**[New Format]{.smallcaps}**

**For future versions of this manual, changes to the regulations will
show [highlights]{.mark} for deletions and underline for
[additions]{.underline}.**

***Example:***

**§195.222 Welders: Qualification of welders.**

[[(a)]{.underline} Each welder must be qualified in accordance with
section 3 of API Standard 1104 or section IX of the ASME Boiler and
Pressure Vessel Code, except that a welder]{.mark}

[qualified under an earlier edition than listed in §195.3 may weld but
may not requalify under that earlier edition.]{.mark}

[[(b) No welder may weld with a particular welding process unless,
within the preceding 6 calendar months, the welder
has---]{.underline}]{.mark}

[[(1) Engaged in welding with that process; and]{.underline}]{.mark}

[[(2) Had one weld tested and found acceptable under Section 6 of API
1104.]{.underline}]{.mark}

[(a)]{.underline} [Each welder must be qualified in accordance with
Section 6 of API 1104 (incorporated by reference[ibr]{.mark}, *see*
§195.3) or Section IX of the ASME Boiler and Pressure Vessel Code,
(incorporated by reference[ibr]{.mark}, *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.]{.underline}

[(b) No welder may weld with a welding process unless, within the
preceding 6 calendar months, the welder has---]{.underline}

[(1) Engaged in welding with that process; and]{.underline}

[(2) Had one welded tested and found acceptable under section 9 of API
1104 (incorporated by reference[ibr]{.mark}, *see* §195.3).]{.underline}

# \[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-8, 40 FR 10181, Mar. 5, 1975; Amdt. 195-8A, 40 FR 27222, June 27, 1975; Amdt. 195-21, 46 FR 10157, Feb. 2, 1981; Amdt. 195-22, 46 FR 38357, July 27, 1981; Amdt. 195-32, 49 FR 36859, Sept. 20, 1984; Amdt. 195-38, 51 FR 20294, June 4, 1986; [Amdt. 195-79, 68 FR 53526, Sept. 11, 2003; Amdt. 195-81, 69 FR 32886, June 14, 2004; Amdt. 195-81A, 69 FR 54591, Sept. 9, 2004]{.underline}\]

**[Amendment Table of Section Revisions]{.smallcaps}**

  ----------------------- -------------------------- ----------------------- --------------------------
  **[Part 195 Amendment   **[Effective Date of       **[Paragraph\           **[In Refference
  Number]{.smallcaps}**   Amendment]{.smallcaps}**   Impact]{.smallcaps}**   to:]{.smallcaps}**

  84                      07/01/05                   195.505, .509           [Statutory
                                                                             Changes]{.smallcaps}

  No Number               03/08/05                   195.1., .2, .3, .9,     [Administration Name
                                                     .57, .58, .59, .452     Change]{.smallcaps}

  84                      06/20/05                   195.3, .440             [Public Awareness
                                                                             Programs]{.smallcaps}

  85                      11/25/05                   195.3, 452, .553, .588  [Standards for Direct
                                                                             Assessment]{.smallcaps}

  86                      07/10/06                   195..3, .116, .264,     [Update Incorporated by
                                                     .307, .440, .571, .573  Reference]{.smallcaps}

  86c                     03/05/07                   195.59                  [Update of Website Info
                                                                             and Removal of Dead Line
                                                                             Dates]{.smallcaps}
  ----------------------- -------------------------- ----------------------- --------------------------

# 

# Subpart A--General

Sec.

195.0 Scope.

195.1 Applicability.

195.2 Definitions.

195.3 Matter incorporated by reference in whole or in part.

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)

8.  Transportation of hazardous liquids or carbon dioxide in pipelines
    constructed with other than steel pipe.

9.  Outer continental shelf pipelines.

195.10 Responsibility of operator for compliance with this part.

**Subpart B---Annual, Accident, and Safety-Related Condition Reporting**

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 Addressee for written reports.

195.59 Abandoned underwater facilities report.

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.

194.126 Flange connection.

195.128 Station piping.

195.130 Fabricated assemblies.

195.132 Design and construction of aboveground breakout tanks.

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.

195.208 Welding of supports and braces.

195.210 Pipeline location.

195.212 Bending of pipe.

195.214 Welding procedures.

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 External corrosion protection.

195.238 External coating.

195.242 Cathodic protection system.

195.244 Test leads.

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 Aboveground 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.

**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.

195.307 Pressure testing aboveground breakout tanks.

195.306 Test medium.

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.

195.420 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 education.

442. Damage prevention program.

195.444 CPM leak detection.

**[High Consequence Areas]{.smallcaps}**

195.450 Definitions.

**[Pipeline Integrity Management]{.smallcaps}**

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 how do I 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?]{.underline}

195.589 What corrosion control information do I have to maintain?

**Appendix A** -- Delineation Between Federal and State
Jurisdiction-Statement of Agency Policy and Interpretation.

**Appendix B**---Risk-Based Alternative to Pressure Testing Older
Hazardous Liquid and Carbon Dioxide Pipelines

**Appendix C to Part 195**--Guidance for Implementation of Integrity
Management Program

**Authority:** 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60118; and 49
CFR 1.53.

\[50 FR 45733, Nov. 1, 1985 as amended by Amdt. 195-70, 65 FR 75378;
Amdt. 195-71, 65 FR 80530, Dec. 21, 2000; Amdt. 195-72, 66 FR 43523,
Aug. 20, 2001; Amdt. 195-73, 66 FR 66993, Dec. 27, 2002; Amdt. 195-80,
69 FR 537, Jan. 6, 2004; [Amdt. 195-85, 70 FR 61571, Oct. 25,
2005]{.underline}\]

# 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.

\[Amdt. 195-22, 46 FR 38357, July 27, 1981 as amended by Amdt. 195-45,
56 FR 26922, June 12, 1991\]

**§195.1 Applicability.**

\(a\) Except as provided 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.

\(b\) This part does not apply to--

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

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

\(3\) Transportation through any of the following low-stress pipelines:

\(i\) An onshore pipeline or pipeline segment that --

(A) Does not transport HVL;

(B) Is located in a rural area; and

(C) Is located outside a waterway currently used for commercial
    navigation;

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

\(iii\) A pipeline that serves refining, manufacturing, or truck, rail
or vessel terminal facilities, if the pipeline is less than 1 mile long
(measured outside facility grounds) and does not cross an offshore area
or a waterway currently used for commercial navigation;

\(4\) Transportation of petroleum in onshore gathering lines in rural
areas except gathering lines in the inlets of the Gulf of Mexico subject
to §195.413;

\(5\) Transportation of hazardous liquid or carbon dioxide in offshore
pipelines in State waters which are located upstream from the outlet
flange of each facility where hydrocarbons or carbon dioxide are
produced or where produced hydrocarbons or carbon dioxide are first
separated, dehydrated, or otherwise processed, whichever facility is
farther downstream;

\(6\) Transportation of hazardous liquid or carbon dioxide in Outer
Continental Shelf pipelines which are located upstream of the point at
which operating responsibility transfers from a producing operator to a
transporting operator;

\(7\) Pipelines on the Outer Continental Shelf (OCS) that are
producer-operated and cross into State waters without first connecting
to a transporting operator\'s facility on the OCS, upstream (generally
seaward) of the last valve on the last production facility on the OCS.
Safety equipment protecting [RSPA]{.mark} PHMSA-regulated pipeline
segments is not excluded. Producing operators for those pipeline
segments upstream of the last valve of the last production facility on
the OCS may petition the Administrator, or designee, for approval to
operate under [RSPA]{.mark} PHMSA regulations governing pipeline design,
construction, operation, and maintenance under 49 CFR 190.9.

\(8\) 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 terminal that 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, not including any device and
associated piping that are necessary to control pressure in the pipeline
under §195.406(b); and,

\(10\) Transportation of carbon dioxide downstream from the following
point, as applicable:

\(i\) 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 that transports carbon dioxide to injection wells or to headers or
manifolds from which pipelines branch to injection wells.

\(c\) 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).

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-1, 35 FR 5332,
Mar. 31, 1970; Amdt. 195-22, 46 FR 38357, July 27, 1981; Amdt. 195-33,
50 FR 15895, Apr. 23, 1985; Amdt. 195-34, 50 FR 34470, Aug. 26, 1985;
Amdt. 195-36, 52 FR 15005, Apr. 22, 1986; Amdt. 195-36C, 51 FR 20976,
June 10, 1986; Amdt. 195-45, 56 FR 26922, June 12, 1991; Amdt. 195-47,
56 FR 63764, Dec. 5, 1991; Amdt. 195-52, 59 FR 33388, June 28, 1994;
Amdt. 195-53, 59 FR 35465, July 12, 1994; Amdt. 195-57, 62 FR 31364,
June 9, 1997; Amdt. 195-57A, 62 FR 52511, Oct. 8, 1997; Amdt. 195-59, 62
FR 61692, Nov. 19, 1997; Amdt. 195-64, 63 FR 46692, Sep. 2, 1998; Amdt.
195-66, 64 FR 15926, April 2, 1999; Amdt. 195-78, 68 FR 46109, Aug. 5,
2003; [70 FR 11135, Mar. 8, 2005]{.underline}\]

**§195.2 Definitions.**

As used in this part--

***Abandoned*** means permanently removed from service.

***Administrator*** means the Administrator, [Research and Special
Programs Administration]{.mark} [Pipeline Hazardous Materials Safety
Administration]{.underline} or his or her delegate.

***Barrel*** means a unit of measure-ment 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.

***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 (8 5/8 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 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.

***Hazardous liquid*** means petroleum, petroleum products, or anhydrous
ammonia.

***Hazard to navigation*** means, for the purpose 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 water less than 15 feet
(4.6 meters) deep, as measured from the mean low water.

***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 76 kPa (40 psia) at 37.8°C (100°F).

***In-plant piping systems*** 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 transpor-tation, 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 repre-sentative 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.

***Production facility*** means piping or equipment used in the
production, extraction, recovery, lifting, stabiliza-tion, 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 CO~2~ 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
unincorporated 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.

