[Title 49 CFR ]
[Code of Federal Regulations (annual edition) - October 1, 2009 Edition]
[From the U.S. Government Printing Office]



[[Page i]]



          49


          Parts 186 to 199

                         Revised as of October 1, 2009


          Transportation




________________________

          Containing a codification of documents of general 
          applicability and future effect

          As of October 1, 2009
          With Ancillaries
                    Published by
                    Office of the Federal Register
                    National Archives and Records
                    Administration
                    A Special Edition of the Federal Register

[[Page ii]]

          U.S. GOVERNMENT OFFICIAL EDITION NOTICE

          Legal Status and Use of Seals and Logos
          
          
          The seal of the National Archives and Records Administration 
              (NARA) authenticates the Code of Federal Regulations (CFR) as 
              the official codification of Federal regulations established 
              under the Federal Register Act. Under the provisions of 44 
              U.S.C. 1507, the contents of the CFR, a special edition of the 
              Federal Register, shall be judicially noticed. The CFR is 
              prima facie evidence of the original documents published in 
              the Federal Register (44 U.S.C. 1510).

          It is prohibited to use NARA's official seal and the stylized Code 
              of Federal Regulations logo on any republication of this 
              material without the express, written permission of the 
              Archivist of the United States or the Archivist's designee. 
              Any person using NARA's official seals and logos in a manner 
              inconsistent with the provisions of 36 CFR part 1200 is 
              subject to the penalties specified in 18 U.S.C. 506, 701, and 
              1017.

          Use of ISBN Prefix

          This is the Official U.S. Government edition of this publication 
              and is herein identified to certify its authenticity. Use of 
              the 0-16 ISBN prefix is for U.S. Government Printing Office 
              Official Editions only. The Superintendent of Documents of the 
              U.S. Government Printing Office requests that any reprinted 
              edition clearly be labeled as a copy of the authentic work 
              with a new ISBN.

              
              
          U . S . G O V E R N M E N T P R I N T I N G O F F I C E

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

          U.S. Superintendent of Documents  Washington, DC 
              20402-0001

          http://bookstore.gpo.gov

          Phone: toll-free (866) 512-1800; DC area (202) 512-1800

[[Page iii]]




                            Table of Contents



                                                                    Page
  Explanation.................................................       v

  Title 49:
    SUBTITLE B--Other Regulations Relating to Transportation 
      (Continued)
          Chapter I--Pipeline and Hazardous Materials Safety 
          Administration, Department of Transportation 
          (Continued)                                                5
  Finding Aids:
      Table of CFR Titles and Chapters........................     255
      Alphabetical List of Agencies Appearing in the CFR......     275
      List of CFR Sections Affected...........................     285

[[Page iv]]





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

                     Cite this Code: CFR
                     To cite the regulations in 
                       this volume use title, 
                       part and section number. 
                       Thus, 49 CFR 190.1 refers 
                       to title 49, part 190, 
                       section 1.

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

[[Page v]]



                               EXPLANATION

    The Code of Federal Regulations is a codification of the general and 
permanent rules published in the Federal Register by the Executive 
departments and agencies of the Federal Government. The Code is divided 
into 50 titles which represent broad areas subject to Federal 
regulation. Each title is divided into chapters which usually bear the 
name of the issuing agency. Each chapter is further subdivided into 
parts covering specific regulatory areas.
    Each volume of the Code is revised at least once each calendar year 
and issued on a quarterly basis approximately as follows:

Title 1 through Title 16.................................as of January 1
Title 17 through Title 27..................................as of April 1
Title 28 through Title 41...................................as of July 1
Title 42 through Title 50................................as of October 1

    The appropriate revision date is printed on the cover of each 
volume.

LEGAL STATUS

    The contents of the Federal Register are required to be judicially 
noticed (44 U.S.C. 1507). The Code of Federal Regulations is prima facie 
evidence of the text of the original documents (44 U.S.C. 1510).

HOW TO USE THE CODE OF FEDERAL REGULATIONS

    The Code of Federal Regulations is kept up to date by the individual 
issues of the Federal Register. These two publications must be used 
together to determine the latest version of any given rule.
    To determine whether a Code volume has been amended since its 
revision date (in this case, October 1, 2009), consult the ``List of CFR 
Sections Affected (LSA),'' which is issued monthly, and the ``Cumulative 
List of Parts Affected,'' which appears in the Reader Aids section of 
the daily Federal Register. These two lists will identify the Federal 
Register page number of the latest amendment of any given rule.

EFFECTIVE AND EXPIRATION DATES

    Each volume of the Code contains amendments published in the Federal 
Register since the last revision of that volume of the Code. Source 
citations for the regulations are referred to by volume number and page 
number of the Federal Register and date of publication. Publication 
dates and effective dates are usually not the same and care must be 
exercised by the user in determining the actual effective date. In 
instances where the effective date is beyond the cut-off date for the 
Code a note has been inserted to reflect the future effective date. In 
those instances where a regulation published in the Federal Register 
states a date certain for expiration, an appropriate note will be 
inserted following the text.

OMB CONTROL NUMBERS

    The Paperwork Reduction Act of 1980 (Pub. L. 96-511) requires 
Federal agencies to display an OMB control number with their information 
collection request.

[[Page vi]]

Many agencies have begun publishing numerous OMB control numbers as 
amendments to existing regulations in the CFR. These OMB numbers are 
placed as close as possible to the applicable recordkeeping or reporting 
requirements.

OBSOLETE PROVISIONS

    Provisions that become obsolete before the revision date stated on 
the cover of each volume are not carried. Code users may find the text 
of provisions in effect on a given date in the past by using the 
appropriate numerical list of sections affected. For the period before 
January 1, 2001, consult either the List of CFR Sections Affected, 1949-
1963, 1964-1972, 1973-1985, or 1986-2000, published in eleven separate 
volumes. For the period beginning January 1, 2001, a ``List of CFR 
Sections Affected'' is published at the end of each CFR volume.

INCORPORATION BY REFERENCE

    What is incorporation by reference? Incorporation by reference was 
established by statute and allows Federal agencies to meet the 
requirement to publish regulations in the Federal Register by referring 
to materials already published elsewhere. For an incorporation to be 
valid, the Director of the Federal Register must approve it. The legal 
effect of incorporation by reference is that the material is treated as 
if it were published in full in the Federal Register (5 U.S.C. 552(a)). 
This material, like any other properly issued regulation, has the force 
of law.
    What is a proper incorporation by reference? The Director of the 
Federal Register will approve an incorporation by reference only when 
the requirements of 1 CFR part 51 are met. Some of the elements on which 
approval is based are:
    (a) The incorporation will substantially reduce the volume of 
material published in the Federal Register.
    (b) The matter incorporated is in fact available to the extent 
necessary to afford fairness and uniformity in the administrative 
process.
    (c) The incorporating document is drafted and submitted for 
publication in accordance with 1 CFR part 51.
    What if the material incorporated by reference cannot be found? If 
you have any problem locating or obtaining a copy of material listed as 
an approved incorporation by reference, please contact the agency that 
issued the regulation containing that incorporation. If, after 
contacting the agency, you find the material is not available, please 
notify the Director of the Federal Register, National Archives and 
Records Administration, Washington DC 20408, or call 202-741-6010.

CFR INDEXES AND TABULAR GUIDES

    A subject index to the Code of Federal Regulations is contained in a 
separate volume, revised annually as of January 1, entitled CFR Index 
and Finding Aids. This volume contains the Parallel Table of Authorities 
and Rules. A list of CFR titles, chapters, subchapters, and parts and an 
alphabetical list of agencies publishing in the CFR are also included in 
this volume.
    An index to the text of ``Title 3--The President'' is carried within 
that volume.
    The Federal Register Index is issued monthly in cumulative form. 
This index is based on a consolidation of the ``Contents'' entries in 
the daily Federal Register.
    A List of CFR Sections Affected (LSA) is published monthly, keyed to 
the revision dates of the 50 CFR titles.




[[Page vii]]



REPUBLICATION OF MATERIAL

    There are no restrictions on the republication of material appearing 
in the Code of Federal Regulations.

INQUIRIES

    For a legal interpretation or explanation of any regulation in this 
volume, contact the issuing agency. The issuing agency's name appears at 
the top of odd-numbered pages.
    For inquiries concerning CFR reference assistance, call 202-741-6000 
or write to the Director, Office of the Federal Register, National 
Archives and Records Administration, Washington, DC 20408 or e-mail 
fedreg.info@nara.gov.

SALES

    The Government Printing Office (GPO) processes all sales and 
distribution of the CFR. For payment by credit card, call toll-free, 
866-512-1800, or DC area, 202-512-1800, M-F 8 a.m. to 4 p.m. e.s.t. or 
fax your order to 202-512-2250, 24 hours a day. For payment by check, 
write to: US Government Printing Office - New Orders, P.O. Box 979050, 
St. Louis, MO 63197-9000. For GPO Customer Service call 202-512-1803.

ELECTRONIC SERVICES

    The full text of the Code of Federal Regulations, the LSA (List of 
CFR Sections Affected), The United States Government Manual, the Federal 
Register, Public Laws, Public Papers, Daily Compilation of Presidential 
Documents and the Privacy Act Compilation are available in electronic 
format via Federalregister.gov. For more information, contact Electronic 
Information Dissemination Services, U.S. Government Printing Office. 
Phone 202-512-1530, or 888-293-6498 (toll-free). E-mail, 
gpoaccess@gpo.gov.
    The Office of the Federal Register also offers a free service on the 
National Archives and Records Administration's (NARA) World Wide Web 
site for public law numbers, Federal Register finding aids, and related 
information. Connect to NARA's web site at www.archives.gov/federal-
register. The NARA site also contains links to GPO Access.

    Raymond A. Mosley,
    Director,
    Office of the Federal Register.
    October 1, 2009.







[[Page ix]]



                               THIS TITLE

    Title 49--Transportation is composed of nine volumes. The parts in 
these volumes are arranged in the following order: Parts 1-99, parts 
100-185, parts 186-199, parts 200-299, parts 300-399, parts 400-571, 
parts 572-999, parts 1000-1199, and part 1200 to end. The first volume 
(parts 1-99) contains current regulations issued under subtitle A--
Office of the Secretary of Transportation; the second volume (parts 100-
185) and the third volume (parts 186-199) contain the current 
regulations issued under chapter I--Pipeline and Hazardous Materials 
Safety Administration (DOT); the fourth volume (parts 200-299) contains 
the current regulations issued under chapter II--Federal Railroad 
Administration (DOT); the fifth volume (parts 300-399) contains the 
current regulations issued under chapter III--Federal Motor Carrier 
Safety Administration (DOT); the sixth volume (parts 400-571) contains 
the current regulations issued under chapter IV--Coast Guard (DHS), and 
some of chapter V--National Highway Traffic Safety Administration (DOT); 
the seventh volume (parts 572-999) contains the rest of the regulations 
issued under chapter IV, and the current regulations issued under 
chapter VI--Federal Transit Administration (DOT), chapter VII--National 
Railroad Passenger Corporation (AMTRAK), and chapter VIII--National 
Transportation Safety Board; the eighth volume (parts 1000-1199) 
contains the current regulations issued under chapter X--Surface 
Transportation Board and the ninth volume (part 1200 to end) contains 
the current regulations issued under chapter X--Surface Transportation 
Board, chapter XI--Research and Innovative Technology Administration, 
and chapter XII--Transportation Security Administration, Department of 
Transportation. The contents of these volumes represent all current 
regulations codified under this title of the CFR as of October 1, 2009.

    In the volume containing parts 100-185, see Sec.  172.101 for the 
Hazardous Materials Table. The Federal Motor Vehicle Safety Standards 
appear in part 571.

    Redesignation tables for chapter III--Federal Motor Carrier Safety 
Administration, Department of Transportation and chapter XII--
Transportation Security Administration, Department of Transportation 
appear in the Finding Aids section of the fifth and ninth volumes.

    For this volume, Susannah C. Hurley was Chief Editor. The Code of 
Federal Regulations publication program is under the direction of 
Michael L. White, assisted by Ann Worley.


[[Page 1]]



                        TITLE 49--TRANSPORTATION




                  (This book contains parts 186 to 199)

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

  Editorial Note: Other regulations issued by the Department of 
Transportation appear in 14 CFR chapters I and II, 23 CFR, 33 CFR 
chapters I and IV, 44 CFR chapter IV, 46 CFR chapters I through III, 48 
CFR chapter 12, and 49 CFR chapters I through VI.

  SUBTITLE B--Other Regulations Relating to Transportation (Continued)

                                                                    Part

chapter I--Research and Special Programs Administration, 
  Department of Transportation (Continued)..................         190

[[Page 3]]

  Subtitle B--Other Regulations Relating to Transportation (Continued)

[[Page 5]]



   CHAPTER I--PIPELINE AND HAZARDOUS MATERIALS SAFETY ADMINISTRATION, 
                DEPARTMENT OF TRANSPORTATION (CONTINUED)




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

                      SUBCHAPTER D--PIPELINE SAFETY
Part                                                                Page
186-189

[Reserved]

190             Pipeline safety programs and rulemaking 
                    procedures..............................           7
191             Transportation of natural and other gas by 
                    pipeline; annual reports, incident 
                    reports, and safety-related condition 
                    reports.................................          28
192             Transportation of natural and other gas by 
                    pipeline: minimum Federal safety 
                    standards...............................          33
193             Liquefied natural gas facilities: Federal 
                    safety standards........................         142
194             Response plans for onshore oil pipelines....         161
195             Transportation of hazardous liquids by 
                    pipeline................................         171
196-197

[Reserved]

198             Regulations for grants to aid State pipeline 
                    safety programs.........................         235
199             Drug and alcohol testing....................         238

[[Page 7]]



                      SUBCHAPTER D_PIPELINE SAFETY



                        PARTS 186	189 [RESERVED]



PART 190_PIPELINE SAFETY PROGRAMS AND RULEMAKING PROCEDURES--Table of
Contents




                            Subpart A_General

Sec.
190.1 Purpose and scope.
190.3 Definitions.
190.5 Service.
190.7 Subpoenas; witness fees.
190.9 Petitions for finding or approval.
190.11 Availability of informal guidance and interpretive assistance.

                          Subpart B_Enforcement

190.201 Purpose and scope.
190.203 Inspections and investigations.
190.205 Warning letters.
190.207 Notice of probable violation.
190.209 Response options.
190.211 Hearing.
190.213 Final order.
190.215 Petitions for reconsideration.

                            Compliance Orders

190.217 Compliance orders generally.
190.219 Consent order.

                             Civil Penalties

190.221 Civil penalties generally.
190.223 Maximum penalties.
190.225 Assessment considerations.
190.227 Payment of penalty.

                           Criminal Penalties

190.229 Criminal penalties generally.
190.231 Referral for prosecution.

                             Specific Relief

190.233 Corrective action orders.
190.235 Injunctive action.
190.237 Amendment of plans or procedures.
190.239 Safety orders.

               Subpart C_Procedures for Adoption of Rules

190.301 Scope.
190.303 Delegations.
190.305 Regulatory dockets.
190.307 Records.
190.309 Where to file petitions.
190.311 General.
190.313 Initiation of rulemaking.
190.315 Contents of notices of proposed rulemaking.
190.317 Participation by interested persons.
190.319 Petitions for extension of time to comment.
190.321 Contents of written comments.
190.323 Consideration of comments received.
190.325 Additional rulemaking proceedings.
190.327 Hearings.
190.329 Adoption of final rules.
190.331 Petitions for rulemaking.
190.333 Processing of petition.
190.335 Petitions for reconsideration.
190.337 Proceedings on petitions for reconsideration.
190.338 Appeals.
190.339 Direct final rulemaking.
190.341 Special permits.

    Authority: 33 U.S.C. 1321; 49 U.S.C. 5101-5127, 60101 et seq.; 49 
CFR 1.53.

    Source: 45 FR 20413, Mar. 27, 1980, unless otherwise noted.



                            Subpart A_General



Sec. 190.1  Purpose and scope.

    (a) This part prescribes procedures used by the Pipeline and 
Hazardous Materials Safety Administration in carrying out duties 
regarding pipeline safety under 49 U.S.C. 60101 et seq. (the pipeline 
safety laws) and 49 U.S.C. 5101 et seq. (the hazardous material 
transportation laws).
    (b) This subpart defines certain terms and prescribes procedures 
that are applicable to each proceeding described in this part.

[45 FR 20413, Mar. 27, 1980, as amended by Amdt. 190-6, 61 FR 18512, 
Apr. 26, 1996; 70 FR 11137, Mar. 8, 2005]



Sec. 190.3  Definitions.

    As used in this part:
    Administrator means the Administrator, Pipeline and Hazardous 
Materials Safety Administration or his or her delegate.
    Hearing means an informal conference or a proceeding for oral 
presentation. Unless otherwise specifically prescribed in this part, the 
use of ``hearing'' is not intended to require a hearing on the record in 
accordance with section 554 of title 5, U.S.C.
    OPS means the Office of Pipeline Safety, which is part of the 
Pipeline and Hazardous Materials Safety Administration, U.S. Department 
of Transportation.

[[Page 8]]

    Person means any individual, firm, joint venture, partnership, 
corporation, association, State, municipality, cooperative association, 
or joint stock association, and includes any trustee, receiver, 
assignee, or personal representative thereof.
    Presiding Official means the person who conducts any hearing 
relating to civil penalty assessments, compliance orders or hazardous 
facility orders.
    Regional Director means the head of any one of the Regional Offices 
of the Office of Pipeline Safety, or a designee appointed by the 
Regional Director. Regional Offices are located in Washington, DC 
(Eastern Region); Atlanta, Georgia (Southern Region); Kansas City, 
Missouri (Central Region); Houston, Texas (Southwest Region); and 
Lakewood, Colorado (Western Region).
    Respondent means a person upon whom the OPS has served a notice of 
probable violation.
    PHMSA means the Pipeline and Hazardous Materials Safety 
Administration of the United States Department of Transportation.
    State means a State of the United States, the District of Columbia 
and the Commonwealth of Puerto Rico.

[Amdt. 190-6, 61 FR 18513, Apr. 26, 1996, as amended at 68 FR 11749, 
Mar. 12, 2003; 70 FR 11137, Mar. 8, 2005]



Sec. 190.5  Service.

    (a) Each order, notice, or other document required to be served 
under this part shall be served personally, by registered or certified 
mail, overnight courier, or electronic transmission by facsimile or 
other electronic means that includes reliable acknowledgement of actual 
receipt.
    (b) Service upon a person's duly authorized representative or agent 
constitutes service upon that person.
    (c) Service by registered or certified mail or overnight courier is 
complete upon mailing. Service by electronic transmission is complete 
upon transmission and acknowledgement of receipt. An official receipt 
for the mailing from the U.S. Postal Service or overnight courier, or a 
facsimile or other electronic transmission confirmation, constitutes 
prima facie evidence of service.

[45 FR 20413, Mar. 27, 1980, as amended at 73 FR 16567, Mar. 28, 2008]



Sec. 190.7  Subpoenas; witness fees.

    (a) The Administrator, PHMSA, the Chief Counsel, PHMSA, or the 
official designated by the Administrator, PHMSA, to preside over a 
hearing convened in accordance with this part, may sign and issue 
subpoenas individually on their own initiative or, upon request and 
adequate showing by any person participating in the proceeding that the 
information sought will materially advance the proceeding.
    (b) A subpoena may require the attendance of a witness, or the 
production of documentary or other tangible evidence in the possession 
or under the control of person served, or both.
    (c) A subpoena may be served personally by any person who is not an 
interested person and is not less than 18 years of age, or by certified 
or registered mail.
    (d) Service of a subpoena upon the person named therein shall be 
made by delivering a copy of the subpoena to such person and by 
tendering the fees for one day's attendance and mileage as specified by 
paragraph (g) of this section. When a subpoena is issued at the instance 
of any officer or agency of the United States, fees and mileage need not 
be tendered at the time of service. Delivery of a copy of a subpoena and 
tender of the fees to a natural person may be made by handing them to 
the person, leaving them at the person's office with the person in 
charge thereof, leaving them at the person's dwelling place or usual 
place of abode with some person of suitable age and discretion then 
residing therein, by mailing them by registered or certified mail to the 
person at the last known address, or by any method whereby actual notice 
is given to the person and the fees are made available prior to the 
return date.
    (e) When the person to be served is not a natural person, delivery 
of a copy of the subpoena and tender of the fees may be effected by 
handing them to a designated agent or representative for service, or to 
any officer, director, or

[[Page 9]]

agent in charge of any office of the person, or by mailing them by 
registered or certified mail to that agent or representative and the 
fees are made available prior to the return date.
    (f) The original subpoena bearing a certificate of service shall be 
filed with the official having responsibility for the proceeding in 
connection with which the subpoena was issued.
    (g) A subpoenaed witness shall be paid the same fees and mileage as 
would be paid to a witness in a proceeding in the district courts of the 
United States. The witness fees and mileage shall be paid by the person 
at whose instance the subpoena was issued.
    (h) Notwithstanding the provisions of paragraph (g) of this section, 
and upon request, the witness fees and mileage may be paid by the PHMSA 
if the official who issued the subpoena determines on the basis of good 
cause shown, that:
    (1) The presence of the subpoenaed witness will materially advance 
the proceeding; and
    (2) The person at whose instance the subpoena was issued would 
suffer a serious hardship if required to pay the witness fees and 
mileage.
    (i) Any person to whom a subpoena is directed may, prior to the time 
specified therein for compliance, but in no event more than 10 days 
after the date of service of such subpoena, apply to the official who 
issued the subpoena, or if the person is unavailable, to the 
Administrator, PHMSA to quash or modify the subpoena. The application 
shall contain a brief statement of the reasons relied upon in support of 
the action sought therein. The Administrator, PHMSA, or this issuing 
official, as the case may be, may:
    (1) Deny the application;
    (2) Quash or modify the subpoena; or
    (3) Condition a grant or denial of the application to quash or 
modify the subpoena upon the satisfaction of certain just and reasonable 
requirements. The denial may be summary.
    (j) Upon refusal to obey a subpoena served upon any person under the 
provisions of this section, the PHMSA may request the Attorney General 
to seek the aid of the U. S. District Court for any District in which 
the person is found to compel that person, after notice, to appear and 
give testimony, or to appear and produce the subpoenaed documents before 
the PHMSA, or both.

[45 FR 20413, Mar. 27, 1980, as amended by Amdt. 190-6, 61 FR 18513, 
Apr. 26, 1996; Amdt. 190-7, 63 FR 7722, Feb. 17, 1998; 70 FR 11137, Mar. 
8, 2005]



Sec. 190.9  Petitions for finding or approval.

    (a) In circumstances where a rule contained in parts 192, 193 and 
195 of this chapter authorizes the Administrator to make a finding or 
approval, an operator may petition the Administrator for such a finding 
or approval.
    (b) Each petition must refer to the rule authorizing the action 
sought and contain information or arguments that justify the action. 
Unless otherwise specified, no public proceeding is held on a petition 
before it is granted or denied. After a petition is received, the 
Administrator or participating state agency notifies the petitioner of 
the disposition of the petition or, if the request requires more 
extensive consideration or additional information or comments are 
requested and delay is expected, of the date by which action will be 
taken.
    (1) For operators seeking a finding or approval involving intrastate 
pipeline transportation, petitions must be sent to:
    (i) The State agency certified to participate under 49 U.S.C. 60105.
    (ii) Where there is no state agency certified to participate, the 
Administrator, Pipeline and Hazardous Materials Safety Administration, 
1200 New Jersey Avenue, SE, Washington, DC 20590.
    (2) For operators seeking a finding or approval involving interstate 
pipeline transportation, petitions must be sent to the Administrator, 
Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey 
Avenue, SE, Washington, DC 20590.
    (c) All petitions must be received at least 90 days prior to the 
date by which the operator requests the finding or approval to be made.
    (d) The Administrator will make all findings or approvals of 
petitions initiated under this section. A participating

[[Page 10]]

state agency receiving petitions initiated under this section shall 
provide the Administrator a written recommendation as to the disposition 
of any petition received by them. Where the Administrator does not 
reverse or modify a recommendation made by a state agency within 10 
business days of its receipt, the recommended disposition shall 
constitute the Administrator's decision on the petition.

[Amdt. 190-5, 59 FR 17280, Apr. 12, 1994, as amended by Amdt. 190-6, 61 
FR 18513, Apr. 26, 1996; 70 FR 11137, Mar. 8, 2005; 73 FR 16566, Mar. 
28, 2008]



Sec. 190.11  Availability of informal guidance and interpretive 
assistance.

    (a) Availability of telephonic and Internet assistance. (1) PHMSA 
has established a website on the Internet and a telephone line at the 
Office of Pipeline Safety headquarters where small operators and others 
can obtain information on and advice about compliance with pipeline 
safety regulations, 49 CFR parts 190-199. The website and telephone line 
are staffed by personnel from PHMSA's Office of Pipeline Safety from 
9:00 a.m. through 5:00 p.m., Eastern time, Monday through Friday, except 
Federal holidays. When the lines are not staffed, individuals may leave 
a recorded voicemail message, or post a message at the OPS website. All 
messages will receive a response by the following business day. The 
telephone number for the OPS information line is (202) 366-4595 and the 
OPS website can be accessed via the Internet at http://ops.dot.gov.
    (2) PHMSA's Office of the Chief Counsel (OCC) is available to answer 
questions concerning Federal pipeline safety law, 49 U.S.C. 60101 et 
seq. OCC may be contacted by telephone (202-366-4400) from 9:00 a.m. to 
4:00 p.m. Eastern time, Monday through Friday, except Federal holidays. 
Information and guidance concerning Federal pipeline safety law may also 
be obtained by contacting OCC via the Internet at http://rspa-
atty.dot.gov.
    (b) Availability of Written Interpretations. (1) A written 
regulatory interpretation, response to a question, or an opinion 
concerning a pipeline safety issue may be obtained by submitting a 
written request to the Office of Pipeline Safety (PHP-30), PHMSA, U.S. 
Department of Transportation, 1200 New Jersey Avenue, SE, Washington, DC 
20590-0001. The requestor must include his or her return address and 
should also include a daytime telephone number. Written requests should 
be submitted at least 120 days before the time the requestor needs the 
response.
    (2) A written interpretation regarding Federal pipeline safety law, 
49 U.S.C 60101 et seq., may be obtained from the Office of the Chief 
Counsel, PHMSA, U.S. Department of Transportation, 1200 New Jersey 
Avenue, SE, Washington, DC 20590-0001. The requestor must include his or 
her return address and should also include a daytime telephone number.

[62 FR 24057, May 2, 1997; 62 FR 34415, June 26, 1997, as amended at 70 
FR 11137, Mar. 8, 2005; 73 FR 16566, Mar. 28, 2008; 73 FR 16567, Mar. 
28, 2008]



                          Subpart B_Enforcement



Sec. 190.201  Purpose and scope.

    (a) This subpart describes the enforcement authority and sanctions 
exercised by the Associate Administrator, OPS for achieving and 
maintaining pipeline safety. It also prescribes the procedures governing 
the exercise of that authority and the imposition of those sanctions.
    (b) A person who is the subject of action pursuant to this subpart 
may be represented by legal counsel at all stages of the proceeding.

[45 FR 20413, Mar. 27, 1980, as amended by Amdt. 190-6, 61 FR 18513, 
Apr. 26, 1996]



Sec. 190.203  Inspections and investigations.

    (a) Officers, employees, or agents authorized by the Associate 
Administrator for Pipeline Safety, PHMSA, upon presenting appropriate 
credentials, are authorized to enter upon, inspect, and examine, at 
reasonable times and in a reasonable manner, the records and properties 
of persons to the extent such records and properties are relevant to 
determining the compliance of such persons with the requirements of 49 
U.S.C. 60101 et seq., or regulations or orders issued thereunder.

[[Page 11]]

    (b) Inspections are ordinarily conducted pursuant to one of the 
following:
    (1) Routine scheduling by the Regional Director of the Region in 
which the facility is located;
    (2) A complaint received from a member of the public;
    (3) Information obtained from a previous inspection;
    (4) Report from a State Agency participating in the Federal Program 
under 49 U.S.C. 60105;
    (5) Pipeline accident or incident; or
    (6) Whenever deemed appropriate by the Administrator, PHMSA or his 
designee.
    (c) If, after an inspection, the Associate Administrator, OPS 
believes that further information is needed to determine appropriate 
action, the Associate Administrator, OPS may send the owner or operator 
a ``Request for Specific Information'' to be answered within 45 days 
after receipt of the letter.
    (d) To the extent necessary to carry out the responsibilities under 
49 U.S.C. 60101 et seq., the Administrator, PHMSA or the Associate 
Administrator, OPS may require testing of portions of pipeline 
facilities that have been involved in, or affected by, an accident. 
However, before exercising this authority, the Administrator, PHMSA or 
the Associate Administrator, OPS shall make every effort to negotiate a 
mutually acceptable plan with the owner of those facilities and, where 
appropriate, the National Transportation Safety Board for performing the 
testing.
    (e) If a representative of the DOT investigates an incident 
involving a pipeline facility, OPS may request that the operator make 
available to the representative all records and information that pertain 
to the incident in any way, including integrity management plans and 
test results, and that the operator afford all reasonable assistance in 
the investigation.
    (f) When the information obtained from an inspection or from other 
appropriate sources indicates that further OPS action is warranted, the 
OPS may issue a warning letter under Sec. 190.205 or initiate one or 
more of the enforcement proceedings prescribed in Sec. Sec. 190.207 
through 190.235.

[45 FR 20413, Mar. 27, 1980, as amended by Amdt. 190-3, 56 FR 31090, 
July 9, 1991; Amdt. 190-6, 61 FR 18513, Apr. 26, 1996; Amdt. 190-7, 61 
FR 27792, June 3, 1996; Amdt. 190-7, 63 FR 7722, Feb. 17, 1998; 70 FR 
11137, Mar. 8, 2005]



Sec. 190.205  Warning letters.

    Upon determining that a probable violation of 49 U.S.C. 60101 et 
seq. or any regulation or order issued thereunder has occurred, the 
Associate Administrator, OPS, may issue a Warning Letter notifying the 
owner or operator of the probable violation and advising the owner or 
operator to correct it or be subject to enforcement action under 
Sec. Sec. 190.207 through 190.235.

[Amdt. 190-6, 61 FR 38403, July 24, 1996]



Sec. 190.207  Notice of probable violation.

    (a) Except as otherwise provided by this subpart, a Regional 
Director begins an enforcement proceeding by serving a notice of 
probable violation on a person charging that person with a probable 
violation of 49 U.S.C. 60101 et seq. or any regulation or order issued 
thereunder.
    (b) A notice of probable violation issued under this section shall 
include:
    (1) Statement of the provisions of the laws, regulations or orders 
which the respondent is alleged to have violated and a statement of the 
evidence upon which the allegations are based;
    (2) Notice of response options available to the respondent under 
Sec. 190.209;
    (3) If a civil penalty is proposed under Sec. 190.221, the amount 
of the proposed civil penalty and the maximum civil penalty for which 
respondent is liable under law; and
    (4) If a compliance order is proposed under Sec. 190.217, a 
statement of the remedial action being sought in the form of a proposed 
compliance order.
    (c) The Associate Administrator, OPS may amend a notice of probable 
violation at any time prior to issuance of a final order under Sec. 
190.213. If an amendment includes any new material allegations of fact 
or proposes an increased civil penalty amount or new or additional 
remedial action under

[[Page 12]]

Sec. 190.217, the respondent shall have the opportunity to respond 
under Sec. 190.209.

[45 FR 20413, Mar. 27, 1980, as amended by Amdt. 190-6, 61 FR 18513, 
Apr. 26, 1996]



Sec. 190.209  Response options.

    Within 30 days of receipt of a notice of probable violation, the 
respondent shall respond to the Regional Director who issued the notice 
in the following way:
    (a) When the notice contains a proposed civil penalty--
    (1) Pay the proposed civil penalty as provided in Sec. 190.227 and 
close the case with prejudice to the respondent;
    (2) Submit written explanations, information or other materials in 
answer to the allegations or in mitigation of the proposed civil 
penalty; or
    (3) Request a hearing under Sec. 190.211.
    (b) When the notice contains a proposed compliance order--
    (1) Agree to the proposed compliance order;
    (2) Request the execution of a consent order under Sec. 190.219;
    (3) Object to the proposed compliance order and submit written 
explanations, information or other materials in answer to the 
allegations in the notice of probable violation; or
    (4) Request a hearing under Sec. 190.211.
    (c) Failure of the respondent to respond in accordance with 
paragraph (a) of this section or, when applicable, paragraph (c) of this 
section, constitutes a waiver of the right to contest the allegations in 
the notice of probable violation and authorizes the Associate 
Administrator, OPS, without further notice to the respondent, to find 
facts to be as alleged in the notice of probable violation and to issue 
a final order under Sec. 190.213.
    (d) All materials submitted by operators in response to enforcement 
actions may be placed on publicly accessible Web sites. A Respondent 
that seeks confidential treatment under 5 U.S.C. 552(b) for any portion 
of its responsive materials must provide a second copy of such materials 
along with the complete original document. A Respondent may redact the 
portions it believes qualify for confidential treatment in the second 
copy but must provide an explanation for each redaction.

[45 FR 20413, Mar. 27, 1980, as amended by Amdt. 190-1, 53 FR 1635, Jan. 
21, 1988; Amdt. 190-6, 61 FR 18513, Apr. 26, 1996; Amdt. 190-7, 61 FR 
27792, June 3, 1996; Amdt. 190-7, 63 FR 7722, Feb. 17, 1998; 73 FR 
16567, Mar. 28, 2008]



Sec. 190.211  Hearing.

    (a) A request for a hearing provided for in this part must be 
accompanied by a statement of the issues that the respondent intends to 
raise at the hearing. The issues may relate to the allegations in the 
notice, the proposed corrective action (including a proposed amendment, 
a proposed compliance order, or a proposed hazardous facility order), or 
the proposed civil penalty amount. A respondent's failure to specify an 
issue may result in waiver of the respondent's right to raise that issue 
at the hearing. The respondent's request must also indicate whether or 
not the respondent will be represented by counsel at the hearing.
    (b) A telephone hearing will be held if the amount of the proposed 
civil penalty or the cost of the proposed corrective action is less than 
$10,000, unless the respondent submits a written request for an in-
person hearing. Hearings are held in a location agreed upon by the 
presiding official, OPS and the respondent.
    (c) An attorney from the Office of the Chief Counsel, Pipeline and 
Hazardous Materials Safety Administration, serves as the presiding 
official at the hearing.
    (d) The hearing is conducted informally without strict adherence to 
rules of evidence. The respondent may submit any relevant information 
and material and call witnesses on the respondent's behalf. The 
respondent may also examine the evidence and witnesses presented by the 
government. No detailed record of a hearing is prepared.
    (e) Upon request by respondent, and whenever practicable, the 
material in the case file pertinent to the issues to be determined is 
provided to the respondent 30 days before the hearing. The respondent 
may respond to or rebut this material at the hearing.
    (f) During the hearing, the respondent may offer any facts, 
statements,

[[Page 13]]

explanations, documents, testimony or other items which are relevant to 
the issues under consideration.
    (g) At the close of the respondent's presentation, the presiding 
official may present or allow the presentation of any OPS rebuttal 
information. The respondent may then respond to that information.
    (h) After the evidence in the case has been presented, the presiding 
official shall permit argument on the issues under consideration.
    (i) The respondent may also request an opportunity to submit further 
written materal for inclusion in the case file. The presiding official 
shall allow a reasonable time for the submission of the material and 
shall specify the date by which it must be submitted. If the material is 
not submitted within the time prescribed, the case shall proceed to 
final action without the material.
    (j) After submission of all materials during and after the hearing, 
the presiding official shall prepare a written recommendation as to 
final action in the case. This recommendation, along with any material 
submitted during and after the hearing, shall be included in the case 
file which is forwarded to the Associate Administrator, OPS for final 
administrative action.

[45 FR 20413, Mar. 17, 1980, as amended by Amdt. 190-3, 56 FR 31090, 
July 9, 1991; Amdt. 190-6, 61 FR 18514, Apr. 26, 1996; Amdt. 190-7, 61 
FR 27792, June 3, 1996; 70 FR 11137, Mar. 8, 2005]



Sec. 190.213  Final order.

    (a) After a hearing under Sec. 190.211 or, if no hearing has been 
held, after expiration of the 30 day response period prescribed in Sec. 
190.209, the case file of an enforcement proceeding commenced under 
Sec. 190.207 is forwarded to the Associate Administrator, OPS for 
issuance of a final order.
    (b) The case file of an enforcement proceeding commenced under Sec. 
190.207 includes:
    (1) The inspection reports and any other evidence of alleged 
violations;
    (2) A copy of the notice of probable violation issued under Sec. 
190.207;
    (3) Material submitted by the respondent in accord with Sec. 
190.209 in response to the notice of probable violation;
    (4) The Regional Director's evaluation of response material 
submitted by the respondent and recommendation for final action to be 
taken under this section; and
    (5) In cases involving a Sec. 190.211 hearing, any material 
submitted during and after the hearing and the presiding official's 
recommendation for final action to be taken under this section.
    (c) Based on a review of a case file described in paragraph (b) of 
this section, the Associate Administrator, OPS shall issue a final order 
that includes--
    (1) A statement of findings and determinations on all material 
issues, including a determination as to whether each alleged violation 
has been proved;
    (2) If a civil penalty is assessed, the amount of the penalty and 
the procedures for payment of the penalty, provided that the assessed 
civil penalty may not exceed the penalty proposed in the notice of 
probable violation; and
    (3) If a compliance order is issued, a statement of the actions 
required to be taken by the respondent and the time by which such 
actions must be accomplished.
    (d) Except as provided by Sec. 190.215, an order issued under this 
section regarding an enforcement proceeding is considered final 
administrative action on that enforcement proceeding.
    (e) It is the policy of the Associate Administrator, OPS to issue a 
final order under this section expeditiously. In cases where a 
substantial delay is expected, notice of that fact and the date by which 
it is expected that action will be taken is provided to the respondent 
upon request and whenever practicable.

[45 FR 20413, Mar. 27, 1980, as amended by Amdt. 190-6, 61 FR 18514, 
Apr. 26, 1996; 70 FR 11137, Mar. 8, 2005]



Sec. 190.215  Petitions for reconsideration.

    (a) A respondent may petition the Associate Administrator, OPS for 
reconsideration of a final order issued under Sec. 190.213. It is 
requested, but not required, that three copies be submitted. The 
petition must be received no later than 20 days after service of the 
final order upon the respondent. Petitions received after that time will 
not be considered. The petition must

[[Page 14]]

contain a brief statement of the complaint and an explanation as to why 
the effectiveness of the final order should be stayed.
    (b) If the respondent requests the consideration of additional facts 
or arguments, the respondent must submit the reasons they were not 
presented prior to issuance of the final order.
    (c) The Associate Administrator, OPS does not consider repetitious 
information, arguments, or petitions.
    (d) The filing of a petition under this section stays the payment of 
any civil penalty assessed. However, unless the Associate Administrator, 
OPS otherwise provides, the order, including any required corrective 
action, is not stayed.
    (e) The Associate Administrator, OPS may grant or deny, in whole or 
in part, any petition for reconsideration without further proceedings. 
In the event the Associate Administrator, OPS reconsiders a final order, 
a final decision on reconsideration may be issued without further 
proceedings, or, in the alternative, additional information, data, and 
comment may be requested by the Associate Administrator, OPS as deemed 
appropriate.
    (f) It is the policy of the Associate Administrator, OPS to issue 
notice of the action taken on a petition for reconsideration 
expeditiously. In cases where a substantial delay is expected, notice of 
that fact and the date by which it is expected that action will be taken 
is provided to the respondent upon request and whenever practicable.

[Amdt. 190-6, 61 FR 18514, Apr. 26, 1996, as amended by Amdt 190-7, 61 
FR 27792, June 3, 1996; 70 FR 11137, Mar. 8, 2005]

                            Compliance Orders



Sec. 190.217  Compliance orders generally.

    When the Associate Administrator, OPS has reason to believe that a 
person is engaging in conduct which involves a violation of the 49 
U.S.C. 60101 et seq. or any regulation issued thereunder, and if the 
nature of the violation, and the public interest warrant, the Associate 
Administrator, OPS may conduct proceedings under Sec. Sec. 190.207 
through 190.213 of this part to determine the nature and extent of the 
violations and to issue an order directing compliance.

[Amdt. 190-6, 61 FR 18514, Apr. 26, 1996]



Sec. 190.219  Consent order.

    (a) At any time before the issuance of a compliance order under 
Sec. 190.213 the Associate Administrator, OPS and the respondent may 
agree to dispose of the case by joint execution of a consent order. Upon 
such joint execution, the consent order shall be considered a final 
order under Sec. 190.213.
    (b) A consent order executed under paragraph (a) of this section 
shall include:
    (1) An admission by the respondent of all jurisdictional facts;
    (2) An express waiver of further procedural steps and of all right 
to seek judicial review or otherwise challenge or contest the validity 
of that order;
    (3) An acknowledgement that the notice of probable violation may be 
used to construe the terms of the consent order; and
    (4) A statement of the actions required of the respondent and the 
time by which such actions shall be accomplished.

[45 FR 20413, Mar. 27, 1980, as amended by Amdt. 190-6, 61 FR 18514, 
Apr. 26, 1996]

                             Civil Penalties



Sec. 190.221  Civil penalties generally.

    When the Associate Administrator, OPS has reason to believe that a 
person has committed an act which is a violation of any provision of the 
49 U.S.C. 60101 et seq. or any regulation or order issued thereunder, 
proceedings under Sec. Sec. 190.207 through 190.213 may be conducted to 
determine the nature and extent of the violations and to assess and, if 
appropriate, compromise a civil penalty.

[Amdt. 190-6, 61 FR 18515, Apr. 26, 1996]



Sec. 190.223  Maximum penalties.

    (a) Any person who is determined to have violated a provision of 49 
U.S.C. 60101 et seq., or any regulation or order issued thereunder, is 
subject to a civil penalty not to exceed $100,000 for each violation for 
each day the violation continues except that the maximum

[[Page 15]]

civil penalty may not exceed $1,000,000 for any related series of 
violations.
    (b) Any person who knowingly violates a regulation or order under 
this subchapter applicable to offshore gas gathering lines issued under 
the authority of 49 U.S.C. 5101 et seq is liable for a civil penalty of 
not more than $25,000 for each violation, and if any such violation is a 
continuing one, each day of violation constitutes a separate offense.
    (c) Any person who is determined to have violated any standard or 
order under 49 U.S.C. 60103 shall be subjected to a civil penalty of not 
to exceed $50,000, which penalty shall be in addition to any other 
penalties to which such person may be subject under paragraph (a) of 
this section.
    (d) Any person who is determined to have violated any standard or 
order under 49 U.S.C. 60129 shall be subject to a civil penalty not to 
exceed $1,000, which shall be in addition to any other penalties to 
which such person may be subject under paragraph (a) of this section.
    (e) No person shall be subject to a civil penalty under this section 
for the violation of any requirement of this subchapter and an order 
issued under Sec. 190.217, Sec. 190.219 or Sec. 190.233 if both 
violations are based on the same act.

[45 FR 20413, Mar. 27, 1980, as amended by Amdt. 190-2, 54 FR 32344, 
Aug. 7, 1989; Amdt. 190-6, 61 FR 18515, Apr. 26, 1996; 61 FR 38403, July 
24, 1996; 70 FR 11137, Mar. 8, 2005]



Sec. 190.225  Assessment considerations.

    In determining the amount of a civil penalty under this part,
    (a) The Associate Administrator, OPS shall consider:
    (1) The nature, circumstances and gravity of the violation, 
including adverse impact on the environment;
    (2) The degree of the respondent's culpability;
    (3) The respondent's history of prior offenses;
    (4) The respondent's ability to pay;
    (5) Any good faith by the respondent in attempting to achieve 
compliance;
    (6) The effect on the respondent's ability to continue in business; 
and
    (b) The Associate Administrator, OPS may consider:
    (1) The economic benefit gained from violation, if readily 
ascertainable, without any reduction because of subsequent damages; and
    (2) Such other matters as justice may require.

[70 FR 11137, Mar. 8, 2005]



Sec. 190.227  Payment of penalty.

    (a) Except for payments exceeding $10,000, payment of a civil 
penalty proposed or assessed under this subpart may be made by certified 
check or money order (containing the CPF Number for the case), payable 
to ``U.S. Department of Transportation,'' to the Federal Aviation 
Administration, Mike Monroney Aeronautical Center, Financial Operations 
Division (AMZ-341), P.O. Box 25770, Oklahoma City, OK 73125, or by wire 
transfer through the Federal Reserve Communications System (Fedwire) to 
the account of the U.S. Treasury. Payments exceeding $10,000 must be 
made by wire transfer.
    (b) Payment of a civil penalty assessed in a final order issued 
under Sec. 190.213 or affirmed in a decision on a petition for 
reconsideration must be made within 20 days after receipt of the final 
order or decision. Failure to do so will result in the initiation of 
collection action, including the accrual of interest and penalties, in 
accordance with 31 U.S.C. 3717 and 49 CFR part 89.

[Amdt. 190-7, 61 FR 27792, June 3, 1996, as amended at 70 FR 11138, Mar. 
8, 2005; 73 FR 16567, Mar. 28, 2008]

                           Criminal Penalties



Sec. 190.229  Criminal penalties generally.

    (a) Any person who willfully and knowingly violates a provision of 
49 U.S.C. 60101 et seq. or any regulation or order issued thereunder 
shall upon conviction be subject for each offense to a fine of not more 
than $25,000 and imprisonment for not more than five years, or both.
    (b) Any person who willfully violates a regulation or order under 
this subchapter issued under the authority of 49 U.S.C. 5101 et seq. as 
applied to offshore gas gathering lines shall upon conviction be subject 
for each offense to a fine of not more than $25,000, imprisonment for a 
term not to exceed 5 years, or both.

[[Page 16]]

    (c) Any person who willfully and knowingly injures or destroys, or 
attempts to injure or destroy, any interstate transmission facility, any 
interstate pipeline facility, or any intrastate pipeline facility used 
in interstate or foreign commerce or in any activity affecting 
interstate or foreign commerce (as those terms are defined in 49 U.S.C. 
60101 et seq.) shall, upon conviction, be subject for each offense to a 
fine of not more than $25,000, imprisonment for a term not to exceed 15 
years, or both.
    (d) Any person who willfully and knowingly defaces, damages, 
removes, destroys any pipeline sign, right-of-way marker, or marine buoy 
required by 49 U.S.C. 60101 et seq. or 49 U.S.C. 5101 et seq., or any 
regulation or order issued thereunder shall, upon conviction, be subject 
for each offense to a fine of not more than $5,000, imprisonment for a 
term not to exceed 1 year, or both.
    (e) Any person who willfully and knowingly engages in excavation 
activity without first using an available one-call notification system 
to establish the location of underground facilities in the excavation 
area; or without considering location information or markings 
established by a pipeline facility operator; and
    (1) Subsequently damages a pipeline facility resulting in death, 
serious bodily harm, or property damage exceeding $50,000;
    (2) Subsequently damages a pipeline facility and knows or has reason 
to know of the damage but fails to promptly report the damage to the 
operator and to the appropriate authorities; or
    (3) Subsequently damages a hazardous liquid pipeline facility that 
results in the release of more than 50 barrels of product; shall, upon 
conviction, be subject for each offense to a fine of not more than 
$5,000, imprisonment for a term not to exceed 5 years, or both.
    (f) No person shall be subject to criminal penalties under paragraph 
(a) of this section for violation of any regulation and the violation of 
any order issued under Sec. 190.217, Sec. 190.219 or Sec. 190.229 if 
both violations are based on the same act.

[45 FR 20413, Mar. 27, 1980, as amended by Amdt. 190-2, 54 FR 32344, 
Aug. 7, 1989; Amdt. 190-4, 56 FR 63770, Dec. 5, 1991; Amdt. 190-6, 61 FR 
18515, Apr. 26, 1996; 70 FR 11138, Mar. 8, 2005]



Sec. 190.231  Referral for prosecution.

    If an employee of the Pipeline and Hazardous Materials Safety 
Administration becomes aware of any actual or possible activity subject 
to criminal penalties under Sec. 190.229, the employee reports it to 
the Office of the Chief Counsel, Pipeline and Hazardous Materials Safety 
Administration, U.S. Department of Transportation, Washington, DC 20590. 
The Chief Counsel refers the report to OPS for investigation. Upon 
completion of the investigation and if appropriate, the Chief Counsel 
refers the report to the Department of Justice for criminal prosecution 
of the offender.

[Amdt. 190-6, 61 FR 18515, Apr. 26, 1996, as amended at 70 FR 11137, 
Mar. 8, 2005]

                             Specific Relief



Sec. 190.233  Corrective action orders.

    (a) Except as provided by paragraph (b) of this section, if the 
Associate Administrator, OPS finds, after reasonable notice and 
opportunity for hearing in accord with paragraph (c) of this section and 
Sec. 190.211(a), a particular pipeline facility to be hazardous to 
life, property, or the environment, the Associate Administrator, OPS 
shall issue an order pursuant to this section requiring the owner or 
operator of the facility to take corrective action. Corrective action 
may include suspended or restricted use of the facility, physical 
inspection, testing, repair, replacement, or other appropriate action.
    (b) The Associate Administrator, OPS may waive the requirement for 
notice and opportunity for hearing under paragraph (a) of this section 
before issuing an order pursuant to this section when the Associate 
Administrator, OPS determines that the failure to do so would result in 
the likelihood of serious harm to life, property, or the environment. 
However, the Associate Administrator, OPS shall provide an opportunity 
for a hearing as soon as is

[[Page 17]]

practicable after the issuance of a compliance order. The provisions of 
paragraph (c)(2) of this section apply to an owner or operator's 
decision to exercise its opportunity for a hearing. The purpose of such 
a post-order hearing is for the Associate Administrator, OPS to 
determine whether a compliance order should remain in effect or be 
rescinded or suspended in accord with paragraph (g) of this section.
    (c) Notice and hearing:
    (1) Written notice that OPS intends to issue an order under this 
section shall be served upon the owner or operator of an alleged 
hazardous facility in accordance with Sec. 190.5. The notice shall 
allege the existence of a hazardous facility and state the facts and 
circumstances supporting the issuance of a corrective action order. The 
notice shall also provide the owner or operator with the opportunity for 
a hearing and shall identify a time and location where a hearing may be 
held.
    (2) An owner or operator that elects to exercise its opportunity for 
a hearing under this section must notify the Associate Administrator, 
OPS of that election in writing within 10 days of service of the notice 
provided under paragraph (c)(1) of this section, or under paragraph (b) 
of this section when applicable. The absence of such written 
notification waives an owner or operator's opportunity for a hearing and 
allows the Associate Administrator, OPS to issue a corrective action 
order in accordance with paragraphs (d) through (h) of this section.
    (3) A hearing under this section shall be presided over by an 
attorney from the Office of Chief Counsel, Pipeline and Hazardous 
Materials Safety Administration, acting as Presiding Official, and 
conducted without strict adherence to formal rules of evidence. The 
Presiding Official presents the allegations contained in the notice 
issued under this section. The owner or operator of the alleged 
hazardous facility may submit any relevant information or materials, 
call witnesses, and present arguments on the issue of whether or not a 
corrective action order should be issued.
    (4) Within 48 hours after conclusion of a hearing under this 
section, the Presiding Official shall submit a recommendation to the 
Associate Administrator, OPS as to whether or not a corrective action 
order is required. Upon receipt of the recommendation, the Associate 
Administrator, OPS shall proceed in accordance with paragraphs (d) 
through (h) of this section. If the Associate Administrator, OPS finds 
the facility is or would be hazardous to life, property, or the 
environment, the Associate Administrator, OPS shall issue a corrective 
action order in accordance with this section. If the Associate 
Administrator, OPS does not find the facility is or would be hazardous 
to life, property, or the environment, the Associate Administrator shall 
withdraw the allegation of the existence of a hazardous facility 
contained in the notice, and promptly notify the owner or operator in 
writing by service as prescribed in Sec. 190.5.
    (d) The Associate Administrator, OPS may find a pipeline facility to 
be hazardous under paragraph (a) of this section:
    (1) If under the facts and circumstances the Associate 
Administrator, OPS determines the particular facility is hazardous to 
life, property, or the environment; or
    (2) If the pipeline facility or a component thereof has been 
constructed or operated with any equipment, material, or technique which 
the Associate Administrator, OPS determines is hazardous to life, 
property, or the environment, unless the operator involved demonstrates 
to the satisfaction of the Associate Administrator, OPS that, under the 
particular facts and circumstances involved, such equipment, material, 
or technique is not hazardous.
    (e) In making a determination under paragraph (d) of this section, 
the Associate Administrator, OPS shall consider, if relevant:
    (1) The characteristics of the pipe and other equipment used in the 
pipeline facility involved, including its age, manufacturer, physical 
properties (including its resistance to corrosion and deterioration), 
and the method of its manufacture, construction or assembly;
    (2) The nature of the materials transported by such facility 
(including their corrosive and deteriorative qualities),

[[Page 18]]

the sequence in which such materials are transported, and the pressure 
required for such transportation;
    (3) The characteristics of the geographical areas in which the 
pipeline facility is located, in particular the climatic and geologic 
conditions (including soil characteristics) associated with such areas, 
and the population density and population and growth patterns of such 
areas;
    (4) Any recommendation of the National Transportation Safety Board 
issued in connection with any investigation conducted by the Board; and
    (5) Such other factors as the Associate Administrator, OPS may 
consider appropriate.
    (f) A corrective action order shall contain the following 
information:
    (1) A finding that the pipeline facility is hazardous to life, 
property, or the environment.
    (2) The relevant facts which form the basis of that finding.
    (3) The legal basis for the order.
    (4) The nature and description of any particular corrective action 
required of the respondent.
    (5) The date by which the required corrective action must be taken 
or completed and, where appropriate, the duration of the order.
    (6) If the opportunity for a hearing was waived pursuant to 
paragraph (b) of this section, a statement that an opportunity for a 
hearing will be available at a particular time and location after 
issuance of the order.
    (g) The Associate Administrator, OPS shall rescind or suspend a 
corrective action order whenever the Associate Administrator, OPS 
determines that the facility is no longer hazardous to life, property, 
or the environment. When appropriate, however, such a rescission or 
suspension may be accompanied by a notice of probable violation issued 
under Sec. 190.207.
    (h) At any time after a corrective action order issued under this 
section has become effective, the Associate Administrator, OPS may 
request the Attorney General to bring an action for appropriate relief 
in accordance with Sec. 190.235.
    (i) Upon petition by the Attorney General, the District Courts of 
the United States shall have jurisdiction to enforce orders issued under 
this section by appropriate means.

[70 FR 11138, Mar. 8, 2005]



Sec. 190.235  Civil actions generally.

    Whenever it appears to the Associate Administrator, OPS that a 
person has engaged, is engaged, or is about to engage in any act or 
practice constituting a violation of any provision of 49 U.S.C. 60101 et 
seq., or any regulations issued thereunder, the Administrator, PHMSA, or 
the person to whom the authority has been delegated, may request the 
Attorney General to bring an action in the appropriate U.S. District 
Court for such relief as is necessary or appropriate, including 
mandatory or prohibitive injunctive relief, interim equitable relief, 
civil penalties, and punitive damages as provided under 49 U.S.C. 60120 
and 49 U.S.C. 5123.

[70 FR 11139, Mar. 8, 2005]



Sec. 190.237  Amendment of plans or procedures.

    (a) A Regional Director begins a proceeding to determine whether an 
operator's plans or procedures required under parts 192, 193, 195, and 
199 of this subchapter are inadequate to assure safe operation of a 
pipeline facility by issuing a notice of amendment. The notice shall 
provide an opportunity for a hearing under Sec. 190.211 of this part 
and shall specify the alleged inadequacies and the proposed action for 
revision of the plans or procedures. The notice shall allow the operator 
30 days after receipt of the notice to submit written comments or 
request a hearing. After considering all material presented in writing 
or at the hearing, the Associate Administrator, OPS shall determine 
whether the plans or procedures are inadequate as alleged and order the 
required amendment if they are inadequate, or withdraw the notice if 
they are not. In determining the adequacy of an operator's plans or 
procedures, the Associate Administrator, OPS shall consider:
    (1) Relevant available pipeline safety data;
    (2) Whether the plans or procedures are appropriate for the 
particular type of pipeline transportation or facility, and for the 
location of the facility;

[[Page 19]]

    (3) The reasonableness of the plans or procedures; and
    (4) The extent to which the plans or procedures contribute to public 
safety.
    (b) The amendment of an operator's plans or procedures prescribed in 
paragraph (a) of this section is in addition to, and may be used in 
conjunction with, the appropriate enforcement actions prescribed in this 
subpart.

[Amdt. 190-3, 56 FR 31090, July 9, 1991, as amended by Amdt. 190-6, 61 
FR 18516, Apr. 26, 1996]



               Subpart C_Procedures for Adoption of Rules

    Source: Amdt. 190-8, 61 FR 50909, Sept. 27, 1996, unless otherwise 
noted.



Sec. 190.239  Safety orders.

    (a) When may PHMSA issue a safety order? If the Associate 
Administrator, OPS finds, after notice and an opportunity for hearing 
under paragraph (b) of this section, that a particular pipeline facility 
has a condition or conditions that pose a pipeline integrity risk to 
public safety, property, or the environment, the Associate Administrator 
may issue an order requiring the operator of the facility to take 
necessary corrective action. Such action may include physical 
inspection, testing, repair or other appropriate action to remedy the 
identified risk condition.
    (b) How is an operator notified of the proposed issuance of a safety 
order and what are its response options? (1) Notice of proposed safety 
order. PHMSA will serve written notice of a proposed safety order under 
Sec. 190.5 to an operator of the pipeline facility. The notice will 
allege the existence of a condition that poses a pipeline integrity risk 
to public safety, property, or the environment, and state the facts and 
circumstances that support issuing a safety order for the specified 
pipeline or portion thereof. The notice will also specify proposed 
testing, evaluations, integrity assessment, or other actions to be taken 
by the operator and may propose that the operator submit a work plan and 
schedule to address the conditions identified in the notice. The notice 
will also provide the operator with its response options, including 
procedures for requesting informal consultation and a hearing. An 
operator receiving a notice will have 30 days to respond to the PHMSA 
official who issued the notice.
    (2) Informal consultation. Upon timely request by the operator, 
PHMSA will provide an opportunity for informal consultation concerning 
the proposed safety order. Such informal consultation shall commence 
within 30 days, provided that PHMSA may extend this time by request or 
otherwise for good cause. Informal consultation provides an opportunity 
for the respondent to explain the circumstances associated with the risk 
condition(s) identified in the notice and, where appropriate, to present 
a proposal for corrective action, without prejudice to the operator's 
position in any subsequent hearing. If the respondent and Regional 
Director agree within 30 days of the informal consultation on a plan for 
the operator to address each risk condition, they may enter into a 
written consent agreement and the Associate Administrator may issue a 
consent order incorporating the terms of the agreement. If a consent 
agreement is reached, no further hearing will be provided in the matter 
and any pending hearing request will be considered withdrawn. If a 
consent agreement is not reached within 30 days of the informal 
consultation (or if informal consultation is not requested), the 
Associate Administrator may proceed under paragraphs (b)(3) through (5) 
of this section. If PHMSA subsequently determines that an operator has 
failed to comply with the terms of a consent order, PHMSA may obtain any 
administrative or judicial remedies available under 49 U.S.C. 60101 et 
seq. and this part. If a consent agreement is not reached, any 
admissions made by the operator during the informal consultation shall 
be excluded from the record in any subsequent hearing. Nothing in this 
paragraph (b) precludes PHMSA from terminating the informal consultation 
process if it has reason to believe that the operator is not engaging in 
good faith discussions or otherwise concludes that further consultation 
would not be productive or in the public interest.
    (3) Hearing. An operator receiving a notice of proposed safety order 
may

[[Page 20]]

contest the notice, or any portion thereof, by filing a written request 
for a hearing within 30 days following receipt of the notice or within 
10 days following the conclusion of informal consultation that did not 
result in a consent agreement, as applicable. In the absence of a timely 
request for a hearing, the Associate Administrator may issue a safety 
order in the form of the proposed order in accordance with paragraphs 
(c) through (g) of this section.
    (4) Conduct of hearing. An attorney from the Office of Chief 
Counsel, PHMSA, will serve as the Presiding Official in a hearing under 
this section. The hearing will be conducted informally, without strict 
adherence to formal rules of evidence in accordance with Sec. 190.211. 
The respondent may submit any relevant information or materials, call 
witnesses, and present arguments on the issue of whether a safety order 
should be issued to address the alleged presence of a condition that 
poses a pipeline integrity risk to public safety, property, or the 
environment.
    (5) Post-hearing action. Following a hearing under this section, the 
Presiding Official will submit a recommendation to the Associate 
Administrator concerning issuance of a final safety order. Upon receipt 
of the recommendation, the Associate Administrator may proceed under 
paragraphs (c) through (g) of this section. If the Associate 
Administrator finds the facility to have a condition that poses a 
pipeline integrity risk to public safety, property, or the environment, 
the Associate Administrator will issue a safety order under this 
section. If the Associate Administrator does not find that the facility 
has such a condition, or concludes that a safety order is otherwise not 
warranted, the Associate Administrator will withdraw the notice and 
promptly notify the operator in writing by service as prescribed in 
Sec. 190.5. Nothing in this subsection precludes PHMSA and the operator 
from entering into a consent agreement at any time before a safety order 
is issued.
    (6) Termination of safety order. Once all remedial actions set forth 
in the safety order and associated work plans are completed, as 
determined by PHMSA, the Associate Administrator will notify the 
operator that the safety order has been lifted. The Associate 
Administrator shall suspend or terminate a safety order whenever the 
Associate Administrator determines that the pipeline facility no longer 
has a condition or conditions that pose a pipeline integrity risk to 
public safety, property, or the environment.
    (c) How is the determination made that a pipeline facility has a 
condition that poses an integrity risk? The Associate Administrator, OPS 
may find a pipeline facility to have a condition that poses a pipeline 
integrity risk to public safety, property, or the environment under 
paragraph (a) of this section:
    (1) If under the facts and circumstances the Associate Administrator 
determines the particular facility has such a condition; or
    (2) If the pipeline facility or a component thereof has been 
constructed or operated with any equipment, material, or technique with 
a history of being susceptible to failure when used in pipeline service, 
unless the operator involved demonstrates that such equipment, material, 
or technique is not susceptible to failure given the manner it is being 
used for a particular facility.
    (d) What factors must PHMSA consider in making a determination that 
a risk condition is present? In making a determination under paragraph 
(c) of this section, the Associate Administrator, OPS shall consider, if 
relevant:
    (1) The characteristics of the pipe and other equipment used in the 
pipeline facility involved, including its age, manufacturer, physical 
properties (including its resistance to corrosion and deterioration), 
and the method of its manufacture, construction or assembly;
    (2) The nature of the materials transported by such facility 
(including their corrosive and deteriorative qualities), the sequence in 
which such materials are transported, and the pressure required for such 
transportation;

[[Page 21]]

    (3) The characteristics of the geographical areas where the pipeline 
facility is located, in particular the climatic and geologic conditions 
(including soil characteristics) associated with such areas;
    (4) For hazardous liquid pipelines, the proximity of the pipeline to 
an unusually sensitive area;
    (5) The population density and growth patterns of the area in which 
the pipeline facility is located;
    (6) Any relevant recommendation of the National Transportation 
Safety Board issued in connection with any investigation conducted by 
the Board;
    (7) The likelihood that the condition will impair the serviceability 
of the pipeline;
    (8) The likelihood that the condition will worsen over time; and
    (9) The likelihood that the condition is present or could develop on 
other areas of the pipeline.
    (e) What information will be included in a safety order? A safety 
order shall contain the following:
    (1) A finding that the pipeline facility has a condition that poses 
a pipeline integrity risk to public safety, property, or the 
environment;
    (2) The relevant facts which form the basis of that finding;
    (3) The legal basis for the order;
    (4) The nature and description of any particular corrective actions 
to be required of the operator; and
    (5) The date(s) by which the required corrective actions must be 
taken or completed and, where appropriate, the duration of the order.
    (f) Can PHMSA take other enforcement actions on the affected 
facilities? Nothing in this section precludes PHMSA from issuing a 
Notice of Probable Violation under Sec. 190.207 or taking other 
enforcement action if noncompliance is identified at the facilities that 
are the subject of a safety order proceeding.

[73 FR 16567, Mar. 28, 2008, as amended at 74 FR 2893, Jan. 16, 2009]



Sec. 190.301  Scope.

    This subpart prescribes general rulemaking procedures for the issue, 
amendment, and repeal of Pipeline Safety Program regulations of the 
Pipeline and Hazardous Materials Safety Administration of the Department 
of Transportation.

[Amdt. 190-8, 61 FR 50909, Sept. 27, 1996, as amended at 70 FR 11137, 
Mar. 8, 2005]



Sec. 190.303  Delegations.

    For the purposes of this subpart, Administrator means the 
Administrator, Pipeline and Hazardous Materials Safety Administration, 
or his or her delegate.

[Amdt. 190-8, 61 FR 50909, Sept. 27, 1996, as amended at 70 FR 11137, 
Mar. 8, 2005]



Sec. 190.305  Regulatory dockets.

    (a) Information and data considered relevant by the Administrator 
relating to rulemaking actions, including notices of proposed 
rulemaking; comments received in response to notices; petitions for 
rulemaking and reconsideration; denials of petitions for rulemaking and 
reconsideration; records of additional rulemaking proceedings under 
Sec. 190.325; and final regulations are maintained by the Pipeline and 
Hazardous Materials Safety Administration at 1200 New Jersey Avenue, SE, 
Washington, D.C. 20590-0001.
    (b) Once a public docket is established, docketed material may be 
accessed at http://www.regulations.gov. Public comments also may be 
submitted at http://www.regulations.gov. Comment submissions must 
identify the docket number. You may also examine public docket material 
at the offices of the Docket Operations Facility (M-30), U.S. Department 
of Transportation, West Building, First Floor, Room W12-140, 1200 New 
Jersey Avenue, SE., Washington, DC 20590. You may obtain a copy during 
normal business hours, excluding Federal holidays, for a fee, with the 
exception of material which the Administrator of PHMSA determines should 
be withheld from public disclosure under 5 U.S.C. 552(b) or any other 
applicable statutory provision.

[Amdt. 190-8, 61 FR 50909, Sept. 27, 1996, as amended at 70 FR 11137 and 
11139, Mar. 8, 2005; 73 FR 16566, Mar. 28, 2008; 73 FR 16568, Mar. 28, 
2008]

[[Page 22]]



Sec. 190.307  Records.

    Records of the Pipeline and Hazardous Materials Safety 
Administration relating to rulemaking proceedings are available for 
inspection as provided in section 552(b) of title 5, United States Code, 
and part 7 of the Regulations of the Office of the Secretary of 
Transportation (part 7 of this title).

[Amdt. 190-8, 61 FR 50909, Sept. 27, 1996, as amended at 70 FR 11137, 
Mar. 8, 2005]



Sec. 190.309  Where to file petitions.

    Petitions for extension of time to comment submitted under Sec. 
190.319, petitions for hearings submitted under Sec. 190.327, petitions 
for rulemaking submitted under Sec. 190.331, and petitions for 
reconsideration submitted under Sec. 190.335 must be submitted to: 
Administrator, Pipeline and Hazardous Materials Safety Administration, 
U.S. Department of Transportation, 1200 New Jersey Avenue, SE, 
Washington, D.C. 20590-0001.

[Amdt. 190-8, 61 FR 50909, Sept. 27, 1996, as amended at 70 FR 11137, 
Mar. 8, 2005; 73 FR 16566, Mar. 28, 2008]



Sec. 190.311  General.

    Unless the Administrator, for good cause, finds that notice is 
impracticable, unnecessary, or contrary to the public interest, and 
incorporates that finding and a brief statement of the reasons for it in 
the rule, a notice of proposed rulemaking is issued and interested 
persons are invited to participate in the rulemaking proceedings with 
respect to each substantive rule.



Sec. 190.313  Initiation of rulemaking.

    The Administrator initiates rulemaking on his or her own motion; 
however, in so doing, the Administrator may use discretion to consider 
the recommendations of other agencies of the United States or of other 
interested persons including those of any technical advisory body 
established by statute for that purpose.



Sec. 190.315  Contents of notices of proposed rulemaking.

    (a) Each notice of proposed rulemaking is published in the Federal 
Register, unless all persons subject to it are named and are personally 
served with a copy of it.
    (b) Each notice, whether published in the Federal Register or 
personally served, includes:
    (1) A statement of the time, place, and nature of the proposed 
rulemaking proceeding;
    (2) A reference to the authority under which it is issued;
    (3) A description of the subjects and issues involved or the 
substance and terms of the proposed regulation;
    (4) A statement of the time within which written comments must be 
submitted; and
    (5) A statement of how and to what extent interested persons may 
participate in the proceeding.



Sec. 190.317  Participation by interested persons.

    (a) Any interested person may participate in rulemaking proceedings 
by submitting comments in writing containing information, views or 
arguments in accordance with instructions for participation in the 
rulemaking document.
    (b) The Administrator may invite any interested person to 
participate in the rulemaking proceedings described in Sec. 190.325.
    (c) For the purposes of this subpart, an interested person includes 
any Federal or State government agency or any political subdivision of a 
State.



Sec. 190.319  Petitions for extension of time to comment.

    A petition for extension of the time to submit comments must be 
received not later than 10 days before expiration of the time stated in 
the notice. It is requested, but not required, that three copies be 
submitted. The filing of the petition does not automatically extend the 
time for petitioner's comments. A petition is granted only if the 
petitioner shows good cause for the extension, and if the extension is 
consistent with the public interest. If an extension is granted, it is 
granted to all persons, and it is published in the Federal Register.

[[Page 23]]



Sec. 190.321  Contents of written comments.

    All written comments must be in English. It is requested, but not 
required, that five copies be submitted. Any interested person should 
submit as part of written comments all material considered relevant to 
any statement of fact. Incorporation of material by reference should be 
avoided; however, where necessary, such incorporated material shall be 
identified by document title and page.



Sec. 190.323  Consideration of comments received.

    All timely comments and the recommendations of any technical 
advisory body established by statute for the purpose of reviewing the 
proposed rule concerned are considered before final action is taken on a 
rulemaking proposal. Late filed comments are considered so far as 
practicable.



Sec. 190.325  Additional rulemaking proceedings.

    The Administrator may initiate any further rulemaking proceedings 
that the Administrator finds necessary or desirable. For example, 
interested persons may be invited to make oral arguments, to participate 
in conferences between the Administrator or the Administrator's 
representative and interested persons, at which minutes of the 
conference are kept, to appear at informal hearings presided over by 
officials designated by the Administrator at which a transcript of 
minutes are kept, or participate in any other proceeding to assure 
informed administrative action and to protect the public interest.



Sec. 190.327  Hearings.

    (a) If a notice of proposed rulemaking does not provide for a 
hearing, any interested person may petition the Administrator for an 
informal hearing. The petition must be received by the Administrator not 
later than 20 days before expiration of the time stated in the notice. 
The filing of the petition does not automatically result in the 
scheduling of a hearing. A petition is granted only if the petitioner 
shows good cause for a hearing. If a petition for a hearing is granted, 
notice of the hearing is published in the Federal Register.
    (b) Sections 556 and 557 of title 5, United States Code, do not 
apply to hearings held under this part. Unless otherwise specified, 
hearings held under this part are informal, nonadversary fact-finding 
proceedings, at which there are no formal pleadings or adverse parties. 
Any regulation issued in a case in which an informal hearing is held is 
not necessarily based exclusively on the record of the hearing.
    (c) The Administrator designates a representative to conduct any 
hearing held under this subpart. The Chief Counsel designates a member 
of his or her staff to serve as legal officer at the hearing.



Sec. 190.329  Adoption of final rules.

    Final rules are prepared by representatives of the Office of 
Pipeline Safety and the Office of the Chief Counsel. The regulation is 
then submitted to the Administrator for consideration. If the 
Administrator adopts the regulation, it is published in the Federal 
Register, unless all persons subject to it are named and are personally 
served with a copy of it.



Sec. 190.331  Petitions for rulemaking.

    (a) Any interested person may petition the Associate Administrator 
for Pipeline Safety to establish, amend, or repeal a substantive 
regulation, or may petition the Chief Counsel to establish, amend, or 
repeal a procedural regulation.
    (b) Each petition filed under this section must--
    (1) Summarize the proposed action and explain its purpose;
    (2) State the text of the proposed rule or amendment, or specify the 
rule proposed to be repealed;
    (3) Explain the petitioner's interest in the proposed action and the 
interest of any party the petitioner represents; and
    (4) Provide information and arguments that support the proposed 
action, including relevant technical, scientific or other data as 
available to the petitioner, and any specific known cases that 
illustrate the need for the proposed action.

[[Page 24]]

    (c) If the potential impact of the proposed action is substantial, 
and information and data related to that impact are available to the 
petitioner, the Associate Administrator or the Chief Counsel may request 
the petitioner to provide--
    (1) The costs and benefits to society and identifiable groups within 
society, quantifiable and otherwise;
    (2) The direct effects (including preemption effects) of the 
proposed action on States, on the relationship between the Federal 
Government and the States, and on the distribution of power and 
responsibilities among the various levels of government;
    (3) The regulatory burden on small businesses, small organizations 
and small governmental jurisdictions;
    (4) The recordkeeping and reporting requirements and to whom they 
would apply; and
    (5) Impacts on the quality of the natural and social environments.
    (d) The Associate Administrator or Chief Counsel may return a 
petition that does not comply with the requirements of this section, 
accompanied by a written statement indicating the deficiencies in the 
petition.



Sec. 190.333  Processing of petition.

    (a) General. Unless the Associate Administrator or the Chief Counsel 
otherwise specifies, no public hearing, argument, or other proceeding is 
held directly on a petition before its disposition under this section.
    (b) Grants. If the Associate Administrator or the Chief Counsel 
determines that the petition contains adequate justification, he or she 
initiates rulemaking action under this subpart.
    (c) Denials. If the Associate Administrator or the Chief Counsel 
determines that the petition does not justify rulemaking, the petition 
is denied.
    (d) Notification. The Associate Administrator or the Chief Counsel 
will notify a petitioner, in writing, of the decision to grant or deny a 
petition for rulemaking.



Sec. 190.335  Petitions for reconsideration.

    (a) Except as provided in Sec. 190.339(d), any interested person 
may petition the Associate Administrator for reconsideration of any 
regulation issued under this subpart, or may petition the Chief Counsel 
for reconsideration of any procedural regulation issued under this 
subpart and contained in this subpart. It is requested, but not 
required, that three copies be submitted. The petition must be received 
not later than 30 days after publication of the rule in the Federal 
Register. Petitions filed after that time will be considered as 
petitions filed under Sec. 190.331. The petition must contain a brief 
statement of the complaint and an explanation as to why compliance with 
the rule is not practicable, is unreasonable, or is not in the public 
interest.
    (b) If the petitioner requests the consideration of additional 
facts, the petitioner must state the reason they were not presented to 
the Associate Administrator or the Chief Counsel within the prescribed 
time.
    (c) The Associate Administrator or the Chief Counsel does not 
consider repetitious petitions.
    (d) Unless the Associate Administrator or the Chief Counsel 
otherwise provides, the filing of a petition under this section does not 
stay the effectiveness of the rule.



Sec. 190.337  Proceedings on petitions for reconsideration.

    (a) The Associate Administrator or the Chief Counsel may grant or 
deny, in whole or in part, any petition for reconsideration without 
further proceedings, except where a grant of the petition would result 
in issuance of a new final rule. In the event that the Associate 
Administrator or the Chief Counsel determines to reconsider any 
regulation, a final decision on reconsideration may be issued without 
further proceedings, or an opportunity to submit comment or information 
and data as deemed appropriate, may be provided. Whenever the Associate 
Administrator or the Chief Counsel determines that a petition should be 
granted or denied, the Office of the Chief Counsel prepares a notice of 
the grant or denial of a petition for reconsideration, for issuance to 
the petitioner, and the Associate Administrator or the Chief Counsel 
issues it to the petitioner. The Associate Administrator or the Chief 
Counsel may consolidate petitions relating to the same rules.

[[Page 25]]

    (b) It is the policy of the Associate Administrator or the Chief 
Counsel to issue notice of the action taken on a petition for 
reconsideration within 90 days after the date on which the regulation in 
question is published in the Federal Register, unless it is found 
impracticable to take action within that time. In cases where it is so 
found and the delay beyond that period is expected to be substantial, 
notice of that fact and the date by which it is expected that action 
will be taken is issued to the petitioner and published in the Federal 
Register.



Sec. 190.338  Appeals.

    (a) Any interested person may appeal a denial of the Associate 
Administrator or the Chief Counsel, issued under Sec. 190.333 or Sec. 
190.337, to the Administrator.
    (b) An appeal must be received within 20 days of service of written 
notice to petitioner of the Associate Administrator's or the Chief 
Counsel's decision, or within 20 days from the date of publication of 
the decision in the Federal Register, and should set forth the contested 
aspects of the decision as well as any new arguments or information.
    (c) It is requested, but not required, that three copies of the 
appeal be submitted to the Administrator.
    (d) Unless the Administrator otherwise provides, the filing of an 
appeal under this section does not stay the effectiveness of any rule.



Sec. 190.339  Direct final rulemaking.

    (a) Where practicable, the Administrator will use direct final 
rulemaking to issue the following types of rules:
    (1) Minor, substantive changes to regulations;
    (2) Incorporation by reference of the latest edition of technical or 
industry standards;
    (3) Extensions of compliance dates; and
    (4) Other noncontroversial rules where the Administrator determines 
that use of direct final rulemaking is in the public interest, and that 
a regulation is unlikely to result in adverse comment.
    (b) The direct final rule will state an effective date. The direct 
final rule will also state that unless an adverse comment or notice of 
intent to file an adverse comment is received within the specified 
comment period, generally 60 days after publication of the direct final 
rule in the Federal Register, the Administrator will issue a 
confirmation document, generally within 15 days after the close of the 
comment period, advising the public that the direct final rule will 
either become effective on the date stated in the direct final rule or 
at least 30 days after the publication date of the confirmation 
document, whichever is later.
    (c) For purposes of this section, an adverse comment is one which 
explains why the rule would be inappropriate, including a challenge to 
the rule's underlying premise or approach, or would be ineffective or 
unacceptable without a change. Comments that are frivolous or 
insubstantial will not be considered adverse under this procedure. A 
comment recommending a rule change in addition to the rule will not be 
considered an adverse comment, unless the commenter states why the rule 
would be ineffective without the additional change.
    (d) Only parties who filed comments to a direct final rule issued 
under this section may petition under Sec. 190.335 for reconsideration 
of that direct final rule.
    (e) If an adverse comment or notice of intent to file an adverse 
comment is received, a timely document will be published in the Federal 
Register advising the public and withdrawing the direct final rule in 
whole or in part. The Administrator may then incorporate the adverse 
comment into a subsequent direct final rule or may publish a notice of 
proposed rulemaking. A notice of proposed rulemaking will provide an 
opportunity for public comment, generally a minimum of 60 days, and will 
be processed in accordance with Sec. Sec. 190.311-190.329.



Sec. 190.341  Special permits.

    (a) What is a special permit? A special permit is an order by which 
PHMSA waives compliance with one or more of the Federal pipeline safety 
regulations under the standards set forth in 49 U.S.C. 60118(c) and 
subject to conditions set forth in the order. A special permit is issued 
to a pipeline operator

[[Page 26]]

(or prospective operator) for specified facilities that are or, absent 
waiver, would be subject to the regulation.
    (b) How do I apply for a special permit? Applications for special 
permits must be submitted at least 120 days before the requested 
effective date using any of the following methods:
    (1) Direct fax to PHMSA at: 202-366-4566; or
    (2) Mail, express mail, or overnight courier to the Associate 
Administrator for Pipeline Safety, Pipeline and Hazardous Materials 
Safety Administration, 1200 New Jersey Avenue, SE., East Building, 
Washington, DC 20590.
    (c) What information must be contained in the application? 
Applications must contain the following information:
    (1) The name, mailing address, and telephone number of the applicant 
and whether the applicant is an operator;
    (2) A detailed description of the pipeline facilities for which the 
special permit is sought, including:
    (i) The beginning and ending points of the pipeline mileage to be 
covered and the Counties and States in which it is located;
    (ii) Whether the pipeline is interstate or intrastate and a general 
description of the right-of-way including proximity of the affected 
segments to populated areas and unusually sensitive areas;
    (iii) Relevant pipeline design and construction information 
including the year of installation, the material, grade, diameter, wall 
thickness, and coating type; and
    (iv) Relevant operating information including operating pressure, 
leak history, and most recent testing or assessment results;
    (3) A list of the specific regulation(s) from which the applicant 
seeks relief;
    (4) An explanation of the unique circumstances that the applicant 
believes make the applicability of that regulation or standard (or 
portion thereof) unnecessary or inappropriate for its facility;
    (5) A description of any measures or activities the applicant 
proposes to undertake as an alternative to compliance with the relevant 
regulation, including an explanation of how such measures will mitigate 
any safety or environmental risks;
    (6) A description of any positive or negative impacts on affected 
stakeholders and a statement indicating how operating the pipeline 
pursuant to a special permit would be in the public interest;
    (7) A certification that operation of the applicant's pipeline under 
the requested special permit would not be inconsistent with pipeline 
safety;
    (8) If the application is for a renewal of a previously granted 
waiver or special permit, a copy of the original grant of the waiver or 
permit; and
    (9) Any other information PHMSA may need to process the application 
including environmental analysis where necessary.
    (d) How does PHMSA handle special permit applications? (1) Public 
notice. Upon receipt of an application for a special permit, PHMSA will 
provide notice to the public of its intent to consider the application 
and invite comment. In addition, PHMSA may consult with other Federal 
agencies before granting or denying an application on matters that PHMSA 
believes may have significance for proceedings under their areas of 
responsibility.
    (2) Grants and denials. If the Associate Administrator determines 
that the application complies with the requirements of this section and 
that the waiver of the relevant regulation or standard is not 
inconsistent with pipeline safety, the Associate Administrator may grant 
the application, in whole or in part, on a temporary or permanent basis. 
Conditions may be imposed on the grant if the Associate Administrator 
concludes they are necessary to assure safety, environmental protection, 
or are otherwise in the public interest. If the Associate Administrator 
determines that the application does not comply with the requirements of 
this section or that a waiver is not justified, the application will be 
denied. Whenever the Associate Administrator grants or denies an 
application, notice of the decision will be provided to the applicant. 
PHMSA will post all special permits on its Web site at http://
www.phmsa.dot.gov/.
    (e) Can a special permit be requested on an emergency basis? Yes. 
PHMSA may grant an application for an emergency special permit without 
notice

[[Page 27]]

and comment or hearing if the Associate Administrator determines that 
such action is in the public interest, is not inconsistent with pipeline 
safety, and is necessary to address an actual or impending emergency 
involving pipeline transportation. For purposes of this section, an 
emergency event may be local, regional, or national in scope and 
includes significant fuel supply disruptions and natural or manmade 
disasters such as hurricanes, floods, earthquakes, terrorist acts, 
biological outbreaks, releases of dangerous radiological, chemical, or 
biological materials, war-related activities, or other similar events. 
PHMSA will determine on a case-by-case basis what duration is necessary 
to address the emergency. However, as required by statute, no emergency 
special permit may be issued for a period of more than 60 days. Each 
emergency special permit will automatically expire on the date specified 
in the permit. Emergency special permits may be renewed upon application 
to PHMSA only after notice and opportunity for a hearing on the renewal.
    (f) How do I apply for an emergency special permit? Applications for 
emergency special permits may be submitted to PHMSA using any of the 
following methods:
    (1) Direct fax to the Crisis Management Center at: 202-366-3768;
    (2) Direct e-mail to PHMSA at: phmsa.pipeline-
emergencyspecpermit@dot.gov; or
    (3) Express mail/overnight courier to the Associate Administrator 
for Pipeline Safety, Pipeline and Hazardous Materials Safety 
Administration, 1200 New Jersey Avenue, SE., East Building, Washington, 
DC 20590.
    (g) What must be contained in an application for an emergency 
special permit? In addition to the information required under paragraph 
(c) of this section, applications for emergency special permits must 
include:
    (1) An explanation of the actual or impending emergency and how the 
applicant is affected;
    (2) A citation of the regulations that are implicated and the 
specific reasons the permit is necessary to address the emergency (e.g., 
lack of accessibility, damaged equipment, insufficient manpower);
    (3) A statement indicating how operating the pipeline pursuant to an 
emergency special permit is in the public interest (e.g., continuity of 
service, service restoration);
    (4) A description of any proposed alternatives to compliance with 
the regulation (e.g., additional inspections and tests, shortened 
reassessment intervals); and
    (5) A description of any measures to be taken after the emergency 
situation or permit expires--whichever comes first--to confirm long-term 
operational reliability of the pipeline facility.
    Note to paragraph (g): If PHMSA determines that handling of the 
application on an emergency basis is not warranted, PHMSA will notify 
the applicant and process the application under normal special permit 
procedures of this section.
    (h) In what circumstances will PHMSA revoke, suspend, or modify a 
special permit?
    (1) PHMSA may revoke, suspend, or modify a special permit on a 
finding that:
    (i) Intervening changes in Federal law mandate revocation, 
suspension, or modification of the special permit;
    (ii) Based on a material change in conditions or circumstances, 
continued adherence to the terms of the special permit would be 
inconsistent with safety;
    (iii) The application contained inaccurate or incomplete 
information, and the special permit would not have been granted had the 
application been accurate and complete;
    (iv) The application contained deliberately inaccurate or incomplete 
information; or
    (v) The holder has failed to comply with any material term or 
condition of the special permit.
    (2) Except as provided in paragraph (h)(3) of this section, before a 
special permit is modified, suspended or revoked, PHMSA will notify the 
holder in writing of the proposed action and the reasons for it, and 
provide an opportunity to show cause why the proposed action should not 
be taken.

[[Page 28]]

    (i) The holder may file a written response that shows cause why the 
proposed action should not be taken within 30 days of receipt of notice 
of the proposed action.
    (ii) After considering the holder's written response, or after 30 
days have passed without response since receipt of the notice, PHMSA 
will notify the holder in writing of the final decision with a brief 
statement of reasons.
    (3) If necessary to avoid a risk of significant harm to persons, 
property, or the environment, PHMSA may in the notification declare the 
proposed action immediately effective.
    (4) Unless otherwise specified, the terms and conditions of a 
corrective action order, compliance order, or other order applicable to 
a pipeline facility covered by a special permit will take precedence 
over the terms of the special permit.
    (5) A special permit holder may seek reconsideration of a decision 
under paragraph (h) of this section as provided in paragraph (i) of this 
section.
    (i) Can a denial of a request for a special permit or a revocation 
of an existing special permit be appealed? Reconsideration of the denial 
of an application for a special permit or a revocation of an existing 
special permit may be sought by petition to the Associate Administrator. 
Petitions for reconsideration must be received by PHMSA within 20 
calendar days of the notice of the grant or denial and must contain a 
brief statement of the issue and an explanation of why the petitioner 
believes that the decision being appealed is not in the public interest. 
The Associate Administrator may grant or deny, in whole or in part, any 
petition for reconsideration without further proceedings. The Associate 
Administrator's decision is the final administrative action.
    (j) Are documents related to an application for a special permit 
available for public inspection? Documents related to an application, 
including the application itself, are available for public inspection on 
regulations.gov or the Docket Operations Facility to the extent such 
documents do not include information exempt from public disclosure under 
5 U.S.C. 552(b). Applicants may request confidential treatment under 
part 7 of this title.

[73 FR 16568, Mar. 28, 2008, as amended at 74 FR 2893, Jan. 16, 2009]



PART 191_TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE; ANNUAL
REPORTS, INCIDENT REPORTS, AND SAFETY-RELATED CONDITION REPORTS--Table

of Contents




Sec.
191.1 Scope.
191.3 Definitions.
191.5 Telephonic notice of certain incidents.
191.7 Addressee for written reports.
191.9 Distribution system: Incident report.
191.11 Distribution system: Annual report.
191.13 Distribution systems reporting transmission pipelines; 
          transmission or gathering systems reporting distribution 
          pipelines.
191.15 Transmission and gathering systems: Incident report.
191.17 Transmission and gathering systems: Annual report.
191.19 Report forms.
191.21 OMB control number assigned to information collection.
191.23 Reporting safety-related conditions.
191.25 Filing safety-related condition reports.
191.27 Filing offshore pipeline condition reports.

    Authority: 49 U.S.C. 5121, 60102, 60103, 60104, 60108, 60117, 60118, 
and 60124; and 49 CFR 1.53.



Sec. 191.1  Scope.

    (a) This part prescribes requirements for the reporting of 
incidents, safety-related conditions, and annual pipeline summary data 
by operators of gas pipeline facilities located in the United States or 
Puerto Rico, including pipelines within the limits of the Outer 
Continental Shelf as that term is defined in the Outer Continental Shelf 
Lands Act (43 U.S.C. 1331).
    (b) This part does not apply to--
    (1) Offshore gathering of gas in State waters upstream from the 
outlet flange of each facility where hydrocarbons are produced or where 
produced hydrocarbons are first separated, dehydrated, or otherwise 
processed, whichever facility is farther downstream;
    (2) Pipelines on the Outer Continental Shelf (OCS) that are 
producer-operated and cross into State waters

[[Page 29]]

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 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 PHMSA regulations governing 
pipeline design, construction, operation, and maintenance under 49 CFR 
190.9.
    (3) Pipelines on the Outer Continental Shelf upstream of the point 
at which operating responsibility transfers from a producing operator to 
a transporting operator; or
    (4) Onshore gathering of gas outside of the following areas:
    (i) An area within the limits of any incorporated or unincorporated 
city, town, or village.
    (ii) Any designated residential or commercial area such as a 
subdivision, business or shopping center, or community development.

[Amdt. 191-5, 49 FR 18960, May 3, 1984, as amended by Amdt. 191-6, 53 FR 
24949, July 1, 1988; Amdt. 191-11, 61 FR 27793, June 3, 1996; Amdt. 191-
12, 62 FR 61695, Nov. 19, 1997; Amdt. 191-15, 68 FR 46111, Aug. 5, 2003; 
70 FR 11139, Mar. 8, 2005]



Sec. 191.3  Definitions.

    As used in this part and the PHMSA Forms referenced in this part--
    Administrator means the Administrator, Pipeline and Hazardous 
Materials Safety Administration or his or her delegate
    Gas means natural gas, flammable gas, or gas which is toxic or 
corrosive;
    Incident means any of the following events:
    (1) An event that involves a release of gas from a pipeline or of 
liquefied natural gas or gas from an LNG facility and
    (i) A death, or personal injury necessitating in-patient 
hospitalization; or
    (ii) Estimated property damage, including cost of gas lost, of the 
operator or others, or both, of $50,000 or more.
    (2) An event that results in an emergency shutdown of an LNG 
facility.
    (3) An event that is significant, in the judgement of the operator, 
even though it did not meet the criteria of paragraphs (1) or (2).
    LNG facility means a liquefied natural gas facility as defined in 
Sec. 193.2007 of part 193 of this chapter;
    Master Meter System means a pipeline system for distributing gas 
within, but not limited to, a definable area, such as a mobile home 
park, housing project, or apartment complex, where the operator 
purchases metered gas from an outside source for resale through a gas 
distribution pipeline system. The gas distribution pipeline system 
supplies the ultimate consumer who either purchases the gas directly 
through a meter or by other means, such as by rents;
    Municipality means a city, county, or any other political 
subdivision of a State;
    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 engages in the transportation of gas;
    Outer Continental Shelf means all submerged lands lying seaward and 
outside the area of lands beneath navigable waters as defined in Section 
2 of the Submerged Lands Act (43 U.S.C. 1301) and of which the subsoil 
and seabed appertain to the United States and are subject to its 
jurisdiction and control.
    Person means any individual, firm, joint venture, partnership, 
corporation, association, State, municipality, cooperative association, 
or joint stock association, and includes any trustee, receiver, 
assignee, or personal representative thereof;
    Pipeline or Pipeline System means all parts of those physical 
facilities through which gas moves in transportation, including, but not 
limited to, pipe, valves, and other appurtenance attached to pipe, 
compressor units, metering stations, regulator stations, delivery 
stations, holders, and fabricated assemblies.
    State includes each of the several States, the District of Columbia, 
and the Commonwealth of Puerto Rico;

[[Page 30]]

    Transportation of gas means the gathering, transmission, or 
distribution of gas by pipeline, or the storage of gas in or affecting 
interstate or foreign commerce.

