’’ (in State 

X) to ‘‘Point D’’ (in State Y). DOT will consider the pipeline to be an interstate pipeline 

facility. 

Example 9. Pipeline company P is constructing a pipeline from ‘‘Point C’’ to 

‘‘Point E’’ (both in State X) but intends to 

file tariffs with FERC in the transportation 

of hazardous liquid in interstate commerce. 

Assuming there is some connection to an 

interstate pipeline facility, DOT will consider this line to be an interstate pipeline facility. 

Example 10. Pipeline Company P has operated a pipeline subject to FERC economic 

regulation. Solely because of some statutory 

economic deregulation, that pipeline is no 

longer regulated by FERC. DOT will continue to consider that pipeline to be an 

interstate pipeline facility. 

As seen from the examples, the types of 

situations in which DOT will not defer to the 

FERC regulatory scheme are generally clearcut cases. For the remainder of the situations where variation from the FERC scheme 

would require DOT to replicate the forum already provided by FERC and to consider economic factors better left to that agency, 

DOT will decline to vary its reliance on the 

FERC filings unless, of course, not doing so 

would result in situations clearly not intended by the HLPSA. 

[Amdt. 195–33, 50 FR 15899, Apr. 23, 1985] 

APPENDIX B TO PART 195—RISK-BASED

ALTERNATIVE TO PRESSURE TESTING

OLDER HAZARDOUS LIQUID AND CARBON DIOXIDE PIPELINES

RISK-BASED ALTERNATIVE

This Appendix provides guidance on how a 

risk-based alternative to pressure testing 

older hazardous liquid and carbon dioxide 

pipelines rule allowed by §195.303 will work. 

This risk-based alternative establishes test 

priorities for older pipelines, not previously 

pressure tested, based on the inherent risk of 

a given pipeline segment. The first step is to 

determine the classification based on the 

type of pipe or on the pipeline segment’s 

proximity to populated or environmentally 

sensitive area. Secondly, the classifications 

must be adjusted based on the pipeline failure history, product transported, and the release volume potential. 

Tables 2–6 give definitions of risk classification A, B, and C facilities. For the purposes of this rule, pipeline segments containing high risk electric resistance-welded 

pipe (ERW pipe) and lapwelded pipe manufactured prior to 1970 and considered a risk classification C or B facility shall be treated as 

the top priority for testing because of the 

higher risk associated with the susceptibility of this pipe to longitudinal seam failures. 

In all cases, operators shall annually, at 

intervals not to exceed 15 months, review 

their facilities to reassess the classification 

and shall take appropriate action within two 

years or operate the pipeline system at a 

lower pressure. Pipeline failures, changes in 

the characteristics of the pipeline route, or 

changes in service should all trigger a reassessment of the originally classification. 

Table 1 explains different levels of test requirements depending on the inherent risk of 

a given pipeline segment. The overall risk 

classification is determined based on the 

type of pipe involved, the facility’s location, 

the product transported, the relative volume 

of flow and pipeline failure history as determined from Tables 2–6. 

TABLE 1. TEST REQUIREMENTS—MAINLINE SEGMENTS OUTSIDE OF TERMINALS, STATIONS, AND TANK

FARMS

Pipeline segment Risk classification Test deadline 1 Test medium 

Pre-1970 Pipeline Segments susceptible to longitudinal seam failures 2.

C or B 

A 

12/7/2000 3 ...............................

12/7/2002 3 ...............................

Water only. 

Water only. 

All Other Pipeline Segments ......................................... C 12/7/2002 4 ............................... Water only. 

B 12/7/2004 4 ............................... Water/Liq. 5


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Pipeline and Hazardous Materials Safety Administration, DOT Pt. 195, App. B 

TABLE 1. TEST REQUIREMENTS—MAINLINE SEGMENTS OUTSIDE OF TERMINALS, STATIONS, AND TANK

FARMS—Continued 

Pipeline segment Risk classification Test deadline 1 Test medium 

A Additional pressure testing not 

required. 