***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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-2, 35 FR 17183,
Nov. 7, 1970; Amdt 195-5, 38 FR 2977, Jan. 31, 1973; Amdt. 195-15, 44 FR
41197, July 16, 1979; Amdt. 195-22, 46 FR 38357, July 27, 1981; Amdt.
195-33, 50 FR 15895, Apr. 23, 1985; Amdt. 195-33C, 50 FR 38659, Sept.
24, 1985; Amdt. 195-36, 51 FR 15005, Apr. 22, 1986; Amdt. 195-45, 56 FR
26922, June 12, 1991; Amdt. 195-47, 56 FR 63764, Dec. 5, 1991; Amdt.
195-50, 59 FR 17275, Apr. 12, 1994; Amdt. 195-52, 59 FR 33388, June 28,
1994; Amdt. 195-53, 59 FR 35465, July 12, 1994; Amdt. 195-59, 62 FR
61692, Nov. 19, 1997; Amdt. 195-62, 63 FR 36373, July 6, 1998; Amdt.
195-63, 63 FR 37500, July 13, 1998; Amdt. 195-69, 65 FR 54440, Sept. 8,
2000, Amdt. 915-71, 65 FR 80530, Dec. 21, 2000; Amdt. 195-77, 68 FR
11748, Mar. 12, 2003; Amdt. 195-81, 69 FR 32886, June 14, 2004; Amdt.
195-82, 69 FR 48400, Aug. 10, [2004; 70 FR 11135, Mar. 8,
2005]{.underline}\]

**§195.3 Matter incorporated by reference in whole or in part.**

\(a\) 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 reminder 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
[Research and Special Programs]{.mark} Pipeline and Hazardous Materials
SafetyAdministration, 400 Seventh Street, SW, Washington, DC, 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/federal_register/code_of_federal_regulations/ibr_locations.html*.
These materials have been approved for incorporation by reference by the
Director of the Federal Register in accordance with 5 U.S.C. 552(a) and
1 CFR part 51. In addition, materials incorporated by reference are
available as follows:

[(1) American Gas Association (AGA), 400 North Capitol Street, NW,
Washington, DC 20001.]{.mark}

[(2) American Petroleum Institute (API), 1220 L Street, NW, Washington,
DC 20005.]{.mark}

[(3) ASME International (ASME), Three Park Avenue, New York, NY
10016-5990.]{.mark}

[(4) Manufacturers Standardization Society of the Valve and Fittings
Industry, Inc. (MSS), 127 Park Street, NE, Vienna, VA 22180.]{.mark}

[(5) American Society for Testing and Materials (ASTM), 100 Barr Harbor
Drive, West Conshohocken, PA 19428.]{.mark}

[(6) National Fire Protection Association (NFPA), 1 Batterymarch Park,
P.O. Box 9101, Quincy, MA 02269-9101.]{.mark}

[(7) NACE International, 1440 South Creek Drive, Houston, TX
77084]{.mark}

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:

+---------------------------------------------------+------------------+
| Source and name of referenced material            | 49 CFR reference |
+---------------------------------------------------+------------------+
| A. [Pipeline Research Council International, Inc. | §1               |
| (PRCI)]{.underline}[American Gas Association      | 95.452(h)(4)(B). |
| (AGA)]{.mark}:                                    |                  |
|                                                   |                  |
| \(1\) 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 remaining strength.          |                  |
|                                                   |                  |
| [(2) \[Reserved\].]{.mark}                        |                  |
+---------------------------------------------------+------------------+
| B. American Petroleum Institute (API):            | §§               |
|                                                   | 1                |
| \(1\) API Specification 5L "Specification for     | 95.106(b)(1)(i); |
| Line Pipe" [(43rd edition and errata,             | 195.106(e).      |
| 2004)]{.underline}[(42nd edition, 2000)]{.mark}.  |                  |
+---------------------------------------------------+------------------+
| \(2\) API Specification 6D "Specification for     | §195.116(d).     |
| Pipeline Valves (Gate, Plug, Ball, and Check      |                  |
| Valves)" [(22nd edition, January                  |                  |
| 2002)]{.underline}[(21st edition, 1994)]{.mark}.  |                  |
+---------------------------------------------------+------------------+
| \(3\) API Specification 12F "Specification for    | §§               |
| Shop Welded Tanks for Storage of Production       | 195.132(b)(1);   |
| Liquids" (11th edition, November 1994).           | 195.205(b)(2);   |
|                                                   | 195.264(b)(1);   |
|                                                   | 195.264(e)(1);   |
|                                                   | 195.307(a);      |
|                                                   | 195.565;         |
|                                                   | 195.579(d).      |
+---------------------------------------------------+------------------+
| \(4\) API 510 "Pressure Vessel Inspection Code:   | §§               |
| Maintenance Inspection, Rating, Repair, and       | 195.205(b)(3);   |
| Alteration" (8th edition, June 1997, and Addenda  | 195.432(c).      |
| 1 through 4).                                     |                  |
+---------------------------------------------------+------------------+
| \(5\) API Standard 620 "Design and Construction   | §§               |
| of Large, Welded, Low-Pressure Storage Tanks"     | 195.132(b)(2);   |
| [(10th edition, 2002 including Addendum           | 195.205(b)(2);   |
| 1)]{.underline}[(9th edition)]{.mark}.            | 195.264(b)(1);   |
|                                                   | 195.264(e)(3);   |
|                                                   | 195.307(b).      |
+---------------------------------------------------+------------------+
| \(6\) API 650 "Welded Steel Tanks for Oil         | §§               |
| Storage" [(10th edition, 1998 including Addenda   | 195.132(b)(3);   |
| 1-3)]{.underline}[(1998)]{.mark}.                 | 195.205(b)(1);   |
|                                                   | 195.264(b)(1);   |
|                                                   | 195.264(e)(2);   |
|                                                   | 195.307(c);      |
|                                                   | 195.307(d);      |
|                                                   | 195.565;         |
|                                                   | 195.579(d).      |
+---------------------------------------------------+------------------+
| \(7\) API Recommended Practice 651 "Cathodic      | §§ 195.565;      |
| Protection of Aboveground Petroleum Storage       | 195.579(d).      |
| Tanks" (2nd edition, December 1997).              |                  |
+---------------------------------------------------+------------------+
| \(8\) API Recommended Practice 652 "Lining of     | §195.579(d).     |
| Aboveground Petroleum Storage Tank Bottoms" (2nd  |                  |
| edition, December 1997).                          |                  |
+---------------------------------------------------+------------------+
| \(9\) API Standard 653 "Tank Inspection, Repair,  | §§               |
| Alteration, and Reconstruction" (3rd edition,     | 195.205(b)(1);   |
| 2001 [including]{.underline} [, and]{.mark}       | 195.432(b).      |
| Addendum 1, 2003).                                |                  |
+---------------------------------------------------+------------------+
| \(10\) API 1104 "Welding of Pipelines and Related | §§ 195.222;      |
| Facilities" (19th edition, 1999                   | 195.228(b).      |
| [including]{.underline} [plus its]{.mark} October |                  |
| 31, 2001 errata).                                 |                  |
+---------------------------------------------------+------------------+
| [(11) API Standard 2000 "Venting Atmospheric and  | [§§              |
| Low-Pressure Storage Tanks" (4th edition,         | 195.264(e)(2);   |
| September 1992).]{.mark}                          | 195.26           |
|                                                   | 4(e)(3).]{.mark} |
+---------------------------------------------------+------------------+
| (1[1]{.underline}[2]{.mark}) API 1130             | §§ 195.134;      |
| "Computational Pipeline Monitoring" [(2nd         | 195.444.         |
| edition, 2002)]{.underline}[(1st edition,         |                  |
| 1995)]{.mark}.                                    |                  |
+---------------------------------------------------+------------------+
| [(12) API Standard 2000 "Venting Atmospheric and  | [§§              |
| Low-Pressure Storage Tanks" (5th edition, April   | 195.264(e)(2);   |
| 1998).]{.underline}                               | 195.264(e)(      |
|                                                   | 3).]{.underline} |
+---------------------------------------------------+------------------+
| [[(13) API Recommended Practice 1162 "Public      | [[§195.440]{.un  |
| Awareness Programs for Pipeline Operators," First | derline}]{.mark} |
| Edition (December 2003)]{.underline}]{.mark}      |                  |
+---------------------------------------------------+------------------+
| ([13]{.underline}[13 [14]{.underline}]{.mark})    | §195.405(a).     |
| API Recommended Practice 2003 "Protection Against |                  |
| Ignitions Arising out of Static, Lightning, and   |                  |
| Stray Currents" (6th edition, 1998).              |                  |
+---------------------------------------------------+------------------+
| ([14]{.underline}[14 [15]{.underline}]{.mark})    | §195.405(b).     |
| API Publication 2026 "Safe Access/Egress          |                  |
| Involving Floating Roofs of Storage Tanks in      |                  |
| Petroleum Service" (2nd edition, 1998).           |                  |
+---------------------------------------------------+------------------+
| ([15]{.underline}[15 [16]{.underline}]{.mark})    | §195.428(c).     |
| API Recommended Practice 2350 "Overfill           |                  |
| Protection for Storage Tanks In Petroleum         |                  |
| Facilities" (2nd edition, 1996).                  |                  |
+---------------------------------------------------+------------------+
| ([16]{.underline}[16 [17]{.underline}]{.mark})    | §§               |
| API Standard 2510 "Design and Construction of LPG | 195.132(b)(3);   |
| Installations"[(8th edition,                      | 195.205(b)(3);   |
| 2001)]{.underline}[(7th edition, 1995)]{.mark}.   | 195.264(b)(2);   |
|                                                   | 195.264(e)(4);   |
|                                                   | 195.307(e);      |
|                                                   | 195.428(c);      |
|                                                   | 195.432(c).      |
+---------------------------------------------------+------------------+
| [(17) API Recommended Practice 1162 "Public       | [§§ 195.440(a);  |
| Awareness Programs for Pipeline Operators,"       | 195.440(b);      |
| (1^st^ edition, December 2003)]{.underline}       | 195.440          |
|                                                   | (c)]{.underline} |
+---------------------------------------------------+------------------+
| C. ASME International (ASME):                     | §195.118(a).     |
|                                                   |                  |
| \(1\) ASME[/ANSI]{.mark} B16.9[-2003 (February    |                  |
| 2004)]{.underline} "Factory-Made Wrought Steel    |                  |
| Butt welding Fittings" [(1993)]{.mark}.           |                  |
+---------------------------------------------------+------------------+
| \(2\) ASME[/ANSI]{.mark} B31.4[-2002 (October     | §1               |
| 2002)]{.underline} "Pipeline Transportation       | 95.452(h)(4)(i). |
| Systems for Liquid Hydrocarbons and Other         |                  |
| Liquids" [(1998)]{.mark}.                         |                  |
+---------------------------------------------------+------------------+
| \(3\) ASME[/ANSI]{.mark} B31G[-1991 (Reaffirmed;  | §§               |
| 2004)]{.underline} "Manual for Determining the    | 195.             |
| Remaining Strength of Corroded Pipelines"         | 452(h)(4)(i)(B); |
| [(1991)]{.mark}.                                  | 195.45           |
|                                                   | 2(h)(4)(iii)(D). |
+---------------------------------------------------+------------------+
| \(4\) ASME[/ANSI]{.mark} B31.8[-2003 (February    | §§               |
| 2004)]{.underline} "Gas Transmission and          | 195.5(a)(1)(i);  |
| Distribution Piping Systems" [(1995)]{.mark}.     | 1                |
|                                                   | 95.406(a)(1)(i). |
+---------------------------------------------------+------------------+
| \(5\) ASME Boiler and Pressure vessel Code,       | §§ 195.124;      |
| Section VIII, Division 1 "Rules for Construction  | 195.307(e).      |
| of Pressure Vessels," [(2004 edition, including   |                  |
| addenda through July 1, 2005)]{.underline}[(1998  |                  |
| edition with 2000 addenda)]{.mark}.               |                  |
+---------------------------------------------------+------------------+
| \(6\) ASME Boiler and Pressure Vessel Code,       | §195.307(e).     |
| Section VIII, Division 2 "Alternate Rules for     |                  |
| Construction for Pressure Vessels" [(2004         |                  |
| edition, including addenda through July 1,        |                  |
| 2005)]{.underline}[(2001 Edition)]{.mark}.        |                  |
+---------------------------------------------------+------------------+
| \(7\) ASME Boiler and Pressure vessel Code,       | §195.222.        |
| Section IX "Welding and Brazing Qualifications,"  |                  |
| [(2004 edition, including addenda through July 1, |                  |
| 2005)]{.underline}[(2001 Edition)]{.mark}.        |                  |
+---------------------------------------------------+------------------+
| D. Manufacturers Standardization Society of the   | §195.118(a).     |
| Valve and Fittings Industry, Inc. (MSS):          |                  |
|                                                   |                  |
| \(1\) MSS SP-75[-2004]{.underline} "Specification |                  |
| for High Test Wrought Butt Welding Fittings"      |                  |
| [(1993)]{.mark}.                                  |                  |
|                                                   |                  |
| \(2\) \[Reserved\].                               |                  |
+---------------------------------------------------+------------------+
| E. American Society for Testing and Materials     | §195.106(e).     |
| (ASTM):                                           |                  |
|                                                   |                  |
| \(1\) ASTM Designation: A53/A53M[-04a             |                  |
| (2004)]{.underline} "Standard Specification for   |                  |
| Pipe, Steel, Black and Hot-Dipped, Zinc-Coated    |                  |
| Welded and Seamless" [(A53/A53M-99b)]{.mark}.     |                  |
+---------------------------------------------------+------------------+
| \(2\) ASTM Designation: A106[/A106M-04b           | §195.106(e).     |
| (2004)]{.underline} "Standard Specification for   |                  |
| Seamless Carbon Steel Pipe for High-Temperature   |                  |
| Service" [(A106-99)]{.mark}.                      |                  |
+---------------------------------------------------+------------------+
| \(3\) ASTM Designation: A 333/A                   | §195.106(e).     |
| 333M[-05]{.underline} "Standard Specification for |                  |
| Seamless and Welded Steel Pipe for                |                  |
| Low-Temperature Service" [(A 333/A                |                  |
| 333M-99)]{.mark}.                                 |                  |
+---------------------------------------------------+------------------+
| \(4\) ASTM Designation: A 381[-96 (Reapproved     | §195.106(e).     |
| 2001)]{.underline} "Standard Specification for    |                  |
| Metal-Arc-Welded Steel Pipe for Use With          |                  |
| High-Pressure Transmission Systems" [(A           |                  |
| 381-96)]{.mark}.                                  |                  |
+---------------------------------------------------+------------------+
| \(5\) ASTM Designation: A 671[-04                 | §195.106(e).     |
| (2004)]{.underline} "Standard Specification for   |                  |
| Electric-Fusion-Welded Steel Pipe for Atmospheric |                  |
| and Lower Temperatures" [(A 671-96)]{.mark}.      |                  |
+---------------------------------------------------+------------------+
| \(6\) ASTM Designation: A 672[-96 (Reapproved     | §195.106(e).     |
| 2001)]{.underline} "Standard Specification for    |                  |
| Electric-Fusion-Welded Steel Pipe for             |                  |
| High-Pressure Service at Moderate Temperatures"   |                  |
| [(A 672-96)]{.mark}.                              |                  |
+---------------------------------------------------+------------------+
| \(7\) ASTM Designation: A 691[-98 (Reapproved     | §195.106(e).     |
| 2002)]{.underline} "Standard Specification for    |                  |
| Carbon and Alloy Steel Pipe                       |                  |
| Electric-Fusion-Welded for High-Pressure Service  |                  |
| at High Temperatures" [(A 691-98)]{.mark}.        |                  |
+---------------------------------------------------+------------------+
| F. National Fire Protection Association (NFPA):   | §195.264(b)(1).  |
|                                                   |                  |
| \(1\) [ANSI/]{.mark}NFPA 30 [(2003)]{.underline}  |                  |
| "Flammable and Combustible Liquids Code"          |                  |
| [(1996)]{.mark}.                                  |                  |
|                                                   |                  |
| \(2\) \[Reserved\].                               |                  |
+---------------------------------------------------+------------------+
| G. NACE International (NACE):                     | §195.571         |
|                                                   |                  |
| \(1\) NACE Standard                               |                  |
| RP[-]{.mark}[0]{.under                            |                  |
| line}169[-96]{.mark}[-2002]{.underline}[:]{.mark} |                  |
| "Control of External Corrosion on Underground or  |                  |
| Submerged Metallic Piping Systems"                |                  |
| [(1996)]{.mark}.                                  |                  |
+---------------------------------------------------+------------------+
| \(2\) [Reserved.]{.mark} [NACE Standard           | [§195.           |
| RP0502-2002 "Pipeline External Corrosion Direct   | 588]{.underline} |
| Assessment Methodology\']{.underline}\' (2002).   |                  |
+---------------------------------------------------+------------------+