[35 FR 320, Jan. 8, 1970, as amended by Amdt. 191-5, 49 FR 18960, May 3, 
1984; Amdt. 191-10, 61 FR 18516, Apr. 26, 1996; Amdt. 191-12, 62 FR 
61695, Nov. 19, 1997; 68 FR 11749, Mar. 12, 2003; 70 FR 11139, Mar. 8, 
2005]



Sec. 191.5  Telephonic notice of certain incidents.

    (a) At the earliest practicable moment following discovery, each 
operator shall give notice in accordance with paragraph (b) of this 
section of each incident as defined in Sec. 191.3.
    (b) Each notice required by paragraph (a) of this section shall be 
made by telephone to 800-424-8802 (in Washington, DC, 267-2675) and 
shall include the following information.
    (1) Names of operator and person making report and their telephone 
numbers.
    (2) The location of the incident.
    (3) The time of the incident.
    (4) The number of fatalities and personal injuries, if any.
    (5) All other significant facts that are known by the operator that 
are relevant to the cause of the incident or extent of the damages.

[Amdt. 191-4, 47 FR 32720, July 29, 1982, as amended by Amdt. 191-5, 49 
FR 18960, May 3, 1984; Amdt. 191-8, 54 FR 40878, Oct. 4, 1989]



Sec. 191.7  Addressee for written reports.

    Each written report required by this part must be made to Office of 
Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, 
U.S. Department of Transportation, the Information Resources Manager, 
PHP-10, 1200 New Jersey Avenue, SE., Washington, DC 20590-0001. However, 
incident and annual reports for intrastate pipeline transportation 
subject to the jurisdiction of a State agency pursuant to a 
certification under section 5(a) of the Natural Gas Pipeline Safety Act 
of 1968 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 
for incident reports and not later than March 15 for annual reports to 
the Information Resources Manager. Safety-related condition reports 
required by Sec. 191.23 for intrastate pipeline transportation must be 
submitted concurrently to that State agency, and if that agency acts as 
an agent of the Secretary with respect to interstate transmission 
facilities, safety-related condition reports for these facilities must 
be submitted concurrently to that agency.

[Amdt. 191-6, 53 FR 24949, July 1, 1988, as amended by Amdt. 191-16, 69 
FR 32892, June 14, 2004; 70 FR 11139, Mar. 8, 2005; 73 FR 16570, Mar. 
28, 2008; 74 FR 2894, Jan. 16, 2009]



Sec. 191.9  Distribution system: Incident report.

    (a) Except as provided in paragraph (c) of this section, each 
operator of a distribution pipeline system shall submit Department of 
Transportation Form RSPA F 7100.1 as soon as practicable but not more 
than 30 days after detection of an incident required to be reported 
under Sec. 191.5.
    (b) When additional relevant information is obtained after the 
report is submitted under paragraph (a) of this section, the operator 
shall make supplementary reports as deemed necessary with a clear 
reference by date and subject to the original report.
    (c) The incident report required by this section need not be 
submitted with respect to master meter systems or LNG facilities.

[Amdt. 191-5, 49 FR 18960, May 3, 1984]



Sec. 191.11  Distribution system: Annual report.

    (a) Except as provided in paragraph (b) of this section, each 
operator of a distribution pipeline system shall submit an annual report 
for that system on Department of Transportation Form RSPA F 7100.1-1. 
This report must be submitted each year, not later than March 15, for 
the preceding calendar year.
    (b) The annual report required by this section need not be submitted 
with respect to:
    (1) Petroleum gas systems which serve fewer than 100 customers from 
a single source;
    (2) Master meter systems; or

[[Page 31]]

    (3) LNG facilities.

[Amdt. 191-5, 49 FR 18960, May 3, 1984]



Sec. 191.13  Distribution systems reporting transmission pipelines; 
transmission or gathering systems reporting distribution pipelines.

    Each operator, primarily engaged in gas distribution, who also 
operates gas transmission or gathering pipelines shall submit separate 
reports for these pipelines as required by Sec. Sec. 191.15 and 191.17. 
Each operator, primarily engaged in gas transmission or gathering, who 
also operates gas distribution pipelines shall submit separate reports 
for these pipelines as required by Sec. Sec. 191.9 and 191.11.

[Amdt. 191-5, 49 FR 18961, May 3, 1984]



Sec. 191.15  Transmission and gathering systems: Incident report.

    (a) Except as provided in paragraph (c) of this section, each 
operator of a transmission or a gathering pipeline system shall submit 
Department of Transportation Form RSPA F 7100.2 as soon as practicable 
but not more than 30 days after detection of an incident required to be 
reported under Sec. 191.5.
    (b) Where additional related information is obtained after a report 
is submitted under paragraph (a) of this section, the operator shall 
make a supplemental report as soon as practicable with a clear reference 
by date and subject to the original report.
    (c) The incident report required by paragraph (a) of this section 
need not be submitted with respect to LNG facilities.

[35 FR 320, Jan. 8, 1970, as amended by Amdt. 191-5, 49 FR 18961, May 3, 
1984]



Sec. 191.17  Transmission and gathering systems: Annual report.

    (a) Except as provided in paragraph (b) of this section, each 
operator of a transmission or a gathering pipeline system shall submit 
an annual report for that system on Department of Transportation Form 
RSPA 7100.2-1. This report must be submitted each year, not later than 
March 15, for the preceding calendar year.
    (b) The annual report required by paragraph (a) of this section need 
not be submitted with respect to LNG facilities.

[Amdt. 191-5, 49 FR 18961, May 3, 1984]



Sec. 191.19  Report forms.

    Copies of the prescribed report forms are available without charge 
upon request from the address given in Sec. 191.7. Additional copies in 
this prescribed format may be reproduced and used if in the same size 
and kind of paper. In addition, the information required by these forms 
may be submitted by any other means that is acceptable to the 
Administrator.

[Amdt. 191-10, 61 FR 18516, Apr. 26, 1996]



Sec. 191.21  OMB control number assigned to information collection.

    This section displays the control number assigned by the Office of 
Management and Budget (OMB) to the gas pipeline information collection 
requirements of the Office of Pipeline Safety pursuant to the Paperwork 
Reduction Act of 1980, Public Law 96-511. It is the intent of this 
section to comply with the requirements of section 3507(f) of the 
Paperwork Reduction Act which requires that agencies display a current 
control number assigned by the Director of OMB for each agency 
information collection requirement.

                      OMB Control Number 2137-0522
------------------------------------------------------------------------
    Section of 49 CFR part 191 where
               identified                            Form No.
------------------------------------------------------------------------
191.5..................................  Telephonic.
191.9..................................  RSPA 7100.1
191.11.................................  RSPA 7100.1-1
191.15.................................  RSPA 7100.2
191.17.................................  RSPA 7100.2-1.
------------------------------------------------------------------------


[Amdt. 191-5, 49 FR 18961, May 3, 1984, as amended by Amdt.191-13, 63 FR 
7723, Feb. 17, 1998]



Sec. 191.23  Reporting safety-related conditions.

    (a) Except as provided in paragraph (b) of this section, each 
operator shall report in accordance with Sec. 191.25 the existence of 
any of the following safety-related conditions involving facilities in 
service:
    (1) In the case of a pipeline (other than an LNG facility) that 
operates at a hoop stress of 20 percent or more of its specified minimum 
yield strength,

[[Page 32]]

general corrosion that has reduced the wall thickness to less than that 
required for the maximum allowable operating pressure, and localized 
corrosion pitting to a degree where leakage might result.
    (2) Unintended movement or abnormal loading by environmental causes, 
such as an earthquake, landslide, or flood, that impairs the 
serviceability of a pipeline or the structural integrity or reliability 
of an LNG facility that contains, controls, or processes gas or LNG.
    (3) Any crack or other material defect that impairs the structural 
integrity or reliability of an LNG facility that contains, controls, or 
processes gas or LNG.
    (4) Any material defect or physical damage that impairs the 
serviceability of a pipeline that operates at a hoop stress of 20 
percent or more of its specified minimum yield strength.
    (5) Any malfunction or operating error that causes the pressure of a 
pipeline or LNG facility that contains or processes gas or LNG to rise 
above its maximum allowable operating pressure (or working pressure for 
LNG facilities) plus the build-up allowed for operation of pressure 
limiting or control devices.
    (6) A leak in a pipeline or LNG facility that contains or processes 
gas or LNG that constitutes an emergency.
    (7) Inner tank leakage, ineffective insulation, or frost heave that 
impairs the structural integrity of an LNG storage tank.
    (8) 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 
or an LNG facility that contains or processes gas or LNG.
    (b) A report is not required for any safety-related condition that--
    (1) Exists on a master meter system or a customer-owned service 
line;
    (2) Is an incident or results in an incident before the deadline for 
filing the safety-related condition report;
    (3) Exists on a pipeline (other than an LNG facility) 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
    (4) 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 
conditions under paragraph (a)(1) of this section other than localized 
corrosion pitting on an effectively coated and cathodically protected 
pipeline.

[Amdt. 191-6, 53 FR 24949, July 1, 1988, as amended by Amdt. 191-14, 63 
FR 37501, July 13, 1998]



Sec. 191.25  Filing safety-related condition reports.

    (a) Each report of a safety-related condition under Sec. 191.23(a) 
must be filed (received by the Associate Administrator, OPS) in writing 
within five working days (not including Saturday, Sunday, 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. Reports may be transmitted by facsimile at (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

[[Page 33]]

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.

[Amdt. 191-6, 53 FR 24949, July 1, 1988; 53 FR 29800, Aug. 8, 1988, as 
amended by Amdt. 191-7, 54 FR 32344, Aug. 7, 1989; Amdt. 191-8, 54 FR 
40878, Oct. 4, 1989; Amdt. 191-10, 61 FR 18516, Apr. 26, 1996]



Sec. 191.27  Filing offshore pipeline condition reports.

    (a) Each operator shall, within 60 days after completion of the 
inspection of all its underwater pipelines subject to Sec. 192.612(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 length of pipeline inspected.
    (5) Length and date of installation of each exposed pipeline 
segment, and location, including, if available, the location according 
to the Minerals Management Service or state offshore area and block 
number tract.
    (6) Length and date of installation of each pipeline segment, if 
different from a pipeline segment identified under paragraph (a)(5) of 
this section, that is a hazard to navigation, and the location, 
including, if available, the location according to the Minerals 
Management Service or state offshore area and block number tract.
    (b) The report shall be mailed to the Office of Pipeline Safety, 
Pipeline and Hazardous Materials Safety Administration, Department of 
Transportation, Information Resources Manager, PHP-10, 1200 New Jersey 
Avenue SE., Washington, DC 20590-0001.

[Amdt. 191-9, 56 FR 63770, Dec. 5, 1991, as amended by Amdt. 191-14, 63 
FR 37501, July 13, 1998; 70 FR 11139, Mar. 8, 2005; 73 FR 16570, Mar. 
28, 2008; 74 FR 2894, Jan. 16, 2009]



PART 192_TRANSPORTATION OF NATURAL AND OTHER GAS BY PIPELINE: MINIMUM
FEDERAL SAFETY STANDARDS--Table of Contents




                            Subpart A_General

Sec.
192.1 What is the scope of this part?
192.3 Definitions.
192.5 Class locations.
192.7 What documents are incorporated by reference partly or wholly in 
          this part?
192.8 How are onshore gathering lines and regulated onshore gathering 
          lines determined?
192.9 What requirements apply to gathering lines?
192.10 Outer continental shelf pipelines.
192.11 Petroleum gas systems.
192.13 What general requirements apply to pipelines regulated under this 
          part?
192.14 Conversion to service subject to this part.
192.15 Rules of regulatory construction.
192.16 Customer notification.

                           Subpart B_Materials

192.51 Scope.
192.53 General.
192.55 Steel pipe.
192.57 [Reserved]
192.59 Plastic pipe.
192.61 [Reserved]
192.63 Marking of materials.
192.65 Transportation of pipe.

                          Subpart C_Pipe Design

192.101 Scope.
192.103 General.
192.105 Design formula for steel pipe.
192.107 Yield strength (S) for steel pipe.
192.109 Nominal wall thickness (t) for steel pipe.
192.111 Design factor (F) for steel pipe.
192.112 Additional design requirements for steel pipe using alternative 
          maximum allowable operating pressure.
192.113 Longitudinal joint factor (E) for steel pipe.
192.115 Temperature derating factor (T) for steel pipe.
192.117 [Reserved]
192.119 [Reserved]
192.121 Design of plastic pipe.
192.123 Design limitations for plastic pipe.
192.125 Design of copper pipe.

                 Subpart D_Design of Pipeline Components

192.141 Scope.
192.143 General requirements.
192.144 Qualifying metallic components.
192.145 Valves.

[[Page 34]]

192.147 Flanges and flange accessories.
192.149 Standard fittings.
192.150 Passage of internal inspection devices.
192.151 Tapping.
192.153 Components fabricated by welding.
192.155 Welded branch connections.
192.157 Extruded outlets.
192.159 Flexibility.
192.161 Supports and anchors.
192.163 Compressor stations: Design and construction.
192.165 Compressor stations: Liquid removal.
192.167 Compressor stations: Emergency shutdown.
192.169 Compressor stations: Pressure limiting devices.
192.171 Compressor stations: Additional safety equipment.
192.173 Compressor stations: Ventilation.
192.175 Pipe-type and bottle-type holders.
192.177 Additional provisions for bottle-type holders.
192.179 Transmission line valves.
192.181 Distribution line valves.
192.183 Vaults: Structural design requirements.
192.185 Vaults: Accessibility.
192.187 Vaults: Sealing, venting, and ventilation.
192.189 Vaults: Drainage and waterproofing.
192.191 Design pressure of plastic fittings.
192.193 Valve installation in plastic pipe.
192.195 Protection against accidental overpressuring.
192.197 Control of the pressure of gas delivered from high-pressure 
          distribution systems.
192.199 Requirements for design of pressure relief and limiting devices.
192.201 Required capacity of pressure relieving and limiting stations.
192.203 Instrument, control, and sampling pipe and components.

                 Subpart E_Welding of Steel in Pipelines

192.221 Scope.
192.225 Welding procedures.
192.227 Qualification of welders.
192.229 Limitations on welders.
192.231 Protection from weather.
192.233 Miter joints.
192.235 Preparation for welding.
192.241 Inspection and test of welds.
192.243 Nondestructive testing.
192.245 Repair or removal of defects.

          Subpart F_Joining of Materials Other Than by Welding

192.271 Scope.
192.273 General.
192.275 Cast iron pipe.
192.277 Ductile iron pipe.
192.279 Copper pipe.
192.281 Plastic pipe.
192.283 Plastic pipe: Qualifying joining procedures.
192.285 Plastic pipe: Qualifying persons to make joints.
192.287 Plastic pipe: Inspection of joints.

 Subpart G_General Construction Requirements for Transmission Lines and 
                                  Mains

192.301 Scope.
192.303 Compliance with specifications or standards.
192.305 Inspection: General.
192.307 Inspection of materials.
192.309 Repair of steel pipe.
192.311 Repair of plastic pipe.
192.313 Bends and elbows.
192.315 Wrinkle bends in steel pipe.
192.317 Protection from hazards.
192.319 Installation of pipe in a ditch.
192.321 Installation of plastic pipe.
192.323 Casing.
192.325 Underground clearance.
192.327 Cover.
192.328 Additional construction requirements for steel pipe using 
          alternative maximum allowable operating pressure.

    Subpart H_Customer Meters, Service Regulators, and Service Lines

192.351 Scope.
192.353 Customer meters and regulators: Location.
192.355 Customer meters and regulators: Protection from damage.
192.357 Customer meters and regulators: Installation.
192.359 Customer meter installations: Operating pressure.
192.361 Service lines: Installation.
192.363 Service lines: Valve requirements.
192.365 Service lines: Location of valves.
192.367 Service lines: General requirements for connections to main 
          piping.
192.369 Service lines: Connections to cast iron or ductile iron mains.
192.371 Service lines: Steel.
192.373 Service lines: Cast iron and ductile iron.
192.375 Service lines: Plastic.
192.377 Service lines: Copper.
192.379 New service lines not in use.
192.381 Service lines: Excess flow valve performance standards.
192.383 Excess flow valve customer notification.

              Subpart I_Requirements for Corrosion Control

192.451 Scope.
192.452 How does this subpart apply to converted pipelines and regulated 
          onshore gathering lines?
192.453 General.

[[Page 35]]

192.455 External corrosion control: Buried or submerged pipelines 
          installed after July 31, 1971.
192.457 External corrosion control: Buried or submerged pipelines 
          installed before August 1, 1971.
192.459 External corrosion control: Examination of buried pipeline when 
          exposed.
192.461 External corrosion control: Protective coating.
192.463 External corrosion control: Cathodic protection.
192.465 External corrosion control: Monitoring.
192.467 External corrosion control: Electrical isolation.
192.469 External corrosion control: Test stations.
192.471 External corrosion control: Test leads.
192.473 External corrosion control: Interference currents.
192.475 Internal corrosion control: General.
192.476 Internal corrosion control: Design and construction of 
          transmission line.
192.477 Internal corrosion control: Monitoring.
192.479 Atmospheric corrosion control: General.
192.481 Atmospheric corrosion control: Monitoring.
192.483 Remedial measures: General.
192.485 Remedial measures: Transmission lines.
192.487 Remedial measures: Distribution lines other than cast iron or 
          ductile iron lines.
192.489 Remedial measures: Cast iron and ductile iron pipelines.
192.490 Direct assessment.
192.491 Corrosion control records.

                       Subpart J_Test Requirements

192.501 Scope.
192.503 General requirements.
192.505 Strength test requirements for steel pipeline to operate at a 
          hoop stress of 30 percent or more of SMYS.
192.507 Test requirements for pipelines to operate at a hoop stress less 
          than 30 percent of SMYS and at or above 100 p.s.i. (689 kPa) 
          gage.
192.509 Test requirements for pipelines to operate below 100 p.s.i. (689 
          kPa) gage.
192.511 Test requirements for service lines.
192.513 Test requirements for plastic pipelines.
192.515 Environmental protection and safety requirements.
192.517 Records.

                           Subpart K_Uprating

192.551 Scope.
192.553 General requirements.
192.555 Uprating to a pressure that will produce a hoop stress of 30 
          percent or more of SMYS in steel pipelines.
192.557 Uprating: Steel pipelines to a pressure that will produce a hoop 
          stress less than 30 percent of SMYS; plastic, cast iron, and 
          ductile iron pipelines.

                          Subpart L_Operations

192.601 Scope.
192.603 General provisions.
192.605 Procedural manual for operations, maintenance, and emergencies.
192.607 [Reserved]
192.609 Change in class location: Required study.
192.611 Change in class location: Confirmation or revision of maximum 
          allowable operating pressure.
192.612 Underwater inspection and reburial of pipelines in the Gulf of 
          Mexico and its inlets.
192.613 Continuing surveillance.
192.614 Damage prevention program.
192.615 Emergency plans.
192.616 Public awareness.
192.617 Investigation of failures.
192.619 What is the maximum allowable operating pressure for steel or 
          plastic pipelines?
192.620 Alternative maximum allowable operating pressure for certain 
          steel pipelines.
192.621 Maximum allowable operating pressure: High-pressure distribution 
          systems.
192.623 Maximum and minimum allowable operating pressure; Low-pressure 
          distribution systems.
192.625 Odorization of gas.
192.627 Tapping pipelines under pressure.
192.629 Purging of pipelines.

                          Subpart M_Maintenance

192.701 Scope.
192.703 General.
192.705 Transmission lines: Patrolling.
192.706 Transmission lines: Leakage surveys.
192.707 Line markers for mains and transmission lines.
192.709 Transmission lines: Record keeping.
192.711 Transmission lines: General requirements for repair procedures.
192.713 Transmission lines: Permanent field repair of imperfections and 
          damages.
192.715 Transmission lines: Permanent field repair of welds.
192.717 Transmission lines: Permanent field repair of leaks.
192.719 Transmission lines: Testing of repairs.
192.721 Distribution systems: Patrolling.
192.723 Distribution systems: Leakage surveys.
192.725 Test requirements for reinstating service lines.

[[Page 36]]

192.727 Abandonment or deactivation of facilities.
192.731 Compressor stations: Inspection and testing of relief devices.
192.735 Compressor stations: Storage of combustible materials.
192.736 Compressor stations: Gas detection.
192.739 Pressure limiting and regulating stations: Inspection and 
          testing.
192.741 Pressure limiting and regulating stations: Telemetering or 
          recording gauges.
192.743 Pressure limiting and regulating stations: Capacity of relief 
          devices.
192.745 Valve maintenance: Transmission lines.
192.747 Valve maintenance: Distribution systems.
192.749 Vault maintenance.
192.751 Prevention of accidental ignition.
192.753 Caulked bell and spigot joints.
192.755 Protecting cast-iron pipelines.

              Subpart N_Qualification of Pipeline Personnel

192.801 Scope.
192.803 Definitions.
192.805 Qualification Program.
192.807 Recordkeeping.
192.809 General.

        Subpart O_Gas Transmission Pipeline Integrity Management

192.901 What do the regulations in this subpart cover?
192.903 What definitions apply to this subpart?
192.905 How does an operator identify a high consequence area?
192.907 What must an operator do to implement this subpart?
192.909 How can an operator change its integrity management program?
192.911 What are the elements of an integrity management program?
192.913 When may an operator deviate its program from certain 
          requirements of this subpart?
192.915 What knowledge and training must personnel have to carry out an 
          integrity management program?
192.917 How does an operator identify potential threats to pipeline 
          integrity and use the threat identification in its integrity 
          program?
192.919 What must be in the baseline assessment plan?
192.921 How is the baseline assessment to be conducted?
192.923 How is direct assessment used and for what threats?
192.925 What are the requirements for using External Corrosion Direct 
          Assessment (ECDA)?
192.927 What are the requirements for using Internal Corrosion Direct 
          Assessment (ICDA)?
192.929 What are the requirements for using Direct Assessment for Stress 
          Corrosion Cracking (SCCDA)?
192.931 How may Confirmatory Direct Assessment (CDA) be used?
192.933 What actions must be taken to address integrity issues?
192.935 What additional preventive and mitigative measures must an 
          operator take?
192.937 What is a continual process of evaluation and assessment to 
          maintain a pipeline's integrity?
192.939 What are the required reassessment intervals?
192.941 What is a low stress reassessment?
192.943 When can an operator deviate from these reassessment intervals?
192.945 What methods must an operator use to measure program 
          effectiveness?
192.947 What records must an operator keep?
192.949 How does an operator notify PHMSA?
192.951 Where does an operator file a report?

Appendix A to Part 192 [Reserved]
Appendix B to Part 192--Qualification of Pipe
Appendix C to Part 192--Qualification of Welders for Low Stress Level 
          Pipe
Appendix D to Part 192--Criteria for Cathodic Protection and 
          Determination of Measurements
Appendix E to Part 192--Guidance on Determining High Consequence Areas 
          and on Carrying out Requirements in the Integrity Management 
          Rule

    Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60109, 60110, 60113, 
and 60118; and 49 CFR 1.53.

    Source: 35 FR 13257, Aug. 19, 1970, unless otherwise noted.

    Editorial Note: Nomenclature changes to part 192 appear at 71 FR 
33406, June 9, 2006.



                            Subpart A_General



Sec. 192.1  What is the scope of this part?

    (a) This part prescribes minimum safety requirements for pipeline 
facilities and the transportation of gas, including pipeline facilities 
and the transportation of gas within the limits of the outer continental 
shelf as that term is defined in the Outer Continental Shelf Lands Act 
(43 U.S.C. 1331).
    (b) This part does not apply to--
    (1) Offshore gathering of gas in State waters upstream from the 
outlet flange of each facility where hydrocarbons are

[[Page 37]]

produced or where produced hydrocarbons are first separated, dehydrated, 
or otherwise processed, whichever facility is farther downstream;
    (2) 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 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 PHMSA 
regulations governing pipeline design, construction, operation, and 
maintenance under 49 CFR 190.9;
    (3) Pipelines on the Outer Continental Shelf upstream of the point 
at which operating responsibility transfers from a producing operator to 
a transporting operator;
    (4) Onshore gathering of gas--
    (i) Through a pipeline that operates at less than 0 psig (0 kPa);
    (ii) Through a pipeline that is not a regulated onshore gathering 
line (as determined in Sec. 192.8); and
    (iii) Within inlets of the Gulf of Mexico, except for the 
requirements in Sec. 192.612; or
    (5) Any pipeline system that transports only petroleum gas or 
petroleum gas/air mixtures to--
    (i) Fewer than 10 customers, if no portion of the system is located 
in a public place; or
    (ii) A single customer, if the system is located entirely on the 
customer's premises (no matter if a portion of the system is located in 
a public place).

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34605, 
Aug. 16, 1976; Amdt. 192-67, 56 FR 63771, Dec. 5, 1991; Amdt. 192-78, 61 
FR 28782, June 6, 1996; Amdt. 192-81, 62 FR 61695, Nov. 19, 1997; Amdt. 
192-92, 68 FR 46112, Aug. 5, 2003; 70 FR 11139, Mar. 8, 2005; Amdt. 192-
102, 71 FR 13301, Mar. 15, 2006; Amdt. 192-103, 72 FR 4656, Feb. 1, 
2007]



Sec. 192.3  Definitions.

    As used in this part:
    Abandoned means permanently removed from service.
    Administrator means the Administrator, Pipeline and Hazardous 
Materials Safety Administration or his or her delegate.
    Customer meter means the meter that measures the transfer of gas 
from an operator to a consumer.
    Distribution line means a pipeline other than a gathering or 
transmission line.
    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.
    Gas means natural gas, flammable gas, or gas which is toxic or 
corrosive.
    Gathering line means a pipeline that transports gas from a current 
production facility to a transmission line or main.
    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.
    Hazard to navigation means, for the purposes of this part, a 
pipeline where the top of the pipe is less than 12 inches (305 
millimeters) below the underwater natural bottom (as determined by 
recognized and generally accepted practices) in waters less than 15 feet 
(4.6 meters) deep, as measured from the mean low water.
    High-pressure distribution system means a distribution system in 
which the gas pressure in the main is higher than the pressure provided 
to the customer.
    Line section means a continuous run of transmission line between 
adjacent compressor stations, between a compressor station and storage 
facilities, between a compressor station and a block valve, or between 
adjacent block valves.
    Listed specification means a specification listed in section I of 
appendix B of this part.
    Low-pressure distribution system means a distribution system in 
which the gas

[[Page 38]]

pressure in the main is substantially the same as the pressure provided 
to the customer.
    Main means a distribution line that serves as a common source of 
supply for more than one service line.
    Maximum actual operating pressure means the maximum pressure that 
occurs during normal operations over a period of 1 year.
    Maximum allowable operating pressure (MAOP) means the maximum 
pressure at which a pipeline or segment of a pipeline may be operated 
under this part.
    Municipality means a city, county, or any other political 
subdivision of a State.
    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 engages in the transportation of gas.
    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 including any trustee, receiver, 
assignee, or personal representative thereof.
    Petroleum gas means propane, propylene, butane, (normal butane or 
isobutanes), and butylene (including isomers), or mixtures composed 
predominantly of these gases, having a vapor pressure not exceeding 208 
psi (1434 kPa) gage at 100 [deg]F (38 [deg]C).
    Pipe means any pipe or tubing used in the transportation of gas, 
including pipe-type holders.
    Pipeline means all parts of those physical facilities through which 
gas moves in transportation, including pipe, valves, and other 
appurtenance attached to pipe, compressor units, metering stations, 
regulator stations, delivery stations, holders, and fabricated 
assemblies.
    Pipeline facility means new and existing pipelines, rights-of-way, 
and any equipment, facility, or building used in the transportation of 
gas or in the treatment of gas during the course of transportation.
    Service line means a distribution line that transports gas from a 
common source of supply to an individual customer, to two adjacent or 
adjoining residential or small commercial customers, or to multiple 
residential or small commercial customers served through a meter header 
or manifold. A service line ends at the outlet of the customer meter or 
at the connection to a customer's piping, whichever is further 
downstream, or at the connection to customer piping if there is no 
meter.
    Service regulator means the device on a service line that controls 
the pressure of gas delivered from a higher pressure to the pressure 
provided to the customer. A service regulator may serve one customer or 
multiple customers through a meter header or manifold.
    SMYS means specified minimum yield strength is:
    (1) For steel pipe manufactured in accordance with a listed 
specification, the yield strength specified as a minimum in that 
specification; or
    (2) For steel pipe manufactured in accordance with an unknown or 
unlisted specification, the yield strength determined in accordance with 
Sec. 192.107(b).
    State means each of the several States, the District of Columbia, 
and the Commonwealth of Puerto Rico.
    Transmission line means a pipeline, other than a gathering line, 
that: (1) Transports gas from a gathering line or storage facility to a 
distribution center, storage facility, or large volume customer that is 
not down-stream from a distribution center; (2) operates at a hoop 
stress of 20 percent or more of SMYS; or (3) transports gas within a 
storage field.
    Note: A large volume customer may receive similar volumes of gas as 
a distribution center, and includes factories, power plants, and 
institutional users of gas.
    Transportation of gas means the gathering, transmission, or 
distribution of gas by pipeline or the storage of gas, in

[[Page 39]]

or affecting interstate or foreign commerce.

[Amdt. 192-13, 38 FR 9084, Apr. 10, 1973, as amended by Amdt. 192-27, 41 
FR 34605, Aug. 16, 1976; Amdt. 192-58, 53 FR 1635, Jan. 21, 1988; Amdt. 
192-67, 56 FR 63771, Dec. 5, 1991; Amdt. 192-72, 59 FR 17281, Apr. 12, 
1994; Amdt. 192-78, 61 FR 28783, June 6, 1996; Amdt. 192-81, 62 FR 
61695, Nov. 19, 1997; Amdt. 192-85, 63 FR 37501, July 13, 1998; Amdt. 
192-89, 65 FR 54443, Sept. 8, 2000; 68 FR 11749, Mar. 12, 2003; Amdt. 
192-93, 68 FR 53900, Sept. 15, 2003; Amdt. 192-98, 69 FR 48406, Aug. 10, 
2004; Amdt. 192-94, 69 FR 54592, Sept. 9, 2004; 70 FR 3148, Jan. 21, 
2005; 70 FR 11139, Mar. 8, 2005]



Sec. 192.5  Class locations.

    (a) This section classifies pipeline locations for purposes of this 
part. The following criteria apply to classifications under this 
section.
    (1) A ``class location unit'' is an onshore area that extends 220 
yards (200 meters) on either side of the centerline of any continuous 1- 
mile (1.6 kilometers) length of pipeline.
    (2) Each separate dwelling unit in a multiple dwelling unit building 
is counted as a separate building intended for human occupancy.
    (b) Except as provided in paragraph (c) of this section, pipeline 
locations are classified as follows:
    (1) A Class 1 location is:
    (i) An offshore area; or
    (ii) Any class location unit that has 10 or fewer buildings intended 
for human occupancy.
    (2) A Class 2 location is any class location unit that has more than 
10 but fewer than 46 buildings intended for human occupancy.
    (3) A Class 3 location is:
    (i) Any class location unit that has 46 or more buildings intended 
for human occupancy; or
    (ii) An area where the pipeline lies within 100 yards (91 meters) of 
either a building or a small, well-defined outside area (such as a 
playground, recreation area, outdoor theater, or other place of public 
assembly) that is occupied by 20 or more persons on at least 5 days a 
week for 10 weeks in any 12-month period. (The days and weeks need not 
be consecutive.)
    (4) A Class 4 location is any class location unit where buildings 
with four or more stories above ground are prevalent.
    (c) The length of Class locations 2, 3, and 4 may be adjusted as 
follows:
    (1) A Class 4 location ends 220 yards (200 meters) from the nearest 
building with four or more stories above ground.
    (2) When a cluster of buildings intended for human occupancy 
requires a Class 2 or 3 location, the class location ends 220 yards (200 
meters) from the nearest building in the cluster.

[Amdt. 192-78, 61 FR 28783, June 6, 1996; 61 FR 35139, July 5, 1996, as 
amended by Amdt. 192-85, 63 FR 37502, July 13, 1998]



Sec. 192.7  What documents are incorporated by reference partly or 
wholly in this part?

    (a) Any documents or portions thereof incorporated by reference in 
this part are included in this part as though set out in full. When only 
a portion of a document is referenced, the remainder is not incorporated 
in this part.
    (b) All incorporated materials are available for inspection in the 
Office of Pipeline Safety, Pipeline and Hazardous Materials Safety 
Administration, 1200 New Jersey Avenue, SE., Washington, DC, 20590-0001, 
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, the incorporated materials are available from the respective 
organizations listed in paragraph (c) (1) of this section.
    (c) The full titles of documents incorporated by reference, in whole 
or in part, are provided herein. The numbers in parentheses indicate 
applicable editions. For each incorporated document, citations of all 
affected sections are provided. Earlier editions of currently listed 
documents or editions of documents listed in previous editions of 49 CFR 
part 192 may be used for materials and components designed, 
manufactured, or installed in accordance with these earlier documents at 
the time they were listed. The user must refer to the appropriate 
previous edition of

[[Page 40]]

49 CFR part 192 for a listing of the earlier listed editions or 
documents.
    (1) Incorporated by reference (IBR).


List of Organizations and Addresses:

    A. Pipeline Research Council International, Inc. (PRCI), c/o 
Technical Toolboxes, 3801 Kirby Drive, Suite 520, Houston, TX 77098.
    B. American Petroleum Institute (API), 1220 L Street, NW., 
Washington, DC 20005.
    C. American Society for Testing and Materials (ASTM), 100 Barr 
Harbor Drive, West Conshohocken, PA 19428.
    D. ASME International (ASME), Three Park Avenue, New York, NY 10016-
5990.
    E. Manufacturers Standardization Society of the Valve and Fittings 
Industry, Inc. (MSS), 127 Park Street, NE., Vienna, VA 22180.
    F. National Fire Protection Association (NFPA), 1 Batterymarch Park, 
P.O. Box 9101, Quincy, MA 02269-9101.
    G. Plastics Pipe Institute, Inc. (PPI), 1825 Connecticut Avenue, 
NW., Suite 680, Washington, DC 20009.
    H. NACE International (NACE), 1440 South Creek Drive, Houston, TX 
77084.
    I. Gas Technology Institute (GTI), 1700 South Mount Prospect Road, 
Des Plaines, IL 60018.
    (2) Documents incorporated by reference.

------------------------------------------------------------------------
    Source and name of referenced material          49 CFR reference
------------------------------------------------------------------------
A. Pipeline Research Council International
 (PRCI):
  (1) AGA Pipeline Research Committee,         Sec. Sec.  192.933(a);
   Project PR-3-805, ``A Modified Criterion     192.485(c).
   for Evaluating the Remaining Strength of
   Corroded Pipe,'' (December 22, 1989). The
   RSTRENG program may be used for
   calculating remaining strength.
B. American Petroleum Institute (API):
    (1) ANSI/API Specification 5L/ISO 3183     Sec. Sec.  192.55(e);
     ``Specification for Line Pipe'' (43rd      192.112; 192.113; Item I
     edition and errata, 2004, and 44th         of Appendix B.
     edition, 2007).
    (2) API Recommended Practice 5L1           Sec.  192.65(a).
     ``Recommended Practice for Railroad
     Transportation of Line Pipe,'' (6th
     edition, 2002).
    (3) API Specification 6D ``Pipeline        Sec.  192.145(a).
     Valves,'' (22nd edition, January 2002).
    (4) API Recommended Practice 80,           Sec.  192.8(a);
     ``Guidelines for the Definition of         192.8(a)(1);
     Onshore Gas Gathering Lines,'' (1st        192.8(a)(2);
     edition, April 2000).                      192.8(a)(3);
                                                192.8(a)(4).
    (5) API 1104 ``Welding of Pipelines and    Sec. Sec.  192.227(a);
     Related Facilities'' (19th edition 1999,   192.229(c)(1);
     including errata October 31, 2001; and     192.241(c); Item II, and
     20th edition 2007, including errata        Appendix B.
     2008).
    (6) API Recommended Practice 1162          Sec. Sec.  192.616(a);
     ``Public Awareness Programs for Pipeline   192.616(b); 192.616(c).
     Operators,'' (1st edition, December
     2003).
C. American Society for Testing and Materials
 (ASTM):
  (1) ASTM A53/A53M-04a (2004) ``Standard      Sec. Sec.  192.113;
   Specification for Pipe, Steel, Black and     Item I, Appendix B.
   Hot-Dipped, Zinc-Coated, Welded and
   Seamless.''.
  (2) ASTM A106/A106M-04b (2004) ``Standard    Sec. Sec.  192.113;
   Specification for Seamless Carbon Steel      Item I, Appendix B.
   Pipe for High-Temperature Service.''.
  (3) ASTM A333/A333M-05 (2005) ``Standard     Sec. Sec.  192.113;
   Specification for Seamless and Welded        Item I, Appendix B.
   Steel Pipe for Low-Temperature Service.''.
  (4) ASTM A372/A372M-03 (2003) ``Standard     Sec.  192.177(b)(1).
   Specification for Carbon and Alloy Steel
   Forgings for Thin-Walled Pressure
   Vessels.''.
  (5) ASTM A381-96 (Reapproved 2001)           Sec. Sec.  192.113;
   ``Standard Specification for Metal-Arc       Item I, Appendix B.
   Welded Steel Pipe for Use With High-
   Pressure Transmission Systems.''.
(6) ASTM Designation: A 578/A578M-96 (Re-      Sec. Sec.
 approved 2001) ``Standard Specification for    192.112(c)(2)(iii).
 Straight-Beam Ultrasonic Examination of
 Plain and Clad Steel Plates for Special
 Applications''.
  (7) ASTM A671-04 (2004) ``Standard           Sec. Sec.  192.113;
   Specification for Electric-Fusion-Welded     Item I, Appendix B.
   Steel Pipe for Atmospheric and Lower
   Temperatures.''.
  (8) ASTM A672-96 (Reapproved 2001)           Sec. Sec.  192.113;
   ``Standard Specification for Electric-       Item I, Appendix B.
   Fusion-Welded Steel Pipe for High-Pressure
   Service at Moderate Temperatures.''.
  (9) ASTM A691-98 (Reapproved 2002)           Sec. Sec.  192.113;
   ``Standard Specification for Carbon and      Item I, Appendix B.
   Alloy Steel Pipe, Electric-Fusion-Welded
   for High-Pressure Service at High
   Temperatures.''.
  (10) ASTM D638-03 ``Standard Test Method     Sec. Sec.
   for Tensile Properties of Plastics.''.       192.283(a)(3);
                                                192.283(b)(1).
  (11) ASTM D2513-87 ``Standard Specification  Sec.  192.63(a)(1).
   for Thermoplastic Gas Pressure Pipe,
   Tubing, and Fittings.''.
  (12) ASTM D2513-99 ``Standard Specification  Sec. Sec.  192.191(b);
   for Thermoplastic Gas Pressure Pipe,         192.281(b)(2);
   Tubing, and Fittings.''.                     192.283(a)(1)(i); Item
                                                1, Appendix B.
  (13) ASTM D2517-00 ``Standard Specification  Sec. Sec.  192.191(a);
   for Reinforced Epoxy Resin Gas Pressure      192.281(d)(1);
   Pipe and Fittings.''.                        192.283(a)(1)(ii); Item
                                                I, Appendix B.
  (14) ASTM F1055-1998 ``Standard              Sec.
   Specification for Electrofusion Type         192.283(a)(1)(iii).
   Polyethylene Fittings for Outside Diameter
   Controller Polyethylene Pipe and Tubing.''.

[[Page 41]]

 
D. ASME International (ASME):
  (1) ASME B16.1-1998 ``Cast Iron Pipe         Sec.  192.147(c).
   Flanges and Flanged Fittings.''.
  (2) ASME B16.5-2003 (October 2004) ``Pipe    Sec. Sec.  192.147(a);
   Flanges and Flanged Fittings.''.             192.279.
  (3) ASME B31G-1991 (Reaffirmed; 2004)        Sec. Sec.  192.485(c);
   ``Manual for Determining the Remaining       192.933(a).
   Strength of Corroded Pipelines.''.
  (4) ASME B31.8-2003 (February 2004) ``Gas    Sec.  192.619(a)(1)(i).
   Transmission and Distribution Piping
   Systems.''.
  (5) ASME B31.8S-2004 ``Supplement to B31.8   Sec. Sec.  192.903(c);
   on Managing System Integrity of Gas          192.907(b); 192.911,
   Pipelines.''.                                Introductory text;
                                                192.911(i); 192.911(k);
                                                192.911(l); 192.911(m);
                                                192.913(a) Introductory
                                                text; 192.913(b)(1);
                                                192.917(a) Introductory
                                                text; 192.917(b);
                                                192.917(c);
                                                192.917(e)(1);
                                                192.917(e)(4);
                                                192.921(a)(1);
                                                192.923(b)(2);
                                                192.923(b)(3);
                                                192.925(b) Introductory
                                                text; 102.925(b)(1);
                                                192.925(b)(2);
                                                192.925(b)(3);
                                                192.925(b)(4);
                                                192.927(b);
                                                192.927(c)(1)(i);
                                                192.929(b)(1);
                                                192.929(b)(2);
                                                192.933(a);
                                                192.933(d)(1);
                                                192.933(d)(1)(i);
                                                192.935(a);
                                                192.935(b)(1)(iv);
                                                192.937(c)(1);
                                                192.939(a)(1)(i);
                                                192.939(a)(1)(ii);
                                                192.939(a)(3);
                                                192.945(a).
  (6) ASME Boiler and Pressure Vessel Code,    Sec.  192.153(a).
   Section I, ``Rules for Construction of
   Power Boilers,'' (2004 edition, including
   addenda through July 1, 2005).
  (7) ASME Boiler and Pressure Vessel Code,    Sec. Sec.  192.153(a);
   Section VIII, Division 1, ``Rules for        192.153(b); 192.153(d);
   Construction of Pressure Vessels,'' (2004    192.165(b)(3).
   edition, including addenda through July 1,
   2005).
  (8) ASME Boiler and Pressure Vessel Code,    Sec. Sec.  192.153(b);
   Section VIII, Division 2, ``Rules for        192.165(b)(3).
   Construction of Pressure Vessels--
   Alternative Rules,'' (2004 edition,
   including addenda through July 1, 2005).
  (9) ASME Boiler and Pressure Vessel Code,    Sec. Sec.  192.227(a);
   Section IX, ``Welding and Brazing            Item II, Appendix B.
   Qualifications,'' (2004 edition, including
   addenda through July 1, 2005).
E. Manufacturers Standardization Society of
 the Valve and Fittings Industry, Inc. (MSS):
  (1) MSS SP-44-1996 (Reaffirmed; 2001)        Sec.  192.147(a).
   ``Steel Pipe Line Flanges.''.
  (2) [Reserved].............................  .........................
F. National Fire Protection Association
 (NFPA):
  (1) NFPA 30 (2003) ``Flammable and           Sec.  192.735(b).
   Combustible Liquids Code.''.
  (2) NFPA 58 (2004) ``Liquefied Petroleum     Sec.  192.11(a);
   Gas Code (LP-Gas Code).''.                   192.11(b); 192.11(c).
  (3) NFPA 59 (2004) ``Utility LP-Gas Plant    Sec. Sec.  192.11(a);
   Code.''.                                     192.11(b); 192.11(c).
  (4) NFPA 70 (2005) ``National Electrical     Sec. Sec.  192.163(e);
   Code.''.                                     192.189(c).
G. Plastics Pipe Institute, Inc. (PPI):
  (1) PPI TR-3/2004 (2004) ``Policies and      Sec.  192.121.
   Procedures for Developing Hydrostatic
   Design Basis (HDB), Pressure Design Basis
   (PDB), Strength Design Basis (SDB), and
   Minimum Required Strength (MRS) Ratings
   for Thermoplastic Piping Materials or
   Pipe.''.
H. NACE International (NACE):
  (1) NACE Standard RP0502-2002 ``Pipeline     Sec. Sec.
   External Corrosion Direct Assessment         192.923(b)(1);
   Methodology.''.                              192.925(b) Introductory
                                                text; 192.925(b)(1);
                                                192.925(b)(1)(ii);
                                                192.925(b)(2)
                                                Introductory text;
                                                192.925(b)(3)
                                                Introductory text;
                                                192.925(b)(3)(ii);
                                                192.925(b)(iv);
                                                192.925(b)(4)
                                                Introductory text;
                                                192.925(b)(4)(ii);
                                                192.931(d);
                                                192.935(b)(1)(iv);
                                                192.939(a)(2).
I. Gas Technology Institute (GTI):
  (1) GRI 02/0057 (2002) ``Internal Corrosion  Sec.  192.927(c)(2).
   Direct Assessment of Gas Transmission
   Pipelines Methodology.''.
------------------------------------------------------------------------


[[Page 42]]


[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-37, 46 FR 10159, 
Feb. 2, 1981; Amdt 192-51, 51 FR 15334, Apr. 23, 1986; 58 FR 14521, Mar. 
18, 1993; Amdt. 192-78, 61 FR 28783, June 6, 1996; 69 FR 18803, Apr. 9, 
2004; Amdt. 192-94, 69 FR 32892, June 14, 2004; Amdt. 192-94, 69 FR 
54592, Sept. 9, 2004; 70 FR 11139, Mar. 8, 2005; Amdt. 192-100, 70 FR 
28842, May 19, 2005; Amdt. 192-102, 71 FR 13301, Mar. 15, 2006; Amdt. 
192-103, 71 FR 33406, June 9, 2006; Amdt. 192-103, 72 FR 4656, Feb. 1, 
2007; 73 FR 16570, Mar. 28, 2008; 73 FR 62174, Oct. 17, 2008; 74 FR 
2894, Jan. 16, 2009; 74 FR 17101, Apr. 14, 2009]



Sec. 192.8  How are onshore gathering lines and regulated onshore
gathering lines determined?

    (a) An operator must use API RP 80 (incorporated by reference, see 
Sec. 192.7), to determine if an onshore pipeline (or part of a 
connected series of pipelines) is an onshore gathering line. The 
determination is subject to the limitations listed below. After making 
this determination, an operator must determine if the onshore gathering 
line is a regulated onshore gathering line under paragraph (b) of this 
section.
    (1) The beginning of gathering, under section 2.2(a)(1) of API RP 
80, may not extend beyond the furthermost downstream point in a 
production operation as defined in section 2.3 of API RP 80. This 
furthermost downstream point does not include equipment that can be used 
in either production or transportation, such as separators or 
dehydrators, unless that equipment is involved in the processes of 
``production and preparation for transportation or delivery of 
hydrocarbon gas'' within the meaning of ``production operation.''
    (2) The endpoint of gathering, under section 2.2(a)(1)(A) of API RP 
80, may not extend beyond the first downstream natural gas processing 
plant, unless the operator can demonstrate, using sound engineering 
principles, that gathering extends to a further downstream plant.
    (3) If the endpoint of gathering, under section 2.2(a)(1)(C) of API 
RP 80, is determined by the commingling of gas from separate production 
fields, the fields may not be more than 50 miles from each other, unless 
the Administrator finds a longer separation distance is justified in a 
particular case (see 49 CFR Sec. 190.9).
    (4) The endpoint of gathering, under section 2.2(a)(1)(D) of API RP 
80, may not extend beyond the furthermost downstream compressor used to 
increase gathering line pressure for delivery to another pipeline.
    (b) For purposes of Sec. 192.9, ``regulated onshore gathering 
line'' means:
    (1) Each onshore gathering line (or segment of onshore gathering 
line) with a feature described in the second column that lies in an area 
described in the third column; and
    (2) As applicable, additional lengths of line described in the 
fourth column to provide a safety buffer:

----------------------------------------------------------------------------------------------------------------
                 Type                          Feature                    Area                Safety buffer
----------------------------------------------------------------------------------------------------------------
A....................................  --Metallic and the MAOP  Class 2, 3, or 4         None.
                                        produces a hoop stress   location (see Sec.
                                        of 20 percent or more    192.5).
                                        of SMYS. If the stress
                                        level is unknown, an
                                        operator must
                                        determine the stress
                                        level according to the
                                        applicable provisions
                                        in subpart C of this
                                        part.
                                       --Non-metallic and the
                                        MAOP is more than 125
                                        psig (862 kPa).

[[Page 43]]

 
B....................................  --Metallic and the MAOP  Area 1. Class 3 or 4     If the gathering line
                                        produces a hoop stress   location.                is in Area 2(b) or
                                        of less than 20         Area 2. An area within    2(c), the additional
                                        percent of SMYS. If      a Class 2 location the   lengths of line extend
                                        the stress level is      operator determines by   upstream and
                                        unknown, an operator     using any of the         downstream from the
                                        must determine the       following three          area to a point where
                                        stress level according   methods:.                the line is at least
                                        to the applicable       (a) A Class 2 location.   150 feet (45.7 m) from
                                        provisions in subpart   (b) An area extending     the nearest dwelling
                                        C of this part.          150 feet (45.7 m) on     in the area. However,
                                       --Non-metallic and the    each side of the         if a cluster of
                                        MAOP is 125 psig (862    centerline of any        dwellings in Area 2
                                        kPa) or less.            continuous 1 mile (1.6   (b) or 2(c) qualifies
                                                                 km) of pipeline and      a line as Type B, the
                                                                 including more than 10   Type B classification
                                                                 but fewer than 46        ends 150 feet (45.7 m)
                                                                 dwellings.               from the nearest
                                                                (c) An area extending     dwelling in the
                                                                 150 feet (45.7 m) on     cluster.
                                                                 each side of the
                                                                 centerline of any
                                                                 continous 1000 feet
                                                                 (305 m) of pipeline
                                                                 and including 5 or
                                                                 more dwellings.
----------------------------------------------------------------------------------------------------------------


[Amdt. 192-102, 71 FR 13302, Mar. 15, 2006]



Sec. 192.9  What requirements apply to gathering lines?

    (a) Requirements. An operator of a gathering line must follow the 
safety requirements of this part as prescribed by this section.
    (b) Offshore lines. An operator of an offshore gathering line must 
comply with requirements of this part applicable to transmission lines, 
except the requirements in Sec. 192.150 and in subpart O of this part.
    (c) Type A lines. An operator of a Type A regulated onshore 
gathering line must comply with the requirements of this part applicable 
to transmission lines, except the requirements in Sec. 192.150 and in 
subpart O of this part. However, an operator of a Type A regulated 
onshore gathering line in a Class 2 location may demonstrate compliance 
with subpart N by describing the processes it uses to determine the 
qualification of persons performing operations and maintenance tasks.
    (d) Type B lines. An operator of a Type B regulated onshore 
gathering line must comply with the following requirements:
    (1) If a line is new, replaced, relocated, or otherwise changed, the 
design, installation, construction, initial inspection, and initial 
testing must be in accordance with requirements of this part applicable 
to transmission lines;
    (2) If the pipeline is metallic, control corrosion according to 
requirements of subpart I of this part applicable to transmission lines;
    (3) Carry out a damage prevention program under Sec. 192.614;
    (4) Establish a public education program under Sec. 192.616;
    (5) Establish the MAOP of the line under Sec. 192.619; and
    (6) Install and maintain line markers according to the requirements 
for transmission lines in Sec. 192.707.
    (e) Compliance deadlines. An operator of a regulated onshore 
gathering line must comply with the following deadlines, as applicable.
    (1) An operator of a new, replaced, relocated, or otherwise changed 
line must be in compliance with the applicable requirements of this 
section by the date the line goes into service, unless an exception in 
Sec. 192.13 applies.
    (2) If a regulated onshore gathering line existing on April 14, 2006 
was not previously subject to this part, an operator has until the date 
stated in the second column to comply with the applicable requirement 
for the line listed in the first column, unless the Administrator finds 
a later deadline is justified in a particular case:

------------------------------------------------------------------------
                Requirement                      Compliance deadline
------------------------------------------------------------------------
Control corrosion according to Subpart I    April 15, 2009.
 requirements for transmission lines.
Carry out a damage prevention program       October 15, 2007.
 under Sec.  192.614.
Establish MAOP under Sec.  192.619.......  October 15, 2007.
Install and maintain line markers under     April 15, 2008.
 Sec.  192.707.
Establish a public education program under  April 15, 2008.
 Sec.  192.616.

[[Page 44]]

 
Other provisions of this part as required   April 15, 2009.
 by paragraph (c) of this section for Type
 A lines.
------------------------------------------------------------------------

    (3) If, after April 14, 2006, a change in class location or increase 
in dwelling density causes an onshore gathering line to be a regulated 
onshore gathering line, the operator has 1 year for Type B lines and 2 
years for Type A lines after the line becomes a regulated onshore 
gathering line to comply with this section.

[Amdt. 192-102, 71 FR 13301, Mar. 15, 2006]



Sec. 192.10  Outer continental shelf pipelines.

    Operators of transportation pipelines on the Outer Continental Shelf 
(as defined in the Outer Continental Shelf Lands Act; 43 U.S.C. 1331) 
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 located near the 
transfer point. If a transfer point is located subsea, then the operator 
must identify the transfer point on a schematic which must be maintained 
at the nearest upstream facility and provided to PHMSA upon request. For 
those cases in which adjoining operators have not agreed on a transfer 
point by September 15, 1998 the Regional Director and the MMS Regional 
Supervisor will make a joint determination of the transfer point.

[Amdt. 192-81, 62 FR 61695, Nov. 19, 1997, as amended at 70 FR 11139, 
Mar. 8, 2005]



Sec. 192.11  Petroleum gas systems.

    (a) Each plant that supplies petroleum gas by pipeline to a natural 
gas distribution system must meet the requirements of this part and 
ANSI/NFPA 58 and 59.
    (b) Each pipeline system subject to this part that transports only 
petroleum gas or petroleum gas/air mixtures must meet the requirements 
of this part and of ANSI/NFPA 58 and 59.
    (c) In the event of a conflict between this part and ANSI/NFPA 58 
and 59, ANSI/NFPA 58 and 59 prevail.

[Amdt. 192-78, 61 FR 28783, June 6, 1996]



Sec. 192.13  What general requirements apply to pipelines regulated 
under this part?

    (a) No person may operate a segment of pipeline listed in the first 
column that is readied for service after the date in the second column, 
unless:
    (1) The pipeline has been designed, installed, constructed, 
initially inspected, and initially tested in accordance with this part; 
or
    (2) The pipeline qualifies for use under this part according to the 
requirements in Sec. 192.14.

------------------------------------------------------------------------
                 Pipeline                               Date
------------------------------------------------------------------------
Offshore gathering line...................  July 31, 1977.
Regulated onshore gathering line to which   March 15 2007.
 this part did not apply until April 14,
 2006.
All other pipelines.......................  March 12, 1971.
------------------------------------------------------------------------

    (b) No person may operate a segment of pipeline listed in the first 
column that is replaced, relocated, or otherwise changed after the date 
in the second column, unless the replacement, relocation or change has 
been made according to the requirements in this part.

------------------------------------------------------------------------
                 Pipeline                               Date
------------------------------------------------------------------------
Offshore gathering line...................  July 31, 1977.
Regulated onshore gathering line to which   March 15, 2007.
 this part did not apply until April 14,
 2006.
All other pipelines.......................  November 12, 1970.
------------------------------------------------------------------------

    (c) Each operator shall maintain, modify as appropriate, and follow 
the plans, procedures, and programs that it is required to establish 
under this part.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34605, 
Aug. 16, 1976; Amdt. 192-30, 42 FR 60148, Nov. 25, 1977; Amdt. 192-102, 
71 FR 13303, Mar. 15, 2006]

[[Page 45]]



Sec. 192.14  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 carry out the following requirements:
    (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 a satisfactory condition for safe operation.
    (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 J of this 
part to substantiate the maximum allowable operating pressure permitted 
by subpart L of this part.
    (b) 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. 192-30, 42 FR 60148, Nov. 25, 1977]



Sec. 192.15  Rules of regulatory construction.

    (a) As used in this part:
    Includes means including but not limited to.
    May means ``is permitted to'' or ``is authorized to''.
    May not means ``is not permitted to'' or ``is not authorized to''.
    Shall is used in the mandatory and imperative sense.
    (b) In this part:
    (1) Words importing the singular include the plural;
    (2) Words importing the plural include the singular; and
    (3) Words importing the masculine gender include the feminine.



Sec. 192.16  Customer notification.

    (a) This section applies to each operator of a service line who does 
not maintain the customer's buried piping up to entry of the first 
building downstream, or, if the customer's buried piping does not enter 
a building, up to the principal gas utilization equipment or the first 
fence (or wall) that surrounds that equipment. For the purpose of this 
section, ``customer's buried piping'' does not include branch lines that 
serve yard lanterns, pool heaters, or other types of secondary 
equipment. Also, ``maintain'' means monitor for corrosion according to 
Sec. 192.465 if the customer's buried piping is metallic, survey for 
leaks according to Sec. 192.723, and if an unsafe condition is found, 
shut off the flow of gas, advise the customer of the need to repair the 
unsafe condition, or repair the unsafe condition.
    (b) Each operator shall notify each customer once in writing of the 
following information:
    (1) The operator does not maintain the customer's buried piping.
    (2) If the customer's buried piping is not maintained, it may be 
subject to the potential hazards of corrosion and leakage.
    (3) Buried gas piping should be--
    (i) Periodically inspected for leaks;
    (ii) Periodically inspected for corrosion if the piping is metallic; 
and
    (iii) Repaired if any unsafe condition is discovered.
    (4) When excavating near buried gas piping, the piping should be 
located in advance, and the excavation done by hand.
    (5) The operator (if applicable), plumbing contractors, and heating 
contractors can assist in locating, inspecting, and repairing the 
customer's buried piping.
    (c) Each operator shall notify each customer not later than August 
14, 1996, or 90 days after the customer first receives gas at a 
particular location, whichever is later. However, operators of master 
meter systems may continuously post a general notice in a prominent 
location frequented by customers.
    (d) Each operator must make the following records available for 
inspection by the Administrator or a State agency

[[Page 46]]

participating under 49 U.S.C. 60105 or 60106:
    (1) A copy of the notice currently in use; and
    (2) Evidence that notices have been sent to customers within the 
previous 3 years.

[Amdt. 192-74, 60 FR 41828, Aug. 14, 1995, as amended by Amdt. 192-74A, 
60 FR 63451, Dec. 11, 1995; Amdt. 192-83, 63 FR 7723, Feb. 17, 1998]



                           Subpart B_Materials



Sec. 192.51  Scope.

    This subpart prescribes minimum requirements for the selection and 
qualification of pipe and components for use in pipelines.



Sec. 192.53  General.

    Materials for pipe and components must be:
    (a) Able to maintain the structural integrity of the pipeline under 
temperature and other environmental conditions that may be anticipated;
    (b) Chemically compatible with any gas that they transport and with 
any other material in the pipeline with which they are in contact; and
    (c) Qualified in accordance with the applicable requirements of this 
subpart.



Sec. 192.55  Steel pipe.

    (a) New steel pipe is qualified for use under this part if:
    (1) It was manufactured in accordance with a listed specification;
    (2) It meets the requirements of--
    (i) Section II of appendix B to this part; or
    (ii) If it was manufactured before November 12, 1970, either section 
II or III of appendix B to this part; or
    (3) It is used in accordance with paragraph (c) or (d) of this 
section.
    (b) Used steel pipe is qualified for use under this part if:
    (1) It was manufactured in accordance with a listed specification 
and it meets the requirements of paragraph II-C of appendix B to this 
part;
    (2) It meets the requirements of:
    (i) Section II of appendix B to this part; or
    (ii) If it was manufactured before November 12, 1970, either section 
II or III of appendix B to this part;
    (3) It has been used in an existing line of the same or higher 
pressure and meets the requirements of paragraph II-C of appendix B to 
this part; or
    (4) It is used in accordance with paragraph (c) of this section.
    (c) New or used steel pipe may be used at a pressure resulting in a 
hoop stress of less than 6,000 p.s.i. (41 MPa) where no close coiling or 
close bending is to be done, if visual examination indicates that the 
pipe is in good condition and that it is free of split seams and other 
defects that would cause leakage. If it is to be welded, steel pipe that 
has not been manufactured to a listed specification must also pass the 
weldability tests prescribed in paragraph II-B of appendix B to this 
part.
    (d) Steel pipe that has not been previously used may be used as 
replacement pipe in a segment of pipeline if it has been manufactured 
prior to November 12, 1970, in accordance with the same specification as 
the pipe used in constructing that segment of pipeline.
    (e) New steel pipe that has been cold expanded must comply with the 
mandatory provisions of API Specification 5L.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 191-1, 35 FR 17660, 
Nov. 17, 1970; Amdt. 192-12, 38 FR 4761, Feb. 22, 1973; Amdt. 192-51, 51 
FR 15335, Apr. 23, 1986; 58 FR 14521, Mar. 18, 1993; Amdt. 192-85, 63 FR 
37502, July 13, 1998]



Sec. 192.57  [Reserved]



Sec. 192.59  Plastic pipe.

    (a) New plastic pipe is qualified for use under this part if:
    (1) It is manufactured in accordance with a listed specification; 
and
    (2) It is resistant to chemicals with which contact may be 
anticipated.
    (b) Used plastic pipe is qualified for use under this part if:
    (1) It was manufactured in accordance with a listed specification;
    (2) It is resistant to chemicals with which contact may be 
anticipated;
    (3) It has been used only in natural gas service;
    (4) Its dimensions are still within the tolerances of the 
specification to which it was manufactured; and

[[Page 47]]

    (5) It is free of visible defects.
    (c) For the purpose of paragraphs (a)(1) and (b)(1) of this section, 
where pipe of a diameter included in a listed specification is 
impractical to use, pipe of a diameter between the sizes included in a 
listed specification may be used if it:
    (1) Meets the strength and design criteria required of pipe included 
in that listed specification; and
    (2) Is manufactured from plastic compounds which meet the criteria 
for material required of pipe included in that listed specification.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-19, 40 FR 10472, 
Mar. 6, 1975; Amdt. 192-58, 53 FR 1635, Jan. 21, 1988]



Sec. 192.61  [Reserved]



Sec. 192.63  Marking of materials.

    (a) Except as provided in paragraph (d) of this section, each valve, 
fitting, length of pipe, and other component must be marked--
    (1) As prescribed in the specification or standard to which it was 
manufactured, except that thermoplastic fittings must be marked in 
accordance with ASTM D 2513; or
    (2) To indicate size, material, manufacturer, pressure rating, and 
temperature rating, and as appropriate, type, grade, and model.
    (b) Surfaces of pipe and components that are subject to stress from 
internal pressure may not be field die stamped.
    (c) If any item is marked by die stamping, the die must have blunt 
or rounded edges that will minimize stress concentrations.
    (d) Paragraph (a) of this section does not apply to items 
manufactured before November 12, 1970, that meet all of the following:
    (1) The item is identifiable as to type, manufacturer, and model.
    (2) Specifications or standards giving pressure, temperature, and 
other appropriate criteria for the use of items are readily available.

[Amdt. 192-1, 35 FR 17660, Nov. 17, 1970, as amended by Amdt. 192-31, 43 
FR 883, Apr. 3, 1978; Amdt. 192-61, 53 FR 36793, Sept. 22, 1988; Amdt. 
192-62, 54 FR 5627, Feb. 6, 1989; Amdt. 192-61A, 54 FR 32642, Aug. 9, 
1989; 58 FR 14521, Mar. 18, 1993; Amdt. 192-76, 61 FR 26122, May 24, 
1996; 61 FR 36826, July 15, 1996]



Sec. 192.65  Transportation of pipe.

    In a pipeline to be operated at a hoop stress of 20 percent or more 
of SMYS, an operator may not use pipe having an outer diameter to wall 
thickness ratio of 70 to 1, or more, that is transported by railroad 
unless:
    (a) The transportation is performed in accordance with API RP 5L1.
    (b) In the case of pipe transported before November 12, 1970, the 
pipe is tested in accordance with subpart J of this part to at least 
1.25 times the maximum allowable operating pressure if it is to be 
installed in a class 1 location and to at least 1.5 times the maximum 
allowable operating pressure if it is to be installed in a class 2, 3, 
or 4 location. Notwithstanding any shorter time period permitted under 
subpart J of this part, the test pressure must be maintained for at 
least 8 hours.

[Amdt. 192-12, 38 FR 4761, Feb. 22, 1973, as amended by Amdt. 192-17, 40 
FR 6346, Feb. 11, 1975; 58 FR 14521, Mar. 18, 1993]



                          Subpart C_Pipe Design



Sec. 192.101  Scope.

    This subpart prescribes the minimum requirements for the design of 
pipe.



Sec. 192.103  General.

    Pipe must be designed with sufficient wall thickness, or must be 
installed with adequate protection, to withstand anticipated external 
pressures and loads that will be imposed on the pipe after installation.



Sec. 192.105  Design formula for steel pipe.

    (a) The design pressure for steel pipe is determined in accordance 
with the following formula:

P=(2 St/D)xFxExT

P=Design pressure in pounds per square inch (kPa) gauge.
S=Yield strength in pounds per square inch (kPa) determined in 
accordance with Sec. 192.107.
D=Nominal outside diameter of the pipe in inches (millimeters).
t=Nominal wall thickness of the pipe in inches (millimeters). If this is 
unknown, it is determined in accordance with Sec. 192.109. Additional 
wall thickness required for concurrent external loads in accordance with 
Sec. 192.103 may not be included in computing design pressure.

[[Page 48]]

F=Design factor determined in accordance with Sec. 192.111.
E=Longitudinal joint factor determined in accordance with Sec. 192.113.
T=Temperature derating factor determined in accordance with Sec. 
192.115.

    (b) If steel pipe that has been subjected to cold expansion to meet 
the SMYS is subsequently heated, other than by welding or stress 
relieving as a part of welding, the design pressure is limited to 75 
percent of the pressure determined under paragraph (a) of this section 
if the temperature of the pipe exceeds 900 [deg]F (482 [deg]C) at any 
time or is held above 600 [deg]F (316 [deg]C) for more than 1 hour.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-47, 49 FR 7569, 
Mar. 1, 1984; Amdt. 192-85, 63 FR 37502, July 13, 1998]



Sec. 192.107  Yield strength (S) for steel pipe.

    (a) For pipe that is manufactured in accordance with a specification 
listed in section I of appendix B of this part, the yield strength to be 
used in the design formula in Sec. 192.105 is the SMYS stated in the 
listed specification, if that value is known.
    (b) For pipe that is manufactured in accordance with a specification 
not listed in section I of appendix B to this part or whose 
specification or tensile properties are unknown, the yield strength to 
be used in the design formula in Sec. 192.105 is one of the following:
    (1) If the pipe is tensile tested in accordance with section II-D of 
appendix B to this part, the lower of the following:
    (i) 80 percent of the average yield strength determined by the 
tensile tests.
    (ii) The lowest yield strength determined by the tensile tests.
    (2) If the pipe is not tensile tested as provided in paragraph 
(b)(1) of this section, 24,000 p.s.i. (165 MPa).

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-78, 61 FR 28783, 
June 6, 1996; Amdt. 192-83, 63 FR 7723, Feb. 17, 1998; Amdt. 192-85, 63 
FR 37502, July 13, 1998]



Sec. 192.109  Nominal wall thickness (t) for steel pipe.

    (a) If the nominal wall thickness for steel pipe is not known, it is 
determined by measuring the thickness of each piece of pipe at quarter 
points on one end.
    (b) However, if the pipe is of uniform grade, size, and thickness 
and there are more than 10 lengths, only 10 percent of the individual 
lengths, but not less than 10 lengths, need be measured. The thickness 
of the lengths that are not measured must be verified by applying a 
gauge set to the minimum thickness found by the measurement. The nominal 
wall thickness to be used in the design formula in Sec. 192.105 is the 
next wall thickness found in commercial specifications that is below the 
average of all the measurements taken. However, the nominal wall 
thickness used may not be more than 1.14 times the smallest measurement 
taken on pipe less than 20 inches (508 millimeters) in outside diameter, 
nor more than 1.11 times the smallest measurement taken on pipe 20 
inches (508 millimeters) or more in outside diameter.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37502, 
July 13, 1998]



Sec. 192.111  Design factor (F) for steel pipe.

    (a) Except as otherwise provided in paragraphs (b), (c), and (d) of 
this section, the design factor to be used in the design formula in 
Sec. 192.105 is determined in accordance with the following table:

------------------------------------------------------------------------
                                                                Design
                       Class location                         factor (F)
------------------------------------------------------------------------
1...........................................................        0.72
2...........................................................        0.60
3...........................................................        0.50
4...........................................................        0.40
------------------------------------------------------------------------

    (b) A design factor of 0.60 or less must be used in the design 
formula in Sec. 192.105 for steel pipe in Class 1 locations that:
    (1) Crosses the right-of-way of an unimproved public road, without a 
casing;
    (2) Crosses without a casing, or makes a parallel encroachment on, 
the right-of-way of either a hard surfaced road, a highway, a public 
street, or a railroad;
    (3) Is supported by a vehicular, pedestrian, railroad, or pipeline 
bridge; or
    (4) Is used in a fabricated assembly, (including separators, 
mainline valve assemblies, cross-connections, and

[[Page 49]]

river crossing headers) or is used within five pipe diameters in any 
direction from the last fitting of a fabricated assembly, other than a 
transition piece or an elbow used in place of a pipe bend which is not 
associated with a fabricated assembly.
    (c) For Class 2 locations, a design factor of 0.50, or less, must be 
used in the design formula in Sec. 192.105 for uncased steel pipe that 
crosses the right-of-way of a hard surfaced road, a highway, a public 
street, or a railroad.
    (d) For Class 1 and Class 2 locations, a design factor of 0.50, or 
less, must be used in the design formula in Sec. 192.105 for--
    (1) Steel pipe in a compressor station, regulating station, or 
measuring station; and
    (2) Steel pipe, including a pipe riser, on a platform located 
offshore or in inland navigable waters.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34605, 
Aug. 16, 1976]



Sec. 192.112  Additional design requirements for steel pipe using 
alternative maximum allowable operating pressure.

    For a new or existing pipeline segment to be eligible for operation 
at the alternative maximum allowable operating pressure (MAOP) 
calculated under Sec. 192.620, a segment must meet the following 
additional design requirements. Records for alternative MAOP must be 
maintained, for the useful life of the pipeline, demonstrating 
compliance with these requirements:

------------------------------------------------------------------------
                                    The pipeline segment must meet these
   To address this design issue:          additional requirements:
------------------------------------------------------------------------
(a) General standards for the       (1) The plate, skelp, or coil used
 steel pipe.                         for the pipe must be micro-alloyed,
                                     fine grain, fully killed,
                                     continuously cast steel with
                                     calcium treatment.
                                    (2) The carbon equivalents of the
                                     steel used for pipe must not exceed
                                     0.25 percent by weight, as
                                     calculated by the Ito-Bessyo
                                     formula (Pcm formula) or 0.43
                                     percent by weight, as calculated by
                                     the International Institute of
                                     Welding (IIW) formula.
                                    (3) The ratio of the specified
                                     outside diameter of the pipe to the
                                     specified wall thickness must be
                                     less than 100. The wall thickness
                                     or other mitigative measures must
                                     prevent denting and ovality
                                     anomalies during construction,
                                     strength testing and anticipated
                                     operational stresses.
                                    (4) The pipe must be manufactured
                                     using API Specification 5L, product
                                     specification level 2 (incorporated
                                     by reference, see Sec.  192.7) for
                                     maximum operating pressures and
                                     minimum and maximum operating
                                     temperatures and other requirements
                                     under this section.
(b) Fracture control..............  (1) The toughness properties for
                                     pipe must address the potential for
                                     initiation, propagation and arrest
                                     of fractures in accordance with:
                                    (i) API Specification 5L
                                     (incorporated by reference, see
                                     Sec.  192.7); or
                                    (ii) American Society of Mechanical
                                     Engineers (ASME) B31.8
                                     (incorporated by reference, see
                                     Sec.  192.7); and
                                    (iii) Any correction factors needed
                                     to address pipe grades, pressures,
                                     temperatures, or gas compositions
                                     not expressly addressed in API
                                     Specification 5L, product
                                     specification level 2 or ASME B31.8
                                     (incorporated by reference, see
                                     Sec.  192.7).
                                    (2) Fracture control must:
                                    (i) Ensure resistance to fracture
                                     initiation while addressing the
                                     full range of operating
                                     temperatures, pressures, gas
                                     compositions, pipe grade and
                                     operating stress levels, including
                                     maximum pressures and minimum
                                     temperatures for shut-in
                                     conditions, that the pipeline is
                                     expected to experience. If these
                                     parameters change during operation
                                     of the pipeline such that they are
                                     outside the bounds of what was
                                     considered in the design
                                     evaluation, the evaluation must be
                                     reviewed and updated to assure
                                     continued resistance to fracture
                                     initiation over the operating life
                                     of the pipeline;
                                    (ii) Address adjustments to
                                     toughness of pipe for each grade
                                     used and the decompression behavior
                                     of the gas at operating parameters;
                                    (iii) Ensure at least 99 percent
                                     probability of fracture arrest
                                     within eight pipe lengths with a
                                     probability of not less than 90
                                     percent within five pipe lengths;
                                     and
                                    (iv) Include fracture toughness
                                     testing that is equivalent to that
                                     described in supplementary
                                     requirements SR5A, SR5B, and SR6 of
                                     API Specification 5L (incorporated
                                     by reference, see Sec.  192.7) and
                                     ensures ductile fracture and arrest
                                     with the following exceptions:
                                    (A) The results of the Charpy impact
                                     test prescribed in SR5A must
                                     indicate at least 80 percent
                                     minimum shear area for any single
                                     test on each heat of steel; and
                                    (B) The results of the drop weight
                                     test prescribed in SR6 must
                                     indicate 80 percent average shear
                                     area with a minimum single test
                                     result of 60 percent shear area for
                                     any steel test samples. The test
                                     results must ensure a ductile
                                     fracture and arrest.
                                    (3) If it is not physically possible
                                     to achieve the pipeline toughness
                                     properties of paragraphs (b)(1) and
                                     (2) of this section, additional
                                     design features, such as mechanical
                                     or composite crack arrestors and/or
                                     heavier walled pipe of proper
                                     design and spacing, must be used to
                                     ensure fracture arrest as described
                                     in paragraph (b)(2)(iii) of this
                                     section.
(c) Plate/coil quality control....  (1) There must be an internal
                                     quality management program at all
                                     mills involved in producing steel,
                                     plate, coil, skelp, and/or rolling
                                     pipe to be operated at alternative
                                     MAOP. These programs must be
                                     structured to eliminate or detect
                                     defects and inclusions affecting
                                     pipe quality.

[[Page 50]]

 
                                    (2) A mill inspection program or
                                     internal quality management program
                                     must include (i) and either (ii) or
                                     (iii):
                                    (i) An ultrasonic test of the ends
                                     and at least 35 percent of the
                                     surface of the plate/coil or pipe
                                     to identify imperfections that
                                     impair serviceability such as
                                     laminations, cracks, and
                                     inclusions. At least 95 percent of
                                     the lengths of pipe manufactured
                                     must be tested. For all pipelines
                                     designed after [the effective date
                                     of the final rule], the test must
                                     be done in accordance with ASTM
                                     A578/A578M Level B, or API 5L
                                     Paragraph 7.8.10 (incorporated by
                                     reference, see Sec.  192.7) or
                                     equivalent method, and either
                                    (ii) A macro etch test or other
                                     equivalent method to identify
                                     inclusions that may form centerline
                                     segregation during the continuous
                                     casting process. Use of sulfur
                                     prints is not an equivalent method.
                                     The test must be carried out on the
                                     first or second slab of each
                                     sequence graded with an acceptance
                                     criteria of one or two on the
                                     Mannesmann scale or equivalent; or
                                    (iii) A quality assurance monitoring
                                     program implemented by the operator
                                     that includes audits of: (a) all
                                     steelmaking and casting facilities,
                                     (b) quality control plans and
                                     manufacturing procedure
                                     specifications, (c) equipment
                                     maintenance and records of
                                     conformance, (d) applicable casting
                                     superheat and speeds, and (e)
                                     centerline segregation monitoring
                                     records to ensure mitigation of
                                     centerline segregation during the
                                     continuous casting process.
(d) Seam quality control..........  (1) There must be a quality
                                     assurance program for pipe seam
                                     welds to assure tensile strength
                                     provided in API Specification 5L
                                     (incorporated by reference, see
                                     Sec.  192.7) for appropriate
                                     grades.
                                    (2) There must be a hardness test,
                                     using Vickers (Hv10) hardness test
                                     method or equivalent test method,
                                     to assure a maximum hardness of 280
                                     Vickers of the following:
                                    (i) A cross section of the weld seam
                                     of one pipe from each heat plus one
                                     pipe from each welding line per
                                     day; and
                                    (ii) For each sample cross section,
                                     a minimum of 13 readings (three for
                                     each heat affected zone, three in
                                     the weld metal, and two in each
                                     section of pipe base metal).
                                    (3) All of the seams must be
                                     ultrasonically tested after cold
                                     expansion and mill hydrostatic
                                     testing.
(e) Mill hydrostatic test.........  (1) All pipe to be used in a new
                                     pipeline segment must be
                                     hydrostatically tested at the mill
                                     at a test pressure corresponding to
                                     a hoop stress of 95 percent SMYS
                                     for 10 seconds. The test pressure
                                     may include a combination of
                                     internal test pressure and the
                                     allowance for end loading stresses
                                     imposed by the pipe mill
                                     hydrostatic testing equipment as
                                     allowed by API Specification 5L,
                                     Appendix K (incorporated by
                                     reference, see Sec.  192.7).
                                    (2) Pipe in operation prior to
                                     November 17, 2008, must have been
                                     hydrostatically tested at the mill
                                     at a test pressure corresponding to
                                     a hoop stress of 90 percent SMYS
                                     for 10 seconds.
(f) Coating.......................  (1) The pipe must be protected
                                     against external corrosion by a non-
                                     shielding coating.
                                    (2) Coating on pipe used for
                                     trenchless installation must be non-
                                     shielding and resist abrasions and
                                     other damage possible during
                                     installation.
                                    (3) A quality assurance inspection
                                     and testing program for the coating
                                     must cover the surface quality of
                                     the bare pipe, surface cleanliness
                                     and chlorides, blast cleaning,
                                     application temperature control,
                                     adhesion, cathodic disbondment,
                                     moisture permeation, bending,
                                     coating thickness, holiday
                                     detection, and repair.
(g) Fittings and flanges..........  (1) There must be certification
                                     records of flanges, factory
                                     induction bends and factory weld
                                     ells. Certification must address
                                     material properties such as
                                     chemistry, minimum yield strength
                                     and minimum wall thickness to meet
                                     design conditions.
                                    (2) If the carbon equivalents of
                                     flanges, bends and ells are greater
                                     than 0.42 percent by weight, the
                                     qualified welding procedures must
                                     include a pre-heat procedure.
                                    (3) Valves, flanges and fittings
                                     must be rated based upon the
                                     required specification rating class
                                     for the alternative MAOP.
(h) Compressor stations...........  (1) A compressor station must be
                                     designed to limit the temperature
                                     of the nearest downstream segment
                                     operating at alternative MAOP to a
                                     maximum of 120 degrees Fahrenheit
                                     (49 degrees Celsius) or the higher
                                     temperature allowed in paragraph
                                     (h)(2) of this section unless a
                                     long-term coating integrity
                                     monitoring program is implemented
                                     in accordance with paragraph (h)(3)
                                     of this section.
                                    (2) If research, testing and field
                                     monitoring tests demonstrate that
                                     the coating type being used will
                                     withstand a higher temperature in
                                     long-term operations, the
                                     compressor station may be designed
                                     to limit downstream piping to that
                                     higher temperature. Test results
                                     and acceptance criteria addressing
                                     coating adhesion, cathodic
                                     disbondment, and coating condition
                                     must be provided to each PHMSA
                                     pipeline safety regional office
                                     where the pipeline is in service at
                                     least 60 days prior to operating
                                     above 120 degrees Fahrenheit (49
                                     degrees Celsius). An operator must
                                     also notify a State pipeline safety
                                     authority when the pipeline is
                                     located in a State where PHMSA has
                                     an interstate agent agreement, or
                                     an intrastate pipeline is regulated
                                     by that State.

[[Page 51]]

 
                                    (3) Pipeline segments operating at
                                     alternative MAOP may operate at
                                     temperatures above 120 degrees
                                     Fahrenheit (49 degrees Celsius) if
                                     the operator implements a long-term
                                     coating integrity monitoring
                                     program. The monitoring program
                                     must include examinations using
                                     direct current voltage gradient
                                     (DCVG), alternating current voltage
                                     gradient (ACVG), or an equivalent
                                     method of monitoring coating
                                     integrity. An operator must specify
                                     the periodicity at which these
                                     examinations occur and criteria for
                                     repairing identified indications.
                                     An operator must submit its long-
                                     term coating integrity monitoring
                                     program to each PHMSA pipeline
                                     safety regional office in which the
                                     pipeline is located for review
                                     before the pipeline segments may be
                                     operated at temperatures in excess
                                     of 120 degrees Fahrenheit (49
                                     degrees Celsius). An operator must
                                     also notify a State pipeline safety
                                     authority when the pipeline is
                                     located in a State where PHMSA has
                                     an interstate agent agreement, or
                                     an intrastate pipeline is regulated
                                     by that State.
------------------------------------------------------------------------


[73 FR 62175, Oct. 17, 2008]



Sec. 192.113  Longitudinal joint factor (E) for steel pipe.

    The longitudinal joint factor to be used in the design formula in 
Sec. 192.105 is determined in accordance with the following table:

------------------------------------------------------------------------
                                                          Longitudinal
         Specification                Pipe class        joint factor (E)
------------------------------------------------------------------------
ASTM A 53/A53M.................  Seamless............               1.00
                                 Electric resistance                1.00
                                  welded.
                                 Furnace butt welded.                .60
ASTM A 106.....................  Seamless............               1.00
ASTM A 333/A 333M..............  Seamless............               1.00
                                 Electric resistance                1.00
                                  welded.
ASTM A 381.....................  Double submerged arc               1.00
                                  welded.
ASTM A 671.....................  Electric-fusion-                   1.00
                                  welded.
ASTM A 672.....................  Electric-fusion-                   1.00
                                  welded.
ASTM A 691.....................  Electric-fusion-                   1.00
                                  welded.
API 5 L........................  Seamless............               1.00
                                 Electric resistance                1.00
                                  welded.
                                 Electric flash                     1.00
                                  welded.
                                 Submerged arc welded               1.00
                                 Furnace butt welded.                .60
Other..........................  Pipe over 4 inches                  .80
                                  (102 millimeters).
Other..........................  Pipe 4 inches (102                  .60
                                  millimeters) or
                                  less.
------------------------------------------------------------------------


If the type of longitudinal joint cannot be determined, the joint factor 
to be used must not exceed that designated for ``Other.''

[Amdt. 192-37, 46 FR 10159, Feb. 2, 1981, as amended by Amdt. 192-51, 51 
FR 15335, Apr. 23, 1986; Amdt. 192-62, 54 FR 5627, Feb. 6, 1989; 58 FR 
14521, Mar. 18, 1993; Amdt. 192-85, 63 FR 37502, July 13, 1998; Amdt. 
192-94, 69 FR 32894, June 14, 2004]



Sec. 192.115  Temperature derating factor (T) for steel pipe.

    The temperature derating factor to be used in the design formula in 
Sec. 192.105 is determined as follows:

------------------------------------------------------------------------
                                                             Temperature
      Gas temperature in degrees Fahrenheit (Celsius)          derating
                                                              factor (T)
------------------------------------------------------------------------
250 [deg]F (121 [deg]C) or less............................        1.000
300 [deg]F (149 [deg]C)....................................        0.967
350 [deg]F (177 [deg]C)....................................        0.933
400 [deg]F (204 [deg]C)....................................        0.900
450 [deg]F (232 [deg]C)....................................        0.867
------------------------------------------------------------------------


For intermediate gas temperatures, the derating factor is determined by 
interpolation.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37502, 
July 13, 1998]



Sec. 192.117  [Reserved]



Sec. 192.119  [Reserved]



Sec. 192.121  Design of plastic pipe.

    Subject to the limitations of Sec. 192.123, the design pressure for 
plastic pipe is

[[Page 52]]

determined by either of the following formulas:
[GRAPHIC] [TIFF OMITTED] TR24DE08.014

Where:

P = Design pressure, gauge, psig (kPa).
S = For thermoplastic pipe, the HDB is determined in accordance with the 
listed specification at a temperature equal to 73F[deg] (23C[deg]), 100 
[deg]F (38 [deg]C), 120 [deg]F (49 [deg]C), or 140 [deg]F (60 [deg]C). 
In the absence of an HDB established at the specified temperature, the 
HDB of a higher temperature may be used in determining a design pressure 
rating at the specified temperature by arithmetic interpolation using 
the procedure in Part D.2 of PPI TR-3/2004, HDB/PDB/SDB/MRS Policies 
(incorporated by reference, see Sec. 192.7). For reinforced 
thermosetting plastic pipe, 11,000 psig (75,842 kPa). [Note: Arithmetic 
interpolation is not allowed for PA-11 pipe.]
t = Specified wall thickness, inches (mm).
D = Specified outside diameter, inches (mm).
SDR = Standard dimension ratio, the ratio of the average specified 
outside diameter to the minimum specified wall thickness, corresponding 
to a value from a common numbering system that was derived from the 
American National Standards Institute preferred number series 10.
D F = 0.32 or
    = 0.40 for nominal pipe size (IPS or CTS) 4-inch or less, SDR-11 or 
greater (i.e. thicker pipe wall), PA-11 pipe produced after January 23, 
2009.

[73 FR 79005, Dec. 24, 2008]



Sec. 192.123  Design limitations for plastic pipe.

    (a) Except as provided in paragraph (e) and paragraph (f) of this 
section, the design pressure may not exceed a gauge pressure of 100 psig 
(689 kPa) for plastic pipe used in:
    (1) Distribution systems; or
    (2) Classes 3 and 4 locations.
    (b) Plastic pipe may not be used where operating temperatures of the 
pipe will be:
    (1) Below -20[deg]F (-20[deg]C), or -40[deg]F (-40[deg]C) if all 
pipe and pipeline components whose operating temperature will be below -
29[deg]C (-20[deg]F) have a temperature rating by the manufacturer 
consistent with that operating temperature; or
    (2) Above the following applicable temperatures:
    (i) For thermoplastic pipe, the temperature at which the HDB used in 
the design formula under Sec. 192.121 is determined.
    (ii) For reinforced thermosetting plastic pipe, 150[deg]F 
(66[deg]C).
    (c) The wall thickness for thermoplastic pipe may not be less than 
0.062 inches (1.57 millimeters).
    (d) The wall thickness for reinforced thermosetting plastic pipe may 
not be less than that listed in the following table:

------------------------------------------------------------------------
                                                           Minimum wall
                                                             thickness
          Nominal size in inches (millimeters).               inches
                                                          (millimeters).
------------------------------------------------------------------------
2 (51)..................................................   0.060 (1.52)
3 (76)..................................................   0.060 (1.52)
4 (102).................................................   0.070 (1.78)
6 (152).................................................   0.100 (2.54)
------------------------------------------------------------------------

    (e) The design pressure for thermoplastic pipe produced after July 
14, 2004 may exceed a gauge pressure of 100 psig (689 kPa) provided 
that:
    (1) The design pressure does not exceed 125 psig (862 kPa);
    (2) The material is a PE2406 or a PE3408 as specified within ASTM 
D2513 (incorporated by reference, see Sec. 192.7);
    (3) The pipe size is nominal pipe size (IPS) 12 or less; and
    (4) The design pressure is determined in accordance with the design 
equation defined in Sec. 192.121.
    (f) The design pressure for polyamide-11 (PA-11) pipe produced after 
January 23, 2009 may exceed a gauge pressure of 100 psig (689 kPa) 
provided that:
    (1) The design pressure does not exceed 200 psig (1379 kPa);
    (2) The pipe size is nominal pipe size (IPS or CTS) 4-inch or less; 
and
    (3) The pipe has a standard dimension ratio of SDR-11 or greater 
(i.e., thicker pipe wall).

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-31, 43 FR 13883, 
Apr. 3, 1978; Amdt. 192-78, 61 FR 28783, June 6, 1996; Amdt. 192-85, 63 
FR 37502, July 13, 1998; Amdt. 192-93, 68 FR 53900, Sept. 15, 2003; 69 
FR 32894, June 14, 2004; Amdt. 192-94, 69 FR 54592, Sept. 9, 2004; Amdt. 
192-103, 71 FR 33407, June 9, 2006; 73 FR 79005, Dec. 24, 2008]

[[Page 53]]



Sec. 192.125  Design of copper pipe.

    (a) Copper pipe used in mains must have a minimum wall thickness of 
0.065 inches (1.65 millimeters) and must be hard drawn.
    (b) Copper pipe used in service lines must have wall thickness not 
less than that indicated in the following table:

------------------------------------------------------------------------
                                        Wall thickness inch (millimeter)
Standard size inch   Nominal O.D. inch ---------------------------------
   (millimeter)        (millimeter)         Nominal         Tolerance
------------------------------------------------------------------------
    \1/2\ (13)           .625 (16)       .040 (1.06)     .0035 (.0889)
    \5/8\ (16)           .750 (19)       .042 (1.07)     .0035 (.0889)
    \3/4\ (19)           .875 (22)       .045 (1.14)       .004 (.102)
        1 (25)          1.125 (29)       .050 (1.27)       .004 (.102)
   1\1/4\ (32)          1.375 (35)       .055 (1.40)     .0045 (.1143)
   1\1/2\ (38)          1.625 (41)       .060 (1.52)     .0045 (.1143)
------------------------------------------------------------------------

    (c) Copper pipe used in mains and service lines may not be used at 
pressures in excess of 100 p.s.i. (689 kPa) gage.
    (d) Copper pipe that does not have an internal corrosion resistant 
lining may not be used to carry gas that has an average hydrogen sulfide 
content of more than 0.3 grains/100 ft\3\ (6.9/m\3\) under standard 
conditions. Standard conditions refers to 60[deg]F and 14.7 psia 
(15.6[deg]C and one atmosphere) of gas.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-62, 54 FR 5628, 
Feb. 6, 1989; Amdt. 192-85, 63 FR 37502, July 13, 1998]



                 Subpart D_Design of Pipeline Components



Sec. 192.141  Scope.

    This subpart prescribes minimum requirements for the design and 
installation of pipeline components and facilities. In addition, it 
prescribes requirements relating to protection against accidental 
overpressuring.



Sec. 192.143  General requirements.

    (a) Each component of a pipeline must be able to withstand operating 
pressures and other anticipated loadings without impairment of its 
serviceability with unit stresses equivalent to those allowed for 
comparable material in pipe in the same location and kind of service. 
However, if design based upon unit stresses is impractical for a 
particular component, design may be based upon a pressure rating 
established by the manufacturer by pressure testing that component or a 
prototype of the component.
    (b) The design and installation of pipeline components and 
facilities must meet applicable requirements for corrosion control found 
in subpart I of this part.

[Amdt. 48, 49 FR 19824, May 10, 1984 as amended at 72 FR 20059, Apr. 23, 
2007]



Sec. 192.144  Qualifying metallic components.

    Notwithstanding any requirement of this subpart which incorporates 
by reference an edition of a document listed in Sec. 192.7 or Appendix 
B of this part, a metallic component manufactured in accordance with any 
other edition of that document is qualified for use under this part 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 Sec. 
192.7 or appendix B of this part:
    (1) Pressure testing;
    (2) Materials; and
    (3) Pressure and temperature ratings.

[Amdt. 192-45, 48 FR 30639, July 5, 1983, as amended by Amdt. 192-94, 69 
FR 32894, June 14, 2004]



Sec. 192.145  Valves.

    (a) Except for cast iron and plastic valves, each valve must meet 
the minimum requirements of API 6D (incorporated by reference, see Sec. 
192.7), or to a national or international standard that provides an 
equivalent performance level. A valve may not be used under operating 
conditions that exceed the applicable pressure-temperature ratings 
contained in those requirements.
    (b) Each cast iron and plastic valve must comply with the following:
    (1) The valve must have a maximum service pressure rating for 
temperatures that equal or exceed the maximum service temperature.
    (2) The valve must be tested as part of the manufacturing, as 
follows:

[[Page 54]]

    (i) With the valve in the fully open position, the shell must be 
tested with no leakage to a pressure at least 1.5 times the maximum 
service rating.
    (ii) After the shell test, the seat must be tested to a pressure not 
less than 1.5 times the maximum service pressure rating. Except for 
swing check valves, test pressure during the seat test must be applied 
successively on each side of the closed valve with the opposite side 
open. No visible leakage is permitted.
    (iii) After the last pressure test is completed, the valve must be 
operated through its full travel to demonstrate freedom from 
interference.
    (c) Each valve must be able to meet the anticipated operating 
conditions.
    (d) No valve having shell components made of ductile iron may be 
used at pressures exceeding 80 percent of the pressure ratings for 
comparable steel valves at their listed temperature. However, a valve 
having shell components made of ductile iron may be used at pressures up 
to 80 percent of the pressure ratings for comparable steel valves at 
their listed temperature, if:
    (1) The temperature-adjusted service pressure does not exceed 1,000 
p.s.i. (7 Mpa) gage; and
    (2) Welding is not used on any ductile iron component in the 
fabrication of the valve shells or their assembly.
    (e) No valve having pressure containing parts made of ductile iron 
may be used in the gas pipe components of compressor stations.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-62, 54 FR 5628, 
Feb. 6, 1989; Amdt. 192-85, 63 FR 37502, July 13, 1998; Amdt. 192-94, 69 
FR 32894, June 14, 2004]



Sec. 192.147  Flanges and flange accessories.