1 If operational experience indicates a history of past failures for a particular pipeline segment, failure causes (time-dependent 

defects due to corrosion, construction, manufacture, or transmission problems, etc.) shall be reviewed in determining risk classification (See Table 6) and the timing of the pressure test should be accelerated. 2All pre-1970 ERW pipeline segments may not require testing. In determining which ERW pipeline segments should be included in this category, an operator must consider the seam-related leak history of the pipe and pipe manufacturing information

as available, which may include the pipe steel’s mechanical properties, including fracture toughness; the manufacturing process

and controls related to seam properties, including whether the ERW process was high-frequency or low-frequency, whether the 

weld seam was heat treated, whether the seam was inspected, the test pressure and duration during mill hydrotest; the quality 

control of the steel-making process; and other factors pertinent to seam properties and quality. 3For those pipeline operators with extensive mileage of pre-1970 ERW pipe, any waiver requests for timing relief should be 

supported by an assessment of hazards in accordance with location, product, volume, and probability of failure considerations 

consistent with Tables 3, 4, 5, and 6. 4A magnetic flux leakage or ultrasonic internal inspection survey may be utilized as an alternative to pressure testing where 

leak history and operating experience do not indicate leaks caused by longitudinal cracks or seam failures. 5Pressure tests utilizing a hydrocarbon liquid may be conducted, but only with a liquid which does not vaporize rapidly. 

Using LOCATION, PRODUCT, VOLUME, 

and FAILURE HISTORY ‘‘Indicators’’ from 

Tables 3, 4, 5, and 6 respectively, the overall 

risk classification of a given pipeline or pipeline segment can be established from Table 

2. The LOCATION Indicator is the primary 

factor which determines overall risk, with 

the PRODUCT, VOLUME, and PROBABILITY OF FAILURE Indicators used to 

adjust to a higher or lower overall risk classification per the following table. 

TABLE 2—RISK CLASSIFICATION

Risk classification Hazard location indicator Product/volume indicator Probability of failure indicator 

A .............................................. L or M .................................... L/L .......................................... L. 

B .............................................. Not A or C Risk Classification 

C .............................................. H ............................................ Any ........................................ Any. 

H=High M=Moderate L=Low. 

NOTE: For Location, Product, Volume, and Probability of Failure Indicators, see Tables 3, 4, 5, and 6. 

Table 3 is used to establish the LOCATION 

Indicator used in Table 2. Based on the population and environment characteristics associated with a pipeline facility’s location, a 

LOCATION Indicator of H, M or L is selected. 

TABLE 3—LOCATION INDICATORS—PIPELINE SEGMENTS

Indicator Population 1 Environment 2

H ...................................................... Non-rural areas ............................................. Environmentally sensitive 2 areas. 

M ........................................................................

L ....................................................... Rural areas .................................................... Not environmentally sensitive 2 areas. 

1The effects of potential vapor migration should be considered for pipeline segments transporting highly volatile or toxic prod- ucts. 2We expect operators to use their best judgment in applying this factor. 

Tables 4, 5 and 6 are used to establish the 

PRODUCT, VOLUME, and PROBABILITY 

OF FAILURE Indicators respectively, in 

Table 2. The PRODUCT Indicator is selected 

from Table 4 as H, M, or L based on the acute 

and chronic hazards associated with the 

product transported. The VOLUME Indicator 

is selected from Table 5 as H, M, or L based 

on the nominal diameter of the pipeline. The 

Probability of Failure Indicator is selected 

from Table 6. 

TABLE 4—PRODUCT INDICATORS

Indicator Considerations Product examples 

H ................................................................ (Highly volatile and flammable) ............... (Propane, butane, Natural Gas Liquid 

(NGL), ammonia) 


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TABLE 4—PRODUCT INDICATORS—Continued 

Indicator Considerations Product examples 

Highly toxic .............................................. (Benzene, high Hydrogen Sulfide content crude oils). 

M ................................................................ Flammable—flashpoint <100F ................ (Gasoline, JP4, low flashpoint crude 

oils). 

L ................................................................. Non-flammable—flashpoint 100+F .......... (Diesel, fuel oil, kerosene, JP5, most 

crude oils). 

Highly volatile and non-flammable/nontoxic.Carbon Dioxide. 

Considerations: The degree of acute and 

chronic toxicity to humans, wildlife, and 

aquatic life; reactivity; and, volatility, flammability, and water solubility determine the 

Product Indicator. Comprehensive Environmental Response, Compensation and Liability Act Reportable Quantity values can be 

used as an indication of chronic toxicity. National Fire Protection Association health 

factors can be used for rating acute hazards. 