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-5, 38 FR 2977,
Jan. 31, 1973; Amdt. 195-9, 41 FR 13590, Mar. 31, 1976; Amdt. 195-14, 43
FR 18553, May 1, 1978; Amdt. 195-21, 46 FR 10157, Feb. 2, 1981; Amdt.
195-22, 46 FR 38357, July 27, 1981; Amdt. 195-32, 49 FR 36859, Sep. 20,
1984; Amdt. 195-37, 51 FR 15333, Apr. 23. 1986; Amdt. 195-40, 54 FR
5625, Feb. 6. 1989; Amdt. 195-41, 54 FR 22781, July 3, 1989; Amdt.
195-43, 54 FR 32344, Aug. 7, 1989; Amdt. 195-45, 56 FR 26922, June 12,
1991; Amdt. 195-48, 58 FR 14519, Mar. 18, 1993; Amdt. 195-52, 59 FR
33388, June 28, 1994; Amdt. 195-56, 61 FR 26121, May, 24, 1996; Amdt.
195-56A, 61 FR 36825, July 15, 1996; Amdt. 195-61, 63 FR 7721, Feb. 17,
1998; Amdt. 195-62, 63 FR 36373, July 6, 1998; Amdt. 195-66, 64 FR
15926, April 2, 1999; Amdt. 195-66A, 65 FR 4770, Feb. 1, 2000; Amdt.
195-73, 66 FR 66993, Dec. 27, 2002; Amdt. 195-81, 69 FR 32886, June 14,
[2004; Amdt. 195-84, 70 FR 28833, May 19, 2005; Amdt. 195-85, 70 FR
61571, Oct. 25, 2005; Amdt. 195-86, 71 FR 33402, June 9,
2006]{.underline}\]

**§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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981; Amdt. 195-45, 56 FR 26922, June 12, 1991\]

**§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 determine 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.

\[Amdt. 195-13, 43 FR 6786, Feb. 16, 1979 as amended by Amdt. 195-22, 46
FR 38357, July 27, 1981; Amdt. 195-52, 59 FR 33388, June 28, 1994; Amdt.
195-73, 66 FR 66993, Dec. 27, 2002\]

**§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 Non-

transient 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;

\(3\) 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.

*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 man-made 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.