    (a) Each flange or flange accessory (other than cast iron) must meet 
the minimum requirements of ASME/ANSI B16.5, MSS SP-44, or the 
equivalent.
    (b) Each flange assembly must be able to withstand the maximum 
pressure at which the pipeline is to be operated and to maintain its 
physical and chemical properties at any temperature to which it is 
anticipated that it might be subjected in service.
    (c) Each flange on a flanged joint in cast iron pipe must conform in 
dimensions, drilling, face and gasket design to ASME/ANSI B16.1 and be 
cast integrally with the pipe, valve, or fitting.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-62, 54 FR 5628, 
Feb. 6, 1989; 58 FR 14521, Mar. 18, 1993]



Sec. 192.149  Standard fittings.

    (a) The minimum metal thickness of threaded fittings may not be less 
than specified for the pressures and temperatures in the applicable 
standards referenced in this part, or their equivalent.
    (b) Each steel butt-welding fitting must have pressure and 
temperature ratings based on stresses for pipe of the same or equivalent 
material. The actual bursting strength of the fitting must at least 
equal the computed bursting strength of pipe of the designated material 
and wall thickness, as determined by a prototype that was tested to at 
least the pressure required for the pipeline to which it is being added.



Sec. 192.150  Passage of internal inspection devices.

    (a) Except as provided in paragraphs (b) and (c) of this section, 
each new transmission line and each replacement of line pipe, valve, 
fitting, or other line component in a transmission line 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 compressor stations, meter stations, 
or regulator stations;
    (3) Piping associated with storage facilities, other than a 
continuous run of transmission line between a compressor station and 
storage facilities;
    (4) Cross-overs;
    (5) Sizes of pipe for which an instrumented internal inspection 
device is not commercially available;
    (6) Transmission lines, operated in conjunction with a distribution 
system which are installed in Class 4 locations;
    (7) Offshore transmission lines, except transmission lines 10\3/4\ 
inches (273 millimeters) or more in outside diameter on which 
construction begins after December 28, 2005, that run from platform to 
platform or platform to shore unless--

[[Page 55]]

    (i) Platform space or configuration is incompatible with launching 
or retrieving instrumented internal inspection devices; or
    (ii) If the design includes taps for lateral connections, the 
operator can demonstrate, based on investigation or experience, that 
there is no reasonably practical alternative under the design 
circumstances to the use of a tap that will obstruct the passage of 
instrumented internal inspection devices; and
    (8) Other piping that, under Sec. 190.9 of this chapter, the 
Administrator 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 or other unforeseen construction problems need not construct 
a new or replacement segment of a transmission line 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 Sec. 190.9 of this chapter, 
for approval that design and construction to accommodate passage of 
instrumented internal inspection devices would be impracticable. If the 
petition is denied, within 1 year after the date of the notice of the 
denial, the operator must modify that segment to allow passage of 
instrumented internal inspection devices.

[Amdt. 192-72, 59 FR 17281, Apr. 12, 1994, as amended by Amdt. 192-85, 
63 FR 37502, July 13, 1998; Amdt. 192-97, 69 FR 36029, June 28, 2004]



Sec. 192.151  Tapping.

    (a) Each mechanical fitting used to make a hot tap must be designed 
for at least the operating pressure of the pipeline.
    (b) Where a ductile iron pipe is tapped, the extent of full-thread 
engagement and the need for the use of outside-sealing service 
connections, tapping saddles, or other fixtures must be determined by 
service conditions.
    (c) Where a threaded tap is made in cast iron or ductile iron pipe, 
the diameter of the tapped hole may not be more than 25 percent of the 
nominal diameter of the pipe unless the pipe is reinforced, except that
    (1) Existing taps may be used for replacement service, if they are 
free of cracks and have good threads; and
    (2) A 1\1/4\-inch (32 millimeters) tap may be made in a 4-inch (102 
millimeters) cast iron or ductile iron pipe, without reinforcement.

However, in areas where climate, soil, and service conditions may create 
unusual external stresses on cast iron pipe, unreinforced taps may be 
used only on 6-inch (152 millimeters) or larger pipe.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37502, 
July 13, 1998]



Sec. 192.153  Components fabricated by welding.

    (a) Except for branch connections and assemblies of standard pipe 
and fittings joined by circumferential welds, the design pressure of 
each component fabricated by welding, whose strength cannot be 
determined, must be established in accordance with paragraph UG-101 of 
section VIII, Division 1, of the ASME Boiler and Pressure Vessel Code.
    (b) Each prefabricated unit that uses plate and longitudinal seams 
must be designed, constructed, and tested in accordance with section I, 
section VIII, Division 1, or section VIII, Division 2 of the ASME Boiler 
and Pressure Vessel Code, except for the following:
    (1) Regularly manufactured butt-welding fittings.
    (2) Pipe that has been produced and tested under a specification 
listed in appendix B to this part.
    (3) Partial assemblies such as split rings or collars.
    (4) Prefabricated units that the manufacturer certifies have been 
tested to at least twice the maximum pressure to which they will be 
subjected under the anticipated operating conditions.
    (c) Orange-peel bull plugs and orange-peel swages may not be used on 
pipelines that are to operate at a hoop stress of 20 percent or more of 
the SMYS of the pipe.
    (d) Except for flat closures designed in accordance with section 
VIII of the ASME Boiler and Pressure Code, flat

[[Page 56]]

closures and fish tails may not be used on pipe that either operates at 
100 p.s.i. (689 kPa) gage, or more, or is more than 3 inches (76 
millimeters) nominal diameter.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-1, 35 FR 17660, 
Nov. 17, 1970; 58 FR 14521, Mar. 18, 1993; Amdt. 192-68, 58 FR 45268, 
Aug. 27, 1993; Amdt. 192-85, 63 FR 37502, July 13, 1998]



Sec. 192.155  Welded branch connections.

    Each welded branch connection made to pipe in the form of a single 
connection, or in a header or manifold as a series of connections, must 
be designed to ensure that the strength of the pipeline system is not 
reduced, taking into account the stresses in the remaining pipe wall due 
to the opening in the pipe or header, the shear stresses produced by the 
pressure acting on the area of the branch opening, and any external 
loadings due to thermal movement, weight, and vibration.



Sec. 192.157  Extruded outlets.

    Each extruded outlet must be suitable for anticipated service 
conditions and must be at least equal to the design strength of the pipe 
and other fittings in the pipeline to which it is attached.



Sec. 192.159  Flexibility.

    Each pipeline must be designed with enough flexibility to prevent 
thermal expansion or contraction from causing excessive stresses in the 
pipe or components, excessive bending or unusual loads at joints, or 
undesirable forces or moments at points of connection to equipment, or 
at anchorage or guide points.



Sec. 192.161  Supports and anchors.

    (a) Each pipeline and its associated equipment must have enough 
anchors or supports to:
    (1) Prevent undue strain on connected equipment;
    (2) Resist longitudinal forces caused by a bend or offset in the 
pipe; and
    (3) Prevent or damp out excessive vibration.
    (b) Each exposed pipeline must have enough supports or anchors to 
protect the exposed pipe joints from the maximum end force caused by 
internal pressure and any additional forces caused by temperature 
expansion or contraction or by the weight of the pipe and its contents.
    (c) Each support or anchor on an exposed pipeline must be made of 
durable, noncombustible material and must be designed and installed as 
follows:
    (1) Free expansion and contraction of the pipeline between supports 
or anchors may not be restricted.
    (2) Provision must be made for the service conditions involved.
    (3) Movement of the pipeline may not cause disengagement of the 
support equipment.
    (d) Each support on an exposed pipeline operated at a stress level 
of 50 percent or more of SMYS must comply with the following:
    (1) A structural support may not be welded directly to the pipe.
    (2) The support must be provided by a member that completely 
encircles the pipe.
    (3) If an encircling member is welded to a pipe, the weld must be 
continuous and cover the entire circumference.
    (e) Each underground pipeline that is connected to a relatively 
unyielding line or other fixed object must have enough flexibility to 
provide for possible movement, or it must have an anchor that will limit 
the movement of the pipeline.
    (f) Except for offshore pipelines, each underground pipeline that is 
being connected to new branches must have a firm foundation for both the 
header and the branch to prevent detrimental lateral and vertical 
movement.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR 1635, 
Jan. 21, 1988]



Sec. 192.163  Compressor stations: Design and construction.

    (a) Location of compressor building. Except for a compressor 
building on a platform located offshore or in inland navigable waters, 
each main compressor building of a compressor station must be located on 
property under the control of the operator. It must be far enough away 
from adjacent property, not under control of the operator, to minimize 
the possibility of fire being communicated to the compressor building 
from structures on adjacent property. There must be enough open

[[Page 57]]

space around the main compressor building to allow the free movement of 
fire-fighting equipment.
    (b) Building construction. Each building on a compressor station 
site must be made of noncombustible materials if it contains either--
    (1) Pipe more than 2 inches (51 millimeters) in diameter that is 
carrying gas under pressure; or
    (2) Gas handling equipment other than gas utilization equipment used 
for domestic purposes.
    (c) Exits. Each operating floor of a main compressor building must 
have at least two separated and unobstructed exits located so as to 
provide a convenient possibility of escape and an unobstructed passage 
to a place of safety. Each door latch on an exit must be of a type which 
can be readily opened from the inside without a key. Each swinging door 
located in an exterior wall must be mounted to swing outward.
    (d) Fenced areas. Each fence around a compressor station must have 
at least two gates located so as to provide a convenient opportunity for 
escape to a place of safety, or have other facilities affording a 
similarly convenient exit from the area. Each gate located within 200 
feet (61 meters) of any compressor plant building must open outward and, 
when occupied, must be openable from the inside without a key.
    (e) Electrical facilities. Electrical equipment and wiring installed 
in compressor stations must conform to the National Electrical Code, 
ANSI/NFPA 70, so far as that code is applicable.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34605, 
Aug. 16, 1976; Amdt. 192-37, 46 FR 10159, Feb. 2, 1981; 58 FR 14521, 
Mar. 18, 1993; Amdt. 192-85, 63 FR 37502, 37503, July 13, 1998]



Sec. 192.165  Compressor stations: Liquid removal.

    (a) Where entrained vapors in gas may liquefy under the anticipated 
pressure and temperature conditions, the compressor must be protected 
against the introduction of those liquids in quantities that could cause 
damage.
    (b) Each liquid separator used to remove entrained liquids at a 
compressor station must:
    (1) Have a manually operable means of removing these liquids.
    (2) Where slugs of liquid could be carried into the compressors, 
have either automatic liquid removal facilities, an automatic compressor 
shutdown device, or a high liquid level alarm; and
    (3) Be manufactured in accordance with section VIII of the ASME 
Boiler and Pressure Vessel Code, except that liquid separators 
constructed of pipe and fittings without internal welding must be 
fabricated with a design factor of 0.4, or less.



Sec. 192.167  Compressor stations: Emergency shutdown.

    (a) Except for unattended field compressor stations of 1,000 
horsepower (746 kilowatts) or less, each compressor station must have an 
emergency shutdown system that meets the following:
    (1) It must be able to block gas out of the station and blow down 
the station piping.
    (2) It must discharge gas from the blowdown piping at a location 
where the gas will not create a hazard.
    (3) It must provide means for the shutdown of gas compressing 
equipment, gas fires, and electrical facilities in the vicinity of gas 
headers and in the compressor building, except that:
    (i) Electrical circuits that supply emergency lighting required to 
assist station personnel in evacuating the compressor building and the 
area in the vicinity of the gas headers must remain energized; and
    (ii) Electrical circuits needed to protect equipment from damage may 
remain energized.
    (4) It must be operable from at least two locations, each of which 
is:
    (i) Outside the gas area of the station;
    (ii) Near the exit gates, if the station is fenced, or near 
emergency exits, if not fenced; and
    (iii) Not more than 500 feet (153 meters) from the limits of the 
station.
    (b) If a compressor station supplies gas directly to a distribution 
system with no other adequate source of gas available, the emergency 
shutdown system must be designed so that it will not function at the 
wrong time and cause an unintended outage on the distribution system.

[[Page 58]]

    (c) On a platform located offshore or in inland navigable waters, 
the emergency shutdown system must be designed and installed to actuate 
automatically by each of the following events:
    (1) In the case of an unattended compressor station:
    (i) When the gas pressure equals the maximum allowable operating 
pressure plus 15 percent; or
    (ii) When an uncontrolled fire occurs on the platform; and
    (2) In the case of a compressor station in a building:
    (i) When an uncontrolled fire occurs in the building; or
    (ii) When the concentration of gas in air reaches 50 percent or more 
of the lower explosive limit in a building which has a source of 
ignition.

For the purpose of paragraph (c)(2)(ii) of this section, an electrical 
facility which conforms to Class 1, Group D, of the National Electrical 
Code is not a source of ignition.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34605, 
Aug. 16, 1976; Amdt. 192-85, 63 FR 37503, July 13, 1998]



Sec. 192.169  Compressor stations: Pressure limiting devices.

    (a) Each compressor station must have pressure relief or other 
suitable protective devices of sufficient capacity and sensitivity to 
ensure that the maximum allowable operating pressure of the station 
piping and equipment is not exceeded by more than 10 percent.
    (b) Each vent line that exhausts gas from the pressure relief valves 
of a compressor station must extend to a location where the gas may be 
discharged without hazard.



Sec. 192.171  Compressor stations: Additional safety equipment.

    (a) Each compressor station must have adequate fire protection 
facilities. If fire pumps are a part of these facilities, their 
operation may not be affected by the emergency shutdown system.
    (b) Each compressor station prime mover, other than an electrical 
induction or synchronous motor, must have an automatic device to shut 
down the unit before the speed of either the prime mover or the driven 
unit exceeds a maximum safe speed.
    (c) Each compressor unit in a compressor station must have a 
shutdown or alarm device that operates in the event of inadequate 
cooling or lubrication of the unit.
    (d) Each compressor station gas engine that operates with pressure 
gas injection must be equipped so that stoppage of the engine 
automatically shuts off the fuel and vents the engine distribution 
manifold.
    (e) Each muffler for a gas engine in a compressor station must have 
vent slots or holes in the baffles of each compartment to prevent gas 
from being trapped in the muffler.



Sec. 192.173  Compressor stations: Ventilation.

    Each compressor station building must be ventilated to ensure that 
employees are not endangered by the accumulation of gas in rooms, sumps, 
attics, pits, or other enclosed places.



Sec. 192.175  Pipe-type and bottle-type holders.

    (a) Each pipe-type and bottle-type holder must be designed so as to 
prevent the accumulation of liquids in the holder, in connecting pipe, 
or in auxiliary equipment, that might cause corrosion or interfere with 
the safe operation of the holder.
    (b) Each pipe-type or bottle-type holder must have minimum clearance 
from other holders in accordance with the following formula:

C=(DxPxF)/48.33) (C=(3DxPxF/1,000))

in which:

C=Minimum clearance between pipe containers or bottles in inches 
(millimeters).
D=Outside diameter of pipe containers or bottles in inches 
(millimeters).
P=Maximum allowable operating pressure, p.s.i. (kPa) gage.
F=Design factor as set forth in Sec. 192.111 of this part.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503, 
July 13, 1998]



Sec. 192.177  Additional provisions for bottle-type holders.

    (a) Each bottle-type holder must be--
    (1) Located on a site entirely surrounded by fencing that prevents 
access by unauthorized persons and with

[[Page 59]]

minimum clearance from the fence as follows:

------------------------------------------------------------------------
                                                             Minimum
          Maximum allowable operating pressure            clearance feet
                                                             (meters)
------------------------------------------------------------------------
Less than 1,000 p.s.i. (7 MPa) gage....................         25 (7.6)
1,000 p.s.i. (7 MPa) gage or more......................         100 (31)
------------------------------------------------------------------------

    (2) Designed using the design factors set forth in Sec. 192.111; 
and
    (3) Buried with a minimum cover in accordance with Sec. 192.327.
    (b) Each bottle-type holder manufactured from steel that is not 
weldable under field conditions must comply with the following:
    (1) A bottle-type holder made from alloy steel must meet the 
chemical and tensile requirements for the various grades of steel in 
ASTM A 372/A 372M.
    (2) The actual yield-tensile ratio of the steel may not exceed 0.85.
    (3) Welding may not be performed on the holder after it has been 
heat treated or stress relieved, except that copper wires may be 
attached to the small diameter portion of the bottle end closure for 
cathodic protection if a localized thermit welding process is used.
    (4) The holder must be given a mill hydrostatic test at a pressure 
that produces a hoop stress at least equal to 85 percent of the SMYS.
    (5) The holder, connection pipe, and components must be leak tested 
after installation as required by subpart J of this part.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR 1635, 
Jan. 21, 1988; Amdt 192-62, 54 FR 5628, Feb. 6, 1989; 58 FR 14521, Mar. 
18, 1993; Amdt. 192-85, 63 FR 37503, July 13, 1998]



Sec. 192.179  Transmission line valves.

    (a) Each transmission line, other than offshore segments, must have 
sectionalizing block valves spaced as follows, unless in a particular 
case the Administrator finds that alternative spacing would provide an 
equivalent level of safety:
    (1) Each point on the pipeline in a Class 4 location must be within 
2\1/2\ miles (4 kilometers)of a valve.
    (2) Each point on the pipeline in a Class 3 location must be within 
4 miles (6.4 kilometers) of a valve.
    (3) Each point on the pipeline in a Class 2 location must be within 
7\1/2\ miles (12 kilometers) of a valve.
    (4) Each point on the pipeline in a Class 1 location must be within 
10 miles (16 kilometers) of a valve.
    (b) Each sectionalizing block valve on a transmission line, other 
than offshore segments, must comply with the following:
    (1) The valve and the operating device to open or close the valve 
must be readily accessible and protected from tampering and damage.
    (2) The valve must be supported to prevent settling of the valve or 
movement of the pipe to which it is attached.
    (c) Each section of a transmission line, other than offshore 
segments, between main line valves must have a blowdown valve with 
enough capacity to allow the transmission line to be blown down as 
rapidly as practicable. Each blowdown discharge must be located so the 
gas can be blown to the atmosphere without hazard and, if the 
transmission line is adjacent to an overhead electric line, so that the 
gas is directed away from the electrical conductors.
    (d) Offshore segments of transmission lines must be equipped with 
valves or other components to shut off the flow of gas to an offshore 
platform in an emergency.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34606, 
Aug. 16, 1976; Amdt. 192-78, 61 FR 28784, June 6, 1996; Amdt. 192-85, 63 
FR 37503, July 13, 1998]



Sec. 192.181  Distribution line valves.

    (a) Each high-pressure distribution system must have valves spaced 
so as to reduce the time to shut down a section of main in an emergency. 
The valve spacing is determined by the operating pressure, the size of 
the mains, and the local physical conditions.
    (b) Each regulator station controlling the flow or pressure of gas 
in a distribution system must have a valve installed on the inlet piping 
at a distance from the regulator station sufficient to permit the 
operation of the valve during an emergency that might preclude access to 
the station.

[[Page 60]]

    (c) Each valve on a main installed for operating or emergency 
purposes must comply with the following:
    (1) The valve must be placed in a readily accessible location so as 
to facilitate its operation in an emergency.
    (2) The operating stem or mechanism must be readily accessible.
    (3) If the valve is installed in a buried box or enclosure, the box 
or enclosure must be installed so as to avoid transmitting external 
loads to the main.



Sec. 192.183  Vaults: Structural design requirements.

    (a) Each underground vault or pit for valves, pressure relieving, 
pressure limiting, or pressure regulating stations, must be able to meet 
the loads which may be imposed upon it, and to protect installed 
equipment.
    (b) There must be enough working space so that all of the equipment 
required in the vault or pit can be properly installed, operated, and 
maintained.
    (c) Each pipe entering, or within, a regulator vault or pit must be 
steel for sizes 10 inch (254 millimeters), and less, except that control 
and gage piping may be copper. Where pipe extends through the vault or 
pit structure, provision must be made to prevent the passage of gases or 
liquids through the opening and to avert strains in the pipe.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503, 
July 13, 1998]



Sec. 192.185  Vaults: Accessibility.

    Each vault must be located in an accessible location and, so far as 
practical, away from:
    (a) Street intersections or points where traffic is heavy or dense;
    (b) Points of minimum elevation, catch basins, or places where the 
access cover will be in the course of surface waters; and
    (c) Water, electric, steam, or other facilities.



Sec. 192.187  Vaults: Sealing, venting, and ventilation.

    Each underground vault or closed top pit containing either a 
pressure regulating or reducing station, or a pressure limiting or 
relieving station, must be sealed, vented or ventilated as follows:
    (a) When the internal volume exceeds 200 cubic feet (5.7 cubic 
meters):
    (1) The vault or pit must be ventilated with two ducts, each having 
at least the ventilating effect of a pipe 4 inches (102 millimeters) in 
diameter;
    (2) The ventilation must be enough to minimize the formation of 
combustible atmosphere in the vault or pit; and
    (3) The ducts must be high enough above grade to disperse any gas-
air mixtures that might be discharged.
    (b) When the internal volume is more than 75 cubic feet (2.1 cubic 
meters) but less than 200 cubic feet (5.7 cubic meters):
    (1) If the vault or pit is sealed, each opening must have a tight 
fitting cover without open holes through which an explosive mixture 
might be ignited, and there must be a means for testing the internal 
atmosphere before removing the cover;
    (2) If the vault or pit is vented, there must be a means of 
preventing external sources of ignition from reaching the vault 
atmosphere; or
    (3) If the vault or pit is ventilated, paragraph (a) or (c) of this 
section applies.
    (c) If a vault or pit covered by paragraph (b) of this section is 
ventilated by openings in the covers or gratings and the ratio of the 
internal volume, in cubic feet, to the effective ventilating area of the 
cover or grating, in square feet, is less than 20 to 1, no additional 
ventilation is required.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503, 
July 13, 1998]



Sec. 192.189  Vaults: Drainage and waterproofing.

    (a) Each vault must be designed so as to minimize the entrance of 
water.
    (b) A vault containing gas piping may not be connected by means of a 
drain connection to any other underground structure.
    (c) Electrical equipment in vaults must conform to the applicable 
requirements of Class 1, Group D, of the National Electrical Code, ANSI/
NFPA 70.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-76, 61 FR 26122, 
May 24, 1996]

[[Page 61]]



Sec. 192.191  Design pressure of plastic fittings.

    (a) Thermosetting fittings for plastic pipe must conform to ASTM D 
2517.
    (b) Thermoplastic fittings for plastic pipe must conform to ASTM D 
2513.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR 1635, 
Jan. 21, 1988]



Sec. 192.193  Valve installation in plastic pipe.

    Each valve installed in plastic pipe must be designed so as to 
protect the plastic material against excessive torsional or shearing 
loads when the valve or shutoff is operated, and from any other 
secondary stresses that might be exerted through the valve or its 
enclosure.



Sec. 192.195  Protection against accidental overpressuring.

    (a) General requirements. Except as provided in Sec. 192.197, each 
pipeline that is connected to a gas source so that the maximum allowable 
operating pressure could be exceeded as the result of pressure control 
failure or of some other type of failure, must have pressure relieving 
or pressure limiting devices that meet the requirements of Sec. Sec. 
192.199 and 192.201.
    (b) Additional requirements for distribution systems. Each 
distribution system that is supplied from a source of gas that is at a 
higher pressure than the maximum allowable operating pressure for the 
system must--
    (1) Have pressure regulation devices capable of meeting the 
pressure, load, and other service conditions that will be experienced in 
normal operation of the system, and that could be activated in the event 
of failure of some portion of the system; and
    (2) Be designed so as to prevent accidental overpressuring.



Sec. 192.197  Control of the pressure of gas delivered from high-
pressure distribution systems.

    (a) If the maximum actual operating pressure of the distribution 
system is 60 p.s.i. (414 kPa) gage, or less and a service regulator 
having the following characteristics is used, no other pressure limiting 
device is required:
    (1) A regulator capable of reducing distribution line pressure to 
pressures recommended for household appliances.
    (2) A single port valve with proper orifice for the maximum gas 
pressure at the regulator inlet.
    (3) A valve seat made of resilient material designed to withstand 
abrasion of the gas, impurities in gas, cutting by the valve, and to 
resist permanent deformation when it is pressed against the valve port.
    (4) Pipe connections to the regulator not exceeding 2 inches (51 
millimeters) in diameter.
    (5) A regulator that, under normal operating conditions, is able to 
regulate the downstream pressure within the necessary limits of accuracy 
and to limit the build-up of pressure under no-flow conditions to 
prevent a pressure that would cause the unsafe operation of any 
connected and properly adjusted gas utilization equipment.
    (6) A self-contained service regulator with no external static or 
control lines.
    (b) If the maximum actual operating pressure of the distribution 
system is 60 p.s.i. (414 kPa) gage, or less, and a service regulator 
that does not have all of the characteristics listed in paragraph (a) of 
this section is used, or if the gas contains materials that seriously 
interfere with the operation of service regulators, there must be 
suitable protective devices to prevent unsafe overpressuring of the 
customer's appliances if the service regulator fails.
    (c) If the maximum actual operating pressure of the distribution 
system exceeds 60 p.s.i. (414 kPa) gage, one of the following methods 
must be used to regulate and limit, to the maximum safe value, the 
pressure of gas delivered to the customer:
    (1) A service regulator having the characteristics listed in 
paragraph (a) of this section, and another regulator located upstream 
from the service regulator. The upstream regulator may not be set to 
maintain a pressure higher than 60 p.s.i. (414 kPa) gage. A device must 
be installed between the upstream regulator and the service regulator to 
limit the pressure on the inlet of the service regulator to 60 p.s.i. 
(414 kPa) gage or less in case the upstream regulator fails to function 
properly.

[[Page 62]]

This device may be either a relief valve or an automatic shutoff that 
shuts, if the pressure on the inlet of the service regulator exceeds the 
set pressure (60 p.s.i. (414 kPa) gage or less), and remains closed 
until manually reset.
    (2) A service regulator and a monitoring regulator set to limit, to 
a maximum safe value, the pressure of the gas delivered to the customer.
    (3) A service regulator with a relief valve vented to the outside 
atmosphere, with the relief valve set to open so that the pressure of 
gas going to the customer does not exceed a maximum safe value. The 
relief valve may either be built into the service regulator or it may be 
a separate unit installed downstream from the service regulator. This 
combination may be used alone only in those cases where the inlet 
pressure on the service regulator does not exceed the manufacturer's 
safe working pressure rating of the service regulator, and may not be 
used where the inlet pressure on the service regulator exceeds 125 
p.s.i. (862 kPa) gage. For higher inlet pressures, the methods in 
paragraph (c) (1) or (2) of this section must be used.
    (4) A service regulator and an automatic shutoff device that closes 
upon a rise in pressure downstream from the regulator and remains closed 
until manually reset.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-1, 35 FR 17660, 
Nov. 7, 1970; Amdt 192-85, 63 FR 37503, July 13, 1998; Amdt. 192-93, 68 
FR 53900, Sept. 15, 2003]



Sec. 192.199  Requirements for design of pressure relief and limiting
devices.

    Except for rupture discs, each pressure relief or pressure limiting 
device must:
    (a) Be constructed of materials such that the operation of the 
device will not be impaired by corrosion;
    (b) Have valves and valve seats that are designed not to stick in a 
position that will make the device inoperative;
    (c) Be designed and installed so that it can be readily operated to 
determine if the valve is free, can be tested to determine the pressure 
at which it will operate, and can be tested for leakage when in the 
closed position;
    (d) Have support made of noncombustible material;
    (e) Have discharge stacks, vents, or outlet ports designed to 
prevent accumulation of water, ice, or snow, located where gas can be 
discharged into the atmosphere without undue hazard;
    (f) Be designed and installed so that the size of the openings, 
pipe, and fittings located between the system to be protected and the 
pressure relieving device, and the size of the vent line, are adequate 
to prevent hammering of the valve and to prevent impairment of relief 
capacity;
    (g) Where installed at a district regulator station to protect a 
pipeline system from overpressuring, be designed and installed to 
prevent any single incident such as an explosion in a vault or damage by 
a vehicle from affecting the operation of both the overpressure 
protective device and the district regulator; and
    (h) Except for a valve that will isolate the system under protection 
from its source of pressure, be designed to prevent unauthorized 
operation of any stop valve that will make the pressure relief valve or 
pressure limiting device inoperative.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-1, 35 FR 17660, 
Nov. 17, 1970]



Sec. 192.201  Required capacity of pressure relieving and limiting 
stations.

    (a) Each pressure relief station or pressure limiting station or 
group of those stations installed to protect a pipeline must have enough 
capacity, and must be set to operate, to insure the following:
    (1) In a low pressure distribution system, the pressure may not 
cause the unsafe operation of any connected and properly adjusted gas 
utilization equipment.
    (2) In pipelines other than a low pressure distribution system:
    (i) If the maximum allowable operating pressure is 60 p.s.i. (414 
kPa) gage or more, the pressure may not exceed the maximum allowable 
operating pressure plus 10 percent, or the pressure that produces a hoop 
stress of 75 percent of SMYS, whichever is lower;
    (ii) If the maximum allowable operating pressure is 12 p.s.i. (83 
kPa) gage or more, but less than 60 p.s.i. (414 kPa) gage, the pressure 
may not exceed the

[[Page 63]]

maximum allowable operating pressure plus 6 p.s.i. (41 kPa) gage; or
    (iii) If the maximum allowable operating pressure is less than 12 
p.s.i. (83 kPa) gage, the pressure may not exceed the maximum allowable 
operating pressure plus 50 percent.
    (b) When more than one pressure regulating or compressor station 
feeds into a pipeline, relief valves or other protective devices must be 
installed at each station to ensure that the complete failure of the 
largest capacity regulator or compressor, or any single run of lesser 
capacity regulators or compressors in that station, will not impose 
pressures on any part of the pipeline or distribution system in excess 
of those for which it was designed, or against which it was protected, 
whichever is lower.
    (c) Relief valves or other pressure limiting devices must be 
installed at or near each regulator station in a low-pressure 
distribution system, with a capacity to limit the maximum pressure in 
the main to a pressure that will not exceed the safe operating pressure 
for any connected and properly adjusted gas utilization equipment.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-9, 37 FR 20827, 
Oct. 4, 1972; Amdt 192-85, 63 FR 37503, July 13, 1998]



Sec. 192.203  Instrument, control, and sampling pipe and components.

    (a) Applicability. This section applies to the design of instrument, 
control, and sampling pipe and components. It does not apply to 
permanently closed systems, such as fluid-filled temperature-responsive 
devices.
    (b) Materials and design. All materials employed for pipe and 
components must be designed to meet the particular conditions of service 
and the following:
    (1) Each takeoff connection and attaching boss, fitting, or adapter 
must be made of suitable material, be able to withstand the maximum 
service pressure and temperature of the pipe or equipment to which it is 
attached, and be designed to satisfactorily withstand all stresses 
without failure by fatigue.
    (2) Except for takeoff lines that can be isolated from sources of 
pressure by other valving, a shutoff valve must be installed in each 
takeoff line as near as practicable to the point of takeoff. Blowdown 
valves must be installed where necessary.
    (3) Brass or copper material may not be used for metal temperatures 
greater than 400[deg] F (204[deg]C).
    (4) Pipe or components that may contain liquids must be protected by 
heating or other means from damage due to freezing.
    (5) Pipe or components in which liquids may accumulate must have 
drains or drips.
    (6) Pipe or components subject to clogging from solids or deposits 
must have suitable connections for cleaning.
    (7) The arrangement of pipe, components, and supports must provide 
safety under anticipated operating stresses.
    (8) Each joint between sections of pipe, and between pipe and valves 
or fittings, must be made in a manner suitable for the anticipated 
pressure and temperature condition. Slip type expansion joints may not 
be used. Expansion must be allowed for by providing flexibility within 
the system itself.
    (9) Each control line must be protected from anticipated causes of 
damage and must be designed and installed to prevent damage to any one 
control line from making both the regulator and the over-pressure 
protective device inoperative.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-78, 61 FR 28784, 
June 6, 1996; Amdt. 192-85, 63 FR 37503, July 13, 1998]



                 Subpart E_Welding of Steel in Pipelines



Sec. 192.221  Scope.

    (a) This subpart prescribes minimum requirements for welding steel 
materials in pipelines.
    (b) This subpart does not apply to welding that occurs during the 
manufacture of steel pipe or steel pipeline components.



Sec. 192.225  Welding procedures.

    (a) Welding must be performed by a qualified welder in accordance 
with welding procedures qualified under section 5 of API 1104 
(incorporated by reference, see Sec. 192.7) or section IX of the

[[Page 64]]

ASME Boiler and Pressure Vessel Code `` Welding and Brazing 
Qualifications'' (incorporated by reference, see Sec. 192.7) to produce 
welds meeting the requirements of this subpart. The quality of the test 
welds used to qualify welding procedures shall be determined by 
destructive testing in accordance with the applicable welding 
standard(s).
    (b) Each welding procedure must be recorded in detail, including the 
results of the qualifying tests. This record must be retained and 
followed whenever the procedure is used.

[Amdt. 192-52, 51 FR 20297, June 4, 1986; Amdt. 192-94, 69 FR 32894, 
June 14, 2004]



Sec. 192.227  Qualification of welders.

    (a) Except as provided in paragraph (b) of this section, each welder 
must be qualified in accordance with section 6 of API 1104 (incorporated 
by reference, see Sec. 192.7) or section IX of the ASME Boiler and 
Pressure Vessel Code (incorporated by reference, see Sec. 192.7). 
However, a welder qualified under an earlier edition than listed in 
Sec. 192.7 of this part may weld but may not requalify under that 
earlier edition.
    (b) A welder may qualify to perform welding on pipe to be operated 
at a pressure that produces a hoop stress of less than 20 percent of 
SMYS by performing an acceptable test weld, for the process to be used, 
under the test set forth in section I of Appendix C of this part. Each 
welder who is to make a welded service line connection to a main must 
first perform an acceptable test weld under section II of Appendix C of 
this part as a requirement of the qualifying test.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-43, 47 FR 46851, 
Oct. 21, 1982; Amdt. 192-52, 51 FR 20297, June 4, 1986; Amdt. 192-78, 61 
FR 28784, June 6, 1996; Amdt. 192-94, 69 FR 32894, June 14, 2004; Amdt. 
192-103, 72 FR 4656, Feb. 1, 2007]



Sec. 192.229  Limitations on welders.

    (a) No welder whose qualification is based on nondestructive testing 
may weld compressor station pipe and components.
    (b) No welder may weld with a particular welding process unless, 
within the preceding 6 calendar months, he has engaged in welding with 
that process.
    (c) A welder qualified under Sec. 192.227(a)--
    (1) May not weld on pipe to be operated at a pressure that produces 
a hoop stress of 20 percent or more of SMYS unless within the preceding 
6 calendar months the welder has had one weld tested and found 
acceptable under the sections 6 or 9 of API Standard 1104 (incorporated 
by reference, see Sec. 192.7). Alternatively, welders may maintain an 
ongoing qualification status by performing welds tested and found 
acceptable under the above acceptance criteria at least twice each 
calendar year, but at intervals not exceeding 7\1/2\ months. A welder 
qualified under an earlier edition of a standard listed in Sec. 192.7 
of this part may weld but may not requalify under that earlier edition; 
and
    (2) May not weld on pipe to be operated at a pressure that produces 
a hoop stress of less than 20 percent of SMYS unless the welder is 
tested in accordance with paragraph (c)(1) of this section or 
requalifies under paragraph (d)(1) or (d)(2) of this section.
    (d) A welder qualified under Sec. 192.227(b) may not weld unless--
    (1) Within the preceding 15 calendar months, but at least once each 
calendar year, the welder has requalified under Sec. 192.227(b); or
    (2) Within the preceding 7\1/2\ calendar months, but at least twice 
each calendar year, the welder has had--
    (i) A production weld cut out, tested, and found acceptable in 
accordance with the qualifying test; or
    (ii) For welders who work only on service lines 2 inches (51 
millimeters) or smaller in diameter, two sample welds tested and found 
acceptable in accordance with the test in section III of Appendix C of 
this part.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-37, 46 FR 10159, 
Feb. 2, 1981; Amdt. 192-78, 61 FR 28784, June 6, 1996; Amdt. 192-85, 63 
FR 37503, July 13, 1998; Amdt. 192-94, 69 FR 32895, June 14, 2004]



Sec. 192.231  Protection from weather.

    The welding operation must be protected from weather conditions that 
would impair the quality of the completed weld.

[[Page 65]]



Sec. 192.233  Miter joints.

    (a) A miter joint on steel pipe to be operated at a pressure that 
produces a hoop stress of 30 percent or more of SMYS may not deflect the 
pipe more than 3[deg].
    (b) A miter joint on steel pipe to be operated at a pressure that 
produces a hoop stress of less than 30 percent, but more than 10 
percent, of SMYS may not deflect the pipe more than 12\1/2\[deg] and 
must be a distance equal to one pipe diameter or more away from any 
other miter joint, as measured from the crotch of each joint.
    (c) A miter joint on steel pipe to be operated at a pressure that 
produces a hoop stress of 10 percent or less of SMYS may not deflect the 
pipe more than 90[deg].



Sec. 192.235  Preparation for welding.

    Before beginning any welding, the welding surfaces must be clean and 
free of any material that may be detrimental to the weld, and the pipe 
or component must be aligned to provide the most favorable condition for 
depositing the root bead. This alignment must be preserved while the 
root bead is being deposited.



Sec. 192.241  Inspection and test of welds.

    (a) Visual inspection of welding must be conducted by an individual 
qualified by appropriate training and experience to ensure that:
    (1) The welding is performed in accordance with the welding 
procedure; and
    (2) The weld is acceptable under paragraph (c) of this section.
    (b) The welds on a pipeline to be operated at a pressure that 
produces a hoop stress of 20 percent or more of SMYS must be 
nondestructively tested in accordance with Sec. 192.243, except that 
welds that are visually inspected and approved by a qualified welding 
inspector need not be nondestructively tested if:
    (1) The pipe has a nominal diameter of less than 6 inches (152 
millimeters); or
    (2) The pipeline is to be operated at a pressure that produces a 
hoop stress of less than 40 percent of SMYS and the welds are so limited 
in number that nondestructive testing is impractical.
    (c) The acceptability of a weld that is nondestructively tested or 
visually inspected is determined according to the standards in Section 9 
of API Standard 1104 (incorporated by reference, see Sec. 192.7). 
However, if a girth weld is unacceptable under those standards for a 
reason other than a crack, and if Appendix A to API 1104 applies to the 
weld, the acceptability of the weld may be further determined under that 
appendix.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-37, 46 FR 10160, 
Feb. 2, 1981; Amdt. 192-78, 61 FR 28784, June 6, 1996; Amdt. 192-85, 63 
FR 37503, July 13, 1998; Amdt. 192-94, 69 FR 32894, June 14, 2004]



Sec. 192.243  Nondestructive testing.

    (a) Nondestructive testing of welds must be performed by any 
process, other than trepanning, that will clearly indicate defects that 
may affect the integrity of the weld.
    (b) Nondestructive testing of welds must be performed:
    (1) In accordance with written procedures; and
    (2) By persons who have been trained and qualified in the 
established procedures and with the equipment employed in testing.
    (c) Procedures must be established for the proper interpretation of 
each nondestructive test of a weld to ensure the acceptability of the 
weld under Sec. 192.241(c).
    (d) When nondestructive testing is required under Sec. 192.241(b), 
the following percentages of each day's field butt welds, selected at 
random by the operator, must be nondestructively tested over their 
entire circumference:
    (1) In Class 1 locations, except offshore, at least 10 percent.
    (2) In Class 2 locations, at least 15 percent.
    (3) In Class 3 and Class 4 locations, at crossings of major or 
navigable rivers, offshore, and within railroad or public highway 
rights-of-way, including tunnels, bridges, and overhead road crossings, 
100 percent unless impracticable, in which case at least 90 percent. 
Nondestructive testing must be impracticable for each girth weld not 
tested.
    (4) At pipeline tie-ins, including tie-ins of replacement sections, 
100 percent.

[[Page 66]]

    (e) Except for a welder whose work is isolated from the principal 
welding activity, a sample of each welder's work for each day must be 
nondestructively tested, when nondestructive testing is required under 
Sec. 192.241(b).
    (f) When nondestructive testing is required under Sec. 192.241(b), 
each operator must retain, for the life of the pipeline, a record 
showing by milepost, engineering station, or by geographic feature, the 
number of girth welds made, the number nondestructively tested, the 
number rejected, and the disposition of the rejects.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34606, 
Aug. 16, 1976; Amdt. 192-50, 50 FR 37192, Sept. 12, 1985; Amdt. 192-78, 
61 FR 28784, June 6, 1996]



Sec. 192.245  Repair or removal of defects.

    (a) Each weld that is unacceptable under Sec. 192.241(c) must be 
removed or repaired. Except for welds on an offshore pipeline being 
installed from a pipeline 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 Sec. 192.225. Repair procedures must provide that 
the minimum mechanical properties specified for the welding procedure 
used to make the original weld are met upon completion of the final weld 
repair.

[Amdt. 192-46, 48 FR 48674, Oct. 20, 1983]



          Subpart F_Joining of Materials Other Than by Welding



Sec. 192.271  Scope.

    (a) This subpart prescribes minimum requirements for joining 
materials in pipelines, other than by welding.
    (b) This subpart does not apply to joining during the manufacture of 
pipe or pipeline components.



Sec. 192.273  General.

    (a) The pipeline must be designed and installed so that each joint 
will sustain the longitudinal pullout or thrust forces caused by 
contraction or expansion of the piping or by anticipated external or 
internal loading.
    (b) Each joint must be made in accordance with written procedures 
that have been proven by test or experience to produce strong gastight 
joints.
    (c) Each joint must be inspected to insure compliance with this 
subpart.



Sec. 192.275  Cast iron pipe.

    (a) Each caulked bell and spigot joint in cast iron pipe must be 
sealed with mechanical leak clamps.
    (b) Each mechanical joint in cast iron pipe must have a gasket made 
of a resilient material as the sealing medium. Each gasket must be 
suitably confined and retained under compression by a separate gland or 
follower ring.
    (c) Cast iron pipe may not be joined by threaded joints.
    (d) Cast iron pipe may not be joined by brazing.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-62, 54 FR 5628, 
Feb. 6, 1989]



Sec. 192.277  Ductile iron pipe.

    (a) Ductile iron pipe may not be joined by threaded joints.
    (b) Ductile iron pipe may not be joined by brazing.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-62, 54 FR 5628, 
Feb. 6, 1989]



Sec. 192.279  Copper pipe.

    Copper pipe may not be threaded except that copper pipe used for 
joining screw fittings or valves may be threaded if the wall thickness 
is equivalent to the comparable size of Schedule 40 or heavier wall pipe 
listed in Table C1 of ASME/ANSI B16.5.

[Amdt. 192-62, 54 FR 5628, Feb. 6, 1989, as amended at 58 FR 14521, Mar. 
18, 1993]



Sec. 192.281  Plastic pipe.

    (a) General. A plastic pipe joint that is joined by solvent cement, 
adhesive,

[[Page 67]]

or heat fusion may not be disturbed until it has properly set. Plastic 
pipe may not be joined by a threaded joint or miter joint.
    (b) Solvent cement joints. Each solvent cement joint on plastic pipe 
must comply with the following:
    (1) The mating surfaces of the joint must be clean, dry, and free of 
material which might be deterimental to the joint.
    (2) The solvent cement must conform to ASTM Designation D 2513.
    (3) The joint may not be heated to accelerate the setting of the 
cement.
    (c) Heat-fusion joints. Each heat-fusion joint on plastic pipe must 
comply with the following:
    (1) A butt heat-fusion joint must be joined by a device that holds 
the heater element square to the ends of the piping, compresses the 
heated ends together, and holds the pipe in proper alignment while the 
plastic hardens.
    (2) A socket heat-fusion joint must be joined by a device that heats 
the mating surfaces of the joint uniformly and simultaneously to 
essentially the same temperature.
    (3) An electrofusion joint must be joined utilizing the equipment 
and techniques of the fittings manufacturer or equipment and techniques 
shown, by testing joints to the requirements of Sec. 
192.283(a)(1)(iii), to be at least equivalent to those of the fittings 
manufacturer.
    (4) Heat may not be applied with a torch or other open flame.
    (d) Adhesive joints. Each adhesive joint on plastic pipe must comply 
with the following:
    (1) The adhesive must conform to ASTM Designation D 2517.
    (2) The materials and adhesive must be compatible with each other.
    (e) Mechanical joints. Each compression type mechanical joint on 
plastic pipe must comply with the following:
    (1) The gasket material in the coupling must be compatible with the 
plastic.
    (2) A rigid internal tubular stiffener, other than a split tubular 
stiffener, must be used in conjunction with the coupling.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-34, 44 FR 42973, 
July 23, 1979; Amdt. 192-58, 53 FR 1635, Jan. 21, 1988; Amdt. 192-61, 53 
FR 36793, Sept. 22, 1988; 58 FR 14521, Mar. 18, 1993; Amdt. 192-78, 61 
FR 28784, June 6, 1996]



Sec. 192.283  Plastic pipe: Qualifying joining procedures.

    (a) Heat fusion, solvent cement, and adhesive joints. Before any 
written procedure established under Sec. 192.273(b) is used for making 
plastic pipe joints by a heat fusion, solvent cement, or adhesive 
method, the procedure must be qualified by subjecting specimen joints 
made according to the procedure to the following tests:
    (1) The burst test requirements of--
    (i) In the case of thermoplastic pipe, paragraph 6.6 (sustained 
pressure test) or paragraph 6.7 (Minimum Hydrostatic Burst Test) or 
paragraph 8.9 ( Sustained Static pressure Test) of ASTM D2513 
(incorporated by reference, see Sec. 192.7);
    (ii) In the case of thermosetting plastic pipe, paragraph 8.5 
(Minimum Hydrostatic Burst Pressure) or paragraph 8.9 (Sustained Static 
Pressure Test) of ASTM D2517 (incorporated by reference, see Sec. 
192.7); or
    (iii) In the case of electrofusion fittings for polyethylene pipe 
and tubing, paragraph 9.1 (Minimum Hydraulic Burst Pressure Test), 
paragraph 9.2 (Sustained Pressure Test), paragraph 9.3 (Tensile Strength 
Test), or paragraph 9.4 (Joint Integrity Tests) of ASTM Designation 
F1055 (incorporated by reference, see Sec. 192.7).
    (2) For procedures intended for lateral pipe connections, subject a 
specimen joint made from pipe sections joined at right angles according 
to the procedure to a force on the lateral pipe until failure occurs in 
the specimen. If failure initiates outside the joint area, the procedure 
qualifies for use; and
    (3) For procedures intended for non-lateral pipe connections, follow 
the tensile test requirements of ASTM D638 (incorporated by reference, 
see Sec. 192.7), except that the test may be conducted at ambient 
temperature and humidity If the specimen elongates no less than 25 
percent or failure initiates

[[Page 68]]

outside the joint area, the procedure qualifies for use.
    (b) Mechanical joints. Before any written procedure established 
under Sec. 192.273(b) is used for making mechanical plastic pipe joints 
that are designed to withstand tensile forces, the procedure must be 
qualified by subjecting 5 specimen joints made according to the 
procedure to the following tensile test:
    (1) Use an apparatus for the test as specified in ASTM D 638 (except 
for conditioning), (incorporated by reference, see Sec. 192.7).
    (2) The specimen must be of such length that the distance between 
the grips of the apparatus and the end of the stiffener does not affect 
the joint strength.
    (3) The speed of testing is 0.20 in (5.0 mm) per minute, plus or 
minus 25 percent.
    (4) Pipe specimens less than 4 inches (102 mm) in diameter are 
qualified if the pipe yields to an elongation of no less than 25 percent 
or failure initiates outside the joint area.
    (5) Pipe specimens 4 inches (102 mm) and larger in diameter shall be 
pulled until the pipe is subjected to a tensile stress equal to or 
greater than the maximum thermal stress that would be produced by a 
temperature change of 100[deg]F (38[deg]C) or until the pipe is pulled 
from the fitting. If the pipe pulls from the fitting, the lowest value 
of the five test results or the manufacturer's rating, whichever is 
lower must be used in the design calculations for stress.
    (6) Each specimen that fails at the grips must be retested using new 
pipe.
    (7) Results obtained pertain only to the specific outside diameter, 
and material of the pipe tested, except that testing of a heavier wall 
pipe may be used to qualify pipe of the same material but with a lesser 
wall thickness.
    (c) A copy of each written procedure being used for joining plastic 
pipe must be available to the persons making and inspecting joints.
    (d) Pipe or fittings manufactured before July 1, 1980, may be used 
in accordance with procedures that the manufacturer certifies will 
produce a joint as strong as the pipe.

[Amdt. 192-34A, 45 FR 9935, Feb. 14, 1980, as amended by Amdt. 192-34B, 
46 FR 39, Jan. 2, 1981; 47 FR 32720, July 29, 1982; 47 FR 49973, Nov. 4, 
1982; 58 FR 14521, Mar. 18, 1993; Amdt. 192-78, 61 FR 28784, June 6, 
1996; Amdt. 192-85, 63 FR 37503, July 13, 1998; Amdt. 192-94, 69 FR 
32895, June 14, 2004; Amdt. 192-94, 69 FR 54592, Sept. 9, 2004]



Sec. 192.285  Plastic pipe: Qualifying persons to make joints.

    (a) No person may make a plastic pipe joint unless that person has 
been qualified under the applicable joining procedure by:
    (1) Appropriate training or experience in the use of the procedure; 
and
    (2) Making a specimen joint from pipe sections joined according to 
the procedure that passes the inspection and test set forth in paragraph 
(b) of this section.
    (b) The specimen joint must be:
    (1) Visually examined during and after assembly or joining and found 
to have the same appearance as a joint or photographs of a joint that is 
acceptable under the procedure; and
    (2) In the case of a heat fusion, solvent cement, or adhesive joint:
    (i) Tested under any one of the test methods listed under Sec. 
192.283(a) applicable to the type of joint and material being tested;
    (ii) Examined by ultrasonic inspection and found not to contain 
flaws that would cause failure; or
    (iii) Cut into at least 3 longitudinal straps, each of which is:
    (A) Visually examined and found not to contain voids or 
discontinuities on the cut surfaces of the joint area; and
    (B) Deformed by bending, torque, or impact, and if failure occurs, 
it must not initiate in the joint area.
    (c) A person must be requalified under an applicable procedure, if 
during any 12-month period that person:
    (1) Does not make any joints under that procedure; or
    (2) Has 3 joints or 3 percent of the joints made, whichever is 
greater, under that procedure that are found unacceptable by testing 
under Sec. 192.513.
    (d) Each operator shall establish a method to determine that each 
person making joints in plastic pipelines in

[[Page 69]]

the operator's system is qualified in accordance with this section.

[Amdt. 192-34A, 45 FR 9935, Feb. 14, 1980, as amended by Amdt. 192-34B, 
46 FR 39, Jan. 2, 1981; Amdt. 192-93, 68 FR 53900, Sept. 15, 2003]



Sec. 192.287  Plastic pipe: Inspection of joints.

    No person may carry out the inspection of joints in plastic pipes 
required by Sec. Sec. 192.273(c) and 192.285(b) unless that person has 
been qualified by appropriate training or experience in evaluating the 
acceptability of plastic pipe joints made under the applicable joining 
procedure.

[Amdt. 192-34, 44 FR 42974, July 23, 1979]



 Subpart G_General Construction Requirements for Transmission Lines and 
                                  Mains



Sec. 192.301  Scope.

    This subpart prescribes minimum requirements for constructing 
transmission lines and mains.



Sec. 192.303  Compliance with specifications or standards.

    Each transmission line or main must be constructed in accordance 
with comprehensive written specifications or standards that are 
consistent with this part.



Sec. 192.305  Inspection: General.

    Each transmission line or main must be inspected to ensure that it 
is constructed in accordance with this part.



Sec. 192.307  Inspection of materials.

    Each length of pipe and each other component must be visually 
inspected at the site of installation to ensure that it has not 
sustained any visually determinable damage that could impair its 
serviceability.



Sec. 192.309  Repair of steel pipe.

    (a) Each imperfection or damage that impairs the serviceability of a 
length of steel pipe must be repaired or removed. If a repair is made by 
grinding, the remaining wall thickness must at least be equal to either:
    (1) The minimum thickness required by the tolerances in the 
specification to which the pipe was manufactured; or
    (2) The nominal wall thickness required for the design pressure of 
the pipeline.
    (b) Each of the following dents must be removed from steel pipe to 
be operated at a pressure that produces a hoop stress of 20 percent, or 
more, of SMYS, unless the dent is repaired by a method that reliable 
engineering tests and analyses show can permanently restore the 
serviceability of the pipe:
    (1) A dent that contains a stress concentrator such as a scratch, 
gouge, groove, or arc burn.
    (2) A dent that affects the longitudinal weld or a circumferential 
weld.
    (3) In pipe to be operated at a pressure that produces a hoop stress 
of 40 percent or more of SMYS, a dent that has a depth of:
    (i) More than \1/4\ inch (6.4 millimeters) in pipe 12\3/4\ inches 
(324 millimeters) or less in outer diameter; or
    (ii) More than 2 percent of the nominal pipe diameter in pipe over 
12\3/4\ inches (324 millimeters) in outer diameter.

For the purpose of this section a ``dent'' is a depression that produces 
a gross disturbance in the curvature of the pipe wall without reducing 
the pipe-wall thickness. The depth of a dent is measured as the gap 
between the lowest point of the dent and a prolongation of the original 
contour of the pipe.
    (c) Each arc burn on steel pipe to be operated at a pressure that 
produces a hoop stress of 40 percent, or more, of SMYS must be repaired 
or removed. If a repair is made by grinding, the arc burn must be 
completely removed and the remaining wall thickness must be at least 
equal to either:
    (1) The minimum wall thickness required by the tolerances in the 
specification to which the pipe was manufactured; or
    (2) The nominal wall thickness required for the design pressure of 
the pipeline.
    (d) A gouge, groove, arc burn, or dent may not be repaired by insert 
patching or by pounding out.
    (e) Each gouge, groove, arc burn, or dent that is removed from a 
length of

[[Page 70]]

pipe must be removed by cutting out the damaged portion as a cylinder.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-1, 35 FR 17660, 
Nov. 17, 1970; Amdt. 192-85, 63 FR 37503, July 13, 1998; Amdt. 192-88, 
64 FR 69664, Dec. 14, 1999]



Sec. 192.311  Repair of plastic pipe.

    Each imperfection or damage that would impair the serviceability of 
plastic pipe must be repaired or removed.

[Amdt. 192-93, 68 FR 53900, Sept. 15, 2003]



Sec. 192.313  Bends and elbows.

    (a) Each field bend in steel pipe, other than a wrinkle bend made in 
accordance with Sec. 192.315, 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 12 inches (305 millimeters) or less in outside 
diameter or has a diameter to wall thickness ratio less than 70.
    (b) Each circumferential weld of steel pipe 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.
    (c) Wrought-steel welding elbows and transverse segments of these 
elbows may not be used for changes in direction on steel pipe that is 2 
inches (51 millimeters) or more in diameter unless the arc length, as 
measured along the crotch, is at least 1 inch (25 millimeters).

[Amdt. No. 192-26, 41 FR 26018, June 24, 1976, as amended by Amdt. 192-
29, 42 FR 42866, Aug. 25, 1977; Amdt. 192-29, 42 FR 60148, Nov. 25, 
1977; Amdt. 192-49, 50 FR 13225, Apr. 3, 1985; Amdt. 192-85, 63 FR 
37503, July 13, 1998]



Sec. 192.315  Wrinkle bends in steel pipe.

    (a) A wrinkle bend may not be made on steel pipe to be operated at a 
pressure that produces a hoop stress of 30 percent, or more, of SMYS.
    (b) Each wrinkle bend on steel pipe must comply with the following:
    (1) The bend must not have any sharp kinks.
    (2) When measured along the crotch of the bend, the wrinkles must be 
a distance of at least one pipe diameter.
    (3) On pipe 16 inches (406 millimeters) or larger in diameter, the 
bend may not have a deflection of more than 1\1/2\[deg] for each 
wrinkle.
    (4) On pipe containing a longitudinal weld the longitudinal seam 
must be as near as practicable to the neutral axis of the bend.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503, 
July 13, 1998]



Sec. 192.317  Protection from hazards.

    (a) The operator must take all practicable steps to protect each 
transmission line or main from washouts, floods, unstable soil, 
landslides, or other hazards that may cause the pipeline to move or to 
sustain abnormal loads. In addition, the operator must take all 
practicable steps to protect offshore pipelines from damage by mud 
slides, water currents, hurricanes, ship anchors, and fishing 
operations.
    (b) Each aboveground transmission line or main, not located offshore 
or in inland navigable water areas, must be protected from accidental 
damage by vehicular traffic or other similar causes, either by being 
placed at a safe distance from the traffic or by installing barricades.
    (c) Pipelines, including pipe risers, on each platform located 
offshore or in inland navigable waters must be protected from accidental 
damage by vessels.

[Amdt. 192-27, 41 FR 34606, Aug. 16, 1976, as amended by Amdt. 192-78, 
61 FR 28784, June 6, 1996]



Sec. 192.319  Installation of pipe in a ditch.

    (a) When installed in a ditch, each transmission line that is to be 
operated at a pressure producing a hoop stress of 20 percent or more of 
SMYS must be installed so that the pipe fits the ditch so as to minimize 
stresses and protect the pipe coating from damage.

[[Page 71]]

    (b) When a ditch for a transmission line or main is backfilled, it 
must be backfilled in a manner that:
    (1) Provides firm support under the pipe; and
    (2) Prevents damage to the pipe and pipe coating from equipment or 
from the backfill material.
    (c) All offshore pipe in water at least 12 feet (3.7 meters) deep 
but not more than 200 feet (61 meters) deep, as measured from the mean 
low tide, except pipe in the Gulf of Mexico and its inlets under 15 feet 
(4.6 meters) of water, must be installed so that the top of the pipe is 
below the natural bottom unless the pipe is supported by stanchions, 
held in place by anchors or heavy concrete coating, or protected by an 
equivalent means. Pipe in the Gulf of Mexico and its inlets under 15 
feet (4.6 meters) of water must be installed so that the top of the pipe 
is 36 inches (914 millimeters) below the seabed for normal excavation or 
18 inches (457 millimeters) for rock excavation.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34606, 
Aug. 16, 1976; Amdt. 192-78, 61 FR 28784, June 6, 1996; Amdt. 192-85, 63 
FR 37503, July 13, 1998]



Sec. 192.321  Installation of plastic pipe.

    (a) Plastic pipe must be installed below ground level except as 
provided by paragraphs (g) and (h) of this section.
    (b) Plastic pipe that is installed in a vault or any other below 
grade enclosure must be completely encased in gas-tight metal pipe and 
fittings that are adequately protected from corrosion.
    (c) Plastic pipe must be installed so as to minimize shear or 
tensile stresses.
    (d) Thermoplastic pipe that is not encased must have a minimum wall 
thickness of 0.090 inch (2.29 millimeters), except that pipe with an 
outside diameter of 0.875 inch (22.3 millimeters) or less may have a 
minimum wall thickness of 0.062 inch (1.58 millimeters).
    (e) Plastic pipe that is not encased must have an electrically 
conducting wire or other means of locating the pipe while it is 
underground. Tracer wire may not be wrapped around the pipe and contact 
with the pipe must be minimized but is not prohibited. Tracer wire or 
other metallic elements installed for pipe locating purposes must be 
resistant to corrosion damage, either by use of coated copper wire or by 
other means.
    (f) Plastic pipe that is being encased must be inserted into the 
casing pipe in a manner that will protect the plastic. The leading end 
of the plastic must be closed before insertion.
    (g) Uncased plastic pipe may be temporarily installed above ground 
level under the following conditions:
    (1) The operator must be able to demonstrate that the cumulative 
aboveground exposure of the pipe does not exceed the manufacturer's 
recommended maximum period of exposure or 2 years, whichever is less.
    (2) The pipe either is located where damage by external forces is 
unlikely or is otherwise protected against such damage.
    (3) The pipe adequately resists exposure to ultraviolet light and 
high and low temperatures.
    (h) Plastic pipe may be installed on bridges provided that it is:
    (1) Installed with protection from mechanical damage, such as 
installation in a metallic casing;
    (2) Protected from ultraviolet radiation; and
    (3) Not allowed to exceed the pipe temperature limits specified in 
Sec. 192.123.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-78, 61 FR 28784, 
June 6, 1996; Amdt. 192-85, 63 FR 37503, July 13, 1998; Amdt. 192-93, 68 
FR 53900, Sept. 15, 2003; Amdt. 192-94, 69 FR 32895, June 14, 2004]



Sec. 192.323  Casing.

    Each casing used on a transmission line or main under a railroad or 
highway must comply with the following:
    (a) The casing must be designed to withstand the superimposed loads.
    (b) If there is a possibility of water entering the casing, the ends 
must be sealed.
    (c) If the ends of an unvented casing are sealed and the sealing is 
strong enough to retain the maximum allowable operating pressure of the 
pipe, the casing must be designed to hold this pressure at a stress 
level of not more than 72 percent of SMYS.

[[Page 72]]

    (d) If vents are installed on a casing, the vents must be protected 
from the weather to prevent water from entering the casing.



Sec. 192.325  Underground clearance.

    (a) Each transmission line must be installed with at least 12 inches 
(305 millimeters) of clearance from any other underground structure not 
associated with the transmission line. If this clearance cannot be 
attained, the transmission line must be protected from damage that might 
result from the proximity of the other structure.
    (b) Each main must be installed with enough clearance from any other 
underground structure to allow proper maintenance and to protect against 
damage that might result from proximity to other structures.
    (c) In addition to meeting the requirements of paragraph (a) or (b) 
of this section, each plastic transmission line or main must be 
installed with sufficient clearance, or must be insulated, from any 
source of heat so as to prevent the heat from impairing the 
serviceability of the pipe.
    (d) Each pipe-type or bottle-type holder must be installed with a 
minimum clearance from any other holder as prescribed in Sec. 
192.175(b).

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503, 
July 13, 1998]



Sec. 192.327  Cover.

    (a) Except as provided in paragraphs (c), (e), (f), and (g) of this 
section, each buried transmission line must be installed with a minimum 
cover as follows:

------------------------------------------------------------------------
                                                  Normal    Consolidated
                   Location                        soil         rock
------------------------------------------------------------------------
Inches (Millimeters)..........................
Class 1 locations.............................    30 (762)     18 (457)
Class 2, 3, and 4 locations...................    36 (914)     24 (610)
Drainage ditches of public roads and railroad     36 (914)     24 (610)
 crossings....................................
------------------------------------------------------------------------

    (b) Except as provided in paragraphs (c) and (d) of this section, 
each buried main must be installed with at least 24 inches (610 
millimeters) of cover.
    (c) Where an underground structure prevents the installation of a 
transmission line or main with the minimum cover, the transmission line 
or main may be installed with less cover if it is provided with 
additional protection to withstand anticipated external loads.
    (d) A main may be installed with less than 24 inches (610 
millimeters) of cover if the law of the State or municipality:
    (1) Establishes a minimum cover of less than 24 inches (610 
millimeters);
    (2) Requires that mains be installed in a common trench with other 
utility lines; and
    (3) Provides adequately for prevention of damage to the pipe by 
external forces.
    (e) Except as provided in paragraph (c) of this section, all pipe 
installed in a navigable river, stream, or harbor must be installed with 
a minimum cover of 48 inches (1,219 millimeters) in soil or 24 inches 
(610 millimeters) in consolidated rock between the top of the pipe and 
the underwater natural bottom (as determined by recognized and generally 
accepted practices).
    (f) All pipe installed offshore, except in the Gulf of Mexico and 
its inlets, under water not more than 200 feet (60 meters) deep, as 
measured from the mean low tide, must be installed as follows:
    (1) Except as provided in paragraph (c) of this section, pipe under 
water less than 12 feet (3.66 meters) deep, must be installed with a 
minimum cover of 36 inches (914 millimeters) in soil or 18 inches (457 
millimeters) in consolidated rock between the top of the pipe and the 
natural bottom.
    (2) Pipe under water at least 12 feet (3.66 meters) deep must be 
installed so that the top of the pipe is below the natural bottom, 
unless the pipe is supported by stanchions, held in place by anchors or 
heavy concrete coating, or protected by an equivalent means.
    (g) All pipelines installed under water in the Gulf of Mexico and 
its inlets, as defined in Sec. 192.3, must be installed in accordance 
with Sec. 192.612(b)(3).

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27, 41 FR 34606, 
Aug. 16, 1976; Amdt. 192-78, 61 FR 28785, June 6, 1996; Amdt. 192-85, 63 
FR 37503, July 13, 1998; Amdt. 192-98, 69 FR 48406, Aug. 10, 2004]

[[Page 73]]



Sec. 192.328  Additional construction requirements for steel pipe using
alternative maximum allowable operating pressure.

    For a new or existing pipeline segment to be eligible for operation 
at the alternative maximum allowable operating pressure calculated under 
Sec. 192.620, a segment must meet the following additional construction 
requirements. Records must be maintained, for the useful life of the 
pipeline, demonstrating compliance with these requirements:

------------------------------------------------------------------------
   To address this construction      The pipeline segment must meet this
              issue:                additional construction requirement:
------------------------------------------------------------------------
 (a) Quality assurance............  (1) The construction of the pipeline
                                     segment must be done under a
                                     quality assurance plan addressing
                                     pipe inspection, hauling and
                                     stringing, field bending, welding,
                                     non-destructive examination of
                                     girth welds, applying and testing
                                     field applied coating, lowering of
                                     the pipeline into the ditch,
                                     padding and backfilling, and
                                     hydrostatic testing.
                                    (2) The quality assurance plan for
                                     applying and testing field applied
                                     coating to girth welds must be:
                                    (i) Equivalent to that required
                                     under Sec.  192.112(f)(3) for
                                     pipe; and
                                    (ii) Performed by an individual with
                                     the knowledge, skills, and ability
                                     to assure effective coating
                                     application.
 (b) Girth welds..................  (1) All girth welds on a new
                                     pipeline segment must be non-
                                     destructively examined in
                                     accordance with Sec.  192.243(b)
                                     and (c).
 (c) Depth of cover...............  (1) Notwithstanding any lesser depth
                                     of cover otherwise allowed in Sec.
                                      192.327, there must be at least 36
                                     inches (914 millimeters) of cover
                                     or equivalent means to protect the
                                     pipeline from outside force damage.
                                    (2) In areas where deep tilling or
                                     other activities could threaten the
                                     pipeline, the top of the pipeline
                                     must be installed at least one foot
                                     below the deepest expected
                                     penetration of the soil.
 (d) Initial strength testing.....  (1) The pipeline segment must not
                                     have experienced failures
                                     indicative of systemic material
                                     defects during strength testing,
                                     including initial hydrostatic
                                     testing. A root cause analysis,
                                     including metallurgical examination
                                     of the failed pipe, must be
                                     performed for any failure
                                     experienced to verify that it is
                                     not indicative of a systemic
                                     concern. The results of this root
                                     cause analysis must be reported to
                                     each PHMSA pipeline safety regional
                                     office where the pipe is in service
                                     at least 60 days prior to operating
                                     at the alternative MAOP. An
                                     operator must also notify a State
                                     pipeline safety authority when the
                                     pipeline is located in a State
                                     where PHMSA has an interstate agent
                                     agreement, or an intrastate
                                     pipeline is regulated by that
                                     State.
 (e) Interference currents........  (1) For a new pipeline segment, the
                                     construction must address the
                                     impacts of induced alternating
                                     current from parallel electric
                                     transmission lines and other known
                                     sources of potential interference
                                     with corrosion control.
------------------------------------------------------------------------


[72 FR 62176, Oct. 17, 2008]



    Subpart H_Customer Meters, Service Regulators, and Service Lines



Sec. 192.351  Scope.

    This subpart prescribes minimum requirements for installing customer 
meters, service regulators, service lines, service line valves, and 
service line connections to mains.



Sec. 192.353  Customer meters and regulators: Location.

    (a) Each meter and service regulator, whether inside or outside a 
building, must be installed in a readily accessible location and be 
protected from corrosion and other damage, including, if installed 
outside a building, vehicular damage that may be anticipated. However, 
the upstream regulator in a series may be buried.
    (b) Each service regulator installed within a building must be 
located as near as practical to the point of service line entrance.
    (c) Each meter installed within a building must be located in a 
ventilated place and not less than 3 feet (914 millimeters) from any 
source of ignition or any source of heat which might damage the meter.
    (d) Where feasible, the upstream regulator in a series must be 
located outside the building, unless it is located in a separate 
metering or regulating building.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt 192-85, 63 FR 37503, 
July 13, 1998; Amdt. 192-93, 68 FR 53900, Sept. 15, 2003]



Sec. 192.355  Customer meters and regulators: Protection from damage.

    (a) Protection from vacuum or back pressure. If the customer's 
equipment might create either a vacuum or a back

[[Page 74]]

pressure, a device must be installed to protect the system.
    (b) Service regulator vents and relief vents. Service regulator 
vents and relief vents must terminate outdoors, and the outdoor terminal 
must--
    (1) Be rain and insect resistant;
    (2) Be located at a place where gas from the vent can escape freely 
into the atmosphere and away from any opening into the building; and
    (3) Be protected from damage caused by submergence in areas where 
flooding may occur.
    (c) Pits and vaults. Each pit or vault that houses a customer meter 
or regulator at a place where vehicular traffic is anticipated, must be 
able to support that traffic.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR 1635, 
Jan. 21, 1988]



Sec. 192.357  Customer meters and regulators: Installation.

    (a) Each meter and each regulator must be installed so as to 
minimize anticipated stresses upon the connecting piping and the meter.
    (b) When close all-thread nipples are used, the wall thickness 
remaining after the threads are cut must meet the minimum wall thickness 
requirements of this part.
    (c) Connections made of lead or other easily damaged material may 
not be used in the installation of meters or regulators.
    (d) Each regulator that might release gas in its operation must be 
vented to the outside atmosphere.



Sec. 192.359  Customer meter installations: Operating pressure.

    (a) A meter may not be used at a pressure that is more than 67 
percent of the manufacturer's shell test pressure.
    (b) Each newly installed meter manufactured after November 12, 1970, 
must have been tested to a minimum of 10 p.s.i. (69 kPa) gage.
    (c) A rebuilt or repaired tinned steel case meter may not be used at 
a pressure that is more than 50 percent of the pressure used to test the 
meter after rebuilding or repairing.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-1, 35 FR 17660, 
Nov. 17, 1970; Amdt. 192-85, 63 FR 37503, July 13, 1998]



Sec. 192.361  Service lines: Installation.

    (a) Depth. Each buried service line must be installed with at least 
12 inches (305 millimeters) of cover in private property and at least 18 
inches (457 millimeters) of cover in streets and roads. However, where 
an underground structure prevents installation at those depths, the 
service line must be able to withstand any anticipated external load.
    (b) Support and backfill. Each service line must be properly 
supported on undisturbed or well-compacted soil, and material used for 
backfill must be free of materials that could damage the pipe or its 
coating.
    (c) Grading for drainage. Where condensate in the gas might cause 
interruption in the gas supply to the customer, the service line must be 
graded so as to drain into the main or into drips at the low points in 
the service line.
    (d) Protection against piping strain and external loading. Each 
service line must be installed so as to minimize anticipated piping 
strain and external loading.
    (e) Installation of service lines into buildings. Each underground 
service line installed below grade through the outer foundation wall of 
a building must:
    (1) In the case of a metal service line, be protected against 
corrosion;
    (2) In the case of a plastic service line, be protected from 
shearing action and backfill settlement; and
    (3) Be sealed at the foundation wall to prevent leakage into the 
building.
    (f) Installation of service lines under buildings. Where an 
underground service line is installed under a building:
    (1) It must be encased in a gas tight conduit;
    (2) The conduit and the service line must, if the service line 
supplies the building it underlies, extend into a normally usable and 
accessible part of the building; and
    (3) The space between the conduit and the service line must be 
sealed to prevent gas leakage into the building and, if the conduit is 
sealed at both ends, a vent line from the annular space must extend to a 
point where gas would not be a hazard, and extend

[[Page 75]]

above grade, terminating in a rain and insect resistant fitting.
    (g) Locating underground service lines. Each underground nonmetallic 
service line that is not encased must have a means of locating the pipe 
that complies with Sec. 192.321(e).

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-75, 61 FR 18517, 
Apr. 26, 1996; Amdt. 192-85, 63 FR 37503, July 13, 1998; Amdt. 192-93, 
68 FR 53900, Sept. 15, 2003]



Sec. 192.363  Service lines: Valve requirements.

    (a) Each service line must have a service-line valve that meets the 
applicable requirements of subparts B and D of this part. A valve 
incorporated in a meter bar, that allows the meter to be bypassed, may 
not be used as a service-line valve.
    (b) A soft seat service line valve may not be used if its ability to 
control the flow of gas could be adversely affected by exposure to 
anticipated heat.
    (c) Each service-line valve on a high-pressure service line, 
installed above ground or in an area where the blowing of gas would be 
hazardous, must be designed and constructed to minimize the possibility 
of the removal of the core of the valve with other than specialized 
tools.



Sec. 192.365  Service lines: Location of valves.

    (a) Relation to regulator or meter. Each service-line valve must be 
installed upstream of the regulator or, if there is no regulator, 
upstream of the meter.
    (b) Outside valves. Each service line must have a shut-off valve in 
a readily accessible location that, if feasible, is outside of the 
building.
    (c) Underground valves. Each underground service-line valve must be 
located in a covered durable curb box or standpipe that allows ready 
operation of the valve and is supported independently of the service 
lines.



Sec. 192.367  Service lines: General requirements for connections to main
piping.

    (a) Location. Each service line connection to a main must be located 
at the top of the main or, if that is not practical, at the side of the 
main, unless a suitable protective device is installed to minimize the 
possibility of dust and moisture being carried from the main into the 
service line.
    (b) Compression-type connection to main. Each compression-type 
service line to main connection must:
    (1) Be designed and installed to effectively sustain the 
longitudinal pull-out or thrust forces caused by contraction or 
expansion of the piping, or by anticipated external or internal loading; 
and
    (2) If gaskets are used in connecting the service line to the main 
connection fitting, have gaskets that are compatible with the kind of 
gas in the system.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-75, 61 FR 18517, 
Apr. 26, 1996]



Sec. 192.369  Service lines: Connections to cast iron or ductile iron mains.

    (a) Each service line connected to a cast iron or ductile iron main 
must be connected by a mechanical clamp, by drilling and tapping the 
main, or by another method meeting the requirements of Sec. 192.273.
    (b) If a threaded tap is being inserted, the requirements of Sec. 
192.151 (b) and (c) must also be met.



Sec. 192.371  Service lines: Steel.

    Each steel service line to be operated at less than 100 p.s.i. (689 
kPa) gage must be constructed of pipe designed for a minimum of 100 
p.s.i. (689 kPa) gage.

[Amdt. 192-1, 35 FR 17660, Nov. 17, 1970, as amended by Amdt. 192-85, 63 
FR 37503, July 13, 1998]



Sec. 192.373  Service lines: Cast iron and ductile iron.

    (a) Cast or ductile iron pipe less than 6 inches (152 millimeters) 
in diameter may not be installed for service lines.
    (b) If cast iron pipe or ductile iron pipe is installed for use as a 
service line, the part of the service line which extends through the 
building wall must be of steel pipe.
    (c) A cast iron or ductile iron service line may not be installed in 
unstable soil or under a building.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37503, 
July 13, 1998]

[[Page 76]]



Sec. 192.375  Service lines: Plastic.

    (a) Each plastic service line outside a building must be installed 
below ground level, except that--
    (1) It may be installed in accordance with Sec. 192.321(g); and
    (2) It may terminate above ground level and outside the building, 
if--
    (i) The above ground level part of the plastic service line is 
protected against deterioration and external damage; and
    (ii) The plastic service line is not used to support external loads.
    (b) Each plastic service line inside a building must be protected 
against external damage.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-78, 61 FR 28785, 
June 6, 1996]



Sec. 192.377  Service lines: Copper.

    Each copper service line installed within a building must be 
protected against external damage.



Sec. 192.379  New service lines not in use.

    Each service line that is not placed in service upon completion of 
installation must comply with one of the following until the customer is 
supplied with gas:
    (a) The valve that is closed to prevent the flow of gas to the 
customer must be provided with a locking device or other means designed 
to prevent the opening of the valve by persons other than those 
authorized by the operator.
    (b) A mechanical device or fitting that will prevent the flow of gas 
must be installed in the service line or in the meter assembly.
    (c) The customer's piping must be physically disconnected from the 
gas supply and the open pipe ends sealed.

[Amdt. 192-8, 37 FR 20694, Oct. 3, 1972]



Sec. 192.381  Service lines: Excess flow valve performance standards.

    (a) Excess flow valves to be used on single residence service lines 
that operate continuously throughout the year at a pressure not less 
than 10 p.s.i. (69 kPa) gage must be manufactured and tested by the 
manufacturer according to an industry specification, or the 
manufacturer's written specification, to ensure that each valve will:
    (1) Function properly up to the maximum operating pressure at which 
the valve is rated;
    (2) Function properly at all temperatures reasonably expected in the 
operating environment of the service line;
    (3) At 10 p.s.i. (69 kPa) gage:
    (i) Close at, or not more than 50 percent above, the rated closure 
flow rate specified by the manufacturer; and
    (ii) Upon closure, reduce gas flow--
    (A) For an excess flow valve designed to allow pressure to equalize 
across the valve, to no more than 5 percent of the manufacturer's 
specified closure flow rate, up to a maximum of 20 cubic feet per hour 
(0.57 cubic meters per hour); or
    (B) For an excess flow valve designed to prevent equalization of 
pressure across the valve, to no more than 0.4 cubic feet per hour (.01 
cubic meters per hour); and
    (4) Not close when the pressure is less than the manufacturer's 
minimum specified operating pressure and the flow rate is below the 
manufacturer's minimum specified closure flow rate.
    (b) An excess flow valve must meet the applicable requirements of 
Subparts B and D of this part.
    (c) An operator must mark or otherwise identify the presence of an 
excess flow valve in the service line.
    (d) An operator shall locate an excess flow valve as near as 
practical to the fitting connecting the service line to its source of 
gas supply.
    (e) An operator should not install an excess flow valve on a service 
line where the operator has prior experience with contaminants in the 
gas stream, where these contaminants could be expected to cause the 
excess flow valve to malfunction or where the excess flow valve would 
interfere with necessary operation and maintenance activities on the 
service, such as blowing liquids from the line.

[Amdt. 192-79, 61 FR 31459, June 20, 1996, as amended by Amdt. 192-80, 
62 FR 2619, Jan. 17, 1997; Amdt. 192-85, 63 FR 37504, July 13, 1998]



Sec. 192.383  Excess flow valve customer notification.

    (a) Definitions. As used in this section:
    Costs associated with installation means the costs directly 
connected

[[Page 77]]

with installing an excess flow valve, for example, costs of parts, 
labor, inventory and procurement. It does not include maintenance and 
replacement costs until such costs are incurred.
    Replaced service line means a natural gas service line where the 
fitting that connects the service line to the main is replaced or the 
piping connected to this fitting is replaced.
    Service line customer means the person who pays the gas bill, or 
where service has not yet been established, the person requesting 
service.
    (b) Which customers must receive notification. Notification is 
required on each newly installed service line or replaced service line 
that operates continuously throughout the year at a pressure not less 
than 68.9 kPa (10 psig) and that serves a single residence. On these 
lines an operator of a natural gas distribution system must notify the 
service line customer once in writing.
    (c) What to put in the written notice. (1) An explanation for the 
customer that an excess flow valve meeting the performance standards 
prescribed under Sec. 192.381 is available for the operator to install 
if the customer bears the costs associated with installation;
    (2) An explanation for the customer of the potential safety benefits 
that may be derived from installing an excess flow valve. The 
explanation must include that an excess flow valve is designed to shut 
off flow of natural gas automatically if the service line breaks;
    (3) A description of installation, maintenance, and replacement 
costs. The notice must explain that if the customer requests the 
operator to install an EFV, the customer bears all costs associated with 
installation, and what those costs are. The notice must alert the 
customer that the costs for maintaining and replacing an EFV may later 
be incurred, and what those costs will be, to the extent known.
    (d) When notification and installation must be made. (1) After 
February 3, 1999 an operator must notify each service line customer set 
forth in paragraph (b) of this section:
    (i) On new service lines when the customer applies for service.
    (ii) On replaced service lines when the operator determines the 
service line will be replaced.
    (2) If a service line customer requests installation an operator 
must install the EFV at a mutually agreeable date.
    (e) What records are required. (1) An operator must make the 
following records available for inspection by the Administrator or a 
State agency participating under 49 U.S.C. 60105 or 60106:
    (i) A copy of the notice currently in use; and
    (ii) Evidence that notice has been sent to the service line 
customers set forth in paragraph (b) of this section, within the 
previous three years.
    (2) [Reserved]
    (f) When notification is not required. The notification requirements 
do not apply if the operator can demonstrate--
    (1) That the operator will voluntarily install an excess flow valve 
or that the state or local jurisdiction requires installation;
    (2) That excess flow valves meeting the performance standards in 
Sec. 192.381 are not available to the operator;
    (3) That the operator has prior experience with contaminants in the 
gas stream that could interfere with the operation of an excess flow 
valve, cause loss of service to a residence, or interfere with necessary 
operation or maintenance activities, such as blowing liquids from the 
line.
    (4) That an emergency or short time notice replacement situation 
made it impractical for the operator to notify a service line customer 
before replacing a service line. Examples of these situations would be 
where an operator has to replace a service line quickly because of--
    (i) Third party excavation damage;
    (ii) Grade 1 leaks as defined in the Appendix G-192-11 of the Gas 
Piping Technology Committee guide for gas transmission and distribution 
systems;
    (iii) A short notice service line relocation request.

[Amdt.192-82, 63 FR 5471, Feb. 3, 1998; Amdt. 192-83, 63 FR 20135, Apr. 
23, 1998]

[[Page 78]]



              Subpart I_Requirements for Corrosion Control

    Source: Amdt. 192-4, 36 FR 12302, June 30, 1971, unless otherwise 
noted.



Sec. 192.451  Scope.

    (a) This subpart prescribes minimum requirements for the protection 
of metallic pipelines from external, internal, and atmospheric 
corrosion.
    (b) [Reserved]

[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-27, 41 
FR 34606, Aug. 16, 1976; Amdt. 192-33, 43 FR 39389, Sept. 5, 1978]



Sec. 192.452  How does this subpart apply to converted pipelines and 
regulated onshore gathering lines?

    (a) Converted pipelines. Notwithstanding the date the pipeline was 
installed or any earlier deadlines for compliance, each pipeline which 
qualifies for use under this part in accordance with Sec. 192.14 must 
meet the requirements of this subpart specifically applicable to 
pipelines installed before August 1, 1971, and all other applicable 
requirements within 1 year after the pipeline is readied for service. 
However, the requirements of this subpart specifically applicable to 
pipelines installed after July 31, 1971, apply if the pipeline 
substantially meets those requirements before it is readied for service 
or it is a segment which is replaced, relocated, or substantially 
altered.
    (b) Regulated onshore gathering lines. For any regulated onshore 
gathering line under Sec. 192.9 existing on April 14, 2006, that was 
not previously subject to this part, and for any onshore gathering line 
that becomes a regulated onshore gathering line under Sec. 192.9 after 
April 14, 2006, because of a change in class location or increase in 
dwelling density:
    (1) The requirements of this subpart specifically applicable to 
pipelines installed before August 1, 1971, apply to the gathering line 
regardless of the date the pipeline was actually installed; and
    (2) The requirements of this subpart specifically applicable to 
pipelines installed after July 31, 1971, apply only if the pipeline 
substantially meets those requirements.

[Amdt. 192-30, 42 FR 60148, Nov. 25, 1977, as amended by Amdt. 192-102, 
71 FR 13303, Mar. 15, 2006]



Sec. 192.453  General.

    The corrosion control procedures required by Sec. 192.605(b)(2), 
including those for the design, installation, operation, and maintenance 
of cathodic protection systems, must be carried out by, or under the 
direction of, a person qualified in pipeline corrosion control methods.

[Amdt. 192-71, 59 FR 6584, Feb. 11, 1994]



Sec. 192.455  External corrosion control: Buried or submerged pipelines 
installed after July 31, 1971.

    (a) Except as provided in paragraphs (b), (c), and (f) of this 
section, each buried or submerged pipeline installed after July 31, 
1971, must be protected against external corrosion, including the 
following:
    (1) It must have an external protective coating meeting the 
requirements of Sec. 192.461.
    (2) It must have a cathodic protection system designed to protect 
the pipeline in accordance with this subpart, installed and placed in 
operation within 1 year after completion of construction.
    (b) An operator need not comply with paragraph (a) of this section, 
if the operator can demonstrate by tests, investigation, or experience 
in the area of application, including, as a minimum, soil resistivity 
measurements and tests for corrosion accelerating bacteria, that a 
corrosive environment does not exist. However, within 6 months after an 
installation made pursuant to the preceding sentence, the operator shall 
conduct tests, including pipe-to-soil potential measurements with 
respect to either a continuous reference electrode or an electrode using 
close spacing, not to exceed 20 feet (6 meters), and soil resistivity 
measurements at potential profile peak locations, to adequately evaluate 
the potential profile along the entire pipeline. If the tests made 
indicate that a corrosive condition exists, the pipeline must be 
cathodically protected in accordance with paragraph (a)(2) of this 
section.

[[Page 79]]

    (c) An operator need not comply with paragraph (a) of this section, 
if the operator can demonstrate by tests, investigation, or experience 
that--
    (1) For a copper pipeline, a corrosive environment does not exist; 
or
    (2) For a temporary pipeline with an operating period of service not 
to exceed 5 years beyond installation, corrosion during the 5-year 
period of service of the pipeline will not be detrimental to public 
safety.
    (d) Notwithstanding the provisions of paragraph (b) or (c) of this 
section, if a pipeline is externally coated, it must be cathodically 
protected in accordance with paragraph (a)(2) of this section.
    (e) Aluminum may not be installed in a buried or submerged pipeline 
if that aluminum is exposed to an environment with a natural pH in 
excess of 8, unless tests or experience indicate its suitability in the 
particular environment involved.
    (f) This section does not apply to electrically isolated, metal 
alloy fittings in plastic pipelines, if:
    (1) For the size fitting to be used, an operator can show by test, 
investigation, or experience in the area of application that adequate 
corrosion control is provided by the alloy composition; and
    (2) The fitting is designed to prevent leakage caused by localized 
corrosion pitting.

[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended at Amdt. 192-28, 42 
FR 35654, July 11, 1977; Amdt. 192-39, 47 FR 9844, Mar. 8, 1982; Amdt. 
192-78, 61 FR 28785, June 6, 1996; Amdt. 192-85, 63 FR 37504, July 13, 
1998]



Sec. 192.457  External corrosion control: Buried or submerged pipelines
installed before August 1, 1971.

    (a) Except for buried piping at compressor, regulator, and measuring 
stations, each buried or submerged transmission line installed before 
August 1, 1971, that has an effective external coating must be 
cathodically protected along the entire area that is effectively coated, 
in accordance with this subpart. For the purposes of this subpart, a 
pipeline does not have an effective external coating if its cathodic 
protection current requirements are substantially the same as if it were 
bare. The operator shall make tests to determine the cathodic protection 
current requirements.
    (b) Except for cast iron or ductile iron, each of the following 
buried or submerged pipelines installed before August 1, 1971, must be 
cathodically protected in accordance with this subpart in areas in which 
active corrosion is found:
    (1) Bare or ineffectively coated transmission lines.
    (2) Bare or coated pipes at compressor, regulator, and measuring 
stations.
    (3) Bare or coated distribution lines.

[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-33, 43 
FR 39390, Sept. 5, 1978; Amdt. 192-93, 68 FR 53900, Sept. 15, 2003]



Sec. 192.459  External corrosion control: Examination of buried pipeline
when exposed.

    Whenever an operator has knowledge that any portion of a buried 
pipeline is exposed, the exposed portion must be examined for evidence 
of external corrosion if the pipe is bare, or if the coating is 
deteriorated. If external corrosion requiring remedial action under 
Sec. Sec. 192.483 through 192.489 is found, the operator shall 
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. 192-87, 64 FR 56981, Oct. 22, 1999]



Sec. 192.461  External corrosion control: Protective coating.

    (a) Each external protective coating, whether conductive or 
insulating, applied for the purpose of external corrosion control must--
    (1) Be applied on a properly prepared surface;
    (2) Have sufficient adhesion to the metal surface to effectively 
resist underfilm migration of moisture;
    (3) Be sufficiently ductile to resist cracking;
    (4) Have sufficient strength to resist damage due to handling and 
soil stress; and
    (5) Have properties compatible with any supplemental cathodic 
protection.

[[Page 80]]

    (b) Each external protective coating which is an electrically 
insulating type must also have low moisture absorption and high 
electrical resistance.
    (c) Each external protective coating must be inspected just prior to 
lowering the pipe into the ditch and backfilling, and any damage 
detrimental to effective corrosion control must be repaired.
    (d) Each external protective coating must be protected from damage 
resulting from adverse ditch conditions or damage from supporting 
blocks.
    (e) If coated pipe is installed by boring, driving, or other similar 
method, precautions must be taken to minimize damage to the coating 
during installation.



Sec. 192.463  External corrosion control: Cathodic protection.

    (a) Each cathodic protection system required by this subpart must 
provide a level of cathodic protection that complies with one or more of 
the applicable criteria contained in appendix D of this part. If none of 
these criteria is applicable, the cathodic protection system must 
provide a level of cathodic protection at least equal to that provided 
by compliance with one or more of these criteria.
    (b) If amphoteric metals are included in a buried or submerged 
pipeline containing a metal of different anodic potential--
    (1) The amphoteric metals must be electrically isolated from the 
remainder of the pipeline and cathodically protected; or
    (2) The entire buried or submerged pipeline must be cathodically 
protected at a cathodic potential that meets the requirements of 
appendix D of this part for amphoteric metals.
    (c) The amount of cathodic protection must be controlled so as not 
to damage the protective coating or the pipe.



Sec. 192.465  External corrosion control: Monitoring.

    (a) Each pipeline that is under cathodic protection must be tested 
at least once each calendar year, but with intervals not exceeding 15 
months, to determine whether the cathodic protection meets the 
requirements of Sec. 192.463. However, if tests at those intervals are 
impractical for separately protected short sections of mains or 
transmission lines, not in excess of 100 feet (30 meters), or separately 
protected service lines, these pipelines may be surveyed on a sampling 
basis. At least 10 percent of these protected structures, distributed 
over the entire system must be surveyed each calendar year, with a 
different 10 percent checked each subsequent year, so that the entire 
system is tested in each 10-year period.
    (b) Each cathodic protection rectifier or other impressed current 
power source must be inspected six times each calendar year, but with 
intervals not exceeding 2\1/2\ months, to insure that it is operating.
    (c) Each reverse current switch, each diode, and each interference 
bond whose failure would jeopardize structure protection must be 
electrically checked for proper performance six times each calendar 
year, but with intervals not exceeding 2\1/2\ months. Each other 
interference bond must be checked at least once each calendar year, but 
with intervals not exceeding 15 months.
    (d) Each operator shall take prompt remedial action to correct any 
deficiencies indicated by the monitoring.
    (e) After the initial evaluation required by Sec. Sec. 192.455(b) 
and (c) and 192.457(b), each operator must, not less than every 3 years 
at intervals not exceeding 39 months, reevaluate its unprotected 
pipelines and cathodically protect them in accordance with this subpart 
in areas in which active corrosion is found. The operator must determine 
the areas of active corrosion by electrical survey. However, on 
distribution lines and where an electrical survey is impractical on 
transmission lines, areas of active corrosion may be determined 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. In this section:
    (1) Active corrosion means continuing corrosion which, unless 
controlled, could result in a condition that is detrimental to public 
safety.

[[Page 81]]

    (2) 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.
    (3) 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.