TABLE 5—VOLUME INDICATORS

Indicator Line size 

H .................. ≥18′′. 

M ................. 10′′–16′′ nominal diameters. 

L .................. ≤8′′ nominal diameter. 

H=High M=Moderate L=Low. 

Table 6 is used to establish the PROBABILITY OF FAILURE Indicator used in 

Table 2. The ‘‘Probability of Failure’’ Indicator is selected from Table 6 as H or L. 

TABLE 6—PROBABILITY OF FAILURE INDICATORS

[in each haz. location] 

Indicator Failure history (time-dependent defects) 2

H 1 ................ >Three spills in last 10 years. 

L .................. ≤Three spills in last 10 years. 

H=High L=Low. 

1Pipeline segments with greater than three product spills in 

the last 10 years should be reviewed for failure causes as described in subnote 2. The pipeline operator should make an 

appropriate investigation and reach a decision based on 

sound engineering judgment, and be able to demonstrate the 

basis of the decision. 2Time-Dependent Defects are defects that result in spills 

due to corrosion, gouges, or problems developed during manufacture, construction or operation, etc. 

[Amdt. 195–65, 63 FR 59480, Nov. 4, 1998; 64 FR 

6815, Feb. 11, 1999] 

APPENDIX C TO PART 195—GUIDANCE FOR

IMPLEMENTATION OF AN INTEGRITY

MANAGEMENT PROGRAM

This Appendix gives guidance to help an 

operator implement the requirements of the 

integrity management program rule in 

§§195.450 and 195.452. Guidance is provided on: 

(1) Information an operator may use to 

identify a high consequence area and factors 

an operator can use to consider the potential 

impacts of a release on an area; 

(2) Risk factors an operator can use to determine an integrity assessment schedule; 

(3) Safety risk indicator tables for leak 

history, volume or line size, age of pipeline, 

and product transported, an operator may 

use to determine if a pipeline segment falls 

into a high, medium or low risk category; 

(4) Types of internal inspection tools an 

operator could use to find pipeline anomalies; 

(5) Measures an operator could use to 

measure an integrity management program’s 

performance; and 

(6) Types of records an operator will have 

to maintain. 

(7) Types of conditions that an integrity 

assessment may identify that an operator 

should include in its required schedule for 

evaluation and remediation. 

I. Identifying a high consequence area and 

factors for considering a pipeline segment’s 

potential impact on a high consequence area. 

A. The rule defines a High Consequence 

Area as a high population area, an other populated area, an unusually sensitive area, or a 

commercially navigable waterway. The Office of Pipeline Safety (OPS) will map these 

areas on the National Pipeline Mapping System (NPMS). An operator, member of the 

public or other government agency may view 

and download the data from the NPMS home 

page http://www.npms.phmsa.gov/. OPS will 

maintain the NPMS and update it periodically. However, it is an operator’s responsibility to ensure that it has identified all high 

consequence areas that could be affected by 

a pipeline segment. An operator is also responsible for periodically evaluating its pipeline segments to look for population or environmental changes that may have occurred 

around the pipeline and to keep its program 

current with this information. (Refer to 

§195.452(d)(3).) 

(1) Digital Data on populated areas available on U.S. Census Bureau maps. 

(2) Geographic Database on the commercial navigable waterways available on http:// 

www.bts.gov/gis/ntatlas/networks.html. 

(3) The Bureau of Transportation Statistics database that includes commercially 

navigable waterways and non-commercially 


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Pipeline and Hazardous Materials Safety Administration, DOT Pt. 195, App. C 

navigable waterways. The database can be 

downloaded from the BTS website at http:// 

www.bts.gov/gis/ntatlas/networks.html. 

B. The rule requires an operator to include 

a process in its program for identifying 

which pipeline segments could affect a high 

consequence area and to take measures to 

prevent and mitigate the consequences of a 

pipeline failure that could affect a high consequence area. (See §§195.452 (f) and (i).) 

Thus, an operator will need to consider how 

each pipeline segment could affect a high 

consequence area. The primary source for 

the listed risk factors is a US DOT study on 

instrumented Internal Inspection devices 

(November 1992). Other sources include the 

National Transportation Safety Board, the 

Environmental Protection Agency and the 

Technical Hazardous Liquid Pipeline Safety 

Standards Committee. The following list 

provides guidance to an operator on both the 

mandatory and additional factors: 

(1) Terrain surrounding the pipeline. An 

operator should consider the contour of the 

land profile and if it could allow the liquid 

from a release to enter a high consequence 

area. An operator can get this information 

from topographical maps such as U.S. Geological Survey quadrangle maps. 