*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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-1, 35 FR 5332,
Mar. 31, 1970; Amdt. 195-5, 38 FR 2977, Jan. 31, 1973; Amdt. 195-71, 65
FR 80530, Dec. 21, 2000\]

**§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
transport the hazardous liquid or carbon dioxide in the proposed manner
until further notice.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-1, 35 FR 5332,
Mar. 31, 1970; Amdt. 195-2, 35 FR 17183, Nov. 7, 1970; Amdt. 195-22, 46
FR 38357, July 27, 1981; Amdt. 195-45, 56 FR 26922, June 12, 1991, Amdt.
195-50, 59 FR 17275, Apr. 12, 1994\]

**§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 [RSPA]{.mark}
[PHMSA]{.underline} 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.

\[Amdt. 195-59, 62 FR 61692, Nov. 19, 1997[; 70 FR 11135, Mar. 8,
2005]{.underline}\]

**§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.

**Subpart B---Annual, Accident, and Safety-Related Condition Reporting**

**§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.

\[Amdt. 195-80, 69 FR 537, Jan. 6, 2004\]

**§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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-15, 44 FR 41197,
July 16, 1979; Amdt. 195-22, 46 FR 38357, July 27, 1981, Amdt. 195-39,
53 FR 24942, July 1, 1988; Amdt. 195-45, 56 FR 26922, June 12, 1991;
Amdt. 195-52, 59 FR 33388, June 28, 1994; Amdt. 195-63, 63 FR 37500,
July 13, 1998; Amdt. 195-75, 67 FR 831, Jan. 8, 2002; Amdt. 195-75a, 67
FR 6436, Feb. 12, 2002\]

**§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: 267-2675) 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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt 195-5, 38 FR 2977,
Jan. 31, 1973; Amdt 195-6, 38 FR 7121, Jan. 31, 1973; Amdt. 195-22, 46
FR 38357, July 27, 1981, Amdt. 195-23, 47 FR 32719, July 29, 1982; Amdt.
195-44, 54 FR 40878, Oct. 4, 1989; Amdt. 195-45, 56 FR 26922, June 12,
1991; Amdt. 195-52, 59 FR 33388, June 28, 1994\]

**§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.

\(b\) 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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981; Amdt 195-34, 50 FR 34470, Aug. 26, 1985; Amdt. 195-39, 53
FR 24942, July 1, 1988\]

**§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.

\[Amdt. 195-39, 53 FR 24942, July 1, 1988 as amended by Amdt. 195-39C,
53 FR 36942, Sept. 22, 1988; Amdt. 195-63, 63 FR 37500, July 13, 1998\]

**§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.

\(8\) 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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981; Amdt 195-34, 50 FR 34470, Aug. 26, 1985; Amdt. 195-39, 53
FR 24942, July 1, 1988; Amdt. 195-39C, 53 FR 36942, Sept. 22, 1988;
Amdt. 195-42, 54 FR 32342, Aug. 7, 1989; Amdt. 195-44, 54 FR 40878, Oct.
4, 1989; Amdt. 195-50, 59 FR 17275, Apr. 12, 1994; Amdt. 195-61, 63 FR
7721, Feb. 17, 1998\]

**§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 Information Officer, [Research
and Special Programs Administration]{.mark} [Pipeline Hazardous
Materials Safety Administration]{.underline}, Department of
Transportation, 400 Seventh Street, SW., Washington, DC 20590.

\[Amdt. 195-47, 56 FR 63764, Dec. 5, 1991 as amended by Amdt. 195-63, 63
FR 37500, July 13, 1998[; 70 FR 11135, Mar. 8, 2005]{.underline}\]

**§195.58 Address for written reports.**

Each written report required by this subpart must be made to the
Information Resources Manager, Office of Pipeline Safety, [Research and
Special Programs Administration]{.mark} [Pipeline Hazardous Materials
Safety Administration]{.underline}, U.S. Department of Transportation,
Room 7128, 400 Seventh Street SW., Washington, DC 20590. 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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt 195-5, 38 FR 2977,
Jan. 31, 1973; Amdt. 195-22, 46 FR 38357, July 27, 1981, Amdt. 195-23,
47 FR 32719, July 29, 1982; Amdt 195-34, 50 FR 34470, Aug. 26, 1985;
Amdt. 195-39, 53 FR 24942, July 1, 1988; Amdt. 195-50, 59 FR 17275, Apr.
12, 1994; Amdt. 195-55, 61 FR 18512, Apr. 26, 1996; Amdt. 195-81, 69 FR
32886, June 14, 2004; [70 FR 11135, Mar. 8, 2005]{.underline}\]

**§195.59 Abandoned underwater facilities report.**

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
*www.npms.[rspa]{.mark}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 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 [Information Officer,]{.mark} [Research and Special
Programs Administration]{.mark} [Pipeline Hazardous Materials Safety
Administration]{.underline}, Department of Transportation, Room
[2103]{.underline}[7128]{.mark}, 400 Seventh Street, SW, Washington DC
20590; fax (202) 366-4566; e-mail, *roger.little@[rspa.]{.mark}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.

\(b\) [\[Reserved\].]{.underline}[Data on pipeline facilities abandoned
before October 10, 2000 must be filed by before April 10, 2001.
Operators may submit reports by mail, fax or e-mail to the Information
Officer, Research and Special Programs Administration Pipeline Hazardous
Materials Safety Administration, Department of Transportation, Room
7128, 400 Seventh Street, SW, Washington DC 20590; fax (202) 366-4566;
e-mail, roger.little@rspa.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.]{.mark}

\[Amdt. 195-69, 65 FR 54440, Sept. 8, 2000 [as amended by 70 FR 11135,
Mar. 8, 2005; Amdt. 195-86c, 72 FR 4655, February 1, 2007]{.underline}\]

**§195.60 Operator assistance in investigation.**

If the Department of Trans-portation 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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981\]

**§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 Information Resources Manager,
Office of Pipeline Safety, Department of Transportation, Washington, DC
20590.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt 195-5, 38 FR 2977,
Jan. 31, 1973; Amdt. 195-22, 46 FR 38357, July 27, 1981; Amdt. 195-23,
47 FR 32719, July 29, 1982\]

**§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.

\[Amdt. 195-34, 50 FR 34470, Aug. 26, 1985\]

# 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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981\]

**§195.101 Qualifying metallic com-ponents 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 rat-ings.

\[Amdt. 195-28, 48 FR 30637, July 5, 1983\]

**§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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981; Amdt. 195-45, 56 FR 26922, June 12, 1991\]

**§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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981\]

**§195.106 Internal design pressure.**

\(a\) Internal design pressure for the pipe in a pipeline is determined
in accordance with the following formula:

***P = (2 St/D) x E x 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 deter-mined by performing all of the tensile
tests of API Specification 5L on randomly selected specimens with the
following number of tests:

(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.

(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      |
+-----------------------+-----------------------------------+-----------+
| ASTM106               | Seamless                          | 1.00      |
+-----------------------+-----------------------------------+-----------+
| ASTM                  | Seamless                          | 1.00      |
+-----------------------+-----------------------------------+-----------+
| A333/A333M            | 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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-2, 35 FR 17183,
Nov. 7, 1970; Amdt. 195-11, 41 FR 34035, Aug. 12, 1976; Amdt 195-21, 46
FR 10157, Feb. 2, 1981; Amdt. 195-22, 46 FR 38357, July 27, 1981; Amdt.
195-30, 49 FR 7567, Mar. 1, 1984; Amdt. 195-37, 51 FR 15333, Apr. 23,
1986; Amdt. 195-40, 54 FR 5625, Feb. 6, 1989; Amdt. 195-48, 58 FR 14519,
Mar. 18, 1993; Amdt. 195-50, 59 FR 17275, Apr. 12, 1994; Amdt. 195-52,
59 FR 33388, June 28, 1994; Amdt. 195-63, 63 FR 37500, July 13, 1998\]

**§195.108 External pressure.**

Any external pressure that will be exerted on the pipe must be provided
for in designing a pipeline system.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981\]

**§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, §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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt 195-9, 41 FR 13590,
Mar. 31, 1976; Amdt. 195-22, 46 FR 38357, July 27, 1981; Amdt. 195-48,
58 FR 14519, Mar. 18, 1993\]

**§195.111 Fracture propagation.**

A carbon dioxide pipeline system must be designed to mitigate the
effects of fracture propagation.

\[Amdt. 195-45, 56 FR 26922, June 12, 1991\]

**§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 4½ 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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981; Amdt. 195-52, 59 FR 33388, June 28, 1994; Amdt. 195-63,
63 FR 37500, July 13, 1998\]

**§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 §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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-2, 35 FR 17183,
Nov. 7, 1970; Amdt. 195-22, 46 FR 38357, July 27, 1981\]

**§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 [10]{.underline}[5]{.mark} of API Standard 6D
[(incorporated by reference, *see* §195.3)]{.underline}.

\(e\) 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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-2, 35 FR 17183,
Nov. 7, 1970; Amdt 195-9, 41 FR 13590, Mar. 31, 1976; Amdt. 195-22, 46
FR 38357, July 27, 1981; Amdt. 195-45, 56 FR 26922, June 12, 1991[;
Amdt. 195-86, 71 FR 33402, June 9, 2006]{.underline}\]

**§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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt 195-9, 41 FR 13590,
Mar. 31, 1976; Amdt 195-21, 46 FR 10157, Feb. 2, 1981; Amdt. 195-22, 46
FR 38357, July 27, 1981; 47 FR 32721, July 29, 1982, Amdt. 195-48, 58 FR
14519, Mar. 18, 1993\]

**§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,

\(7\) Other piping that the Admini-strator 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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981; Amdt. 195-50, 59 FR 17275, Apr. 12, 1994; Amdt. 195-63,
63 FR 37500, July 13, 1998\]

**§195.122 Fabricated branch connec-tions.**

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

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981\]

**§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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt 195-9, 41 FR 13590,
Mar. 31, 1976; Amdt. 195-22, 46 FR 38357, July 27, 1981\]

**§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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981\]

**§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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981\]

**§195.130 Fabricated assemblies.**

Each fabricated assembly to be installed in a pipeline system must meet
the applicable requirements of this subpart.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981\]

**§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 m^3^)
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 gas (LPG) must
be designed and constructed in accordance with API Standard 2510.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981; Amdt. 195-66, 64 FR 15926, April 2, 1999\]

**§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.

\[Amdt 195-62 63 FR 36373, July 6, 1998\]

# 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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981\]

**§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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981\]

**§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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981; Amdt. 195-52, 59 FR 33388, June 28, 1994\]

**§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.

\[Amdt. 195-66, 64 FR 15926, April 2, 1999\]

**§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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981\]

**§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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981; Amdt. 195-63, 63 FR 37500, July 13, 1998\]

**§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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981; Amdt. 195-63, 63 FR 37500, July 13, 1998\]

**§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 12¾ 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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-10, 41 FR 26106,
Aug. 16, 1976; Amdt. 195-12, 42 FR 42865, Aug. 25, 1977; Amdt. 195-12C,
42 FR 60148, Nov. 25 1977; Amdt. 195-22, 46 FR 38357, July 27, 1981;
Amdt. 195-52, 59 FR 33388, June 28, 1994; Amdt. 195-63, 63 FR 37500,
July 13, 1998\]

**§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 (ibr, *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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981; Amdt. 195-38, 51 FR 20294, June 4, 1986; Amdt. 195-81, 69
FR 32886, June 14, 2004\]

**§195.216 Welding: Miter joints.**

A miter joint is not permitted (not including deflections up to 3° that
are caused by misalignment).

\[Amdt. 195-10, 41 FR 26106, Aug. 16, 1976 as amended by Amdt. 195-22,
46 FR 38357, July 27, 1981\]

**§195.222 Welders: Qualification of welders.**

\(a\) Each welder must be qualified in accordance with Section 6 of API
1104 (ibr, *see* §195.3) or Section IX of the ASME Boiler and Pressure
Vessel Code, (ibr, *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

\(2\) Had one welded tested and found acceptable under section 9 of API
1104 (ibr, *see* §195.3).