[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-33, 43 
FR 39390, Sept. 5, 1978; Amdt. 192-35A, 45 FR 23441, Apr. 7, 1980; Amdt. 
192-85, 63 FR 37504, July 13, 1998; Amdt. 192-93, 68 FR 53900, Sept. 15, 
2003]



Sec. 192.467  External corrosion control: Electrical isolation.

    (a) Each buried or submerged pipeline must be electrically isolated 
from other underground metallic structures, unless the pipeline and the 
other structures are electrically interconnected and cathodically 
protected as a single unit.
    (b) One or more insulating devices must be installed where 
electrical isolation of a portion of a pipeline is necessary to 
facilitate the application of corrosion control.
    (c) Except for unprotected copper inserted in ferrous pipe, each 
pipeline must be electrically isolated from metallic casings that are a 
part of the underground system. However, if isolation is not achieved 
because it is impractical, other measures must be taken to minimize 
corrosion of the pipeline inside the casing.
    (d) Inspection and electrical tests must be made to assure that 
electrical isolation is adequate.
    (e) An insulating device may not be installed in an area where a 
combustible atmosphere is anticipated unless precautions are taken to 
prevent arcing.
    (f) Where a pipeline is located in close proximity to electrical 
transmission tower footings, ground cables or counterpoise, or in other 
areas where fault currents or unusual risk of lightning may be 
anticipated, it must be provided with protection against damage due to 
fault currents or lightning, and protective measures must also be taken 
at insulating devices.

[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-33, 43 
FR 39390, Sept. 5, 1978]



Sec. 192.469  External corrosion control: Test stations.

    Each pipeline under cathodic protection required by this subpart 
must have sufficient test stations or other contact points for 
electrical measurement to determine the adequacy of cathodic protection.

[Amdt. 192-27, 41 FR 34606, Aug. 16, 1976]



Sec. 192.471  External corrosion control: Test leads.

    (a) Each test lead wire must be connected to the pipeline so as to 
remain mechanically secure and electrically conductive.
    (b) Each test lead wire must be attached to the pipeline so as to 
minimize stress concentration on the pipe.
    (c) Each bared test lead wire and bared metallic area at point of 
connection to the pipeline must be coated with an electrical insulating 
material compatible with the pipe coating and the insulation on the 
wire.



Sec. 192.473  External corrosion control: Interference currents.

    (a) Each operator whose pipeline system is subjected to stray 
currents shall have in effect a continuing program to minimize the 
detrimental effects of such currents.
    (b) Each impressed current type cathodic protection system or 
galvanic anode system must be designed and installed so as to minimize 
any adverse effects on existing adjacent underground metallic 
structures.

[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-33, 43 
FR 39390, Sept. 5, 1978]



Sec. 192.475  Internal corrosion control: General.

    (a) Corrosive gas may not be transported by pipeline, unless the 
corrosive effect of the gas on the pipeline has been investigated and 
steps have been taken to minimize internal corrosion.

[[Page 82]]

    (b) Whenever any pipe is removed from a pipeline for any reason, the 
internal surface must be inspected for evidence of corrosion. If 
internal corrosion is found--
    (1) The adjacent pipe must be investigated to determine the extent 
of internal corrosion;
    (2) Replacement must be made to the extent required by the 
applicable paragraphs of Sec. Sec. 192.485, 192.487, or 192.489; and
    (3) Steps must be taken to minimize the internal corrosion.
    (c) Gas containing more than 0.25 grain of hydrogen sulfide per 100 
cubic feet (5.8 milligrams/m\.3\) at standard conditions (4 parts per 
million) may not be stored in pipe-type or bottle-type holders.

[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-33, 43 
FR 39390, Sept. 5, 1978; Amdt. 192-78, 61 FR 28785, June 6, 1996; Amdt. 
192-85, 63 FR 37504, July 13, 1998]



Sec. 192.476  Internal corrosion control: Design and construction of
transmission line.

    (a) Design and construction. Except as provided in paragraph (b) of 
this section, each new transmission line and each replacement of line 
pipe, valve, fitting, or other line component in a transmission line 
must have features incorporated into its design and construction to 
reduce the risk of internal corrosion. At a minimum, unless it is 
impracticable or unnecessary to do so, each new transmission line or 
replacement of line pipe, valve, fitting, or other line component in a 
transmission line must:
    (1) Be configured to reduce the risk that liquids will collect in 
the line;
    (2) Have effective liquid removal features whenever the 
configuration would allow liquids to collect; and
    (3) Allow use of devices for monitoring internal corrosion at 
locations with significant potential for internal corrosion.
    (b) Exceptions to applicability. The design and construction 
requirements of paragraph (a) of this section do not apply to the 
following:
    (1) Offshore pipeline; and
    (2) Pipeline installed or line pipe, valve, fitting or other line 
component replaced before May 23, 2007.
    (c) Change to existing transmission line. When an operator changes 
the configuration of a transmission line, the operator must evaluate the 
impact of the change on internal corrosion risk to the downstream 
portion of an existing onshore transmission line and provide for removal 
of liquids and monitoring of internal corrosion as appropriate.
    (d) Records. An operator must maintain records demonstrating 
compliance with this section. Provided the records show why 
incorporating design features addressing paragraph (a)(1), (a)(2), or 
(a)(3) of this section is impracticable or unnecessary, an operator may 
fulfill this requirement through written procedures supported by as-
built drawings or other construction records.

[72 FR 20059, Apr. 23, 2007]



Sec. 192.477  Internal corrosion control: Monitoring.

    If corrosive gas is being transported, coupons or other suitable 
means must be used to determine the effectiveness of the steps taken to 
minimize internal corrosion. Each coupon or other means of monitoring 
internal corrosion must be checked two times each calendar year, but 
with intervals not exceeding 7\1/2\ months.

[Amdt. 192-33, 43 FR 39390, Sept. 5, 1978]



Sec. 192.479  Atmospheric corrosion control: General.

    (a) Each operator 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, the operator need not protect from atmospheric 
corrosion any pipeline for which the operator demonstrates by test, 
investigation, or experience appropriate to the environment of the 
pipeline that corrosion will--
    (1) Only be a light surface oxide; or

[[Page 83]]

    (2) Not affect the safe operation of the pipeline before the next 
scheduled inspection.

[Amdt. 192-93, 68 FR 53901, Sept. 15, 2003]



Sec. 192.481  Atmospheric corrosion control: Monitoring.

    (a) Each operator must inspect each pipeline or portion of pipeline 
that is exposed to the atmosphere for evidence of atmospheric corrosion, 
as follows:

------------------------------------------------------------------------
                                              Then the frequency of
      If the pipeline is located:                 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 the operator 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 atmospheric corrosion is found during an inspection, the 
operator must provide protection against the corrosion as required by 
Sec. 192.479.

[Amdt. 192-93, 68 FR 53901, Sept. 15, 2003]



Sec. 192.483  Remedial measures: General.

    (a) Each segment of metallic pipe that replaces pipe removed from a 
buried or submerged pipeline because of external corrosion must have a 
properly prepared surface and must be provided with an external 
protective coating that meets the requirements of Sec. 192.461.
    (b) Each segment of metallic pipe that replaces pipe removed from a 
buried or submerged pipeline because of external corrosion must be 
cathodically protected in accordance with this subpart.
    (c) Except for cast iron or ductile iron pipe, each segment of 
buried or submerged pipe that is required to be repaired because of 
external corrosion must be cathodically protected in accordance with 
this subpart.



Sec. 192.485  Remedial measures: Transmission lines.

    (a) General corrosion. Each segment of transmission line with 
general corrosion and with a remaining wall thickness less than that 
required for the MAOP of the pipeline must be replaced or the operating 
pressure reduced commensurate with the strength of the pipe based on 
actual remaining wall thickness. However, corroded pipe may be repaired 
by a method that reliable engineering tests and analyses show can 
permanently restore the serviceability of the pipe. Corrosion pitting so 
closely grouped as to affect the overall strength of the pipe is 
considered general corrosion for the purpose of this paragraph.
    (b) Localized corrosion pitting. Each segment of transmission line 
pipe with localized corrosion pitting to a degree where leakage might 
result must be replaced or repaired, or the operating pressure must be 
reduced commensurate with the strength of the pipe, based on the actual 
remaining wall thickness in the pits.
    (c) Under paragraphs (a) and (b) of this section, the strength of 
pipe based on actual remaining wall thickness may be determined by the 
procedure in ASME/ANSI B31G or the procedure in AGA Pipeline Research 
Committee Project PR 3-805 (with RSTRENG disk). Both procedures apply to 
corroded regions that do not penetrate the pipe wall, subject to the 
limitations prescribed in the procedures.

[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-33, 43 
FR 39390, Sept. 5, 1978; Amdt. 192-78, 61 FR 28785, June 6, 1996; Amdt. 
192-88, 64 FR 69664, Dec. 14, 1999]



Sec. 192.487  Remedial measures: Distribution lines other than cast iron
or ductile iron lines.

    (a) General corrosion. Except for cast iron or ductile iron pipe, 
each segment of generally corroded distribution line pipe with a 
remaining wall thickness less than that required for the MAOP of the 
pipeline, or a remaining wall thickness less than 30 percent of the 
nominal wall thickness, must be replaced. However, corroded pipe may be 
repaired by a method that reliable engineering tests and analyses show 
can permanently restore the serviceability of the pipe. Corrosion 
pitting so closely grouped as to affect the overall

[[Page 84]]

strength of the pipe is considered general corrosion for the purpose of 
this paragraph.
    (b) Localized corrosion pitting. Except for cast iron or ductile 
iron pipe, each segment of distribution line pipe with localized 
corrosion pitting to a degree where leakage might result must be 
replaced or repaired.

[Amdt. 192-4, 36 FR 12302, June 30, 1971, as amended by Amdt. 192-88, 64 
FR 69665, Dec. 14, 1999]



Sec. 192.489  Remedial measures: Cast iron and ductile iron pipelines.

    (a) General graphitization. Each segment of cast iron or ductile 
iron pipe on which general graphitization is found to a degree where a 
fracture or any leakage might result, must be replaced.
    (b) Localized graphitization. Each segment of cast iron or ductile 
iron pipe on which localized graphitization is found to a degree where 
any leakage might result, must be replaced or repaired, or sealed by 
internal sealing methods adequate to prevent or arrest any leakage.



Sec. 192.490  Direct assessment.

    Each operator that uses direct assessment as defined in Sec. 
192.903 on an onshore transmission line made primarily of steel or iron 
to evaluate the effects of a threat in the first column must carry out 
the direct assessment according to the standard listed in the second 
column. These standards do 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.

------------------------------------------------------------------------
                  Threat                            Standard \1\
------------------------------------------------------------------------
External corrosion.......................  Sec.  192.925 \2\
Internal corrosion in pipelines that       Sec.  192.927
 transport dry gas.
Stress corrosion cracking................  Sec.  192.929
------------------------------------------------------------------------
\1\ For lines not subject to subpart O of this part, the terms ``covered
  segment'' and ``covered pipeline segment'' in Sec. Sec.  192.925,
  192.927, and 192.929 refer to the pipeline segment on which direct
  assessment is performed.
\2\ In Sec.  192.925(b), the provision regarding detection of coating
  damage applies only to pipelines subject to subpart O of this part.


[Amdt. 192-101, 70 FR 61575, Oct. 25, 2005]



Sec. 192.491  Corrosion control records.

    (a) Each operator shall maintain records or maps to show the 
location of cathodically protected piping, cathodic protection 
facilities, galvanic anodes, and neighboring structures bonded to the 
cathodic protection system. 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.
    (b) Each record or map required by paragraph (a) of this section 
must be retained for as long as the pipeline remains in service.
    (c) Each operator shall maintain a record of each test, survey, or 
inspection required by this subpart in sufficient detail to demonstrate 
the adequacy of corrosion control measures or that a corrosive condition 
does not exist. These records must be retained for at least 5 years, 
except that records related to Sec. Sec. 192.465 (a) and (e) and 
192.475(b) must be retained for as long as the pipeline remains in 
service.

[Amdt. 192-78, 61 FR 28785, June 6, 1996]



                       Subpart J_Test Requirements



Sec. 192.501  Scope.

    This subpart prescribes minimum leak-test and strength-test 
requirements for pipelines.



Sec. 192.503  General requirements.

    (a) No person may operate a new segment of pipeline, or return to 
service a segment of pipeline that has been relocated or replaced, 
until--
    (1) It has been tested in accordance with this subpart and Sec. 
192.619 to substantiate the maximum allowable operating pressure; and
    (2) Each potentially hazardous leak has been located and eliminated.
    (b) The test medium must be liquid, air, natural gas, or inert gas 
that is--
    (1) Compatible with the material of which the pipeline is 
constructed;
    (2) Relatively free of sedimentary materials; and
    (3) Except for natural gas, nonflammable.
    (c) Except as provided in Sec. 192.505(a), if air, natural gas, or 
inert gas is used as the test medium, the following maximum hoop stress 
limitations apply:

[[Page 85]]



------------------------------------------------------------------------
                                       Maximum hoop stress allowed as
                                             percentage of SMYS
          Class location           -------------------------------------
                                       Natural gas      Air or inert gas
------------------------------------------------------------------------
1.................................         80                 80
2.................................         30                 75
3.................................         30                 50
4.................................         30                 40
------------------------------------------------------------------------

    (d) Each joint used to tie in a test segment of pipeline is excepted 
from the specific test requirements of this subpart, but each non-welded 
joint must be leak tested at not less than its operating pressure.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR 1635, 
Jan. 21, 1988; Amdt. 192-60, 53 FR 36029, Sept. 16, 1988; Amdt. 192-60A, 
54 FR 5485, Feb. 3, 1989]



Sec. 192.505  Strength test requirements for steel pipeline to operate 
at a hoop stress of 30 percent or more of SMYS.

    (a) Except for service lines, each segment of a steel pipeline that 
is to operate at a hoop stress of 30 percent or more of SMYS must be 
strength tested in accordance with this section to substantiate the 
proposed maximum allowable operating pressure. In addition, in a Class 1 
or Class 2 location, if there is a building intended for human occupancy 
within 300 feet (91 meters) of a pipeline, a hydrostatic test must be 
conducted to a test pressure of at least 125 percent of maximum 
operating pressure on that segment of the pipeline within 300 feet (91 
meters) of such a building, but in no event may the test section be less 
than 600 feet (183 meters) unless the length of the newly installed or 
relocated pipe is less than 600 feet (183 meters). However, if the 
buildings are evacuated while the hoop stress exceeds 50 percent of 
SMYS, air or inert gas may be used as the test medium.
    (b) In a Class 1 or Class 2 location, each compressor station 
regulator station, and measuring station, must be tested to at least 
Class 3 location test requirements.
    (c) Except as provided in paragraph (e) of this section, the 
strength test must be conducted by maintaining the pressure at or above 
the test pressure for at least 8 hours.
    (d) If a component other than pipe is the only item being replaced 
or added to a pipeline, a strength test after installation is not 
required, if the manufacturer of the component certifies that--
    (1) The component was tested to at least the pressure required for 
the pipeline to which it is being added;
    (2) The component was manufactured under a quality control system 
that ensures that each item manufactured is at least equal in strength 
to a prototype and that the prototype was tested to at least the 
pressure required for the pipeline to which it is being added; or
    (3) The component carries a pressure rating established through 
applicable ASME/ANSI, MSS specifications, or by unit strength 
calculations as described in Sec. 192.143.
    (e) For fabricated units and short sections of pipe, for which a 
post installation test is impractical, a preinstallation strength test 
must be conducted by maintaining the pressure at or above the test 
pressure for at least 4 hours.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37504, 
July 13, 1998; Amdt. 192-94, 69 FR 32895, June 14, 2004; Amdt. 195-94, 
69 FR 54592, Sept. 9, 2004]



Sec. 192.507  Test requirements for pipelines to operate at a hoop stress
less than 30 percent of SMYS and at or above 100 p.s.i. (689 kPa) gage.

    Except for service lines and plastic pipelines, each segment of a 
pipeline that is to be operated at a hoop stress less than 30 percent of 
SMYS and at or above 100 p.s.i. (689 kPa) gage must be tested in 
accordance with the following:
    (a) The pipeline operator must use a test procedure that will ensure 
discovery of all potentially hazardous leaks in the segment being 
tested.
    (b) If, during the test, the segment is to be stressed to 20 percent 
or more of SMYS and natural gas, inert gas, or air is the test medium--
    (1) A leak test must be made at a pressure between 100 p.s.i. (689 
kPa) gage and the pressure required to produce a hoop stress of 20 
percent of SMYS; or
    (2) The line must be walked to check for leaks while the hoop stress 
is held at approximately 20 percent of SMYS.

[[Page 86]]

    (c) The pressure must be maintained at or above the test pressure 
for at least 1 hour.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR 1635, 
Jan. 21, 1988; Amdt. 192-85, 63 FR 37504, July 13, 1998]



Sec. 192.509  Test requirements for pipelines to operate below 100
p.s.i. (689 kPa) gage.

    Except for service lines and plastic pipelines, each segment of a 
pipeline that is to be operated below 100 p.s.i. (689 kPa) gage must be 
leak tested in accordance with the following:
    (a) The test procedure used must ensure discovery of all potentially 
hazardous leaks in the segment being tested.
    (b) Each main that is to be operated at less than 1 p.s.i. (6.9 kPa) 
gage must be tested to at least 10 p.s.i. (69 kPa) gage and each main to 
be operated at or above 1 p.s.i. (6.9 kPa) gage must be tested to at 
least 90 p.s.i. (621 kPa) gage.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-58, 53 FR 1635, 
Jan. 21, 1988; Amdt. 192-85, 63 FR 37504, July 13, 1998]



Sec. 192.511  Test requirements for service lines.

    (a) Each segment of a service line (other than plastic) must be leak 
tested in accordance with this section before being placed in service. 
If feasible, the service line connection to the main must be included in 
the test; if not feasible, it must be given a leakage test at the 
operating pressure when placed in service.
    (b) Each segment of a service line (other than plastic) intended to 
be operated at a pressure of at least 1 p.s.i. (6.9 kPa) gage but not 
more than 40 p.s.i. (276 kPa) gage must be given a leak test at a 
pressure of not less than 50 p.s.i. (345 kPa) gage.
    (c) Each segment of a service line (other than plastic) intended to 
be operated at pressures of more than 40 p.s.i. (276 kPa) gage must be 
tested to at least 90 p.s.i. (621 kPa) gage, except that each segment of 
a steel service line stressed to 20 percent or more of SMYS must be 
tested in accordance with Sec. 192.507 of this subpart.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-74, 61 FR 18517, 
Apr. 26, 1996; Amdt 192-85, 63 FR 37504, July 13, 1998]



Sec. 192.513  Test requirements for plastic pipelines.

    (a) Each segment of a plastic pipeline must be tested in accordance 
with this section.
    (b) The test procedure must insure discovery of all potentially 
hazardous leaks in the segment being tested.
    (c) The test pressure must be at least 150 percent of the maximum 
operating pressure or 50 p.s.i. (345 kPa) gage, whichever is greater. 
However, the maximum test pressure may not be more than three times the 
pressure determined under Sec. 192.121, at a temperature not less than 
the pipe temperature during the test.
    (d) During the test, the temperature of thermoplastic material may 
not be more than 100[deg]F (38[deg]C), or the temperature at which the 
material's long-term hydrostatic strength has been determined under the 
listed specification, whichever is greater.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-77, 61 FR 27793, 
June 3, 1996; 61 FR 45905, Aug. 30, 1996; Amdt. 192-85, 63 FR 37504, 
July 13, 1998]



Sec. 192.515  Environmental protection and safety requirements.

    (a) In conducting tests under this subpart, each operator shall 
insure that every reasonable precaution is taken to protect its 
employees and the general public during the testing. Whenever the hoop 
stress of the segment of the pipeline being tested will exceed 50 
percent of SMYS, the operator shall take all practicable steps to keep 
persons not working on the testing operation outside of the testing area 
until the pressure is reduced to or below the proposed maximum allowable 
operating pressure.
    (b) The operator shall insure that the test medium is disposed of in 
a manner that will minimize damage to the environment.



Sec. 192.517  Records.

    (a) Each operator shall make, and retain for the useful life of the 
pipeline,

[[Page 87]]

a record of each test performed under Sec. Sec. 192.505 and 192.507. 
The record must contain at least the following information:
    (1) The operator's name, the name of the operator's employee 
responsible for making the test, and the name of any test company used.
    (2) Test medium used.
    (3) Test pressure.
    (4) Test duration.
    (5) Pressure recording charts, or other record of pressure readings.
    (6) Elevation variations, whenever significant for the particular 
test.
    (7) Leaks and failures noted and their disposition.
    (b) Each operator must maintain a record of each test required by 
Sec. Sec. 192.509, 192.511, and 192.513 for at least 5 years.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-93, 68 FR 53901, 
Sept. 15, 2003]



                           Subpart K_Uprating



Sec. 192.551  Scope.

    This subpart prescribes minimum requirements for increasing maximum 
allowable operating pressures (uprating) for pipelines.



Sec. 192.553  General requirements.

    (a) Pressure increases. Whenever the requirements of this subpart 
require that an increase in operating pressure be made in increments, 
the pressure must be increased gradually, at a rate that can be 
controlled, and in accordance with the following:
    (1) At the end of each incremental increase, the pressure must be 
held constant while the entire segment of pipeline that is affected is 
checked for leaks.
    (2) Each leak detected must be repaired before a further pressure 
increase is made, except that a leak determined not to be potentially 
hazardous need not be repaired, if it is monitored during the pressure 
increase and it does not become potentially hazardous.
    (b) Records. Each operator who uprates a segment of pipeline shall 
retain for the life of the segment a record of each investigation 
required by this subpart, of all work performed, and of each pressure 
test conducted, in connection with the uprating.
    (c) Written plan. Each operator who uprates a segment of pipeline 
shall establish a written procedure that will ensure that each 
applicable requirement of this subpart is complied with.
    (d) Limitation on increase in maximum allowable operating pressure. 
Except as provided in Sec. 192.555(c), a new maximum allowable 
operating pressure established under this subpart may not exceed the 
maximum that would be allowed under Sec. Sec. 192.619 and 192.621 for a 
new segment of pipeline constructed of the same materials in the same 
location. However, when uprating a steel pipeline, if any variable 
necessary to determine the design pressure under the design formula 
(Sec. 192.105) is unknown, the MAOP may be increased as provided in 
Sec. 192.619(a)(1).

[35 FR 13257, Aug. 10, 1970, as amended by Amdt. 192-78, 61 FR 28785, 
June 6, 1996; Amdt. 192-93, 68 FR 53901, Sept. 15, 2003]



Sec. 192.555  Uprating to a pressure that will produce a hoop stress of
30 percent or more of SMYS in steel pipelines.

    (a) Unless the requirements of this section have been met, no person 
may subject any segment of a steel pipeline to an operating pressure 
that will produce a hoop stress of 30 percent or more of SMYS and that 
is above the established maximum allowable operating pressure.
    (b) Before increasing operating pressure above the previously 
established maximum allowable operating pressure the operator shall:
    (1) Review the design, operating, and maintenance history and 
previous testing of the segment of pipeline and determine whether the 
proposed increase is safe and consistent with the requirements of this 
part; and
    (2) Make any repairs, replacements, or alterations in the segment of 
pipeline that are necessary for safe operation at the increased 
pressure.
    (c) After complying with paragraph (b) of this section, an operator 
may increase the maximum allowable operating pressure of a segment of 
pipeline constructed before September 12, 1970, to the highest pressure 
that is permitted under Sec. 192.619, using as test

[[Page 88]]

pressure the highest pressure to which the segment of pipeline was 
previously subjected (either in a strength test or in actual operation).
    (d) After complying with paragraph (b) of this section, an operator 
that does not qualify under paragraph (c) of this section may increase 
the previously established maximum allowable operating pressure if at 
least one of the following requirements is met:
    (1) The segment of pipeline is successfully tested in accordance 
with the requirements of this part for a new line of the same material 
in the same location.
    (2) An increased maximum allowable operating pressure may be 
established for a segment of pipeline in a Class 1 location if the line 
has not previously been tested, and if:
    (i) It is impractical to test it in accordance with the requirements 
of this part;
    (ii) The new maximum operating pressure does not exceed 80 percent 
of that allowed for a new line of the same design in the same location; 
and
    (iii) The operator determines that the new maximum allowable 
operating pressure is consistent with the condition of the segment of 
pipeline and the design requirements of this part.
    (e) Where a segment of pipeline is uprated in accordance with 
paragraph (c) or (d)(2) of this section, the increase in pressure must 
be made in increments that are equal to:
    (1) 10 percent of the pressure before the uprating; or
    (2) 25 percent of the total pressure increase,

whichever produces the fewer number of increments.



Sec. 192.557  Uprating: Steel pipelines to a pressure that will produce
a hoop stress less than 30 percent of SMYS: plastic, cast iron, and 

ductile iron pipelines.

    (a) Unless the requirements of this section have been met, no person 
may subject:
    (1) A segment of steel pipeline to an operating pressure that will 
produce a hoop stress less than 30 percent of SMYS and that is above the 
previously established maximum allowable operating pressure; or
    (2) A plastic, cast iron, or ductile iron pipeline segment to an 
operating pressure that is above the previously established maximum 
allowable operating pressure.
    (b) Before increasing operating pressure above the previously 
established maximum allowable operating pressure, the operator shall:
    (1) Review the design, operating, and maintenance history of the 
segment of pipeline;
    (2) Make a leakage survey (if it has been more than 1 year since the 
last survey) and repair any leaks that are found, except that a leak 
determined not to be potentially hazardous need not be repaired, if it 
is monitored during the pressure increase and it does not become 
potentially hazardous;
    (3) Make any repairs, replacements, or alterations in the segment of 
pipeline that are necessary for safe operation at the increased 
pressure;
    (4) Reinforce or anchor offsets, bends and dead ends in pipe joined 
by compression couplings or bell and spigot joints to prevent failure of 
the pipe joint, if the offset, bend, or dead end is exposed in an 
excavation;
    (5) Isolate the segment of pipeline in which the pressure is to be 
increased from any adjacent segment that will continue to be operated at 
a lower pressure; and
    (6) If the pressure in mains or service lines, or both, is to be 
higher than the pressure delivered to the customer, install a service 
regulator on each service line and test each regulator to determine that 
it is functioning. Pressure may be increased as necessary to test each 
regulator, after a regulator has been installed on each pipeline subject 
to the increased pressure.
    (c) After complying with paragraph (b) of this section, the increase 
in maximum allowable operating pressure must be made in increments that 
are equal to 10 p.s.i. (69 kPa) gage or 25 percent of the total pressure 
increase, whichever produces the fewer number of increments. Whenever 
the requirements of paragraph (b)(6) of this section apply, there must 
be at least two approximately equal incremental increases.

[[Page 89]]

    (d) If records for cast iron or ductile iron pipeline facilities are 
not complete enough to determine stresses produced by internal pressure, 
trench loading, rolling loads, beam stresses, and other bending loads, 
in evaluating the level of safety of the pipeline when operating at the 
proposed increased pressure, the following procedures must be followed:
    (1) In estimating the stresses, if the original laying conditions 
cannot be ascertained, the operator shall assume that cast iron pipe was 
supported on blocks with tamped backfill and that ductile iron pipe was 
laid without blocks with tamped backfill.
    (2) Unless the actual maximum cover depth is known, the operator 
shall measure the actual cover in at least three places where the cover 
is most likely to be greatest and shall use the greatest cover measured.
    (3) Unless the actual nominal wall thickness is known, the operator 
shall determine the wall thickness by cutting and measuring coupons from 
at least three separate pipe lengths. The coupons must be cut from pipe 
lengths in areas where the cover depth is most likely to be the 
greatest. The average of all measurements taken must be increased by the 
allowance indicated in the following table:

----------------------------------------------------------------------------------------------------------------
                                                                      Allowance inches (millimeters)
                                                        --------------------------------------------------------
                                                                    Cast iron pipe
             Pipe size inches (millimeters)             --------------------------------------
                                                                              Centrifugally    Ductile iron pipe
                                                           Pit cast pipe        cast pipe
----------------------------------------------------------------------------------------------------------------
3 to 8 (76 to 203).....................................       0.075 (1.91)       0.065 (1.65)       0.065 (1.65)
10 to 12 (254 to 305)..................................        0.08 (2.03)        0.07 (1.78)        0.07 (1.78)
14 to 24 (356 to 610)..................................        0.08 (2.03)        0.08 (2.03)       0.075 (1.91)
30 to 42 (762 to 1067).................................        0.09 (2.29)        0.09 (2.29)       0.075 (1.91)
48 (1219)..............................................        0.09 (2.29)        0.09 (2.29)        0.08 (2.03)
54 to 60 (1372 to 1524)................................        0.09 (2.29)  .................  .................
----------------------------------------------------------------------------------------------------------------

    (4) For cast iron pipe, unless the pipe manufacturing process is 
known, the operator shall assume that the pipe is pit cast pipe with a 
bursting tensile strength of 11,000 p.s.i. (76 MPa) gage and a modulus 
of rupture of 31,000 p.s.i. (214 MPa) gage.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-37, 46 FR 10160, 
Feb. 2, 1981; Amdt. 192-62, 54 FR 5628, Feb. 6, 1989; Amdt. 195-85, 63 
FR 37504, July 13, 1998]



                          Subpart L_Operations



Sec. 192.601  Scope.

    This subpart prescribes minimum requirements for the operation of 
pipeline facilities.



Sec. 192.603  General provisions.

    (a) No person may operate a segment of pipeline unless it is 
operated in accordance with this subpart.
    (b) Each operator shall keep records necessary to administer the 
procedures established under Sec. 192.605.
    (c) 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.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-66, 56 FR 31090, 
July 9, 1991; Amdt. 192-71, 59 FR 6584, Feb. 11, 1994; Amdt. 192-75, 61 
FR 18517, Apr. 26, 1996]



Sec. 192.605  Procedural manual for operations, maintenance, and emergencies.

    (a) General. Each operator shall prepare and follow for each 
pipeline, a manual of written procedures for conducting operations and 
maintenance activities and for emergency response. For transmission 
lines, the manual must also include procedures for handling abnormal 
operations. This manual must be reviewed and updated by the operator at 
intervals not exceeding

[[Page 90]]

15 months, but at least once each calendar year. This manual must be 
prepared before operations of a pipeline system commence. Appropriate 
parts of the manual must be kept at locations where operations and 
maintenance activities are conducted.
    (b) Maintenance and normal operations. The manual required by 
paragraph (a) of this section must include procedures for the following, 
if applicable, to provide safety during maintenance and operations.
    (1) Operating, maintaining, and repairing the pipeline in accordance 
with each of the requirements of this subpart and subpart M of this 
part.
    (2) Controlling corrosion in accordance with the operations and 
maintenance requirements of subpart I of this part.
    (3) Making construction records, maps, and operating history 
available to appropriate operating personnel.
    (4) Gathering of data needed for reporting incidents under Part 191 
of this chapter in a timely and effective manner.
    (5) Starting up and shutting down any part of the pipeline in a 
manner designed to assure operation within the MAOP limits prescribed by 
this part, plus the build-up allowed for operation of pressure-limiting 
and control devices.
    (6) Maintaining compressor stations, including provisions for 
isolating units or sections of pipe and for purging before returning to 
service.
    (7) Starting, operating and shutting down gas compressor units.
    (8) Periodically reviewing the work done by operator personnel to 
determine the effectiveness, and adequacy of the procedures used in 
normal operation and maintenance and modifying the procedures when 
deficiencies are found.
    (9) 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.
    (10) Systematic and routine testing and inspection of pipe-type or 
bottle-type holders including--
    (i) Provision for detecting external corrosion before the strength 
of the container has been impaired;
    (ii) Periodic sampling and testing of gas in storage to determine 
the dew point of vapors contained in the stored gas which, if condensed, 
might cause internal corrosion or interfere with the safe operation of 
the storage plant; and
    (iii) Periodic inspection and testing of pressure limiting equipment 
to determine that it is in safe operating condition and has adequate 
capacity.
    (11) Responding promptly to a report of a gas odor inside or near a 
building, unless the operator's emergency procedures under Sec. 
192.615(a)(3) specifically apply to these reports.
    (c) Abnormal operation. For transmission lines, 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; and
    (v) Any other foreseeable malfunction of a component, deviation from 
normal operation, or personnel error, which may result in 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) Notifying responsible operator personnel when notice of an 
abnormal operation is received.
    (4) 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.
    (5) The requirements of this paragraph (c) do not apply to natural 
gas distribution operators that are operating transmission lines in 
connection with their distribution system.

[[Page 91]]

    (d) 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 Sec. 191.23 of this 
subchapter.
    (e) Surveillance, emergency response, and accident investigation. 
The procedures required by Sec. Sec. 192.613(a), 192.615, and 192.617 
must be included in the manual required by paragraph (a) of this 
section.

[Amdt. 192-71, 59 FR 6584, Feb. 11, 1994, as amended by Amdt. 192-71A, 
60 FR 14381, Mar. 17, 1995; Amdt. 192-93, 68 FR 53901, Sept. 15, 2003]



Sec. 192.607  [Reserved]



Sec. 192.609  Change in class location: Required study.

    Whenever an increase in population density indicates a change in 
class location for a segment of an existing steel pipeline operating at 
hoop stress that is more than 40 percent of SMYS, or indicates that the 
hoop stress corresponding to the established maximum allowable operating 
pressure for a segment of existing pipeline is not commensurate with the 
present class location, the operator shall immediately make a study to 
determine:
    (a) The present class location for the segment involved.
    (b) The design, construction, and testing procedures followed in the 
original construction, and a comparison of these procedures with those 
required for the present class location by the applicable provisions of 
this part.
    (c) The physical condition of the segment to the extent it can be 
ascertained from available records;
    (d) The operating and maintenance history of the segment;
    (e) The maximum actual operating pressure and the corresponding 
operating hoop stress, taking pressure gradient into account, for the 
segment of pipeline involved; and
    (f) The actual area affected by the population density increase, and 
physical barriers or other factors which may limit further expansion of 
the more densely populated area.



Sec. 192.611  Change in class location: Confirmation or revision of
maximum allowable operating pressure.

    (a) If the hoop stress corresponding to the established maximum 
allowable operating pressure of a segment of pipeline is not 
commensurate with the present class location, and the segment is in 
satisfactory physical condition, the maximum allowable operating 
pressure of that segment of pipeline must be confirmed or revised 
according to one of the following requirements:
    (1) If the segment involved has been previously tested in place for 
a period of not less than 8 hours:
    (i) The maximum allowable operating pressure is 0.8 times the test 
pressure in Class 2 locations, 0.667 times the test pressure in Class 3 
locations, or 0.555 times the test pressure in Class 4 locations. The 
corresponding hoop stress may not exceed 72 percent of the SMYS of the 
pipe in Class 2 locations, 60 percent of SMYS in Class 3 locations, or 
50 percent of SMYS in Class 4 locations.
    (ii) The alternative maximum allowable operating pressure is 0.8 
times the test pressure in Class 2 locations and 0.667 times the test 
pressure in Class 3 locations. For pipelines operating at alternative 
maximum allowable pressure per Sec. 192.620, the corresponding hoop 
stress may not exceed 80 percent of the SMYS of the pipe in Class 2 
locations and 67 percent of SMYS in Class 3 locations.
    (2) The maximum allowable operating pressure of the segment involved 
must be reduced so that the corresponding hoop stress is not more than 
that allowed by this part for new segments of pipelines in the existing 
class location.
    (3) The segment involved must be tested in accordance with the 
applicable requirements of subpart J of this part, and its maximum 
allowable operating pressure must then be established according to the 
following criteria:
    (i) The maximum allowable operating pressure after the 
requalification test is 0.8 times the test pressure for Class 2 
locations, 0.667 times the test pressure for Class 3 locations, and 
0.555

[[Page 92]]

times the test pressure for Class 4 locations.
    (ii) The corresponding hoop stress may not exceed 72 percent of the 
SMYS of the pipe in Class 2 locations, 60 percent of SMYS in Class 3 
locations, or 50 percent of SMYS in Class 4 locations.
    (iii) For pipeline operating at an alternative maximum allowable 
operating pressure per Sec. 192.620, the alternative maximum allowable 
operating pressure after the requalification test is 0.8 times the test 
pressure for Class 2 locations and 0.667 times the test pressure for 
Class 3 locations. The corresponding hoop stress may not exceed 80 
percent of the SMYS of the pipe in Class 2 locations and 67 percent of 
SMYS in Class 3 locations.
    (b) The maximum allowable operating pressure confirmed or revised in 
accordance with this section, may not exceed the maximum allowable 
operating pressure established before the confirmation or revision.
    (c) Confirmation or revision of the maximum allowable operating 
pressure of a segment of pipeline in accordance with this section does 
not preclude the application of Sec. Sec. 192.553 and 192.555.
    (d) Confirmation or revision of the maximum allowable operating 
pressure that is required as a result of a study under Sec. 192.609 
must be completed within 24 months of the change in class location. 
Pressure reduction under paragraph (a) (1) or (2) of this section within 
the 24-month period does not preclude establishing a maximum allowable 
operating pressure under paragraph (a)(3) of this section at a later 
date.

[Amdt. 192-63A, 54 FR 24174, June 6, 1989 as amended by Amdt. 192-78, 61 
FR 28785, June 6, 1996; Amdt. 192-94, 69 FR 32895, June 14, 2004; 73 FR 
62177, Oct. 17, 2008]



Sec. 192.612  Underwater inspection and reburial of pipelines in the 
Gulf of Mexico and its inlets.

    (a) 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. 192-98, 69 FR 48406, Aug. 10, 2004]



Sec. 192.613  Continuing surveillance.

    (a) Each operator shall have a procedure for continuing surveillance 
of its facilities to determine and take appropriate action concerning 
changes in class location, failures, leakage history, corrosion, 
substantial changes in cathodic protection requirements, and other 
unusual operating and maintenance conditions.

[[Page 93]]

    (b) If a segment of pipeline is determined to be in unsatisfactory 
condition but no immediate hazard exists, the operator shall initiate a 
program to recondition or phase out the segment involved, or, if the 
segment cannot be reconditioned or phased out, reduce the maximum 
allowable operating pressure in accordance with Sec. 192.619 (a) and 
(b).



Sec. 192.614  Damage prevention program.

    (a) Except as provided in paragraphs (d) and (e) of this section, 
each operator of a buried pipeline must carry out, in accordance with 
this section, a written program to prevent damage to that pipeline from 
excavation activities. For the purposes of this section, the term 
``excavation activities'' includes excavation, blasting, boring, 
tunneling, backfilling, the removal of aboveground structures by either 
explosive or mechanical means, and other earthmoving operations.
    (b) An operator may comply with any of the requirements of paragraph 
(c) of this section through participation in a public service program, 
such as a 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 
Sec. 198.37 of this chapter; or
    (2) The one-call system:
    (i) Is operated in accordance with Sec. 198.39 of this chapter;
    (ii) Provides a pipeline operator an opportunity similar to a 
voluntary participant to have a part in management responsibilities; and
    (iii) Assesses a participating pipeline operator a fee that is 
proportionate to the costs of the one-call system's coverage of the 
operator's pipeline.
    (c) The damage prevention program required by paragraph (a) of this 
section must, at a minimum:
    (1) Include the identity, on a current basis, of persons who 
normally engage in excavation activities in the area in which the 
pipeline is located.
    (2) Provides for notification of the public in the vicinity of the 
pipeline and actual notification of 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 
excavation activities are begun.
    (3) Provide a means of receiving and recording notification of 
planned excavation activities.
    (4) If the operator has buried pipelines in the area of excavation 
activity, provide for actual notification of persons who give notice of 
their intent to excavate of the type of temporary marking to be provided 
and how to identify the markings.
    (5) Provide for temporary marking of buried pipelines in the area of 
excavation activity before, as far as practical, the activity begins.
    (6) Provide as follows for inspection of pipelines that an operator 
has reason to believe could be damaged by excavation activities:
    (i) The inspection must be done as frequently as necessary during 
and after the activities to verify the integrity of the pipeline; and
    (ii) In the case of blasting, any inspection must include leakage 
surveys.
    (d) A damage prevention program under this section is not required 
for the following pipelines:
    (1) Pipelines located offshore.
    (2) Pipelines, other than those located offshore, in Class 1 or 2 
locations until September 20, 1995.
    (3) Pipelines to which access is physically controlled by the 
operator.

[[Page 94]]

    (e) Pipelines operated by persons other than municipalities 
(including operators of master meters) whose primary activity does not 
include the transportation of gas need not comply with the following:
    (1) The requirement of paragraph (a) of this section that the damage 
prevention program be written; and
    (2) The requirements of paragraphs (c)(1) and (c)(2) of this 
section.

[Amdt. 192-40, 47 FR 13824, Apr. 1, 1982, as amended by Amdt. 192-57, 52 
FR 32800, Aug. 31, 1987; Amdt. 192-73, 60 FR 14650, Mar. 20, 1995; Amdt. 
192-78, 61 FR 28785, June 6, 1996; Amdt.192-82, 62 FR 61699, Nov. 19, 
1997; Amdt. 192-84, 63 FR 38758, July 20, 1998]



Sec. 192.615  Emergency plans.

    (a) Each operator shall establish written procedures to minimize the 
hazard resulting from a gas pipeline emergency. At a minimum, the 
procedures must provide for the following:
    (1) Receiving, identifying, and classifying notices of events which 
require immediate response by the operator.
    (2) Establishing and maintaining adequate means of communication 
with appropriate fire, police, and other public officials.
    (3) Prompt and effective response to a notice of each type of 
emergency, including the following:
    (i) Gas detected inside or near a building.
    (ii) Fire located near or directly involving a pipeline facility.
    (iii) Explosion occurring near or directly involving a pipeline 
facility.
    (iv) Natural disaster.
    (4) The availability of personnel, equipment, tools, and materials, 
as needed at the scene of an emergency.
    (5) Actions directed toward protecting people first and then 
property.
    (6) Emergency shutdown and pressure reduction in any section of the 
operator's pipeline system necessary to minimize hazards to life or 
property.
    (7) Making safe any actual or potential hazard to life or property.
    (8) Notifying appropriate fire, police, and other public officials 
of gas pipeline emergencies and coordinating with them both planned 
responses and actual responses during an emergency.
    (9) Safely restoring any service outage.
    (10) Beginning action under Sec. 192.617, if applicable, as soon 
after the end of the emergency as possible.
    (b) Each operator shall:
    (1) Furnish its supervisors who are responsible for emergency action 
a copy of that portion of the latest edition of the emergency procedures 
established under paragraph (a) of this section as necessary for 
compliance with those procedures.
    (2) Train the appropriate operating personnel to assure that they 
are knowledgeable of the emergency procedures and verify that the 
training is effective.
    (3) Review employee activities to determine whether the procedures 
were effectively followed in each emergency.
    (c) Each operator shall establish and maintain liaison with 
appropriate fire, police, and other public officials to:
    (1) Learn the responsibility and resources of each government 
organization that may respond to a gas pipeline emergency;
    (2) Acquaint the officials with the operator's ability in responding 
to a gas pipeline emergency;
    (3) Identify the types of gas pipeline emergencies of which the 
operator notifies the officials; and
    (4) Plan how the operator and officials can engage in mutual 
assistance to minimize hazards to life or property.

[Amdt. 192-24, 41 FR 13587, Mar. 31, 1976, as amended by Amdt. 192-71, 
59 FR 6585, Feb. 11, 1994]



Sec. 192.616  Public awareness.

    (a) Except for an operator of a master meter or petroleum gas system 
covered under paragraph (j) of this section, each pipeline operator must 
develop and implement a written continuing public education program that 
follows the guidance provided in the American Petroleum Institute's 
(API) Recommended Practice (RP) 1162 (incorporated by reference, see 
Sec. 192.7).
    (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.

[[Page 95]]

    (c) The operator must follow the general program recommendations, 
including baseline and supplemental requirements of API RP 1162, unless 
the operator provides justification in its program or procedural manual 
as to why compliance with all or certain provisions of the recommended 
practice is not practicable and not necessary for safety.
    (d) The operator's program must specifically include provisions to 
educate the public, appropriate government organizations, and persons 
engaged in excavation related activities on:
    (1) Use of a one-call notification system prior to excavation and 
other damage prevention activities;
    (2) Possible hazards associated with unintended releases from a gas 
pipeline facility;
    (3) Physical indications that such a release may have occurred;
    (4) Steps that should be taken for public safety in the event of a 
gas pipeline release; and
    (5) Procedures for reporting such an event.
    (e) The program must include activities to advise affected 
municipalities, school districts, businesses, and residents of pipeline 
facility locations.
    (f) The program and the media used must be as comprehensive as 
necessary to reach all areas in which the operator transports gas.
    (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.
    (h) Operators in existence on June 20, 2005, must have completed 
their written programs no later than June 20, 2006. The operator of a 
master meter or petroleum gas system covered under paragraph (j) of this 
section must complete development of its written procedure by June 13, 
2008. Upon request, operators must submit their completed programs to 
PHMSA or, in the case of an intrastate pipeline facility operator, the 
appropriate State agency.
    (i) The operator's program documentation and evaluation results must 
be available for periodic review by appropriate regulatory agencies.
    (j) Unless the operator transports gas as a primary activity, the 
operator of a master meter or petroleum gas system is not required to 
develop a public awareness program as prescribed in paragraphs (a) 
through (g) of this section. Instead the operator must develop and 
implement a written procedure to provide its customers public awareness 
messages twice annually. If the master meter or petroleum gas system is 
located on property the operator does not control, the operator must 
provide similar messages twice annually to persons controlling the 
property. The public awareness message must include:
    (1) A description of the purpose and reliability of the pipeline;
    (2) An overview of the hazards of the pipeline and prevention 
measures used;
    (3) Information about damage prevention;
    (4) How to recognize and respond to a leak; and
    (5) How to get additional information.

[Amdt. 192-100, 70 FR 28842, May 19, 2005; 70 FR 35041, June 16, 2005; 
72 FR 70810, Dec. 13, 2007]



Sec. 192.617  Investigation of failures.

    Each operator shall establish procedures for analyzing accidents and 
failures, including the selection of samples of the failed facility or 
equipment for laboratory examination, where appropriate, for the purpose 
of determining the causes of the failure and minimizing the possibility 
of a recurrence.



Sec. 192.619  Maximum allowable operating pressure: Steel or plastic 
pipelines.

    (a) No person may operate a segment of steel or plastic pipeline at 
a pressure that exceeds a maximum allowable operating pressure 
determined under paragraph (c) or (d) of this section, or the lowest of 
the following:
    (1) The design pressure of the weakest element in the segment, 
determined in accordance with subparts C and D of this part. However, 
for steel pipe in pipelines being converted under Sec. 192.14 or 
uprated under subpart K of this part, if any variable necessary to 
determine the design pressure under

[[Page 96]]

the design formula (Sec. 192.105) is 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 of Appendix N of ASME B31.8 (incorporated by reference, 
see Sec. 192.7), reduced by the appropriate factor in paragraph 
(a)(2)(ii) of this section; or
    (ii) If the pipe is 12\3/4\ inches (324 mm) or less in outside 
diameter and is not tested to yield under this paragraph, 200 p.s.i. 
(1379 kPa).
    (2) The pressure obtained by dividing the pressure to which the 
segment was tested after construction as follows:
    (i) For plastic pipe in all locations, the test pressure is divided 
by a factor of 1.5.
    (ii) For steel pipe operated at 100 p.s.i. (689 kPa) gage or more, 
the test pressure is divided by a factor determined in accordance with 
the following table:

------------------------------------------------------------------------
                                            Factors \1\, segment--
                                     -----------------------------------
                                       Installed   Installed   Converted
           Class location               before       after    under Sec.
                                       (Nov. 12,   (Nov. 11,     192.14
                                         1970)       1970)
------------------------------------------------------------------------
1...................................         1.1         1.1        1.25
2...................................        1.25        1.25        1.25
3...................................         1.4         1.5         1.5
4...................................         1.4         1.5         1.5
------------------------------------------------------------------------
\1\ For offshore segments installed, uprated or converted after July 31,
  1977, that are not located on an offshore platform, the factor is
  1.25. For segments installed, uprated or converted after July 31,
  1977, that are located on an offshore platform or on a platform in
  inland navigable waters, including a pipe riser, the factor is 1.5.

    (3) The highest actual operating pressure to which the segment was 
subjected during the 5 years preceding the applicable date in the second 
column. This pressure restriction applies unless the segment was tested 
according to the requirements in paragraph (a)(2) of this section after 
the applicable date in the third column or the segment was uprated 
according to the requirements in subpart K of this part:

------------------------------------------------------------------------
        Pipeline segment             Pressure date         Test date
------------------------------------------------------------------------
--Onshore gathering line that     March 15, 2006, or  5 years preceding
 first became subject to this      date line becomes   applicable date
 part (other than Sec.            subject to this     in second column.
 192.612) after April 13, 2006.    part, whichever
                                   is later.
--Onshore transmission line that
 was a gathering line not
 subject to this part before
 March 15, 2006.
Offshore gathering lines........  July 1, 1976......  July 1, 1971.
All other pipelines.............  July 1, 1970......  July 1, 1965.
------------------------------------------------------------------------

    (4) The pressure determined by the operator to be the maximum safe 
pressure after considering the history of the segment, particularly 
known corrosion and the actual operating pressure.
    (b) No person may operate a segment to which paragraph (a)(4) of 
this section is applicable, unless over-pressure protective devices are 
installed on the segment in a manner that will prevent the maximum 
allowable operating pressure from being exceeded, in accordance with 
Sec. 192.195.
    (c) The requirements on pressure restrictions in this section do not 
apply in the following instance. An operator may operate a segment of 
pipeline found to be in satisfactory condition, considering its 
operating and maintenance history, at the highest actual operating 
pressure to which the segment was subjected during the 5 years preceding 
the applicable date in the second column of the table in paragraph 
(a)(3) of this section. An operator must still comply with Sec. 
192.611.
    (d) The operator of a pipeline segment of steel pipeline meeting the 
conditions prescribed in Sec. 192.620(b) may elect to operate the 
segment at a maximum allowable operating pressure determined under Sec. 
192.620(a).

[35 FR 13257, Aug. 19, 1970]

    Editorial Note: For Federal Register citations affecting Sec. 
192.619, see the List of CFR Sections Affected, which appears in the 
Finding Aids section of the printed volume and on GPO Access.



Sec. 192.620  Alternative maximum allowable operating pressure for certain 
steel pipelines.

    (a) How does an operator calculate the alternative maximum allowable 
operating

[[Page 97]]

pressure? An operator calculates the alternative maximum allowable 
operating pressure by using different factors in the same formulas used 
for calculating maximum allowable operating pressure under Sec. 
192.619(a) as follows:
    (1) In determining the alternative design pressure under Sec. 
192.105, use a design factor determined in accordance with Sec. 
192.111(b), (c), or (d) or, if none of these paragraphs apply, in 
accordance with the following table:

------------------------------------------------------------------------
                                                            Alternative
                     Class location                        design factor
                                                                (F)
------------------------------------------------------------------------
 1......................................................            0.80
 2......................................................            0.67
 3......................................................            0.56
------------------------------------------------------------------------

    (i) For facilities installed prior to November 17, 2008, for which 
Sec. 192.111(b), (c), or (d) apply, use the following design factors as 
alternatives for the factors specified in those paragraphs: Sec. 
192.111(b)--0.67 or less; 192.111(c) and (d)--0.56 or less.
    (ii) [Reserved]
    (2) The alternative maximum allowable operating pressure is the 
lower of the following:
    (i) The design pressure of the weakest element in the pipeline 
segment, determined under subparts C and D of this part.
    (ii) The pressure obtained by dividing the pressure to which the 
pipeline segment was tested after construction by a factor determined in 
the following table:

------------------------------------------------------------------------
                                                            Alternative
                     Class location                         test factor
------------------------------------------------------------------------
 1......................................................            1.25
 2......................................................        \1\ 1.50
 3......................................................            1.50
------------------------------------------------------------------------
\1\ For Class 2 alternative maximum allowable operating pressure
  segments installed prior to November 17, 2008, the alternative test
  factor is 1.25.

    (b) When may an operator use the alternative maximum allowable 
operating pressure calculated under paragraph (a) of this section? An 
operator may use an alternative maximum allowable operating pressure 
calculated under paragraph (a) of this section if the following 
conditions are met:
    (1) The pipeline segment is in a Class 1, 2, or 3 location;
    (2) The pipeline segment is constructed of steel pipe meeting the 
additional design requirements in Sec. 192.112;
    (3) A supervisory control and data acquisition system provides 
remote monitoring and control of the pipeline segment. The control 
provided must include monitoring of pressures and flows, monitoring 
compressor start-ups and shut-downs, and remote closure of valves;
    (4) The pipeline segment meets the additional construction 
requirements described in Sec. 192.328;
    (5) The pipeline segment does not contain any mechanical couplings 
used in place of girth welds;
    (6) If a pipeline segment has been previously operated, the segment 
has not experienced any failure during normal operations indicative of a 
systemic fault in material as determined by a root cause analysis, 
including metallurgical examination of the failed pipe. The results of 
this root cause analysis must be reported to each PHMSA pipeline safety 
regional office where the pipeline is in service at least 60 days prior 
to operation at the alternative MAOP. An operator must also notify a 
State pipeline safety authority when the pipeline is located in a State 
where PHMSA has an interstate agent agreement, or an intrastate pipeline 
is regulated by that State; and
    (7) At least 95 percent of girth welds on a segment that was 
constructed prior to November 17, 2008, must have been non-destructively 
examined in accordance with Sec. 192.243(b) and (c).
    (c) What is an operator electing to use the alternative maximum 
allowable operating pressure required to do? If an operator elects to 
use the alternative maximum allowable operating pressure calculated 
under paragraph (a) of this section for a pipeline segment, the operator 
must do each of the following:
    (1) Notify each PHMSA pipeline safety regional office where the 
pipeline is in service of its election with respect to a segment at 
least 180 days before operating at the alternative maximum allowable 
operating pressure. An operator must also notify a State pipeline safety 
authority when the pipeline is located in a State where PHMSA has an 
interstate agent agreement, or an intrastate pipeline is regulated by 
that State.

[[Page 98]]

    (2) Certify, by signature of a senior executive officer of the 
company, as follows:
    (i) The pipeline segment meets the conditions described in paragraph 
(b) of this section; and
    (ii) The operating and maintenance procedures include the additional 
operating and maintenance requirements of paragraph (d) of this section; 
and
    (iii) The review and any needed program upgrade of the damage 
prevention program required by paragraph (d)(4)(v) of this section has 
been completed.
    (3) Send a copy of the certification required by paragraph (c)(2) of 
this section to each PHMSA pipeline safety regional office where the 
pipeline is in service 30 days prior to operating at the alternative 
MAOP. An operator must also send a copy to a State pipeline safety 
authority when the pipeline is located in a State where PHMSA has an 
interstate agent agreement, or an intrastate pipeline is regulated by 
that State.
    (4) For each pipeline segment, do one of the following:
    (i) Perform a strength test as described in Sec. 192.505 at a test 
pressure calculated under paragraph (a) of this section or
    (ii) For a pipeline segment in existence prior to November 17, 2008, 
certify, under paragraph (c)(2) of this section, that the strength test 
performed under Sec. 192.505 was conducted at a test pressure 
calculated under paragraph (a) of this section, or conduct a new 
strength test in accordance with paragraph (c)(4)(i) of this section.
    (5) Comply with the additional operation and maintenance 
requirements described in paragraph (d) of this section.
    (6) If the performance of a construction task associated with 
implementing alternative MAOP can affect the integrity of the pipeline 
segment, treat that task as a ``covered task'', notwithstanding the 
definition in Sec. 192.801(b) and implement the requirements of subpart 
N as appropriate.
    (7) Maintain, for the useful life of the pipeline, records 
demonstrating compliance with paragraphs (b), (c)(6), and (d) of this 
section.
    (8) A Class 1 and Class 2 pipeline location can be upgraded one 
class due to class changes per Sec. 192.611(a)(3)(i). All class 
location changes from Class 1 to Class 2 and from Class 2 to Class 3 
must have all anomalies evaluated and remediated per: The ``original 
pipeline class grade'' Sec. 192.620(d)(11) anomaly repair requirements; 
and all anomalies with a wall loss equal to or greater than 40 percent 
must be excavated and remediated. Pipelines in Class 4 may not operate 
at an alternative MAOP.
    (d) What additional operation and maintenance requirements apply to 
operation at the alternative maximum allowable operating pressure? In 
addition to compliance with other applicable safety standards in this 
part, if an operator establishes a maximum allowable operating pressure 
for a pipeline segment under paragraph (a) of this section, an operator 
must comply with the additional operation and maintenance requirements 
as follows:

------------------------------------------------------------------------
  To address increased risk of a
    maximum allowable operating
  pressure based on higher stress    Take the following additional step:
  levels in the following areas:
------------------------------------------------------------------------
(1) Identifying and evaluating      Develop a threat matrix consistent
 threats.                            with Sec.  192.917 to do the
                                     following:
                                    (i) Identify and compare the
                                     increased risk of operating the
                                     pipeline at the increased stress
                                     level under this section with
                                     conventional operation; and
                                    (ii) Describe and implement
                                     procedures used to mitigate the
                                     risk.
(2) Notifying the public..........  (i) Recalculate the potential impact
                                     circle as defined in Sec.  192.903
                                     to reflect use of the alternative
                                     maximum operating pressure
                                     calculated under paragraph (a) of
                                     this section and pipeline operating
                                     conditions; and
                                    (ii) In implementing the public
                                     education program required under
                                     Sec.  192.616, perform the
                                     following:
                                    (A) Include persons occupying
                                     property within 220 yards of the
                                     centerline and within the potential
                                     impact circle within the targeted
                                     audience; and
                                    (B) Include information about the
                                     integrity management activities
                                     performed under this section within
                                     the message provided to the
                                     audience.

[[Page 99]]

 
(3) Responding to an emergency in   (i) Ensure that the identification
 an area defined as a high           of high consequence areas reflects
 consequence area in Sec.           the larger potential impact circle
 192.903.                            recalculated under paragraph
                                     (d)(1)(i) of this section.
                                    (ii) If personnel response time to
                                     mainline valves on either side of
                                     the high consequence area exceeds
                                     one hour (under normal driving
                                     conditions and speed limits) from
                                     the time the event is identified in
                                     the control room, provide remote
                                     valve control through a supervisory
                                     control and data acquisition
                                     (SCADA) system, other leak
                                     detection system, or an alternative
                                     method of control.
                                    (iii) Remote valve control must
                                     include the ability to close and
                                     monitor the valve position (open or
                                     closed), and monitor pressure
                                     upstream and downstream.
                                    (iv) A line break valve control
                                     system using differential pressure,
                                     rate of pressure drop or other
                                     widely-accepted method is an
                                     acceptable alternative to remote
                                     valve control.
(4) Protecting the right-of-way...  (i) Patrol the right-of-way at
                                     intervals not exceeding 45 days,
                                     but at least 12 times each calendar
                                     year, to inspect for excavation
                                     activities, ground movement, wash
                                     outs, leakage, or other activities
                                     or conditions affecting the safety
                                     operation of the pipeline.
                                    (ii) Develop and implement a plan to
                                     monitor for and mitigate
                                     occurrences of unstable soil and
                                     ground movement.
                                    (iii) If observed conditions
                                     indicate the possible loss of
                                     cover, perform a depth of cover
                                     study and replace cover as
                                     necessary to restore the depth of
                                     cover or apply alternative means to
                                     provide protection equivalent to
                                     the originally-required depth of
                                     cover.
                                    (iv) Use line-of-sight line markers
                                     satisfying the requirements of Sec.
                                       192.707(d) except in agricultural
                                     areas, large water crossings or
                                     swamp, steep terrain, or where
                                     prohibited by Federal Energy
                                     Regulatory Commission orders,
                                     permits, or local law.
                                    (v) Review the damage prevention
                                     program under Sec.  192.614(a) in
                                     light of national consensus
                                     practices, to ensure the program
                                     provides adequate protection of the
                                     right-of-way. Identify the
                                     standards or practices considered
                                     in the review, and meet or exceed
                                     those standards or practices by
                                     incorporating appropriate changes
                                     into the program.
                                    (vi) Develop and implement a right-
                                     of-way management plan to protect
                                     the pipeline segment from damage
                                     due to excavation activities.
(5) Controlling internal corrosion  (i) Develop and implement a program
                                     to monitor for and mitigate the
                                     presence of, deleterious gas stream
                                     constituents.
                                    (ii) At points where gas with
                                     potentially deleterious
                                     contaminants enters the pipeline,
                                     use filter separators or separators
                                     and gas quality monitoring
                                     equipment.
                                    (iii) Use gas quality monitoring
                                     equipment that includes a moisture
                                     analyzer, chromatograph, and
                                     periodic hydrogen sulfide sampling.
                                    (iv) Use cleaning pigs and
                                     inhibitors, and sample accumulated
                                     liquids when corrosive gas is
                                     present.
                                    (v) Address deleterious gas stream
                                     constituents as follows:
                                    (A) Limit carbon dioxide to 3
                                     percent by volume;
                                    (B) Allow no free water and
                                     otherwise limit water to seven
                                     pounds per million cubic feet of
                                     gas; and
                                    (C) Limit hydrogen sulfide to 1.0
                                     grain per hundred cubic feet (16
                                     ppm) of gas, where the hydrogen
                                     sulfide is greater than 0.5 grain
                                     per hundred cubic feet (8 ppm) of
                                     gas, implement a pigging and
                                     inhibitor injection program to
                                     address deleterious gas stream
                                     constituents, including follow-up
                                     sampling and quality testing of
                                     liquids at receipt points.
                                    (vi) Review the program at least
                                     quarterly based on the gas stream
                                     experience and implement
                                     adjustments to monitor for, and
                                     mitigate the presence of,
                                     deleterious gas stream
                                     constituents.
(6) Controlling interference that   (i) Prior to operating an existing
 can impact external corrosion.      pipeline segment at an alternate
                                     maximum allowable operating
                                     pressure calculated under this
                                     section, or within six months after
                                     placing a new pipeline segment in
                                     service at an alternate maximum
                                     allowable operating pressure
                                     calculated under this section,
                                     address any interference currents
                                     on the pipeline segment.
                                    (ii) To address interference
                                     currents, perform the following:
                                    (A) Conduct an interference survey
                                     to detect the presence and level of
                                     any electrical current that could
                                     impact external corrosion where
                                     interference is suspected;
                                    (B) Analyze the results of the
                                     survey; and
                                    (C) Take any remedial action needed
                                     within 6 months after completing
                                     the survey to protect the pipeline
                                     segment from deleterious current.
(7) Confirming external corrosion   (i) Within six months after placing
 control through indirect            the cathodic protection of a new
 assessment.                         pipeline segment in operation, or
                                     within six months after certifying
                                     a segment under Sec.
                                     192.620(c)(1) of an existing
                                     pipeline segment under this
                                     section, assess the adequacy of the
                                     cathodic protection through an
                                     indirect method such as close-
                                     interval survey, and the integrity
                                     of the coating using direct current
                                     voltage gradient (DCVG) or
                                     alternating current voltage
                                     gradient (ACVG).
                                    (ii) Remediate any construction
                                     damaged coating with a voltage drop
                                     classified as moderate or severe
                                     (IR drop greater than 35% for DCVG
                                     or 50 dB[micro]v for ACVG) under
                                     section 4 of NACE RP-0502-2002
                                     (incorporated by reference, see
                                     Sec.  192.7).

[[Page 100]]

 
                                    (iii) Within six months after
                                     completing the baseline internal
                                     inspection required under paragraph
                                     (8) of this section, integrate the
                                     results of the indirect assessment
                                     required under paragraph (6)(i) of
                                     this section with the results of
                                     the baseline internal inspection
                                     and take any needed remedial
                                     actions.
                                    (iv) For all pipeline segments in
                                     high consequence areas, perform
                                     periodic assessments as follows:
                                    (A) Conduct periodic close interval
                                     surveys with current interrupted to
                                     confirm voltage drops in
                                     association with periodic
                                     assessments under subpart O of this
                                     part.
                                    (B) Locate pipe-to-soil test
                                     stations at half-mile intervals
                                     within each high consequence area
                                     ensuring at least one station is
                                     within each high consequence area,
                                     if practicable.
                                    (C) Integrate the results with those
                                     of the baseline and periodic
                                     assessments for integrity done
                                     under paragraphs (d)(8) and (d)(9)
                                     of this section.
(8) Controlling external corrosion  (i) If an annual test station
 through cathodic protection.        reading indicates cathodic
                                     protection below the level of
                                     protection required in subpart I of
                                     this part, complete remedial action
                                     within six months of the failed
                                     reading or notify each PHMSA
                                     pipeline safety regional office
                                     where the pipeline is in service
                                     demonstrating that the integrity of
                                     the pipeline is not compromised if
                                     the repair takes longer than 6
                                     months. An operator must also
                                     notify a State pipeline safety
                                     authority when the pipeline is
                                     located in a State where PHMSA has
                                     an interstate agent agreement, or
                                     an intrastate pipeline is regulated
                                     by that State; and
                                    (ii) After remedial action to
                                     address a failed reading, confirm
                                     restoration of adequate corrosion
                                     control by a close interval survey
                                     on either side of the affected test
                                     station to the next test station.
                                    (iii) If the pipeline segment has
                                     been in operation, the cathodic
                                     protection system on the pipeline
                                     segment must have been operational
                                     within 12 months of the completion
                                     of construction.
(9) Conducting a baseline           (i) Except as provided in paragraph
 assessment of integrity.            (d)(8)(iii) of this section, for a
                                     new pipeline segment operating at
                                     the new alternative maximum
                                     allowable operating pressure,
                                     perform a baseline internal
                                     inspection of the entire pipeline
                                     segment as follows:
                                    (A) Assess using a geometry tool
                                     after the initial hydrostatic test
                                     and backfill and within six months
                                     after placing the new pipeline
                                     segment in service; and
                                    (B) Assess using a high resolution
                                     magnetic flux tool within three
                                     years after placing the new
                                     pipeline segment in service at the
                                     alternative maximum allowable
                                     operating pressure.
                                    (ii) Except as provided in paragraph
                                     (d)(8)(iii) of this section, for an
                                     existing pipeline segment, perform
                                     a baseline internal assessment
                                     using a geometry tool and a high
                                     resolution magnetic flux tool
                                     before, but within two years prior
                                     to, raising pressure to the
                                     alternative maximum allowable
                                     operating pressure as allowed under
                                     this section.
                                    (iii) If headers, mainline valve by-
                                     passes, compressor station piping,
                                     meter station piping, or other
                                     short portion of a pipeline segment
                                     operating at alternative maximum
                                     allowable operating pressure cannot
                                     accommodate a geometry tool and a
                                     high resolution magnetic flux tool,
                                     use direct assessment (per Sec.
                                     192.925, Sec.  192.927 and/or Sec.
                                       192.929) or pressure testing (per
                                     subpart J of this part) to assess
                                     that portion.
(10) Conducting periodic            (i) Determine a frequency for
 assessments of integrity.           subsequent periodic integrity
                                     assessments as if all the
                                     alternative maximum allowable
                                     operating pressure pipeline
                                     segments were covered by subpart O
                                     of this part and
                                    (ii) Conduct periodic internal
                                     inspections using a high resolution
                                     magnetic flux tool on the frequency
                                     determined under paragraph
                                     (d)(9)(i) of this section, or
                                    (iii) Use direct assessment (per
                                     Sec.  192.925, Sec.  192.927 and/
                                     or Sec.  192.929) or pressure
                                     testing (per subpart J of this
                                     part) for periodic assessment of a
                                     portion of a segment to the extent
                                     permitted for a baseline assessment
                                     under paragraph (d)(8)(iii) of this
                                     section.
(11) Making repairs...............  (i) Perform the following when
                                     evaluating an anomaly:
                                    (A) Use the most conservative
                                     calculation for determining
                                     remaining strength or an
                                     alternative validated calculation
                                     based on pipe diameter, wall
                                     thickness, grade, operating
                                     pressure, operating stress level,
                                     and operating temperature: and
                                    (B) Take into account the tolerances
                                     of the tools used for the
                                     inspection.
                                    (ii) Repair a defect immediately if
                                     any of the following apply:
                                    (A) The defect is a dent discovered
                                     during the baseline assessment for
                                     integrity under paragraph (d)(8) of
                                     this section and the defect meets
                                     the criteria for immediate repair
                                     in Sec.  192.309(b).
                                    (B) The defect meets the criteria
                                     for immediate repair in Sec.
                                     192.933(d).
                                    (C) The alternative maximum
                                     allowable operating pressure was
                                     based on a design factor of 0.67
                                     under paragraph (a) of this section
                                     and the failure pressure is less
                                     than 1.25 times the alternative
                                     maximum allowable operating
                                     pressure.
                                    (D) The alternative maximum
                                     allowable operating pressure was
                                     based on a design factor of 0.56
                                     under paragraph (a) of this section
                                     and the failure pressure is less
                                     than or equal to 1.4 times the
                                     alternative maximum allowable
                                     operating pressure.
                                    (iii) If paragraph (d)(10)(ii) of
                                     this section does not require
                                     immediate repair, repair a defect
                                     within one year if any of the
                                     following apply:
                                    (A) The defect meets the criteria
                                     for repair within one year in Sec.
                                      192.933(d).

[[Page 101]]

 
                                    (B) The alternative maximum
                                     allowable operating pressure was
                                     based on a design factor of 0.80
                                     under paragraph (a) of this section
                                     and the failure pressure is less
                                     than 1.25 times the alternative
                                     maximum allowable operating
                                     pressure.
                                    (C) The alternative maximum
                                     allowable operating pressure was
                                     based on a design factor of 0.67
                                     under paragraph (a) of this section
                                     and the failure pressure is less
                                     than 1.50 times the alternative
                                     maximum allowable operating
                                     pressure.
                                    (D) The alternative maximum
                                     allowable operating pressure was
                                     based on a design factor of 0.56
                                     under paragraph (a) of this section
                                     and the failure pressure is less
                                     than or equal to 1.80 times the
                                     alternative maximum allowable
                                     operating pressure.
                                    (iv) Evaluate any defect not
                                     required to be repaired under
                                     paragraph (d)(10)(ii) or (iii) of
                                     this section to determine its
                                     growth rate, set the maximum
                                     interval for repair or re-
                                     inspection, and repair or re-
                                     inspect within that interval.
------------------------------------------------------------------------

    (e) Is there any change in overpressure protection associated with 
operating at the alternative maximum allowable operating pressure? 
Notwithstanding the required capacity of pressure relieving and limiting 
stations otherwise required by Sec. 192.201, if an operator establishes 
a maximum allowable operating pressure for a pipeline segment in 
accordance with paragraph (a) of this section, an operator must:
    (1) Provide overpressure protection that limits mainline pressure to 
a maximum of 104 percent of the maximum allowable operating pressure; 
and
    (2) Develop and follow a procedure for establishing and maintaining 
accurate set points for the supervisory control and data acquisition 
system.

[73 FR 62177, Oct. 17, 2008]



Sec. 192.621  Maximum allowable operating pressure: High-pressure 
distribution systems.

    (a) No person may operate a segment of a high pressure distribution 
system at a pressure that exceeds the lowest of the following pressures, 
as applicable:
    (1) The design pressure of the weakest element in the segment, 
determined in accordance with subparts C and D of this part.
    (2) 60 p.s.i. (414 kPa) gage, for a segment of a distribution system 
otherwise designed to operate at over 60 p.s.i. (414 kPa) gage, unless 
the service lines in the segment are equipped with service regulators or 
other pressure limiting devices in series that meet the requirements of 
Sec. 192.197(c).
    (3) 25 p.s.i. (172 kPa) gage in segments of cast iron pipe in which 
there are unreinforced bell and spigot joints.
    (4) The pressure limits to which a joint could be subjected without 
the possibility of its parting.
    (5) The pressure determined by the operator to be the maximum safe 
pressure after considering the history of the segment, particularly 
known corrosion and the actual operating pressures.
    (b) No person may operate a segment of pipeline to which paragraph 
(a)(5) of this section applies, unless overpressure protective devices 
are installed on the segment in a manner that will prevent the maximum 
allowable operating pressure from being exceeded, in accordance with 
Sec. 192.195.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt 192-85, 63 FR 37504, 
July 13, 1998]



Sec. 192.623  Maximum and minimum allowable operating pressure; 
Low-pressure distribution systems.

    (a) No person may operate a low-pressure distribution system at a 
pressure high enough to make unsafe the operation of any connected and 
properly adjusted low-pressure gas burning equipment.
    (b) No person may operate a low pressure distribution system at a 
pressure lower than the minimum pressure at which the safe and 
continuing operation of any connected and properly adjusted low-pressure 
gas burning equipment can be assured.



Sec. 192.625  Odorization of gas.

    (a) A combustible gas in a distribution line must contain a natural 
odorant or be odorized so that at a concentration in air of one-fifth of 
the lower explosive limit, the gas is readily

[[Page 102]]

detectable by a person with a normal sense of smell.
    (b) After December 31, 1976, a combustible gas in a transmission 
line in a Class 3 or Class 4 location must comply with the requirements 
of paragraph (a) of this section unless:
    (1) At least 50 percent of the length of the line downstream from 
that location is in a Class 1 or Class 2 location;
    (2) The line transports gas to any of the following facilities which 
received gas without an odorant from that line before May 5, 1975;
    (i) An underground storage field;
    (ii) A gas processing plant;
    (iii) A gas dehydration plant; or
    (iv) An industrial plant using gas in a process where the presence 
of an odorant:
    (A) Makes the end product unfit for the purpose for which it is 
intended;
    (B) Reduces the activity of a catalyst; or
    (C) Reduces the percentage completion of a chemical reaction;
    (3) In the case of a lateral line which transports gas to a 
distribution center, at least 50 percent of the length of that line is 
in a Class 1 or Class 2 location; or
    (4) The combustible gas is hydrogen intended for use as a feedstock 
in a manufacturing process.
    (c) In the concentrations in which it is used, the odorant in 
combustible gases must comply with the following:
    (1) The odorant may not be deleterious to persons, materials, or 
pipe.
    (2) The products of combustion from the odorant may not be toxic 
when breathed nor may they be corrosive or harmful to those materials to 
which the products of combustion will be exposed.
    (d) The odorant may not be soluble in water to an extent greater 
than 2.5 parts to 100 parts by weight.
    (e) Equipment for odorization must introduce the odorant without 
wide variations in the level of odorant.
    (f) To assure the proper concentration of odorant in accordance with 
this section, each operator must conduct periodic sampling of 
combustible gases using an instrument capable of determining the 
percentage of gas in air at which the odor becomes readily detectable. 
Operators of master meter systems may comply with this requirement by--
    (1) Receiving written verification from their gas source that the 
gas has the proper concentration of odorant; and
    (2) Conducting periodic ``sniff'' tests at the extremities of the 
system to confirm that the gas contains odorant.

[35 FR 13257, Aug. 19, 1970]

    Editorial Note: For Federal Register citations affecting Sec. 
192.625, see the List of CFR Sections Affected, which appears in the 
Finding Aids section of the printed volume and on GPO Access.



Sec. 192.627  Tapping pipelines under pressure.

    Each tap made on a pipeline under pressure must be performed by a 
crew qualified to make hot taps.



Sec. 192.629  Purging of pipelines.

    (a) When a pipeline is being purged of air by use of gas, the gas 
must be released into one end of the line in a moderately rapid and 
continuous flow. If gas cannot be supplied in sufficient quantity to 
prevent the formation of a hazardous mixture of gas and air, a slug of 
inert gas must be released into the line before the gas.
    (b) When a pipeline is being purged of gas by use of air, the air 
must be released into one end of the line in a moderately rapid and 
continuous flow. If air cannot be supplied in sufficient quantity to 
prevent the formation of a hazardous mixture of gas and air, a slug of 
inert gas must be released into the line before the air.



                          Subpart M_Maintenance



Sec. 192.701  Scope.

    This subpart prescribes minimum requirements for maintenance of 
pipeline facilities.



Sec. 192.703  General.

    (a) No person may operate a segment of pipeline, unless it is 
maintained in accordance with this subpart.
    (b) Each segment of pipeline that becomes unsafe must be replaced, 
repaired, or removed from service.
    (c) Hazardous leaks must be repaired promptly.

[[Page 103]]



Sec. 192.705  Transmission lines: Patrolling.

    (a) Each operator shall have a patrol program to observe surface 
conditions on and adjacent to the transmission line right-of-way for 
indications of leaks, construction activity, and other factors affecting 
safety and operation.
    (b) The frequency of patrols is determined by the size of the line, 
the operating pressures, the class location, terrain, weather, and other 
relevant factors, but intervals between patrols may not be longer than 
prescribed in the following table:

------------------------------------------------------------------------
                                     Maximum interval between patrols
------------------------------------------------------------------------
                                    At highway and       At all other
     Class location of line       railroad crossings        places
------------------------------------------------------------------------
1, 2............................  7\1/2\ months; but  15 months; but at
                                   at least twice      least once each
                                   each calendar       calendar year.
                                   year.
3...............................  4\1/2\ months; but  7\1/2\ months; but
                                   at least four       at least twice
                                   times each          each calendar
                                   calendar year.      year.
4...............................  4\1/2\ months; but  4\1/2\ months; but
                                   at least four       at least four
                                   times each          times each
                                   calendar year.      calendar year.
------------------------------------------------------------------------

    (c) Methods of patrolling include walking, driving, flying or other 
appropriate means of traversing the right-of-way.

[Amdt. 192-21, 40 FR 20283, May 9, 1975, as amended by Amdt. 192-43, 47 
FR 46851, Oct. 21, 1982; Amdt. 192-78, 61 FR 28786, June 6, 1996]



Sec. 192.706  Transmission lines: Leakage surveys.

    Leakage surveys of a transmission line must be conducted at 
intervals not exceeding 15 months, but at least once each calendar year. 
However, in the case of a transmission line which transports gas in 
conformity with Sec. 192.625 without an odor or odorant, leakage 
surveys using leak detector equipment must be conducted--
    (a) In Class 3 locations, at intervals not exceeding 7\1/2\ months, 
but at least twice each calendar year; and
    (b) In Class 4 locations, at intervals not exceeding 4\1/2\ months, 
but at least four times each calendar year.

[Amdt. 192-21, 40 FR 20283, May 9, 1975, as amended by Amdt. 192-43, 47 
FR 46851, Oct. 21, 1982; Amdt. 192-71, 59 FR 6585, Feb. 11, 1994]



Sec. 192.707  Line markers for mains and transmission lines.

    (a) Buried pipelines. Except as provided in paragraph (b) of this 
section, a line marker must be placed and maintained as close as 
practical over each buried main and transmission line:
    (1) At each crossing of a public road and railroad; and
    (2) Wherever necessary to identify the location of the transmission 
line or main to reduce the possibility of damage or interference.
    (b) Exceptions for buried pipelines. Line markers are not required 
for the following pipelines:
    (1) Mains and transmission lines located offshore, or at crossings 
of or under waterways and other bodies of water.
    (2) Mains in Class 3 or Class 4 locations where a damage prevention 
program is in effect under Sec. 192.614.
    (3) Transmission lines in Class 3 or 4 locations until March 20, 
1996.
    (4) Transmission lines in Class 3 or 4 locations where placement of 
a line marker is impractical.
    (c) Pipelines aboveground. Line markers must be placed and 
maintained along each section of a main and transmission line that is 
located aboveground in an area accessible to the public.
    (d) Marker warning. The following must be written legibly on a 
background of sharply contrasting color on each line marker:
    (1) The word ``Warning,'' ``Caution,'' or ``Danger'' followed by the 
words ``Gas (or name of gas transported) Pipeline'' all of which, except 
for markers in heavily developed urban areas, must be in letters at 
least 1 inch (25 millimeters) high with \1/4\ inch (6.4 millimeters) 
stroke.
    (2) The name of the operator and the telephone number (including 
area code) where the operator can be reached at all times.

[Amdt. 192-20, 40 FR 13505, Mar. 27, 1975; Amdt. 192-27, 41 FR 39752, 
Sept. 16, 1976, as amended by Amdt. 192-20A, 41 FR 56808, Dec. 30, 1976; 
Amdt. 192-44, 48 FR 25208, June 6, 1983; Amdt. 192-73, 60 FR 14650, Mar. 
20, 1995; Amdt. 192-85, 63 FR 37504, July 13, 1998]

[[Page 104]]



Sec. 192.709  Transmission lines: Record keeping.

    Each operator shall maintain the following records for transmission 
lines for the periods specified:
    (a) The date, location, and description of each repair made to pipe 
(including pipe-to-pipe connections) must be retained for as long as the 
pipe remains in service.
    (b) The date, location, and description of each repair made to parts 
of the pipeline system other than pipe must be retained for at least 5 
years. However, repairs generated by patrols, surveys, inspections, or 
tests required by subparts L and M of this part must be retained in 
accordance with paragraph (c) of this section.
    (c) A record of each patrol, survey, inspection, and test required 
by subparts L and M of this part must be retained for at least 5 years 
or until the next patrol, survey, inspection, or test is completed, 
whichever is longer.

[Amdt. 192-78, 61 FR 28786, June 6, 1996]



Sec. 192.711  Transmission lines: General requirements for repair 
procedures.

    (a) Each operator shall take immediate temporary measures to protect 
the public whenever:
    (1) A leak, imperfection, or damage that impairs its serviceability 
is found in a segment of steel transmission line operating at or above 
40 percent of the SMYS; and
    (2) It is not feasible to make a permanent repair at the time of 
discovery.

As soon as feasible, the operator shall make permanent repairs.
    (b) Except as provided in Sec. 192.717(b)(3), no operator may use a 
welded patch as a means of repair.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-27B, 45 FR 3272, 
Jan. 17, 1980; Amdt. 192-88, 64 FR 69665, Dec. 14, 1999]



Sec. 192.713  Transmission lines: Permanent field repair of imperfections
and damages.

    (a) Each imperfection or damage that impairs the serviceability of 
pipe in a steel transmission line operating at or above 40 percent of 
SMYS must be--
    (1) Removed by cutting out and replacing a cylindrical piece of 
pipe; or
    (2) Repaired by a method that reliable engineering tests and 
analyses show can permanently restore the serviceability of the pipe.
    (b) Operating pressure must be at a safe level during repair 
operations.

[Amdt. 192-88, 64 FR 69665, Dec. 14, 1999]



Sec. 192.715  Transmission lines: Permanent field repair of welds.

    Each weld that is unacceptable under Sec. 192.241(c) must be 
repaired as follows:
    (a) If it is feasible to take the segment of transmission line out 
of service, the weld must be repaired in accordance with the applicable 
requirements of Sec. 192.245.
    (b) A weld may be repaired in accordance with Sec. 192.245 while 
the segment of transmission line is in service if:
    (1) The weld is not leaking;
    (2) The pressure in the segment is reduced so that it does not 
produce a stress that is more than 20 percent of the SMYS of the pipe; 
and
    (3) Grinding of the defective area can be limited so that at least 
\1/8\-inch (3.2 millimeters) thickness in the pipe weld remains.
    (c) A defective weld which cannot be repaired in accordance with 
paragraph (a) or (b) of this section must be repaired by installing a 
full encirclement welded split sleeve of appropriate design.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37504, 
July 13, 1998]



Sec. 192.717  Transmission lines: Permanent field repair of leaks.

    Each permanent field repair of a leak on a transmission line must be 
made by--
    (a) Removing the leak by cutting out and replacing a cylindrical 
piece of pipe; or
    (b) Repairing the leak by one of the following methods:
    (1) Install a full encirclement welded split sleeve of appropriate 
design, unless the transmission line is joined by mechanical couplings 
and operates at less than 40 percent of SMYS.
    (2) If the leak is due to a corrosion pit, install a properly 
designed bolt-on-leak clamp.
    (3) If the leak is due to a corrosion pit and on pipe of not more 
than 40,000 psi (267 Mpa) SMYS, fillet weld over

[[Page 105]]

the pitted area a steel plate patch with rounded corners, of the same or 
greater thickness than the pipe, and not more than one-half of the 
diameter of the pipe in size.
    (4) If the leak is on a submerged offshore pipeline or submerged 
pipeline in inland navigable waters, mechanically apply a full 
encirclement split sleeve of appropriate design.
    (5) Apply a method that reliable engineering tests and analyses show 
can permanently restore the serviceability of the pipe.

[Amdt. 192-88, 64 FR 69665, Dec. 14, 1999]



Sec. 192.719  Transmission lines: Testing of repairs.

    (a) Testing of replacement pipe. If a segment of transmission line 
is repaired by cutting out the damaged portion of the pipe as a 
cylinder, the replacement pipe must be tested to the pressure required 
for a new line installed in the same location. This test may be made on 
the pipe before it is installed.
    (b) Testing of repairs made by welding. Each repair made by welding 
in accordance with Sec. Sec. 192.713, 192.715, and 192.717 must be 
examined in accordance with Sec. 192.241.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-54, 51 FR 41635, 
Nov. 18, 1986]



Sec. 192.721  Distribution systems: Patrolling.

    (a) The frequency of patrolling mains must be determined by the 
severity of the conditions which could cause failure or leakage, and the 
consequent hazards to public safety.
    (b) Mains in places or on structures where anticipated physical 
movement or external loading could cause failure or leakage must be 
patrolled--
    (1) In business districts, at intervals not exceeding 4\1/2\ months, 
but at least four times each calendar year; and
    (2) Outside business districts, at intervals not exceeding 7\1/2\ 
months, but at least twice each calendar year.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-43, 47 FR 46851, 
Oct. 21, 1982; Amdt. 192-78, 61 FR 28786, June 6, 1996]



Sec. 192.723  Distribution systems: Leakage surveys.

    (a) Each operator of a distribution system shall conduct periodic 
leakage surveys in accordance with this section.
    (b) The type and scope of the leakage control program must be 
determined by the nature of the operations and the local conditions, but 
it must meet the following minimum requirements:
    (1) A leakage survey with leak detector equipment must be conducted 
in business districts, including tests of the atmosphere in gas, 
electric, telephone, sewer, and water system manholes, at cracks in 
pavement and sidewalks, and at other locations providing an opportunity 
for finding gas leaks, at intervals not exceeding 15 months, but at 
least once each calendar year.
    (2) A leakage survey with leak detector equipment must be conducted 
outside business districts as frequently as necessary, but at least once 
every 5 calendar years at intervals not exceeding 63 months. However, 
for cathodically unprotected distribution lines subject to Sec. 
192.465(e) on which electrical surveys for corrosion are impractical, a 
leakage survey must be conducted at least once every 3 calendar years at 
intervals not exceeding 39 months.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-43, 47 FR 46851, 
Oct. 21, 1982; Amdt. 192-70, 58 FR 54528, 54529, Oct. 22, 1993; Amdt. 
192-71, 59 FR 6585, Feb. 11, 1994; Amdt. 192-94, 69 FR 32895, June 14, 
2004; Amdt. 192-94, 69 FR 54592, Sept. 9, 2004]



Sec. 192.725  Test requirements for reinstating service lines.

    (a) Except as provided in paragraph (b) of this section, each 
disconnected service line must be tested in the same manner as a new 
service line, before being reinstated.
    (b) Each service line temporarily disconnected from the main must be 
tested from the point of disconnection to the service line valve in the 
same manner as a new service line, before reconnecting. However, if 
provisions are made to maintain continuous service, such as by 
installation of a bypass, any part of the original service line used to 
maintain continuous service need not be tested.

[[Page 106]]



Sec. 192.727  Abandonment or deactivation of facilities.

    (a) Each operator shall conduct abandonment or deactivation of 
pipelines in accordance with the requirements of this section.
    (b) Each pipeline abandoned in place must be disconnected from all 
sources and supplies of gas; purged of gas; in the case of offshore 
pipelines, filled with water or inert materials; and sealed at the ends. 
However, the pipeline need not be purged when the volume of gas is so 
small that there is no potential hazard.
    (c) Except for service lines, each inactive pipeline that is not 
being maintained under this part must be disconnected from all sources 
and supplies of gas; purged of gas; in the case of offshore pipelines, 
filled with water or inert materials; and sealed at the ends. However, 
the pipeline need not be purged when the volume of gas is so small that 
there is no potential hazard.
    (d) Whenever service to a customer is discontinued, one of the 
following must be complied with:
    (1) The valve that is closed to prevent the flow of gas to the 
customer must be provided with a locking device or other means designed 
to prevent the opening of the valve by persons other than those 
authorized by the operator.
    (2) A mechanical device or fitting that will prevent the flow of gas 
must be installed in the service line or in the meter assembly.
    (3) The customer's piping must be physically disconnected from the 
gas supply and the open pipe ends sealed.
    (e) If air is used for purging, the operator shall insure that a 
combustible mixture is not present after purging.
    (f) Each abandoned vault must be filled with a suitable compacted 
material.
    (g) 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.
    (1) The preferred method to submit data on pipeline facilities 
abandoned after October 10, 2000 is to the National Pipeline Mapping 
System (NPMS) in accordance with the NPMS ``Standards for Pipeline and 
Liquefied Natural Gas Operator Submissions.'' To obtain a copy of the 
NPMS Standards, please refer to the NPMS homepage at http://
www.npms.phmsa.dot.gov or contact the NPMS National Repository at 703-
317-3073. A digital data format is preferred, but hard copy submissions 
are acceptable if they comply with the NPMS Standards. In addition to 
the NPMS-required attributes, operators must submit the date of 
abandonment, diameter, method of abandonment, and certification that, to 
the best of the operator's knowledge, all of the reasonably available 
information requested was provided and, to the best of the operator's 
knowledge, the abandonment was completed in accordance with applicable 
laws. Refer to the NPMS Standards for details in preparing your data for 
submission. The NPMS Standards also include details of how to submit 
data. Alternatively, operators may submit reports by mail, fax or e-mail 
to the Office of Pipeline Safety, Pipeline and Hazardous Materials 
Safety Administration, U.S. Department of Transportation, Information 
Resources Manager, PHP-10, 1200 New Jersey Avenue, SE., Washington, DC 
20590-0001; fax (202) 366-4566; e-mail 
InformationResourcesManager@phmsa.

dot.gov. The information in the report must contain all reasonably 
available information related to the facility, including information in 
the possession of a third party. The report must contain the location, 
size, date, method of abandonment, and a certification that the facility 
has been abandoned in accordance with all applicable laws.
    (2) [Reserved]

[Amdt. 192-8, 37 FR 20695, Oct. 3, 1972, as amended by Amdt. 192-27, 41 
FR 34607, Aug. 16, 1976; Amdt. 192-71, 59 FR 6585, Feb. 11, 1994; Amdt. 
192-89, 65 FR 54443, Sept. 8, 2000; 65 FR 57861, Sept. 26, 2000; 70 FR 
11139, Mar. 8, 2005; Amdt. 192-103, 72 FR 4656, Feb. 1, 2007; 73 FR 
16570, Mar. 28, 2008; 74 FR 2894, Jan. 16, 2009]



Sec. 192.731  Compressor stations: Inspection and testing of relief
devices.

    (a) Except for rupture discs, each pressure relieving device in a 
compressor station must be inspected and tested in accordance with 
Sec. Sec. 192.739 and

[[Page 107]]

192.743, and must be operated periodically to determine that it opens at 
the correct set pressure.
    (b) Any defective or inadequate equipment found must be promptly 
repaired or replaced.
    (c) Each remote control shutdown device must be inspected and tested 
at intervals not exceeding 15 months, but at least once each calendar 
year, to determine that it functions properly.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-43, 47 FR 46851, 
Oct. 21, 1982]



Sec. 192.735  Compressor stations: Storage of combustible materials.

    (a) Flammable or combustible materials in quantities beyond those 
required for everyday use, or other than those normally used in 
compressor buildings, must be stored a safe distance from the compressor 
building.
    (b) Aboveground oil or gasoline storage tanks must be protected in 
accordance with National Fire Protection Association Standard No. 30.



Sec. 192.736  Compressor stations: Gas detection.

    (a) Not later than September 16, 1996, each compressor building in a 
compressor station must have a fixed gas detection and alarm system, 
unless the building is--
    (1) Constructed so that at least 50 percent of its upright side area 
is permanently open; or
    (2) Located in an unattended field compressor station of 1,000 
horsepower (746 kW) or less.
    (b) Except when shutdown of the system is necessary for maintenance 
under paragraph (c) of this section, each gas detection and alarm system 
required by this section must--
    (1) Continuously monitor the compressor building for a concentration 
of gas in air of not more than 25 percent of the lower explosive limit; 
and
    (2) If that concentration of gas is detected, warn persons about to 
enter the building and persons inside the building of the danger.
    (c) Each gas detection and alarm system required by this section 
must be maintained to function properly. The maintenance must include 
performance tests.

[58 FR 48464, Sept. 16, 1993, as amended by Amdt. 192-85, 63 FR 37504, 
July 13, 1998]



Sec. 192.739  Pressure limiting and regulating stations: Inspection and
testing.