(2) Drainage systems such as small streams 

and other smaller waterways that could 

serve as a conduit to a high consequence 

area. 

(3) Crossing of farm tile fields. An operator 

should consider the possibility of a spillage 

in the field following the drain tile into a 

waterway. 

(4) Crossing of roadways with ditches along 

the side. The ditches could carry a spillage 

to a waterway. 

(5) The nature and characteristics of the 

product the pipeline is transporting (refined 

products, crude oils, highly volatile liquids, 

etc.) Highly volatile liquids becomes gaseous 

when exposed to the atmosphere. A spillage 

could create a vapor cloud that could settle 

into the lower elevation of the ground profile. 

(6) Physical support of the pipeline segment such as by a cable suspension bridge. 

An operator should look for stress indicators 

on the pipeline (strained supports, inadequate support at towers), atmospheric corrosion, vandalism, and other obvious signs of 

improper maintenance. 

(7) Operating conditions of the pipeline 

(pressure, flow rate, etc.). Exposure of the 

pipeline to an operating pressure exceeding 

the established maximum operating pressure. 

(8) The hydraulic gradient of the pipeline. 

(9) The diameter of the pipeline, the potential release volume, and the distance between the isolation points. 

(10) Potential physical pathways between 

the pipeline and the high consequence area. 

(11) Response capability (time to respond, 

nature of response). 

(12) Potential natural forces inherent in 

the area (flood zones, earthquakes, subsidence areas, etc.) 

II. Risk factors for establishing frequency 

of assessment. 

A. By assigning weights or values to the 

risk factors, and using the risk indicator tables, an operator can determine the priority 

for assessing pipeline segments, beginning 

with those segments that are of highest risk, 

that have not previously been assessed. This 

list provides some guidance on some of the 

risk factors to consider (see §195.452(e)). An 

operator should also develop factors specific 

to each pipeline segment it is assessing, including: 

(1) Populated areas, unusually sensitive environmental areas, National Fish Hatcheries, 

commercially navigable waters, areas where 

people congregate. 

(2) Results from previous testing/inspection. (See §195.452(h).) 

(3) Leak History. (See leak history risk 

table.) 

(4) Known corrosion or condition of pipeline. (See §195.452(g).) 

(5) Cathodic protection history. 

(6) Type and quality of pipe coating 

(disbonded coating results in corrosion). 

(7) Age of pipe (older pipe shows more corrosion—may be uncoated or have an ineffective coating) and type of pipe seam. (See Age 

of Pipe risk table.) 

(8) Product transported (highly volatile, 

highly flammable and toxic liquids present a 

greater threat for both people and the environment) (see Product transported risk 

table.) 

(9) Pipe wall thickness (thicker walls give 

a better safety margin) 

(10) Size of pipe (higher volume release if 

the pipe ruptures). 

(11) Location related to potential ground 

movement (e.g., seismic faults, rock quarries, and coal mines); climatic (permafrost 

causes settlement—Alaska); geologic (landslides or subsidence). 

(12) Security of throughput (effects on customers if there is failure requiring shutdown). 

(13) Time since the last internal inspection/ 

pressure testing. 

(14) With respect to previously discovered 

defects/anomalies, the type, growth rate, and 

size. 

(15) Operating stress levels in the pipeline. 

(16) Location of the pipeline segment as it 

relates to the ability of the operator to detect and respond to a leak. (e.g., pipelines 

deep underground, or in locations that make 

leak detection difficult without specific sectional monitoring and/or significantly impede access for spill response or any other 

purpose). 


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(17) Physical support of the segment such 

as by a cable suspension bridge. 

(18) Non-standard or other than recognized 

industry practice on pipeline installation 

(e.g., horizontal directional drilling). 