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-8, 40 FR 10181,
Mar. 5, 1975; Amdt. 195-8A, 40 FR 27222, June 27, 1975; Amdt. 195-21, 46
FR 10157, Feb. 2, 1981; Amdt. 195-22, 46 FR 38357, July 27, 1981; Amdt.
195-32, 49 FR 36859, Sept. 20, 1984; Amdt. 195-38, 51 FR 20294, June 4,
1986; Amdt. 195-79, 68 FR 53526, Sept. 11, 2003; Amdt. 195-81, 69 FR
32886, June 14, 2004; Amdt. 195-81A, 69 FR 54591, Sept. 9, 2004\]

**§195.224 Welding: Weather.**

Welding must be protected from weather conditions that would impair the
quality of the completed weld.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981\]

**§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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981\]

**§195.228 Welds and welding inspection: Standards of acceptability.**

\(a\) Each weld and welding must be inspected to ensure 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 (ibr, *see* §195.3) applies to the weld, the
acceptability of the weld may be determined under that appendix.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt 195-8, 40 FR 10181,
Mar. 5, 1975; Amdt 195-8A, 40 FR 27222, June 27, 1975; Amdt 195-21, 46
FR 10157, Feb. 2, 1981; Amdt. 195-22, 46 FR 38357, July 27, 1981; Amdt.
195-52, 59 FR 33388, June 28, 1994[;]{.underline} Amdt. 195-81, 69 FR
32886, June 14, 2004\]

**§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 pipe lay 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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-11, 41 FR 34035,
Aug. 12, 1976; Amdt. 195-22, 46 FR 38357, July 27, 1981; Amdt. 195-29,
48 FR 48669, Oct. 20, 1983\]

**§195.234 Welds: Nondestructive**

**testing.**

\(a\) A weld may be nondestructively tested by an 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, 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 tie-ins of replacement sections,
100 percent of the girth welds must be nondestructively tested.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-1, 35 FR 5332,
Mar. 31, 1970; Amdt. 195-11, 41 FR 34035, Aug. 12, 1976; Amdt. 195-22,
46 FR 38357, July 27, 1981; Amdt. 195-26, 48 FR 9013, Mar. 3, 1983;
Amdt. 195-35, 50 FR 37191, Sep. 12, 1985; Amdt. 195-52, 59 FR 33388,
June 28, 1994\]

**§195.246 Installation of pipe in a ditch.**

\(a\) All pipe installed in a ditch must be installed in a manner that
minimized 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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-11, 41 FR 34035,
Aug. 12, 1976; Amdt. 195-22, 46 FR 38357, July 27, 1981; Amdt. 195-52,
59 FR 33388, June 28, 1994; Amdt. 195-82, 69 FR 48400, Aug. 10, 2004\]

**§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:

  ------------------------------- ---------------------------------------
                                  Cover (inches) (millimeters)

  ------------------------------- ---------------------------------------

> 4

  ------------------------------- -------------------- --------------------
  Location                        For normal           For rock excavation
                                  excavation           ^1^

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

  Crossings of inland bodies of   48 (1219)            18 (457)
  water with a width of at least                       
  100 ft (30 m) from high water                        
  mark to high water mark                              

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

  Deepwater port safety zone      48 (1219)            24 (610)

  Gulf of Mexico and its inlets   36 (914)             18 (457)
  in waters less than 15 feet                          
  (4.6 meters) deep as measured                        
  from mean low water                                  

  Other offshore areas under      [36                  [18
  water less than 12 ft (3.7      (914)]{.underline}   (457)]{.underline}
  meters) deep as measured from                        
  mean low water                                       

  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.

\[Amdt. 195-22, 46 FR 38357, July 27, 1981; 47 FR 32721, July 29, 1982,
as amended by Amdt. 195-52, 59 FR 33388, June 28, 1994; 59 FR 36256,
July 15, 1994; Amdt. 195-63, 63 FR 37500, July 13, 1998; Amdt. 195-82,
69 FR 48400, Aug. 10, 2004\]

**§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
reduce if adequate provisions are made for corrosion control.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981; Amdt. 195-63, 63 FR 37500, July 13, 1998\]

**§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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981; Amdt. 195-79, 68 FR 53526, Sept. 11, 2003\]

**§195.254 Aboveground components.**

\(a\) Any component may be installed aboveground in the following
situations, if the other applicable requirements of this part are
compiled with:

\(1\) Overhead crossings of high-ways, 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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981\]

**§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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981\]

**§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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-11, 41 FR 34035,
Aug. 12, 1976; Amdt. 195-22, 46 FR 38357, July 27, 1981\]

**§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 high-water 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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt 195-5, 38 FR 2977,
Jan. 31, 1973; Amdt. 195-11, 41 FR 34035, Aug. 12, 1976; Amdt. 195-22,
46 FR 38357, July 27, 1981; Amdt. 195-50, 59 FR 17275, Apr. 12, 1994;
Amdt. 195-63, 63 FR 37500, July 13, 1998\]

**§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.

\(2\) 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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981; Amdt. 195-52, 59 FR 33388, June 28, 1994\]

**§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 [S]{.mark}[s]{.underline}ection
[4.3.2.3.2]{.underline}[2-3.4.3]{.mark}; and

\(ii\) Impoundment by drainage to a remote impounding area must be
installed in accordance with [S]{.mark}[s]{.underline}ection
[4.3.2.3.1]{.underline}[2-3.4.2]{.mark}.

\(2\) For tanks built to API Standard 2510, the installation of
impoundment must be in accordance with [S]{.mark}[s]{.underline}ection
[5]{.underline}[3]{.mark} or [11]{.underline}[9]{.mark} of API Standard
2510 [(incorporated by reference, *see* §195.3)]{.underline}.

\(c\) 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 must be in accordance with Section
4, and Appendices B and C, of API Specification 12F.

\(2\) 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.

\(3\) Pressure-relieving and emergency vacuum-relieving devices
installed on low pressure tanks built to API Standard 620 must be in
accordance with [S]{.mark}[s]{.underline}ection
[9]{.underline}[7]{.mark} of API Standard 620 [(incorporated by
reference, *see* §195.3)]{.underline} and its references to the normal
and emergency venting requirements in API Standard 2000 [(incorporated
by reference, *see* §195.3)]{.underline}.

\(4\) Pressure and vacuum-relieving devices installed on high pressure
tanks built to API Standard 2510 must be in accordance with
[S]{.mark}[s]{.underline}ections [7]{.underline}[5]{.mark} or
[11]{.underline}[9]{.mark} of API Standard 2510 [(incorporated by
reference, *see* §195.3)]{.underline}.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981; Amdt. 195-66, 64 FR 15926, April 2, 1999[; Amdt. 195-86,
71 FR 33402, June 9, 2006]{.underline}\]

**§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.

\(b\) 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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981; Amdt. 195-34, 50 FR 34470, Aug. 26, 1985\]

# 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.

\[Amdt. 195-2, 35 FR 17183, Nov. 7, 1970 as amended by Amdt. 195-17, 45
FR 59161, Sept. 8, 1980; Amdt. 195-22, 46 FR 38357, July 27, 1981; Amdt.
195-33, 50 FR 15895, Apr. 23, 1985; Amdt. 195-51, 59 FR 29379, June 7,
1994\]

**§195.302 General requirements.**

\(a\) Except as otherwise provided in this section and in §195.305(b),
no operator may operator 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 con-structed before January 8, 1971; (ii)
An interstate offshore gathering line constructed before August 1, 1977;

\(iii\) An intrastate pipeline con-structed before October 21, 1985; or

\(iv\) A low-stress pipeline con-structed 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 risk-based 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 pipelines 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).

\[Amdt. 195-2, 35 FR 17183, Nov. 7, 1970 as amended by Amdt. 195-17, 45
FR 59161, Sept. 8, 1980; Amdt. 195-22, 46 FR 38357, July 27, 1981; Amdt.
195-33, 50 FR 15895, Apr. 23, 1985; Amdt. 195-33C, 50 FR 38659, Sept.
24; 1985; Amdt. 195-51, 59 FR 29379, June 7, 1994; Amdt. 195-51B, 61 FR
43026, Aug. 20, 1996, Amdt. 195-53, 59 FR 35465, July 12, 1994; Amdt.
195-58, 62 FR 54591, Oct. 21, 1997; Amdt. 195-63, 63 FR 37500, July 13,
1998, Amdt. 195-65, 63 FR 59475, Nov. 4, 1998\]

**§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 risk-based 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 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[^2]

\(i\) 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 deg. 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:

[Table:---§195.303---Test deadlines]{.smallcaps}

+---------------------------+-----------------------+-------------------+
| Pipeline                  | Risk                  | Test              |
|                           |                       |                   |
| segment                   | classification        | deadline          |
+---------------------------+-----------------------+-------------------+
| Pre-1970 Pipe susceptible | C or B                | 12/7/2000         |
| to longitudinal seam      |                       |                   |
| failures \[defined in     |                       |                   |
| §195.303(c) & (d)\]       |                       |                   |
+---------------------------+-----------------------+-------------------+
|                           | A                     | 12/7/2002         |
+---------------------------+-----------------------+-------------------+
| All Other                 | C                     | 12/7/2002         |
|                           |                       |                   |
| Pipeline                  |                       |                   |
+---------------------------+-----------------------+-------------------+
| Segments.                 | B                     | 12/7/2004         |
+---------------------------+-----------------------+-------------------+
|                           | A                     | Additional        |
|                           |                       | testing not       |
|                           |                       | required.         |
+---------------------------+-----------------------+-------------------+
|                           |                       |                   |
+---------------------------+-----------------------+-------------------+

\(g\) 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.

\[Amdt. 195-65, 63 FR 59475, Nov. 4, 1998\]

**§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 test, for at least an
additional 4 continuous hours at a pressure equal to 110 percent, or
more, of the maximum operating pressure.

\[Amdt. 195-51, 59 FR 29379, June 7, 1994; Amdt. 195-65, 63 FR 59475,
Nov. 4, 1998\]

**§195.305 Testing of components.**

\(a\) Each pressure test under §195.302 must test all pipe and attached
fittings, including com-ponents, 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 hydro-statically tested at the factory; or

\(2\) The component was manu-factured 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.

\[Amdt. 195-2, 35 FR 17183, Nov. 7, 1970 as amended by Amdt. 195-22, 46
FR 38357, July 27, 1981; Amdt. 195-51, 59 FR 29379, June 7, 1994; Amdt.
195-52, 59 FR 33388, June 28, 1994; Amdt. 195-65, 63 FR 59475, Nov. 4,
1998\]

**§195.306 Test medium.**

\(a\) Except as provided in paragraph (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.