    (a) Each pressure limiting station, relief device (except rupture 
discs), and pressure regulating station and its equipment must be 
subjected at intervals not exceeding 15 months, but at least once each 
calendar year, to inspections and tests to determine that it is--
    (1) In good mechanical condition;
    (2) Adequate from the standpoint of capacity and reliability of 
operation for the service in which it is employed;
    (3) Except as provided in paragraph (b) of this section, set to 
control or relieve at the correct pressure consistent with the pressure 
limits of Sec. 192.201(a); and
    (4) Properly installed and protected from dirt, liquids, or other 
conditions that might prevent proper operation.
    (b) For steel pipelines whose MAOP is determined under Sec. 
192.619(c), if the MAOP is 60 psi (414 kPa) gage or more, the control or 
relief pressure limit is as follows:

------------------------------------------------------------------------
  If the MAOP produces a hoop stress that
                    is:                      Then the pressure limit is:
------------------------------------------------------------------------
Greater than 72 percent of SMYS...........  MAOP plus 4 percent.
Unknown as a percentage of SMYS...........  A pressure that will prevent
                                             unsafe operation of the
                                             pipeline considering its
                                             operating and maintenance
                                             history and MAOP.
------------------------------------------------------------------------


[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-43, 47 FR 46851, 
Oct. 21, 1982; Amdt. 192-93, 68 FR 53901, Sept. 15, 2003; Amdt. 192-96, 
69 FR 27863, May 17, 2004]



Sec. 192.741  Pressure limiting and regulating stations: Telemetering or 
recording gauges.

    (a) Each distribution system supplied by more than one district 
pressure regulating station must be equipped with telemetering or 
recording pressure gauges to indicate the gas pressure in the district.
    (b) On distribution systems supplied by a single district pressure 
regulating station, the operator shall determine

[[Page 108]]

the necessity of installing telemetering or recording gauges in the 
district, taking into consideration the number of customers supplied, 
the operating pressures, the capacity of the installation, and other 
operating conditions.
    (c) If there are indications of abnormally high or low pressure, the 
regulator and the auxiliary equipment must be inspected and the 
necessary measures employed to correct any unsatisfactory operating 
conditions.



Sec. 192.743  Pressure limiting and regulating stations: Capacity of 
relief devices.

    (a) Pressure relief devices at pressure limiting stations and 
pressure regulating stations must have sufficient capacity to protect 
the facilities to which they are connected. Except as provided in Sec. 
192.739(b), the capacity must be consistent with the pressure limits of 
Sec. 192.201(a). This capacity must be determined at intervals not 
exceeding 15 months, but at least once each calendar year, by testing 
the devices in place or by review and calculations.
    (b) If review and calculations are used to determine if a device has 
sufficient capacity, the calculated capacity must be compared with the 
rated or experimentally determined relieving capacity of the device for 
the conditions under which it operates. After the initial calculations, 
subsequent calculations need not be made if the annual review documents 
that parameters have not changed to cause the rated or experimentally 
determined relieving capacity to be insufficient.
    (c) If a relief device is of insufficient capacity, a new or 
additional device must be installed to provide the capacity required by 
paragraph (a) of this section.

[Amdt. 192-93, 68 FR 53901, Sept. 15, 2003, as amended by Amdt. 192-96, 
69 FR 27863, May 17, 2004]



Sec. 192.745  Valve maintenance: Transmission lines.

    (a) Each transmission line valve that might be required during any 
emergency must be inspected and partially operated at intervals not 
exceeding 15 months, but at least once each calendar year.
    (b) Each operator must take prompt remedial action to correct any 
valve found inoperable, unless the operator designates an alternative 
valve.

[Amdt. 192-43, 47 FR 46851, Oct. 21, 1982, as amended by Amdt. 192-93, 
68 FR 53901, Sept. 15, 2003]



Sec. 192.747  Valve maintenance: Distribution systems.

    (a) Each valve, the use of which may be necessary for the safe 
operation of a distribution system, must be checked and serviced at 
intervals not exceeding 15 months, but at least once each calendar year.
    (b) Each operator must take prompt remedial action to correct any 
valve found inoperable, unless the operator designates an alternative 
valve.

[Amdt. 192-43, 47 FR 46851, Oct. 21, 1982, as amended by Amdt. 192-93, 
68 FR 53901, Sept. 15, 2003]



Sec. 192.749  Vault maintenance.

    (a) Each vault housing pressure regulating and pressure limiting 
equipment, and having a volumetric internal content of 200 cubic feet 
(5.66 cubic meters) or more, must be inspected at intervals not 
exceeding 15 months, but at least once each calendar year, to determine 
that it is in good physical condition and adequately ventilated.
    (b) If gas is found in the vault, the equipment in the vault must be 
inspected for leaks, and any leaks found must be repaired.
    (c) The ventilating equipment must also be inspected to determine 
that it is functioning properly.
    (d) Each vault cover must be inspected to assure that it does not 
present a hazard to public safety.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-43, 47 FR 46851, 
Oct. 21, 1982; Amdt. 192-85, 63 FR 37504, July 13, 1998]



Sec. 192.751  Prevention of accidental ignition.

    Each operator shall take steps to minimize the danger of accidental 
ignition of gas in any structure or area where the presence of gas 
constitutes a hazard of fire or explosion, including the following:

[[Page 109]]

    (a) When a hazardous amount of gas is being vented into open air, 
each potential source of ignition must be removed from the area and a 
fire extinguisher must be provided.
    (b) Gas or electric welding or cutting may not be performed on pipe 
or on pipe components that contain a combustible mixture of gas and air 
in the area of work.
    (c) Post warning signs, where appropriate.



Sec. 192.753  Caulked bell and spigot joints.

    (a) Each cast iron caulked bell and spigot joint that is subject to 
pressures of more than 25 psi (172kPa) gage must be sealed with:
    (1) A mechanical leak clamp; or
    (2) A material or device which:
    (i) Does not reduce the flexibility of the joint;
    (ii) Permanently bonds, either chemically or mechanically, or both, 
with the bell and spigot metal surfaces or adjacent pipe metal surfaces; 
and
    (iii) Seals and bonds in a manner that meets the strength, 
environmental, and chemical compatibility requirements of Sec. Sec. 
192.53 (a) and (b) and 192.143.
    (b) Each cast iron caulked bell and spigot joint that is subject to 
pressures of 25 psi (172kPa) gage or less and is exposed for any reason 
must be sealed by a means other than caulking.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-25, 41 FR 23680, 
June 11, 1976; Amdt. 192-85, 63 FR 37504, July 13, 1998; Amdt. 192-93, 
68 FR 53901, Sept. 15, 2003]



Sec. 192.755  Protecting cast-iron pipelines.

    When an operator has knowledge that the support for a segment of a 
buried cast-iron pipeline is disturbed:
    (a) That segment of the pipeline must be protected, as necessary, 
against damage during the disturbance by:
    (1) Vibrations from heavy construction equipment, trains, trucks, 
buses, or blasting;
    (2) Impact forces by vehicles;
    (3) Earth movement;
    (4) Apparent future excavations near the pipeline; or
    (5) Other foreseeable outside forces which may subject that segment 
of the pipeline to bending stress.
    (b) As soon as feasible, appropriate steps must be taken to provide 
permanent protection for the disturbed segment from damage that might 
result from external loads, including compliance with applicable 
requirements of Sec. Sec. 192.317(a), 192.319, and 192.361(b)-(d).

[Amdt. 192-23, 41 FR 13589, Mar. 31, 1976]



              Subpart N_Qualification of Pipeline Personnel

    Source: Amdt. 192-86, 64 FR 46865, Aug. 27, 1999, unless otherwise 
noted.



Sec. 192.801  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.



Sec. 192.803  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

[[Page 110]]

    (b) Recognize and react to abnormal operating conditions.

[Amdt. 192-86, 64 FR 46865, Aug. 27, 1999, as amended by Amdt. 192-90, 
66 FR 43523, Aug. 20, 2001]



Sec. 192.805  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 
incident as defined in Part 191;
    (e) Evaluate an individual if the operator has reason to believe 
that the individual is no longer qualified to perform a covered task;
    (f) Communicate changes that affect covered tasks to individuals 
performing those covered tasks;
    (g) Identify those covered tasks and the intervals at which 
evaluation of the individual's qualifications is needed;
    (h) After December 16, 2004, provide training, as appropriate, to 
ensure that individuals performing covered tasks have the necessary 
knowledge and skills to perform the tasks in a manner that ensures the 
safe operation of pipeline facilities; and
    (i) After December 16, 2004, notify the Administrator or a state 
agency participating under 49 U.S.C. Chapter 601 if the operator 
significantly modifies the program after the Administrator or state 
agency has verified that it complies with this section.

[ Amdt. 192-86, 64 FR 46865, Aug. 27, 1999, as amended by Amdt. 192-100, 
70 FR 10335, Mar. 3, 2005]



Sec. 192.807  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.



Sec. 192.809  General.

    (a) Operators must have a written qualification program by April 27, 
2001. The program must be available for review by the Administrator or 
by a state agency participating under 49 U.S.C. Chapter 601 if the 
program is under the authority of that state agency.
    (b) Operators must complete the qualification of individuals 
performing covered tasks by October 28, 2002.
    (c) Work performance history review may be used as a sole evaluation 
method for individuals who were performing a covered task prior to 
October 26, 1999.
    (d) After October 28, 2002, work performance history may not be used 
as a sole evaluation method.
    (e) After December 16, 2004, observation of on-the-job performance 
may not be used as the sole method of evaluation.

[Amdt. 192-86, 64 FR 46865, Aug. 27, 1999, as amended by Amdt. 192-90, 
66 FR 43524, Aug. 20, 2001; Amdt. 192-100, 70 FR 10335, Mar. 3, 2005]



        Subpart O_Gas Transmission Pipeline Integrity Management

    Source: 68 FR 69817, Dec. 15, 2003, unless otherwise noted.



Sec. 192.901  What do the regulations in this subpart cover?

    This subpart prescribes minimum requirements for an integrity 
management program on any gas transmission pipeline covered under this 
part. For gas transmission pipelines constructed of plastic, only the 
requirements in

[[Page 111]]

Sec. Sec. 192.917, 192.921, 192.935 and 192.937 apply.



Sec. 192.903  What definitions apply to this subpart?

    The following definitions apply to this subpart:
    Assessment is the use of testing techniques as allowed in this 
subpart to ascertain the condition of a covered pipeline segment.
    Confirmatory direct assessment is an integrity assessment method 
using more focused application of the principles and techniques of 
direct assessment to identify internal and external corrosion in a 
covered transmission pipeline segment.
    Covered segment or covered pipeline segment means a segment of gas 
transmission pipeline located in a high consequence area. The terms gas 
and transmission line are defined in Sec. 192.3.
    Direct assessment is an integrity assessment method that utilizes a 
process to evaluate certain threats (i.e., external corrosion, internal 
corrosion and stress corrosion cracking) to a covered 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.
    High consequence area means an area established by one of the 
methods described in paragraphs (1) or (2) as follows:
    (1) An area defined as--
    (i) A Class 3 location under Sec. 192.5; or
    (ii) A Class 4 location under Sec. 192.5; or
    (iii) Any area in a Class 1 or Class 2 location where the potential 
impact radius is greater than 660 feet (200 meters), and the area within 
a potential impact circle contains 20 or more buildings intended for 
human occupancy; or
    (iv) Any area in a Class 1 or Class 2 location where the potential 
impact circle contains an identified site.
    (2) The area within a potential impact circle containing--
    (i) 20 or more buildings intended for human occupancy, unless the 
exception in paragraph (4) applies; or
    (ii) An identified site.
    (3) Where a potential impact circle is calculated under either 
method (1) or (2) to establish a high consequence area, the length of 
the high consequence area extends axially along the length of the 
pipeline from the outermost edge of the first potential impact circle 
that contains either an identified site or 20 or more buildings intended 
for human occupancy to the outermost edge of the last contiguous 
potential impact circle that contains either an identified site or 20 or 
more buildings intended for human occupancy. (See figure E.I.A. in 
appendix E.)
    (4) If in identifying a high consequence area under paragraph 
(1)(iii) of this definition or paragraph (2)(i) of this definition, the 
radius of the potential impact circle is greater than 660 feet (200 
meters), the operator may identify a high consequence area based on a 
prorated number of buildings intended for human occupancy with a 
distance of 660 feet (200 meters) from the centerline of the pipeline 
until December 17, 2006. If an operator chooses this approach, the 
operator must prorate the number of buildings intended for human 
occupancy based on the ratio of an area with a radius of 660 feet (200 
meters) to the area of the potential impact circle (i.e., the prorated 
number of buildings intended for human occupancy is equal to 20 x (660 
feet) [or 200 meters]/potential impact radius in feet [or meters] \2\).
    Identified site means each of the following areas:
    (a) An outside area or open structure that is occupied by twenty 
(20) or more persons on at least 50 days in any twelve (12)-month 
period. (The days need not be consecutive.) Examples include but are not 
limited to, beaches, playgrounds, recreational facilities, camping 
grounds, outdoor theaters, stadiums, recreational areas near a body of 
water, or areas outside a rural building such as a religious facility; 
or
    (b) A building that is occupied by twenty (20) or more persons on at 
least five (5) days a week for ten (10) weeks in any twelve (12)-month 
period. (The days and weeks need not be consecutive.) Examples include, 
but are not limited to, religious facilities, office buildings, 
community centers, general

[[Page 112]]

stores, 4-H facilities, or roller skating rinks; or
    (c) A facility occupied by persons who are confined, are of impaired 
mobility, or would be difficult to evacuate. Examples include but are 
not limited to hospitals, prisons, schools, day-care facilities, 
retirement facilities or assisted-living facilities.
    Potential impact circle is a circle of radius equal to the potential 
impact radius (PIR).
    Potential impact radius (PIR) means the radius of a circle within 
which the potential failure of a pipeline could have significant impact 
on people or property. PIR is determined by the formula r = 0.69* 
(square root of (p*d \2\)), where `r' is the radius of a circular area 
in feet surrounding the point of failure, `p' is the maximum allowable 
operating pressure (MAOP) in the pipeline segment in pounds per square 
inch and `d' is the nominal diameter of the pipeline in inches.
    Note: 0.69 is the factor for natural gas. This number will vary for 
other gases depending upon their heat of combustion. An operator 
transporting gas other than natural gas must use section 3.2 of ASME/
ANSI B31.8S-2001 (Supplement to ASME B31.8; incorporated by reference, 
see Sec. 192.7) to calculate the impact radius formula.
    Remediation is a repair or mitigation activity an operator takes on 
a covered segment to limit or reduce the probability of an undesired 
event occurring or the expected consequences from the event.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18231, 
Apr. 6, 2004; Amdt. 192-95, 69 FR 29904, May 26, 2004; Amdt. 192-103, 72 
FR 4657, Feb. 1, 2007]



Sec. 192.905  How does an operator identify a high consequence area?

    (a) General. To determine which segments of an operator's 
transmission pipeline system are covered by this subpart, an operator 
must identify the high consequence areas. An operator must use method 
(1) or (2) from the definition in Sec. 192.903 to identify a high 
consequence area. An operator may apply one method to its entire 
pipeline system, or an operator may apply one method to individual 
portions of the pipeline system. An operator must describe in its 
integrity management program which method it is applying to each portion 
of the operator's pipeline system. The description must include the 
potential impact radius when utilized to establish a high consequence 
area. (See appendix E.I. for guidance on identifying high consequence 
areas.)
    (b)(1) Identified sites. An operator must identify an identified 
site, for purposes of this subpart, from information the operator has 
obtained from routine operation and maintenance activities and from 
public officials with safety or emergency response or planning 
responsibilities who indicate to the operator that they know of 
locations that meet the identified site criteria. These public officials 
could include officials on a local emergency planning commission or 
relevant Native American tribal officials.
    (2) If a public official with safety or emergency response or 
planning responsibilities informs an operator that it does not have the 
information to identify an identified site, the operator must use one of 
the following sources, as appropriate, to identify these sites.
    (i) Visible marking (e.g., a sign); or
    (ii) The site is licensed or registered by a Federal, State, or 
local government agency; or
    (iii) The site is on a list (including a list on an internet web 
site) or map maintained by or available from a Federal, State, or local 
government agency and available to the general public.
    (c) Newly identified areas. When an operator has information that 
the area around a pipeline segment not previously identified as a high 
consequence area could satisfy any of the definitions in Sec. 192.903, 
the operator must complete the evaluation using method (1) or (2). If 
the segment is determined to meet the definition as a high consequence 
area, it must be incorporated into the operator's baseline assessment 
plan as a high consequence area within one year from the date the area 
is identified.



Sec. 192.907  What must an operator do to implement this subpart?

    (a) General. No later than December 17, 2004, an operator of a 
covered pipeline segment must develop and follow a written integrity 
management program that contains all the elements described in Sec. 
192.911 and that addresses

[[Page 113]]

the risks on each covered transmission pipeline segment. The initial 
integrity management program must consist, at a minimum, of a framework 
that describes the process for implementing each program element, how 
relevant decisions will be made and by whom, a time line for completing 
the work to implement the program element, and how information gained 
from experience will be continuously incorporated into the program. The 
framework will evolve into a more detailed and comprehensive program. An 
operator must make continual improvements to the program.
    (b) Implementation Standards. In carrying out this subpart, an 
operator must follow the requirements of this subpart and of ASME/ANSI 
B31.8S (incorporated by reference, see Sec. 192.7) and its appendices, 
where specified. An operator may follow an equivalent standard or 
practice only when the operator demonstrates the alternative standard or 
practice provides an equivalent level of safety to the public and 
property. In the event of a conflict between this subpart and ASME/ANSI 
B31.8S, the requirements in this subpart control.



Sec. 192.909  How can an operator change its integrity management 
program?

    (a) General. An operator must document any change to its program and 
the reasons for the change before implementing the change.
    (b) Notification. An operator must notify OPS, in accordance with 
Sec. 192.949, of any change to the program that may substantially 
affect the program's implementation or may significantly modify the 
program or schedule for carrying out the program elements. An operator 
must also notify a State or local pipeline safety authority when either 
a covered segment is located in a State where OPS has an interstate 
agent agreement, or an intrastate covered segment is regulated by that 
State. An operator must provide the notification within 30 days after 
adopting this type of change into its program.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18231, 
Apr. 6, 2004]



Sec. 192.911  What are the elements of an integrity management program?

    An operator's initial integrity management program begins with a 
framework (see Sec. 192.907) and evolves into a more detailed and 
comprehensive integrity management program, as information is gained and 
incorporated into the program. An operator must make continual 
improvements to its program. The initial program framework and 
subsequent program must, at minimum, contain the following elements. 
(When indicated, refer to ASME/ANSI B31.8S (incorporated by reference, 
see Sec. 192.7) for more detailed information on the listed element.)
    (a) An identification of all high consequence areas, in accordance 
with Sec. 192.905.
    (b) A baseline assessment plan meeting the requirements of Sec. 
192.919 and Sec. 192.921.
    (c) An identification of threats to each covered pipeline segment, 
which must include data integration and a risk assessment. An operator 
must use the threat identification and risk assessment to prioritize 
covered segments for assessment (Sec. 192.917) and to evaluate the 
merits of additional preventive and mitigative measures (Sec. 192.935) 
for each covered segment.
    (d) A direct assessment plan, if applicable, meeting the 
requirements of Sec. 192.923, and depending on the threat assessed, of 
Sec. Sec. 192.925, 192.927, or 192.929.
    (e) Provisions meeting the requirements of Sec. 192.933 for 
remediating conditions found during an integrity assessment.
    (f) A process for continual evaluation and assessment meeting the 
requirements of Sec. 192.937.
    (g) If applicable, a plan for confirmatory direct assessment meeting 
the requirements of Sec. 192.931.
    (h) Provisions meeting the requirements of Sec. 192.935 for adding 
preventive and mitigative measures to protect the high consequence area.
    (i) A performance plan as outlined in ASME/ANSI B31.8S, section 9 
that includes performance measures meeting the requirements of Sec. 
192.945.
    (j) Record keeping provisions meeting the requirements of Sec. 
192.947.

[[Page 114]]

    (k) A management of change process as outlined in ASME/ANSI B31.8S, 
section 11.
    (l) A quality assurance process as outlined in ASME/ANSI B31.8S, 
section 12.
    (m) A communication plan that includes the elements of ASME/ANSI 
B31.8S, section 10, and that includes procedures for addressing safety 
concerns raised by--
    (1) OPS; and
    (2) A State or local pipeline safety authority when a covered 
segment is located in a State where OPS has an interstate agent 
agreement.
    (n) Procedures for providing (when requested), by electronic or 
other means, a copy of the operator's risk analysis or integrity 
management program to--
    (1) OPS; and
    (2) A State or local pipeline safety authority when a covered 
segment is located in a State where OPS has an interstate agent 
agreement.
    (o) Procedures for ensuring that each integrity assessment is being 
conducted in a manner that minimizes environmental and safety risks.
    (p) A process for identification and assessment of newly-identified 
high consequence areas. (See Sec. 192.905 and Sec. 192.921.)

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18231, 
Apr. 6, 2004]



Sec. 192.913  When may an operator deviate its program from certain 
requirements of this subpart?

    (a) General. ASME/ANSI B31.8S (incorporated by reference, see Sec. 
192.7) provides the essential features of a performance-based or a 
prescriptive integrity management program. An operator that uses a 
performance-based approach that satisfies the requirements for 
exceptional performance in paragraph (b) of this section may deviate 
from certain requirements in this subpart, as provided in paragraph (c) 
of this section.
    (b) Exceptional performance. An operator must be able to demonstrate 
the exceptional performance of its integrity management program through 
the following actions.
    (1) To deviate from any of the requirements set forth in paragraph 
(c) of this section, an operator must have a performance-based integrity 
management program that meets or exceed the performance-based 
requirements of ASME/ANSI B31.8S and includes, at a minimum, the 
following elements--
    (i) A comprehensive process for risk analysis;
    (ii) All risk factor data used to support the program;
    (iii) A comprehensive data integration process;
    (iv) A procedure for applying lessons learned from assessment of 
covered pipeline segments to pipeline segments not covered by this 
subpart;
    (v) A procedure for evaluating every incident, including its cause, 
within the operator's sector of the pipeline industry for implications 
both to the operator's pipeline system and to the operator's integrity 
management program;
    (vi) A performance matrix that demonstrates the program has been 
effective in ensuring the integrity of the covered segments by 
controlling the identified threats to the covered segments;
    (vii) Semi-annual performance measures beyond those required in 
Sec. 192.945 that are part of the operator's performance plan. (See 
Sec. 192.911(i).) An operator must submit these measures, by electronic 
or other means, on a semi-annual frequency to OPS in accordance with 
Sec. 192.951; and
    (viii) An analysis that supports the desired integrity reassessment 
interval and the remediation methods to be used for all covered 
segments.
    (2) In addition to the requirements for the performance-based plan, 
an operator must--
    (i) Have completed at least two integrity assessments on each 
covered pipeline segment the operator is including under the 
performance-based approach, and be able to demonstrate that each 
assessment effectively addressed the identified threats on the covered 
segment.
    (ii) Remediate all anomalies identified in the more recent 
assessment according to the requirements in Sec. 192.933, and 
incorporate the results and lessons learned from the more recent 
assessment into the operator's data integration and risk assessment.

[[Page 115]]

    (c) Deviation. Once an operator has demonstrated that it has 
satisfied the requirements of paragraph (b) of this section, the 
operator may deviate from the prescriptive requirements of ASME/ANSI 
B31.8S and of this subpart only in the following instances.
    (1) The time frame for reassessment as provided in Sec. 192.939 
except that reassessment by some method allowed under this subpart 
(e.g., confirmatory direct assessment) must be carried out at intervals 
no longer than seven years;
    (2) The time frame for remediation as provided in Sec. 192.933 if 
the operator demonstrates the time frame will not jeopardize the safety 
of the covered segment.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18231, 
Apr. 6, 2004]



Sec. 192.915  What knowledge and training must personnel have to 
carry out an integrity management program?

    (a) Supervisory personnel. The integrity management program must 
provide that each supervisor whose responsibilities relate to the 
integrity management program possesses and maintains a thorough 
knowledge of the integrity management program and of the elements for 
which the supervisor is responsible. The program must provide that any 
person who qualifies as a supervisor for the integrity management 
program has appropriate training or experience in the area for which the 
person is responsible.
    (b) Persons who carry out assessments and evaluate assessment 
results. The integrity management program must provide criteria for the 
qualification of any person--
    (1) Who conducts an integrity assessment allowed under this subpart; 
or
    (2) Who reviews and analyzes the results from an integrity 
assessment and evaluation; or
    (3) Who makes decisions on actions to be taken based on these 
assessments.
    (c) Persons responsible for preventive and mitigative measures. The 
integrity management program must provide criteria for the qualification 
of any person--
    (1) Who implements preventive and mitigative measures to carry out 
this subpart, including the marking and locating of buried structures; 
or
    (2) Who directly supervises excavation work carried out in 
conjunction with an integrity assessment.



Sec. 192.917  How does an operator identify potential threats to
pipeline integrity and use the threat identification in its 

integrity program?

    (a) Threat identification. An operator must identify and evaluate 
all potential threats to each covered pipeline segment. Potential 
threats that an operator must consider include, but are not limited to, 
the threats listed in ASME/ANSI B31.8S (incorporated by reference, see 
Sec. 192.7), section 2, which are grouped under the following four 
categories:
    (1) Time dependent threats such as internal corrosion, external 
corrosion, and stress corrosion cracking;
    (2) Static or resident threats, such as fabrication or construction 
defects;
    (3) Time independent threats such as third party damage and outside 
force damage; and
    (4) Human error.
    (b) Data gathering and integration. To identify and evaluate the 
potential threats to a covered pipeline segment, an operator must gather 
and integrate existing data and information on the entire pipeline that 
could be relevant to the covered segment. In performing this data 
gathering and integration, an operator must follow the requirements in 
ASME/ANSI B31.8S, section 4. At a minimum, an operator must gather and 
evaluate the set of data specified in Appendix A to ASME/ANSI B31.8S, 
and consider both on the covered segment and similar non-covered 
segments, past incident history, corrosion control records, continuing 
surveillance records, patrolling records, maintenance history, internal 
inspection records and all other conditions specific to each pipeline.
    (c) Risk assessment. An operator must conduct a risk assessment that 
follows ASME/ANSI B31.8S, section 5, and considers the identified 
threats for each covered segment. An operator must use the risk 
assessment to prioritize the covered segments for the baseline and 
continual reassessments (Sec. Sec. 192.919, 192.921, 192.937), and to 
determine what

[[Page 116]]

additional preventive and mitigative measures are needed (Sec. 192.935) 
for the covered segment.
    (d) Plastic transmission pipeline. An operator of a plastic 
transmission pipeline must assess the threats to each covered segment 
using the information in sections 4 and 5 of ASME B31.8S, and consider 
any threats unique to the integrity of plastic pipe.
    (e) Actions to address particular threats. If an operator identifies 
any of the following threats, the operator must take the following 
actions to address the threat.
    (1) Third party damage. An operator must utilize the data 
integration required in paragraph (b) of this section and ASME/ANSI 
B31.8S, Appendix A7 to determine the susceptibility of each covered 
segment to the threat of third party damage. If an operator identifies 
the threat of third party damage, the operator must implement 
comprehensive additional preventive measures in accordance with Sec. 
192.935 and monitor the effectiveness of the preventive measures. If, in 
conducting a baseline assessment under Sec. 192.921, or a reassessment 
under Sec. 192.937, an operator uses an internal inspection tool or 
external corrosion direct assessment, the operator must integrate data 
from these assessments with data related to any encroachment or foreign 
line crossing on the covered segment, to define where potential 
indications of third party damage may exist in the covered segment.
    An operator must also have procedures in its integrity management 
program addressing actions it will take to respond to findings from this 
data integration.
    (2) Cyclic fatigue. An operator must evaluate whether cyclic fatigue 
or other loading condition (including ground movement, suspension bridge 
condition) could lead to a failure of a deformation, including a dent or 
gouge, or other defect in the covered segment. An evaluation must assume 
the presence of threats in the covered segment that could be exacerbated 
by cyclic fatigue. An operator must use the results from the evaluation 
together with the criteria used to evaluate the significance of this 
threat to the covered segment to prioritize the integrity baseline 
assessment or reassessment.
    (3) Manufacturing and construction defects. If an operator 
identifies the threat of manufacturing and construction defects 
(including seam defects) in the covered segment, an operator must 
analyze the covered segment to determine the risk of failure from these 
defects. The analysis must consider the results of prior assessments on 
the covered segment. An operator may consider manufacturing and 
construction related defects to be stable defects if the operating 
pressure on the covered segment has not increased over the maximum 
operating pressure experienced during the five years preceding 
identification of the high consequence area. If any of the following 
changes occur in the covered segment, an operator must prioritize the 
covered segment as a high risk segment for the baseline assessment or a 
subsequent reassessment.
    (i) Operating pressure increases above the maximum operating 
pressure experienced during the preceding five years;
    (ii) MAOP increases; or
    (iii) The stresses leading to cyclic fatigue increase.
    (4) ERW pipe. If a covered pipeline segment contains low frequency 
electric resistance welded pipe (ERW), lap welded pipe or other pipe 
that satisfies the conditions specified in ASME/ANSI B31.8S, Appendices 
A4.3 and A4.4, and any covered or noncovered segment in the pipeline 
system with such pipe has experienced seam failure, or operating 
pressure on the covered segment has increased over the maximum operating 
pressure experienced during the preceding five years, an operator must 
select an assessment technology or technologies with a proven 
application capable of assessing seam integrity and seam corrosion 
anomalies. The operator must prioritize the covered segment as a high 
risk segment for the baseline assessment or a subsequent reassessment.
    (5) Corrosion. If an operator identifies corrosion on a covered 
pipeline segment that could adversely affect the integrity of the line 
(conditions specified in Sec. 192.933), the operator must evaluate and 
remediate, as necessary,

[[Page 117]]

all pipeline segments (both covered and non-covered) with similar 
material coating and environmental characteristics. An operator must 
establish a schedule for evaluating and remediating, as necessary, the 
similar segments that is consistent with the operator's established 
operating and maintenance procedures under part 192 for testing and 
repair.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18231, 
Apr. 6, 2004]



Sec. 192.919  What must be in the baseline assessment plan?

    An operator must include each of the following elements in its 
written baseline assessment plan:
    (a) Identification of the potential threats to each covered pipeline 
segment and the information supporting the threat identification. (See 
Sec. 192.917.);
    (b) The methods selected to assess the integrity of the line pipe, 
including an explanation of why the assessment method was selected to 
address the identified threats to each covered segment. The integrity 
assessment method an operator uses must be based on the threats 
identified to the covered segment. (See Sec. 192.917.) More than one 
method may be required to address all the threats to the covered 
pipeline segment;
    (c) A schedule for completing the integrity assessment of all 
covered segments, including risk factors considered in establishing the 
assessment schedule;
    (d) If applicable, a direct assessment plan that meets the 
requirements of Sec. Sec. 192.923, and depending on the threat to be 
addressed, of Sec. 192.925, Sec. 192.927, or Sec. 192.929; and
    (e) A procedure to ensure that the baseline assessment is being 
conducted in a manner that minimizes environmental and safety risks.



Sec. 192.921  How is the baseline assessment to be conducted?

    (a) Assessment methods. An operator must assess the integrity of the 
line pipe in each covered segment by applying one or more of the 
following methods depending on the threats to which the covered segment 
is susceptible. An operator must select the method or methods best 
suited to address the threats identified to the covered segment (See 
Sec. 192.917).
    (1) Internal inspection tool or tools capable of detecting 
corrosion, and any other threats to which the covered segment is 
susceptible. An operator must follow ASME/ANSI B31.8S (incorporated by 
reference, see Sec. 192.7), section 6.2 in selecting the appropriate 
internal inspection tools for the covered segment.
    (2) Pressure test conducted in accordance with subpart J of this 
part. An operator must use the test pressures specified in Table 3 of 
section 5 of ASME/ANSI B31.8S, to justify an extended reassessment 
interval in accordance with Sec. 192.939.
    (3) Direct assessment to address threats of external corrosion, 
internal corrosion, and stress corrosion cracking. An operator must 
conduct the direct assessment in accordance with the requirements listed 
in Sec. 192.923 and with, as applicable, the requirements specified in 
Sec. Sec. 192.925, 192.927 or 192.929;
    (4) Other technology that an 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) 180 
days before conducting the assessment, in accordance with Sec. 192.949. 
An operator must also notify a State or local pipeline safety authority 
when either a covered segment is located in a State where OPS has an 
interstate agent agreement, or an intrastate covered segment is 
regulated by that State.
    (b) Prioritizing segments. An operator must prioritize the covered 
pipeline segments for the baseline assessment according to a risk 
analysis that considers the potential threats to each covered segment. 
The risk analysis must comply with the requirements in Sec. 192.917.
    (c) Assessment for particular threats. In choosing an assessment 
method for the baseline assessment of each covered segment, an operator 
must take the actions required in Sec. 192.917(e) to address particular 
threats that it has identified.
    (d) Time period. An operator must prioritize all the covered 
segments for assessment in accordance with Sec. 192.917

[[Page 118]]

(c) and paragraph (b) of this section. An operator must assess at least 
50% of the covered segments beginning with the highest risk segments, by 
December 17, 2007. An operator must complete the baseline assessment of 
all covered segments by December 17, 2012.
    (e) Prior assessment. An operator may use a prior integrity 
assessment conducted before December 17, 2002 as a baseline assessment 
for the covered segment, if the integrity assessment meets the baseline 
requirements in this subpart and subsequent remedial actions to address 
the conditions listed in Sec. 192.933 have been carried out. In 
addition, if an operator uses this prior assessment as its baseline 
assessment, the operator must reassess the line pipe in the covered 
segment according to the requirements of Sec. 192.937 and Sec. 
192.939.
    (f) Newly identified areas. When an operator identifies a new high 
consequence area (see Sec. 192.905), an operator must complete the 
baseline assessment of the line pipe in the newly identified high 
consequence area within ten (10) years from the date the area is 
identified.
    (g) Newly installed pipe. An operator must complete the baseline 
assessment of a newly-installed segment of pipe covered by this subpart 
within ten (10) years from the date the pipe is installed. An operator 
may conduct a pressure test in accordance with paragraph (a)(2) of this 
section, to satisfy the requirement for a baseline assessment.
    (h) Plastic transmission pipeline. If the threat analysis required 
in Sec. 192.917(d) on a plastic transmission pipeline indicates that a 
covered segment is susceptible to failure from causes other than third-
party damage, an operator must conduct a baseline assessment of the 
segment in accordance with the requirements of this section and of Sec. 
192.917. The operator must justify the use of an alternative assessment 
method that will address the identified threats to the covered segment.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18232, 
Apr. 6, 2004]



Sec. 192.923  How is direct assessment used and for what threats?

    (a) General. An operator may use direct assessment either as a 
primary assessment method or as a supplement to the other assessment 
methods allowed under this subpart. An operator may only use direct 
assessment as the primary assessment method to address the identified 
threats of external corrosion (ECDA), internal corrosion (ICDA), and 
stress corrosion cracking (SCCDA).
    (b) Primary method. An operator using direct assessment as a primary 
assessment method must have a plan that complies with the requirements 
in--
    (1) ASME/ANSI B31.8S (incorporated by reference, see Sec. 192.7), 
section 6.4; NACE RP0502-2002 (incorporated by reference, see Sec. 
192.7); and Sec. 192.925 if addressing external corrosion (ECDA).
    (2) ASME/ANSI B31.8S, section 6.4 and appendix B2, and Sec. 192.927 
if addressing internal corrosion (ICDA).
    (3) ASME/ANSI B31.8S, appendix A3, and Sec. 192.929 if addressing 
stress corrosion cracking (SCCDA).
    (c) Supplemental method. An operator using direct assessment as a 
supplemental assessment method for any applicable threat must have a 
plan that follows the requirements for confirmatory direct assessment in 
Sec. 192.931.



Sec. 192.925  What are the requirements for using External Corrosion 
Direct Assessment (ECDA)?

    (a) Definition. ECDA is a four-step process that combines 
preassessment, indirect inspection, direct examination, and post 
assessment to evaluate the threat of external corrosion to the integrity 
of a pipeline.
    (b) General requirements. An operator that uses direct assessment to 
assess the threat of external corrosion must follow the requirements in 
this section, in ASME/ANSI B31.8S (incorporated by reference, see Sec. 
192.7), section 6.4, and in NACE RP 0502-2002 (incorporated by 
reference, see Sec. 192.7). An operator must develop and implement a 
direct assessment plan that has procedures addressing preassessment, 
indirect examination, direct examination, and post-assessment. If the 
ECDA detects pipeline coating damage, the operator must also integrate 
the data from the ECDA

[[Page 119]]

with other information from the data integration (Sec. 192.917(b)) to 
evaluate the covered segment for the threat of third party damage, and 
to address the threat as required by Sec. 192.917(e)(1).
    (1) Preassessment. In addition to the requirements in ASME/ANSI 
B31.8S section 6.4 and NACE RP 0502-2002, section 3, the plan's 
procedures for preassessment must include--
    (i) Provisions for applying more restrictive criteria when 
conducting ECDA for the first time on a covered segment; and
    (ii) The basis on which an operator selects at least two different, 
but complementary indirect assessment tools to assess each ECDA Region. 
If an operator utilizes an indirect inspection method that is not 
discussed in Appendix A of NACE RP0502-2002, the operator must 
demonstrate the applicability, validation basis, equipment used, 
application procedure, and utilization of data for the inspection 
method.
    (2) Indirect examination. In addition to the requirements in ASME/
ANSI B31.8S section 6.4 and NACE RP 0502-2002, section 4, the plan's 
procedures for indirect examination of the ECDA regions must include--
    (i) Provisions for applying more restrictive criteria when 
conducting ECDA for the first time on a covered segment;
    (ii) Criteria for identifying and documenting those indications that 
must be considered for excavation and direct examination. Minimum 
identification criteria include the known sensitivities of assessment 
tools, the procedures for using each tool, and the approach to be used 
for decreasing the physical spacing of indirect assessment tool readings 
when the presence of a defect is suspected;
    (iii) Criteria for defining the urgency of excavation and direct 
examination of each indication identified during the indirect 
examination. These criteria must specify how an operator will define the 
urgency of excavating the indication as immediate, scheduled or 
monitored; and
    (iv) Criteria for scheduling excavation of indications for each 
urgency level.
    (3) Direct examination. In addition to the requirements in ASME/ANSI 
B31.8S section 6.4 and NACE RP 0502-2002, section 5, the plan's 
procedures for direct examination of indications from the indirect 
examination must include--
    (i) Provisions for applying more restrictive criteria when 
conducting ECDA for the first time on a covered segment;
    (ii) Criteria for deciding what action should be taken if either:
    (A) Corrosion defects are discovered that exceed allowable limits 
(Section 5.5.2.2 of NACE RP0502-2002), or
    (B) Root cause analysis reveals conditions for which ECDA is not 
suitable (Section 5.6.2 of NACE RP0502-2002);
    (iii) Criteria and notification procedures for any changes in the 
ECDA Plan, including changes that affect the severity classification, 
the priority of direct examination, and the time frame for direct 
examination of indications; and
    (iv) Criteria that describe how and on what basis an operator will 
reclassify and reprioritize any of the provisions that are specified in 
section 5.9 of NACE RP0502-2002.
    (4) Post assessment and continuing evaluation. In addition to the 
requirements in ASME/ANSI B31.8S section 6.4 and NACE RP 0502-2002, 
section 6, the plan's procedures for post assessment of the 
effectiveness of the ECDA process must include--
    (i) Measures for evaluating the long-term effectiveness of ECDA in 
addressing external corrosion in covered segments; and
    (ii) Criteria for evaluating whether conditions discovered by direct 
examination of indications in each ECDA region indicate a need for 
reassessment of the covered segment at an interval less than that 
specified in Sec. 192.939. (See Appendix D of NACE RP0502-2002.)

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 29904, 
May 26, 2004]



Sec. 192.927  What are the requirements for using Internal Corrosion
Direct Assessment (ICDA)?

    (a) Definition. Internal Corrosion Direct Assessment (ICDA) is a 
process an operator uses to identify areas along

[[Page 120]]

the pipeline where fluid or other electrolyte introduced during normal 
operation or by an upset condition may reside, and then focuses direct 
examination on the locations in covered segments where internal 
corrosion is most likely to exist. The process identifies the potential 
for internal corrosion caused by microorganisms, or fluid with 
CO2, O2, hydrogen sulfide or other contaminants 
present in the gas.
    (b) General requirements. An operator using direct assessment as an 
assessment method to address internal corrosion in a covered pipeline 
segment must follow the requirements in this section and in ASME/ANSI 
B31.8S (incorporated by reference, see Sec. 192.7), section 6.4 and 
appendix B2. The ICDA process described in this section applies only for 
a segment of pipe transporting nominally dry natural gas, and not for a 
segment with electrolyte nominally present in the gas stream. If an 
operator uses ICDA to assess a covered segment operating with 
electrolyte present in the gas stream, the operator must develop a plan 
that demonstrates how it will conduct ICDA in the segment to effectively 
address internal corrosion, and must provide notification in accordance 
with Sec. 192.921 (a)(4) or Sec. 192.937(c)(4).
    (c) The ICDA plan. An operator must develop and follow an ICDA plan 
that provides for preassessment, identification of ICDA regions and 
excavation locations, detailed examination of pipe at excavation 
locations, and post-assessment evaluation and monitoring.
    (1) Preassessment. In the preassessment stage, an operator must 
gather and integrate data and information needed to evaluate the 
feasibility of ICDA for the covered segment, and to support use of a 
model to identify the locations along the pipe segment where electrolyte 
may accumulate, to identify ICDA regions, and to identify areas within 
the covered segment where liquids may potentially be entrained. This 
data and information includes, but is not limited to--
    (i) All data elements listed in appendix A2 of ASME/ANSI B31.8S;
    (ii) Information needed to support use of a model that an operator 
must use to identify areas along the pipeline where internal corrosion 
is most likely to occur. (See paragraph (a) of this section.) This 
information, includes, but is not limited to, location of all gas input 
and withdrawal points on the line; location of all low points on covered 
segments such as sags, drips, inclines, valves, manifolds, dead-legs, 
and traps; the elevation profile of the pipeline in sufficient detail 
that angles of inclination can be calculated for all pipe segments; and 
the diameter of the pipeline, and the range of expected gas velocities 
in the pipeline;
    (iii) Operating experience data that would indicate historic upsets 
in gas conditions, locations where these upsets have occurred, and 
potential damage resulting from these upset conditions; and
    (iv) Information on covered segments where cleaning pigs may not 
have been used or where cleaning pigs may deposit electrolytes.
    (2) ICDA region identification. An operator's plan must identify 
where all ICDA Regions are located in the transmission system, in which 
covered segments are located. An ICDA Region extends from the location 
where liquid may first enter the pipeline and encompasses the entire 
area along the pipeline where internal corrosion may occur and where 
further evaluation is needed. An ICDA Region may encompass one or more 
covered segments. In the identification process, an operator must use 
the model in GRI 02-0057, ``Internal Corrosion Direct Assessment of Gas 
Transmission Pipelines--Methodology,'' (incorporated by reference, see 
Sec. 192.7). An operator may use another model if the operator 
demonstrates it is equivalent to the one shown in GRI 02-0057. A model 
must consider changes in pipe diameter, locations where gas enters a 
line (potential to introduce liquid) and locations down stream of gas 
draw-offs (where gas velocity is reduced) to define the critical pipe 
angle of inclination above which water film cannot be transported by the 
gas.
    (3) Identification of locations for excavation and direct 
examination. An operator's plan must identify the locations where 
internal corrosion is most likely in each ICDA region. In the location 
identification process, an operator

[[Page 121]]

must identify a minimum of two locations for excavation within each ICDA 
Region within a covered segment and must perform a direct examination 
for internal corrosion at each location, using ultrasonic thickness 
measurements, radiography, or other generally accepted measurement 
technique. One location must be the low point (e.g., sags, drips, 
valves, manifolds, dead-legs, traps) within the covered segment nearest 
to the beginning of the ICDA Region. The second location must be further 
downstream, within a covered segment, near the end of the ICDA Region. 
If corrosion exists at either location, the operator must--
    (i) Evaluate the severity of the defect (remaining strength) and 
remediate the defect in accordance with Sec. 192.933;
    (ii) As part of the operator's current integrity assessment either 
perform additional excavations in each covered segment within the ICDA 
region, or use an alternative assessment method allowed by this subpart 
to assess the line pipe in each covered segment within the ICDA region 
for internal corrosion; and
    (iii) Evaluate the potential for internal corrosion in all pipeline 
segments (both covered and non-covered) in the operator's pipeline 
system with similar characteristics to the ICDA region containing the 
covered segment in which the corrosion was found, and as appropriate, 
remediate the conditions the operator finds in accordance with Sec. 
192.933.
    (4) Post-assessment evaluation and monitoring. An operator's plan 
must provide for evaluating the effectiveness of the ICDA process and 
continued monitoring of covered segments where internal corrosion has 
been identified. The evaluation and monitoring process includes--
    (i) Evaluating the effectiveness of ICDA as an assessment method for 
addressing internal corrosion and determining whether a covered segment 
should be reassessed at more frequent intervals than those specified in 
Sec. 192.939. An operator must carry out this evaluation within a year 
of conducting an ICDA; and
    (ii) Continually monitoring each covered segment where internal 
corrosion has been identified using techniques such as coupons, UT 
sensors or electronic probes, periodically drawing off liquids at low 
points and chemically analyzing the liquids for the presence of 
corrosion products. An operator must base the frequency of the 
monitoring and liquid analysis on results from all integrity assessments 
that have been conducted in accordance with the requirements of this 
subpart, and risk factors specific to the covered segment. If an 
operator finds any evidence of corrosion products in the covered 
segment, the operator must take prompt action in accordance with one of 
the two following required actions and remediate the conditions the 
operator finds in accordance with Sec. 192.933.
    (A) Conduct excavations of covered segments at locations downstream 
from where the electrolyte might have entered the pipe; or
    (B) Assess the covered segment using another integrity assessment 
method allowed by this subpart.
    (5) Other requirements. The ICDA plan must also include--
    (i) Criteria an operator will apply in making key decisions (e.g., 
ICDA feasibility, definition of ICDA Regions, conditions requiring 
excavation) in implementing each stage of the ICDA process;
    (ii) Provisions for applying more restrictive criteria when 
conducting ICDA for the first time on a covered segment and that become 
less stringent as the operator gains experience; and
    (iii) Provisions that analysis be carried out on the entire pipeline 
in which covered segments are present, except that application of the 
remediation criteria of Sec. 192.933 may be limited to covered 
segments.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18232, 
Apr. 6, 2004]



Sec. 192.929  What are the requirements for using Direct Assessment 
for Stress Corrosion Cracking (SCCDA)?

    (a) Definition. Stress Corrosion Cracking Direct Assessment (SCCDA) 
is a process to assess a covered pipe segment for the presence of SCC 
primarily by systematically gathering and analyzing excavation data for 
pipe

[[Page 122]]

having similar operational characteristics and residing in a similar 
physical environment.
    (b) General requirements. An operator using direct assessment as an 
integrity assessment method to address stress corrosion cracking in a 
covered pipeline segment must have a plan that provides, at minimum, 
for--
    (1) Data gathering and integration. An operator's plan must provide 
for a systematic process to collect and evaluate data for all covered 
segments to identify whether the conditions for SCC are present and to 
prioritize the covered segments for assessment. This process must 
include gathering and evaluating data related to SCC at all sites an 
operator excavates during the conduct of its pipeline operations where 
the criteria in ASME/ANSI B31.8S (incorporated by reference, see Sec. 
192.7), appendix A3.3 indicate the potential for SCC. This data includes 
at minimum, the data specified in ASME/ANSI B31.8S, appendix A3.
    (2) Assessment method. The plan must provide that if conditions for 
SCC are identified in a covered segment, an operator must assess the 
covered segment using an integrity assessment method specified in ASME/
ANSI B31.8S, appendix A3, and remediate the threat in accordance with 
ASME/ANSI B31.8S, appendix A3, section A3.4.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18233, 
Apr. 6, 2004]



Sec. 192.931  How may Confirmatory Direct Assessment (CDA) be used?

    An operator using the confirmatory direct assessment (CDA) method as 
allowed in Sec. 192.937 must have a plan that meets the requirements of 
this section and of Sec. Sec. 192.925 (ECDA) and Sec. 192.927 (ICDA).
    (a) Threats. An operator may only use CDA on a covered segment to 
identify damage resulting from external corrosion or internal corrosion.
    (b) External corrosion plan. An operator's CDA plan for identifying 
external corrosion must comply with Sec. 192.925 with the following 
exceptions.
    (1) The procedures for indirect examination may allow use of only 
one indirect examination tool suitable for the application.
    (2) The procedures for direct examination and remediation must 
provide that--
    (i) All immediate action indications must be excavated for each ECDA 
region; and
    (ii) At least one high risk indication that meets the criteria of 
scheduled action must be excavated in each ECDA region.
    (c) Internal corrosion plan. An operator's CDA plan for identifying 
internal corrosion must comply with Sec. 192.927 except that the plan's 
procedures for identifying locations for excavation may require 
excavation of only one high risk location in each ICDA region.
    (d) Defects requiring near-term remediation. If an assessment 
carried out under paragraph (b) or (c) of this section reveals any 
defect requiring remediation prior to the next scheduled assessment, the 
operator must schedule the next assessment in accordance with NACE RP 
0502-2002 (incorporated by reference, see Sec. 192.7), section 6.2 and 
6.3. If the defect requires immediate remediation, then the operator 
must reduce pressure consistent with Sec. 192.933 until the operator 
has completed reassessment using one of the assessment techniques 
allowed in Sec. 192.937.



Sec. 192.933  What actions must be taken to address integrity issues?

    (a) General requirements. An operator must take prompt action to 
address all anomalous conditions the operator discovers through the 
integrity assessment. In addressing all conditions, an operator must 
evaluate all anomalous conditions and remediate those that could reduce 
a pipeline's integrity. An operator must be able to demonstrate that the 
remediation of the condition will ensure the condition is unlikely to 
pose a threat to the integrity of the pipeline until the next 
reassessment of the covered segment.
    (1) Temporary pressure reduction. If an operator is unable to 
respond within the time limits for certain conditions specified in this 
section, the operator must temporarily reduce the operating pressure of 
the pipeline or take other action that ensures the safety of the covered 
segment. An operator must determine any temporary reduction in

[[Page 123]]

operating pressure required by this section using ASME/ANSI B31G 
(incorporated by reference, see Sec. 192.7) or AGA Pipeline Research 
Committee Project PR-3-805 (``RSTRENG,'' incorporated by reference, see 
Sec. 192.7) or reduce the operating pressure to a level not exceeding 
80 percent of the level at the time the condition was discovered. (See 
appendix A to this part for information on availability of incorporation 
by reference information.) An operator must notify PHMSA in accordance 
with Sec. 192.949 if it cannot meet the schedule for evaluation and 
remediation required under paragraph (c) of this section and cannot 
provide safety through temporary reduction in operating pressure or 
other action. An operator must also notify a State pipeline safety 
authority when either a covered segment is located in a State where 
PHMSA has an interstate agent agreement, or an intrastate covered 
segment is regulated by that State.
    (2) Long-term pressure reduction. When a pressure reduction exceeds 
365 days, the operator must notify PHMSA under Sec. 192.949 and explain 
the reasons for the remediation delay. This notice must include a 
technical justification that the continued pressure reduction will not 
jeopardize the integrity of the pipeline. The operator also must notify 
a State pipeline safety authority when either a covered segment is 
located in a State where PHMSA has an interstate agent agreement, or an 
intrastate covered segment is regulated by that State.
    (b) Discovery of condition. Discovery of a condition occurs when an 
operator has adequate information about a condition to determine that 
the condition presents a potential threat to the integrity of the 
pipeline. A condition that presents a potential threat includes, but is 
not limited to, those conditions that require remediation or monitoring 
listed under paragraphs (d)(1) through (d)(3) of this section. An 
operator must promptly, but no later than 180 days after conducting an 
integrity assessment, obtain sufficient information about a condition to 
make that determination, unless the operator demonstrates that the 180-
day period is impracticable.
    (c) Schedule for evaluation and remediation. An operator must 
complete remediation of a condition according to a schedule prioritizing 
the conditions for evaluation and remediation. Unless a special 
requirement for remediating certain conditions applies, as provided in 
paragraph (d) of this section, an operator must follow the schedule in 
ASME/ANSI B31.8S (incorporated by reference, see Sec. 192.7), section 
7, Figure 4. If an operator cannot meet the schedule for any condition, 
the operator must explain the reasons why it cannot meet the schedule 
and how the changed schedule will not jeopardize public safety.
    (d) Special requirements for scheduling remediation--(1) Immediate 
repair conditions. An operator's evaluation and remediation schedule 
must follow ASME/ANSI B31.8S, section 7 in providing for immediate 
repair conditions. To maintain safety, an operator must temporarily 
reduce operating pressure in accordance with paragraph (a) of this 
section or shut down the pipeline until the operator completes the 
repair of these conditions. An operator must treat the following 
conditions as immediate repair conditions:
    (i) A calculation of the remaining strength of the pipe shows a 
predicted failure pressure less than or equal to 1.1 times the maximum 
allowable operating pressure at the location of the anomaly. Suitable 
remaining strength calculation methods include, ASME/ANSI B31G; RSTRENG; 
or an alternative equivalent method of remaining strength calculation. 
These documents are incorporated by reference and available at the 
addresses listed in appendix A to part 192.
    (ii) A dent that has any indication of metal loss, cracking or a 
stress riser.
    (iii) An indication or anomaly that in the judgment of the person 
designated by the operator to evaluate the assessment results requires 
immediate action.
    (2) One-year conditions. Except for conditions listed in paragraph 
(d)(1) and (d)(3) of this section, an operator must remediate any of the 
following within one year of discovery of the condition:
    (i) A smooth dent located between the 8 o'clock and 4 o'clock 
positions

[[Page 124]]

(upper \2/3\ of the pipe) with a depth greater than 6% of the pipeline 
diameter (greater than 0.50 inches in depth for a pipeline diameter less 
than Nominal Pipe Size (NPS) 12).
    (ii) 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 at a longitudinal seam weld.
    (3) Monitored conditions. An operator does not have to schedule the 
following conditions for remediation, but must record and monitor the 
conditions during subsequent risk assessments and integrity assessments 
for any change that may require remediation:
    (i) A dent with a depth greater than 6% of the pipeline diameter 
(greater than 0.50 inches in depth for a pipeline diameter less than NPS 
12) located between the 4 o'clock position and the 8 o'clock position 
(bottom \1/3\ of the pipe).
    (ii) A dent located between the 8 o'clock and 4 o'clock positions 
(upper \2/3\ of the pipe) with a depth greater than 6% of the pipeline 
diameter (greater than 0.50 inches in depth for a pipeline diameter less 
than Nominal Pipe Size (NPS) 12), and engineering analyses of the dent 
demonstrate critical strain levels are not exceeded.
    (iii) 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, and 
engineering analyses of the dent and girth or seam weld demonstrate 
critical strain levels are not exceeded. These analyses must consider 
weld properties.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18233, 
Apr. 6, 2004; Amdt. 192-104, 72 FR 39016, July 17, 2007]



Sec. 192.935  What additional preventive and mitigative measures must 
an operator take?

    (a) General requirements. An operator must take additional measures 
beyond those already required by Part 192 to prevent a pipeline failure 
and to mitigate the consequences of a pipeline failure in a high 
consequence area. An operator must base the additional measures on the 
threats the operator has identified to each pipeline segment. (See Sec. 
192.917) An operator must conduct, in accordance with one of the risk 
assessment approaches in ASME/ANSI B31.8S (incorporated by reference, 
see Sec. 192.7), section 5, a risk analysis of its pipeline to identify 
additional measures to protect the high consequence area and enhance 
public safety. Such additional measures include, but are not limited to, 
installing Automatic Shut-off Valves or Remote Control Valves, 
installing computerized monitoring and leak detection systems, replacing 
pipe segments with pipe of heavier wall thickness, providing additional 
training to personnel on response procedures, conducting drills with 
local emergency responders and implementing additional inspection and 
maintenance programs.
    (b) Third party damage and outside force damage--
    (1) Third party damage. An operator must enhance its damage 
prevention program, as required under Sec. 192.614 of this part, with 
respect to a covered segment to prevent and minimize the consequences of 
a release due to third party damage. Enhanced measures to an existing 
damage prevention program include, at a minimum--
    (i) Using qualified personnel (see Sec. 192.915) for work an 
operator is conducting that could adversely affect the integrity of a 
covered segment, such as marking, locating, and direct supervision of 
known excavation work.
    (ii) Collecting in a central database information that is location 
specific on excavation damage that occurs in covered and non covered 
segments in the transmission system and the root cause analysis to 
support identification of targeted additional preventative and 
mitigative measures in the high consequence areas. This information must 
include recognized damage that is not required to be reported as an 
incident under part 191.
    (iii) Participating in one-call systems in locations where covered 
segments are present.
    (iv) Monitoring of excavations conducted on covered pipeline 
segments by pipeline personnel. If an operator finds physical evidence 
of encroachment involving excavation that the operator

[[Page 125]]

did not monitor near a covered segment, an operator must either excavate 
the area near the encroachment or conduct an above ground survey using 
methods defined in NACE RP-0502-2002 (incorporated by reference, see 
Sec. 192.7). An operator must excavate, and remediate, in accordance 
with ANSI/ASME B31.8S and Sec. 192.933 any indication of coating 
holidays or discontinuity warranting direct examination.
    (2) Outside force damage. If an operator determines that outside 
force (e.g., earth movement, floods, unstable suspension bridge) is a 
threat to the integrity of a covered segment, the operator must take 
measures to minimize the consequences to the covered segment from 
outside force damage. These measures include, but are not limited to, 
increasing the frequency of aerial, foot or other methods of patrols, 
adding external protection, reducing external stress, and relocating the 
line.
    (c) Automatic shut-off valves (ASV) or Remote control valves (RCV). 
If an operator determines, based on a risk analysis, that an ASV or RCV 
would be an efficient means of adding protection to a high consequence 
area in the event of a gas release, an operator must install the ASV or 
RCV. In making that determination, an operator must, at least, consider 
the following factors--swiftness of leak detection and pipe shutdown 
capabilities, the type of gas being transported, operating pressure, the 
rate of potential release, pipeline profile, the potential for ignition, 
and location of nearest response personnel.
    (d) Pipelines operating below 30% SMYS. An operator of a 
transmission pipeline operating below 30% SMYS located in a high 
consequence area must follow the requirements in paragraphs (d)(1) and 
(d)(2) of this section. An operator of a transmission pipeline operating 
below 30% SMYS located in a Class 3 or Class 4 area but not in a high 
consequence area must follow the requirements in paragraphs (d)(1), 
(d)(2) and (d)(3) of this section.
    (1) Apply the requirements in paragraphs (b)(1)(i) and (b)(1)(iii) 
of this section to the pipeline; and
    (2) Either monitor excavations near the pipeline, or conduct patrols 
as required by Sec. 192.705 of the pipeline at bi-monthly intervals. If 
an operator finds any indication of unreported construction activity, 
the operator must conduct a follow up investigation to determine if 
mechanical damage has occurred.
    (3) Perform semi-annual leak surveys (quarterly for unprotected 
pipelines or cathodically protected pipe where electrical surveys are 
impractical).
    (e) Plastic transmission pipeline. An operator of a plastic 
transmission pipeline must apply the requirements in paragraphs 
(b)(1)(i), (b)(1)(iii) and (b)(1)(iv) of this section to the covered 
segments of the pipeline.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18233, 
Apr. 6, 2004; Amdt. 192-95, 69 FR 29904, May 26, 2004]



Sec. 192.937  What is a continual process of evaluation and assessment
to maintain a pipeline's integrity?

    (a) General. After completing the baseline integrity assessment of a 
covered segment, an operator must continue to assess the line pipe of 
that segment at the intervals specified in Sec. 192.939 and 
periodically evaluate the integrity of each covered pipeline segment as 
provided in paragraph (b) of this section. An operator must reassess a 
covered segment on which a prior assessment is credited as a baseline 
under Sec. 192.921(e) by no later than December 17, 2009. An operator 
must reassess a covered segment on which a baseline assessment is 
conducted during the baseline period specified in Sec. 192.921(d) by no 
later than seven years after the baseline assessment of that covered 
segment unless the evaluation under paragraph (b) of this section 
indicates earlier reassessment.
    (b) Evaluation. An operator must conduct a periodic evaluation as 
frequently as needed to assure the integrity of each covered segment. 
The periodic evaluation must be based on a data integration and risk 
assessment of the entire pipeline as specified in Sec. 192.917. For 
plastic transmission pipelines, the periodic evaluation is based on the 
threat analysis specified in 192.917(d). For all other transmission 
pipelines, the evaluation must consider the past and present integrity 
assessment results, data integration and risk assessment information 
(Sec. 192.917), and decisions about remediation (Sec. 192.933)

[[Page 126]]

and additional preventive and mitigative actions (Sec. 192.935). An 
operator must use the results from this evaluation to identify the 
threats specific to each covered segment and the risk represented by 
these threats.
    (c) Assessment methods. In conducting the integrity reassessment, an 
operator must assess the integrity of the line pipe in the covered 
segment by any of the following methods as appropriate for the threats 
to which the covered segment is susceptible (see Sec. 192.917), or by 
confirmatory direct assessment under the conditions specified in Sec. 
192.931.
    (1) Internal inspection tool or tools capable of detecting 
corrosion, and any other threats to which the covered segment is 
susceptible. An operator must follow ASME/ANSI B31.8S (incorporated by 
reference, see Sec. 192.7), section 6.2 in selecting the appropriate 
internal inspection tools for the covered segment.
    (2) Pressure test conducted in accordance with subpart J of this 
part. An operator must use the test pressures specified in Table 3 of 
section 5 of ASME/ANSI B31.8S, to justify an extended reassessment 
interval in accordance with Sec. 192.939.
    (3) Direct assessment to address threats of external corrosion, 
internal corrosion, or stress corrosion cracking. An operator must 
conduct the direct assessment in accordance with the requirements listed 
in Sec. 192.923 and with as applicable, the requirements specified in 
Sec. Sec. 192.925, 192.927 or 192.929;
    (4) Other technology that an 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) 180 
days before conducting the assessment, in accordance with Sec. 192.949. 
An operator must also notify a State or local pipeline safety authority 
when either a covered segment is located in a State where OPS has an 
interstate agent agreement, or an intrastate covered segment is 
regulated by that State.
    (5) Confirmatory direct assessment when used on a covered segment 
that is scheduled for reassessment at a period longer than seven years. 
An operator using this reassessment method must comply with Sec. 
192.931.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18234, 
Apr. 6, 2004]



Sec. 192.939  What are the required reassessment intervals?

    An operator must comply with the following requirements in 
establishing the reassessment interval for the operator's covered 
pipeline segments.
    (a) Pipelines operating at or above 30% SMYS. An operator must 
establish a reassessment interval for each covered segment operating at 
or above 30% SMYS in accordance with the requirements of this section. 
The maximum reassessment interval by an allowable reassessment method is 
seven years. If an operator establishes a reassessment interval that is 
greater than seven years, the operator must, within the seven-year 
period, conduct a confirmatory direct assessment on the covered segment, 
and then conduct the follow-up reassessment at the interval the operator 
has established. A reassessment carried out using confirmatory direct 
assessment must be done in accordance with Sec. 192.931. The table that 
follows this section sets forth the maximum allowed reassessment 
intervals.
    (1) Pressure test or internal inspection or other equivalent 
technology. An operator that uses pressure testing or internal 
inspection as an assessment method must establish the reassessment 
interval for a covered pipeline segment by--
    (i) Basing the interval on the identified threats for the covered 
segment (see Sec. 192.917) and on the analysis of the results from the 
last integrity assessment and from the data integration and risk 
assessment required by Sec. 192.917; or
    (ii) Using the intervals specified for different stress levels of 
pipeline (operating at or above 30% SMYS) listed in ASME/ANSI B31.8S, 
section 5, Table 3.
    (2) External Corrosion Direct Assessment. An operator that uses ECDA 
that meets the requirements of this subpart must determine the 
reassessment interval according to the requirements in paragraphs 6.2 
and 6.3 of NACE RP0502-2002 (incorporated by reference, see Sec. 
192.7).

[[Page 127]]

    (3) Internal Corrosion or SCC Direct Assessment. An operator that 
uses ICDA or SCCDA in accordance with the requirements of this subpart 
must determine the reassessment interval according to the following 
method. However, the reassessment interval cannot exceed those specified 
for direct assessment in ASME/ANSI B31.8S, section 5, Table 3.
    (i) Determine the largest defect most likely to remain in the 
covered segment and the corrosion rate appropriate for the pipe, soil 
and protection conditions;
    (ii) Use the largest remaining defect as the size of the largest 
defect discovered in the SCC or ICDA segment; and
    (iii) Estimate the reassessment interval as half the time required 
for the largest defect to grow to a critical size.
    (b) Pipelines Operating Below 30% SMYS. An operator must establish a 
reassessment interval for each covered segment operating below 30% SMYS 
in accordance with the requirements of this section. The maximum 
reassessment interval by an allowable reassessment method is seven 
years. An operator must establish reassessment by at least one of the 
following--
    (1) Reassessment by pressure test, internal inspection or other 
equivalent technology following the requirements in paragraph (a)(1) of 
this section except that the stress level referenced in paragraph 
(a)(1)(ii) of this section would be adjusted to reflect the lower 
operating stress level. If an established interval is more than seven 
years, the operator must conduct by the seventh year of the interval 
either a confirmatory direct assessment in accordance with Sec. 
192.931, or a low stress reassessment in accordance with Sec. 192.941.
    (2) Reassessment by ECDA following the requirements in paragraph 
(a)(2) of this section.
    (3) Reassessment by ICDA or SCCDA following the requirements in 
paragraph (a)(3) of this section.
    (4) Reassessment by confirmatory direct assessment at 7-year 
intervals in accordance with Sec. 192.931, with reassessment by one of 
the methods listed in paragraphs (b)(1) through (b)(3) of this section 
by year 20 of the interval.
    (5) Reassessment by the low stress assessment method at 7-year 
intervals in accordance with Sec. 192.941 with reassessment by one of 
the methods listed in paragraphs (b)(1) through (b)(3) of this section 
by year 20 of the interval.
    (6) The following table sets forth the maximum reassessment 
intervals. Also refer to Appendix E.II for guidance on Assessment 
Methods and Assessment Schedule for Transmission Pipelines Operating 
Below 30% SMYS. In case of conflict between the rule and the guidance in 
the Appendix, the requirements of the rule control. An operator must 
comply with the following requirements in establishing a reassessment 
interval for a covered segment:

                                          Maximum Reassessment Interval
----------------------------------------------------------------------------------------------------------------
                                                                 Pipeline operating at
          Assessment method             Pipeline operating at    or above 30% SMYS, up      Pipeline operating
                                          or above 50% SMYS           to 50% SMYS             below 30% SMYS
----------------------------------------------------------------------------------------------------------------
Internal Inspection Tool, Pressure     10 years (*)...........  15 years (*)...........  20 years.(**)
 Test or Direct Assessment.
Confirmatory Direct Assessment.......  7 years................  7 years................  7 years.
Low Stress Reassessment..............  Not applicable.........  Not applicable.........  7 years + ongoing
                                                                                          actions specified in
                                                                                          Sec.  192.941.
----------------------------------------------------------------------------------------------------------------
(*) A Confirmatory direct assessment as described in Sec.  192.931 must be conducted by year 7 in a 10-year
  interval and years 7 and 14 of a 15-year interval.
(**) A low stress reassessment or Confirmatory direct assessment must be conducted by years 7 and 14 of the
  interval.


[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18234, 
Apr. 6, 2004]



Sec. 192.941  What is a low stress reassessment?

    (a) General. An operator of a transmission line that operates below 
30% SMYS may use the following method to reassess a covered segment in 
accordance with Sec. 192.939. This method of reassessment addresses the 
threats of external and internal corrosion. The

[[Page 128]]

operator must have conducted a baseline assessment of the covered 
segment in accordance with the requirements of Sec. Sec. 192.919 and 
192.921.
    (b) External corrosion. An operator must take one of the following 
actions to address external corrosion on the low stress covered segment.
    (1) Cathodically protected pipe. To address the threat of external 
corrosion on cathodically protected pipe in a covered segment, an 
operator must perform an electrical survey (i.e. indirect examination 
tool/method) at least every 7 years on the covered segment. An operator 
must use the results of each survey as part of an overall evaluation of 
the cathodic protection and corrosion threat for the covered segment. 
This evaluation must consider, at minimum, the leak repair and 
inspection records, corrosion monitoring records, exposed pipe 
inspection records, and the pipeline environment.
    (2) Unprotected pipe or cathodically protected pipe where electrical 
surveys are impractical. If an electrical survey is impractical on the 
covered segment an operator must--
    (i) Conduct leakage surveys as required by Sec. 192.706 at 4-month 
intervals; and
    (ii) Every 18 months, identify and remediate areas of active 
corrosion by evaluating leak repair and inspection records, corrosion 
monitoring records, exposed pipe inspection records, and the pipeline 
environment.
    (c) Internal corrosion. To address the threat of internal corrosion 
on a covered segment, an operator must--
    (1) Conduct a gas analysis for corrosive agents at least once each 
calendar year;
    (2) Conduct periodic testing of fluids removed from the segment. At 
least once each calendar year test the fluids removed from each storage 
field that may affect a covered segment; and
    (3) At least every seven (7) years, integrate data from the analysis 
and testing required by paragraphs (c)(1)-(c)(2) with applicable 
internal corrosion leak records, incident reports, safety-related 
condition reports, repair records, patrol records, exposed pipe reports, 
and test records, and define and implement appropriate remediation 
actions.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18234, 
Apr. 6, 2004]



Sec. 192.943  When can an operator deviate from these reassessment 
intervals?

    (a) Waiver from reassessment interval in limited situations. In the 
following limited instances, OPS may allow a waiver from a reassessment 
interval required by Sec. 192.939 if OPS finds a waiver would not be 
inconsistent with pipeline safety.
    (1) Lack of internal inspection tools. An operator who uses internal 
inspection as an assessment method may be able to justify a longer 
reassessment period for a covered segment if internal inspection tools 
are not available to assess the line pipe. To justify this, the operator 
must demonstrate that it cannot obtain the internal inspection tools 
within the required reassessment period and that the actions the 
operator is taking in the interim ensure the integrity of the covered 
segment.
    (2) Maintain product supply. An operator may be able to justify a 
longer reassessment period for a covered segment if the operator 
demonstrates that it cannot maintain local product supply if it conducts 
the reassessment within the required interval.
    (b) How to apply. If one of the conditions specified in paragraph 
(a) (1) or (a) (2) of this section applies, an operator may seek a 
waiver of the required reassessment interval. An operator must apply for 
a waiver in accordance with 49 U.S.C. 60118(c), at least 180 days before 
the end of the required reassessment interval, unless local product 
supply issues make the period impractical. If local product supply 
issues make the period impractical, an operator must apply for the 
waiver as soon as the need for the waiver becomes known.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18234, 
Apr. 6, 2004]



Sec. 192.945  What methods must an operator use to measure program 
effectiveness?

    (a) General. An operator must include in its integrity management 
program methods to measure, on a semi-annual

[[Page 129]]

basis, whether the program is effective in assessing and evaluating the 
integrity of each covered pipeline segment and in protecting the high 
consequence areas. These measures must include the four overall 
performance measures specified in ASME/ANSI B31.8S (incorporated by 
reference, see Sec. 192.7), section 9.4, and the specific measures for 
each identified threat specified in ASME/ANSI B31.8S, Appendix A. An 
operator must submit the four overall performance measures, by 
electronic or other means, on a semi-annual frequency to OPS in 
accordance with Sec. 192.951. An operator must submit its first report 
on overall performance measures by August 31, 2004. Thereafter, the 
performance measures must be complete through June 30 and December 31 of 
each year and must be submitted within 2 months after those dates.
    (b) External Corrosion Direct assessment. In addition to the general 
requirements for performance measures in paragraph (a) of this section, 
an operator using direct assessment to assess the external corrosion 
threat must define and monitor measures to determine the effectiveness 
of the ECDA process. These measures must meet the requirements of Sec. 
192.925.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18234, 
Apr. 6, 2004]



Sec. 192.947  What records must an operator keep?

    An operator must maintain, for the useful life of the pipeline, 
records that demonstrate compliance with the requirements of this 
subpart. At minimum, an operator must maintain the following records for 
review during an inspection.
    (a) A written integrity management program in accordance with Sec. 
192.907;
    (b) Documents supporting the threat identification and risk 
assessment in accordance with Sec. 192.917;
    (c) A written baseline assessment plan in accordance with Sec. 
192.919;
    (d) Documents to support any decision, analysis and process 
developed and used to implement and evaluate each element of the 
baseline assessment plan and integrity management program. Documents 
include those developed and used in support of any identification, 
calculation, amendment, modification, justification, deviation and 
determination made, and any action taken to implement and evaluate any 
of the program elements;
    (e) Documents that demonstrate personnel have the required training, 
including a description of the training program, in accordance with 
Sec. 192.915;
    (f) Schedule required by Sec. 192.933 that prioritizes the 
conditions found during an assessment for evaluation and remediation, 
including technical justifications for the schedule.
    (g) Documents to carry out the requirements in Sec. Sec. 192.923 
through 192.929 for a direct assessment plan;
    (h) Documents to carry out the requirements in Sec. 192.931 for 
confirmatory direct assessment;
    (i) Verification that an operator has provided any documentation or 
notification required by this subpart to be provided to OPS, and when 
applicable, a State authority with which OPS has an interstate agent 
agreement, and a State or local pipeline safety authority that regulates 
a covered pipeline segment within that State.

[68 FR 69817, Dec. 15, 2003, as amended by Amdt. 192-95, 69 FR 18234, 
Apr. 6, 2004]



Sec. 192.949  How does an operator notify PHMSA?

    An operator must provide any notification required by this subpart 
by--
    (a) Sending the notification to the Office of Pipeline Safety, 
Pipeline and Hazardous Materials Safety Administration, U.S. Department 
of Transportation, Information Resources Manager, PHP-10, 1200 New 
Jersey Avenue, SE., Washington, DC 20590-0001;
    (b) Sending the notification to the Information Resources Manager by 
facsimile to (202) 366-7128; or
    (c) Entering the information directly on the Integrity Management 
Database (IMDB) Web site at http://primis.rspa.dot.gov/gasimp/.

[68 FR 69817, Dec. 15, 2003, as amended at 70 FR 11139, Mar. 8, 2005; 
Amdt. 192-103, 72 FR 4657, Feb. 1, 2007; 73 FR 16570, Mar. 28, 2008; 74 
FR 2894, Jan. 16, 2009]

[[Page 130]]



Sec. 192.951  Where does an operator file a report?

    An operator must send any performance report required by this 
subpart to the Information Resources Manager--
    (a) By mail to the Office of Pipeline Safety, Pipeline and Hazardous 
Materials Safety Administration, U.S. Department of Transportation, 
Information Resources Manager, PHP-10, 1200 New Jersey Avenue, SE., 
Washington, DC 20590-0001;
    (b) Via facsimile to (202) 366-7128; or
    (c) Through the online reporting system provided by OPS for 
electronic reporting available at the OPS Home Page at http://
ops.dot.gov.

[68 FR 69817, Dec. 15, 2003, as amended at 70 FR 11139, Mar. 8, 2005 ; 
Amdt. 192-103, 72 FR 4657, Feb. 1, 2007; 73 FR 16570, Mar. 28, 2008; 74 
FR 2894, Jan. 16, 2009]



                 Sec. Appendix A to Part 192 [Reserved]



           Sec. Appendix B to Part 192--Qualification of Pipe

    I. Listed Pipe Specifications
    API 5L--Steel pipe, ``API Specification for Line Pipe'' 
(incorporated by reference, see Sec. 192.7).
    ASTM A53/A53M--Steel pipe, ``Standard Specification for Pipe, Steel 
Black and Hot-Dipped, Zinc-Coated, Welded and Seamless'' (incorporated 
by reference, see Sec. 192.7).
    ASTM A106--Steel pipe, ``Standard Specification for Seamless Carbon 
Steel Pipe for High Temperature Service'' (incorporated by reference, 
see Sec. 192.7).
    ASTM A333/A333M--Steel pipe, ``Standard Specification for Seamless 
and Welded Steel Pipe for Low Temperature Service'' (incorporated by 
reference, see Sec. 192.7).
    ASTM A381--Steel pipe, ``Standard Specification for Metal-Arc-Welded 
Steel Pipe for Use with High-Pressure Transmission Systems'' 
(incorporated by reference, see Sec. 192.7).
    ASTM A671--Steel pipe, ``Standard Specification for Electric-Fusion-
Welded Pipe for Atmospheric and Lower Temperatures'' (incorporated by 
reference, see Sec. 192.7).
    ASTM A672--Steel pipe, ``Standard Specification for Electric-Fusion-
Welded Steel Pipe for High-Pressure Service at Moderate Temperatures'' 
(incorporated by reference, see Sec. 192.7).
    ASTM A691--Steel pipe, ``Standard Specification for Carbon and Alloy 
Steel Pipe, Electric-Fusion-Welded for High Pressure Service at High 
Temperatures'' (incorporated by reference, see Sec. 192.7).
    ASTM D2513--Thermoplastic pipe and tubing, ``Standard Specification 
for Thermoplastic Gas Pressure Pipe, Tubing, and Fittings'' 
(incorporated by reference, see Sec. 192.7).
    ASTM D2517--Thermosetting plastic pipe and tubing, ``Standard 
Specification for Reinforced Epoxy Resin Gas Pressure Pipe and 
Fittings'' (incorporated by reference, see Sec. 192.7).
    II. Steel pipe of unknown or unlisted specification.
    A. Bending Properties. For pipe 2 inches (51 millimeters) or less in 
diameter, a length of pipe must be cold bent through at least 90 degrees 
around a cylindrical mandrel that has a diameter 12 times the diameter 
of the pipe, without developing cracks at any portion and without 
opening the longitudinal weld.
    For pipe more than 2 inches (51 millimeters) in diameter, the pipe 
must meet the requirements of the flattening tests set forth in ASTM A53 
(incorporated by reference, see Sec. 192.7), except that the number of 
tests must be at least equal to the minimum required in paragraph II-D 
of this appendix to determine yield strength.
    B. Weldability. A girth weld must be made in the pipe by a welder 
who is qualified under subpart E of this part. The weld must be made 
under the most severe conditions under which welding will be allowed in 
the field and by means of the same procedure that will be used in the 
field. On pipe more than 4 inches (102 millimeters) in diameter, at 
least one test weld must be made for each 100 lengths of pipe. On pipe 4 
inches (102 millimeters) or less in diameter, at least one test weld 
must be made for each 400 lengths of pipe. The weld must be tested in 
accordance with API Standard 1104 (incorporated by reference, see Sec. 
192.7). If the requirements of API Standard 1104 cannot be met, 
weldability may be established by making chemical tests for carbon and 
manganese, and proceeding in accordance with section IX of the ASME 
Boiler and Pressure Vessel Code (ibr, see 192.7). The same number of 
chemical tests must be made as are required for testing a girth weld.
    C. Inspection. The pipe must be clean enough to permit adequate 
inspection. It must be visually inspected to ensure that it is 
reasonably round and straight and there are no defects which might 
impair the strength or tightness of the pipe.
    D. Tensile Properties. If the tensile properties of the pipe are not 
known, the minimum yield strength may be taken as 24,000 p.s.i. (165 
MPa) or less, or the tensile properties may be established by performing 
tensile tests as set forth in API Specification 5L (incorporated by 
reference, see Sec. 192.7). All test specimens shall be selected at 
random and the following number of tests must be performed:

[[Page 131]]



                   Number of Tensile Tests--All Sizes
10 lengths or less........................  1 set of tests for each
                                             length.
11 to 100 lengths.........................  1 set of tests for each 5
                                             lengths, but not less than
                                             10 tests.
Over 100 lengths..........................  1 set of tests for each 10
                                             lengths, but not less than
                                             20 tests.
------------------------------------------------------------------------

If the yield-tensile ratio, based on the properties determined by those 
tests, exceeds 0.85, the pipe may be used only as provided in Sec. 
192.55(c).
    III. Steel pipe manufactured before November 12, 1970, to earlier 
editions of listed specifications. Steel pipe manufactured before 
November 12, 1970, in accordance with a specification of which a later 
edition is listed in section I of this appendix, is qualified for use 
under this part if the following requirements are met:
    A. Inspection. The pipe must be clean enough to permit adequate 
inspection. It must be visually inspected to ensure that it is 
reasonably round and straight and that there are no defects which might 
impair the strength or tightness of the pipe.
    B. Similarity of specification requirements. The edition of the 
listed specification under which the pipe was manufactured must have 
substantially the same requirements with respect to the following 
properties as a later edition of that specification listed in section I 
of this appendix:
    (1) Physical (mechanical) properties of pipe, including yield and 
tensile strength, elongation, and yield to tensile ratio, and testing 
requirements to verify those properties.
    (2) Chemical properties of pipe and testing requirements to verify 
those properties.
    C. Inspection or test of welded pipe. On pipe with welded seams, one 
of the following requirements must be met:
    (1) The edition of the listed specification to which the pipe was 
manufactured must have substantially the same requirements with respect 
to nondestructive inspection of welded seams and the standards for 
acceptance or rejection and repair as a later edition of the 
specification listed in section I of this appendix.
    (2) The pipe must be tested in accordance with subpart J of this 
part to at least 1.25 times the maximum allowable operating pressure if 
it is to be installed in a class 1 location and to at least 1.5 times 
the maximum allowable operating pressure if it is to be installed in a 
class 2, 3, or 4 location. Notwithstanding any shorter time period 
permitted under subpart J of this part, the test pressure must be 
maintained for at least 8 hours.

[35 FR 13257, Aug. 19, 1970]

    Editorial Note: For Federal Register citations affecting appendix B 
of part 192, see the List of CFR Sections Affected, which appears in the 
Finding Aids section of the printed volume and on GPO Access.



  Sec. Appendix C to Part 192--Qualification of Welders for Low Stress 
                               Level Pipe

    I. Basic test. The test is made on pipe 12 inches (305 millimeters) 
or less in diameter. The test weld must be made with the pipe in a 
horizontal fixed position so that the test weld includes at least one 
section of overhead position welding. The beveling, root opening, and 
other details must conform to the specifications of the procedure under 
which the welder is being qualified. Upon completion, the test weld is 
cut into four coupons and subjected to a root bend test. If, as a result 
of this test, two or more of the four coupons develop a crack in the 
weld material, or between the weld material and base metal, that is more 
than \1/8\-inch (3.2 millimeters) long in any direction, the weld is 
unacceptable. Cracks that occur on the corner of the specimen during 
testing are not considered. A welder who successfully passes a butt-weld 
qualification test under this section shall be qualified to weld on all 
pipe diameters less than or equal to 12 inches.
    II. Additional tests for welders of service line connections to 
mains. A service line connection fitting is welded to a pipe section 
with the same diameter as a typical main. The weld is made in the same 
position as it is made in the field. The weld is unacceptable if it 
shows a serious undercutting or if it has rolled edges. The weld is 
tested by attempting to break the fitting off the run pipe. The weld is 
unacceptable if it breaks and shows incomplete fusion, overlap, or poor 
penetration at the junction of the fitting and run pipe.
    III. Periodic tests for welders of small service lines. Two samples 
of the welder's work, each about 8 inches (203 millimeters) long with 
the weld located approximately in the center, are cut from steel service 
line and tested as follows:
    (1) One sample is centered in a guided bend testing machine and bent 
to the contour of the die for a distance of 2 inches (51 millimeters) on 
each side of the weld. If the sample shows any breaks or cracks after 
removal from the bending machine, it is unacceptable.
    (2) The ends of the second sample are flattened and the entire joint 
subjected to a tensile strength test. If failure occurs adjacent to or 
in the weld metal, the weld is unacceptable. If a tensile strength 
testing machine is not available, this sample must also pass the

[[Page 132]]

bending test prescribed in subparagraph (1) of this paragraph.

[35 FR 13257, Aug. 19, 1970, as amended by Amdt. 192-85, 63 FR 37504, 
July 13, 1998; Amdt. 192-94, 69 FR 32896, June 14, 2004]



   Sec. Appendix D to Part 192--Criteria for Cathodic Protection and 
                      Determination of Measurements

    I. Criteria for cathodic protection-- A. Steel, cast iron, and 
ductile iron structures. (1) A negative (cathodic) voltage of at least 
0.85 volt, with reference to a saturated copper-copper sulfate half 
cell. Determination of this voltage must be made with the protective 
current applied, and in accordance with sections II and IV of this 
appendix.
    (2) A negative (cathodic) voltage shift of at least 300 millivolts. 
Determination of this voltage shift must be made with the protective 
current applied, and in accordance with sections II and IV of this 
appendix. This criterion of voltage shift applies to structures not in 
contact with metals of different anodic potentials.
    (3) A minimum negative (cathodic) polarization voltage shift of 100 
millivolts. This polarization voltage shift must be determined in 
accordance with sections III and IV of this appendix.
    (4) A voltage at least as negative (cathodic) as that originally 
established at the beginning of the Tafel segment of the E-log-I curve. 
This voltage must be measured in accordance with section IV of this 
appendix.
    (5) A net protective current from the electrolyte into the structure 
surface as measured by an earth current technique applied at 
predetermined current discharge (anodic) points of the structure.
    B. Aluminum structures. (1) Except as provided in paragraphs (3) and 
(4) of this paragraph, a minimum negative (cathodic) voltage shift of 
150 millivolts, produced by the application of protective current. The 
voltage shift must be determined in accordance with sections II and IV 
of this appendix.
    (2) Except as provided in paragraphs (3) and (4) of this paragraph, 
a minimum negative (cathodic) polarization voltage shift of 100 
millivolts. This polarization voltage shift must be determined in 
accordance with sections III and IV of this appendix.
    (3) Notwithstanding the alternative minimum criteria in paragraphs 
(1) and (2) of this paragraph, aluminum, if cathodically protected at 
voltages in excess of 1.20 volts as measured with reference to a copper-
copper sulfate half cell, in accordance with section IV of this 
appendix, and compensated for the voltage (IR) drops other than those 
across the structure-electrolyte boundary may suffer corrosion resulting 
from the build-up of alkali on the metal surface. A voltage in excess of 
1.20 volts may not be used unless previous test results indicate no 
appreciable corrosion will occur in the particular environment.
    (4) Since aluminum may suffer from corrosion under high pH 
conditions, and since application of cathodic protection tends to 
increase the pH at the metal surface, careful investigation or testing 
must be made before applying cathodic protection to stop pitting attack 
on aluminum structures in environments with a natural pH in excess of 8.
    C. Copper structures. A minimum negative (cathodic) polarization 
voltage shift of 100 millivolts. This polarization voltage shift must be 
determined in accordance with sections III and IV of this appendix.
    D. Metals of different anodic potentials. A negative (cathodic) 
voltage, measured in accordance with section IV of this appendix, equal 
to that required for the most anodic metal in the system must be 
maintained. If amphoteric structures are involved that could be damaged 
by high alkalinity covered by paragraphs (3) and (4) of paragraph B of 
this section, they must be electrically isolated with insulating 
flanges, or the equivalent.
    II. Interpretation of voltage measurement. Voltage (IR) drops other 
than those across the structure-electrolyte boundary must be considered 
for valid interpretation of the voltage measurement in paragraphs A(1) 
and (2) and paragraph B(1) of section I of this appendix.
    III. Determination of polarization voltage shift. The polarization 
voltage shift must be determined by interrupting the protective current 
and measuring the polarization decay. When the current is initially 
interrupted, an immediate voltage shift occurs. The voltage reading 
after the immediate shift must be used as the base reading from which to 
measure polarization decay in paragraphs A(3), B(2), and C of section I 
of this appendix.
    IV. Reference half cells. A. Except as provided in paragraphs B and 
C of this section, negative (cathodic) voltage must be measured between 
the structure surface and a saturated copper-copper sulfate half cell 
contacting the electrolyte.
    B. Other standard reference half cells may be substituted for the 
saturated cooper-copper sulfate half cell. Two commonly used reference 
half cells are listed below along with their voltage equivalent to -0.85 
volt as referred to a saturated copper-copper sulfate half cell:
    (1) Saturated KCl calomel half cell: -0.78 volt.
    (2) Silver-silver chloride half cell used in sea water: -0.80 volt.
    C. In addition to the standard reference half cells, an alternate 
metallic material or structure may be used in place of the saturated 
copper-copper sulfate half cell if its potential stability is assured 
and if its voltage

[[Page 133]]

equivalent referred to a saturated copper-copper sulfate half cell is 
established.

[Amdt. 192-4, 36 FR 12305, June 30, 1971]



 Sec. Appendix E to Part 192--Guidance on Determining High Consequence 
 Areas and on Carrying out Requirements in the Integrity Management Rule

           I. Guidance on Determining a High Consequence Area

    To determine which segments of an operator's transmission pipeline 
system are covered for purposes of the integrity management program 
requirements, an operator must identify the high consequence areas. An 
operator must use method (1) or (2) from the definition in Sec. 192.903 
to identify a high consequence area. An operator may apply one method to 
its entire pipeline system, or an operator may apply one method to 
individual portions of the pipeline system. (Refer to figure E.I.A for a 
diagram of a high consequence area).

[[Page 134]]

[GRAPHIC] [TIFF OMITTED] TR06AP04.003

    II. Guidance on Assessment Methods and Additional Preventive and 
             Mitigative Measures for Transmission Pipelines

    (a) Table E.II.1 gives guidance to help an operator implement 
requirements on additional preventive and mitigative measures for 
addressing time dependent and independent threats for a transmission 
pipeline operating below 30% SMYS not in an HCA (i.e. outside of 
potential impact circle) but located within a Class 3 or Class 4 
Location.
    (b) Table E.II.2 gives guidance to help an operator implement 
requirements on assessment methods for addressing time dependent and 
independent threats for a transmission pipeline in an HCA.
    (c) Table E.II.3 gives guidance on preventative & mitigative 
measures addressing time

[[Page 135]]

dependent and independent threats for transmission pipelines that 
operate below 30% SMYS, in HCAs.
[GRAPHIC] [TIFF OMITTED] TR06AP04.004


[[Page 136]]


[GRAPHIC] [TIFF OMITTED] TR06AP04.005


[[Page 137]]


[GRAPHIC] [TIFF OMITTED] TR06AP04.006


[[Page 138]]


[GRAPHIC] [TIFF OMITTED] TR06AP04.007


[[Page 139]]


[GRAPHIC] [TIFF OMITTED] TR06AP04.008


[[Page 140]]


[GRAPHIC] [TIFF OMITTED] TR06AP04.009


[[Page 141]]


[GRAPHIC] [TIFF OMITTED] TR06AP04.010


[[Page 142]]



[Amdt. 192-95, 69 FR 18234, Apr. 6, 2004, as amended by Amdt. 192-95, 
May 26, 2004]



PART 193_LIQUEFIED NATURAL GAS FACILITIES: FEDERAL SAFETY STANDARDS--
Table of Contents




                            Subpart A_General

Sec.
193.2001 Scope of part.
193.2003 [Reserved]
193.2005 Applicability.
193.2007 Definitions.
193.2009 Rules of regulatory construction.
193.2011 Reporting.
193.2013 Incorporation by reference.
193.2015 [Reserved]
193.2017 Plans and procedures.
193.2019 Mobile and temporary LNG facilities.

                      Subpart B_Siting Requirements

193.2051 Scope.
193.2055 [Reserved]
193.2057 Thermal radiation protection.
193.2059 Flammable vapor-gas dispersion protection.
193.2061-193.2065 [Reserved]
193.2067 Wind forces.
193.2069-193.2073 [Reserved]

                            Subpart C_Design

193.2101 Scope.

                                Materials

193.2103-193.2117 [Reserved]
193.2119 Records.

                   Design of Components and Buildings

193.2121-193.2153 [Reserved]

                     Impoundment Design and Capacity

193.2155 Structural requirements.
193.2157-193.2159 [Reserved]
193.2161 Dikes, general.
193.2163-193.2165 [Reserved]
193.2167 Covered systems.
193.2169-193.2171 [Reserved]
193.2173 Water removal.
193.2175-193.2179 [Reserved]
193.2181 Impoundment capacity: LNG storage tanks.
193.2183-193.2185 [Reserved]

                            LNG Storage Tanks

193.2187 Nonmetallic membrane liner.
193.2189-193.2233 [Reserved]

                         Subpart D_Construction

193.2301 Scope.
193.2303 Construction acceptance.
193.2304 Corrosion control overview.
193.2305-193.2319 [Reserved]
193.2321 Nondestructive tests.
193.2323-193.2329 [Reserved]

                           Subpart E_Equipment

193.2401 Scope.

                         Vaporization Equipment

193.2403-193.2439 [Reserved]
193.2441 Control center.
193.2443 [Reserved]
193.2445 Sources of power.