B. Example: This example illustrates a hypothetical model used to establish an integrity assessment schedule for a hypothetical 

pipeline segment. After we determine the 

risk factors applicable to the pipeline segment, we then assign values or numbers to 

each factor, such as, high (5), moderate (3), 

or low (1). We can determine an overall risk 

classification (A, B, C) for the segment using 

the risk tables and a sliding scale (values 5 

to 1) for risk factors for which tables are not 

provided. We would classify a segment as C if 

it fell above 2⁄3 of maximum value (highest 

overall risk value for any one segment when 

compared with other segments of a pipeline), 

a segment as B if it fell between 1⁄3 to 2⁄3 of 

maximum value, and the remaining segments as A. 

i. For the baseline assessment schedule, we 

would plan to assess 50% of all pipeline segments covered by the rule, beginning with 

the highest risk segments, within the first 

31⁄2 years and the remaining segments within 

the seven-year period. For the continuing integrity assessments, we would plan to assess 

the C segments within the first two (2) years 

of the schedule, the segments classified as 

moderate risk no later than year three or 

four and the remaining lowest risk segments 

no later than year five (5). 

ii. For our hypothetical pipeline segment, 

we have chosen the following risk factors 

and obtained risk factor values from the appropriate table. The values assigned to the 

risk factors are for illustration only. 

Age of pipeline: assume 30 years old (refer to 

‘‘Age of Pipeline’’ risk table)— 

Risk Value=5 

Pressure tested: tested once during construction— 

Risk Value=5 

Coated: (yes/no)—yes 

Coating Condition: Recent excavation of suspected areas showed holidays in coating 

(potential corrosion risk)— 

Risk Value=5 

Cathodically Protected: (yes/no)—yes—Risk 

Value=1 

Date cathodic protection installed: five years 

after pipeline was constructed (Cathodic 

protection installed within one year of the 

pipeline’s construction is generally considered low risk.)—Risk Value=3 

Close interval survey: (yes/no)—no—Risk 

Value =5 

Internal Inspection tool used: (yes/no)—yes. 

Date of pig run? In last five years—Risk 

Value=1 

Anomalies found: (yes/no)—yes, but do not 

pose an immediate safety risk or environmental hazard—Risk Value=3 

Leak History: yes, one spill in last 10 years. 

(refer to ‘‘Leak History’’ risk table)—Risk 

Value=2 

Product transported: Diesel fuel. Product low 

risk. (refer to ‘‘Product’’ risk table)—Risk 

Value=1 

Pipe size: 16 inches. Size presents moderate 

risk (refer to ‘‘Line Size’’ risk table)—Risk 

Value=3 

iii. Overall risk value for this hypothetical 

segment of pipe is 34. Assume we have two 

other pipeline segments for which we conduct similar risk rankings. The second pipeline segment has an overall risk value of 20, 

and the third segment, 11. For the baseline 

assessment we would establish a schedule 

where we assess the first segment (highest 

risk segment) within two years, the second 

segment within five years and the third segment within seven years. Similarly, for the 

continuing integrity assessment, we could 

establish an assessment schedule where we 

assess the highest risk segment no later than 

the second year, the second segment no later 

than the third year, and the third segment 

no later than the fifth year. 

III. Safety risk indicator tables for leak 

history, volume or line size, age of pipeline, 

and product transported. 

LEAK HISTORY

Safety risk 

indicator 

Leak history 

(Time-dependent defects) 1

High .......................... > 3 Spills in last 10 years 

Low ........................... < 3 Spills in last 10 years 

1Time-dependent defects are those that result in spills due 

to corrosion, gouges, or problems developed during manufacture, construction or operation, etc. 

LINE SIZE OR VOLUME TRANSPORTED

Safety risk 

indicator Line size 

High .......................... ≥ 18′ 

Moderate .................. 10′—16′ nominal diameters 

Low ........................... ≤ 8′ nominal diameter 

AGE OF PIPELINE

Safety risk 

indicator 

Age Pipeline condition 

dependent) 1

High .......................... > 25 years 

Low ........................... < 25 years 

1 Depends on pipeline’s coating & corrosion condition, and 

steel quality, toughness, welding. 

PRODUCT TRANSPORTED

Safety 

risk 

indicator 

Considerations 1 Product examples 

High ... (Highly volatile and flammable).(Propane, butane, Natural Gas Liquid (NGL), 

ammonia). 