\(d\) Air on inert gas may be used as the test medium in low-stress
pipelines.

\[Amdt. 195-2, 35 FR 17183, Nov. 7, 1970 as amended by Amdt. 195-3, 36
FR 14618, May 4, 1971; Amdt. 195-11, 41 FR 34035, Aug. 12, 1976; Amdt.
195-22, 46 FR 38357, July 27, 1981; Amdt. 195-45, 56 FR 26922, June 12,
1991; Amdt. 195-51, 59 FR 29379, June 7, 1994; Amdt. 195-51A, 59 FR
41259, Aug. 11, 1994; Amdt. 195-51B, 59 FR 54328, Oct. 23, Amdt. 195-53,
59 FR 35471, July 12, 1994; Amdt. 195-63, 63 FR 37500, July 13, 1998\]

**§195.307 Pressure testing aboveground breakout tanks.**

\(a\) For aboveground breakout tanks built to 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 12F.

\(b\) 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]{.underline}[5.18]{.mark} of API Standard 620 [(incorporated by
reference, *see* §195.3)]{.underline}.

\(c\) For aboveground breakout tanks built to API Standard 650 and first
placed in service after October 2, 2000, hydrostatic and pneumatic
testing must be in accordance with section 5.3 of API Standard 650.

\(d\) 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.

\[Amdt. 195-66, 64 FR 15926, April 2, 1999 [as amended by Amdt. 195-86,
71 FR 33402, June 9, 2006]{.underline}\]

**§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.

\[Amdt. 195-2, 35 FR 17183, Nov. 7, 1970 as amended by Amdt. 195-22, 46
FR 38357, July 27, 1981; Amdt. 195-51, 59 FR 29379, June 7, 1994\]

**§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.

\[Amdt. 195-2, 35 FR 17183, Nov. 7, 1970 as amended by Amdt. 195-22, 46
FR 38357, July 27, 1981; Amdt. 195-34, 50 FR 34470, Aug. 26, 1985; Amdt.
195-51, 59 FR 29379, June 7, 1994; Amdt. 195-63, 63 FR 37500, July 13,
1998; Amdt. 195-79, 68 FR 53526, Sept. 11, 2003\]

**Subpart F--Operation and Mainte-nance**

**§195.400 Scope.**

This subpart prescribes minimum requirements for operating and
maintaining pipeline systems con-structed with steel pipe.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981\]

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

\(b\) Whenever an operator discovers any condition that could adversely
affect the safe operation of its pipeline system, it shall correct it
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.

\(c\) Except as provided by §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, 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 con-struction was begun after July 11, 1991
that transports carbon dioxide.

\(5\) A low-stress pipeline on which construction was begun after August
10, 1994.

\[Amdt. 195-15, 44 FR 41197, July 16, 1979 as amended by Amdt. 195-16,
44 FR 70164, Dec. 6, 1979; Amdt. 195-22, 46 FR 38357, July 27, 1981;
Amdt. 195-33, 50 FR 15895, Apr. 23, 1985; Amdt. 195-36, 51 FR 15005,
Apr. 22, 1986, Amdt. 195-45, 56 FR 26922, June 12, 1991; Amdt. 195-53,
59 FR 35465, July 12, 1994\]

**§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
manner designed to assure operation within the limits prescribed by
paragraph §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 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 §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.

\(d\) *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 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.

\(f\) *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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-11, 41 FR 34035,
Aug. 12, 1976; Amdt. 195-13, 43 FR 6786, Feb. 16, 1979; Amdt. 195-15, 44
FR 41197, July 16, 1979; Amdt. 195-16, 44 FR 70164, Dec. 6, 1979; Amdt.
195-22, 46 FR 38357, July 27, 1981; Amdt. 195-24, 47 FR 46850, Oct. 21,
1982; Amdt. 195-39, 53 FR 24942, July 1, 1988; Amdt. 195-45, 56 FR
26922, June 12, 1991; Amdt. 195-46, 56 FR 31087, July 9, 1991; Amdt.
195-49, 59 FR 6579, Feb. 11, 1994; Amdt. 195-55, 61 FR 18512, Apr. 26,
1996; Amdt. 195-69, 65 FR 54440, Sept. 8, 2000; Amdt. 195-73, 66 FR
66993, Dec. 27, 2002\]

**§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:

\(1\) 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.

\[Amdt. 195-15, 44 FR 41197, July 16, 1979 as amended by Amdt. 195-22,
46 FR 38357, July 27, 1981; Amdt. 195-24, 47 FR 46850, Oct. 21, 1982;
Amdt. 195-45, 56 FR 26920, June 12, 1991; Amdt. 192-67, 64 FR 46853,
Aug. 27, 1999; Amdt. 195-78, 68 FR 53526, Sept. 11, 2003\]

**§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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-1, 35 FR 5332,
Mar. 31, 1970; Amdt. 195-2, 35 FR 17183, Nov. 7, 1970; Amdt. 195-22, 46
FR 38357, July 27, 1981; Amdt. 195-34, 50 FR 34470, Aug. 26, 1985; Amdt.
195-73, 66 FR 66993, Dec. 27, 2002\]

**§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
in-service 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)).

\[Amdt. 195-66, 64 FR 15926, April 2, 1999\]

**§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 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 12¾ in (324 mm) or less outside diameter and is
not tested to yield under this paragraph, 200 p.s.i. (1379 kPa).

\(2\) 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 §195.304.

\(5\) 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.

\[Amdt. 195-2, 35 FR 17183, Nov. 7, 1970 as amended by Amdt. 195-17, 45
FR 59161, Sep. 8, 1980; Amdt. 195-22, 46 FR 38357, July 27, 1981; Amdt.
195-33, 50 FR 15895, Apr. 23, 1985; Amdt. 195-33C, 50 FR 38659, Sep. 24,
1985; Amdt. 195-51, 59 FR 29379, June 7, 1994; Amdt. 195-52, 59 FR
33388, June 28, 1994; Amdt. 195-63, 63 FR 37500, July 13, 1998; Amdt.
195-65, 63 FR 59475, Nov. 4, 1998\]

**§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 public
officials during emergency conditions, including a natural disaster.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-15, 44 FR 41197,
July 16, 1979; Amdt. 195-22, 46 FR 38357, July 27, 1981\]

**§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 ¼-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

\(ii\) The local government maintains current substructure records.

\(c\) Each operator shall provide line marking at locations where the
line is aboveground in areas that are accessible to the public.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981; Amdt. 195-27, 48 FR 25206, June 6, 1983, Amdt. 195-45, 56
FR 26922, June 12, 1991; Amdt. 195-54, 60 FR 14646, Mar. 20, 1995; Amdt.
195-63, 63 FR 37500, July 13, 1998\]

**§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 mean 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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981; Amdt. 195-24, 47 FR 48650, Oct. 21, 1982; Amdt. 195-52,
59 FR 33388, June 28, 1994\]

**§195.413 Underwater inspection and reburial of pipelines in the Gulf
of Mexico and its inlets.**

\(a\) Except for gathering lines of 4½ 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.

\[Amdt. 195-47, 56 FR 63764, Dec. 5, 1991, as amended by Amdt. 195-52,
59 FR 33388, June 28, 1994; Amdt. 195-63, 63 FR 37500, July 13, 1998;
Amdt. 195-82, 69 FR 48400, Aug. 10, 2004[\]]{.underline}

**§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 7½ 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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981; Amdt. 195-24, 47 FR 46850, Oct. 21, 1982\]

**§195.422 Pipeline repairs.**

\(a\) Each operator shall, in repairing its pipeline systems, insure
that the repairs are made in a safe manner and 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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981\]

**§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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt 195-7, 39 FR 19780,
June 4, 1974; Amdt. 195-15, 44 FR 41197, July 16, 1979; Amdt. 195-22, 46
FR 38357, July 27, 1981; Amdt. 195-63, 63 FR 37500, July 13, 1998\]

**§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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-15, 44 FR 41197,
July 16, 1979; Amdt. 195-22, 46 FR 38357, July 27, 1981\]

**§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 7½ 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 the inspection and testing of overfill protection systems.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-4, 37 FR 18733,
Sep. 15, 1972; Amdt. 195-15, 44 FR 41197, July 16, 1979; Amdt. 195-22,
46 FR 38357, July 27, 1981; Amdt. 195-24, 47 FR 46850, Oct. 21, 1982;
Amdt. 195-66, 64 FR 15926, April 2, 1999\]

**§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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981\]

**§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 shall inspect the physical integrity of in-

service atmospheric and low-pressure steel aboveground breakout tanks
according to section 4 of API Standard 653. 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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981; Amdt. 195-24, 47 FR 46850, Oct. 21, 1982; Amdt. 195-66,
64 FR 15926, April 2, 1999\]

**§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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981; Amdt. 195-79, 68 FR 53526, Sept. 11, 2003\]

**§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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981\]

**§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.

\[Part 195 - Org., Oct. 4, 1969 as amended by Amdt. 195-22, 46 FR 38357,
July 27, 1981\]

**§195.440 Public awareness.**

[Each operator shall establish a continuing educational program to
enable the public, appropriate govern-ment organizations and persons
engaged in excavation-related activities to recognize a hazardous liquid
or a carbon dioxide pipeline emergency and to report it to the operator
or the fire, police, or other appropriate public officials. The program
must be conducted in English and in other languages commonly understood
by a significant number and concentration of non-English speaking
population in the operator\'s operating areas.]{.mark}