                          Subpart F_Operations

193.2501 Scope.
193.2503 Operating procedures.
193.2505 Cooldown.
193.2507 Monitoring operations.
193.2509 Emergency procedures.
193.2511 Personnel safety.
193.2513 Transfer procedures.
193.2515 Investigations of failures.
193.2517 Purging.
193.2519 Communication systems.
193.2521 Operating records.

                          Subpart G_Maintenance

193.2601 Scope.
193.2603 General.
193.2605 Maintenance procedures.
193.2607 Foreign material.
193.2609 Support systems.
193.2611 Fire protection.
193.2613 Auxiliary power sources.
193.2615 Isolating and purging.
193.2617 Repairs.
193.2619 Control systems.
193.2621 Testing transfer hoses.
193.2623 Inspecting LNG storage tanks.
193.2625 Corrosion protection.
193.2627 Atmospheric corrosion control.
193.2629 External corrosion control: buried or submerged components.
193.2631 Internal corrosion control.
193.2633 Interference currents.
193.2635 Monitoring corrosion control.
193.2637 Remedial measures.
193.2639 Maintenance records.

             Subpart H_Personnel Qualifications and Training

193.2701 Scope.
193.2703 Design and fabrication.
193.2705 Construction, installation, inspection, and testing.
193.2707 Operations and maintenance.
193.2709 Security.
193.2711 Personnel health.
193.2713 Training: operations and maintenance.
193.2715 Training: security.
193.2717 Training: fire protection.
193.2719 Training: records.

[[Page 143]]

                        Subpart I_Fire Protection

193.2801 Fire protection.
193.2803-193.2821 [Reserved]

                           Subpart J_Security

193.2901 Scope.
193.2903 Security procedures.
193.2905 Protective enclosures.
193.2907 Protective enclosure construction.
193.2909 Security communications.
193.2911 Security lighting.
193.2913 Security monitoring.
193.2915 Alternative power sources.
193.2917 Warning signs.

    Authority: 49 U.S.C. 5103, 60102, 60103, 60104, 60108, 60109, 60110, 
60113, 60118; and 49 CFR 1.53.

    Source: 45 FR 9203, Feb. 11, 1980, unless otherwise noted.

    Editorial Note: Nomenclature changes to part 193 appear at 71 FR 
33408, June 9, 2006.



                            Subpart A_General



Sec. 193.2001  Scope of part.

    (a) This part prescribes safety standards for LNG facilities used in 
the transportation of gas by pipeline that is subject to the pipeline 
safety laws (49 U.S.C. 60101 et seq.) and Part 192 of this chapter.
    (b) This part does not apply to:
    (1) LNG facilities used by ultimate consumers of LNG or natural gas.
    (2) LNG facilities used in the course of natural gas treatment or 
hydrocarbon extraction which do not store LNG.
    (3) In the case of a marine cargo transfer system and associated 
facilities, any matter other than siting pertaining to the system or 
facilities between the marine vessel and the last manifold (or in the 
absence of a manifold, the last valve) located immediately before a 
storage tank.
    (4) Any LNG facility located in navigable waters (as defined in 
Section 3(8) of the Federal Power Act (16 U.S.C. 796(8)).

[45 FR 9203, Feb. 11, 1980, as amended by Amdt. 193-1, 45 FR 57418, Aug. 
28, 1980; Amdt. 193-10, 61 FR 18517, Apr. 26, 1996]



Sec. 193.2003  [Reserved]



Sec. 193.2005  Applicability.

    (a) Regulations in this part governing siting, design, installation, 
or construction of LNG facilities (including material incorporated by 
reference in these regulations) do not apply to LNG facilities in 
existence or under construction when the regulations go into effect.
    (b) If an existing LNG facility (or facility under construction 
before March 31, 2000 is replaced, relocated or significantly altered 
after March 31, 2000, the facility must comply with the applicable 
requirements of this part governing, siting, design, installation, and 
construction, except that:
    (1) The siting requirements apply only to LNG storage tanks that are 
significantly altered by increasing the original storage capacity or 
relocated, and
    (2) To the extent compliance with the design, installation, and 
construction requirements would make the replaced, relocated, or altered 
facility incompatible with the other facilities or would otherwise be 
impractical, the replaced, relocated, or significantly altered facility 
may be designed, installed, or constructed in accordance with the 
original specifications for the facility, or in another manner subject 
to the approval of the Administrator.

[Amdt. 193-17, 65 FR 10958, Mar. 1, 2000, as amended by Amdt. 193-18, 69 
FR 11336, Mar. 10, 2004]



Sec. 193.2007  Definitions.

    As used in this part:
    Administrator means the Administrator, Pipeline and Hazardous 
Materials Safety Administration or his or her delegate.
    Ambient vaporizer means a vaporizer which derives heat from 
naturally occurring heat sources, such as the atmosphere, sea water, 
surface waters, or geothermal waters.
    Cargo transfer system means a component, or system of components 
functioning as a unit, used exclusively for transferring hazardous 
fluids in bulk between a tank car, tank truck, or marine vessel and a 
storage tank.
    Component means any part, or system of parts functioning as a unit, 
including, but not limited to, piping, processing equipment, containers, 
control devices, impounding systems, lighting, security devices, fire 
control equipment, and communication equipment,

[[Page 144]]

whose integrity or reliability is necessary to maintain safety in 
controlling, processing, or containing a hazardous fluid.
    Container means a component other than piping that contains a 
hazardous fluid.
    Control system means a component, or system of components 
functioning as a unit, including control valves and sensing, warning, 
relief, shutdown, and other control devices, which is activated either 
manually or automatically to establish or maintain the performance of 
another component.
    Controllable emergency means an emergency where reasonable and 
prudent action can prevent harm to people or property.
    Design pressure means the pressure used in the design of components 
for the purpose of determining the minimum permissible thickness or 
physical characteristics of its various parts. When applicable, static 
head shall be included in the design pressure to determine the thickness 
of any specific part.
    Determine means make an appropriate investigation using scientific 
methods, reach a decision based on sound engineering judgment, and be 
able to demonstrate the basis of the decision.
    Dike means the perimeter of an impounding space forming a barrier to 
prevent liquid from flowing in an unintended direction.
    Emergency means a deviation from normal operation, a structural 
failure, or severe environmental conditions that probably would cause 
harm to people or property.
    Exclusion zone means an area surrounding an LNG facility in which an 
operator or government agency legally controls all activities in 
accordance with Sec. 193.2057 and Sec. 193.2059 for as long as the 
facility is in operation.
    Fail-safe means a design feature which will maintain or result in a 
safe condition in the event of malfunction or failure of a power supply, 
component, or control device.
    g means the standard acceleration of gravity of 9.806 meters per 
second\2\ (32.17 feet per second\2\).
    Gas, except when designated as inert, means natural gas, other 
flammable gas, or gas which is toxic or corrosive.
    Hazardous fluid means gas or hazardous liquid.
    Hazardous liquid means LNG or a liquid that is flammable or toxic.
    Heated vaporizer means a vaporizer which derives heat from other 
than naturally occurring heat sources.
    Impounding space means a volume of space formed by dikes and floors 
which is designed to confine a spill of hazardous liquid.
    Impounding system includes an impounding space, including dikes and 
floors for conducting the flow of spilled hazardous liquids to an 
impounding space.
    Liquefied natural gas or LNG means natural gas or synthetic gas 
having methane (CH4) as its major constituent which has been 
changed to a liquid.
    LNG facility means a pipeline facility that is used for liquefying 
natural gas or synthetic gas or transferring, storing, or vaporizing 
liquefied natural gas.
    LNG plant means an LNG facility or system of LNG facilities 
functioning as a unit.
    m\3\ means a volumetric unit which is one cubic metre, 6.2898 
barrels, 35.3147 ft.\3\, or 264.1720 U.S. gallons, each volume being 
considered as equal to the other.
    Maximum allowable working pressure means the maximum gage pressure 
permissible at the top of the equipment, containers or pressure vessels 
while operating at design temperature.
    Normal operation means functioning within ranges of pressure, 
temperature, flow, or other operating criteria required by this part.
    Operator means a person who owns or operates an LNG facility.
    Person means any individual, firm, joint venture, partnership, 
corporation, association, state, municipality, cooperative association, 
or joint stock association and includes any trustee, receiver, assignee, 
or personal representative thereof.
    Pipeline facility means new and existing piping, rights-of-way, and 
any equipment, facility, or building used in the transportation of gas 
or in the treatment of gas during the course of transportation.

[[Page 145]]

    Piping means pipe, tubing, hoses, fittings, valves, pumps, 
connections, safety devices or related components for containing the 
flow of hazardous fluids.
    Storage tank means a container for storing a hazardous fluid.
    Transfer piping means a system of permanent and temporary piping 
used for transferring hazardous fluids between any of the following: 
Liquefaction process facilities, storage tanks, vaporizers, compressors, 
cargo transfer systems, and facilities other than pipeline facilities.
    Transfer system includes transfer piping and cargo transfer system.
    Vaporization means an addition of thermal energy changing a liquid 
to a vapor or gaseous state.
    Vaporizer means a heat transfer facility designed to introduce 
thermal energy in a controlled manner for changing a liquid to a vapor 
or gaseous state.
    Waterfront LNG plant means an LNG plant with docks, wharves, piers, 
or other structures in, on, or immediately adjacent to the navigable 
waters of the United States or Puerto Rico and any shore area 
immediately adjacent to those waters to which vessels may be secured and 
at which LNG cargo operations may be conducted.

[45 FR 9203, Feb. 11, 1980, as amended by Amdt. 193-1, 45 FR 57418, Aug. 
28, 1980; Amdt. 193-2, 45 FR 70404, Oct. 23, 1980; Amdt. 193-10, 61 FR 
18517, Apr. 26, 1996; Amdt. 193-17, 65 FR 10958, Mar. 1, 2000; 68 FR 
11749, Mar. 12, 2003; 70 FR 11140, Mar. 8, 2005]



Sec. 193.2009  Rules of regulatory construction.

    (a) As used in this part:
    (1) Includes means including but not limited to;
    (2) May means is permitted to or is authorized to;
    (3) May not means is not permitted to or is not authorized to; and
    (4) Shall or must is used in the mandatory and imperative sense.
    (b) In this part:
    (1) Words importing the singular include the plural; and
    (2) Words importing the plural include the singular.



Sec. 193.2011  Reporting.

    Leaks and spills of LNG must be reported in accordance with the 
requirements of part 191 of this chapter.



Sec. 193.2013  Incorporation by reference.

    (a) Any document or portion thereof incorporated by reference in 
this part is included in this part as though it were printed in full. 
When only a portion of a document is referenced, then this part 
incorporates only that referenced portion of the document and the 
remainder is not incorporated. Applicable editions are listed in 
paragraph (c) of this section in parentheses following the title of the 
referenced material. Earlier editions listed in previous editions of 
this section may be used for components manufactured, designed, or 
installed in accordance with those earlier editions at the time they 
were listed. The user must refer to the appropriate previous edition of 
49 CFR for a listing of the earlier editions.
    (b) All incorporated materials are available for inspection in the 
Pipeline and Hazardous Materials Safety Administration, PHP-30, 1200 New 
Jersey Avenue, SE., Washington, DC, 20590-0001, 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.
    Documents incorporated by reference are available from the 
publishers as follows:
    A. American Gas Association (AGA), 400 North Capitol Street, NW., 
Washington, DC 20001.
    B. American Society of Civil Engineers (ASCE), Parallel Centre, 1801 
Alexander Bell Drive, Reston, VA 20191-4400.
    C. ASME International (ASME), Three Park Avenue, New York, NY 10016-
5990.
    D. Gas Technology Institute (GTI), 1700 S. Mount Prospect Road, Des 
Plaines, IL 60018.
    E. National Fire Protection Association (NFPA), 1 Batterymarch Park, 
P.O. Box 9101, Quincy, MA 02269-9101.
    (c) Documents incorporated by reference.

[[Page 146]]



------------------------------------------------------------------------
    Source and name of referenced material          49 CFR reference
------------------------------------------------------------------------
A. American Gas Association (AGA):
  (1) ``Purging Principles and Practices,''    Sec. Sec.  193.2513;
   (3rd edition, 2001)..                        193.2517; 193.2615.
B. American Society of Civil Engineers
 (ASCE):
  (1) SEI/ASCE 7-02 ``Minimum Design Loads     Sec.  193.2067.
   for Buildings and Other Structures,''
   (2002 edition)..
C. ASME International (ASME):
  (1) ASME Boiler and Pressure Vessel Code,    Sec.  193.2321.
   Section VIII, Division 1, ``Rules for
   Construction of Pressure Vessels,'' (2004
   edition, including addenda through July 1,
   2005).
  (2) ASME Boiler and Pressure Vessel Code,    Sec.  193.2321.
   Section VIII, Division 2, ``Rules for
   Construction of Pressure Vessels--
   Alternative Rules,'' (2004 edition,
   including addenda through July 1, 2005).
D. Gas Technology Institute (GTI):
  (1) GRI-89/0176 ``LNGFIRE: A Thermal         Sec.  193.2057.
   Radiation Model for LNG Fires,'' (June 29,
   1990).
  (2) GTI-04/0049 (April 2004) ``LNG Vapor     Sec.  193.2059.
   Dispersion Prediction with the DEGADIS
   2.1: Dense Gas Dispersion Model for LNG
   Vapor Dispersion''.
  (3) GRI-96/0396.5 ``Evaluation of            Sec.  193.2059.
   Mitigation Methods for Accidental LNG
   Releases, Volume 5: Using FEM3A for LNG
   Accident Consequence Analyses,'' (April
   1997).
E. National Fire Protection Association
 (NFPA):
  (1) NFPA 59A (2001) ``Standard for the       Sec. Sec.  193.2019;
   Production, Storage, and Handling of         193.2051; 193.2057;
   Liquefied Natural Gas (LNG).''.              193.2059; 193.2101;
                                                193.2301; 193.2303;
                                                193.2401; 193.2521;
                                                193.2639; 193.2801.
------------------------------------------------------------------------


[Amdt. 193-19, 71 FR 33408, June 9, 2006; 73 FR 16570, Mar. 28, 2008; 74 
FR 2894, Jan. 16, 2009]



Sec. 193.2015  [Reserved]



Sec. 193.2017  Plans and procedures.

    (a) Each operator shall maintain at each LNG plant the plans and 
procedures required for that plant by this part. The plans and 
procedures must be available upon request for review and inspection by 
the Administrator or any State Agency that has submitted a current 
certification or agreement with respect to the plant under the pipeline 
safety laws (49 U.S.C. 60101 et seq.). In addition, each change to the 
plans or procedures must be available at the LNG plant for review and 
inspection within 20 days after the change is made.
    (b) The Administrator or the State Agency that has submitted a 
current certification under section 5(a) of the Natural Gas Pipeline 
Safety Act 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) Each operator must review and update the plans and procedures 
required by this part--
    (1) When a component is changed significantly or a new component is 
installed; and
    (2) At intervals not exceeding 27 months, but at least once every 2 
calendar years.

[Amdt. 193-2, 45 FR 70404, Oct. 23, 1980, as amended by Amdt. 193-7, 56 
FR 31090, July 9, 1991; Amdt. 193-10, 61 FR 18517, Apr. 26, 1996; Amdt. 
193-18, 69 FR 11336, Mar. 10, 2004]



Sec. 193.2019  Mobile and temporary LNG facilities.

    (a) Mobile and temporary LNG facilities for peakshaving application, 
for service maintenance during gas pipeline systems repair/alteration, 
or for other short term applications need not meet the requirements of 
this part if the facilities are in compliance with applicable sections 
of NFPA 59A (incorporated by reference, see Sec. 193.2013).
    (b) The State agency having jurisdiction over pipeline safety in the 
State in which the portable LNG equipment is to be located must be 
provided with a location description for the installation at least 2 
weeks in advance, including to the extent practical, the details of 
siting, leakage containment or control, fire fighting equipment, and 
methods employed to restrict public

[[Page 147]]

access, except that in the case of emergency where such notice is not 
possible, as much advance notice as possible must be provided.

[Amdt. 193-14, 62 FR 41311, Aug. 1, 1997, as amended by Amdt. 193-18, 
11336, Mar. 10, 2004]



                      Subpart B_Siting Requirements



Sec. 193.2051  Scope.

    Each LNG facility designed, constructed, replaced, relocated or 
significantly altered after March 31, 2000 must be provided with siting 
requirements in accordance with the requirements of this part and of 
NFPA 59A (incorporated by reference, see Sec. 193.2013). In the event 
of a conflict between this part and NFPA 59A, this part prevails.

[Amdt. 193-17, 65 FR 10958, Mar. 1, 2000, as amended by Amdt. 193-18, 69 
FR 11336, Mar. 10, 2004]



Sec. 193.2055  [Reserved]



Sec. 193.2057  Thermal radiation protection.

    Each LNG container and LNG transfer system must have a thermal 
exclusion zone in accordance with section 2.2.3.2 of NFPA 59A 
(incorporated by reference, see Sec. 193.2013) with the following 
exceptions:
    (a) The thermal radiation distances shall be calculated using Gas 
Research Institute's (GRI) report GRI-89/0176 (incorporated by 
reference, see Sec. 193.2013), which is also available as the ``LNGFIRE 
III'' computer model produced by GRI. The use of other alternate models 
which take into account the same physical factors and have been 
validated by experimental test data shall be permitted subject to the 
Administrator's approval.
    (b) In calculating exclusion distances, the wind speed producing the 
maximum exclusion distances shall be used except for wind speeds that 
occur less than 5 percent of the time based on recorded data for the 
area.
    (c) In calculating exclusion distances, the ambient temperature and 
relative humidity that produce the maximum exclusion distances shall be 
used except for values that occur less than five percent of the time 
based on recorded data for the area.

[Amdt. 193-17, 65 FR 10958, Mar. 1, 2000, as amended by Amdt. 193-18, 69 
FR 11336, Mar. 10, 2004]



Sec. 193.2059  Flammable vapor-gas dispersion protection.

    Each LNG container and LNG transfer system must have a dispersion 
exclusion zone in accordance with sections 2.2.3.3 and 2.2.3.4 of NFPA 
59A (incorporated by reference, see Sec. 193.2013) with the following 
exceptions:
    (a) Flammable vapor-gas dispersion distances must be determined in 
accordance with the model described in the Gas Research Institute report 
GRI-89/0242 (incorporated by reference, see Sec. 193.2013), ``LNG Vapor 
Dispersion Prediction with the DEGADIS Dense Gas Dispersion Model.'' 
Alternatively, in order to account for additional cloud dilution which 
may be caused by the complex flow patterns induced by tank and dike 
structure, dispersion distances may be calculated in accordance with the 
model described in the Gas Research Institute report GRI-96/0396.5 
(incorporated by reference, see Sec. 193.2013), ``Evaluation of 
Mitigation Methods for Accidental LNG Releases. Volume 5: Using FEM3A 
for LNG Accident Consequence Analyses''. The use of alternate models 
which take into account the same physical factors and have been 
validated by experimental test data shall be permitted, subject to the 
Administrator's approval.
    (b) The following dispersion parameters must be used in computing 
dispersion distances:
    (1) Average gas concentration in air = 2.5 percent.
    (2) Dispersion conditions are a combination of those which result in 
longer predicted downwind dispersion distances than other weather 
conditions at the site at least 90 percent of the time, based on figures 
maintained by National Weather Service of the U.S. Department of 
Commerce, or as an alternative where the model used gives longer 
distances at lower wind speeds, Atmospheric Stability (Pasquill Class) 
F, wind speed = 4.5 miles per hour (2.01 meters/sec) at reference height 
of 10

[[Page 148]]

meters, relative humidity = 50.0 percent, and atmospheric temperature = 
average in the region.
    (3) The elevation for contour (receptor) output H = 0.5 meters.
    (4) A surface roughness factor of 0.03 meters shall be used. Higher 
values for the roughness factor may be used if it can be shown that the 
terrain both upwind and downwind of the vapor cloud has dense vegetation 
and that the vapor cloud height is more than ten times the height of the 
obstacles encountered by the vapor cloud.
    (c) The design spill shall be determined in accordance with section 
2.2.3.5 of NFPA 59A (incorporated by reference, see Sec. 193.2013).

[Amdt. 193-17, 65 FR 10959, Mar. 1, 2000, as amended by Amdt. 193-18, 69 
FR 11336, Mar. 10, 2004]



Sec. Sec. 193.2061-193.2065  [Reserved]



Sec. 193.2067  Wind forces.

    (a) LNG facilities must be designed to withstand without loss of 
structural or functional integrity:
    (1) The direct effect of wind forces;
    (2) The pressure differential between the interior and exterior of a 
confining, or partially confining, structure; and
    (3) In the case of impounding systems for LNG storage tanks, impact 
forces and potential penetrations by wind borne missiles.
    (b) The wind forces at the location of the specific facility must be 
based on one of the following:
    (1) For shop fabricated containers of LNG or other hazardous fluids 
with a capacity of not more than 70,000 gallons, applicable wind load 
data in SEI/ASCE 7-02 (incorporated by reference, see Sec. 193.2013).
    (2) For all other LNG facilities:
    (i) An assumed sustained wind velocity of not less than 150 miles 
per hour, unless the Administrator finds a lower velocity is justified 
by adequate supportive data; or
    (ii) The most critical combination of wind velocity and duration, 
with respect to the effect on the structure, having a probability of 
exceedance in a 50-year period of 0.5 percent or less, if adequate wind 
data are available and the probabilistic methodology is reliable.

[45 FR 9203, Feb. 11, 1980, as amended by Amdt. 193-1, 45 FR 57419, Aug. 
28, 1980; 58 FR 14522, Mar. 18, 1993; Amdt. 193-16, 63 FR 37505, July 
13, 1998; Amdt. 193-17, 65 FR 10959, Mar. 1, 2000; Amdt. 193-19, 71 FR 
33409, June 9, 2006]



Sec. Sec. 193.2069-193.2073  [Reserved]



                            Subpart C_Design



Sec. 193.2101  Scope.

    Each LNG facility designed after March 31, 2000 must comply with 
requirements of this part and of NFPA 59A (incorporated by reference, 
see Sec. 193.2013). In the event of a conflict between this part and 
NFPA 59A, this part prevails.

[Amdt. 193-17, 65 FR 10959, Mar. 1, 2000, as amended by Amdt. 193-18, 69 
FR 11336, Mar. 10, 2004]

                                Materials



Sec. Sec. 193.2103-193.2117  [Reserved]



Sec. 193.2119  Records

    Each operator shall keep a record of all materials for components, 
buildings, foundations, and support systems, as necessary to verify that 
material properties meet the requirements of this part. These records 
must be maintained for the life of the item concerned.

                   Design of Components and Buildings



Sec. Sec. 193.2121-193.2153  [Reserved]

                     Impoundment Design and Capacity



Sec. 193.2155  Structural requirements.

    (a) The structural members of an impoundment system must be designed 
and constructed to prevent impairment of the system's performance 
reliability and structural integrity as a result of the following:
    (1) The imposed loading from--
    (i) Full hydrostatic head of impounded LNG;
    (ii) Hydrodynamic action, including the effect of any material 
injected into the system for spill control;
    (iii) The impingement of the trajectory of an LNG jet discharged at 
any predictable angle; and

[[Page 149]]

    (iv) Anticipated hydraulic forces from a credible opening in the 
component or item served, assuming that the discharge pressure equals 
design pressure.
    (2) The erosive action from a spill, including jetting of spilling 
LNG, and any other anticipated erosive action including surface water 
runoff, ice formation, dislodgement of ice formation, and snow removal.
    (3) The effect of the temperature, any thermal gradient, and any 
other anticipated degradation resulting from sudden or localized contact 
with LNG.
    (4) Exposure to fire from impounded LNG or from sources other than 
impounded LNG.
    (5) If applicable, the potential impact and loading on the dike due 
to--
    (i) Collapse of the component or item served or adjacent components; 
and
    (ii) If the LNG facility adjoins the right-of-way of any highway or 
railroad, collision by or explosion of a train, tank car, or tank truck 
that could reasonably be expected to cause the most severe loading.
    (b) An LNG storage tank must not be located within a horizontal 
distance of one mile (1.6 km) from the ends, or \1/4\ mile (0.4 km) from 
the nearest point of a runway, whichever is longer. The height of LNG 
structures in the vicinity of an airport must also comply with Federal 
Aviation Administration requirements in 14 CFR Section 1.1.

[45 FR 9203, Feb. 11, 1980, as amended by Amdt. 193-17, 65 FR 10959, 
Mar. 1, 2000]



Sec. Sec. 193.2157-193.2159  [Reserved]



Sec. 193.2161  Dikes, general.

    An outer wall of a component served by an impounding system may not 
be used as a dike unless the outer wall is constructed of concrete.

[Amdt. 193-17, 65 FR 10959, Mar. 1, 2000]



Sec. Sec. 193.2163-193.2165  [Reserved]



Sec. 193.2167  Covered systems.

    A covered impounding system is prohibited except for concrete wall 
designed tanks where the concrete wall is an outer wall serving as a 
dike.

[Amdt. 193-17, 65 FR 10959, Mar. 1, 2000]



Sec. Sec. 193.2169-193.2171  [Reserved]



Sec. 193.2173  Water removal.

    (a) Impoundment areas must be constructed such that all areas drain 
completely to prevent water collection. Drainage pumps and piping must 
be provided to remove water from collecting in the impoundment area. 
Alternative means of draining may be acceptable subject to the 
Administrator's approval.
    (b) The water removal system must have adequate capacity to remove 
water at a rate equal to 25% of the maximum predictable collection rate 
from a storm of 10-year frequency and 1-hour duration, and other natural 
causes. For rainfall amounts, operators must use the ``Rainfall 
Frequency Atlas of the United States'' published by the National Weather 
Service of the U.S. Department of Commerce.
    (c) Sump pumps for water removal must--
    (1) Be operated as necessary to keep the impounding space as dry as 
practical; and
    (2) If sump pumps are designed for automatic operation, have 
redundant automatic shutdown controls to prevent operation when LNG is 
present.

[45 FR 9203, Feb. 11, 1980, as amended by Amdt. 193-17, 65 FR 10959, 
Mar. 1, 2000]



Sec. Sec. 193.2175-193.2179  [Reserved]



Sec. 193.2181  Impoundment capacity: LNG storage tanks.

    Each impounding system serving an LNG storage tank must have a 
minimum volumetric liquid impoundment capacity of:
    (a) 110 percent of the LNG tank's maximum liquid capacity for an 
impoundment serving a single tank;
    (b) 100 percent of all tanks or 110 percent of the largest tank's 
maximum liquid capacity, whichever is greater, for the impoundment 
serving more than one tank; or
    (c) If the dike is designed to account for a surge in the event of 
catastrophic failure, then the impoundment capacity may be reduced to 
100 percent in lieu of 110 percent.

[Amdt. 193-17, 65 FR 10960, Mar. 1, 2000]

[[Page 150]]



Sec. Sec. 193.2183-193.2185  [Reserved]

                            LNG Storage Tanks



Sec. 193.2187  Nonmetallic membrane liner.

    A flammable nonmetallic membrane liner may not be used as an inner 
container in a storage tank.

[Amdt. 193-17, 65 FR 10960, Mar. 1, 2000]



Sec. Sec. 193.2189-193.2233  [Reserved]



                         Subpart D_Construction



Sec. 193.2301  Scope.

    Each LNG facility constructed after March 31, 2000 must comply with 
requirements of this part and of NFPA 59A (incorporated by reference see 
Sec. 193.2013). In the event of a conflict between this part and NFPA 
59A, this part prevails.

[Amdt. 193-17, 65 FR 10960, Mar. 1, 2000, as amended by Amdt. 193-18, 69 
FR 11336, Mar. 10, 2004]



Sec. 193.2303  Construction acceptance.

    No person may place in service any component until it passes all 
applicable inspections and tests prescribed by this subpart and NFPA 59A 
(incorporated by reference, see Sec. 193.2013).

[45 FR 9203, Feb. 11, 1980, as amended by Amdt. 193-17, 65 FR 10960, 
Mar. 1, 2000; Amdt. 193-18, 69 FR 11337, Mar. 10, 2004]



Sec. 193.2304  Corrosion control overview.

    (a) Subject to paragraph (b) of this section, components may not be 
constructed, repaired, replaced, or significantly altered until a person 
qualified under Sec. 193.2707(c) reviews the applicable design drawings 
and materials specifications from a corrosion control viewpoint and 
determines that the materials involved will not impair the safety or 
reliability of the component or any associated components.
    (b) The repair, replacement, or significant alteration of components 
must be reviewed only if the action to be taken--
    (1) Involves a change in the original materials specified;
    (2) Is due to a failure caused by corrosion; or
    (3) Is occasioned by inspection revealing a significant 
deterioration of the component due to corrosion.

[Amdt. 193-2, 45 FR 70404, Oct. 23, 1980]



Sec. Sec. 193.2305-193.2319  [Reserved]



Sec. 193.2321  Nondestructive tests.

    The butt welds in metal shells of storage tanks with internal design 
pressure above 15 psig must be radiographically tested in accordance 
with the ASME Boiler and Pressure Vessel Code (Section VIII Division 1), 
except that hydraulic load bearing shells with curved surfaces that are 
subject to cryogenic temperatures, 100 percent of both longitudinal (or 
meridional) and circumferential (or latitudinal) welds must be 
radiographically tested.

[Amdt. 193-17, 65 FR 10960, Mar. 1, 2000]



Sec. Sec. 193.2323-193.2329  [Reserved]



                           Subpart E_Equipment



Sec. 193.2401  Scope.

    After March 31, 2000, each new, replaced, relocated or significantly 
altered vaporization equipment, liquefaction equipment, and control 
systems must be designed, fabricated, and installed in accordance with 
requirements of this part and of NFPA 59A. In the event of a conflict 
between this part and NFPA 59A (incorporated by reference, see Sec. 
193.2013), this part prevails.

[Amdt. 193-17, 65 FR 10960, Mar. 1, 2000, as amended by Amdt. 193-18, 69 
FR 11337, Mar. 10, 2004]

                         Vaporization Equipment



Sec. Sec. 193.2403-193.2439  [Reserved]



Sec. 193.2441  Control center.

    Each LNG plant must have a control center from which operations and 
warning devices are monitored as required by this part. A control center 
must have the following capabilities and characteristics:
    (a) It must be located apart or protected from other LNG facilities 
so that it is operational during a controllable emergency.

[[Page 151]]

    (b) Each remotely actuated control system and each automatic 
shutdown control system required by this part must be operable from the 
control center.
    (c) Each control center must have personnel in continuous attendance 
while any of the components under its control are in operation, unless 
the control is being performed from another control center which has 
personnel in continuous attendance.
    (d) If more than one control center is located at an LNG Plant, each 
control center must have more than one means of communication with each 
other center.
    (e) Each control center must have a means of communicating a warning 
of hazardous conditions to other locations within the plant frequented 
by personnel.



Sec. 193.2443  [Reserved]



Sec. 193.2445  Sources of power.

    (a) Electrical control systems, means of communication, emergency 
lighting, and firefighting systems must have at least two sources of 
power which function so that failure of one source does not affect the 
capability of the other source.
    (b) Where auxiliary generators are used as a second source of 
electrical power:
    (1) They must be located apart or protected from components so that 
they are not unusable during a controllable emergency; and
    (2) Fuel supply must be protected from hazards.



                          Subpart F_Operations

    Source: Amdt. 193-2, 45 FR 70405, Oct. 23, 1980, unless otherwise 
noted.



Sec. 193.2501  Scope.

    This subpart prescribes requirements for the operation of LNG 
facilities.



Sec. 193.2503  Operating procedures.

    Each operator shall follow one or more manuals of written procedures 
to provide safety in normal operation and in responding to an abnormal 
operation that would affect safety. The procedures must include 
provisions for:
    (a) Monitoring components or buildings according to the requirements 
of Sec. 193.2507.
    (b) Startup and shutdown, including for initial startup, performance 
testing to demonstrate that components will operate satisfactory in 
service.
    (c) Recognizing abnormal operating conditions.
    (d) Purging and inerting components according to the requirements of 
Sec. 193.2517.
    (e) In the case of vaporization, maintaining the vaporization rate, 
temperature and pressure so that the resultant gas is within limits 
established for the vaporizer and the downstream piping.
    (f) In the case of liquefaction, maintaining temperatures, 
pressures, pressure differentials and flow rates, as applicable, within 
their design limits for:
    (1) Boilers;
    (2) Turbines and other prime movers;
    (3) Pumps, compressors, and expanders;
    (4) Purification and regeneration equipment; and
    (5) Equipment within cold boxes.
    (g) Cooldown of components according to the requirements of Sec. 
193.2505.

[Amdt. 193-2, 45 FR 70405, Oct. 23, 1980, as amended by Amdt. 193-18, 69 
FR 11337, Mar. 10, 2004]



Sec. 193.2505  Cooldown.

    (a) The cooldown of each system of components that is subjected to 
cryogenic temperatures must be limited to a rate and distribution 
pattern that keeps thermal stresses within design limits during the 
cooldown period, paying particular attention to the performance of 
expansion and contraction devices.
    (b) After cooldown stabilization is reached, cryogenic piping 
systems must be checked for leaks in areas of flanges, valves, and 
seals.



Sec. 193.2507  Monitoring operations.

    Each component in operation or building in which a hazard to persons 
or property could exist must be monitored to detect fire or any 
malfunction or flammable fluid that could cause a hazardous condition. 
Monitoring must be accomplished by watching or listening from an 
attended control center for

[[Page 152]]

warning alarms, such as gas, temperature, pressure, vacuum, and flow 
alarms, or by conducting an inspection or test at intervals specified in 
the operating procedures.

[Amdt, 193-2, 45 FR 70405, Oct. 23, 1980, as amended by Amdt. 193-18, 69 
FR 11337, Mar. 10, 2004]



Sec. 193.2509  Emergency procedures.

    (a) Each operator shall determine the types and places of 
emergencies other than fires that may reasonably be expected to occur at 
an LNG plant due to operating malfunctions, structural collapse, 
personnel error, forces of nature, and activities adjacent to the plant.
    (b) To adequately handle each type of emergency identified under 
paragraph (a) of this section and each fire emergency, each operator 
must follow one or more manuals of written procedures. The procedures 
must provide for the following:
    (1) Responding to controllable emergencies, including notifying 
personnel and using equipment appropriate for handling the emergency.
    (2) Recognizing an uncontrollable emergency and taking action to 
minimize harm to the public and personnel, including prompt notification 
of appropriate local officials of the emergency and possible need for 
evacuation of the public in the vicinity of the LNG plant.
    (3) Coordinating with appropriate local officials in preparation of 
an emergency evacuation plan, which sets forth the steps required to 
protect the public in the event of an emergency, including catastrophic 
failure of an LNG storage tank.
    (4) Cooperating with appropriate local officials in evacuations and 
emergencies requiring mutual assistance and keeping these officials 
advised of:
    (i) The LNG plant fire control equipment, its location, and quantity 
of units located throughout the plant;
    (ii) Potential hazards at the plant, including fires;
    (iii) Communication and emergency control capabilities at the LNG 
plant; and
    (iv) The status of each emergency.

[Amdt. 193-2, 45 FR 70405, Oct. 23, 1980, as amended by Amdt. 193-18, 69 
FR 11337, Mar. 10, 2004]



Sec. 193.2511  Personnel safety.

    (a) Each operator shall provide any special protective clothing and 
equipment necessary for the safety of personnel while they are 
performing emergency response duties.
    (b) All personnel who are normally on duty at a fixed location, such 
as a building or yard, where they could be harmed by thermal radiation 
from a burning pool of impounded liquid, must be provided a means of 
protection at that location from the harmful effects of thermal 
radiation or a means of escape.
    (c) Each LNG plant must be equipped with suitable first-aid 
material, the location of which is clearly marked and readily available 
to personnel.



Sec. 193.2513  Transfer procedures.

    (a) Each transfer of LNG or other hazardous fluid must be conducted 
in accordance with one or more manuals of written procedures to provide 
for safe transfers.
    (b) The transfer procedures must include provisions for personnel 
to:
    (1) Before transfer, verify that the transfer system is ready for 
use, with connections and controls in proper positions, including if the 
system could contain a combustible mixture, verifying that it has been 
adequately purged in accordance with a procedure which meets the 
requirements of AGA ``Purging Principles and Practice.''
    (2) Before transfer, verify that each receiving container or tank 
vehicle does not contain any substance that would be incompatible with 
the incoming fluid and that there is sufficient capacity available to 
receive the amount of fluid to be transferred;
    (3) Before transfer, verify the maximum filling volume of each 
receiving container or tank vehicle to ensure that expansion of the 
incoming fluid due to warming will not result in overfilling or 
overpressure;
    (4) When making bulk transfer of LNG into a partially filled 
(excluding cooldown heel) container, determine any differences in 
temperature or specific gravity between the LNG being transferred and 
the LNG already in the container and, if necessary, provide a means to 
prevent rollover due to stratification.

[[Page 153]]

    (5) Verify that the transfer operations are proceeding within design 
conditions and that overpressure or overfilling does not occur by 
monitoring applicable flow rates, liquid levels, and vapor returns.
    (6) Manually terminate the flow before overfilling or overpressure 
occurs; and
    (7) Deactivate cargo transfer systems in a safe manner by 
depressurizing, venting, and disconnecting lines and conducting any 
other appropriate operations.
    (c) In addition to the requirements of paragraph (b) of this 
section, the procedures for cargo transfer must be located at the 
transfer area and include provisions for personnel to:
    (1) Be in constant attendance during all cargo transfer operations;
    (2) Prohibit the backing of tank trucks in the transfer area, except 
when a person is positioned at the rear of the truck giving instructions 
to the driver;
    (3) Before transfer, verify that:
    (i) Each tank car or tank truck complies with applicable regulations 
governing its use;
    (ii) All transfer hoses have been visually inspected for damage and 
defects;
    (iii) Each tank truck is properly immobilized with chock wheels, and 
electrically grounded; and
    (iv) Each tank truck engine is shut off unless it is required for 
transfer operations;
    (4) Prevent a tank truck engine that is off during transfer 
operations from being restarted until the transfer lines have been 
disconnected and any released vapors have dissipated;
    (5) Prevent loading LNG into a tank car or tank truck that is not in 
exclusive LNG service or that does not contain a positive pressure if it 
is in exclusive LNG service, until after the oxygen content in the tank 
is tested and if it exceeds 2 percent by volume, purged in accordance 
with a procedure that meets the requirements of AGA ``Purging Principles 
and Practice;''
    (6) Verify that all transfer lines have been disconnected and 
equipment cleared before the tank car or tank truck is moved from the 
transfer position; and
    (7) Verify that transfers into a pipeline system will not exceed the 
pressure or temperature limits of the system.



Sec. 193.2515  Investigations of failures.

    (a) Each operator shall investigate the cause of each explosion, 
fire, or LNG spill or leak which results in:
    (1) Death or injury requiring hospitalization; or
    (2) Property damage exceeding $10,000.
    (b) As a result of the investigation, appropriate action must be 
taken to minimize recurrence of the incident.
    (c) If the Administrator or relevant state agency under the pipeline 
safety laws (49 U.S.C. 60101 et seq.) investigates an incident, the 
operator involved shall make available all relevant information and 
provide reasonable assistance in conducting the investigation. Unless 
necessary to restore or maintain service, or for safety, no component 
involved in the incident may be moved from its location or otherwise 
altered until the investigation is complete or the investigating agency 
otherwise provides. Where components must be moved for operational or 
safety reasons, they must not be removed from the plant site and must be 
maintained intact to the extent practicable until the investigation is 
complete or the investigating agency otherwise provides.

[Amdt. 193-2, 45 FR 70405, Oct. 23, 1980, as amended by Amdt. 193-10, 61 
FR 18517, Apr. 26, 1996]



Sec. 193.2517  Purging.

    When necessary for safety, components that could accumulate 
significant amounts of combustible mixtures must be purged in accordance 
with a procedure which meets the provisions of the AGA ``Purging 
Principles and Practice'' after being taken out of service and before 
being returned to service.



Sec. 193.2519  Communication systems.

    (a) Each LNG plant must have a primary communication system that 
provides for verbal communications between all operating personnel at 
their work stations in the LNG plant.

[[Page 154]]

    (b) Each LNG plant in excess of 70,000 gallons (265,000 liters) 
storage capacity must have an emergency communication system that 
provides for verbal communications between all persons and locations 
necessary for the orderly shutdown of operating equipment and the 
operation of safety equipment in time of emergency. The emergency 
communication system must be independent of and physically separated 
from the primary communication system and the security communication 
system under Sec. 193.2909.
    (c) Each communication system required by this part must have an 
auxiliary source of power, except sound-powered equipment.

[45 FR 9203, Feb. 11, 1980, as amended by Amdt. 193-16, 63 FR 37505, 
July 13, 1998]



Sec. 193.2521  Operating records.

    Each operator shall maintain a record of results of each inspection, 
test and investigation required by this subpart. For each LNG facility 
that is designed and constructed after March 31, 2000 the operator shall 
also maintain related inspection, testing, and investigation records 
that NFPA 59A (incorporated by reference, see Sec. 193.2013) requires. 
Such records, whether required by this part or NFPA 59A, must be kept 
for a period of not less than five years.

[Amdt. 193-17, 65 FR 10960, Mar. 1, 2000, as amended by Amdt. 193-18, 69 
FR 11337, Mar. 10, 2004]



                          Subpart G_Maintenance

    Source: Amdt. 193-2, 45 FR 70407, Oct. 23, 1980, unless otherwise 
noted.



Sec. 193.2601  Scope.

    This subpart prescribes requirements for maintaining components at 
LNG plants.



Sec. 193.2603  General.

    (a) Each component in service, including its support system, must be 
maintained in a condition that is compatible with its operational or 
safety purpose by repair, replacement, or other means.
    (b) An operator may not place, return, or continue in service any 
component which is not maintained in accordance with this subpart.
    (c) Each component taken out of service must be identified in the 
records kept under Sec. 193.2639.
    (d) If a safety device is taken out of service for maintenance, the 
component being served by the device must be taken out of service unless 
the same safety function is provided by an alternate means.
    (e) If the inadvertent operation of a component taken out of service 
could cause a hazardous condition, that component must have a tag 
attached to the controls bearing the words ``do not operate'' or words 
of comparable meaning.



Sec. 193.2605  Maintenance procedures.

    (a) Each operator shall determine and perform, consistent with 
generally accepted engineering practice, the periodic inspections or 
tests needed to meet the applicable requirements of this subpart and to 
verify that components meet the maintenance standards prescribed by this 
subpart.
    (b) Each operator shall follow one or more manuals of written 
procedures for the maintenance of each component, including any required 
corrosion control. The procedures must include:
    (1) The details of the inspections or tests determined under 
paragraph (a) of this section and their frequency of performance; and
    (2) A description of other actions necessary to maintain the LNG 
plant according to the requirements of this subpart.
    (c) Each operator shall include in the manual required by paragraph 
(b) of this section 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 Sec. 191.23 of this subchapter.

[Amdt. 193-2, 45 FR 70407, Oct. 23, 1980, as amended by Amdt. 193-5, 53 
FR 24950, July 1, 1988; 53 FR 26560, July 13, 1988; Amdt. 193-18, 69 FR 
11337, Mar. 10, 2004]



Sec. 193.2607  Foreign material.

    (a) The presence of foreign material, contaminants, or ice shall be 
avoided

[[Page 155]]

or controlled to maintain the operational safety of each component.
    (b) LNG plant grounds must be free from rubbish, debris, and other 
material which present a fire hazard. Grass areas on the LNG plant 
grounds must be maintained in a manner that does not present a fire 
hazard.



Sec. 193.2609  Support systems.

    Each support system or foundation of each component must be 
inspected for any detrimental change that could impair support.



Sec. 193.2611  Fire protection.

    (a) Maintenance activities on fire control equipment must be 
scheduled so that a minimum of equipment is taken out of service at any 
one time and is returned to service in a reasonable period of time.
    (b) Access routes for movement of fire control equipment within each 
LNG plant must be maintained to reasonably provide for use in all 
weather conditions.



Sec. 193.2613  Auxiliary power sources.

    Each auxiliary power source must be tested monthly to check its 
operational capability and tested annually for capacity. The capacity 
test must take into account the power needed to start up and 
simultaneously operate equipment that would have to be served by that 
power source in an emergency.



Sec. 193.2615  Isolating and purging.

    (a) Before personnel begin maintenance activities on components 
handling flammable fluids which are isolated for maintenance, the 
component must be purged in accordance with a procedure which meets the 
requirements of AGA ``Purging Principles and Practices,'' unless the 
maintenance procedures under Sec. 193.2605 provide that the activity 
can be safely performed without purging.
    (b) If the component or maintenance activity provides an ignition 
source, a technique in addition to isolation valves (such as removing 
spool pieces or valves and blank flanging the piping, or double block 
and bleed valving) must be used to ensure that the work area is free of 
flammable fluids.



Sec. 193.2617  Repairs.

    (a) Repair work on components must be performed and tested in a 
manner which:
    (1) As far as practicable, complies with the applicable requirements 
of Subpart D of this part; and
    (2) Assures the integrity and operational safety of the component 
being repaired.
    (b) For repairs made while a component is operating, each operator 
shall include in the maintenance procedures under Sec. 193.2605 
appropriate precautions to maintain the safety of personnel and property 
during repair activities.



Sec. 193.2619  Control systems.

    (a) Each control system must be properly adjusted to operate within 
design limits.
    (b) If a control system is out of service for 30 days or more, it 
must be inspected and tested for operational capability before returning 
it to service.
    (c) Control systems in service, but not normally in operation, such 
as relief valves and automatic shutdown devices, and control systems for 
internal shutoff valves for bottom penetration tanks must be inspected 
and tested once each calender year, not exceeding 15 months, with the 
following exceptions:
    (1) Control systems used seasonally, such as for liquefaction or 
vaporization, must be inspected and tested before use each season.
    (2) Control systems that are intended for fire protection must be 
inspected and tested at regular intervals not to exceed 6 months.
    (d) Control systems that are normally in operation, such as required 
by a base load system, must be inspected and tested once each calendar 
year but with intervals not exceeding 15 months.
    (e) Relief valves must be inspected and tested for verification of 
the valve seat lifting pressure and reseating.

[Amdt. 193-2, 45 FR 70407, Oct. 23, 1980, as amended by Amdt. 193-17, 65 
FR 10960, Mar. 1, 2000]



Sec. 193.2621  Testing transfer hoses.

    Hoses used in LNG or flammable refrigerant transfer systems must be:

[[Page 156]]

    (a) Tested once each calendar year, but with intervals not exceeding 
15 months, to the maximum pump pressure or relief valve setting; and
    (b) Visually inspected for damage or defects before each use.



Sec. 193.2623  Inspecting LNG storage tanks.

    Each LNG storage tank must be inspected or tested to verify that 
each of the following conditions does not impair the structural 
integrity or safety of the tank:
    (a) Foundation and tank movement during normal operation and after a 
major meteorological or geophysical disturbance.
    (b) Inner tank leakage.
    (c) Effectiveness of insulation.
    (d) Frost heave.

[Amdt. 193-2, 45 FR 70407, Oct. 23, 1980, as amended at 47 FR 32720, 
July 29, 1982]



Sec. 193.2625  Corrosion protection.

    (a) Each operator shall determine which metallic components could, 
unless corrosion is controlled, have their integrity or reliability 
adversely affected by external, internal, or atmospheric corrosion 
during their intended service life.
    (b) Components whose integrity or reliability could be adversely 
affected by corrosion must be either--
    (1) Protected from corrosion in accordance with Sec. Sec. 193.2627 
through 193.2635, as applicable; or
    (2) Inspected and replaced under a program of scheduled maintenance 
in accordance with procedures established under Sec. 193.2605.



Sec. 193.2627  Atmospheric corrosion control.

    Each exposed component that is subject to atmospheric corrosive 
attack must be protected from atmospheric corrosion by--
    (a) Material that has been designed and selected to resist the 
corrosive atmosphere involved; or
    (b) Suitable coating or jacketing.



Sec. 193.2629  External corrosion control: buried or submerged components.

    (a) Each buried or submerged component that is subject to external 
corrosive attack must be protected from external corrosion by--
    (1) Material that has been designed and selected to resist the 
corrosive environment involved; or
    (2) The following means:
    (i) An external protective coating designed and installed to prevent 
corrosion attack and to meet the requirements of Sec. 192.461 of this 
chapter; and
    (ii) A cathodic protection system designed to protect components in 
their entirety in accordance with the requirements of Sec. 192.463 of 
this chapter and placed in operation before October 23, 1981, or within 
1 year after the component is constructed or installed, whichever is 
later.
    (b) Where cathodic protection is applied, components that are 
electrically interconnected must be protected as a unit.

[Amdt. 193-2, 45 FR 70407, Oct. 23, 1980, as amended at 47 FR 32720, 
July 29, 1982]



Sec. 193.2631  Internal corrosion control.

    Each component that is subject to internal corrosive attack must be 
protected from internal corrosion by--
    (a) Material that has been designed and selected to resist the 
corrosive fluid involved; or
    (b) Suitable coating, inhibitor, or other means.



Sec. 193.2633  Interference currents.

    (a) Each component that is subject to electrical current 
interference must be protected by a continuing program to minimize the 
detrimental effects of currents.
    (b) Each cathodic protection system must be designed and installed 
so as to minimize any adverse effects it might cause to adjacent metal 
components.
    (c) Each impressed current power source must be installed and 
maintained to prevent adverse interference with communications and 
control systems.



Sec. 193.2635  Monitoring corrosion control.

    Corrosion protection provided as required by this subpart must be 
periodically monitored to give early recognition of ineffective 
corrosion protection, including the following, as applicable:

[[Page 157]]

    (a) Each buried or submerged component under cathodic protection 
must be tested at least once each calendar year, but with intervals not 
exceeding 15 months, to determine whether the cathodic protection meets 
the requirements of Sec. 192.463 of this chapter.
    (b) Each cathodic protection rectifier or other impressed current 
power source must be inspected at least 6 times each calendar year, but 
with intervals not exceeding 2\1/2\ months, to ensure that it is 
operating properly.
    (c) Each reverse current switch, each diode, and each interference 
bond whose failure would jeopardize component protection must be 
electrically checked for proper performance at least 6 times each 
calendar year, but with intervals not exceeding 2\1/2\ months. Each 
other interference bond must be checked at least once each calendar 
year, but with intervals not exceeding 15 months.
    (d) Each component that is protected from atmospheric corrosion must 
be inspected at intervals not exceeding 3 years.
    (e) If a component is protected from internal corrosion, monitoring 
devices designed to detect internal corrosion, such as coupons or 
probes, must be located where corrosion is most likely to occur. 
However, monitoring is not required for corrosion resistant materials if 
the operator can demonstrate that the component will not be adversely 
affected by internal corrosion during its service life. Internal 
corrosion control monitoring devices must be checked at least two times 
each calendar year, but with intervals not exceeding 7\1/2\ months.



Sec. 193.2637  Remedial measures.

    Prompt corrective or remedial action must be taken whenever an 
operator learns by inspection or otherwise that atmospheric, external, 
or internal corrosion is not controlled as required by this subpart.



Sec. 193.2639  Maintenance records.

    (a) Each operator shall keep a record at each LNG plant of the date 
and type of each maintenance activity performed on each component to 
meet the requirements of this part. For each LNG facility that is 
designed and constructed after March 31, 2000 the operator shall also 
maintain related periodic inspection and testing records that NFPA 59A 
(incorporated by reference, see Sec. 193.2013) requires. Maintenance 
records, whether required by this part or NFPA 59A, must be kept for a 
period of not less than five years.
    (b) Each operator shall maintain records or maps to show the 
location of cathodically protected components, neighboring structures 
bonded to the cathodic protection system, and corrosion protection 
equipment.
    (c) Each of the following records must be retained for as long as 
the LNG facility remains in service:
    (1) Each record or map required by paragraph (b) of this section.
    (2) Records of each test, survey, or inspection required by this 
subpart in sufficient detail to demonstrate the adequacy of corrosion 
control measures.

[Amdt. 193-2, 45 FR 70407, Oct. 23, 1980, as amended by Amdt. 193-17, 65 
FR 10960, Mar. 1, 2000; Amdt. 193-18, 69 FR 11337, Mar. 10, 2004]



             Subpart H_Personnel Qualifications and Training

    Source: Sections 193.2707 through 193.2719 appear at Amdt. 193-2, 45 
FR 70404, Oct. 23, 1980 , unless otherwise noted.



Sec. 193.2701  Scope.

    This subpart prescribes requirements for personnel qualifications 
and training.

[45 FR 9219, Feb. 11, 1980]



Sec. 193.2703  Design and fabrication.

    For the design and fabrication of components, each operator shall 
use--
    (a) With respect to design, persons who have demonstrated competence 
by training or experience in the design of comparable components.
    (b) With respect to fabrication, persons who have demonstrated 
competence by training or experience in the fabrication of comparable 
components.

[45 FR 9219, Feb. 11, 1980]

[[Page 158]]



Sec. 193.2705  Construction, installation, inspection, and testing.

    (a) Supervisors and other personnel utilized for construction, 
installation, inspection, or testing must have demonstrated their 
capability to perform satisfactorily the assigned function by 
appropriate training in the methods and equipment to be used or related 
experience and accomplishments.
    (b) Each operator must periodically determine whether inspectors 
performing construction, installation, and testing duties required by 
this part are satisfactorily performing their assigned functions.

[45 FR 9219, Feb. 11, 1980, as amended by Amdt. 193-18, 69 FR 11337, 
Mar. 10, 2004]



Sec. 193.2707  Operations and maintenance.

    (a) Each operator shall utilize for operation or maintenance of 
components only those personnel who have demonstrated their capability 
to perform their assigned functions by--
    (1) Successful completion of the training required by Sec. Sec. 
193.2713 and 193.2717; and
    (2) Experience related to the assigned operation or maintenance 
function; and
    (3) Acceptable performance on a proficiency test relevant to the 
assigned function.
    (b) A person who does not meet the requirements of paragraph (a) of 
this section may operate or maintain a component when accompanied and 
directed by an individual who meets the requirements.
    (c) Corrosion control procedures under Sec. 193.2605(b), including 
those for the design, installation, operation, and maintenance of 
cathodic protection systems, must be carried out by, or under the 
direction of, a person qualified by experience and training in corrosion 
control technology.



Sec. 193.2709  Security.

    Personnel having security duties must be qualified to perform their 
assigned duties by successful completion of the training required under 
Sec. 193.2715.



Sec. 193.2711  Personnel health.

    Each operator shall follow a written plan to verify that personnel 
assigned operating, maintenance, security, or fire protection duties at 
the LNG plant do not have any physical condition that would impair 
performance of their assigned duties. The plan must be designed to 
detect both readily observable disorders, such as physical handicaps or 
injury, and conditions requiring professional examination for discovery.



Sec. 193.2713  Training: operations and maintenance.

    (a) Each operator shall provide and implement a written plan of 
initial training to instruct--
    (1) All permanent maintenance, operating, and supervisory 
personnel--
    (i) About the characteristics and hazards of LNG and other flammable 
fluids used or handled at the facility, including, with regard to LNG, 
low temperatures, flammability of mixtures with air, odorless vapor, 
boiloff characteristics, and reaction to water and water spray;
    (ii) About the potential hazards involved in operating and 
maintenance activities; and
    (iii) To carry out aspects of the operating and maintenance 
procedures under Sec. Sec. 193.2503 and 193.2605 that relate to their 
assigned functions; and
    (2) All personnel--
    (i) To carry out the emergency procedures under Sec. 193.2509 that 
relate to their assigned functions; and
    (ii) To give first-aid; and
    (3) All operating and appropriate supervisory personnel--
    (i) To understand detailed instructions on the facility operations, 
including controls, functions, and operating procedures; and
    (ii) To understand the LNG transfer procedures provided under Sec. 
193.2513.
    (b) A written plan of continuing instruction must be conducted at 
intervals of not more than two years to keep all personnel current on 
the knowledge and skills they gained in the program of initial 
instruction.

[[Page 159]]



Sec. 193.2715  Training: security.

    (a) Personnel responsible for security at an LNG plant must be 
trained in accordance with a written plan of initial instruction to:
    (1) Recognize breaches of security;
    (2) Carry out the security procedures under Sec. 193.2903 that 
relate to their assigned duties;
    (3) Be familiar with basic plant operations and emergency 
procedures, as necessary to effectively perform their assigned duties; 
and
    (4) Recognize conditions where security assistance is needed.
    (b) A written plan of continuing instruction must be conducted at 
intervals of not more than two years to keep all personnel having 
security duties current on the knowledge and skills they gained in the 
program of initial instruction.



Sec. 193.2717  Training: fire protection.

    (a) All personnel involved in maintenance and operations of an LNG 
plant, including their immediate supervisors, must be trained according 
to a written plan of initial instruction, including plant fire drills, 
to:
    (1) Know the potential causes and areas of fire;
    (2) Know the types, sizes, and predictable consequences of fire; and
    (3) Know and be able to perform their assigned fire control duties 
according to the procedures established under Sec. 193.2509 and by 
proper use of equipment provided under Sec. 193.2801.
    (b) A written plan of continuing instruction, including plant fire 
drills, must be conducted at intervals of not more than two years to 
keep personnel current on the knowledge and skills they gained in the 
instruction under paragraph (a) of the section.
    (c) Plant fire drills must provide personnel hands-on experience in 
carrying out their duties under the fire emergency procedures required 
by Sec. 193.2509.

[Amdt. 193-2, 45 FR 70404, Oct. 23, 1980, as amended by Amdt. 193-18, 69 
FR 11337, Mar. 10, 2004]



Sec. 193.2719  Training: records.

    (a) Each operator shall maintain a system of records which--
    (1) Provide evidence that the training programs required by this 
subpart have been implemented; and
    (2) Provide evidence that personnel have undergone and 
satisfactorily completed the required training programs.
    (b) Records must be maintained for one year after personnel are no 
longer assigned duties at the LNG plant.



                        Subpart I_Fire Protection

    Source: Amdt. 193-2, 45 FR 70408, Oct. 23, 1980, unless otherwise 
noted.



Sec. 193.2801  Fire protection.

    Each operator must provide and maintain fire protection at LNG 
plants according to sections 9.1 through 9.7 and section 9.9 of NFPA 59A 
(incorporated by reference, see Sec. 193.2013). However, LNG plants 
existing on March 31, 2000, need not comply with provisions on emergency 
shutdown systems, water delivery systems, detection systems, and 
personnel qualification and training until September 12, 2005.

[Amdt. 193-18, 69 FR 11337, Mar. 10, 2004]



Sec. Sec. 193.2803-193.2821  [Reserved]



                           Subpart J_Security

    Source: Amdt. 193-2, 45 FR 70409, Oct. 23, 1980, unless otherwise 
noted.



Sec. 193.2901  Scope.

    This subpart prescribes requirements for security at LNG plants. 
However, the requirements do not apply to existing LNG plants that do 
not contain LNG.

[Amdt. 193-4, 52 FR 675, Jan. 8, 1987]



Sec. 193.2903  Security procedures.

    Each operator shall prepare and follow one or more manuals of 
written procedures to provide security for each LNG plant. The 
procedures must be available at the plant in accordance with Sec. 
193.2017 and include at least:
    (a) A description and schedule of security inspections and patrols 
performed in accordance with Sec. 193.2913;
    (b) A list of security personnel positions or responsibilities 
utilized at the LNG plant;

[[Page 160]]

    (c) A brief description of the duties associated with each security 
personnel position or responsibility;
    (d) Instructions for actions to be taken, including notification of 
other appropriate plant personnel and law enforcement officials, when 
there is any indication of an actual or attempted breach of security;
    (e) Methods for determining which persons are allowed access to the 
LNG plant;
    (f) Positive identification of all persons entering the plant and on 
the plant, including methods at least as effective as picture badges; 
and
    (g) Liaison with local law enforcement officials to keep them 
informed about current security procedures under this section.



Sec. 193.2905  Protective enclosures.

    (a) The following facilities must be surrounded by a protective 
enclosure:
    (1) Storage tanks;
    (2) Impounding systems;
    (3) Vapor barriers;
    (4) Cargo transfer systems;
    (5) Process, liquefaction, and vaporization equipment;
    (6) Control rooms and stations;
    (7) Control systems;
    (8) Fire control equipment;
    (9) Security communications systems; and
    (10) Alternative power sources.

The protective enclosure may be one or more separate enclosures 
surrounding a single facility or multiple facilities.
    (b) Ground elevations outside a protective enclosure must be graded 
in a manner that does not impair the effectiveness of the enclosure.
    (c) Protective enclosures may not be located near features outside 
of the facility, such as trees, poles, or buildings, which could be used 
to breach the security.
    (d) At least two accesses must be provided in each protective 
enclosure and be located to minimize the escape distance in the event of 
emergency.
    (e) Each access must be locked unless it is continuously guarded. 
During normal operations, an access may be unlocked only by persons 
designated in writing by the operator. During an emergency, a means must 
be readily available to all facility personnel within the protective 
enclosure to open each access.



Sec. 193.2907  Protective enclosure construction.

    (a) Each protective enclosure must have sufficient strength and 
configuration to obstruct unauthorized access to the facilities 
enclosed.
    (b) Openings in or under protective enclosures must be secured by 
grates, doors or covers of construction and fastening of sufficient 
strength such that the integrity of the protective enclosure is not 
reduced by any opening.

[Amdt. 193-2, 45 FR 70409, Oct. 23, 1980, as amended by Amdt. 193-12, 61 
FR 27793, June 3, 1996; 61 FR 45905, Aug. 30, 1996]



Sec. 193.2909  Security communications.

    A means must be provided for:
    (a) Prompt communications between personnel having supervisory 
security duties and law enforcement officials; and
    (b) Direct communications between all on-duty personnel having 
security duties and all control rooms and control stations.



Sec. 193.2911  Security lighting.

    Where security warning systems are not provided for security 
monitoring under Sec. 193.2913, the area around the facilities listed 
under Sec. 193.2905(a) and each protective enclosure must be 
illuminated with a minimum in service lighting intensity of not less 
than 2.2 lux (0.2 ft\c\) between sunset and sunrise.



Sec. 193.2913  Security monitoring.

    Each protective enclosure and the area around each facility listed 
in Sec. 193.2905(a) must be monitored for the presence of unauthorized 
persons. Monitoring must be by visual observation in accordance with the 
schedule in the security procedures under Sec. 193.2903(a) or by 
security warning systems that continuously transmit data to an attended 
location. At an LNG plant with less than 40,000 m\3\ (250,000 bbl) of 
storage capacity, only the protective enclosure must be monitored.



Sec. 193.2915  Alternative power sources.

    An alternative source of power that meets the requirements of Sec. 
193.2445 must be provided for security lighting

[[Page 161]]

and security monitoring and warning systems required under Sec. Sec. 
193.2911 and 193.2913.



Sec. 193.2917  Warning signs.

    (a) Warning signs must be conspicuously placed along each protective 
enclosure at intervals so that at least one sign is recognizable at 
night from a distance of 30m (100 ft.) from any way that could 
reasonably be used to approach the enclosure.
    (b) Signs must be marked with at least the following on a background 
of sharply contrasting color:

The words ``NO TRESPASSING,'' or words of comparable meaning.

[Amdt. 193-2, 45 FR 70409, Oct. 23, 1980, as amended at 47 FR 32720, 
July 29, 1982]



PART 194_RESPONSE PLANS FOR ONSHORE OIL PIPELINES--Table of Contents




                            Subpart A_General

Sec.
194.1 Purpose.
194.3 Applicability.
194.5 Definitions.
194.7 Operating restrictions and interim operating authorization.

                        Subpart B_Response Plans

194.101 Operators required to submit plans.
194.103 Significant and substantial harm; operator's statement.
194.105 Worst case discharge.
194.107 General response plan requirements.
194.109 Submission of state response plans.
194.111 Response plan retention.
194.113 Information summary.
194.115 Response resources.
194.117 Training.
194.119 Submission and approval procedures.
194.121 Response plan review and update procedures.

Appendix A to Part 194--Guidelines for the Preparation of Response Plans
Appendix B to Part 194--High Volume Areas

    Authority: 33 U.S.C. 1231, 1321(j)(1)(C), (j)(5) and (j)(6); sec. 2, 
E.O. 12777, 56 FR 54757, 3 CFR, 1991 Comp., p. 351; 49 CFR 1.53.

    Source: 58 FR 253, Jan. 5, 1993, unless otherwise noted.



                            Subpart A_General



Sec. 194.1  Purpose.

    This part contains requirements for oil spill response plans to 
reduce the environmental impact of oil discharged from onshore oil 
pipelines.



Sec. 194.3  Applicability.

    This part applies to an operator of an onshore oil pipeline that, 
because of its location, could reasonably be expected to cause 
substantial harm, or significant and substantial harm to the environment 
by discharging oil into or on any navigable waters of the United States 
or adjoining shorelines.



Sec. 194.5  Definitions.

    Adverse weather means the weather conditions that the operator will 
consider when identifying response systems and equipment to be deployed 
in accordance with a response plan. Factors to consider include ice 
conditions, temperature ranges, weather-related visibility, significant 
wave height as specified in 33 CFR Part 154, Appendix C, Table 1, and 
currents within the areas in which those systems or equipment are 
intended to function.
    Barrel means 42 United States gallons (159 liters) at 60[deg] 
Fahrenheit (15.6[deg] Celsius).
    Breakout tank means a tank used to:
    (1) Relieve surges in an oil pipeline system or
    (2) Receive and store oil transported by a pipeline for reinjection 
and continued transportation by pipeline.
    Contract or other approved means is:
    (1) A written contract or other legally binding agreement between 
the operator and a response contractor or other spill response 
organization identifying and ensuring the availability of the specified 
personnel and equipment within stipulated response times for a specified 
geographic area;
    (2) Certification that specified equipment is owned or operated by 
the pipeline operator, and operator personnel and equipment are 
available within stipulated response times for a specified geographic 
area; or
    (3) Active membership in a local or regional oil spill removal 
organization that has identified specified personnel and equipment to be 
available within

[[Page 162]]

stipulated response times for a specified geographic area.
    Environmentally sensitive area means an area of environmental 
importance which is in or adjacent to navigable waters.
    High volume area means an area which an oil pipeline having a 
nominal outside diameter of 20 inches (508 millimeters) or more crosses 
a major river or other navigable waters, which, because of the velocity 
of the river flow and vessel traffic on the river, would require a more 
rapid response in case of a worst case discharge or substantial threat 
of such a discharge. Appendix B to this part contains a list of some of 
the high volume areas in the United States.
    Line section means a continuous run of pipe that is contained 
between adjacent pressure pump stations, between a pressure pump station 
and a terminal or breakout tank, between a pressure pump station and a 
block valve, or between adjacent block valves.
    Major river means a river that, because of its velocity and vessel 
traffic, would require a more rapid response in case of a worst case 
discharge. For a list of rivers see ``Rolling Rivers, An Encyclopedia of 
America's Rivers,'' Richard A. Bartlett, Editor, McGraw-Hill Book 
Company, 1984.
    Maximum extent practicable means the limits of available technology 
and the practical and technical limits on a pipeline operator in 
planning the response resources required to provide the on-water 
recovery capability and the shoreline protection and cleanup capability 
to conduct response activities for a worst case discharge from a 
pipeline in adverse weather.
    Navigable waters means the waters of the United States, including 
the territorial sea and such waters as lakes, rivers, streams; waters 
which are used for recreation; and waters from which fish or shellfish 
are taken and sold in interstate or foreign commerce.
    Oil means oil of any kind or in any form, including, but not limited 
to, petroleum, fuel oil, vegetable oil, animal oil, sludge, oil refuse, 
oil mixed with wastes other than dredged spoil.
    Oil spill removal organization means an entity that provides 
response resources.
    On-Scene Coordinator (OSC) means the federal official designated by 
the Administrator of the EPA or by the Commandant of the USCG to 
coordinate and direct federal response under subpart D of the National 
Contingency Plan (40 CFR part 300).
    Onshore oil pipeline facilities means new and existing pipe, rights-
of-way and any equipment, facility, or building used in the 
transportation of oil located in, on, or under, any land within the 
United States other than submerged land.
    Operator means a person who owns or operates onshore oil pipeline 
facilities.
    Pipeline means all parts of an onshore pipeline facility through 
which oil moves 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.
    Qualified individual means an English-speaking representative of an 
operator, located in the United States, available on a 24-hour basis, 
with full authority to: activate and contract with required oil spill 
removal organization(s); activate personnel and equipment maintained by 
the operator; act as liaison with the OSC; and obligate any funds 
required to carry out all required or directed oil response activities.
    Response activities means the containment and removal of oil from 
the water and shorelines, the temporary storage and disposal of 
recovered oil, or the taking of other actions as necessary to minimize 
or mitigate damage to the environment.
    Response plan means the operator's core plan and the response zone 
appendices for responding, to the maximum extent practicable, to a worse 
case discharge of oil, or the substantial threat of such a discharge.
    Response resources means the personnel, equipment, supplies, and 
other resources necessary to conduct response activities.
    Response zone means a geographic area either along a length of 
pipeline or including multiple pipelines, containing one or more 
adjacent line sections, for which the operator must plan

[[Page 163]]

for the deployment of, and provide, spill response capabilities. The 
size of the zone is determined by the operator after considering 
available capability, resources, and geographic characteristics.
    Specified minimum yield strength means the minimum yield strength, 
expressed in pounds per square inch, 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.
    Worst case discharge means the largest foreseeable discharge of oil, 
including a discharge from fire or explosion, in adverse weather 
conditions. This volume will be determined by each pipeline operator for 
each response zone and is calculated according to Sec. 194.105.

[58 FR 253, Jan. 5, 1993, as amended by Amdt. 194-3, 63 FR 37505, July 
13, 1998; Amdt. 194-4, 70 FR 8746, Feb. 23, 2005]



Sec. 194.7  Operating restrictions and interim operating authorization.

    (a) An operator of a pipeline for which a response plan is required 
under Sec. 194.101, may not handle, store, or transport oil in that 
pipeline unless the operator has submitted a response plan meeting the 
requirements of this part.
    (b) An operator must operate its onshore pipeline facilities in 
accordance with the applicable response plan.
    (c) The operator of a pipeline line section described in Sec. 
194.103(c), may continue to operate the pipeline for two years after the 
date of submission of a response plan, pending approval or disapproval 
of that plan, only if the operator has submitted the certification 
required by Sec. 194.119(e).

[Amdt. 194-4, 70 FR 8746, Feb. 23, 2005]



                        Subpart B_Response Plans



Sec. 194.101  Operators required to submit plans.

    (a) Except as provided in paragraph (b) of this section, unless OPS 
grants a request from an Federal On-Scene Coordinator (FOSC) to require 
an operator of a pipeline in paragraph (b) to submit a response plan, 
each operator of an onshore pipeline facility shall prepare and submit a 
response plan to PHMSA as provided in Sec. 194.119. A pipeline which 
does not meet the criteria for significant and substantial harm as 
defined in Sec. 194.103(c) and is not eligible for an exception under 
Sec. 194.101(b), can be expected to cause substantial harm. Operators 
of substantial harm pipeline facilities must prepare and submit plans to 
PHMSA for review.
    (b) Exception. An operator need not submit a response plan for:
    (1) A pipeline that is 6\5/8\ inches (168 millimeters) or less in 
outside nominal diameter, is 10 miles (16 kilometers) or less in length, 
and all of the following conditions apply to the pipeline:
    (i) The pipeline has not experienced a release greater than 1,000 
barrels (159 cubic meters) within the previous five years,
    (ii) The pipeline has not experienced at least two reportable 
releases, as defined in Sec. 195.50, within the previous five years,
    (iii) A pipeline containing any electric resistance welded pipe, 
manufactured prior to 1970, does not operate at a maximum operating 
pressure established under Sec. 195.406 that corresponds to a stress 
level greater than 50 percent of the specified minimum yield strength of 
the pipe, and
    (iv) The pipeline is not in proximity to navigable waters, public 
drinking water intakes, or environmentally sensitive areas.
    (2)(i) A line section that is greater than 6\5/8\ inches in outside 
nominal diameter and is greater than 10 miles in length, where the 
operator determines that it is unlikely that the worst case discharge 
from any point on the line section would adversely affect, within 12 
hours after the initiation of the discharge, any navigable waters, 
public drinking water intake, or environmentally sensitive areas.
    (ii) A line section that is 6\5/8\ inches (168 millimeters) or less 
in outside nominal diameter and is 10 miles (16 kilometers) or less in 
length, where the operator determines that it is unlikely that the worst 
case discharge from any point on the line section would adversely 
affect, within 4 hours after the

[[Page 164]]

initiation of the discharge, any navigable waters, public drinking water 
intake, or environmentally sensitive areas.

[58 FR 253, Jan. 5, 1993, as amended by Amdt. 194-3, 63 FR 37505, July 
13, 1998; Amdt. 194-4, 70 FR 8747, Feb. 23, 2005; 70 FR 11140, Mar. 8, 
2005]



Sec. 194.103  Significant and substantial harm; operator's statement.

    (a) Each operator shall submit a statement with its response plan, 
as required by Sec. Sec. 194.107 and 194.113, identifying which line 
sections in a response zone can be expected to cause significant and 
substantial harm to the environment in the event of a discharge of oil 
into or on the navigable waters or adjoining shorelines.
    (b) If an operator expects a line section in a response zone to 
cause significant and substantial harm, then the entire response zone 
must, for the purpose of response plan review and approval, be treated 
as if it is expected to cause significant and substantial harm. However, 
an operator will not have to submit separate plans for each line 
section.
    (c) A line section can be expected to cause significant and 
substantial harm to the environment in the event of a discharge of oil 
into or on the navigable waters or adjoining shorelines if; the pipeline 
is greater than 6\5/8\ inches (168 millimeters) in outside nominal 
diameter, greater than 10 miles (16 kilometers) in length, and the line 
section--
    (1) Has experienced a release greater than 1,000 barrels (159 cubic 
meters) within the previous five years,
    (2) Has experienced two or more reportable releases, as defined in 
Sec. 195.50, within the previous five years,
    (3) Containing any electric resistance welded pipe, manufactured 
prior to 1970, operates at a maximum operating pressure established 
under Sec. 195.406 that corresponds to a stress level greater than 50 
percent of the specified minimum yield strength of the pipe,
    (4) Is located within a 5 mile (8 kilometer) radius of potentially 
affected public drinking water intakes and could reasonably be expected 
to reach public drinking water intakes, or
    (5) Is located within a 1 mile (1.6 kilometer) radius of potentially 
affected environmentally sensitive areas, and could reasonably be 
expected to reach these areas.

[58 FR 253, Jan. 5, 1993, as amended by Amdt. 194-3, 63 FR 37505, July 
13, 1998]



Sec. 194.105  Worst case discharge.

    (a) Each operator shall determine the worst case discharge for each 
of its response zones and provide the methodology, including 
calculations, used to arrive at the volume.
    (b) The worst case discharge is the largest volume, in barrels 
(cubic meters), of the following:
    (1) The pipeline's maximum release time in hours, plus the maximum 
shutdown response time in hours (based on historic discharge data or in 
the absence of such historic data, the operator's best estimate), 
multiplied by the maximum flow rate expressed in barrels per hour (based 
on the maximum daily capacity of the pipeline), plus the largest line 
drainage volume after shutdown of the line section(s) in the response 
zone expressed in barrels (cubic meters); or
    (2) The largest foreseeable discharge for the line section(s) within 
a response zone, expressed in barrels (cubic meters), based on the 
maximum historic discharge, if one exists, adjusted for any subsequent 
corrective or preventive action taken; or
    (3) If the response zone contains one or more breakout tanks, the 
capacity of the single largest tank or battery of tanks within a single 
secondary containment system, adjusted for the capacity or size of the 
secondary containment system, expressed in barrels (cubic meters).
    (4) Operators may claim prevention credits for breakout tank 
secondary containment and other specific spill prevention measures as 
follows:

------------------------------------------------------------------------
                                                               Credit
        Prevention measure                 Standard           (percent)
------------------------------------------------------------------------
Secondary containment    NFPA 30...............            50
 100%.

[[Page 165]]

 
Built/repaired to API standards...  API STD 620/650/653...            10
Overfill protection standards.....  API RP 2350...........             5
Testing/cathodic protection.......  API STD 650/651/653...             5
Tertiary containment/drainage/      NFPA 30...............             5
 treatment.
Maximum allowable credit..........  ......................            75
------------------------------------------------------------------------


[58 FR 253, Jan. 5, 1993, as amended by Amdt. 194-3, 63 FR 37505, July 
13, 1998; Amdt. 194-4, 70 FR 8747, Feb. 23, 2005; Amdt. 194-5, 70 FR 
35042, June 16, 2005]



Sec. 194.107  General response plan requirements.

    (a) Each response plan must include procedures and a list of 
resources for responding, to the maximum extent practicable, to a worst 
case discharge and to a substantial threat of such a discharge. The 
``substantial threat'' term is equivalent to abnormal operations 
outlined in 49 CFR 195.402(d). To comply with this requirement, an 
operator can incorporate by reference into the response plan the 
appropriate procedures from its manual for operations, maintenance, and 
emergencies, which is prepared in compliance with 49 CFR 195.402.
    (b) An operator must certify in the response plan that it reviewed 
the NCP and each applicable ACP and that its response plan is consistent 
with the NCP and each applicable ACP as follows:
    (1) As a minimum to be consistent with the NCP a facility response 
plan must:
    (i) Demonstrate an operator's clear understanding of the function of 
the Federal response structure, including procedures to notify the 
National Response Center reflecting the relationship between the 
operator's response organization's role and the Federal On Scene 
Coordinator's role in pollution response;
    (ii) Establish provisions to ensure the protection of safety at the 
response site; and
    (iii) Identify the procedures to obtain any required Federal and 
State permissions for using alternative response strategies such as in-
situ burning and dispersants as provided for in the applicable ACPs; and
    (2) As a minimum, to be consistent with the applicable ACP the plan 
must:
    (i) Address the removal of a worst case discharge and the mitigation 
or prevention of a substantial threat of a worst case discharge;
    (ii) Identify environmentally and economically sensitive areas;
    (iii) Describe the responsibilities of the operator and of Federal, 
State and local agencies in removing a discharge and in mitigating or 
preventing a substantial threat of a discharge; and
    (iv) Establish the procedures for obtaining an expedited decision on 
use of dispersants or other chemicals.
    (c) Each response plan must include:
    (1) A core plan consisting of--
    (i) An information summary as required in Sec. 194.113,
    (ii) Immediate notification procedures,
    (iii) Spill detection and mitigation procedures,
    (iv) The name, address, and telephone number of the oil spill 
response organization, if appropriate,
    (v) Response activities and response resources,
    (vi) Names and telephone numbers of Federal, State and local 
agencies which the operator expects to have pollution control 
responsibilities or support,
    (vii) Training procedures,
    (viii) Equipment testing,
    (ix) Drill program--an operator will satisfy the requirement for a 
drill program by following the National Preparedness for Response 
Exercise Program (PREP) guidelines. An operator choosing not to follow 
PREP guidelines must have a drill program that is equivalent to PREP. 
The operator must describe the drill program in the response plan and 
OPS will determine if the program is equivalent to PREP.
    (x) Plan review and update procedures;

[[Page 166]]

    (2) An appendix for each response zone that includes the information 
required in paragraph (c)(1)(i)-(ix) of this section and the worst case 
discharge calculations that are specific to that response zone. An 
operator submitting a response plan for a single response zone does not 
need to have a core plan and a response zone appendix. The operator of a 
single response zone onshore pipeline shall have a single summary in the 
plan that contains the required information in Sec. 194.113.7; and
    (3) A description of the operator's response management system 
including the functional areas of finance, logistics, operations, 
planning, and command. The plan must demonstrate that the operator's 
response management system uses common terminology and has a manageable 
span of control, a clearly defined chain of command, and sufficient 
trained personnel to fill each position.

[Amdt. 194-4, 70 FR 8747, Feb. 23, 2005]



Sec. 194.109  Submission of state response plans.

    (a) In lieu of submitting a response plan required by Sec. 194.103, 
an operator may submit a response plan that complies with a state law or 
regulation, if the state law or regulation requires a plan that provides 
equivalent or greater spill protection than a plan required under this 
part.
    (b) A plan submitted under this section must
    (1) Have an information summary required by Sec. 194.113;
    (2) List the names or titles and 24-hour telephone numbers of the 
qualified individual(s) and at least one alternate qualified 
individual(s); and
    (3) Ensure through contract or other approved means the necessary 
private personnel and equipment to respond to a worst case discharge or 
a substantial threat of such a discharge.

[58 FR 253, Jan. 5, 1993, as amended by Amdt. 194-4, 70 FR 8748, Feb. 
23, 2005]



Sec. 194.111  Response plan retention.

    (a) Each operator shall maintain relevant portions of its response 
plan at the operator's headquarters and at other locations from which 
response activities may be conducted, for example, in field offices, 
supervisors' vehicles, or spill response trailers.
    (b) Each operator shall provide a copy of its response plan to each 
qualified individual.

[58 FR 253, Jan. 5, 1993, as amended by Amdt. 194-4, 70 FR 8748, Feb. 
23, 2005]



Sec. 194.113  Information summary.

    (a) The information summary for the core plan, required by Sec. 
194.107, must include:
    (1) The name and address of the operator; and
    (2) For each response zone which contains one or more line sections 
that meet the criteria for determining significant and substantial harm 
as described in Sec. 194.103, a listing and description of the response 
zones, including county(s) and state(s).
    (b) The information summary for the response zone appendix, required 
in Sec. 194.107, must include:
    (1) The information summary for the core plan;
    (2) The names or titles and 24-hour telephone numbers of the 
qualified individual(s) and at least one alternate qualified 
individual(s);
    (3) The description of the response zone, including county(s) and 
state(s), for those zones in which a worst case discharge could cause 
substantial harm to the environment;
    (4) A list of line sections for each pipeline contained in the 
response zone, identified by milepost or survey station number, or other 
operator designation;
    (5) The basis for the operator's determination of significant and 
substantial harm; and
    (6) The type of oil and volume of the worst case discharge.

[58 FR 253, Jan. 5, 1993, as amended by Amdt. 194-4, 70 FR 8748, Feb. 
23, 2005]



Sec. 194.115  Response resources.

    (a) Each operator shall identify and ensure, by contract or other 
approved means, the resources necessary to remove, to the maximum extent 
practicable, a worst case discharge and to mitigate or prevent a 
substantial threat of a worst case discharge.
    (b) An operator shall identify in the response plan the response 
resources

[[Page 167]]

which are available to respond within the time specified, after 
discovery of a worst case discharge, or to mitigate the substantial 
threat of such a discharge, as follows:

----------------------------------------------------------------------------------------------------------------
                                                Tier 1                   Tier 2                   Tier 3
----------------------------------------------------------------------------------------------------------------
High volume area.....................  6 hrs..................  30 hrs.................  54 hrs.
All other areas......................  12 hrs.................  36 hrs.................  60 hrs.
----------------------------------------------------------------------------------------------------------------



Sec. 194.117  Training.

    (a) Each operator shall conduct training to ensure that:
    (1) All personnel know--
    (i) Their responsibilities under the response plan,
    (ii) The name and address of, and the procedure for contacting, the 
operator on a 24-hour basis, and
    (iii) The name of, and procedures for contacting, the qualified 
individual on a 24-hour basis;
    (2) Reporting personnel know--
    (i) The content of the information summary of the response plan,
    (ii) The toll-free telephone number of the National Response Center, 
and
    (iii) The notification process; and
    (3) Personnel engaged in response activities know--
    (i) The characteristics and hazards of the oil discharged,
    (ii) The conditions that are likely to worsen emergencies, including 
the consequences of facility malfunctions or failures, and the 
appropriate corrective actions,
    (iii) The steps necessary to control any accidental discharge of oil 
and to minimize the potential for fire, explosion, toxicity, or 
environmental damage, and
    (iv) The proper firefighting procedures and use of equipment, fire 
suits, and breathing apparatus.
    (b) Each operator shall maintain a training record for each 
individual that has been trained as required by this section. These 
records must be maintained in the following manner as long as the 
individual is assigned duties under the response plan:
    (1) Records for operator personnel must be maintained at the 
operator's headquarters; and
    (2) Records for personnel engaged in response, other than operator 
personnel, shall be maintained as determined by the operator.
    (c) Nothing in this section relieves an operator from the 
responsibility to ensure that all response personnel are trained to meet 
the Occupational Safety and Health Administration (OSHA) standards for 
emergency response operations in 29 CFR 1910.120, including volunteers 
or casual laborers employed during a response who are subject to those 
standards pursuant to 40 CFR part 311.



Sec. 194.119  Submission and approval procedures.

    (a) Each operator shall submit two copies of the response plan 
required by this part. Copies of the response plan shall be submitted 
to: Office of Pipeline Safety, Pipeline and Hazardous Materials Safety 
Administration, Department of Transportation, PHP 80, 1200 New Jersey 
Avenue, SE., Washington, DC 20590-0001. Note: Submission of plans in 
electronic format is preferred.
    (b) If PHMSA determines that a response plan requiring approval does 
not meet all the requirements of this part, PHMSA will notify the 
operator of any alleged deficiencies, and to provide the operator an 
opportunity to respond, including the opportunity for an informal 
conference, on any proposed plan revisions and an opportunity to correct 
any deficiencies.
    (c) An operator who disagrees with the PHMSA determination that a 
plan contains alleged deficiencies may petition PHMSA for 
reconsideration within 30 days from the date of receipt of PHMSA's 
notice. After considering all relevant material presented in writing or 
at an informal conference, PHMSA will notify the operator of its final 
decision. The operator must comply with the final decision within 30 
days of issuance unless PHMSA allows additional time.
    (d) For response zones of pipelines described in Sec. 194.103(c) 
OPS will approve the response plan if OPS determines that the response 
plan meets all requirements of this part. OPS may consult with the U.S. 
Environmental Protection Agency (EPA) or the U.S. Coast Guard (USCG) if 
a Federal on-scene coordinator (FOSC) has concerns about the operator's 
ability to respond to a worst case discharge.

[[Page 168]]

    (e) If OPS has not approved a response plan for a pipeline described 
in Sec. 194.103(c), the operator may submit a certification to OPS that 
the operator has obtained, through contract or other approved means, the 
necessary personnel and equipment to respond, to the maximum extent 
practicable, to a worst case discharge or a substantial threat of such a 
discharge. The certificate must be signed by the qualified individual or 
an appropriate corporate officer.
    (f) If OPS receives a request from a FOSC to review a response plan, 
OPS may require an operator to give a copy of the response plan to the 
FOSC. OPS may consider FOSC comments on response techniques, protecting 
fish, wildlife and sensitive environments, and on consistency with the 
ACP. OPS remains the approving authority for the response plan.

[58 FR 253, Jan. 5, 1993, as amended byAmdt. 194-4, 70 FR 8748, Feb. 23, 
2005; 70 FR 1140, Mar. 8, 2005; 73 FR 16570, Mar. 28, 2008; 74 FR 2894, 
Jan. 16, 2009]



Sec. 194.121  Response plan review and update procedures.

    (a) Each operator shall update its response plan to address new or 
different operating conditions or information. In addition, each 
operator shall review its response plan in full at least every 5 years 
from the date of the last submission or the last approval as follows:
    (1) For substantial harm plans, an operator shall resubmit its 
response plan to OPS every 5 years from the last submission date.
    (2) For significant and substantial harm plans, an operator shall 
resubmit every 5 years from the last approval date.
    (b) If a new or different operating condition or information would 
substantially affect the implementation of a response plan, the operator 
must immediately modify its response plan to address such a change and, 
within 30 days of making such a change, submit the change to PHMSA. 
Examples of changes in operating conditions that would cause a 
significant change to an operator's response plan are:
    (1) An extension of the existing pipeline or construction of a new 
pipeline in a response zone not covered by the previously approved plan;
    (2) Relocation or replacement of the pipeline in a way that 
substantially affects the information included in the response plan, 
such as a change to the worst case discharge volume;
    (3) The type of oil transported, if the type affects the required 
response resources, such as a change from crude oil to gasoline;
    (4) The name of the oil spill removal organization;
    (5) Emergency response procedures;
    (6) The qualified individual;
    (7) A change in the NCP or an ACP that has significant impact on the 
equipment appropriate for response activities; and
    (8) Any other information relating to circumstances that may affect 
full implementation of the plan.
    (c) If PHMSA determines that a change to a response plan does not 
meet the requirements of this part, PHMSA will notify the operator of 
any alleged deficiencies, and provide the operator an opportunity to 
respond, including an opportunity for an informal conference, to any 
proposed plan revisions and an opportunity to correct any deficiencies.
    (d) An operator who disagrees with a determination that proposed 
revisions to a plan are deficient may petition PHMSA for 
reconsideration, within 30 days from the date of receipt of PHMSA's 
notice. After considering all relevant material presented in writing or 
at the conference, PHMSA will notify the operator of its final decision. 
The operator must comply with the final decision within 30 days of 
issuance unless PHMSA allows additional time.

[58 FR 253, Jan. 5, 1993, as amended by Amdt. 194-1, 62 FR 67293, Dec. 
24, 1997; Amdt. 194-4, 70 FR 8748, Feb. 23, 2005; 70 FR 11140, Mar. 8, 
2005]



Sec. Appendix A to Part 194--Guidelines for the Preparation of Response 
                                  Plans

    This appendix provides a recommended format for the preparation and 
submission of the response plans required by 49 CFR Part 194. Operators 
are referenced to the most current version of the guidance documents

[[Page 169]]

listed below. Although these documents contain guidance to assist in 
preparing response plans, their use is not mandatory:
    (1) The ``National Preparedness for Response Exercise Program (PREP) 
Guidelines'' (PREP), which can be found using the search function on the 
USCG's PREP Web page, http://www.uscg.mil;
    (2) The National Response Team's ``Integrated Contingency Plan 
Guidance,'' which can be found using the search function at the National 
Response Center's Web site, http://www.nrt.org and;
    (3) 33 CFR Part 154, Appendix C, ``Guidelines for Determining and 
Evaluating Required Response Resources for Facility Response Plans.''

              Response Plan: Section 1. Information Summary

    Section 1 would include the following:
    (a) For the core plan:
    (1) The name and address of the operator; and
    (2) For each response zone which contains one or more line sections 
that meet the criteria for determining significant and substantial harm 
as described in Sec. 194.103, a listing and description of the response 
zones, including county(s) and state(s).
    (b) For each response zone appendix:
    (1) The information summary for the core plan;
    (2) The name and telephone number of the qualified individual, 
available on a 24-hour basis;
    (3) A description of the response zone, including county(s) and 
state(s) in which a worst case discharge could cause substantial harm to 
the environment;
    (4) A list of line sections contained in the response zone, 
identified by milepost or survey station number or other operator 
designation.
    (5) The basis for the operator's determination of significant and 
substantial harm; and
    (6) The type of oil and volume of the worst case discharge.
    (c) The certification that the operator has obtained, through 
contract or other approved means, the necessary private personnel and 
equipment to respond, to the maximum extent practicable, to a worst case 
discharge or a substantial threat of such a discharge.

            Response Plan: Section 2. Notification Procedures

    Section 2 would include the following:
    (a) Notification requirements that apply in each area of operation 
of pipelines covered by the plan, including applicable State or local 
requirements;
    (b) A checklist of notifications the operator or qualified 
individual is required to make under the response plan, listed in the 
order of priority;
    (c) Names of persons (individuals or organizations) to be notified 
of a discharge, indicating whether notification is to be performed by 
operating personnel or other personnel;
    (d) Procedures for notifying qualified individuals;
    (e) The primary and secondary communication methods by which 
notifications can be made; and
    (f) The information to be provided in the initial and each follow-up 
notification, including the following:
    (1) Name of pipeline;
    (2) Time of discharge;
    (3) Location of discharge;
    (4) Name of oil involved;
    (5) Reason for discharge (e.g., material failure, excavation damage, 
corrosion);
    (6) Estimated volume of oil discharged;
    (7) Weather conditions on scene; and
    (8) Actions taken or planned by persons on scene.