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Pipeline and Hazardous Materials Safety Administration, DOT Pt. 195, App. C 

PRODUCT TRANSPORTED—Continued 

Safety 

risk 

indicator 

Considerations 1 Product examples 

Highly toxic .................... (Benzene, high Hydrogen Sulfide content 

crude oils). 

Medium.Flammable—flashpoint 

<100F.

(Gasoline, JP4, low 

flashpoint crude oils). 

Low .... Non-flammable— 

flashpoint 100+F.

(Diesel, fuel oil, kerosene, JP5, most 

crude oils). 

1The degree of acute and chronic toxicity to humans, wildlife, and aquatic life; reactivity; and, volatility, flammability, and 

water solubility determine the Product Indicator. Comprehensive Environmental Response, Compensation and Liability Act 

Reportable Quantity values may be used as an indication of 

chronic toxicity. National Fire Protection Association health 

factors may be used for rating acute hazards. 

IV. Types of internal inspection tools to 

use. 

An operator should consider at least two 

types of internal inspection tools for the integrity assessment from the following list. 

The type of tool or tools an operator selects 

will depend on the results from previous internal inspection runs, information analysis 

and risk factors specific to the pipeline segment: 

(1) Geometry Internal inspection tools for 

detecting changes to ovality, e.g., bends, 

dents, buckles or wrinkles, due to construction flaws or soil movement, or other outside 

force damage; 

(2) Metal Loss Tools (Ultrasonic and Magnetic Flux Leakage) for determining pipe 

wall anomalies, e.g., wall loss due to corrosion. 

(3) Crack Detection Tools for detecting 

cracks and crack-like features, e.g., stress 

corrosion cracking (SCC), fatigue cracks, 

narrow axial corrosion, toe cracks, hook 

cracks, etc. 

V. Methods to measure performance. 

A. General. (1) This guidance is to help an 

operator establish measures to evaluate the 

effectiveness of its integrity management 

program. The performance measures required will depend on the details of each integrity management program and will be 

based on an understanding and analysis of 

the failure mechanisms or threats to integrity of each pipeline segment. 

(2) An operator should select a set of measurements to judge how well its program is 

performing. An operator’s objectives for its 

program are to ensure public safety, prevent 

or minimize leaks and spills and prevent 

property and environmental damage. A typical integrity management program will be 

an ongoing program and it may contain 

many elements. Therefore, several performance measure are likely to be needed to 

measure the effectiveness of an ongoing program. 

B. Performance measures. These measures 

show how a program to control risk on pipeline segments that could affect a high consequence area is progressing under the integrity management requirements. Performance measures generally fall into three categories: 

(1) Selected Activity Measures—Measures 

that monitor the surveillance and preventive 

activities the operator has implemented. 

These measure indicate how well an operator 

is implementing the various elements of its 

integrity management program. 

(2) Deterioration Measures—Operation and 

maintenance trends that indicate when the 

integrity of the system is weakening despite 

preventive measures. This category of performance measure may indicate that the system condition is deteriorating despite well 

executed preventive activities. 

(3) Failure Measures—Leak History, incident response, product loss, etc. These measures will indicate progress towards fewer 

spills and less damage. 

C. Internal vs. External Comparisons. These 

comparisons show how a pipeline segment 

that could affect a high consequence area is 

progressing in comparison to the operator’s 

other pipeline segments that are not covered 

by the integrity management requirements 

and how that pipeline segment compares to 

other operators’ pipeline segments. 

(1) Internal—Comparing data from the 

pipeline segment that could affect the high 

consequence area with data from pipeline 

segments in other areas of the system may 

indicate the effects from the attention given 

to the high consequence area. 

(2) External—Comparing data external to 

the pipeline segment (e.g., OPS incident 

data) may provide measures on the frequency and size of leaks in relation to other 

companies. 

D. Examples. Some examples of performance measures an operator could use include— 

(1) A performance measurement goal to reduce the total volume from unintended releases by -% (percent to be determined by operator) with an ultimate goal of zero. 

(2) A performance measurement goal to reduce the total number of unintended releases 

(based on a threshold of 5 gallons) by ll-% 

(percent to be determined by operator) with 

an ultimate goal of zero. 

(3) A performance measurement goal to 

document the percentage of integrity management activities completed during the calendar year. 

(4) A performance measurement goal to 

track and evaluate the effectiveness of the 

operator’s community outreach activities. 