[(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[ibr]{.mark}, *see* §195.3).]{.underline}

[(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.]{.underline}

[(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.]{.underline}

[(d) The operator\'s program must specifically include provisions to
educate the public, appropriate government organizations, and persons
engaged in excavation related activities on:]{.underline}

[(1) Use of a one-call notification system prior to excavation and other
damage prevention activities;]{.underline}

[(2) Possible hazards associated with unintended releases from a
hazardous liquid or carbon dioxide pipeline facility;]{.underline}

[(3) Physical indications that such a release may have
occurred;]{.underline}

[(4) Steps that should be taken for public safety in the event of a
hazardous liquid or carbon dioxide pipeline release; and]{.underline}

[(5) Procedures to report such an event.]{.underline}

[(e) The program must include activities to advise affected
municipalities, school districts, businesses, and residents of pipeline
facility locations.]{.underline}

[(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.]{.underline}

[(g) The program must be conducted in English and in other languages
commonly understood by a significant number and concentration of the
non-English speaking population in the operator\'s area.]{.underline}

[(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.]{.underline}

[(i) The operator\'s program documentation and evaluation results must
be available for periodic review by appropriate regulatory
agencies.]{.underline}

\[Amdt. 195-15, 44 FR 41197, July 16, 1979 as amended by Amdt. 195-22,
46 FR 38357, July 27, 1981; Amdt. 195-45, 56 FR 26922, June 12, 1991[;
Amdt. 195-84, 70 FR 28833, May 19, 2005; Amdt. 195-86, 71 FR 33402, June
9, 2006]{.underline}\]

**§195.442 Damage prevention program.**

\(a\) Except as provided in paragraph (d) of this section, each operator
of a buried pipeline shall 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" include excavation, blasting, boring, tunneling,
backfilling, the removal of aboveground structures by either explosive
or mechanical means, and other earth moving 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 one-call system, but such participation does not relieve the
operator of 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) of 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 pro-gram 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 the 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
excava-tion 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 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 inspec-tion 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.

\[Amdt. 195-54, 53 FR 14646, Mar. 20, 1995; Amdt. 195-60, 62 FR 61695,
Nov. 19, 1997\]

**§195.444 CPM leak detection.**

Each computational pipeline monitoring (CPM) leak detection system
installed on a hazardous liquid pipeline transporting liquid in a single
phase (without gas in the liquid) must comply with API 1130 in
operating, maintaining, testing, record keeping, and dispatcher training
of the system.

\[Amdt. 195-62, 63 FR 36373, July 6, 1998\]

**[High Consequence Areas]{.smallcaps}**

**§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.

\[Amdt. 195-70, 65 FR 75378, Dec. 1, 2000\]

**[Pipeline Integrity Management]{.smallcaps}**

**§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.

\(3\) 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;
[or]{.mark}

[(C) External corrosion direct assessment in accordance with §195.588;
or]{.underline}

([C]{.mark}[D]{.underline}) 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     And assess at least
                          assessments not later than 50 percent of the
                          the following date         line pipe on an
                          according to a schedule    expedited basis,
                          that prioritizes           beginning with the
                          assessments                highest risk pipe,
                                                     not later than:

  Category 1              March 31, 2008.            September 30, 2004.

  Category 2              February 17, 2009.         August 16, 2005.

  Category 3              Date the pipeline begins   Not applicable.
                          operation.                 
  ----------------------- -------------------------- ---------------------

\(2\) *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);

\(4\) 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 that 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 that the condition is unlikely to pose a threat to the long-term
integrity of the pipeline. A reduction in operating pressure cannot
exceed 365 days without an operator taking further remedial action to
ensure the safety of the pipeline. An operator must comply with §195.422
when making a repair.

\(2\) *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 that
prioritizes the conditions for evaluation and remediation. If an
operator cannot meet the schedule for any condition, the operator must
justify the reasons why it cannot meet the schedule and that the changed
schedule will not jeopardize public safety or environmental protection.
An operator must notify OPS if the operator cannot meet the schedule and
cannot provide safety through a temporary reduction in operating
pressure. An operator must send the notice to the address specified in
paragraph (m) of this section.

\(4\) *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 451.7 of ASME/ANSI 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.

\(i\) *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 intervals not
to exceed five (5) years for continually assessing the line pipe\'s
integrity. An operator must base the assessment intervals on the risk
the line pipe poses 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; [or]{.mark}

[(iii) External corrosion direct assessment in accordance with §195.588;
or]{.underline}

([iii]{.mark}[iv]{.underline}) 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.

\(m\) *Where does an operator send a notification?* An operator must
send any notification required by this section to the Information
Resources Manager, Office of Pipeline Safety, [Research and Special
Programs Administration]{.mark} [Pipeline Hazardous Materials Safety
Administration]{.underline}, U.S. Department of Transportation, Room
7128, 400 Seventh Street SW, Washington DC 20590, or to the facsimile
number (202) 366-7128.

\[Amdt. 195-70, 65 FR 75378, Dec. 1, 2000 as amended by Amdt. 195-74, 67
FR 1650, Jan. 14, 2002; Amdt. 195-76, 67 FR 2136, Jan. 16, 2002, Amdt.
195-76a, 67 FR 46911, July 17, 2002[; 70 FR 11135, Mar. 8, 2005; Amdt.
195-85, 70 FR 61571, Oct. 25, 2005]{.underline}\]

**Subpart G ---Qualification of Pipeline Personnel**

**§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.

\[Amdt. 195-67, 64 FR 46853, Aug. 27, 1999 as amended by Amdt. 195-72,
66 FR 43523, Aug. 20, 2001\]

**§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; [and]{.mark}

\(g\) Identify those covered tasks and the intervals at which evaluation
of the individual\'s qualifications is needed~~.~~[;]{.underline}

> [(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]{.underline}
>
> [(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.]{.underline}

\[Amdt. 195-67, 64 FR 46853, Aug. 27, 1999 [as amended by Amdt. 195-84,
70 FR 10322, Mar. 3, 2005]{.underline}\]

**§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.

\[Amdt. 195-67, 64 FR 46853, Aug. 27, 1999\]

**§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.]{.underline}

\(b\) 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.]{.underline}

\[Amdt. 195-67, 64 FR 46853, Aug. 27, 1999 as amended by Amdt. 195-72,
66 FR 43523, Aug. 20, 2001[; Amdt. 195-84, 70 FR 10322, Mar. 3,
2005]{.underline}\]

**Subpart H---Corrosion Control**

**§195.551 What do the regulations in this subpart cover?**

This subpart prescribes minimum requirements for protecting steel
pipelines against corrosion.

\[Amdt. 195-73, 66 FR 66993, Dec. 27, 2002\]

**§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.]{.underline}

*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 post-assessment to evaluate the threat of external corrosion to the
integrity of a pipeline.]{.underline}

*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.

\[Amdt. 195-73, 66 FR 66993, Dec. 27, 2002[; Amdt. 195-85, 70 FR 61571,
Oct. 25, 2005]{.underline}\]

**§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 §195.402(c)(3) for which they are responsible for
insuring compliance.

\[Amdt. 195-73, 66 FR 66993, Dec. 27, 2002\]

**§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.

\[Amdt. 195-73, 66 FR 66993, Dec. 27, 2002\]

**§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.

\[Amdt. 195-73, 66 FR 66993, Dec. 27, 2002\]

**§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.

\[Amdt. 195-73, 66 FR 66993, Dec. 27, 2002\]

**§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.[^3] 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).

\[Amdt. 195-73, 66 FR 66993, Dec. 27, 2002\]

**§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 (79.5m^3^) 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.

\[Amdt. 195-73, 66 FR 66993, Dec. 27, 2002\]

**§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.

\[Amdt. 195-73, 66 FR 66993, Dec. 27, 2002\]

**§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.

\[Amdt. 195-73, 66 FR 66993, Dec. 27, 2002\]

**§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 Standard RP
0169[-96]{.mark} (incorporated by reference, *see* §195.3).

\[Amdt. 195-73, 66 FR 66993, Dec. 27, 2002 [as amended by Amdt. 195-86,
71 FR 33402, June 9, 2006]{.underline}\]

**§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 [before December 29, 2003 or]{.mark} not more than 2
years after cathodic protection is installed, whichever comes later, 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 Standard RP 0169[-96]{.mark} (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.

  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      |
| Reverse current switch           | exceeding 2½ months.              |
|                                  |                                   |
| 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).

\[Amdt. 195-73, 66 FR 66993, Dec. 27, 2002[;]{.mark} [as amended
by]{.underline} Amdt. 195-73A, 67 FR 70118, Nov. 20, 2002[: Amdt.
195-86, 71 FR 33402, June 9, 2006]{.underline}\]

**§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.

\[Amdt. 195-73, 66 FR 66993, Dec. 27, 2002\]

**§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.

\[Amdt. 195-73, 66 FR 66993, Dec. 27, 2002\]

**§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
each calendar year, but with intervals not exceeding 7½ 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.

\[Amdt. 195-73, 66 FR 66993, Dec. 27, 2002\]

**§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.

\[Amdt. 195-73, 66 FR 66993, Dec. 27, 2002\]

**§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-to-air 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.

\[Amdt. 195-73, 66 FR 66993, Dec. 27, 2002\]

**§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.

\[Amdt. 195-73, 66 FR 66993, Dec. 27, 2002\]

**§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.

\[Amdt. 195-73, 66 FR 66993, Dec. 27, 2002\]

**[§195.588 What standards apply to direct assessment?]{.underline}**

[(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.]{.underline}

[(b) The requirements for performing external corrosion direct
assessment are as follows:]{.underline}

[(1) *General.* You must follow the requirements of NACE Standard
RP0502-2002 (incorporated by reference, *see* §195.3). Also, you must
develop and implement an ECDA plan that includes procedures addressing
pre-assessment, indirect examination, direct examination, and
post-assessment.]{.underline}

[(2) *Pre-assessment*. In addition to the requirements in Section 3 of
NACE Standard RP0502-2002, the ECDA plan procedures for pre-assessment
must include---]{.underline}