Response Plan: Section 3. Spill Detection and On-Scene Spill Mitigation 
                               Procedures

    Section 3 would include the following:
    (a) Methods of initial discharge detection;
    (b) Procedures, listed in the order of priority, that personnel are 
required to follow in responding to a pipeline emergency to mitigate or 
prevent any discharge from the pipeline;
    (c) A list of equipment that may be needed in response activities on 
land and navigable waters, including--
    (1) Transfer hoses and connection equipment;
    (2) Portable pumps and ancillary equipment; and
    (3) Facilities available to transport and receive oil from a leaking 
pipeline;
    (d) Identification of the availability, location, and contact 
telephone numbers to obtain equipment for response activities on a 24-
hour basis; and
    (e) Identification of personnel and their location, telephone 
numbers, and responsibilities for use of equipment in response 
activities on a 24-hour basis.

              Response Plan: Section 4. Response Activities

    Section 4 would include the following:
    (a) Responsibilities of, and actions to be taken by, operating 
personnel to initiate and supervise response actions pending the arrival 
of the qualified individual or other response resources identified in 
the response plan;
    (b) The qualified individual's responsibilities and authority, 
including notification of the response resources identified in the plan;
    (c) Procedures for coordinating the actions of the operator or 
qualified individual with the action of the OSC responsible for 
monitoring or directing those actions;

[[Page 170]]

    (d) Oil spill response organizations available, through contract or 
other approved means, to respond to a worst case discharge to the 
maximum extent practicable; and
    (e) For each organization identified under paragraph (d) of this 
section, a listing of:
    (1) Equipment and supplies available; and
    (2) Trained personnel necessary to continue operation of the 
equipment and staff the oil spill removal organization for the first 7 
days of the response.

               Response Plan: Section 5. List of Contacts

    Section 5 would include the names and addresses of the following 
individuals or organizations, with telephone numbers at which they can 
be contacted on a 24-hour basis:
    (a) A list of persons the plan requires the operator to contact;
    (b) Qualified individuals for the operator's areas of operation;
    (c) Applicable insurance representatives or surveyors for the 
operator's areas of operation; and
    (d) Persons or organizations to notify for activation of response 
resources.

              Response plan: Section 6. Training Procedures

    Section 6 would include a description of the training procedures and 
programs of the operator.

               Response plan: Section 7. Drill Procedures

    Section 7 would include a description of the drill procedures and 
programs the operator uses to assess whether its response plan will 
function as planned. It would include:
    (a) Announced and unannounced drills;
    (b) The types of drills and their frequencies. For example, drills 
could be described as follows:
    (1) Manned pipeline emergency procedures and qualified individual 
notification drills conducted quarterly.
    (2) Drills involving emergency actions by assigned operating or 
maintenance personnel and notification of the qualified individual on 
pipeline facilities which are normally unmanned, conducted quarterly.
    (3) Shore-based spill management team tabletop drills conducted 
yearly.
    (4) Oil spill removal organization field equipment deployment drills 
conducted yearly.
    (5) A drill that exercises the entire response plan for each 
response zone, would be conducted at least once every 3 years.

  Response plan: Section 8. Response Plan Review and Update Procedures

    Section 8 would include the following:
    (a) Procedures to meet Sec. 194.121; and
    (b) Procedures to review the plan after a worst case discharge and 
to evaluate and record the plan's effectiveness.

           Response plan: Section 9. Response Zone Appendices.

    Each response zone appendix would provide the following information:
    (a) The name and telephone number of the qualified individual;
    (b) Notification procedures;
    (c) Spill detection and mitigation procedures;
    (d) Name, address, and telephone number of oil spill response 
organization;
    (e) Response activities and response resources including--
    (1) Equipment and supplies necessary to meet Sec. 194.115, and
    (2) The trained personnel necessary to sustain operation of the 
equipment and to staff the oil spill removal organization and spill 
management team for the first 7 days of the response;
    (f) Names and telephone numbers of Federal, state and local agencies 
which the operator expects to assume pollution response 
responsibilities;
    (g) The worst case discharge volume;
    (h) The method used to determine the worst case discharge volume, 
with calculations;
    (i) A map that clearly shows--
    (1) The location of the worst case discharge, and
    (2) The distance between each line section in the response zone 
and--
    (i) Each potentially affected public drinking water intake, lake, 
river, and stream within a radius of 5 miles (8 kilometers) of the line 
section, and
    (ii) Each potentially affected environmentally sensitive area within 
a radius of 1 mile (1.6 kilometer) of the line section;
    (j) A piping diagram and plan-profile drawing of each line section, 
which may be kept separate from the response plan if the location is 
identified; and
    (k) For every oil transported by each pipeline in the response zone, 
emergency response data that--
    (1) Include the name, description, physical and chemical 
characteristics, health and safety hazards, and initial spill-handling 
and firefighting methods; and
    (2) Meet 29 CFR 1910.1200 or 49 CFR 172.602.

[58 FR 253, Jan. 5, 1993, as amended by Amdt. 194-3, 63 FR 37505, July 
13, 1998; Amdt. 194-4, 70 FR 8748, Feb. 23, 2005]



             Sec. Appendix B to Part 194--High Volume Areas

    As of January 5, 1993 the following areas are high volume areas:

------------------------------------------------------------------------
               Major rivers                    Nearest town and state
------------------------------------------------------------------------
Arkansas River............................  N. Little Rock, AR.
Arkansas River............................  Jenks, OK.
Arkansas River............................  Little Rock, AR.

[[Page 171]]

 
Black Warrior River.......................  Moundville, AL.
Black Warrior River.......................  Akron, AL.
Brazos River..............................  Glen Rose, TX.
Brazos River..............................  Sealy, TX.
Catawba River.............................  Mount Holly, NC.
Chattahoochee River.......................  Sandy Springs, GA.
Colorado River............................  Yuma, AZ.
Colorado River............................  LaPaz, AZ.
Connecticut River.........................  Lancaster, NH.
Coosa River...............................  Vincent, AL.
Cumberland River..........................  Clarksville, TN.
Delaware River............................  Frenchtown, NJ.
Delaware River............................  Lower Chichester, NJ.
Gila River................................  Gila Bend, AZ.
Grand River...............................  Bosworth, MO.
Illinois River............................  Chillicothe, IL.
Illinois River............................  Havanna, IL.
James River...............................  Arvonia, VA.
Kankakee River............................  Kankakee, IL.
Kankakee River............................  South Bend, IN.
Kankakee River............................  Wilmington, IL.
Kentucky River............................  Salvisa, KY.
Kentucky River............................  Worthville, KY.
Maumee River..............................  Defiance, OH.
Maumee River..............................  Toledo, OH.
Mississippi River.........................  Myrtle Grove, LA.
Mississippi River.........................  Woodriver, IL.
Mississippi River.........................  Chester, IL.
Mississippi River.........................  Cape Girardeau, MO.
Mississippi River.........................  Woodriver, IL.
Mississippi River.........................  St. James, LA.
Mississippi River.........................  New Roads, LA.
Mississippi River.........................  Ball Club, MN.
Mississippi River.........................  Mayersville, MS.
Mississippi River.........................  New Roads, LA.
Mississippi River.........................  Quincy, IL.
Mississippi River.........................  Ft. Madison, IA.
Missouri River............................  Waverly, MO.
Missouri River............................  St. Joseph, MO.
Missouri River............................  Weldon Springs, MO.
Missouri River............................  New Frankfort, MO.
Naches River..............................  Beaumont, TX.
Ohio River................................  Joppa, IL.
Ohio River................................  Cincinnati, OH.
Ohio River................................  Owensboro, KY.
Pascagoula River..........................  Lucedale, MS.
Pascagoula River..........................  Wiggins, MS.
Pearl River...............................  Columbia, MS.
Pearl River...............................  Oria, TX.
Platte River..............................  Ogaliala, NE.
Potomac River.............................  Reston, VA.
Rappahannock River........................  Midland, VA.
Raritan River.............................  South Bound Brook, NJ.
Raritan River.............................  Highland Park, NJ.
Red River (of the South)..................  Hanna, LA.
Red River (of the South)..................  Bonham, TX.
Red River (of the South)..................  Dekalb, TX.
Red River (of the South)..................  Sentell Plantation, LA.
Red River (of the North)..................  Wahpeton, ND.
Rio Grande................................  Anthony, NM.
Sabine River..............................  Edgewood, TX.
Sabine River..............................  Leesville, LA.
Sabine River..............................  Orange, TX.
Sabine River..............................  Echo, TX.
Savannah River............................  Hartwell, GA.
Smokey Hill River.........................  Abilene, KS.
Susquehanna River.........................  Darlington, MD.
Tenessee River............................  New Johnsonville, TN.
Wabash River..............................  Harmony, IN.
Wabash River..............................  Terre Haute, IN.
Wabash River..............................  Mt. Carmel, IL.
White River...............................  Batesville, AR.
White River...............................  Grand Glaise, AR.
Wisconsin River...........................  Wisconsin Rapids, WI.
Yukon River...............................  Fairbanks, AK.
------------------------------------------------------------------------

                         Other Navigable Waters

Arthur Kill Channel, NY
Cook Inlet, AK
Freeport, TX
Los Angeles/Long Beach Harbor, CA
Port Lavaca, TX
San Fransico/San Pablo Bay, CA



PART 195_TRANSPORTATION OF HAZARDOUS LIQUIDS BY PIPELINE--Table of Contents




                            Subpart A_General

Sec.
195.0 Scope.
195.1 Which pipelines are covered by this part?
195.2 Definitions.
195.3 Incorporation by reference.
195.4 Compatibility necessary for transportation of hazardous liquids or 
          carbon dioxide.
195.5 Conversion to service subject to this part.
195.6 Unusually Sensitive Areas (USAs).
195.8 Transportation of hazardous liquid or carbon dioxide in pipelines 
          constructed with other than steel pipe.
195.9 Outer continental shelf pipelines.
195.10 Responsibility of operator for compliance with this part.
195.11 What is a regulated rural gathering line and what requirements 
          apply?
195.12 What requirements apply to low-stress pipelines in rural areas?

   Subpart B_Annual, Accident, and Safety-Related Condition Reporting

195.48 Scope.
195.49 Annual report.
195.50 Reporting accidents.
195.52 Telephonic notice of certain accidents.
195.54 Accident reports.
195.55 Reporting safety-related conditions.
195.56 Filing safety-related condition reports.
195.57 Filing offshore pipeline condition reports.
195.58 Address for written reports.
195.59 Abandonment or deactivation of facilities.
195.60 Operator assistance in investigation.
195.62 Supplies of accident report DOT Form 7000-1.
195.63 OMB control number assigned to information collection.

                      Subpart C_Design Requirements

195.100 Scope.

[[Page 172]]

195.101 Qualifying metallic components other than pipe.
195.102 Design temperature.
195.104 Variations in pressure.
195.106 Internal design pressure.
195.108 External pressure.
195.110 External loads.
195.111 Fracture propagation.
195.112 New pipe.
195.114 Used pipe.
195.116 Valves.
195.118 Fittings.
195.120 Passage of internal inspection devices.
195.122 Fabricated branch connections.
195.124 Closures.
195.126 Flange connection.
195.128 Station piping.
195.130 Fabricated assemblies.
195.132 Design and construction of aboveground breakout tanks.
195.134 CPM leak detection.

                         Subpart D_Construction

195.200 Scope.
195.202 Compliance with specifications or standards.
195.204 Inspection--general.
195.205 Repair, alteration and reconstruction of aboveground breakout 
          tanks that have been in service.
195.206 Material inspection.
195.208 Welding of supports and braces.
195.210 Pipeline location.
195.212 Bending of pipe.
195.214 Welding: General.
195.216 Welding: Miter joints.
195.222 Welders: Qualification of welders.
195.224 Welding: Weather.
195.226 Welding: Arc burns.
195.228 Welds and welding inspection: Standards of acceptability.
195.230 Welds: Repair or removal of defects.
195.234 Welds: Nondestructive testing.
195.236-195.244 [Reserved]
195.246 Installation of pipe in a ditch.
195.248 Cover over buried pipeline.
195.250 Clearance between pipe and underground structures.
195.252 Backfilling.
195.254 Above ground components.
195.256 Crossing of railroads and highways.
195.258 Valves: General.
195.260 Valves: Location.
195.262 Pumping equipment.
195.264 Impoundment, protection against entry, normal/emergency venting 
          or pressure/vacuum relief for aboveground breakout tanks.
195.266 Construction records.

                       Subpart E_Pressure Testing

195.300 Scope.
195.302 General requirements.
195.303 Risk-based alternative to pressure testing older hazardous 
          liquid and carbon dioxide pipelines.
195.304 Test pressure.
195.305 Testing of components.
195.306 Test medium.
195.307 Pressure testing aboveground breakout tanks.
195.308 Testing of tie-ins.
195.310 Records.

                   Subpart F_Operation and Maintenance

195.400 Scope.
195.401 General requirements.
195.402 Procedural manual for operations, maintenance, and emergencies.
195.403 Emergency response training.
195.404 Maps and records.
195.405 Protection against ignitions and safe access/egress involving 
          floating roofs.
195.406 Maximum operating pressure.
195.408 Communications.
195.410 Line markers.
195.412 Inspection of rights-of-way and crossings under navigable 
          waters.
195.413 Underwater inspection and reburial of pipelines in the Gulf of 
          Mexico and its inlets.
195.414-195.418 [Reserved]
195.420 Valve maintenance.
195.422 Pipeline repairs.
195.424 Pipe movement.
195.426 Scraper and sphere facilities.
195.428 Overpressure safety devices and overfill protection systems.
195.430 Firefighting equipment.
195.432 Inspection of in-service breakout tanks.
195.434 Signs.
195.436 Security of facilities.
195.438 Smoking or open flames.
195.440 Public awareness.
195.442 Damage prevention program.
195.444 CPM leak detection.

                         High Consequence Areas

195.450 Definitions.

                      Pipeline Integrity Management

195.452 Pipeline integrity management in high consequence areas.

              Subpart G_Qualification of Pipeline Personnel

195.501 Scope.
195.503 Definitions.
195.505 Qualification program.
195.507 Recordkeeping.
195.509 General.

                       Subpart H_Corrosion Control

195.551 What do the regulations in this subpart cover?

[[Page 173]]

195.553 What special definitions apply to this subpart?
195.555 What are the qualifications for supervisors?
195.557 Which pipelines must have coating for external corrosion 
          control?
195.559 What coating material may I use for external corrosion control?
195.561 When must I inspect pipe coating used for external corrosion 
          control?
195.563 Which pipelines must have cathodic protection?
195.565 How do I install cathodic protection on breakout tanks?
195.567 Which pipelines must have test leads and what must I do to 
          install and maintain the leads?
195.569 Do I have to examine exposed portions of buried pipelines?
195.571 What criteria must I use to determine the adequacy of cathodic 
          protection?
195.573 What must I do to monitor external corrosion control?
195.575 Which facilities must I electrically isolate and what 
          inspections, tests, and safeguards are required?
195.577 What must I do to alleviate interference currents?
195.579 What must I do to mitigate internal corrosion?
195.581 Which pipelines must I protect against atmospheric corrosion and 
          what coating material may I use?
195.583 What must I do to monitor atmospheric corrosion control?
195.585 What must I do to correct corroded pipe?
195.587 What methods are available to determine the strength of corroded 
          pipe?
195.588 What standards apply to direct assessment?
195.589 What corrosion control information do I have to maintain?

Appendix A to Part 195--Delineation Between Federal and State 
          Jurisdiction--Statement of Agency Policy and Interpretation
Appendix B to Part 195--Risk-Based Alternative to Pressure Testing Older 
          Hazardous Liquid and Carbon Dioxide Pipelines
Appendix C to Part 195--Guidance for Implementation of an Integrity 
          Management Program

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

    Source: Amdt. 195-22, 46 FR 38360, July 27, 1981, unless otherwise 
noted.

    Editorial Note: Nomenclature changes to part 195 appear at 71 FR 
33409, June 9, 2006.



                            Subpart A_General



Sec. 195.0  Scope.

    This part prescribes safety standards and reporting requirements for 
pipeline facilities used in the transportation of hazardous liquids or 
carbon dioxide.

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



Sec. 195.1  Which pipelines are covered by this part?

    (a) Covered. Except for the pipelines listed in paragraph (b) of 
this section, this part applies to pipeline facilities and the 
transportation of hazardous liquids or carbon dioxide associated with 
those facilities in or affecting interstate or foreign commerce, 
including pipeline facilities on the Outer Continental Shelf (OCS). This 
includes:
    (1) Any pipeline that transports a highly volatile liquid (HVL);
    (2) Transportation through any pipeline, other than a gathering 
line, that has a maximum operating pressure (MOP) greater than 20-
percent of the specified minimum yield strength;
    (3) Any pipeline segment that crosses a waterway currently used for 
commercial navigation;
    (4) Transportation of petroleum in any of the following onshore 
gathering lines:
    (i) A pipeline located in a non-rural area;
    (ii) To the extent provided in Sec. 195.11, a regulated rural 
gathering line defined in Sec. 195.11; or
    (iii) To the extent provided in Sec. 195.413, a pipeline located in 
an inlet of the Gulf of Mexico.
    (5) Transportation of a hazardous liquid or carbon dioxide through a 
low-stress pipeline or segment of pipeline that:
    (i) Is in a non-rural area; or
    (ii) Meets the criteria defined in Sec. 195.12(a).
    (6) For purposes of the reporting requirements in subpart B, a rural 
low-stress pipeline of any diameter.
    (b) Excepted. This part does not apply to any of the following:
    (1) Transportation of a hazardous liquid transported in a gaseous 
state;
    (2) Transportation of a hazardous liquid through a pipeline by 
gravity;
    (3) A pipeline subject to safety regulations of the U.S. Coast 
Guard;

[[Page 174]]

    (4) A low-stress pipeline that serves refining, manufacturing, or 
truck, rail, or vessel terminal facilities, if the pipeline is less than 
one mile long (measured outside facility grounds) and does not cross an 
offshore area or a waterway currently used for commercial navigation;
    (5) Transportation of hazardous liquid or carbon dioxide in an 
offshore pipeline in State waters where the pipeline is located upstream 
from the outlet flange of the following farthest downstream facility: 
The facility where hydrocarbons or carbon dioxide are produced or the 
facility where produced hydrocarbons or carbon dioxide are first 
separated, dehydrated, or otherwise processed;
    (6) Transportation of hazardous liquid or carbon dioxide in a 
pipeline on the OCS where the pipeline is located upstream of the point 
at which operating responsibility transfers from a producing operator to 
a transporting operator;
    (7) A pipeline segment upstream (generally seaward) of the last 
valve on the last production facility on the OCS where a pipeline on the 
OCS is producer-operated and crosses into State waters without first 
connecting to a transporting operator's facility on the OCS. Safety 
equipment protecting PHMSA-regulated pipeline segments is not excluded. 
A producing operator of a segment falling within this exception may 
petition the Administrator, under Sec. 190.9 of this chapter, for 
approval to operate under PHMSA regulations governing pipeline design, 
construction, operation, and maintenance;
    (8) Transportation of a hazardous liquid or carbon dioxide through 
onshore production (including flow lines), refining, or manufacturing 
facilities or storage or in-plant piping systems associated with such 
facilities;
    (9) Transportation of a hazardous liquid or carbon dioxide:
    (i) By vessel, aircraft, tank truck, tank car, or other non-pipeline 
mode of transportation; or
    (ii) Through facilities located on the grounds of a materials 
transportation terminal if the facilities are used exclusively to 
transfer hazardous liquid or carbon dioxide between non-pipeline modes 
of transportation or between a non-pipeline mode and a pipeline. These 
facilities do not include any device and associated piping that are 
necessary to control pressure in the pipeline under Sec. 195.406(b); or
    (10) Transportation of carbon dioxide downstream from the applicable 
following point:
    (i) The inlet of a compressor used in the injection of carbon 
dioxide for oil recovery operations, or the point where recycled carbon 
dioxide enters the injection system, whichever is farther upstream; or
    (ii) The connection of the first branch pipeline in the production 
field where the pipeline transports carbon dioxide to an injection well 
or to a header or manifold from which a pipeline branches to an 
injection well.
    (c) Breakout tanks. Breakout tanks subject to this part must comply 
with requirements that apply specifically to breakout tanks and, to the 
extent applicable, with requirements that apply to pipeline systems and 
pipeline facilities. If a conflict exists between a requirement that 
applies specifically to breakout tanks and a requirement that applies to 
pipeline systems or pipeline facilities, the requirement that applies 
specifically to breakout tanks prevails. Anhydrous ammonia breakout 
tanks need not comply with Sec. Sec. 195.132(b), 195.205(b), 195.242 
(c) and (d), 195.264(b) and (e), 195.307, 195.428(c) and (d), and 
195.432(b) and (c).

[73 FR 31644, June 3, 2008]

    Editorial Note: For Federal Register citations affecting Sec. 
195.1, see the List of CFR Sections Affected, which appears in the 
Finding Aids section of the printed volume and on GPO Access.



Sec. 195.2  Definitions.

    As used in this part--
    Abandoned means permanently removed from service.
    Administrator means the Administrator, Pipeline and Hazardous 
Materials Safety Administration or his or her delegate.
    Barrel means a unit of measurement equal to 42 U.S. standard 
gallons.
    Breakout tank means a tank used to (a) relieve surges in a hazardous 
liquid pipeline system or (b) receive and store

[[Page 175]]

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 Sec. 
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 Sec. 
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.
    Hazard to navigation means, for the purposes of this part, a 
pipeline where the top of the pipe is less than 12 inches (305 
millimeters) below the underwater natural bottom (as determined by 
recognized and generally accepted practices) in waters less than 15 feet 
(4.6 meters) deep, as measured from the mean low water.
    Hazardous liquid means petroleum, petroleum products, or anhydrous 
ammonia.
    Highly volatile liquid or HVL means a hazardous liquid which will 
form a vapor cloud when released to the atmosphere and which has a vapor 
pressure exceeding 276 kPa (40 psia) at 37.8[deg] C (100[deg] F).
    In-plant piping system means piping that is located on the grounds 
of a plant and used to transfer hazardous liquid or carbon dioxide 
between plant facilities or between plant facilities and a pipeline or 
other mode of transportation, not including any device and associated 
piping that are necessary to control pressure in the pipeline under 
Sec. 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.

[[Page 176]]

    Person means any individual, firm, joint venture, partnership, 
corporation, association, State, municipality, cooperative association, 
or joint stock association, and includes any trustee, receiver, 
assignee, or personal representative thereof.
    Petroleum means crude oil, condensate, natural gasoline, natural gas 
liquids, and liquefied petroleum gas.
    Petroleum product means flammable, toxic, or corrosive products 
obtained from distilling and processing of crude oil, unfinished oils, 
natural gas liquids, blend stocks and other miscellaneous hydrocarbon 
compounds.
    Pipe or line pipe means a tube, usually cylindrical, through which a 
hazardous liquid or carbon dioxide flows from one point to another.
    Pipeline or pipeline system means all parts of a pipeline facility 
through which a hazardous liquid or carbon dioxide moves in 
transportation, including, but not limited to, line pipe, valves, and 
other appurtenances connected to line pipe, pumping units, fabricated 
assemblies associated with pumping units, metering and delivery stations 
and fabricated assemblies therein, and breakout tanks.
    Pipeline facility means new and existing pipe, rights-of-way and any 
equipment, facility, or building used in the transportation of hazardous 
liquids or carbon dioxide.
    Production facility means piping or equipment used in the 
production, extraction, recovery, lifting, stabilization, separation or 
treating of petroleum or carbon dioxide, or associated storage or 
measurement. (To be a production facility under this definition, piping 
or equipment must be used in the process of extracting petroleum or 
carbon dioxide from the ground or from facilities where CO2 
is produced, and preparing it for transportation by pipeline. This 
includes piping between treatment plants which extract carbon dioxide, 
and facilities utilized for the injection of carbon dioxide for recovery 
operations.)
    Rural area means outside the limits of any incorporated or 
unincorpated city, town, village, or any other designated residential or 
commercial area such as a subdivision, a business or shopping center, or 
community development.
    Specified minimum yield strength means the minimum yield strength, 
expressed in p.s.i. (kPa) gage, prescribed by the specification under 
which the material is purchased from the manufacturer.
    Stress level means the level of tangential or hoop stress, usually 
expressed as a percentage of specified minimum yield strength.
    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 Sec. 
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 Sec. 195.6.

[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982, 
as amended by Amdt. 195-33, 50 FR 15898, Apr. 23, 1985; 50 FR 38660, 
Sept. 24, 1985; Amdt. 195-36, 51 FR 15007, Apr. 22, 1986; Amdt. 195-45, 
56 FR 26925, June 12, 1991; Amdt. 195-47, 56 FR 63771, Dec. 5, 1991; 
Amdt. 195-50, 59 FR 17281, Apr. 12, 1994; Amdt. 195-52, 59 FR 33395, 
33396, June 28, 1994; Amdt. 195-53, 59 FR 35471, July 12, 1994; Amdt. 
195-59, 62 FR 61695, Nov. 19, 1997; Amdt. 195-62, 63 FR 36376, July 6, 
1998; Amdt. 195-63, 63 FR 37506, July 13, 1998; Amdt. 195-69, 65 FR 
54444, Sept. 8, 2000; Amdt. 195-71, 65 FR 80544, Dec. 21, 2000; 68 FR 
11749, Mar. 12, 2003; Amdt. 195-81, 69 FR 32896, June 14, 2004; Amdt. 
195-82, 69 FR 48406, Aug. 10, 2004; 70 FR 11140, Mar. 8, 2005]



Sec. 195.3  Incorporation by reference.

    (a) Any document or portion thereof incorporated by reference in 
this part is included in this part as though it were printed in full. 
When only a portion of a document is referenced, then this part 
incorporates only that referenced portion of the document and the 
remainder is not incorporated. Applicable editions are listed in 
paragraph (c) of this section in parentheses following the title of the 
referenced material. Earlier editions listed in previous editions of 
this section may be

[[Page 177]]

used for components manufactured, designed, or installed in accordance 
with those earlier editions at the time they were listed. The user must 
refer to the appropriate previous edition of 49 CFR for a listing of the 
earlier editions.
    (b) All incorporated materials are available for inspection in the 
Office of Pipelline Safety, Pipeline and Hazardous Materials Safety 
Administration, U.S. Department of Transportation, 1200 New Jersey 
Avenue, SE., Washington, DC, 20590-0001 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. 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. (PRCI):
  (1) AGA Pipeline Research Committee,         Sec.  195.452(h)(4)(B).
   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.
B. American Petroleum Institute (API):
  (1) ANSI/API Specification 5L/ISO 3183       Sec. Sec.
   ``Specification for Line Pipe'' (43rd        195.106(b)(1)(i);
   edition and errata, 2004; and 44th           195.106(e).
   edition, 2007).
  (2) API Specification 6D ``Pipeline          Sec.  195.116(d).
   Valves'' (22nd edition, January 2002).
  (3) API Specification 12F ``Specification    Sec. Sec.
   for Shop Welded Tanks for Storage of         195.132(b)(1);
   Production Liquids,'' (11th edition, 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     Sec. Sec.
   Code: Maintenance Inspection, Rating,        195.205(b)(3);
   Repair, and Alteration,'' (8th edition,      195.432(c).
   1997 including Addenda 1 through 4).
  (5) API 620 ``Design and Construction of     Sec. Sec.
   Large, Welded, Low-Pressure Storage          195.132(b)(2);
   Tanks,'' (10th edition, 2002 including       195.205(b)(2);
   Addendum 1).                                 195.264(b)(1);
                                                195.264(e)(3);
                                                195.307(b).
  (6) API 650 ``Welded Steel Tanks for Oil     Sec. Sec.
   Storage,'' (10th edition, 1998 including     195.132(b)(3);
   Addenda 1-3).                                195.205(b)(1);
                                                195.264(b)(1);
                                                195.264(e)(2); 195.307I;
                                                195.307(d); 195.565;
                                                195.579(d).
  (7) API Recommended Practice 651 ``Cathodic  Sec. Sec.  195.565;
   Protection of Aboveground Petroleum          195.579(d).
   Storage Tanks,'' (2nd edition, December
   1997).
  (8) API Recommended Practice 652 ``Lining    Sec.  195.579(d).
   of Aboveground Petroleum Storage Tank
   Bottoms,'' (2nd edition, December 1997).
  (9) API 653 ``Tank Inspection, Repair,       Sec. Sec.
   Alteration, and Reconstruction,'' (3rd       195.205(b)(1);
   edition, 2001 including Addendum 1, 2003).   195.432(b).
  (10) API 1104 ``Welding of Pipelines and     Sec. Sec.  195.222;
   Related Facilities'' (19th edition 1999,     195.228(b); 195.214(a).
   including errata October 31, 2001; and
   20th edition 2007, including errata 2008).
  (11) API 1130 ``Computational Pipeline       Sec. Sec.  195.134;
   Monitoring for Liquid Pipelines,'' (2nd      195.444.
   edition, 2002).
  (12) API 2000 ``Venting Atmospheric and Low- Sec. Sec.
   Pressure Storage Tanks,'' (5th edition,      195.264(e)(2);
   April 1998).                                 195.264(e)(3).
  (13) API Recommended Practice 2003           Sec.  195.405(a).
   ``Protection Against Ignitions Arising Out
   of Static, Lightning, and Stray
   Currents,'' (6th edition, 1998).
  (14) API 2026 ``Safe Access/Egress           Sec.  195.405(b).
   Involving Floating Roofs of Storage Tanks
   in Petroleum Service,'' (2nd edition,
   1998).

[[Page 178]]

 
  (15) API Recommended Practice 2350           Sec.  195.428I.
   ``Overfill Protection for Storage Tanks In
   Petroleum Facilities,'' (2nd edition,
   1996).
  (16) API 2510 ``Design and Construction of   Sec. Sec.
   LPG Installations,'' (8th edition, 2001).    195.132(b)(3);
                                                195.205(b)(3);
                                                195.264(b)(2);
                                                195.264(e)(4);
                                                195.307(e);195.428(c);
                                                195.432(c).
  (17) API Recommended Practice 1162 ``Public  Sec. Sec.  195.440(a);
   Awareness Programs for Pipeline              195.440(b); 195.440(c).
   Operators,'' (1st edition, December 2003).
C. ASME International (ASME):
  (1) ASME B16.9-2003 (February 2004)          Sec.  195.118(a).
   ``Factory-Made Wrought Steel Butt Welding
   Fittings''.
  (2) ASME B31.4-2002 (October 2002)           Sec.  195.452(h)(4)(i).
   ``Pipeline Transportation Systems for
   Liquid Hydrocarbons and Other Liquids''.
  (3) ASME B31G-1991 (Reaffirmed; 2004)        Sec. Sec.
   ``Manual for Determining the Remaining       195.452(h)(4)(i)(B);
   Strength of Corroded Pipelines''.            195.452(h)(4)(iii)(D).
  (4) ASME B31.8-2003 (February 2004) ``Gas    Sec. Sec.
   Transmission and Distribution Piping         195.5(a)(1)(i);
   Systems''.                                   195.406(a)(1)(i).
  (5) ASME Boiler and Pressure Vessel Code,    Sec. Sec.  195.124;
   Section VIII, Division 1 ``Rules for         195.307(e).
   Construction of Pressure Vessels,'' (2004
   edition, including addenda through July 1,
   2005).
  (6) ASME Boiler and Pressure Vessel Code,    Sec.  195.307(e).
   Section VIII, Division 2 ``Rules for
   Construction for Pressure Vessels--
   Alternative Rules,'' (2004 edition,
   including addenda through July 1, 2005).
  (7) ASME Boiler and Pressure Vessel Code,    Sec.  195.222.
   Section IX ``Welding and Brazing
   Qualifications,'' (2004 edition, including
   addenda through July 1, 2005).
D. Manufacturers Standardization Society of
 the Valve and Fittings Industry, Inc. (MSS):
  (1) MSS SP-75-2004 ``Specification for High  Sec.  195.118(a).
   Test Wrought Butt Welding Fittings''.
  (2) [Reserved].............................  .........................
E. American Society for Testing and Materials
 (ASTM):
  (1) ASTM A53/A53M-04a (2004) ``Standard      Sec.  195.106(e).
   Specification for Pipe, Steel, Black and
   Hot-Dipped, Zinc-Coated Welded and
   Seamless''.
  (2) ASTM A106/A106M-04b (2004) ``Standard    Sec.  195.106(e).
   Specification for Seamless Carbon Steel
   Pipe for High-Temperature Service''.
  (3) ASTM A333/A333M-05 ``Standard            Sec.  195.106(e).
   Specification for Seamless and Welded
   Steel Pipe for Low-Temperature Service''.
  (4) ASTM A381-96 (Reapproved 2001)           Sec.  195.106(e).
   ``Standard Specification for Metal-Arc-
   Welded Steel Pipe for Use With High-
   Pressure Transmission Systems''.
  (5) ASTM A671-04 (2004) ``Standard           Sec.  195.106(e).
   Specification for Electric-Fusion-Welded
   Steel Pipe for Atmospheric and Lower
   Temperatures''.
  (6) ASTM A672-96 (Reapproved 2001)           Sec.  195.106(e).
   ``Standard Specification for Electric-
   Fusion-Welded Steel Pipe for High-Pressure
   Service at Moderate Temperatures.''.
  (7) ASTM A691-98 (Reapproved 2002)           Sec.  195.106(e).
   ``Standard Specification for Carbon and
   Alloy Steel Pipe Electric-Fusion-Welded
   for High-Pressure Service at High
   Temperatures.''.
F. National Fire Protection Association
 (NFPA):
  (1) NFPA 30 (2003) ``Flammable and           Sec.  195.264(b)(1).
   Combustible Liquids Code''.
  (2) [Reserved].............................
G. NACE International (NACE):
  (1) NACE Standard RP0169-2002 ``Control of   Sec. Sec.  195.571;
   External Corrosion on Underground or         195.573.
   Submerged Metallic Piping Systems''.
  (2) NACE Standard RP0502-2002 ``Pipeline     Sec.  195.588.
   External Corrosion Direct Assessment
   Methodology''.
------------------------------------------------------------------------


[[Page 179]]


[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982, 
as amended by Amdt. 195-32, 49 FR 36860, Sept. 20, 1984; 58 FR 14523, 
Mar. 18, 1993; Amdt. 195-52, 59 FR 33396, June 28, 1994; Amdt. 195-56, 
61 FR 26123, May 24, 1996; 61 FR 36826, July 15, 1996; Amdt. 195-61, 63 
FR 7723, Feb. 17, 1998; Amdt. 195-62, 63 FR 36376, July 6, 1998; Amdt. 
195-66, 64 FR 15934, Apr. 2, 1999; 65 FR 4770, Feb. 1, 2000; Amdt. 195-
73, 66 FR 67004, Dec. 27, 2001; 69 FR 18803, Apr. 9, 2004; Amdt. 195-81, 
69 FR 32896, June 14, 2004; 70 FR 11140, Mar. 8, 2005; Amdt. 195-84, 70 
FR 28842, May 19, 2005; Amdt. 195-85, 70 FR 61576, Oct. 25, 2005; Amdt. 
195-86, 71 FR 33409, June 9, 2006; 73 FR 16570, Mar. 28, 2008; 74 FR 
2894, Jan. 16, 2009; 74 FR 17101, Apr. 14, 2009]



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

    No person may transport any hazardous liquid or carbon dioxide 
unless the hazardous liquid or carbon dioxide is chemically compatible 
with both the pipeline, including all components, and any other 
commodity that it may come into contact with while in the pipeline.

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



Sec. 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 
Sec. 195.106 or to perform the testing under paragraph (a)(4) of this 
section is unknown, the design pressure may be verified and the maximum 
operating pressure determined by--
    (i) Testing the pipeline in accordance with ASME B31.8, Appendix N, 
to produce a stress equal to the yield strength; and
    (ii) Applying, to not more than 80 percent of the first pressure 
that produces a yielding, the design factor F in Sec. 195.106(a) and 
the appropriate factors in Sec. 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 Sec. 
195.406.
    (b) A pipeline that qualifies for use under this section need not 
comply with the corrosion control requirements of subpart H of this part 
until 12 months after it is placed into service, notwithstanding any 
previous deadlines for compliance.
    (c) Each operator must keep for the life of the pipeline a record of 
the investigations, tests, repairs, replacements, and alterations made 
under the requirements of paragraph (a) of this section.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-52, 
59 FR 33396, June 28, 1994; Amdt. 195-173, 66 FR 67004, Dec. 27, 2001]



Sec. 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

[[Page 180]]

    (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

[[Page 181]]

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

[[Page 182]]

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.

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



Sec. 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

[[Page 183]]

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.

[Amdt. 195-45, 56 FR 26925, June 12, 1991, as amended by Amdt. 195-50, 
59 FR 17281, Apr. 12, 1994]



Sec. 195.9  Outer continental shelf pipelines.

    Operators of transportation pipelines on the Outer Continental Shelf 
must identify on all their respective pipelines the specific points at 
which operating responsibility transfers to a producing operator. For 
those instances in which the transfer points are not identifiable by a 
durable marking, each operator will have until September 15, 1998 to 
identify the transfer points. If it is not practicable to durably mark a 
transfer point and the transfer point is located above water, the 
operator must depict the transfer point on a schematic maintained near 
the transfer point. If a transfer point is located subsea, the operator 
must identify the transfer point on a schematic which must be maintained 
at the nearest upstream facility and provided to PHMSA upon request. For 
those cases in which adjoining operators have not agreed on a transfer 
point by September 15, 1998 the Regional Director and the MMS Regional 
Supervisor will make a joint determination of the transfer point.

[Amdt. 195-59, 62 FR 61695, Nov. 19, 1997, as amended at 70 11140, Mar. 
8, 2005]



Sec. 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.



Sec. 195.11  What is a regulated rural gathering line and what 
requirements apply?

    Each operator of a regulated rural gathering line, as defined in 
paragraph (a) of this section, must comply with the safety requirements 
described in paragraph (b) of this section.
    (a) Definition. As used in this section, a regulated rural gathering 
line means an onshore gathering line in a rural area that meets all of 
the following criteria--
    (1) Has a nominal diameter from 6\5/8\ inches (168 mm) to 8\5/8\ 
inches (219.1 mm);
    (2) Is located in or within one-quarter mile (.40 km) of an 
unusually sensitive area as defined in Sec. 195.6; and
    (3) Operates at a maximum pressure established under Sec. 195.406 
corresponding to--
    (i) A stress level greater than 20-percent of the specified minimum 
yield strength of the line pipe; or
    (ii) If the stress level is unknown or the pipeline is not 
constructed with steel pipe, a pressure of more than 125 psi (861 kPa) 
gage.
    (b) Safety requirements. Each operator must prepare, follow, and 
maintain written procedures to carry out the requirements of this 
section. Except for the requirements in paragraphs (b)(2), (b)(3), 
(b)(9) and (b)(10) of this section, the safety requirements apply to all 
materials of construction.
    (1) Identify all segments of pipeline meeting the criteria in 
paragraph (a) of this section before April 3, 2009.
    (2) For steel pipelines constructed, replaced, relocated, or 
otherwise changed after July 3, 2009, design, install, construct, 
initially inspect, and initially test the pipeline in compliance with 
this part, unless the pipeline is converted under Sec. 195.5.
    (3) For non-steel pipelines constructed after July 3, 2009, notify 
the Administrator according to Sec. 195.8.
    (4) Beginning no later than January 3, 2009, comply with the 
reporting requirements in subpart B of this part.
    (5) Establish the maximum operating pressure of the pipeline 
according to Sec. 195.406 before transportation begins, or if the 
pipeline exists on July 3, 2008, before July 3, 2009.

[[Page 184]]

    (6) Install line markers according to Sec. 195.410 before 
transportation begins, or if the pipeline exists on July 3, 2008, before 
July 3, 2009. Continue to maintain line markers in compliance with Sec. 
195.410.
    (7) Establish a continuing public education program in compliance 
with Sec. 195.440 before transportation begins, or if the pipeline 
exists on July 3, 2008, before January 3, 2010. Continue to carry out 
such program in compliance with Sec. 195.440.
    (8) Establish a damage prevention program in compliance with Sec. 
195.442 before transportation begins, or if the pipeline exists on July 
3, 2008, before July 3, 2009. Continue to carry out such program in 
compliance with Sec. 195.442.
    (9) For steel pipelines, comply with subpart H of this part, except 
corrosion control is not required for pipelines existing on July 3, 2008 
before July 3, 2011.
    (10) For steel pipelines, establish and follow a comprehensive and 
effective program to continuously identify operating conditions that 
could contribute to internal corrosion. The program must include 
measures to prevent and mitigate internal corrosion, such as cleaning 
the pipeline and using inhibitors. This program must be established 
before transportation begins or if the pipeline exists on July 3, 2008, 
before July 3, 2009.
    (11) To comply with the Operator Qualification program requirements 
in subpart G of this part, have a written description of the processes 
used to carry out the requirements in Sec. 195.505 to determine the 
qualification of persons performing operations and maintenance tasks. 
These processes must be established before transportation begins or if 
the pipeline exists on July 3, 2008, before July 3, 2009.
    (c) New unusually sensitive areas. If, after July 3, 2008, a new 
unusually sensitive area is identified and a segment of pipeline becomes 
regulated as a result, except for the requirements of paragraphs (b)(9) 
and (b)(10) of this section, the operator must implement the 
requirements in paragraphs (b)(2) through (b)(11) of this section for 
the affected segment within 6 months of identification. For steel 
pipelines, comply with the deadlines in paragraph (b)(9) and (b)(10).
    (d) Record Retention. An operator must maintain records 
demonstrating compliance with each requirement according to the 
following schedule.
    (1) An operator must maintain the segment identification records 
required in paragraph (b)(1) of this section and the records required to 
comply with (b)(10) of this section, for the life of the pipe.
    (2) An operator must maintain the records necessary to demonstrate 
compliance with each requirement in paragraphs (b)(2) through (b)(9), 
and (b)(11) of this section according to the record retention 
requirements of the referenced section or subpart.

[73 FR 31644, June 3, 2008]



Sec. 195.12  What requirements apply to low-stress pipelines in rural 
areas?

    (a) General. This section does not apply to a rural low-stress 
pipeline regulated under this part as a low-stress pipeline that crosses 
a waterway currently used for commercial navigation. An operator of a 
rural low-stress pipeline meeting the following criteria must comply 
with the safety requirements described in paragraph (b) of this section. 
The pipeline:
    (1) Has a nominal diameter of 8\5/8\ inches (219.1 mm) or more;
    (2) Is located in or within a half mile (.80 km) of an unusually 
sensitive area (USA) as defined in Sec. 195.6; and
    (3) Operates at a maximum pressure established under Sec. 195.406 
corresponding to:
    (i) A stress level equal to or less than 20-percent of the specified 
minimum yield strength of the line pipe; or
    (ii) If the stress level is unknown or the pipeline is not 
constructed with steel pipe, a pressure equal to or less than 125 psi 
(861 kPa) gage.
    (b) Requirements. An operator of a pipeline meeting the criteria in 
paragraph (a) of this section must comply with the following safety 
requirements and compliance deadlines.
    (1) Identify all segments of pipeline meeting the criteria in 
paragraph (a) of this section before April 3, 2009.

[[Page 185]]

    (2) Beginning no later than January 3, 2009, comply with the 
reporting requirements of subpart B for the identified segments.
    (3)(i) Establish a written program in compliance with Sec. 195.452 
before July 3, 2009, to assure the integrity of the low-stress pipeline 
segments. Continue to carry out such program in compliance with Sec. 
195.452.
    (ii) To carry out the integrity management requirements in Sec. 
195.452, an operator may conduct a determination per Sec. 195.452(a) in 
lieu of the half mile buffer.
    (iii) Complete the baseline assessment of all segments in accordance 
with Sec. 195.452(c) before July 3, 2015, and complete at least 50-
percent of the assessments, beginning with the highest risk pipe, before 
January 3, 2012.
    (4) Comply with all other safety requirements of this part, except 
subpart H, before July 3, 2009. Comply with subpart H before July 3, 
2011.
    (c) Economic compliance burden. (1) An operator may notify PHMSA in 
accordance with Sec. 195.452(m) of a situation meeting the following 
criteria:
    (i) The pipeline meets the criteria in paragraph (a) of this 
section;
    (ii) The pipeline carries crude oil from a production facility;
    (iii) The pipeline, when in operation, operates at a flow rate less 
than or equal to 14,000 barrels per day; and
    (iv) The operator determines it would abandon or shut-down the 
pipeline as a result of the economic burden to comply with the 
assessment requirements in Sec. Sec. 195.452(d) or 195.452(j).
    (2) A notification submitted under this provision must include, at 
minimum, the following information about the pipeline: Its operating, 
maintenance and leak history; the estimated cost to comply with the 
integrity assessment requirements (with a brief description of the basis 
for the estimate); the estimated amount of production from affected 
wells per year, whether wells will be shut in or alternate 
transportation used, and if alternate transportation will be used, the 
estimated cost to do so.
    (3) When an operator notifies PHMSA in accordance with paragraph 
(c)(1) of this section, PHMSA will stay compliant with Sec. Sec. 
195.452(d) and 195.452(j)(3) until it has completed an analysis of the 
notification. PHMSA will consult the Department of Energy (DOE), as 
appropriate, to help analyze the potential energy impact of loss of the 
pipeline. Based on the analysis, PHMSA may grant the operator a special 
permit to allow continued operation of the pipeline subject to 
alternative safety requirements.
    (d) New unusually sensitive areas. If, after July 3, 2008, an 
operator identifies a new unusually sensitive area and a segment of 
pipeline meets the criteria in paragraph (a) of this section, the 
operator must take the following actions:
    (1) Except for paragraph (b)(2) of this section and the requirements 
of subpart H, comply with all other safety requirements of this part 
before July 3, 2009. Comply with subpart H before July 3, 2011.
    (2) Establish the program required in paragraph (b)(2)(i) within 12 
months following the date the area is identified. Continue to carry out 
such program in compliance with Sec. 195.452; and
    (3) Complete the baseline assessment required by paragraph 
(b)(2)(ii) of this section according to the schedule in Sec. 
195.452(d)(3).
    (d) Record Retention. An operator must maintain records 
demonstrating compliance with each requirement according to the 
following schedule.
    (1) An operator must maintain the segment identification records 
required in paragraph (b)(1) of this section for the life of the pipe.
    (2) An operator must maintain the records necessary to demonstrate 
compliance with each requirement in paragraphs (b)(2) through (b)(4) of 
this section according to the record retention requirements of the 
referenced section or subpart.

[73 FR 31644, June 3, 2008]



   Subpart B_Annual, Accident, and Safety-Related Condition Reporting



Sec. 195.48  Scope.

    This subpart prescribes requirements for periodic reporting and for 
reporting

[[Page 186]]

of accidents and safety-related conditions. This subpart applies to all 
pipelines subject to this part and, beginning January 5, 2009, applies 
to all rural low-stress hazardous liquid pipelines. An operator of a 
rural low-stress pipeline not otherwise subject to this part is not 
required to complete Parts J and K of the hazardous liquid annual report 
form (PHMSA F 7000-1.1) required by Sec. 195.49 or to provide the 
estimate of total miles that could affect high consequence areas in Part 
B of that form.

[73 FR 31646, June 3, 2008]



Sec. 195.49  Annual report.

    Beginning no later than June 15, 2005, each operator must annually 
complete and submit DOT form RSPA F 7000-1.1 for each type of hazardous 
liquid pipeline facility operated at the end of the previous year. A 
separate report is required for crude oil, HVL (including anhydrous 
ammonia), petroleum products, and carbon dioxide pipelines. Operators 
are encouraged, but not required, to file an annual report by June 15, 
2004, for calendar year 2003.

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



Sec. 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 Sec. 195.52(a)(4);
    (3) Confined to company property or pipeline right-of-way; and
    (4) Cleaned up promptly;
    (c) Death of any person;
    (d) Personal injury necessitating hospitalization;
    (e) Estimated property damage, including cost of clean-up and 
recovery, value of lost product, and damage to the property of the 
operator or others, or both, exceeding $50,000.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-39, 
53 FR 24950, July 1, 1988; Amdt. 195-45, 56 FR 26925, June 12, 1991; 
Amdt. 195-52, 59 FR 33396, June 28, 1994; Amdt. 195-63, 63 FR 37506, 
July 13, 1998; Amdt. 195-75, 67 FR 836, Jan. 8, 2002]



Sec. 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 Sec. 195.50, the operator of the system shall 
give notice, in accordance with paragraph (b) of this section, of any 
failure that:
    (1) Caused a death or a personal injury requiring hospitalization;
    (2) Resulted in either a fire or explosion not intentionally set by 
the operator;
    (3) Caused estimated property damage, including cost of cleanup and 
recovery, value of lost product, and damage to the property of the 
operator or others, or both, exceeding $50,000;
    (4) Resulted in pollution of any stream, river, lake, reservoir, or 
other similar body of water that violated applicable water quality 
standards, caused a discoloration of the surface of the water or 
adjoining shoreline, or deposited a sludge or emulsion beneath the 
surface of the water or upon adjoining shorelines; or
    (5) In the judgment of the operator was significant even though it 
did not meet the criteria of any other paragraph of this section.
    (b) Reports made under paragraph (a) of this section are made by 
telephone to 800-424-8802 (in Washington, DC, 20590-0001 (202) 372-2428) 
and must include the following information:
    (1) Name and address of the operator.
    (2) Name and telephone number of the reporter.
    (3) The location of the failure.
    (4) The time of the failure.
    (5) The fatalities and personal injuries, if any.
    (6) All other significant facts known by the operator that are 
relevant to

[[Page 187]]

the cause of the failure or extent of the damages.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-23, 
47 FR 32720, July 29, 1982; Amdt. 195-44, 54 FR 40878, Oct. 4, 1989; 
Amdt. 195-45, 56 FR 26925, June 12, 1991; Amdt. 195-52, 59 FR 33396, 
June 28, 1994; 74 FR 2894, Jan. 16, 2009]



Sec. 195.54  Accident reports.

    (a) Each operator that experiences an accident that is required to 
be reported under Sec. 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.

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



Sec. 195.55  Reporting safety-related conditions.

    (a) Except as provided in paragraph (b) of this section, each 
operator shall report in accordance with Sec. 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 Sec. 
195.50 or results in such an accident before the deadline for filing the 
safety-related condition report; or
    (3) Is corrected by repair or replacement in accordance with 
applicable safety standards before the deadline for filing the safety-
related condition report, except that reports are required for all 
conditions under paragraph (a)(1) of this section other than localized 
corrosion pitting on an effectively coated and cathodically protected 
pipeline.

[Amdt. 195-39, 53 FR 24950, July 1, 1988; 53 FR 29800, Aug. 8, 1988, as 
amended by Amdt. 195-63, 63 FR 37506, July 13, 1998]



Sec. 195.56  Filing safety-related condition reports.

    (a) Each report of a safety-related condition under Sec. 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.

[[Page 188]]

    (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.

[Amdt. 195-39, 53 FR 24950, July 1, 1988; 53 FR 29800, Aug. 8, 1988, as 
amended by Amdt. 195-42, 54 FR 32344, Aug. 7, 1989; Amdt. 195-44, 54 FR 
40878, Oct. 4, 1989; Amdt. 195-50, 59 FR 17281, Apr. 12, 1994; Amdt. 
195-61, 63 FR 7723, Feb. 17, 1998]



Sec. 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 Sec. 195.413(a), 
report the following information:
    (1) Name and principal address of operator.
    (2) Date of report.
    (3) Name, job title, and business telephone number of person 
submitting the report.
    (4) Total number of miles (kilometers) of pipeline inspected.
    (5) Length and date of installation of each exposed pipeline 
segment, and location; including, if available, the location according 
to the Minerals Management Service or state offshore area and block 
number tract.
    (6) Length and date of installation of each pipeline segment, if 
different from a pipeline segment identified under paragraph (a)(5) of 
this section, that is a hazard to navigation, and the location; 
including, if available, the location according to the Minerals 
Management Service or state offshore area and block number tract.
    (b) The report shall be mailed to the Office of Pipeline Safety, 
Pipeline and Hazardous Materials Safety Administration, Department of 
Transportation, Information Resources Manager, PHP-10, 1200 New Jersey 
Avenue, SE., Washington, DC 20590.

[Amdt. 195-47, 56 FR 63771, Dec. 5, 1991, as amended by Amdt. 195-63, 63 
FR 37506, July 13, 1998; 70 FR 11140, Mar. 8, 2005; 73 FR 16570, Mar. 
28, 2008; 74 FR 2894, Jan. 16, 2009]



Sec. 195.58  Address for written reports.

    Each written report required by this subpart must be made to the 
Office of Pipeline Safety, Pipeline and Hazardous Materials Safety 
Administration, U.S. Department of Transportation, Information Resources 
Manager, PHP-10, 1200 New Jersey Avenue, SE., Washington, DC 20590-0001. 
However, accident reports for intrastate pipelines subject to the 
jurisdiction of a State agency pursuant to a certification under the 
pipeline safety laws (49 U.S.C. 60101 et seq.) may be submitted in 
duplicate to that State agency if the regulations of that agency require 
submission of these reports and provide for further transmittal of one 
copy within 10 days of receipt to the Information Resources Manager. 
Safety-related condition reports required by Sec. 195.55 for intrastate 
pipelines must be submitted concurrently to the State agency, and if 
that agency acts as an agent of the Secretary with respect to interstate 
pipelines, safety-related condition reports for these pipelines must be 
submitted concurrently to that agency.

[Amdt. 195-55, 61 FR 18518, Apr. 26, 1996, as amended by Amdt. 195-81, 
69 FR 32897, June 14, 2004; 70 FR 11140, Mar. 8, 2005; 74 FR 2894, Jan. 
16, 2009]



Sec. 195.59  Abandonment or deactivation of facilities.

    For each abandoned offshore pipeline facility or each abandoned 
onshore pipeline facility that crosses over, under or through a 
commercially navigable waterway, the last operator of

[[Page 189]]

that facility must file a report upon abandonment of that facility.
    (a) The preferred method to submit data on pipeline facilities 
abandoned after October 10, 2000 is to the National Pipeline Mapping 
System (NPMS) in accordance with the NPMS ``Standards for Pipeline and 
Liquefied Natural Gas Operator Submissions.'' To obtain a copy of the 
NPMS Standards, please refer to the NPMS homepage at http://
www.npms.phmsa.dot.gov or contact the NPMS National Repository at 703-
317-3073. A digital data format is preferred, but hard copy submissions 
are acceptable if they comply with the NPMS Standards. In addition to 
the NPMS-required attributes, operators must submit the date of 
abandonment, diameter, method of abandonment, and certification that, to 
the best of the operator's knowledge, all of the reasonably available 
information requested was provided and, to the best of the operator's 
knowledge, the abandonment was completed in accordance with applicable 
laws. Refer to the NPMS Standards for details in preparing your data for 
submission. The NPMS Standards also include details of how to submit 
data. Alternatively, operators may submit reports by mail, fax or e-mail 
to the Office of Pipeline Safety, Pipeline and Hazardous Materials 
Safety Administration, U.S. Department of Transportation, Information 
Resources Manager, PHP-10, 1200 New Jersey Avenue, SE., Washington, DC 
20590-0001; fax (202) 366-4566; e-mail, 
``InformationResourcesManager@phmsa.

dot.gov. The information in the report must contain all reasonably 
available information related to the facility, including information in 
the possession of a third party. The report must contain the location, 
size, date, method of abandonment, and a certification that the facility 
has been abandoned in accordance with all applicable laws.
    (b) [Reserved]

[Amdt. 195-69, 65 FR 54444, Sept. 8, 2000, as amended at 70 FR 11140, 
Mar. 8, 2005; Amdt. 195-86, 72 FR 4657, Feb. 1, 2007; 73 FR 16570, Mar. 
28, 2008; 74 FR 2894, Jan. 16, 2009]



Sec. 195.60  Operator assistance in investigation.

    If the Department of Transportation investigates an accident, the 
operator involved shall make available to the representative of the 
Department all records and information that in any way pertain to the 
accident, and shall afford all reasonable assistance in the 
investigation of the accident.



Sec. 195.62  Supplies of accident report DOT Form 7000-1.

    Each operator shall maintain an adequate supply of forms that are a 
facsimile of DOT Form 7000-1 to enable it to promptly report accidents. 
The Department will, upon request, furnish specimen copies of the form. 
Requests should be addressed to the Office of Pipeline Safety, Pipeline 
and Hazardous Materials Safety Administration, U.S. Department of 
Transportation, Information Resources Manager, PHP-10, 1200 New Jersey 
Avenue, SE., Washington, DC 20590-0001.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended at 47 FR 32720, 
July 29, 1982; 74 FR 2894, Jan. 16, 2009]



Sec. 195.63  OMB control number assigned to information collection.

    The control number assigned by the Office of Management and Budget 
to the hazardous liquid pipeline information collection requirements of 
this part pursuant to the Paperwork Reduction Act of 1980 is 2137-0047.

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



                      Subpart C_Design Requirements



Sec. 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 Sec. 
195.424.



Sec. 195.101  Qualifying metallic components other than pipe.

    Notwithstanding any requirement of the subpart which incorporates by 
reference an edition of a document listed in Sec. 195.3, a metallic 
component other than pipe manufactured in accordance with any other 
edition of that document is qualified for use if--

[[Page 190]]

    (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 Sec. 
195.3:
    (1) Pressure testing;
    (2) Materials; and
    (3) Pressure and temperature ratings.

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



Sec. 195.102  Design temperature.

    (a) Material for components of the system must be chosen for the 
temperature environment in which the components will be used so that the 
pipeline will maintain its structural integrity.
    (b) Components of carbon dioxide pipelines that are subject to low 
temperatures during normal operation because of rapid pressure reduction 
or during the initial fill of the line must be made of materials that 
are suitable for those low temperatures.

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



Sec. 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.



Sec. 195.106  Internal design pressure.

    (a) Internal design pressure for the pipe in a pipeline is 
determined in accordance with the following formula:
P=(2St/D)xExF

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 [deg]F 
(482 [deg]C) for any period of time or over 600 [deg]F (316 [deg]C) for 
more than 1 hour.

    (b) The yield strength to be used in determining the internal design 
pressure under paragraph (a) of this section is the specified minimum 
yield strength. If the specified minimum yield strength is not known, 
the yield strength to be used in the design formula is one of the 
following:
    (1)(i) The yield strength determined by performing all of the 
tensile tests of API Specification 5L on randomly selected specimens 
with the following number of tests:

------------------------------------------------------------------------
                 Pipe size                          No. of tests
------------------------------------------------------------------------
Less than 6\5/8\ in (168 mm) nominal        One test for each 200
 outside diameter.                           lengths.
6 \5/8\ in through 12\3/4\ in (168 mm       One test for each 100
 through 324 mm) nominal outside diameter.   lengths.
Larger than 12\3/4\ in (324 mm) nominal     One test for each 50
 outside diameter.                           lengths.
------------------------------------------------------------------------

    (ii) If the average yield-tensile ratio exceeds 0.85, the yield 
strength shall be taken as 24,000 p.s.i. (165,474 kPa). If the average 
yield-tensile ratio is 0.85 or less, the yield strength of the pipe is 
taken as the lower of the following:
    (A) Eighty percent of the average yield strength determined by the 
tensile tests.
    (B) The lowest yield strength determined by the tensile tests.
    (2) If the pipe is not tensile tested as provided in paragraph (b) 
of this section, the yield strength shall be taken as 24,000 p.s.i. 
(165,474 kPa).
    (c) If the nominal wall thickness to be used in determining internal 
design pressure under paragraph (a) of this section is not known, it is 
determined by measuring the thickness of each piece of pipe at quarter 
points on one end. However, if the pipe is of uniform grade, size, and 
thickness, only 10 individual lengths or 5 percent of all lengths, 
whichever is greater, need be measured. The thickness of the lengths

[[Page 191]]

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 
Sec. Sec. 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:

------------------------------------------------------------------------
                                                                   Seam
            Specification                     Pipe class           joint
                                                                  factor
------------------------------------------------------------------------
ASTM A53............................  Seamless..................    1.00
                                      Electric resistance welded    1.00
                                      Furnace lap welded........    0.80
                                      Furnace butt welded.......    0.60
ASTM A106...........................  Seamless..................    1.00
ASTM A 333/A 333M...................  Seamless..................    1.00
                                      Welded....................    1.00
ASTM A381...........................  Double submerged arc          1.00
                                       welded.
ASTM A671...........................  Electric-fusion-welded....    1.00
ASTM A672...........................  Electric-fusion-welded....    1.00
ASTM A691...........................  Electric-fusion-welded....    1.00
API 5L..............................  Seamless..................    1.00
                                      Electric resistance welded    1.00
                                      Electric flash welded.....    1.00
                                      Submerged arc welded......    1.00
                                      Furnace lap welded........    0.80
                                      Furnace butt welded.......    0.60
------------------------------------------------------------------------


The seam joint factor for pipe which is not covered by this paragraph 
must be approved by the Administrator.

[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982, 
as amended by Amdt. 195-30, 49 FR 7569, Mar. 1, 1984; Amdt 195-37, 51 FR 
15335, Apr. 23, 1986; Amdt 195-40, 54 FR 5628, Feb. 6, 1989; 58 FR 
14524, Mar. 18, 1993; Amdt. 195-50, 59 FR 17281, Apr. 12, 1994; Amdt. 
195-52, 59 FR 33396, 33397, June 28, 1994; Amdt. 195-63, 63 FR 37506, 
July 13, 1998]



Sec. 195.108  External pressure.

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



Sec. 195.110  External loads.

    (a) Anticipated external loads (e.g.), earthquakes, vibration, 
thermal expansion, and contraction must be provided for in designing a 
pipeline system. In providing for expansion and flexibility, section 419 
of ASME/ANSI B31.4 must be followed.
    (b) The pipe and other components must be supported in such a way 
that the support does not cause excess localized stresses. In designing 
attachments to pipe, the added stress to the wall of the pipe must be 
computed and compensated for.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended at 58 FR 14524, 
Mar. 18, 1993]



Sec. 195.111  Fracture propagation.

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

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



Sec. 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.

[[Page 192]]

    (c) Each length of pipe with a nominal outside diameter of 4 \1/2\ 
in (114.3 mm) or more must be marked on the pipe or pipe coating with 
the specification to which it was made, the specified minimum yield 
strength or grade, and the pipe size. The marking must be applied in a 
manner that does not damage the pipe or pipe coating and must remain 
visible until the pipe is installed.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-52, 
59 FR 33396, June 28, 1994; Amdt. 195-63, 63 FR 37506, July 13, 1998]



Sec. 195.114  Used pipe.

    Any used pipe installed in a pipeline system must comply with Sec. 
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 Sec. 195.106(e). If the 
specified minimum yield strength or the wall thickness is not known, it 
is determined in accordance with Sec. 195.106 (b) or (c) as 
appropriate.
    (b) There may not be any:
    (1) Buckles;
    (2) Cracks, grooves, gouges, dents, or other surface defects that 
exceed the maximum depth of such a defect permitted by the specification 
to which the pipe was manufactured; or
    (3) Corroded areas where the remaining wall thickness is less than 
the minimum thickness required by the tolerances in the specification to 
which the pipe was manufactured.

However, pipe that does not meet the requirements of paragraph (b)(3) of 
this section may be used if the operating pressure is reduced to be 
commensurate with the remaining wall thickness.

[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982]



Sec. 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 of API Standard 6D (incorporated by reference, 
see Sec. 195.3).
    (e) Each valve other than a check valve must be equipped with a 
means for clearly indicating the position of the valve (open, closed, 
etc.).
    (f) Each valve must be marked on the body or the nameplate, with at 
least the following:
    (1) Manufacturer's name or trademark.
    (2) Class designation or the maximum working pressure to which the 
valve may be subjected.
    (3) Body material designation (the end connection material, if more 
than one type is used).
    (4) Nominal valve size.

[Amdt. 195-22, 46 FR 38360, July 27, 1981 as amended by Amdt. 195-45, 56 
FR 26926, June 12, 1991; Amdt. 195-86, 71 FR 33410, June 9, 2006]



Sec. 195.118  Fittings.

    (a) Butt-welding type fittings must meet the marking, end 
preparation, and the bursting strength requirements of ASME/ANSI B16.9 
or MSS Standard Practice SP-75.
    (b) There may not be any buckles, dents, cracks, gouges, or other 
defects in the fitting that might reduce the strength of the fitting.
    (c) The fitting must be suitable for the intended service and be at 
least as strong as the pipe and other fittings in the pipeline system to 
which it is attached.

[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982, 
as amended at 58 FR 14524, Mar. 18, 1993]

[[Page 193]]



Sec. 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 Administrator under Sec. 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 Sec. 190.9 of this chapter, 
for approval that design and construction to accommodate passage of 
instrumented internal inspection devices would be impracticable. If the 
petition is denied, within 1 year after the date of the notice of the 
denial, the operator must modify that segment to allow passage of 
instrumented internal inspection devices.

[Amdt. 195-50, 59 FR 17281, Apr. 12, 1994, as amended by Amdt. 195-63, 
63 FR 37506, July 13, 1998]



Sec. 195.122  Fabricated branch connections.

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



Sec. 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.



Sec. 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.



Sec. 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.



Sec. 195.130  Fabricated assemblies.

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



Sec. 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.

[[Page 194]]

    (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.

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



Sec. 195.134  CPM leak detection.

    This section applies to each hazardous liquid pipeline transporting 
liquid in single phase (without gas in the liquid). On such systems, 
each new computational pipeline monitoring (CPM) leak detection system 
and each replaced component of an existing CPM system must comply with 
section 4.2 of API 1130 in its design and with any other design criteria 
addressed in API 1130 for components of the CPM leak detection system.

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



                         Subpart D_Construction



Sec. 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 Sec. 195.424.



Sec. 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.



Sec. 195.204  Inspection--general.

    Inspection must be provided to ensure the installation of pipe or 
pipeline systems in accordance with the requirements of this subpart. No 
person may be used to perform inspections unless that person has been 
trained and is qualified in the phase of construction to be inspected.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-52, 
59 FR 33397, June 28, 1994]



Sec. 195.205  Repair, alteration and reconstruction of aboveground 
breakout tanks that have been in service.

    (a) Aboveground breakout tanks that have been repaired, altered, or 
reconstructed and returned to service must be capable of withstanding 
the internal pressure produced by the hazardous liquid to be stored 
therein and any anticipated external loads.
    (b) After October 2, 2000, compliance with paragraph (a) of this 
section requires the following for the tanks specified:
    (1) For tanks designed for approximately atmospheric pressure 
constructed of carbon and low alloy steel, welded or riveted, and non-
refrigerated and tanks built to API Standard 650 or its predecessor 
Standard 12C, repair, alteration, and reconstruction must be in 
accordance with API Standard 653.
    (2) For tanks built to API Specification 12F or API Standard 620, 
the repair, alteration, and reconstruction must be in accordance with 
the design, welding, examination, and material requirements of those 
respective standards.
    (3) For high pressure tanks built to API Standard 2510, repairs, 
alterations, and reconstruction must be in accordance with API 510.

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

[[Page 195]]



Sec. 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.



Sec. 195.208  Welding of supports and braces.

    Supports or braces may not be welded directly to pipe that will be 
operated at a pressure of more than 100 p.s.i. (689 kPa) gage.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-63, 
63 FR 37506, July 13, 1998]



Sec. 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 Sec. 195.248.

[Amdt. 195-22, 46 FR 39360, July 27, 1981, as amended by Amdt. 195-63, 
63 FR 37506, July 13, 1998]



Sec. 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 12\3/4\ in (324 mm) or less nominal outside 
diameter or has a diameter to wall thickness ratio less than 70.
    (c) Each circumferential weld which is located where the stress 
during bending causes a permanent deformation in the pipe must be 
nondestructively tested either before or after the bending process.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-52, 
59 FR 33396, June 28, 1994; Amdt. 195-63, 63 FR 37506, July 13, 1998]



Sec. 195.214  Welding procedures.

    (a) Welding must be performed by a qualified welder in accordance 
with welding procedures qualified under Section 5 of API 1104 or Section 
IX of the ASME Boiler and Pressure Vessel Code (incorporated by 
reference, see Sec. 195.3) . The quality of the test welds used to 
qualify the welding procedure shall be determined by destructive 
testing.
    (b) Each welding procedure must be recorded in detail, including the 
results of the qualifying tests. This record must be retained and 
followed whenever the procedure is used.

[Amdt. 195-38, 51 FR 20297, June 4, 1986, as amended at Amdt. 195-81, 69 
FR 32897, June 14, 2004]



Sec. 195.216  Welding: Miter joints.

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



Sec. 195.222  Welders: Qualification of welders.

    (a) Each welder must be qualified in accordance with section 6 of 
API 1104 (incorporated by reference, see Sec. 195.3) or section IX of 
the ASME Boiler and Pressure Vessel Code, (incorporated by reference, 
see Sec. 195.3) except that a welder qualified under an earlier edition 
than listed in Sec. 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

[[Page 196]]

    (2) Had one welded tested and found acceptable under section 9 of 
API 1104 (incorporated by reference, see Sec. 195.3).

[Amdt. 195-81, 69 FR 54593, Sept. 9, 2004, as amended by Amdt. 195-86, 
71 FR 33409, June 9, 2006]



Sec. 195.224  Welding: Weather.

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



Sec. 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.



Sec. 195.228  Welds and welding inspection: Standards of acceptability.

    (a) Each weld and welding must be inspected to insure compliance 
with the requirements of this subpart. Visual inspection must be 
supplemented by nondestructive testing.
    (b) The acceptability of a weld is determined according to the 
standards in Section 9 of API 1104. However, if a girth weld is 
unacceptable under those standards for a reason other than a crack, and 
if Appendix A to API 1104 (incorporated by reference, see Sec. 195.3) 
applies to the weld, the acceptability of the weld may be determined 
under that appendix.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-52, 
59 FR 33397, June 28, 1994; Amdt. 195-81, 69 FR 32898, June 14, 2004]



Sec. 195.230  Welds: Repair or removal of defects.

    (a) Each weld that is unacceptable under Sec. 195.228 must be 
removed or repaired. Except for welds on an offshore pipeline being 
installed from a pipelay vessel, a weld must be removed if it has a 
crack that is more than 8 percent of the weld length.
    (b) Each weld that is repaired must have the defect removed down to 
sound metal and the segment to be repaired must be preheated if 
conditions exist which would adversely affect the quality of the weld 
repair. After repair, the segment of the weld that was repaired must be 
inspected to ensure its acceptability.
    (c) Repair of a crack, or of any defect in a previously repaired 
area must be in accordance with written weld repair procedures that have 
been qualified under Sec. 195.214. Repair procedures must provide that 
the minimum mechanical properties specified for the welding procedure 
used to make the original weld are met upon completion of the final weld 
repair.

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



Sec. 195.234  Welds: Nondestructive testing.

    (a) A weld may be nondestructively tested by any process that will 
clearly indicate any defects that may affect the integrity of the weld.
    (b) Any nondestructive testing of welds must be performed--
    (1) In accordance with a written set of procedures for 
nondestructive testing; and
    (2) With personnel that have been trained in the established 
procedures and in the use of the equipment employed in the testing.
    (c) Procedures for the proper interpretation of each weld inspection 
must be established to ensure the acceptability of the weld under Sec. 
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,

[[Page 197]]

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.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-35, 
50 FR 37192, Sept. 21, 1985; Amdt. 195-52, 59 FR 33397, June 28, 1994]



Sec. Sec. 195.236-195.244  [Reserved]



Sec. 195.246  Installation of pipe in a ditch.

    (a) All pipe installed in a ditch must be installed in a manner that 
minimizes the introduction of secondary stresses and the possibility of 
damage to the pipe.
    (b) Except for pipe in the Gulf of Mexico and its inlets in waters 
less than 15 feet deep, all offshore pipe in water at least 12 feet deep 
(3.7 meters) but not more than 200 feet deep (61 meters) deep as 
measured from the mean low water must be installed so that the top of 
the pipe is below the underwater natural bottom (as determined by 
recognized and generally accepted practices) unless the pipe is 
supported by stanchions held in place by anchors or heavy concrete 
coating or protected by an equivalent means.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-52, 
59 FR 33397, June 28, 1994; 59 FR 36256, July 15, 1994; Amdt. 195-85, 69 
FR 48407, Aug. 10, 2004]



Sec. 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)
                                         -------------------------------
                Location                    For normal       For rock
                                            excavation    excavation \1\
------------------------------------------------------------------------
Industrial, commercial, and residential         36 (914)        30 (762)
 areas..................................
Crossing of inland bodies of water with        48 (1219)        18 (457)
 a width of at least 100 feet (30
 millimeters) from high water mark to
 high water mark........................
Drainage ditches at public roads and            36 (914)        36 (914)
 railroads..............................
Deepwater port safety zones.............       48 (1219)        24 (610)
Gulf of Mexico and its inlets in waters         36 (914)        18 (457)
 less than 15 feet (4.6 meters) deep as
 measured from mean low water...........
Other offshore areas under water less           36 (914)        18 (457)
 than 12 ft (3.7 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 Sec. 195.210 may be used if--
    (1) It is impracticable to comply with the minimum cover 
requirements; and
    (2) Additional protection is provided that is equivalent to the 
minimum required cover.

[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982 as 
amended by Amdt. 195-52, 59 FR 33397, June 28, 1994; 59 FR 36256, July 
15, 1994; Amdt. 195-63, 63 FR 37506, July 13, 1998; Amdt. 195-95, 69 FR 
48407, Aug. 10, 2004]

[[Page 198]]



Sec. 195.250  Clearance between pipe and underground structures.

    Any pipe installed underground must have at least 12 inches (305 
millimeters) of clearance between the outside of the pipe and the 
extremity of any other underground structure, except that for drainage 
tile the minimum clearance may be less than 12 inches (305 millimeters) 
but not less than 2 inches (51 millimeters). However, where 12 inches 
(305 millimeters) of clearance is impracticable, the clearance may be 
reduced if adequate provisions are made for corrosion control.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-63, 
63 FR 37506, July 13, 1998]



Sec. 195.252  Backfilling.

    When a ditch for a pipeline is backfilled, it must be backfilled in 
a manner that:
    (a) Provides firm support under the pipe; and
    (b) Prevents damage to the pipe and pipe coating from equipment or 
from the backfill material.

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



Sec. 195.254  Above ground components.

    (a) Any component may be installed above ground in the following 
situations, if the other applicable requirements of this part are 
complied with:
    (1) Overhead crossings of highways, railroads, or a body of water.
    (2) Spans over ditches and gullies.
    (3) Scraper traps or block valves.
    (4) Areas under the direct control of the operator.
    (5) In any area inaccessible to the public.
    (b) Each component covered by this section must be protected from 
the forces exerted by the anticipated loads.



Sec. 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.



Sec. 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.



Sec. 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.

[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982; 
Amdt. 195-50, 59 FR 17281, Apr. 12, 1994; Amdt. 195-63, 63 FR 37506, 
July 13, 1998]



Sec. 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.

[[Page 199]]

    (2) A device for the emergency shutdown of each pumping station.
    (3) If power is necessary to actuate the safety devices, an 
auxiliary power supply.
    (c) Each safety device must be tested under conditions approximating 
actual operations and found to function properly before the pumping 
station may be used.
    (d) Except for offshore pipelines, pumping equipment must be 
installed on property that is under the control of the operator and at 
least 15.2 m (50 ft) from the boundary of the pump station.
    (e) Adequate fire protection must be installed at each pump station. 
If the fire protection system installed requires the use of pumps, 
motive power must be provided for those pumps that is separate from the 
power that operates the station.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-52, 
59 FR 33397, June 28, 1994]



Sec. 195.264  Impoundment, protection against entry, normal/emergency 
venting or pressure/vacuum relief for aboveground breakout tanks.

    (a) A means must be provided for containing hazardous liquids in the 
event of spillage or failure of an aboveground breakout tank.
    (b) After October 2, 2000, compliance with paragraph (a) of this 
section requires the following for the aboveground breakout tanks 
specified:
    (1) For tanks built to API Specification 12F, API Standard 620, and 
others (such as API Standard 650 or its predecessor Standard 12C), the 
installation of impoundment must be in accordance with the following 
sections of NFPA 30:
    (i) Impoundment around a breakout tank must be installed in 
accordance with section 4.3.2.3.2; and
    (ii) Impoundment by drainage to a remote impounding area must be 
installed in accordance with section 4.3.2.3.1.
    (2) For tanks built to API 2510, the installation of impoundment 
must be in accordance with section 5 or 11 of API 2510 (incorporated by 
reference, see Sec. 195.3).
    (c) Aboveground breakout tank areas must be adequately protected 
against unauthorized entry.
    (d) Normal/emergency relief venting must be provided for each 
atmospheric pressure breakout tank. Pressure/vacuum-relieving devices 
must be provided for each low-pressure and high-pressure breakout tank.
    (e) For normal/emergency relief venting and pressure/vacuum-
relieving devices installed on aboveground breakout tanks after October 
2, 2000, compliance with paragraph (d) of this section requires the 
following for the tanks specified:
    (1) Normal/emergency relief venting installed on atmospheric 
pressure tanks built to API Specification 12F 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 section 9 of API Standard 620 (incorporated by 
reference, see Sec. 195.3) and its references to the normal and 
emergency venting requirements in API Standard 2000 (incorporated by 
reference, see Sec. 195.3).
    (4) Pressure and vacuum-relieving devices installed on high pressure 
tanks built to API Standard 2510 must be in accordance with sections 7 
or 11 of API 2510 (incorporated by reference, see Sec. 195.3).

[Amdt. 195-66, 64 FR 15935, Apr. 2, 1999, as amended by 195-86, 71 FR 
33410, June 9, 2006]



Sec. 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.

[[Page 200]]

    (e) The location of each overhead crossing.
    (f) The location of each valve and corrosion test station.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-34, 
50 FR 34474, Aug. 26, 1985]



                       Subpart E_Pressure Testing



Sec. 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 Sec. 195.424.

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



Sec. 195.302  General requirements.

    (a) Except as otherwise provided in this section and in Sec. 
195.305(b), no operator may operate a pipeline unless it has been 
pressure tested under this subpart without leakage. In addition, no 
operator may return to service a segment of pipeline that has been 
replaced, relocated, or otherwise changed until it has been pressure 
tested under this subpart without leakage.
    (b) Except for pipelines converted under Sec. 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 Sec. 195.406(a)(5) that is--
    (i) An interstate pipeline constructed before January 8, 1971;
    (ii) An interstate offshore gathering line constructed before August 
1, 1977;
    (iii) An intrastate pipeline constructed before October 21, 1985; or
    (iv) A low-stress pipeline constructed before August 11, 1994 that 
transports HVL.
    (2) Any carbon dioxide pipeline constructed before July 12, 1991, 
that--
    (i) Has its maximum operating pressure established under Sec. 
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 Sec. 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 Sec. 195.303, the following 
compliance deadlines apply to pipelines under paragraphs (b)(1) and 
(b)(2)(i) of this section that have not been pressure tested under this 
subpart:
    (1) Before December 7, 1998, for each pipeline each operator shall--
    (i) Plan and schedule testing according to this paragraph; or
    (ii) Establish the pipeline's maximum operating pressure under Sec. 
195.406(a)(5).
    (2) For pipelines scheduled for testing, each operator shall--
    (i) Before December 7, 2000, pressure test--
    (A) Each pipeline identified by name, symbol, or otherwise that 
existing records show contains more than 50 percent by mileage (length) 
of electric resistance welded pipe manufactured before 1970; and
    (B) At least 50 percent of the mileage (length) of all other 
pipelines; and
    (ii) Before December 7, 2003, pressure test the remainder of the 
pipeline mileage (length).

[Amdt. 195-51, 59 FR 29384, June 7, 1994, as amended by Amdt. 195-53, 59 
FR 35471, July 12, 1994; Amdt. 195-51B, 61 FR 43027, Aug. 20, 1996; 
Amdt. 195-58, 62 FR 54592, Oct. 21, 1997; Amdt. 195-63, 63 FR 37506, 
July 13, 1998; Amdt. 195-65, 63 FR 59479, Nov. 4, 1998]



Sec. 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 
Sec. 195.302(b)(1)(i)-(iii) and Sec. 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;

[[Page 201]]

    (2) Risk Classification C if the location indicator is ranked as 
high risk; or
    (3) Risk Classification B.
    (b) An operator shall evaluate each pipeline segment in the program 
according to the following indicators of risk:
    (1) The location indicator is--
    (i) High risk if an area is non-rural or environmentally sensitive 
\1\; or
    (ii) Medium risk; or
    (iii) Low risk if an area is not high or medium risk.
    (2) The product indicator is \1\
---------------------------------------------------------------------------

    \1\ (See Appendix B, Table C).
---------------------------------------------------------------------------

    (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:

                     Sec.  195.303--Test Deadlines
------------------------------------------------------------------------
                                         Risk
        Pipeline Segment            classification       Test deadline
------------------------------------------------------------------------
Pre-1970 Pipe susceptible to      C or B............  12/7/2000
 longitudinal seam failures       A.................  12/7/2002
 [defined in Sec.  195.303(c) &
 (d)].
All Other Pipeline Segments.....  C.................  12/7/2002
                                  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

[[Page 202]]

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 
Sec. 195.406(a)(5).
    (h) An operator must maintain records establishing compliance with 
this section, including records verifying the risk classifications, the 
plans and schedule for testing, the conduct of the testing, and the 
review of the risk classifications.
    (i) An operator may discontinue a program under this section only 
after written notification to the Administrator and approval, if needed, 
of a schedule for pressure testing.

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



Sec. 195.304  Test pressure.

    The test pressure for each pressure test conducted under this 
subpart must be maintained throughout the part of the system being 
tested for at least 4 continuous hours at a pressure equal to 125 
percent, or more, of the maximum operating pressure and, in the case of 
a pipeline that is not visually inspected for leakage during the test, 
for at least an additional 4 continuous hours at a pressure equal to 110 
percent, or more, of the maximum operating pressure.

[Amdt. 195-51, 59 FR 29384, June 7, 1994. Redesignated by Amdt. 195-65, 
63 FR 59480, Nov. 4, 1998]



Sec. 195.305  Testing of components.

    (a) Each pressure test under Sec. 195.302 must test all pipe and 
attached fittings, including components, unless otherwise permitted by 
paragraph (b) of this section.
    (b) A component, other than pipe, that is the only item being 
replaced or added to the pipeline system need not be hydrostatically 
tested under paragraph (a) of this section if the manufacturer certifies 
that either--
    (1) The component was hydrostatically tested at the factory; or
    (2) The component was manufactured under a quality control system 
that ensures each component is at least equal in strength to a prototype 
that was hydrostatically tested at the factory.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-51, 
59 FR 29385, June 7, 1994; Amdt. 195-52, 59 FR 33397, June 28, 1994. 
Redesignated by Amdt. 195-65, 63 FR 59480, Nov. 4, 1998]



Sec. 195.306  Test medium.

    (a) Except as provided in paragraphs (b), (c), and (d) of this 
section, water must be used as the test medium.
    (b) Except for offshore pipelines, liquid petroleum that does not 
vaporize rapidly may be used as the test medium if--
    (1) The entire pipeline section under test is outside of cities and 
other populated areas;
    (2) Each building within 300 feet (91 meters) of the test section is 
unoccupied while the test pressure is equal to or greater than a 
pressure which produces a hoop stress of 50 percent of specified minimum 
yield strength;
    (3) The test section is kept under surveillance by regular patrols 
during the test; and
    (4) Continuous communication is maintained along entire test 
section.
    (c) Carbon dioxide pipelines may use inert gas or carbon dioxide as 
the test medium if--
    (1) The entire pipeline section under test is outside of cities and 
other populated areas;
    (2) Each building within 300 feet (91 meters) of the test section is 
unoccupied while the test pressure is equal to or greater than a 
pressure that produces a hoop stress of 50 percent of specified minimum 
yield strength;
    (3) The maximum hoop stress during the test does not exceed 80 
percent of specified minimum yield strength;
    (4) Continuous communication is maintained along entire test 
section; and
    (5) The pipe involved is new pipe having a longitudinal joint factor 
of 1.00.
    (d) Air or inert gas may be used as the test medium in low-stress 
pipelines.

[Amdt. 195-22, 46 FR 38360, July 27, 1991, as amended by Amdt. 195-45, 
56 FR 26926, June 12, 1991; Amdt. 195-51, 59 FR 29385, June 7, 1994; 
Amdt. 195-53, 59 FR 35471, July 12, 1994; Amdt. 195-51A, 59 FR 41260, 
Aug. 11, 1994; Amdt. 195-63, 63 FR 37506, July 13, 1998]

[[Page 203]]



Sec. 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 of API Standard 620 
(incorporated by reference, see Sec. 195.3).
    (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 15936, Apr. 2, 1999, as amended by Amdt. 195-86, 71 
FR 33410, June 9, 2006]



Sec. 195.308  Testing of tie-ins.

    Pipe associated with tie-ins must be pressure tested, either with 
the section to be tied in or separately.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by 195-51, 59 FR 
29385, June 7, 1994]



Sec. 195.310  Records.

    (a) A record must be made of each pressure test required by this 
subpart, and the record of the latest test must be retained as long as 
the facility tested is in use.
    (b) The record required by paragraph (a) of this section must 
include:
    (1) The pressure recording charts;
    (2) Test instrument calibration data;
    (3) The name of the operator, the name of the person responsible for 
making the test, and the name of the test company used, if any;
    (4) The date and time of the test;
    (5) The minimum test pressure;
    (6) The test medium;
    (7) A description of the facility tested and the test apparatus;
    (8) An explanation of any pressure discontinuities, including test 
failures, that appear on the pressure recording charts;
    (9) Where elevation differences in the section under test exceed 100 
feet (30 meters), a profile of the pipeline that shows the elevation and 
test sites over the entire length of the test section; and
    (10) Temperature of the test medium or pipe during the test period.

[Amdt. 195-34, 50 FR 34474, Aug. 26, 1985, as amended by Amdt. 195-51, 
59 FR 29385, June 7, 1994; Amdt. 195-63, 63 FR 37506, July 13, 1998; 
Amdt. 195-78, 68 FR 53528, Sept. 11, 2003]



                   Subpart F_Operation and Maintenance



Sec. 195.400  Scope.

    This subpart prescribes minimum requirements for operating and 
maintaining pipeline systems constructed with steel pipe.



Sec. 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 Sec. 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 in Sec. 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:

[[Page 204]]

    (1) An interstate pipeline, other than a low-stress pipeline, on 
which construction was begun after March 31, 1970, that transports 
hazardous liquid.
    (2) An interstate offshore gathering line, other than a low-stress 
pipeline, on which construction was begun after July 31, 1977, that 
transports hazardous liquid.
    (3) An intrastate pipeline, other than a low-stress pipeline, on 
which construction was begun after October 20, 1985, that transports 
hazardous liquid.
    (4) A pipeline on which construction was begun after July 11, 1991, 
that transports carbon dioxide.
    (5) A low-stress pipeline on which construction was begun after 
August 10, 1994.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-33, 
50 FR 15899, Apr. 23, 1985; Amdt. 195-33A, 50 FR 39008, Sept. 26, 1985; 
Amdt. 195-36, 51 FR 15008, Apr. 22, 1986; Amdt. 195-45, 56 FR 26926, 
June 12, 1991; Amdt. 195-53, 59 FR 35471, July 12, 1994]



Sec. 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 
Sec. 195.406, consider the hazardous liquid or carbon dioxide in 
transportation, variations in altitude along the pipeline, and pressure 
monitoring and control devices.
    (8) In the case of a pipeline that is not equipped to fail safe, 
monitoring from an attended location pipeline pressure during startup 
until steady state pressure and flow conditions are reached and during 
shut-in to assure operation within limits prescribed by Sec. 195.406.
    (9) In the case of facilities not equipped to fail safe that are 
identified under paragraph 195.402(c)(4) or that control receipt and 
delivery of the hazardous liquid or carbon dioxide, detecting abnormal 
operating conditions by monitoring pressure, temperature, flow or other 
appropriate operational data and transmitting this data to an attended 
location.
    (10) Abandoning pipeline facilities, including safe disconnection 
from an

[[Page 205]]

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 Sec. 
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

[[Page 206]]

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 Sec. 195.55.

[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982, 
as amended by Amdt. 195-24, 47 FR 46852, Oct. 21, 1982; Amdt. 195-39, 53 
FR 24951, July 1, 1988; Amdt. 195-45, 56 FR 26926, June 12, 1991; Amdt. 
195-46, 56 FR 31090, July 9, 1991; Amdt. 195-49, 59 FR 6585, Feb. 11, 
1994; Amdt. 195-55, 61 FR 18518, Apr. 26, 1996; Amdt. 195-69, 65 FR 
54444, Sept. 8, 2000; Amdt. 195-173, 66 FR 67004, Dec. 27, 2001]



Sec. 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. 195-67, 64 FR 46866, Aug. 27, 1999, as amended at Amdt. 195-78, 
68 FR 53528, Sept. 11, 2003]



Sec. 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 Sec. 195.402(c)(9) applies;
    (vi) Rights-of-way; and
    (vii) Safety devices to which Sec. 195.428 applies.
    (2) All crossings of public roads, railroads, rivers, buried 
utilities, and foreign pipelines.

[[Page 207]]

    (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 Sec. 195.402 apply.
    (c) Each operator shall maintain the following records for the 
periods specified:
    (1) The date, location, and description of each repair made to pipe 
shall be maintained for the useful life of the pipe.
    (2) The date, location, and description of each repair made to parts 
of the pipeline system other than pipe shall be maintained for at least 
1 year.
    (3) A record of each inspection and test required by this subpart 
shall be maintained for at least 2 years or until the next inspection or 
test is performed, whichever is longer.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-34, 
50 FR 34474, Aug. 26, 1985; Amdt. 195-173, 66 FR 67004, Dec. 27, 2001]



Sec. 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 (Sec. 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 (Sec. 195.402(c)).

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



Sec. 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 Sec. 195.106. However, for steel pipe in pipelines 
being converted under Sec. 195.5, if one or more factors of the design 
formula (Sec. 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 Sec. Sec. 195.106 (a) and (e); or
    (ii) If the pipe is 12 \3/4\ inch (324 mm) or less outside diameter 
and is not tested to yield under this paragraph, 200 p.s.i. (1379 kPa) 
gage.
    (2) The design pressure of any other component of the pipeline.
    (3) Eighty percent of the test pressure for any part of the pipeline 
which has been pressure tested under subpart E of this part.
    (4) Eighty percent of the factory test pressure or of the prototype 
test pressure for any individually installed component which is excepted 
from testing under Sec. 195.305.
    (5) For pipelines under Sec. Sec. 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

[[Page 208]]

controls and protective equipment to control the pressure within this 
limit.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-33, 
50 FR 15899, Apr. 23, 1985; 50 FR 38660, Sept. 24, 1985; Amdt. 195-51, 
59 FR 29385, June 7, 1994; Amdt. 195-52, 59 FR 33397, June 28, 1994; 
Amdt. 195-63, 63 FR 37506, July 13, 1998; Amdt. 195-65, 63 FR 59480, 
Nov. 4, 1998]



Sec. 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 Sec. 195.402(c)(9);
    (2) Receiving notices from operator personnel, the public, and 
public authorities of abnormal or emergency conditions and sending this 
information to appropriate personnel or government agencies for 
corrective action;
    (3) Conducting two-way vocal communication between a control center 
and the scene of abnormal operations and emergencies; and
    (4) Providing communication with fire, police, and other appropriate 
public officials during emergency conditions, including a natural 
disaster.



Sec. 195.410  Line markers.

    (a) Except as provided in paragraph (b) of this section, each 
operator shall place and maintain line markers over each buried pipeline 
in accordance with the following:
    (1) Markers must be located at each public road crossing, at each 
railroad crossing, and in sufficient number along the remainder of each 
buried line so that its location is accurately known.
    (2) The marker must state at least the following on a background of 
sharply contrasting color:
    (i) The word ``Warning,'' ``Caution,'' or ``Danger'' followed by the 
words ``Petroleum (or the name of the hazardous liquid transported) 
Pipeline'', or ``Carbon Dioxide Pipeline,'' all of which, except for 
markers in heavily developed urban areas, must be in letters at least 1 
inch (25 millimeters) high with an approximate stroke of \1/4\ inch (6.4 
millimeters).
    (ii) The name of the operator and a telephone number (including area 
code) where the operator can be reached at all times.
    (b) Line markers are not required for buried pipelines located--
    (1) Offshore or at crossings of or under waterways and other bodies 
of water; or
    (2) In heavily developed urban areas such as downtown business 
centers where--
    (i) The placement of markers is impractical and would not serve the 
purpose for which markers are intended; and
    (ii) The local government maintains current substructure records.
    (c) Each operator shall provide line marking at locations where the 
line is above ground in areas that are accessible to the public.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-27, 
48 FR 25208, June 6, 1983; Amdt. 195-54, 60 FR 14650, Mar. 20, 1995; 
Amdt. 195-63, 63 FR 37506, July 13, 1998]



Sec. 195.412  Inspection of rights-of-way and crossings under navigable
waters.