(5) A narrative description of pipeline system integrity, including a summary of performance improvements, both qualitative 

and quantitative, to an operator’s integrity 

management program prepared periodically. 


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Pt. 198 49 CFR Ch. I (10–1–10 Edition) 

(6) A performance measure based on internal audits of the operator’s pipeline system 

per 49 CFR Part 195. 

(7) A performance measure based on external audits of the operator’s pipeline system 

per 49 CFR Part 195. 

(8) A performance measure based on operational events (for example: relief occurrences, unplanned valve closure, SCADA outages, etc.) that have the potential to adversely affect pipeline integrity. 

(9) A performance measure to demonstrate 

that the operator’s integrity management 

program reduces risk over time with a focus 

on high risk items. 

(10) A performance measure to demonstrate that the operator’s integrity management program for pipeline stations and 

terminals reduces risk over time with a 

focus on high risk items. 

VI. Examples of types of records an operator must maintain. 

The rule requires an operator to maintain 

certain records. (See §195.452(l)). This section 

provides examples of some records that an 

operator would have to maintain for inspection to comply with the requirement. This is 

not an exhaustive list. 

(1) a process for identifying which pipelines 

could affect a high consequence area and a 

document identifying all pipeline segments 

that could affect a high consequence area; 

(2) a plan for baseline assessment of the 

line pipe that includes each required plan 

element; 

(3) modifications to the baseline plan and 

reasons for the modification; 

(4) use of and support for an alternative 

practice; 

(5) a framework addressing each required 

element of the integrity management program, updates and changes to the initial 

framework and eventual program; 

(6) a process for identifying a new high 

consequence area and incorporating it into 

the baseline plan, particularly, a process for 

identifying population changes around a 

pipeline segment; 

(7) an explanation of methods selected to 

assess the integrity of line pipe; 

(8) a process for review of integrity assessment results and data analysis by a person 

qualified to evaluate the results and data; 

(9) the process and risk factors for determining the baseline assessment interval; 

(10) results of the baseline integrity assessment; 

(11) the process used for continual evaluation, and risk factors used for determining 

the frequency of evaluation; 

(12) process for integrating and analyzing 

information about the integrity of a pipeline, information and data used for the information analysis; 

(13) results of the information analyses and 

periodic evaluations; 

(14) the process and risk factors for establishing continual re-assessment intervals; 

(15) justification to support any variance 

from the required re-assessment intervals; 

(16) integrity assessment results and anomalies found, process for evaluating and remediating anomalies, criteria for remedial actions and actions taken to evaluate and remediate the anomalies; 

(17) other remedial actions planned or 

taken; 

(18) schedule for evaluation and remediation of anomalies, justification to support 

deviation from required remediation times; 

(19) risk analysis used to identify additional preventive or mitigative measures, 

records of preventive and mitigative actions 

planned or taken; 

(20) criteria for determining EFRD installation; 

(21) criteria for evaluating and modifying 

leak detection capability; 

(22) methods used to measure the program’s effectiveness. 

VII. Conditions that may impair a pipeline’s integrity. 

Section 195.452(h) requires an operator to 

evaluate and remediate all pipeline integrity 

issues raised by the integrity assessment or 

information analysis. An operator must develop a schedule that prioritizes conditions 

discovered on the pipeline for evaluation and 

remediation. The following are some examples of conditions that an operator should 

schedule for evaluation and remediation. 

A. Any change since the previous assessment. 

B. Mechanical damage that is located on 

the top side of the pipe. 

C. An anomaly abrupt in nature. 

D. An anomaly longitudinal in orientation. 

E. An anomaly over a large area. 

F. An anomaly located in or near a casing, 

a crossing of another pipeline, or an area 

with suspect cathodic protection. 

[Amdt. 195–70, 65 FR 75409, Dec. 1, 2000, as 

amended by Amdt. 195–74, 67 FR 1661, Jan. 14, 

2002; Amdt. 195–94, 75 FR 48608, Aug. 11, 2010] 

PARTS 196–197 [RESERVED] 

PART 198—REGULATIONS FOR 

GRANTS TO AID STATE PIPELINE 

SAFETY PROGRAMS 

Subpart A—General 

Sec. 

198.1 Scope. 

198.3 Definitions. 

Subpart B—Grant Allocation 

198.11 Grant authority. 

198.13 Grant allocation formula. 


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