[(i) Provisions for applying more restrictive criteria when conducting
ECDA for the first time on a pipeline segment;]{.underline}

[(ii) The basis on which you select at least two different, but
complementary, indirect assessment tools to assess each ECDA region;
and]{.underline}

[(iii) If you utilize an indirect inspection method not described in
Appendix A of NACE Standard RP0502-2002, you must demonstrate the
applicability, validation basis, equipment used, application procedure,
and utilization of data for the inspection method.]{.underline}

[(3) *Indirect examination*. In addition to the requirements in Section
4 of NACE Standard RP0502-2002, the procedures for indirect examination
of the ECDA regions must include---]{.underline}

[(i) Provisions for applying more restrictive criteria when conducting
ECDA for the first time on a pipeline segment;]{.underline}

[(ii) Criteria for identifying and documenting those indications that
must be considered for excavation and direct examination, including at
least the following:]{.underline}

[(A) The known sensitivities of assessment tools;]{.underline}

[(B) The procedures for using each tool; and]{.underline}

[(C) The approach to be used for decreasing the physical spacing of
indirect assessment tool readings when the presence of a defect is
suspected;]{.underline}

[(iii) For each indication identified during the indirect examination,
criteria for---]{.underline}

[(A) Defining the urgency of excavation and direct examination of the
indication; and]{.underline}

[(B) Defining the excavation urgency as immediate, scheduled, or
monitored; and]{.underline}

[(iv) Criteria for scheduling excavations of indications in each urgency
level.]{.underline}

[(4) *Direct examination*. In addition to the requirements in Section 5
of NACE Standard RP0502-2002, the procedures for direct examination of
indications from the indirect examination must include---]{.underline}

[(i) Provisions for applying more restrictive criteria when conducting
ECDA for the first time on a pipeline segment;]{.underline}

[(ii) Criteria for deciding what action should be taken if
either:]{.underline}

[(A) Corrosion defects are discovered that exceed allowable limits
(Section 5.5.2.2 of NACE Standard RP0502-2002 provides guidance for
criteria); or]{.underline}

[(B) Root cause analysis reveals conditions for which ECDA is not
suitable (Section 5.6.2 of NACE Standard RP0502-2002 provides guidance
for criteria);]{.underline}

[(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]{.underline}

[(iv) Criteria that describe how and on what basis you will reclassify
and re-prioritize any of the provisions specified in Section 5.9 of NACE
Standard RP0502-2002.]{.underline}

[(5) *Post assessment and continuing evaluation.* In addition to the
requirements in Section 6 of NACE Standard UP 0502-2002, the procedures
for post assessment of the effectiveness of the ECDA process must
include---]{.underline}

[(i) Measures for evaluating the long-term effectiveness of ECDA in
addressing external corrosion in pipeline segments; and]{.underline}

[(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 Standard RP0502-2002 (see
Appendix D of NACE Standard RP0502-2002).]{.underline}

[\[Amdt. 195-85, 70 FR 61571, Oct. 25, 2005\]]{.underline}

**§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.

\[Amdt. 195-73, 66 FR 66993, Dec. 27, 2002\]

**[Appendix A-Delineation Between Federal and State
Jursidiction--Statement of Agency Policy and
Interpretation]{.smallcaps}**

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
Federal-State 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 admini-stratively 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 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 that 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 within State X. DOT will rely on the existence or
non-existence of a FERC filing covering transportation over 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 nor 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 clear-cut 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.

\[Amdt. 195-33, 50 FR 15895, Apr. 23, 1985\]

**[Appendix B---Risk-Based Alternative to Pressure Testing Older
Hazardous Liquid and Carbon Dioxide Pipelines]{.smallcaps}**

**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]{.smallcaps}

+---------------+-----------+------------+----------------------------+
| Pipeline      | Risk      | Test       | Test medium                |
| segment       | class     | d          |                            |
|               | ification | eadline^1^ |                            |
+---------------+-----------+------------+----------------------------+
| Pre-1970      | C or B    | 12/7/2000  | Water only.                |
| Pipeline      |           |            |                            |
|               |           |            |                            |
| Segments      |           |            |                            |
| susceptible   |           |            |                            |
| to            |           |            |                            |
| longitudinal  |           |            |                            |
| seam          |           |            |                            |
| failures^2^   |           |            |                            |
+---------------+-----------+------------+----------------------------+
|               | A         | 12         | Water only.                |
|               |           | /7/2002^3^ |                            |
+---------------+-----------+------------+----------------------------+
| All Other     | C         | 12         | Water only.                |
| Pipeline      |           | /7/2002^3^ |                            |
|               |           |            |                            |
| Segments.     |           |            |                            |
+---------------+-----------+------------+----------------------------+
|               | B         | 12         | Water/Liq.^5^              |
|               |           | /7/2004^4^ |                            |
+---------------+-----------+------------+----------------------------+
|               | A         | Additional |                            |
|               |           | pressure   |                            |
|               |           | testing    |                            |
|               |           | not        |                            |
|               |           | required.  |                            |
+---------------+-----------+------------+----------------------------+

^1^ If operational experience indicates a history of past failures for a
particular pipeline system, 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.

^2^ All 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.

^3^ For 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.

^4^ A 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.

^5^ Pressure 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]{.smallcaps}

+-----------+-------------+------------+------------------------------+
| Risk      | Hazard      | Prod       | Probability of               |
|           | location    | uct/volume |                              |
| class     |             | indicator  | failure indicator            |
| ification | indicator   |            |                              |
+-----------+-------------+------------+------------------------------+
| A         | L or M      | L/L        | L                            |
+-----------+-------------+------------+------------------------------+
| B         | Not A or C  |            |                              |
|           | Risk        |            |                              |
|           | Cla         |            |                              |
|           | ssification |            |                              |
+-----------+-------------+------------+------------------------------+
| C         | H           | Any        | Any                          |
+-----------+-------------+------------+------------------------------+

H=High, M=Moderate, and L=Low.

**Note: For Location, Product, Volume, and Probability of Failure
Indicators, see Tables 3, 4, 5, and 6.**

[Table 3.---Location Indicators---Pipeline Segments]{.smallcaps}

  ------------------ --------------- -------------------------------------
  Indicator          Population^1^   Environment^2^

  H                  Non-rural areas 

  M                                  

  L                  Rural areas     
  ------------------ --------------- -------------------------------------

^1^The effects of potential vapor migration should be considered for
pipeline segments transporting highly volatile or toxic products.

^2^We 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]{.smallcaps}

+------+--------------------+------------------------------------------+
| I    | Considerations     | Product examples                         |
| ndic |                    |                                          |
| ator |                    |                                          |
+------+--------------------+------------------------------------------+
| H    | (Highly volatile   | (Propane, butane, Natural Gas Liquid     |
|      | and flammable).    | (NGL), ammonia).                         |
+------+--------------------+------------------------------------------+
|      | Highly toxic       | (Benzene, high Hydrogen Sulfide          |
|      |                    |                                          |
|      |                    | content crude oils).                     |
+------+--------------------+------------------------------------------+
| M    | Flam               | (Gasoline, JP4, low flashpoint crude     |
|      | mable---flashpoint | oils).                                   |
|      | \<100F.            |                                          |
+------+--------------------+------------------------------------------+
| L    | Non-flam           | (Diesel, fuel oil, kerosene, JP5, most   |
|      | mable---flashpoint | crude oils).                             |
|      | 100+F              |                                          |
+------+--------------------+------------------------------------------+
|      | Highly volatile    | Carbon Dioxide.                          |
|      | and                |                                          |
|      | non-fl             |                                          |
|      | ammable/non-toxic. |                                          |
+------+--------------------+------------------------------------------+

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]{.smallcaps}

  --------------------------- -------------------------------------------
  Indicator                   Line size

  H                           ≥ 18\"

  M                           10\'\'-16\'\' nominal diameters.

  L                           ≤ 8\'\' nominal diameter.
  --------------------------- -------------------------------------------

H=High, M=Moderate, and 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)]{.smallcaps}

  --------------------------- -------------------------------------------
  Indicator                   Failure history (time-dependent defects)^2^

  H^1^                        \> Three spills in last 10 years.

  L                           ≤ Three spills in last 10 years.
  --------------------------- -------------------------------------------

H=High and L=Low.

^1^Pipeline 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.

^2^Time-Dependent Defects are defects that result in spills due to
corrosion, gouges, or problems developed during manufacture,
construction or operation, etc.

\[Amdt. 195-65, 63 FR 59475, November 4, 1998 as amended by Amdt.
195-65A. 64 FR 6814, February 11, 1999\]

**Appendix C to Part 195--Guidance for Implementation of 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.rspa.dot.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).) For more information to help in
identifying high consequence areas, an operator may refer to:

\(1\) 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 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).

\(17\) 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 3½ 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]{.smallcaps}   

  Safety risk indicator  Leak history (Time-dependent defects)^1^

  High                   \> 3 Spills in last 10 years

  Low                    3 Spills in last 10 years
  ---------------------- --------------------------------------------------

^1^ Time-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]{.smallcaps}   

  Safety risk indicator      Line size

  High                       ≥ 18\"

  Moderate                   10\"--16\" nominal diameters

  Low                        ≤ 8\" nominal diameter

  [Age of                    
  Pipeline]{.smallcaps}      

  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]{.smallcaps}                               

  Safety risk indicator      Considerations^1^           Product examples

  High                       (Highly volatile and        (Propane, butane, Natural Gas
                             flammable)                  Liquid (NGL), ammonia).

                             Highly toxic                (Benzene, high Hydrogen Sulfide
                                                         content crude oils).

  Medium                     Flammable\<flashpoint 100F  (Gasoline, JP4, low flashpoint
                                                         crude oils).

  Low                        Non-flammable--flashpoint   (Diesel, fuel oil, kerosene,
                             100+F                       JP5, most crude oils).
  -------------------------- --------------------------- --------------------------------

^1^ 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 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 \_\_\_\_-%
(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.

\(6\) 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 repair of anomalies, justification to
support deviation from required repair 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.

\[Amdt. 195-70, 65 FR 75378, Dec. 1, 2000 as amended by Amdt. 195-74, 67
FR 1650, Jan. 14, 2002\]

[^1]: ^1^ (See Appendix B, Table C).

[^2]: ^1^

[^3]: ^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.