    (a) Each operator shall, at intervals not exceeding 3 weeks, but at 
least 26 times each calendar year, inspect the surface conditions on or 
adjacent to each pipeline right-of-way. Methods of inspection include 
walking, driving, flying or other appropriate means of traversing the 
right-of-way.
    (b) Except for offshore pipelines, each operator shall, at intervals 
not exceeding 5 years, inspect each crossing under a navigable waterway 
to determine the condition of the crossing.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-24, 
47 FR 46852, Oct. 21, 1982; Amdt. 195-52, 59 FR 33397, June 28, 1994]



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

    (a) Except for gathering lines of 4\1/2\ inches (114mm) nominal 
outside diameter or smaller, each operator shall prepare and follow a 
procedure to identify its pipelines in the Gulf of Mexico and

[[Page 209]]

its inlets in waters less than 15 feet (4.6 meters) deep as measured 
from mean low water that are at risk of being an exposed underwater 
pipeline or a hazard to navigation. The procedures must be in effect 
August 10, 2005.
    (b) Each operator shall conduct appropriate periodic underwater 
inspections of its pipelines in the Gulf of Mexico and its inlets in 
waters less than 15 feet (4.6 meters) deep as measured from mean low 
water based on the identified risk.
    (c) If an operator discovers that its pipeline is an exposed 
underwater pipeline or poses a hazard to navigation, the operator 
shall--
    (1) Promptly, but not later than 24 hours after discovery, notify 
the National Response Center, telephone: 1-800-424-8802, of the location 
and, if available, the geographic coordinates of that pipeline.
    (2) Promptly, but not later than 7 days after discovery, mark the 
location of the pipeline in accordance with 33 CFR Part 64 at the ends 
of the pipeline segment and at intervals of not over 500 yards (457 
meters) long, except that a pipeline segment less than 200 yards (183 
meters) long need only be marked at the center; and
    (3) Within 6 months after discovery, or not later than November 1 of 
the following year if the 6 month period is later than November 1 of the 
year of discovery, bury the pipeline so that the top of the pipe is 36 
inches (914 millimeters) below the underwater natural bottom (as 
determined by recognized and generally accepted practices) for normal 
excavation or 18 inches (457 millimeters) for rock excavation.
    (i) An operator may employ engineered alternatives to burial that 
meet or exceed the level of protection provided by burial.
    (ii) If an operator cannot obtain required state or Federal permits 
in time to comply with this section, it must notify OPS; specify whether 
the required permit is State or Federal; and, justify the delay.

[Amdt. 195-82, 69 FR 48407, Aug. 10, 2004]



Sec. Sec. 195.414-195.418  [Reserved]



Sec. 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 7\1/2\ months, 
but at least twice each calendar year, inspect each mainline valve to 
determine that it is functioning properly.
    (c) Each operator shall provide protection for each valve from 
unauthorized operation and from vandalism.

[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982, 
as amended by Amdt. 195-24, 47 FR 46852, Oct. 21, 1982]



Sec. 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.



Sec. 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 Sec. 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,

[[Page 210]]

but not less than 50 p.s.i. (345 kPa) gage above the vapor pressure of 
the commodity.
    (c) No operator may move any pipeline containing highly volatile 
liquids where materials in the line section involved are not joined by 
welding unless--
    (1) The operator complies with paragraphs (b) (1) and (2) of this 
section; and
    (2) That line section is isolated to prevent the flow of highly 
volatile liquid.

[Amdt. 195-22, 46 FR 38360, July 27, 1981; 46 FR 38922, July 30, 1981, 
as amended by Amdt. 195-63, 63 FR 37506, July 13, 1998]



Sec. 195.426  Scraper and sphere facilities.

    No operator may use a launcher or receiver that is not equipped with 
a relief device capable of safely relieving pressure in the barrel 
before insertion or removal of scrapers or spheres. The operator must 
use a suitable device to indicate that pressure has been relieved in the 
barrel or must provide a means to prevent insertion or removal of 
scrapers or spheres if pressure has not been relieved in the barrel.

[Amdt. 195-22, 46 FR 38360, July 27, 1981; 47 FR 32721, July 29, 1982]



Sec. 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 7\1/2\ months, but at least 
twice each calendar year, inspect and test each pressure limiting 
device, relief valve, pressure regulator, or other item of pressure 
control equipment to determine that it is functioning properly, is in 
good mechanical condition, and is adequate from the standpoint of 
capacity and reliability of operation for the service in which it is 
used.
    (b) In the case of relief valves on pressure breakout tanks 
containing highly volatile liquids, each operator shall test each valve 
at intervals not exceeding 5 years.
    (c) Aboveground breakout tanks that are constructed or significantly 
altered according to API Standard 2510 after October 2, 2000, must have 
an overfill protection system installed according to section 5.1.2 of 
API Standard 2510. Other aboveground breakout tanks with 600 gallons 
(2271 liters) or more of storage capacity that are constructed or 
significantly altered after October 2, 2000, must have an overfill 
protection system installed according to API Recommended Practice 2350. 
However, operators need not comply with any part of API Recommended 
Practice 2350 for a particular breakout tank if the operator notes in 
the manual required by Sec. 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.

[Amdt. 195-22, 46 FR 38360, July 27, 1981, as amended by Amdt. 195-24, 
47 FR 46852, Oct. 21, 1982; Amdt. 195-66, 64 FR 15936, Apr. 2, 1999]



Sec. 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.



Sec. 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 Sec. 195.402(c)(3).

[[Page 211]]

    (c) Each operator shall inspect the physical integrity of in-service 
steel aboveground breakout tanks built to API Standard 2510 according to 
section 6 of API 510.
    (d) The intervals of inspection specified by documents referenced in 
paragraphs (b) and (c) of this section begin on May 3, 1999, or on the 
operator's last recorded date of the inspection, whichever is earlier.

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



Sec. 195.434  Signs.

    Each operator must maintain signs visible to the public around each 
pumping station and breakout tank area. Each sign must contain the name 
of the operator and a telephone number (including area code) where the 
operator can be reached at all times.

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



Sec. 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.



Sec. 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.



Sec. 195.440  Public awareness.

    (a) Each pipeline operator must develop and implement a written 
continuing public education program that follows the guidance provided 
in the American Petroleum Institute's (API) Recommended Practice (RP) 
1162 (incorporated by reference, see Sec. 195.3).
    (b) The operator's program must follow the general program 
recommendations of API RP 1162 and assess the unique attributes and 
characteristics of the operator's pipeline and facilities.
    (c) The operator must follow the general program recommendations, 
including baseline and supplemental requirements of API RP 1162, unless 
the operator provides justification in its program or procedural manual 
as to why compliance with all or certain provisions of the recommended 
practice is not practicable and not necessary for safety.
    (d) The operator's program must specifically include provisions to 
educate the public, appropriate government organizations, and persons 
engaged in excavation related activities on:
    (1) Use of a one-call notification system prior to excavation and 
other damage prevention activities;
    (2) Possible hazards associated with unintended releases from a 
hazardous liquid or carbon dioxide pipeline facility;
    (3) Physical indications that such a release may have occurred;
    (4) Steps that should be taken for public safety in the event of a 
hazardous liquid or carbon dioxide pipeline release; and
    (5) Procedures to report such an event.
    (e) The program must include activities to advise affected 
municipalities, school districts, businesses, and residents of pipeline 
facility locations.
    (f) The program and the media used must be as comprehensive as 
necessary to reach all areas in which the operator transports hazardous 
liquid or carbon dioxide.
    (g) The program must be conducted in English and in other languages 
commonly understood by a significant number and concentration of the 
non-English speaking population in the operator's area.
    (h) Operators in existence on June 20, 2005, must have completed 
their written programs no later than June 20, 2006. Upon request, 
operators must submit their completed programs to PHMSA or, in the case 
of an intrastate pipeline facility operator, the appropriate State 
agency.
    (i) The operator's program documentation and evaluation results must 
be available for periodic review by appropriate regulatory agencies.

[Amdt. 195-84, 70 FR 28843, May 19, 2005]



Sec. 195.442  Damage prevention program.

    (a) Except as provided in paragraph (d) of this section, each 
operator of a buried pipeline must carry out, in accordance with this 
section, a written program to prevent damage to that pipeline from 
excavation activities.

[[Page 212]]

For the purpose of this section, the term ``excavation activities'' 
includes excavation, blasting, boring, tunneling, backfilling, the 
removal of aboveground structures by either explosive or mechanical 
means, and other earthmoving operations.
    (b) An operator may comply with any of the requirements of paragraph 
(c) of this section through participation in a public service program, 
such as a one-call system, but such participation does not relieve the 
operator of the responsibility for compliance with this section. 
However, an operator must perform the duties of paragraph (c)(3) of this 
section through participation in a one-call system, if that one-call 
system is a qualified one-call system. In areas that are covered by more 
than one qualified one-call system, an operator need only join one of 
the qualified one-call systems if there is a central telephone number 
for excavators to call for excavation activities, or if the one-call 
systems in those areas communicate with one another. An operator's 
pipeline system must be covered by a qualified one-call system where 
there is one in place. For the purpose of this section, a one-call 
system is considered a ``qualified one-call system'' if it meets the 
requirements of section (b)(1) or (b)(2) or this section.
    (1) The state has adopted a one-call damage prevention program under 
Sec. 198.37 of this chapter; or
    (2) The one-call system:
    (i) Is operated in accordance with Sec. 198.39 of this chapter;
    (ii) Provides a pipeline operator an opportunity similar to a 
voluntary participant to have a part in management responsibilities; and
    (iii) Assesses a participating pipeline operator a fee that is 
proportionate to the costs of the one-call system's coverage of the 
operator's pipeline.
    (c) The damage prevention program required by paragraph (a) of this 
section must, at a minimum:
    (1) Include the identity, on a current basis, of persons who 
normally engage in excavation activities in the area in which the 
pipeline is located.
    (2) Provides for notification of the public in the vicinity of the 
pipeline and actual notification of persons identified in paragraph 
(c)(1) of this section of the following as often as needed to make them 
aware of the damage prevention program:
    (i) The program's existence and purpose; and
    (ii) How to learn the location of underground pipelines before 
excavation activities are begun.
    (3) Provide a means of receiving and recording notification of 
planned excavation activities.
    (4) If the operator has buried pipelines in the area of excavation 
activity, provide for actual notification of persons who give notice of 
their intent to excavate of the type of temporary marking to be provided 
and how to identify the markings.
    (5) Provide for temporary marking of buried pipelines in the area of 
excavation activity before, as far as practical, the activity begins.
    (6) Provide as follows for inspection of pipelines that an operator 
has reason to believe could be damaged by excavation activities:
    (i) The inspection must be done as frequently as necessary during 
and after the activities to verify the integrity of the pipeline; and
    (ii) In the case of blasting, any inspection must include leakage 
surveys.
    (d) A damage prevention program under this section is not required 
for the following pipelines:
    (1) Pipelines located offshore.
    (2) Pipelines to which access is physically controlled by the 
operator.

[Amdt. 195-54, 60 FR 14651, Mar. 20, 1995, as amended by Amdt. 195-60, 
62 FR 61699, Nov. 19, 1997]



Sec. 195.444  CPM leak detection.

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

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

                         High Consequence Areas



Sec. 195.450  Definitions.

    The following definitions apply to this section and Sec. 195.452:

[[Page 213]]

    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 Sec. 195.6.

[Amdt. 195-70, 65 FR 75405, Dec. 1, 2000]

                      Pipeline Integrity Management



Sec. 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--

[[Page 214]]

    (i) This section specifies otherwise; or
    (ii) The operator demonstrates that an alternative practice is 
supported by a reliable engineering evaluation and provides an 
equivalent level of public safety and environmental protection.
    (c) What must be in the baseline assessment plan? (1) An operator 
must include each of the following elements in its written baseline 
assessment plan:
    (i) The methods selected to assess the integrity of the line pipe. 
An operator must assess the integrity of the line pipe by any of the 
following methods. The methods an operator selects to assess low 
frequency electric resistance welded pipe or lap welded pipe susceptible 
to longitudinal seam failure must be capable of assessing seam integrity 
and of detecting corrosion and deformation anomalies.
    (A) Internal inspection tool or tools capable of detecting corrosion 
and deformation anomalies including dents, gouges and grooves;
    (B) Pressure test conducted in accordance with subpart E of this 
part;
    (C) External corrosion direct assessment in accordance with Sec. 
195.588; or
    (D) Other technology that the operator demonstrates can provide an 
equivalent understanding of the condition of the line pipe. An operator 
choosing this option must notify the Office of Pipeline Safety (OPS) 90 
days before conducting the assessment, by sending a notice to the 
address or facsimile number specified in paragraph (m) of this section.
    (ii) A schedule for completing the integrity assessment;
    (iii) An explanation of the assessment methods selected and 
evaluation of risk factors considered in establishing the assessment 
schedule.
    (2) An operator must document, prior to implementing any changes to 
the plan, any modification to the plan, and reasons for the 
modification.
    (d) When must operators complete baseline assessments? Operators 
must complete baseline assessments as follows:
    (1) Time periods. Complete assessments before the following 
deadlines:

------------------------------------------------------------------------
                                     Then complete
                                       baseline          And assess at
                                    assessments not    least 50 percent
                                    later than the     of the line pipe
       If the pipeline is:          following date      on an expedited
                                    according to a     basis, beginning
                                     schedule that     with the highest
                                      prioritizes       risk pipe, not
                                     assessments:         later than:
------------------------------------------------------------------------
Category 1......................  March 31, 2008....  September 30,
                                                       2004.
Category 2......................  February 17, 2009.  August 16, 2005.
Category 3......................  Date the pipeline   Not applicable.
                                   begins 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 Sec. 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.

[[Page 215]]

    (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 the operator discovers through the 
integrity assessment or information analysis. In addressing all 
conditions, an operator must evaluate

[[Page 216]]

all anomalous conditions and remediate those that could reduce a 
pipeline's integrity. An operator must be able to demonstrate that the 
remediation of the condition will ensure the condition is unlikely to 
pose a threat to the long-term integrity of the pipeline. An operator 
must comply with Sec. 195.422 when making a repair.
    (i) Temporary pressure reduction. An operator must notify PHMSA, in 
accordance with paragraph (m) of this section, if the operator cannot 
meet the schedule for evaluation and remediation required under 
paragraph (h)(3) of this section and cannot provide safety through a 
temporary reduction in operating pressure.
    (ii) Long-term pressure reduction. When a pressure reduction exceeds 
365 days, the operator must notify PHMSA in accordance with paragraph 
(m) of this section and explain the reasons for the delay. An operator 
must also take further remedial action to ensure the safety of the 
pipeline.
    (2) Discovery of condition. Discovery of a condition occurs when an 
operator has adequate information about the condition to determine that 
the condition presents a potential threat to the integrity of the 
pipeline. An operator must promptly, but no later than 180 days after an 
integrity assessment, obtain sufficient information about a condition to 
make that determination, unless the operator can demonstrate that the 
180-day period is impracticable.
    (3) Schedule for evaluation and remediation. An operator must 
complete remediation of a condition according to a schedule prioritizing 
the conditions for evaluation and remediation. If an operator cannot 
meet the schedule for any condition, the operator must explain the 
reasons why it cannot meet the schedule and how the changed schedule 
will not jeopardize public safety or environmental protection.
    (4) Special requirements for scheduling remediation--(i) Immediate 
repair conditions. An operator's evaluation and remediation schedule 
must provide for immediate repair conditions. To maintain safety, an 
operator must temporarily reduce operating pressure or shut down the 
pipeline until the operator completes the repair of these conditions. An 
operator must calculate the temporary reduction in operating pressure 
using the formula in section 451.7 of ASME/ANSI B31.4 (incorportaed by 
reference, see Sec. 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 Sec. 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

[[Page 217]]

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 Sec. 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

[[Page 218]]

pipeline system. An operator must evaluate the capability of its leak 
detection means and modify, as necessary, to protect the high 
consequence area. An operator's evaluation must, at least, consider, the 
following factors--length and size of the pipeline, type of product 
carried, the pipeline's proximity to the high consequence area, the 
swiftness of leak detection, location of nearest response personnel, 
leak history, and risk assessment results.
    (4) Emergency Flow Restricting Devices (EFRD). If an operator 
determines that an EFRD is needed on a pipeline segment to protect a 
high consequence area in the event of a hazardous liquid pipeline 
release, an operator must install the EFRD. In making this 
determination, an operator must, at least, consider the following 
factors--the swiftness of leak detection and pipeline shutdown 
capabilities, the type of commodity carried, the rate of potential 
leakage, the volume that can be released, topography or pipeline 
profile, the potential for ignition, proximity to power sources, 
location of nearest response personnel, specific terrain between the 
pipeline segment and the high consequence area, and benefits expected by 
reducing the spill size.
    (j) What is a continual process of evaluation and assessment to 
maintain a pipeline's integrity?--(1) General. After completing the 
baseline integrity assessment, an operator must continue to assess the 
line pipe at specified intervals and periodically evaluate the integrity 
of each pipeline segment that could affect a high consequence area.
    (2) Evaluation. An operator must conduct a periodic evaluation as 
frequently as needed to assure pipeline integrity. An operator must base 
the frequency of evaluation on risk factors specific to its pipeline, 
including the factors specified in paragraph (e) of this section. The 
evaluation must consider the results of the baseline and periodic 
integrity assessments, information analysis (paragraph (g) of this 
section), and decisions about remediation, and preventive and mitigative 
actions (paragraphs (h) and (i) of this section).
    (3) Assessment intervals. An operator must establish five-year 
intervals, not to exceed 68 months, for continually assessing the line 
pipe's integrity. An operator must base the assessment intervals on the 
risk the line pipe poses 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

[[Page 219]]

welded pipe or lap welded pipe susceptible to longitudinal seam failure 
must be capable of assessing seam integrity and of detecting corrosion 
and deformation anomalies.
    (i) Internal inspection tool or tools capable of detecting corrosion 
and deformation anomalies including dents, gouges and grooves;
    (ii) Pressure test conducted in accordance with subpart E of this 
part;
    (iii) External corrosion direct assessment in accordance with Sec. 
195.588; or
    (iv) Other technology that the operator demonstrates can provide an 
equivalent understanding of the condition of the line pipe. An operator 
choosing this option must notify OPS 90 days before conducting the 
assessment, by sending a notice to the address or facsimile number 
specified in paragraph (m) of this section.
    (k) What methods to measure program effectiveness must be used? An 
operator's program must include methods to measure whether the program 
is effective in assessing and evaluating the integrity of each pipeline 
segment and in protecting the high consequence areas. See Appendix C of 
this part for guidance on methods that can be used to evaluate a 
program's effectiveness.
    (l) What records must be kept? (1) An operator must maintain for 
review during an inspection:
    (i) A written integrity management program in accordance with 
paragraph (b) of this section.
    (ii) Documents to support the decisions and analyses, including any 
modifications, justifications, variances, deviations and determinations 
made, and actions taken, to implement and evaluate each element of the 
integrity management program listed in paragraph (f) of this section.
    (2) See Appendix C of this part for examples of records an operator 
would be required to keep.
    (m) How does an operator notify PHMSA? An operator must provide any 
notification required by this section by:
    (1) Entering the information directly on the Integrity Management 
Database Web site at http://primis.phmsa.dot.gov/imdb/;
    (2) Sending the notification to the Information Resources Manager, 
Office of Pipeline Safety, Pipeline and Hazardous Materials Safety 
Administration, 1200 New Jersey Avenue, SE., Washington, DC 20590; or
    (3) Sending the notification to the Information Resources Manager by 
facsimile to (202) 366-7128.

[Amdt. 195-70, 65 FR 75406, Dec. 1, 2000, as amended by Amdt. 195-74, 67 
FR 1660, 1661, Jan. 14, 2002; Amdt. 195-76, 67 FR 2143, Jan. 16, 2002; 
67 FR 46911, July 17, 2002; 70 FR 11140, Mar. 8, 2005; Amdt. 195-85, 70 
FR 61576, Oct. 25, 2005; Amdt. 195-87, 72 FR 39017, July 17, 2007; 73 FR 
16571, Mar. 28, 2008; 73 FR 31646, June 3, 2008]

    Editorial Note: By Amdt. 195-87, 72 FR 39017, July 17, 2007, Sec. 
195.452 was amended by revising paragraph (h)(4); however, the amendment 
could not be incorporated due to inaccurate amendatory instruction.



              Subpart G_Qualification of Pipeline Personnel

    Source: Amdt. 195-67, 64 FR 46866, Aug. 27, 1999, unless otherwise 
noted.



Sec. 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.



Sec. 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;

[[Page 220]]

    (b) Oral examination;
    (c) Work performance history review;
    (d) Observation during:
    (1) performance on the job,
    (2) on the job training, or
    (3) simulations;
    (e) Other forms of assessment.
    Qualified means that an individual has been evaluated and can:
    (a) Perform assigned covered tasks and
    (b) Recognize and react to abnormal operating conditions.

[Amdt. 195-67, 64 FR 46866, Aug. 27, 1999, as amended by Amdt. 195-72, 
66 FR 43524, Aug. 20, 2001]



Sec. 195.505  Qualification program.

    Each operator shall have and follow a written qualification program. 
The program shall include provisions to:
    (a) Identify covered tasks;
    (b) Ensure through evaluation that individuals performing covered 
tasks are qualified;
    (c) Allow individuals that are not qualified pursuant to this 
subpart to perform a covered task if directed and observed by an 
individual that is qualified;
    (d) Evaluate an individual if the operator has reason to believe 
that the individual's performance of a covered task contributed to an 
accident as defined in Part 195;
    (e) Evaluate an individual if the operator has reason to believe 
that the individual is no longer qualified to perform a covered task;
    (f) Communicate changes that affect covered tasks to individuals 
performing those covered tasks;
    (g) Identify those covered tasks and the intervals at which 
evaluation of the individual's qualifications is needed;
    (h) After December 16, 2004, provide training, as appropriate, to 
ensure that individuals performing covered tasks have the necessary 
knowledge and skills to perform the tasks in a manner that ensures the 
safe operation of pipeline facilities; and
    (i) After December 16, 2004, notify the Administrator or a state 
agency participating under 49 U.S.C. Chapter 601 if the operator 
significantly modifies the program after the Administrator or state 
agency has verified that it complies with this section.

[Amdt. 195-67, 64 FR 46866, Aug. 27, 1999, as amended by Amdt. 195-84, 
70 FR 10336, Mar. 3, 2005]



Sec. 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.



Sec. 195.509  General.

    (a) Operators must have a written qualification program by April 27, 
2001. The program must be available for review by the Administrator or 
by a state agency participating under 49 U.S.C. Chapter 601 if the 
program is under the authority of that state agency.
    (b) Operators must complete the qualification of individuals 
performing covered tasks by October 28, 2002.
    (c) Work performance history review may be used as a sole evaluation 
method for individuals who were performing a covered task prior to 
October 26, 1999.
    (d) After October 28, 2002, work performance history may not be used 
as a sole evaluation method.
    (e) After December 16, 2004, observation of on-the-job performance 
may not be used as the sole method of evaluation.

[Amdt. 195-67, 64 FR 46866, Aug. 27, 1999, as amended by Amdt. 195-72, 
66 FR 43524, Aug. 20, 2001; Amdt. 195-84, 70 FR 10336, Mar. 3, 2005]

[[Page 221]]



                       Subpart H_Corrosion Control

    Source: Amdt. 195-73, 66 FR 67004, Dec. 27, 2001, unless otherwise 
noted.



Sec. 195.551  What do the regulations in this subpart cover?

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



Sec. 195.553  What special definitions apply to this subpart?

    As used in this subpart--
    Active corrosion means continuing corrosion which, unless 
controlled, could result in a condition that is detrimental to public 
safety or the environment.
    Buried means covered or in contact with soil.
    Direct assessment means an integrity assessment method that utilizes 
a process to evaluate certain threats (i.e., external corrosion, 
internal corrosion and stress corrosion cracking) to a pipeline 
segment's integrity. The process includes the gathering and integration 
of risk factor data, indirect examination or analysis to identify areas 
of suspected corrosion, direct examination of the pipeline in these 
areas, and post assessment evaluation.
    Electrical survey means a series of closely spaced pipe-to-soil 
readings over a pipeline that are subsequently analyzed to identify 
locations where a corrosive current is leaving the pipeline.
    External corrosion direct assessment (ECDA) means a four-step 
process that combines pre-assessment, indirect inspection, direct 
examination, and post-assessment to evaluate the threat of external 
corrosion to the integrity of a pipeline.
    Pipeline environment includes soil resistivity (high or low), soil 
moisture (wet or dry), soil contaminants that may promote corrosive 
activity, and other known conditions that could affect the probability 
of active corrosion.
    You means operator.

[Amdt. 195-73, 66 FR 67004, Dec. 27, 2001, as amended by Amdt. 195-85, 
70 FR 61576, Oct. 25, 2005]



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



Sec. 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 Sec. 195.401(c), not including the movement of pipe 
covered by Sec. 195.424; or
    (b) Converted under Sec. 195.5 and--
    (1) Has an external coating that substantially meets Sec. 195.559 
before the pipeline is placed in service; or
    (2) Is a segment that is relocated, replaced, or substantially 
altered.



Sec. 195.559  What coating material may I use for external corrosion 
control?

    Coating material for external corrosion control under Sec. 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.



Sec. 195.561  When must I inspect pipe coating used for external
corrosion control?

    (a) You must inspect all external pipe coating required by Sec. 
195.557 just prior to lowering the pipe into the ditch or submerging the 
pipe.
    (b) You must repair any coating damage discovered.

[[Page 222]]



Sec. 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 
Sec. 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 Sec. 195.5 
must have cathodic protection if the pipeline--
    (1) Has cathodic protection that substantially meets Sec. 195.571 
before the pipeline is placed in service; or
    (2) Is a segment that is relocated, replaced, or substantially 
altered.
    (c) All other buried or submerged pipelines that have an effective 
external coating must have cathodic protection. \1\ Except as provided 
by paragraph (d) of this section, this requirement does not apply to 
breakout tanks and does not apply to buried piping in breakout tank 
areas and pumping stations until December 29, 2003.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    (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 
Sec. 195.573(b).



Sec. 195.565  How do I install cathodic protection on breakout tanks?

    After October 2, 2000, when you install cathodic protection under 
Sec. 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 Sec. 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.



Sec. 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 Sec. 195.571.



Sec. 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

[[Page 223]]

corrosion requiring corrective action under Sec. 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.



Sec. 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 
(incorporated by reference, see Sec. 195.3).

[Amdt. 195-86, 71 FR 33411, June 9, 2006]



Sec. 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 Sec. 
195.571:
    (1) Conduct tests on the protected pipeline at least once each 
calendar year, but with intervals not exceeding 15 months. However, if 
tests at those intervals are impractical for separately protected short 
sections of bare or ineffectively coated pipelines, testing may be done 
at least once every 3 calendar years, but with intervals not exceeding 
39 months.
    (2) Identify not more than 2 years after cathodic protection is 
installed, the circumstances in which a close-interval survey or 
comparable technology is practicable and necessary to accomplish the 
objectives of paragraph 10.1.1.3 of NACE Standard RP 0169 (incorporated 
by reference, see Sec. 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 exceeding 2\1/
                                             2\ months.
Reverse current switch....................
Diode.....................................
Interference bond whose failure would
 jeopardize structural protection.
------------------------------------------------------------------------
Other interference bond...................  At least once each calendar
                                             year, but with intervals
                                             not exceeding 15 months.
------------------------------------------------------------------------

    (d) Breakout tanks. You must inspect each cathodic protection system 
used to control corrosion on the bottom of an aboveground breakout tank 
to ensure that operation and maintenance of the system are in accordance 
with API Recommended Practice 651. However, this inspection is not 
required if you note in the corrosion control procedures established 
under Sec. 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 Sec. 195.401(b). However, if the 
deficiency involves a pipeline in an integrity management program under 
Sec. 195.452, you must correct the deficiency as required by Sec. 
195.452(h).

[Amdt. 195-73, 66 FR 67004, Dec. 27, 2001; 67 FR 70118, Nov. 20, 2002, 
as amended by Amdt. 195-86, 71 FR 33411, June 9, 2006]

[[Page 224]]



Sec. 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.



Sec. 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.



Sec. 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 7\1/2\ months.
    (c) Removing pipe. Whenever you remove pipe from a pipeline, you 
must inspect the internal surface of the pipe for evidence of corrosion. 
If you find internal corrosion requiring corrective action under Sec. 
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 Sec. 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.



Sec. 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

[[Page 225]]

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.



Sec. 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:

------------------------------------------------------------------------
                                                Then the frequency of
       If the pipeline is  located:                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 Sec. 195.581.



Sec. 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.



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

    Under Sec. 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.



Sec. 195.588  What standards apply to direct assessment?

    (a) If you use direct assessment on an onshore pipeline to evaluate 
the effects of external corrosion, you must follow the requirements of 
this section for performing external corrosion direct assessment. This 
section does not apply to methods associated with direct assessment, 
such as close interval surveys, voltage gradient surveys, or examination 
of exposed pipelines, when used separately from the direct assessment 
process.
    (b) The requirements for performing external corrosion direct 
assessment are as follows:
    (1) General. You must follow the requirements of NACE Standard 
RP0502-2002 (incorporated by reference, see Sec. 195.3). Also, you must 
develop and implement an ECDA plan that includes procedures addressing 
pre-assessment, indirect examination, direct examination, and post-
assessment.
    (2) Pre-assessment. In addition to the requirements in Section 3 of 
NACE Standard RP0502-2002, the ECDA plan procedures for pre-assessment 
must include--
    (i) Provisions for applying more restrictive criteria when 
conducting ECDA for the first time on a pipeline segment;
    (ii) The basis on which you select at least two different, but 
complementary, indirect assessment tools to assess each ECDA region; and

[[Page 226]]

    (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.
    (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--
    (i) Provisions for applying more restrictive criteria when 
conducting ECDA for the first time on a pipeline segment;
    (ii) Criteria for identifying and documenting those indications that 
must be considered for excavation and direct examination, including at 
least the following:
    (A) The known sensitivities of assessment tools;
    (B) The procedures for using each tool; and
    (C) The approach to be used for decreasing the physical spacing of 
indirect assessment tool readings when the presence of a defect is 
suspected;
    (iii) For each indication identified during the indirect 
examination, criteria for--
    (A) Defining the urgency of excavation and direct examination of the 
indication; and
    (B) Defining the excavation urgency as immediate, scheduled, or 
monitored; and
    (iv) Criteria for scheduling excavations of indications in each 
urgency level.
    (4) Direct examination. In addition to the requirements in Section 5 
of NACE Standard RP0502-2002, the procedures for direct examination of 
indications from the indirect examination must include--
    (i) Provisions for applying more restrictive criteria when 
conducting ECDA for the first time on a pipeline segment;
    (ii) Criteria for deciding what action should be taken if either:
    (A) Corrosion defects are discovered that exceed allowable limits 
(Section 5.5.2.2 of NACE Standard RP0502-2002 provides guidance for 
criteria); or
    (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);
    (iii) Criteria and notification procedures for any changes in the 
ECDA plan, including changes that affect the severity classification, 
the priority of direct examination, and the time frame for direct 
examination of indications; and
    (iv) Criteria that describe how and on what basis you will 
reclassify and re-prioritize any of the provisions specified in Section 
5.9 of NACE Standard RP0502-2002.
    (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--
    (i) Measures for evaluating the long-term effectiveness of ECDA in 
addressing external corrosion in pipeline segments; and
    (ii) Criteria for evaluating whether conditions discovered by direct 
examination of indications in each ECDA region indicate a need for 
reassessment of the pipeline segment at an interval less than that 
specified in Sections 6.2 and 6.3 of NACE Standard RP0502-2002 (see 
appendix D of NACE Standard RP0502-2002).

[Amdt. 195-85, 70 FR 61576, Oct. 25, 2005]



Sec. 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.

[[Page 227]]

You must retain these records for at least 5 years, except that records 
related to Sec. Sec. 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.



   Sec. Appendix A to Part 195--Delineation Between Federal and State 
       Jurisdiction--Statement of Agency Policy and Interpretation

    In 1979, Congress enacted comprehensive safety legislation governing 
the transportation of hazardous liquids by pipeline, the Hazardous 
Liquids Pipeline Safety Act of 1979, 49 U.S.C. 2001 et seq. (HLPSA). The 
HLPSA expanded the existing statutory authority for safety regulation, 
which was limited to transportation by common carriers in interstate and 
foreign commerce, to transportation through facilities used in or 
affecting interstate or foreign commerce. It also added civil penalty, 
compliance order, and injunctive enforcement authorities to the existing 
criminal sanctions. Modeled largely on the Natural Gas Pipeline Safety 
Act of 1968, 49 U.S.C. 1671 et seq. (NGPSA), the HLPSA provides for a 
national hazardous liquid pipeline safety program with nationally 
uniform minimal standards and with enforcement administered through a 
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 administratively practical approach was 
necessary in distinguishing between interstate and intrastate liquid 
pipeline facilities and in determining how best to accomplish this, DOT 
has logically examined the approach used in the NGPSA. The NGPSA defines 
the interstate gas pipeline facilities subject to exclusive Federal 
jurisdiction as those subject to the 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

[[Page 228]]

within the meaning of the HLPSA. The types of situations in which DOT 
will ignore the existence or non-existence of a filing with FERC will be 
limited to those cases in which it appears obvious that a complaint 
filed with FERC would be successful or in which blind reliance on a FERC 
filing would result in a situation clearly not intended by the HLPSA 
such as a pipeline facility not being subject to either State or Federal 
safety regulation. DOT anticipates that the situations in which there is 
any question about the validity of the FERC filings as a ready reference 
will be few and that the actual variations from reliance on those 
filings will be rare. The following examples indicate the types of 
facilities which DOT believes are interstate pipeline facilities subject 
to the HLPSA despite the lack of a filing with FERC and the types of 
facilities over which DOT will generally defer to the jurisdiction of a 
certifying state despite the existence of a filing with FERC.

    Example 1. Pipeline company P operates a pipeline from ``Point A'' 
located in State X to ``Point B'' (also in X). The physical facilities 
never cross a state line and do not connect with any other pipeline 
which does cross a state line. Pipeline company P also operates another 
pipeline between ``Point C'' in State X and ``Point D'' in an adjoining 
State Y. Pipeline company P files a tariff with FERC for transportation 
from ``Point A'' to ``Point B'' as well as for transportation from 
``Point C'' to ``Point D.'' DOT will ignore filing for the line from 
``Point A'' to ``Point B'' and consider the line to be intrastate.
    Example 2. Same as in example 1 except that P does not file any 
tariffs with FERC. DOT will assume jurisdiction of the line between 
``Point C'' and ``Point D.''
    Example 3. Same as in example 1 except that P files its tariff for 
the line between ``Point C'' and ``Point D'' not only with FERC but also 
with State X. DOT will rely on the FERC filing as indication of 
interstate commerce.
    Example 4. Same as in example 1 except that the pipeline from 
``Point A'' to ``Point B'' (in State X) connects with a pipeline 
operated by another company transports liquid between ``Point B'' (in 
State X) and ``Point D'' (in State Y). DOT will rely on the FERC filing 
as indication of interstate commerce.
    Example 5. Same as in example 1 except that the line between ``Point 
C'' and ``Point D'' has a lateral line connected to it. The lateral is 
located entirely with State X. DOT will rely on the existence or non-
existence of a FERC filing covering transportation over that lateral as 
determinative of interstate commerce.
    Example 6. Same as in example 1 except that the certified agency in 
State X has brought an enforcement action (under the pipeline safety 
laws) against P because of its operation of the line between ``Point A'' 
and ``Point B''. P has successfully defended against the action on 
jurisdictional grounds. DOT will assume jurisdiction if necessary to 
avoid the anomaly of a pipeline subject to neither State or Federal 
safety enforcement. DOT's assertion of jurisdiction in such a case would 
be based on the gap in the state's enforcement authority rather than a 
DOT decision that the pipeline is an interstate pipeline facility.
    Example 7. Pipeline Company P operates a pipeline that originates on 
the Outer Continental Shelf. P does not file any tariff for that line 
with FERC. DOT will consider the pipeline to be an interstate pipeline 
facility.
    Example 8. Pipeline Company P is constructing a pipeline from 
``Point C'' (in State X) to ``Point D'' (in State Y). DOT will consider 
the pipeline to be an interstate pipeline facility.
    Example 9. Pipeline company P is constructing a pipeline from 
``Point C'' to ``Point E'' (both in State X) but intends to file tariffs 
with FERC in the transportation of hazardous liquid in interstate 
commerce. Assuming there is some connection to an interstate pipeline 
facility, DOT will consider this line to be an interstate pipeline 
facility.
    Example 10. Pipeline Company P has operated a pipeline subject to 
FERC economic regulation. Solely because of some statutory economic 
deregulation, that pipeline is no longer regulated by FERC. DOT will 
continue to consider that pipeline to be an interstate pipeline 
facility.

    As seen from the examples, the types of situations in which DOT will 
not defer to the FERC regulatory scheme are generally 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 15899, Apr. 23, 1985]



Sec. Appendix B to Part 195--Risk-Based Alternative to Pressure Testing 
           Older Hazardous Liquid and Carbon Dioxide Pipelines

                         Risk-Based Alternative

    This Appendix provides guidance on how a risk-based alternative to 
pressure testing older hazardous liquid and carbon dioxide pipelines 
rule allowed by Sec. 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

[[Page 229]]

determine the classification based on the type of pipe or on the 
pipeline segment's proximity to populated or environmentally sensitive 
area. Secondly, the classifications must be adjusted based on the 
pipeline failure history, product transported, and the release volume 
potential.
    Tables 2-6 give definitions of risk classification A, B, and C 
facilities. For the purposes of this rule, pipeline segments containing 
high risk electric resistance-welded pipe (ERW pipe) and lapwelded pipe 
manufactured prior to 1970 and considered a risk classification C or B 
facility shall be treated as the top priority for testing because of the 
higher risk associated with the susceptibility of this pipe to 
longitudinal seam failures.
    In all cases, operators shall annually, at intervals not to exceed 
15 months, review their facilities to reassess the classification and 
shall take appropriate action within two years or operate the pipeline 
system at a lower pressure. Pipeline failures, changes in the 
characteristics of the pipeline route, or changes in service should all 
trigger a reassessment of the originally classification.
    Table 1 explains different levels of test requirements depending on 
the inherent risk of a given pipeline segment. The overall risk 
classification is determined based on the type of pipe involved, the 
facility's location, the product transported, the relative volume of 
flow and pipeline failure history as determined from Tables 2-6.

          Table 1. Test Requirements--Mainline Segments Outside of Terminals, Stations, and Tank Farms
----------------------------------------------------------------------------------------------------------------
         Pipeline segment           Risk classification           Test deadline \1\              Test medium
----------------------------------------------------------------------------------------------------------------
Pre-1970 Pipeline Segments         C or B                 12/7/2000 \3\...................  Water only.
 susceptible to longitudinal seam  A                      12/7/2002 \3\...................  Water only.
 failures \2\.
All Other Pipeline Segments......  C                      12/7/2002 \4\...................  Water only.
                                   B                      12/7/2004 \4\...................  Water/Liq. \5\
                                   A                      Additional pressure testing not
                                                           required.
----------------------------------------------------------------------------------------------------------------
\1\ If operational experience indicates a history of past failures for a particular pipeline segment, failure
  causes (time-dependent defects due to corrosion, construction, manufacture, or transmission problems, etc.)
  shall be reviewed in determining risk classification (See Table 6) and the timing of the pressure test should
  be accelerated.
\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
----------------------------------------------------------------------------------------------------------------
                                      Hazard location       Product/volume
       Risk classification               indicator             indicator        Probability of failure indicator
----------------------------------------------------------------------------------------------------------------
A................................  L or M..............  L/L.................  L.
B................................                          Not A or C Risk Classification
C................................  H...................  Any.................  Any.
----------------------------------------------------------------------------------------------------------------
H=High M=Moderate L=Low.
Note: For Location, Product, Volume, and Probability of Failure Indicators, see Tables 3, 4, 5, and 6.

    Table 3 is used to establish the LOCATION Indicator used in Table 2. 
Based on the population and environment characteristics associated with 
a pipeline facility's location, a LOCATION Indicator of H, M or L is 
selected.

[[Page 230]]



                                 Table 3--Location Indicators--Pipeline Segments
----------------------------------------------------------------------------------------------------------------
               Indicator                                  Population \1\                      Environment \2\
----------------------------------------------------------------------------------------------------------------
H......................................  Non-rural areas................................  Environmentally
                                                                                           sensitive \2\ areas.
M                                        ...............................................  ......................
L......................................  Rural areas....................................  Not environmentally
                                                                                           sensitive \2\ areas.
----------------------------------------------------------------------------------------------------------------
\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
------------------------------------------------------------------------
          Indicator              Considerations       Product examples
------------------------------------------------------------------------
H...........................  (Highly volatile and  (Propane, butane,
                               flammable).           Natural Gas Liquid
                                                     (NGL), ammonia)
                              Highly toxic........  (Benzene, high
                                                     Hydrogen Sulfide
                                                     content crude
                                                     oils).
M...........................  Flammable--flashpoin  (Gasoline, JP4, low
                               t <100F.              flashpoint crude
                                                     oils).
L...........................  Non-flammable--       (Diesel, fuel oil,
                               flashpoint 100+F.     kerosene, JP5, most
                                                     crude oils).
                              Highly volatile and   Carbon Dioxide.
                               non-flammable/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
------------------------------------------------------------------------
             Indicator                            Line size
------------------------------------------------------------------------
H.................................  =18.
M.................................  10-16 nominal
                                     diameters.
L.................................  <=8 nominal diameter.
------------------------------------------------------------------------
H=High M=Moderate L=Low.

    Table 6 is used to establish the PROBABILITY OF FAILURE Indicator 
used in Table 2. The ``Probability of Failure'' Indicator is selected 
from Table 6 as H or L.

               Table 6--Probability of Failure Indicators
                         [in each haz. location]
------------------------------------------------------------------------
                                       Failure history (time-dependent
             Indicator                          defects) \2\
------------------------------------------------------------------------
H \1\.............................  Three spills in last 10
                                     years.
L.................................  <=Three spills in last 10 years.
------------------------------------------------------------------------
H=High 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 59480, Nov. 4, 1998; 64 FR 6815, Feb. 11, 1999]



Sec. Appendix C to Part 195--Guidance for Implementation of an Integrity 
                           Management Program

    This Appendix gives guidance to help an operator implement the 
requirements of the integrity management program rule in Sec. Sec. 
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;

[[Page 231]]

    (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 Sec. 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 
Sec. Sec. 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 Sec. 
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 Sec. 
195.452(h).)

[[Page 232]]

    (3) Leak History. (See leak history risk table.)
    (4) Known corrosion or condition of pipeline. (See Sec. 
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 3\1/2\ years and the remaining segments 
within the seven-year period. For the continuing integrity assessments, 
we would plan to assess the C segments within the first two (2) years of 
the schedule, the segments classified as moderate risk no later than 
year three or four and the remaining lowest risk segments no later than 
year five (5).
    ii. For our hypothetical pipeline segment, we have chosen the 
following risk factors and obtained risk factor values from the 
appropriate table. The values assigned to the risk factors are for 
illustration only.

Age of pipeline: assume 30 years old (refer to ``Age of Pipeline'' risk 
table)--
Risk Value=5
Pressure tested: tested once during construction--
Risk Value=5
Coated: (yes/no)--yes
Coating Condition: Recent excavation of suspected areas showed holidays 
in coating (potential corrosion risk)--
Risk Value=5
Cathodically Protected: (yes/no)--yes--Risk Value=1
Date cathodic protection installed: five years after pipeline was 
constructed (Cathodic protection installed within one year of the 
pipeline's construction is generally considered low risk.)--Risk Value=3
Close interval survey: (yes/no)--no--Risk Value =5
Internal Inspection tool used: (yes/no)--yes. Date of pig run? In last 
five years--Risk Value=1
Anomalies found: (yes/no)--yes, but do not pose an immediate safety risk 
or environmental hazard--Risk Value=3
Leak History: yes, one spill in last 10 years. (refer to ``Leak 
History'' risk table)--Risk Value=2
Product transported: Diesel fuel. Product low risk. (refer to 
``Product'' risk table)--Risk Value=1
Pipe size: 16 inches. Size presents moderate risk (refer to ``Line 
Size'' risk table)--Risk Value=3
    iii. Overall risk value for this hypothetical segment of pipe is 34. 
Assume we have two other pipeline segments for which we conduct similar 
risk rankings. The second pipeline segment has an overall risk value of 
20, and the third segment, 11. For the baseline assessment we would 
establish a schedule where we assess the first segment (highest risk 
segment) within two years, the second segment within five years and the 
third segment within seven years. Similarly, for the continuing 
integrity assessment, we could establish an assessment schedule where we 
assess the highest risk segment no later than the second year, the 
second segment no later than the third year, and the third segment no 
later than the fifth year.

[[Page 233]]

    III. Safety risk indicator tables for leak history, volume or line 
size, age of pipeline, and product transported.

                              Leak History
------------------------------------------------------------------------
                                           Leak history  (Time-dependent
         Safety risk  indicator                    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
------------------------------------------------------------------------
         Safety risk  indicator                      Line size
------------------------------------------------------------------------
High....................................  = 18'
Moderate................................  10'--16' nominal diameters
Low.....................................  <= 8' nominal diameter
------------------------------------------------------------------------


                             Age of Pipeline
------------------------------------------------------------------------
                                              Age Pipeline condition
         Safety risk  indicator                   dependent) \1\
------------------------------------------------------------------------
High....................................   25 years
Low.....................................  < 25 years
------------------------------------------------------------------------
\1\ Depends on pipeline's coating & corrosion condition, and steel
  quality, toughness, welding.


                           Product Transported
------------------------------------------------------------------------
     Safety risk  indicator       Considerations \1\   Product examples
------------------------------------------------------------------------
High............................  (Highly volatile    (Propane, butane,
                                   and flammable).     Natural Gas
                                                       Liquid (NGL),
                                                       ammonia).
                                  Highly toxic......  (Benzene, high
                                                       Hydrogen Sulfide
                                                       content crude
                                                       oils).
Medium..........................  Flammable--flashpo  (Gasoline, JP4,
                                   int <100F.          low flashpoint
                                                       crude oils).
Low.............................  Non-flammable--     (Diesel, fuel oil,
                                   flashpoint 100+F.   kerosene, 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

[[Page 234]]

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 
Sec. 195.452(l)). This section provides examples of some records that 
an operator would have to maintain for inspection to comply with the 
requirement. This is not an exhaustive list.
    (1) a process for identifying which pipelines could affect a high 
consequence area and a document identifying all pipeline segments that 
could affect a high consequence area;
    (2) a plan for baseline assessment of the line pipe that includes 
each required plan element;
    (3) modifications to the baseline plan and reasons for the 
modification;
    (4) use of and support for an alternative practice;
    (5) a framework addressing each required element of the integrity 
management program, updates and changes to the initial framework and 
eventual program;
    (6) a process for identifying a new high consequence area and 
incorporating it into the baseline plan, particularly, a process for 
identifying population changes around a pipeline segment;
    (7) an explanation of methods selected to assess the integrity of 
line pipe;
    (8) a process for review of integrity assessment results and data 
analysis by a person qualified to evaluate the results and data;
    (9) the process and risk factors for determining the baseline 
assessment interval;
    (10) results of the baseline integrity assessment;
    (11) the process used for continual evaluation, and risk factors 
used for determining the frequency of evaluation;
    (12) process for integrating and analyzing information about the 
integrity of a pipeline, information and data used for the information 
analysis;
    (13) results of the information analyses and periodic evaluations;
    (14) the process and risk factors for establishing continual re-
assessment intervals;
    (15) justification to support any variance from the required re-
assessment intervals;
    (16) integrity assessment results and anomalies found, process for 
evaluating and remediating anomalies, criteria for remedial actions and 
actions taken to evaluate and remediate the anomalies;
    (17) other remedial actions planned or taken;
    (18) schedule for evaluation and remediation of anomalies, 
justification to support deviation from required remediation times;
    (19) risk analysis used to identify additional preventive or 
mitigative measures, records of preventive and mitigative actions 
planned or taken;
    (20) criteria for determining EFRD installation;
    (21) criteria for evaluating and modifying leak detection 
capability;
    (22) methods used to measure the program's effectiveness.
    VII. Conditions that may impair a pipeline's integrity.
    Section 195.452(h) requires an operator to evaluate and remediate 
all pipeline integrity issues raised by the integrity assessment or 
information analysis. An operator must develop a schedule that 
prioritizes conditions discovered on the pipeline for evaluation and

[[Page 235]]

remediation. The following are some examples of conditions that an 
operator should schedule for evaluation and remediation.
    A. Any change since the previous assessment.
    B. Mechanical damage that is located on the top side of the pipe.
    C. An anomaly abrupt in nature.
    D. An anomaly longitudinal in orientation.
    E. An anomaly over a large area.
    F. An anomaly located in or near a casing, a crossing of another 
pipeline, or an area with suspect cathodic protection.

[Amdt. 195-70, 65 FR 75409, Dec. 1, 2000, as amended by Amdt. 195-74, 67 
FR 1661, Jan. 14, 2002]

                        PARTS 196	197 [RESERVED]



PART 198_REGULATIONS FOR GRANTS TO AID STATE PIPELINE SAFETY PROGRAMS--
Table of Contents




                            Subpart A_General

Sec.
198.1 Scope.
198.3 Definitions.

                       Subpart B_Grant Allocation

198.11 Grant authority.
198.13 Grant allocation formula.

        Subpart C_Adoption of One-Call Damage Prevention Program

198.31 Scope.
198.33 [Reserved]
198.35 Grants conditioned on adoption of one-call damage prevention 
          program.
198.37 State one-call damage prevention program.
198.39 Qualifications for operation of one-call notification system.

    Authority: 49 U.S.C. 60105, 60106, 60114; and 49 CFR 1.53.

    Source: 55 FR 38691, Sept. 20, 1990, unless otherwise noted.



                            Subpart A_General



Sec. 198.1  Scope.

    This part prescribes regulations governing grants-in-aid for State 
pipeline safety compliance programs.



Sec. 198.3  Definitions.

    As used in this part:
    Administrator means the Administrator, Pipeline and Hazardous 
Materials Safety Administration or his or her delegate.
    Adopt means establish under State law by statute, regulation, 
license, certification, order, or any combination of these legal means.
    Excavation activity means an excavation activity defined in Sec. 
192.614(a) of this chapter, other than a specific activity the State 
determines would not be expected to cause physical damage to underground 
facilities.
    Excavator means any person intending to engage in an excavation 
activity.
    One-call notification system means a communication system that 
qualifies under this part and the one-call damage prevention program of 
the State concerned in which an operational center receives notices from 
excavators of intended excavation activities and transmits the notices 
to operators of underground pipeline facilities and other underground 
facilities that participate in the system.
    Person means any individual, firm, joint venture, partnership, 
corporation, association, state, municipality, cooperative association, 
or joint stock association, and including any trustee, receiver, 
assignee, or personal representative thereof.
    Underground pipeline facilities means buried pipeline facilities 
used in the transportation of gas or hazardous liquid subject to the 
pipeline safety laws (49 U.S.C. 60101 et seq.).
    Secretary means the Secretary of Transportation or any person to 
whom the Secretary of Transportation has delegated authority in the 
matter concerned.
    Seeking to adopt means actively and effectively proceeding toward 
adoption.
    State means each of the several States, the District of Columbia, 
and the Commonwealth of Puerto Rico.

[55 FR 38691, Sept. 20, 1990, as amended by Amdt. 198-2, 61 FR 18518, 
Apr. 26, 1996; 68 FR 11750, Mar. 12, 2003; 70 FR 11140, Mar. 8, 2005]



                       Subpart B_Grant Allocation

    Source: Amdt. 198-1, 58 FR 10988, Feb. 23, 1993, unless otherwise 
noted.

[[Page 236]]



Sec. 198.11  Grant authority.

    The pipeline safety laws (49 U.S.C. 60101 et seq.) authorize the 
Administrator to pay out funds appropriated or otherwise make available 
up to 50 percent of the cost of the personnel, equipment, and activities 
reasonably required for each state agency to carry out a safety program 
for intrastate pipeline facilities under a certification or agreement 
with the Administrator or to act as an agent of the Administrator with 
respect to interstate pipeline facilities.

[Amdt. 198-2, 61 FR 18518, Apr. 26, 1996]



Sec. 198.13  Grant allocation formula.

    (a) Beginning in calendar year 1993, the Administrator places 
increasing emphasis on program performance in allocating state agency 
funds under Sec. 198.11. The maximum percent of each state agency 
allocation that is based on performance follows: 1993--75 percent; 1994 
and subsequent years--100 percent.
    (b) A state's annual grant allocation is based on maximum of 100 
performance points derived as follows:
    (1) Fifty points based on information provided in the state's annual 
certification/agreement attachments which document its activities for 
the past year; and
    (2) Fifty points based on the annual state program evaluation.
    (c) The Administrator assigns weights to various performance factors 
reflecting program compliance, safety priorities, and national concerns 
identified by the Administrator and communicated to each State agency. 
At a minimum, the Administrator considers the following performance 
factors in allocating funds:
    (1) Adequacy of state operating practices;
    (2) Quality of state inspections, investigations, and enforcement/
compliance actions;
    (3) Adequacy of state recordkeeping;
    (4) Extent of state safety regulatory jurisdiction over pipeline 
facilities;
    (5) Qualifications of state inspectors;
    (6) Number of state inspection person-days;
    (7) State adoption of applicable federal pipeline safety standards; 
and
    (8) Any other factor the Administrator deems necessary to measure 
performance.
    (d) Notwithstanding these performance factors, the Administrator 
may, in 1993 and subsequent years, continue funding any state at the 
1991 level, provided its request is at the 1991 level or higher and 
appropriated funds are at the 1991 level or higher.
    (e) The Administrator notifies each state agency in writing of the 
specific performance factors to be used and the weights to be assigned 
to each factor at least 9 months prior to allocating funds. Prior to 
notification, PHMSA seeks state agency comments on any proposed changes 
to the allocation formula.
    (f) Grants are limited to the appropriated funds available. If total 
state agency requests for grants exceed the funds available, the 
Administrator prorates each state agency's allocation.

[Amdt. 198-1, 58 FR 10988, Feb. 23, 1993, as amended at 70 FR 11140, 
Mar. 8, 2005]



        Subpart C_Adoption of One-Call Damage Prevention Program



Sec. 198.31  Scope.

    This subpart implements parts of the pipeline safety laws (49 U.S.C. 
60101 et seq.), which direct the Secretary to require each State to 
adopt a one-call damage prevention program as a condition to receiving a 
full grant-in-aid for its pipeline safety compliance program.

[Amdt. 198-2, 61 FR 18518, Apr. 26, 1996]



Sec. 198.33  [Reserved]



Sec. 198.35  Grants conditioned on adoption of one-call damage prevention
program.

    In allocating grants to State agencies under the pipeline safety 
laws, (49 U.S.C. 60101 et seq.), the Secretary considers whether a State 
has adopted or is seeking to adopt a one-call damage prevention program 
in accordance with Sec. 198.37. If a State has not adopted or is not 
seeking to adopt such program, the State agency may not receive the full 
reimbursement to which it would otherwise be entitled.

[Amdt. 198-2, 61 FR 38403, July 24, 1996]

[[Page 237]]



Sec. 198.37  State one-call damage prevention program.

    A State must adopt a one-call damage prevention program that 
requires each of the following at a minimum:
    (a) Each area of the State that contains underground pipeline 
facilities must be covered by a one-call notification system.
    (b) Each one-call notification system must be operated in accordance 
with Sec. 198.39.
    (c) Excavators must be required to notify the operational center of 
the one-call notification system that covers the area of each intended 
excavation activity and provide the following information:
    (1) Name of the person notifying the system.
    (2) Name, address and telephone number of the excavator.
    (3) Specific location, starting date, and description of the 
intended excavation activity.

However, an excavator must be allowed to begin an excavation activity in 
an emergency but, in doing so, required to notify the operational center 
at the earliest practicable moment.
    (d) The State must determine whether telephonic and other 
communications to the operational center of a one-call notification 
system under paragraph (c) of this section are to be toll free or not.
    (e) Except with respect to interstate transmission facilities as 
defined in the pipeline safety laws (49 U.S.C. 60101 et seq.), operators 
of underground pipeline facilities must be required to participate in 
the one-call notification systems that cover the areas of the State in 
which those pipeline facilities are located.
    (f) Operators of underground pipeline facilities participating in 
the one-call notification systems must be required to respond in the 
manner prescribed by Sec. 192.614 (b)(4) through (b)(6) of this chapter 
to notices of intended excavation activity received from the operational 
center of a one-call notification system.
    (g) Persons who operate one-call notification systems or operators 
of underground pipeline facilities participating or required to 
participate in the one-call notification systems must be required to 
notify the public and known excavators in the manner prescribed by Sec. 
192.614 (b)(1) and (b)(2) of this chapter of the availability and use of 
one-call notification systems to locate underground pipeline facilities. 
However, this paragraph does not apply to persons (including operator's 
master meters) whose primary activity does not include the production, 
transportation or marketing of gas or hazardous liquids.
    (h) Operators of underground pipeline facilities (other than 
operators of interstate transmission facilities as defined in the 
pipeline safety laws (49 U.S.C. 60101 et seq.), and interstate pipelines 
as defined in Sec. 195.2 of this chapter), excavators and persons who 
operate one-call notification systems who violate the applicable 
requirements of this subpart must be subject to civil penalties and 
injunctive relief that are substantially the same as are provided under 
the pipeline safety laws (49 U.S.C. 60101 et seq.).

[55 FR 38691, Sept. 20, 1990, as amended by Amdt. 198-2, 61 FR 18518, 
Apr. 26, 1996]



Sec. 198.39  Qualifications for operation of one-call notification 
system.

    A one-call notification system qualifies to operate under this 
subpart if it complies with the following:
    (a) It is operated by one or more of the following:
    (1) A person who operates underground pipeline facilities or other 
underground facilities.
    (2) A private contractor.
    (3) A State or local government agency.
    (4) A person who is otherwise eligible under State law to operate a 
one-call notification system.
    (b) It receives and records information from excavators about 
intended excavation activities.
    (c) It promptly transmits to the appropriate operators of 
underground pipeline facilities the information received from excavators 
about intended excavation activities.
    (d) It maintains a record of each notice of intent to engage in an 
excavation activity for the minimum time set by the State or, in the 
absence of such time, for the time specified in the

[[Page 238]]

applicable State statute of limitations on tort actions.
    (e) It tells persons giving notice of an intent to engage in an 
excavation activity the names of participating operators of underground 
pipeline facilities to whom the notice will be transmitted.



PART 199_DRUG AND ALCOHOL TESTING--Table of Contents




                            Subpart A_General

Sec.
199.1 Scope.
199.2 Applicability.
199.3 Definitions.
199.5 DOT procedures.
199.7 Stand-down waivers.
199.9 Preemption of State and local laws.

                         Subpart B_Drug Testing

199.100 Purpose.
199.101 Anti-drug plan.
199.103 Use of persons who fail or refuse a drug test.
199.105 Drug tests required.
199.107 Drug testing laboratory.
199.109 Review of drug testing results.
199.111 Retention of samples and additional testing.
199.113 Employee assistance program.
199.115 Contractor employees.
199.117 Recordkeeping.
199.119 Reporting of anti-drug testing results.

               Subpart C_Alcohol Misuse Prevention Program

199.200 Purpose.
199.201 [Reserved]
199.202 Alcohol misuse plan.
199.203-199.205 [Reserved]
199.209 Other requirements imposed by operators.
199.211 Requirement for notice.
199.213 [Reserved]
199.215 Alcohol concentration.
199.217 On-duty use.
199.219 Pre-duty use.
199.221 Use following an accident.
199.223 Refusal to submit to a required alcohol test.
199.225 Alcohol tests required.
199.227 Retention of records.
199.229 Reporting of alcohol testing results.
199.231 Access to facilities and records.
199.233 Removal from covered function.
199.235 Required evaluation and testing.
199.237 Other alcohol-related conduct.
199.239 Operator obligation to promulgate a policy on the misuse of 
          alcohol.
199.241 Training for supervisors.
199.243 Referral, evaluation, and treatment.
199.245 Contractor employees.

    Authority: 49 U.S.C. 5103, 60102, 60104, 60108, 60117, and 60118; 49 
CFR 1.53.

    Source: 53 FR 47096, Nov. 21, 1988, unless otherwise noted.



                            Subpart A_General



Sec. 199.1  Scope.

    This part requires operators of pipeline facilities subject to part 
192, 193, or 195 of this chapter to test covered employees for the 
presence of prohibited drugs and alcohol.

[Amdt. 199-19, 66 FR 47117, Sept. 11, 2001]



Sec. 199.2  Applicability.

    (a) This part applies to pipeline operators only with respect to 
employees located within the territory of the United States, including 
those employees located within the limits of the ``Outer Continental 
Shelf `` as that term is defined in the Outer Continental Shelf Lands 
Act (43 U.S.C. 1331).
    (b) This part does not apply to any person for whom compliance with 
this part would violate the domestic laws or policies of another 
country.
    (c) This part does not apply to covered functions performed on--
    (1) Master meter systems, as defined in Sec. 191.3 of this chapter; 
or
    (2) Pipeline systems that transport only petroleum gas or petroleum 
gas/air mixtures.

[Amdt. 199-19, 66 FR 47117, Sept. 11, 2001]



Sec. 199.3  Definitions.

    As used in this part--
    Accident means an incident reportable under part 191 of this chapter 
involving gas pipeline facilities or LNG facilities, or an accident 
reportable under part 195 of this chapter involving hazardous liquid 
pipeline facilities.
    Administrator means the Administrator, Pipeline and Hazardous 
Materials Safety Administration or his or her delegate.
    Covered employee, employee, or individual to be tested means a 
person who performs a covered function, including persons employed by 
operators, contractors engaged by operators, and persons employed by 
such contractors.

[[Page 239]]

    Covered function means an operations, maintenance, or emergency-
response function regulated by part 192, 193, or 195 of this chapter 
that is performed on a pipeline or on an LNG facility.
    DOT Procedures means the Procedures for Transportation Workplace 
Drug and Alcohol Testing Programs published by the Office of the 
Secretary of Transportation in part 40 of this title.
    Fail a drug test means that the confirmation test result shows 
positive evidence of the presence under DOT Procedures of a prohibited 
drug in an employee's system.
    Operator means a person who owns or operates pipeline facilities 
subject to part 192, 193, or 195 of this chapter.
    Pass a drug test means that initial testing or confirmation testing 
under DOT Procedures does not show evidence of the presence of a 
prohibited drug in a person's system.
    Performs a covered function includes actually performing, ready to 
perform, or immediately available to perform a covered function.
    Positive rate for random drug testing means the number of verified 
positive results for random drug tests conducted under this part plus 
the number of refusals of random drug tests required by this part, 
divided by the total number of random drug tests results (i.e., 
positives, negatives, and refusals) under this part.
    Prohibited drug means any of the following substances specified in 
Schedule I or Schedule II of the Controlled Substances Act (21 U.S.C. 
812): marijuana, cocaine, opiates, amphetamines, and phencyclidine 
(PCP).
    Refuse to submit, refuse, or refuse to take means behavior 
consistent with DOT Procedures concerning refusal to take a drug test or 
refusal to take an alcohol test.
    State agency means an agency of any of the several states, the 
District of Columbia, or Puerto Rico that participates under the 
pipeline safety laws (49 U.S.C. 60101 et seq.)

[53 FR 47096, Nov. 21, 1988, as amended by Amdt. 199-2, 54 FR 51850, 
Dec. 18, 1989; 59 FR 62227, Dec. 2, 1994; Amdt. 199-13, 61 FR 18518, 
Apr. 26, 1996; Amdt. 199-15, 63 FR 13000, Mar. 17, 1998; Amdt. 199-19, 
66 FR 47117, Sept. 11, 2001; 68 FR 11750, Mar. 12, 2003; 68 FR 75465, 
Dec. 31, 2003; 70 FR 11140, Mar. 8, 2005]



Sec. 199.5  DOT procedures.

    The anti-drug and alcohol programs required by this part must be 
conducted according to the requirements of this part and DOT Procedures. 
Terms and concepts used in this part have the same meaning as in DOT 
Procedures. Violations of DOT Procedures with respect to anti-drug and 
alcohol programs required by this part are violations of this part.

[Amdt. 199-19, 66 FR 47118, Sept. 11, 2001]



Sec. 199.7  Stand-down waivers.

    (a) Each operator who seeks a waiver under Sec. 40.21 of this title 
from the stand-down restriction must submit an application for waiver in 
duplicate to the Associate Administrator for Pipeline Safety, Pipeline 
and Hazardous Materials Safety Administration, U.S. Department of 
Transportation, 1200 New Jersey Avenue, SE, Washington, DC 20590-0001.
    (b) Each application must--
    (1) Identify Sec. 40.21 of this title as the rule from which the 
waiver is sought;
    (2) Explain why the waiver is requested and describe the employees 
to be covered by the waiver;
    (3) Contain the information required by Sec. 40.21 of this title 
and any other information or arguments available to support the waiver 
requested; and
    (4) Unless good cause is shown in the application, be submitted at 
least 60 days before the proposed effective date of the waiver.
    (c) No public hearing or other proceeding is held directly on an 
application before its disposition under this section. If the Associate 
Administrator determines that the application contains adequate 
justification, he or she grants the waiver. If the Associate 
Administrator determines that the application does not justify granting 
the

[[Page 240]]

waiver, he or she denies the application. The Associate Administrator 
notifies each applicant of the decision to grant or deny an application.

[Amdt. 199-19, 66 FR 47118, Sept. 11, 2001, as amended at 70 FR 11140, 
Mar. 8, 2005; 74 FR 2894, Jan. 16, 2009]



Sec. 199.9  Preemption of State and local laws.

    (a) Except as provided in paragraph (b) of this section, this part 
preempts any State or local law, rule, regulation, or order to the 
extent that:
    (1) Compliance with both the State or local requirement and this 
part is not possible;
    (2) Compliance with the State or local requirement is an obstacle to 
the accomplishment and execution of any requirement in this part; or
    (3) The State or local requirement is a pipeline safety standard 
applicable to interstate pipeline facilities.
    (b) This part shall not be construed to preempt provisions of State 
criminal law that impose sanctions for reckless conduct leading to 
actual loss of life, injury, or damage to property, whether the 
provisions apply specifically to transportation employees or employers 
or to the general public.

[Amdt. 199-9, 59 FR 7430, Feb. 15, 1994. Redesignated and amended by 
Amdt. 199-19, 66 FR 47119, Sept. 11, 2001]



                         Subpart B_Drug Testing



Sec. 199.100  Purpose.

    The purpose of this subpart is to establish programs designed to 
help prevent accidents and injuries resulting from the use of prohibited 
drugs by employees who perform covered functions for operators of 
certain pipeline facilities subject to part 192, 193, or 195 of this 
chapter.

[Amdt. 199-19, 66 FR 47118, Sept. 11, 2001]



Sec. 199.101  Anti-drug plan.

    (a) Each operator shall maintain and follow a written anti-drug plan 
that conforms to the requirements of this part and the DOT Procedures. 
The plan must contain--
    (1) Methods and procedures for compliance with all the requirements 
of this part, including the employee assistance program;
    (2) The name and address of each laboratory that analyzes the 
specimens collected for drug testing;
    (3) The name and address of the operator's Medical Review Officer, 
and Substance Abuse Professional; and
    (4) Procedures for notifying employees of the coverage and 
provisions of the plan.
    (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.

[53 FR 47096, Nov. 21, 1988, as amended by Amdt. 199-2, 54 FR 51850, 
Dec. 18, 1989; Amdt. 199-4, 56 FR 31091, July 9, 1991; 56 FR 41077, Aug. 
19, 1991; Amdt. 199-13, 61 FR 18518, Apr. 26, 1996; Amdt. 199-15, 63 FR 
36863, July 8, 1998. Redesignated by Amdt. 199-19, 66 FR 47118, Sept. 
11, 2001]



Sec. 199.103  Use of persons who fail or refuse a drug test.

    (a) An operator may not knowingly use as an employee any person 
who--
    (1) Fails a drug test required by this part and the medical review 
officer makes a determination under DOT Procedures; or
    (2) Refuses to take a drug test required by this part.
    (b) Paragraph (a)(1) of this section does not apply to a person who 
has--
    (1) Passed a drug test under DOT Procedures;
    (2) Been considered by the medical review officer in accordance with 
DOT Procedures and been determined by a substance abuse professional to 
have successfully completed required education or treatment; and
    (3) Not failed a drug test required by this part after returning to 
duty.

[53 FR 47096, Nov. 21, 1988, as amended by Amdt. 199-2, 54 FR 51850, 
Dec. 18, 1989. Redesignated and amended by Amdt. 199-19, 66 FR 47118, 
Sept. 11, 2001]

[[Page 241]]



Sec. 199.105  Drug tests required.

    Each operator shall conduct the following drug tests for the 
presence of a prohibited drug:
    (a) Pre-employment testing. No operator may hire or contract for the 
use of any person as an employee unless that person passes a drug test 
or is covered by an anti-drug program that conforms to the requirements 
of this part.
    (b) Post-accident testing. As soon as possible but no later than 32 
hours after an accident, an operator shall drug test each employee whose 
performance either contributed to the accident or cannot be completely 
discounted as a contributing factor to the accident. An operator may 
decide not to test under this paragraph but such a decision must be 
based on the best information available immediately after the accident 
that the employee's performance could not have contributed to the 
accident or that, because of the time between that performance and the 
accident, it is not likely that a drug test would reveal whether the 
performance was affected by drug use.
    (c) Random testing. (1) Except as provided in paragraphs (c)(2) 
through (4) of this section, the minimum annual percentage rate for 
random drug testing shall be 50 percent of covered employees.
    (2) The Administrator's decision to increase or decrease the minimum 
annual percentage rate for random drug testing is based on the reported 
positive rate for the entire industry. All information used for this 
determination is drawn from the drug MIS reports required by this 
subpart. In order to ensure reliability of the data, the Administrator 
considers the quality and completeness of the reported data, may obtain 
additional information or reports from operators, and may make 
appropriate modifications in calculating the industry positive rate. 
Each year, the Administrator will publish in the Federal Register the 
minimum annual percentage rate for random drug testing of covered 
employees. The new minimum annual percentage rate for random drug 
testing will be applicable starting January 1 of the calendar year 
following publication.
    (3) When the minimum annual percentage rate for random drug testing 
is 50 percent, the Administrator may lower this rate to 25 percent of 
all covered employees if the Administrator determines that the data 
received under the reporting requirements of Sec. 199.119 for two 
consecutive calendar years indicate that the reported positive rate is 
less than 1.0 percent.
    (4) When the minimum annual percentage rate for random drug testing 
is 25 percent, and the data received under the reporting requirements of 
Sec. 199.119 for any calendar year indicate that the reported positive 
rate is equal to or greater than 1.0 percent, the Administrator will 
increase the minimum annual percentage rate for random drug testing to 
50 percent of all covered employees.
    (5) The selection of employees for random drug testing shall be made 
by a scientifically valid method, such as a random number table or a 
computer-based random number generator that is matched with employees' 
Social Security numbers, payroll identification numbers, or other 
comparable identifying numbers. Under the selection process used, each 
covered employee shall have an equal chance of being tested each time 
selections are made.
    (6) The operator shall randomly select a sufficient number of 
covered employees for testing during each calendar year to equal an 
annual rate not less than the minimum annual percentage rate for random 
drug testing determined by the Administrator. If the operator conducts 
random drug testing through a consortium, the number of employees to be 
tested may be calculated for each individual operator or may be based on 
the total number of covered employees covered by the consortium who are 
subject to random drug testing at the same minimum annual percentage 
rate under this subpart or any DOT drug testing rule.
    (7) Each operator shall ensure that random drug tests conducted 
under this subpart are unannounced and that the dates for administering 
random tests are spread reasonably throughout the calendar year.
    (8) If a given covered employee is subject to random drug testing 
under the drug testing rules of more than one DOT agency for the same 
operator, the employee shall be subject to random

[[Page 242]]

drug testing at the percentage rate established for the calendar year by 
the DOT agency regulating more than 50 percent of the employee's 
function.
    (9) If an operator is required to conduct random drug testing under 
the drug testing rules of more than one DOT agency, the operator may--
    (i) Establish separate pools for random selection, with each pool 
containing the covered employees who are subject to testing at the same 
required rate; or
    (ii) Randomly select such employees for testing at the highest 
percentage rate established for the calendar year by any DOT agency to 
which the operator is subject.
    (d) Testing based on reasonable cause. Each operator shall drug test 
each employee when there is reasonable cause to believe the employee is 
using a prohibited drug. The decision to test must be based on a 
reasonable and articulable belief that the employee is using a 
prohibited drug on the basis of specific, contemporaneous physical, 
behavioral, or performance indicators of probable drug use. At least two 
of the employee's supervisors, one of whom is trained in detection of 
the possible symptoms of drug use, shall substantiate and concur in the 
decision to test an employee. The concurrence between the two 
supervisors may be by telephone. However, in the case of operators with 
50 or fewer employees subject to testing under this part, only one 
supervisor of the employee trained in detecting possible drug use 
symptoms shall substantiate the decision to test.
    (e) Return-to-duty testing. A covered employee who refuses to take 
or has a positive drug test may not return to duty in the covered 
function until the covered employee has complied with applicable 
provisions of DOT Procedures concerning substance abuse professionals 
and the return-to-duty process.
    (f) Follow-up testing. A covered employee who refuses to take or has 
a positive drug test shall be subject to unannounced follow-up drug 
tests administered by the operator following the covered employee's 
return to duty. The number and frequency of such follow-up testing shall 
be determined by a substance abuse professional, but shall consist of at 
least six tests in the first 12 months following the covered employee's 
return to duty. In addition, follow-up testing may include testing for 
alcohol as directed by the substance abuse professional, to be performed 
in accordance with 49 CFR part 40. Follow-up testing shall not exceed 60 
months from the date of the covered employee's return to duty. The 
substance abuse professional may terminate the requirement for follow-up 
testing at any time after the first six tests have been administered, if 
the substance abuse professional determines that such testing is no 
longer necessary.

[53 FR 47096, Nov. 21, 1988, as amended by Amdt. 199-2, 54 FR 51850, 
Dec. 18, 1989; 59 FR 62227, Dec. 2, 1994; Amdt. 199-15, 63 FR 13000, 
Mar. 17, 1998; Amdt 199-15, 63 FR 36863, July 8, 1998. Redesignated and 
amended by Amdt. 199-19, 66 FR 47118, Sept. 11, 2001]



Sec. 199.107  Drug testing laboratory.

    (a) Each operator shall use for the drug testing required by this 
part only drug testing laboratories certified by the Department of 
Health and Human Services under the DOT Procedures.
    (b) The drug testing laboratory must permit--
    (1) Inspections by the operator before the laboratory is awarded a 
testing contract; and
    (2) Unannounced inspections, including examination of records, at 
any time, by the operator, the Administrator, and if the operator is 
subject to state agency jurisdiction, a representative of that state 
agency.

[53 FR 47096, Nov. 21, 1988. Redesignated by Amdt. 199-19, 66 FR 47118, 
Sept. 11, 2001]



Sec. 199.109  Review of drug testing results.

    (a) MRO appointment. Each operator shall designate or appoint a 
medical review officer (MRO). If an operator does not have a qualified 
individual on staff to serve as MRO, the operator may contract for the 
provision of MRO services as part of its anti-drug program.
    (b) MRO qualifications. Each MRO must be a licensed physician who 
has the qualifications required by DOT Procedures.

[[Page 243]]

    (c) MRO duties. The MRO must perform functions for the operator as 
required by DOT Procedures.
    (d) MRO reports. The MRO must report all drug test results to the 
operator in accordance with DOT Procedures.
    (e) Evaluation and rehabilitation may be provided by the operator, 
by a substance abuse professional under contract with the operator, or 
by a substance abuse professional not affiliated with the operator. The 
choice of substance abuse professional and assignment of costs shall be 
made in accordance with the operator/employee agreements and operator/
employee policies.
    (f) The operator shall ensure that a substance abuse professional, 
who determines that a covered employee requires assistance in resolving 
problems with drug abuse, does not refer the covered employee to the 
substance abuse professional's private practice or to a person or 
organization from which the substance abuse professional receives 
remuneration or in which the substance abuse professional has a 
financial interest. This paragraph does not prohibit a substance abuse 
professional from referring a covered employee for assistance provided 
through:
    (1) A public agency, such as a State, county, or municipality;
    (2) The operator or a person under contract to provide treatment for 
drug problems on behalf of the operator;
    (3) The sole source of therapeutically appropriate treatment under 
the employee's health insurance program; or
    (4) The sole source of therapeutically appropriate treatment 
reasonably accessible to the employee.

[53 FR 47096, Nov. 21, 1988, as amended by Amdt. 199-2, 54 FR 51850, 
Dec. 18, 1989; Amdt. 199-15, 63 FR 13000, Mar. 17, 1998; Amdt. 199-15, 
63 FR 36863, July 8, 1998. Redesignated and amended by Amdt. 199-19, 66 
FR 47118, Sept. 11, 2001]



Sec. 199.111  Retention of samples and additional testing.

    (a) Samples that yield positive results on confirmation must be 
retained by the laboratory in properly secured, long-term, frozen 
storage for at least 365 days as required by the DOT Procedures. Within 
this 365-day period, the employee or the employee's representative, the 
operator, the Administrator, or, if the operator is subject to the 
jurisdiction of a state agency, the state agency may request that the 
laboratory retain the sample for an additional period. If, within the 
365-day period, the laboratory has not received a proper written request 
to retain the sample for a further reasonable period specified in the 
request, the sample may be discarded following the end of the 365-day 
period.
    (b) If the medical review officer (MRO) determines there is no 
legitimate medical explanation for a confirmed positive test result 
other than the unauthorized use of a prohibited drug, and if timely 
additional testing is requested by the employee according to DOT 
Procedures, the split specimen must be tested. The employee may specify 
testing by the original laboratory or by a second laboratory that is 
certified by the Department of Health and Human Services. The operator 
may require the employee to pay in advance the cost of shipment (if any) 
and reanalysis of the sample, but the employee must be reimbursed for 
such expense if the additional test is negative.
    (c) If the employee specifies testing by a second laboratory, the 
original laboratory must follow approved chain-of-custody procedures in 
transferring a portion of the sample.
    (d) Since some analytes may deteriorate during storage, detected 
levels of the drug below the detection limits established in the DOT 
Procedures, but equal to or greater than the established sensitivity of 
the assay, must, as technically appropriate, be reported and considered 
corroborative of the original positive results.

[53 FR 47096, Nov. 21, 1988; 55 FR 797, Jan. 9, 1990, as amended by 
Amdt. 199-17, 63 FR 7723, Feb. 17, 1998. Redesignated and amended by 
Amdt. 199-19, 66 FR 47118, Sept. 11, 2001]



Sec. 199.113  Employee assistance program.

    (a) Each operator shall provide an employee assistance program (EAP) 
for its employees and supervisory personnel who will determine whether 
an employee must be drug tested based on reasonable cause. The operator 
may establish the EAP as a part of its internal personnel services or 
the operator

[[Page 244]]

may contract with an entity that provides EAP services. Each EAP must 
include education and training on drug use. At the discretion of the 
operator, the EAP may include an opportunity for employee 
rehabilitation.
    (b) Education under each EAP must include at least the following 
elements: display and distribution of informational material; display 
and distribution of a community service hot-line telephone number for 
employee assistance; and display and distribution of the employer's 
policy regarding the use of prohibited drugs.
    (c) Training under each EAP for supervisory personnel who will 
determine whether an employee must be drug tested based on reasonable 
cause must include one 60-minute period of training on the specific, 
contemporaneous physical, behavioral, and performance indicators of 
probable drug use.

[53 FR 47096, Nov. 21, 1988. Redesignated by Amdt. 199-19, 66 FR 47118, 
Sept. 11, 2001]



Sec. 199.115  Contractor employees.

    With respect to those employees who are contractors or employed by a 
contractor, an operator may provide by contract that the drug testing, 
education, and training required by this part be carried out by the 
contractor provided:
    (a) The operator remains responsible for ensuring that the 
requirements of this part are complied with; and
    (b) The contractor allows access to property and records by the 
operator, the Administrator, and if the operator is subject to the 
jurisdiction of a state agency, a representative of the state agency for 
the purpose of monitoring the operator's compliance with the 
requirements of this part.

[53 FR 47096, Nov. 21, 1988. Redesignated by Amdt. 199-19, 66 FR 47118, 
Sept. 11, 2001]



Sec. 199.117  Recordkeeping.

    (a) Each operator shall keep the following records for the periods 
specified and permit access to the records as provided by paragraph (b) 
of this section:
    (1) Records that demonstrate the collection process conforms to this 
part must be kept for at least 3 years.
    (2) Records of employee drug test that indicate a verified positive 
result, records that demonstrate compliance with the recommendations of 
a substance abuse professional, and MIS annual report data shall be 
maintained for a minimum of five years.
    (3) Records of employee drug test results that show employees passed 
a drug test must be kept for at least 1 year.
    (4) Records confirming that supervisors and employees have been 
trained as required by this part must be kept for at least 3 years.
    (b) Information regarding an individual's drug testing results or 
rehabilitation must be released upon the written consent of the 
individual and as provided by DOT Procedures. Statistical data related 
to drug testing and rehabilitation that is not name-specific and 
training records must be made available to the Administrator or the 
representative of a state agency upon request.

[53 FR 47096, Nov. 21, 1988, as amended at 58 FR 68260, Dec. 23, 1993. 
Redesignated and amended by Amdt. 199-19, 66 FR 47119, Sept. 11, 2001; 
68 FR 75465, Dec. 31, 2003]



Sec. 199.119  Reporting of anti-drug testing results.

    (a) Each large operator (having more than 50 covered employees) 
shall submit an annual MIS report to PHMSA of its anti-drug testing 
using the Management Information System (MIS) form and instructions as 
required by 49 CFR part 40 (at Sec. 40.25 and appendix H to Part 40), 
not later than March 15 of each year for the prior calendar year 
(January 1 through December 31). The Administrator shall require by 
written notice that small operators (50 or fewer covered employees) not 
otherwise required to submit annual MIS reports to prepare and submit 
such reports to PHMSA.
    (b) Each report required under this section shall be submitted to 
the Office of Pipeline Safety, Pipeline and Hazardous Materials Safety 
Administration, U.S. Department of Transportation, PHP-60, 1200 New 
Jersey Avenue, SE., Washington, DC 20590.
    (c) To calculate the total number of covered employees eligible for 
random

[[Page 245]]

testing throughout the year, as an operator, you must add the total 
number of covered employees eligible for testing during each random 
testing period for the year and divide that total by the number of 
random testing periods. Covered employees, and only covered employees, 
are to be in an employer's random testing pool, and all covered 
employees must be in the random pool. If you are an employer conducting 
random testing more often than once per month (e.g., you select daily, 
weekly, bi-weekly), you do not need to compute this total number of 
covered employees rate more than on a once per month basis.
    (d) As an employer, you may use a service agent (e.g., C/TPA) to 
perform random selections for you; and your covered employees may be 
part of a larger random testing pool of covered employees. However, you 
must ensure that the service agent you use is testing at the appropriate 
percentage established for your industry and that only covered employees 
are in the random testing pool.
    (e) Each operator that has a covered employee who performs multi-DOT 
agency functions (e.g., an employee performs pipeline maintenance duties 
and drives a commercial motor vehicle), count the employee only on the 
MIS report for the DOT agency under which he or she is randomly tested. 
Normally, this will be the DOT agency under which the employee performs 
more than 50% of his or her duties. Operators may have to explain the 
testing data for these employees in the event of a DOT agency inspection 
or audit.
    (f) A service agent (e.g., Consortia/Third Party Administrator as 
defined in 49 CFR part 40) may prepare the MIS report on behalf of an 
operator. However, each report shall be certified by the operator's 
anti-drug manager or designated representative for accuracy and 
completeness.

[68 FR 75465, Dec. 31, 2003, as amended by Amdt. 199-20, 69 FR 32898, 
June 14, 2004; 70 FR 11140, Mar. 8, 2005; 73 FR 16571, Mar. 28, 2008]



               Subpart C_Alcohol Misuse Prevention Program

    Source: Amdt. 199-9, 59 FR 7430, Feb. 15, 1994, unless otherwise 
noted. Redesignated by Amdt. 199-19, 66 FR 47118, Sept. 11, 2001.



Sec. 199.200  Purpose.

    The purpose of this subpart is to establish programs designed to 
help prevent accidents and injuries resulting from the misuse of alcohol 
by employees who perform covered functions for operators of certain 
pipeline facilities subject to parts 192, 193, or 195 of this chapter.



Sec. 199.201  [Reserved]



Sec. 199.202  Alcohol misuse plan.

    Each operator must maintain and follow a written alcohol misuse plan 
that conforms to the requirements of this part and DOT Procedures 
concerning alcohol testing programs. The plan shall contain methods and 
procedures for compliance with all the requirements of this subpart, 
including required testing, recordkeeping, reporting, education and 
training elements.

[Amdt. 199-9, 59 FR 7430, Feb. 15, 1994, as amended by Amdt. 199-19, 66 
FR 47119, Sept. 11, 2001]



Sec. Sec. 199.203-199.205  [Reserved]



Sec. 199.209  Other requirements imposed by operators.

    (a) Except as expressly provided in this subpart, nothing in this 
subpart shall be construed to affect the authority of operators, or the 
rights of employees, with respect to the use or possession of alcohol, 
including authority and rights with respect to alcohol testing and 
rehabilitation.
    (b) Operators may, but are not required to, conduct pre-employment 
alcohol testing under this subpart. Each operator that conducts pre-
employment alcohol testing must--
    (1) Conduct a pre-employment alcohol test before the first 
performance of covered functions by every covered employee (whether a 
new employee or someone who has transferred to a position involving the 
performance of covered functions);

[[Page 246]]

    (2) Treat all covered employees the same for the purpose of pre-
employment alcohol testing (i.e., you must not test some covered 
employees and not others);
    (3) Conduct the pre-employment tests after making a contingent offer 
of employment or transfer, subject to the employee passing the pre-
employment alcohol test;
    (4) Conduct all pre-employment alcohol tests using the alcohol 
testing procedures in DOT Procedures; and
    (5) Not allow any covered employee to begin performing covered 
functions unless the result of the employee's test indicates an alcohol 
concentration of less than 0.04.

[Amdt. 199-9, 59 FR 7430, Feb. 15, 1994, as amended by Amdt. 199-19, 66 
FR 47119, Sept. 11, 2001]



Sec. 199.211  Requirement for notice.

    Before performing an alcohol test under this subpart, each operator 
shall notify a covered employee that the alcohol test is required by 
this subpart. No operator shall falsely represent that a test is 
administered under this subpart.



Sec. 199.213  [Reserved]



Sec. 199.215  Alcohol concentration.

    Each operator shall prohibit a covered employee from reporting for 
duty or remaining on duty requiring the performance of covered functions 
while having an alcohol concentration of 0.04 or greater. No operator 
having actual knowledge that a covered employee has an alcohol 
concentration of 0.04 or greater shall permit the employee to perform or 
continue to perform covered functions.



Sec. 199.217  On-duty use.

    Each operator shall prohibit a covered employee from using alcohol 
while performing covered functions. No operator having actual knowledge 
that a covered employee is using alcohol while performing covered 
functions shall permit the employee to perform or continue to perform 
covered functions.



Sec. 199.219  Pre-duty use.

    Each operator shall prohibit a covered employee from using alcohol 
within four hours prior to performing covered functions, or, if an 
employee is called to duty to respond to an emergency, within the time 
period after the employee has been notified to report for duty. No 
operator having actual knowledge that a covered employee has used 
alcohol within four hours prior to performing covered functions or 
within the time period after the employee has been notified to report 
for duty shall permit that covered employee to perform or continue to 
perform covered functions.



Sec. 199.221  Use following an accident.

    Each operator shall prohibit a covered employee who has actual 
knowledge of an accident in which his or her performance of covered 
functions has not been discounted by the operator as a contributing 
factor to the accident from using alcohol for eight hours following the 
accident, unless he or she has been given a post-accident test under 
Sec. 199.225(a), or the operator has determined that the employee's 
performance could not have contributed to the accident.



Sec. 199.223  Refusal to submit to a required alcohol test.

    Each operator shall require a covered employee to submit to a post-
accident alcohol test required under Sec. 199.225(a), a reasonable 
suspicion alcohol test required under Sec. 199.225(b), or a follow-up 
alcohol test required under Sec. 199.225(d). No operator shall permit 
an employee who refuses to submit to such a test to perform or continue 
to perform covered functions.



Sec. 199.225  Alcohol tests required.

    Each operator shall conduct the following types of alcohol tests for 
the presence of alcohol:
    (a) Post-accident. (1) As soon as practicable following an accident, 
each operator shall test each surviving covered employee for alcohol if 
that employee's performance of a covered function either contributed to 
the accident or cannot be completely discounted as a contributing factor 
to the accident. The decision not to administer a test

[[Page 247]]

under this section shall be based on the operator's determination, using 
the best available information at the time of the determination, that 
the covered employee's performance could not have contributed to the 
accident.
    (2)(i) If a test required by this section is not administered within 
2 hours following the accident, the operator shall prepare and maintain 
on file a record stating the reasons the test was not promptly 
administered. If a test required by paragraph (a) is not administered 
within 8 hours following the accident, the operator shall cease attempts 
to administer an alcohol test and shall state in the record the reasons 
for not administering the test.
    (ii) [Reserved]
    (3) A covered employee who is subject to post-accident testing who 
fails to remain readily available for such testing, including notifying 
the operator or operator representative of his/her location if he/she 
leaves the scene of the accident prior to submission to such test, may 
be deemed by the operator to have refused to submit to testing. Nothing 
in this section shall be construed to require the delay of necessary 
medical attention for injured people following an accident or to 
prohibit a covered employee from leaving the scene of an accident for 
the period necessary to obtain assistance in responding to the accident 
or to obtain necessary emergency medical care.
    (b) Reasonable suspicion testing. (1) Each operator shall require a 
covered employee to submit to an alcohol test when the operator has 
reasonable suspicion to believe that the employee has violated the 
prohibitions in this subpart.
    (2) The operator's determination that reasonable suspicion exists to 
require the covered employee to undergo an alcohol test shall be based 
on specific, contemporaneous, articulable observations concerning the 
appearance, behavior, speech, or body odors of the employee. The 
required observations shall be made by a supervisor who is trained in 
detecting the symptoms of alcohol misuse. The supervisor who makes the 
determination that reasonable suspicion exists shall not conduct the 
breath alcohol test on that employee.
    (3) Alcohol testing is authorized by this section only if the 
observations required by paragraph (b)(2) of this section are made 
during, just preceding, or just after the period of the work day that 
the employee is required to be in compliance with this subpart. A 
covered employee may be directed by the operator to undergo reasonable 
suspicion testing for alcohol only while the employee is performing 
covered functions; just before the employee is to perform covered 
functions; or just after the employee has ceased performing covered 
functions.
    (4)(i) If a test required by this section is not administered within 
2 hours following the determination under paragraph (b)(2) of this 
section, the operator shall prepare and maintain on file a record 
stating the reasons the test was not promptly administered. If a test 
required by this section is not administered within 8 hours following 
the determination under paragraph (b)(2) of this section, the operator 
shall cease attempts to administer an alcohol test and shall state in 
the record the reasons for not administering the test. Records shall be 
submitted to PHMSA upon request of the Administrator.
    (ii) [Reserved]
    (iii) Notwithstanding the absence of a reasonable suspicion alcohol 
test under this section, an operator shall not permit a covered employee 
to report for duty or remain on duty requiring the performance of 
covered functions while the employee is under the influence of or 
impaired by alcohol, as shown by the behavioral, speech, or performance 
indicators of alcohol misuse, nor shall an operator permit the covered 
employee to perform or continue to perform covered functions, until:
    (A) An alcohol test is administered and the employee's alcohol 
concentration measures less than 0.02; or
    (B) The start of the employee's next regularly scheduled duty 
period, but not less than 8 hours following the determination under 
paragraph (b)(2) of this section that there is reasonable suspicion to 
believe that the employee has violated the prohibitions in this subpart.

[[Page 248]]

    (iv) Except as provided in paragraph (b)(4)(ii), no operator shall 
take any action under this subpart against a covered employee based 
solely on the employee's behavior and appearance in the absence of an 
alcohol test. This does not prohibit an operator with the authority 
independent of this subpart from taking any action otherwise consistent 
with law.
    (c) Return-to-duty testing. Each operator shall ensure that before a 
covered employee returns to duty requiring the performance of a covered 
function after engaging in conduct prohibited by Sec. Sec. 199.215 
through 199.223, the employee shall undergo a return-to-duty alcohol 
test with a result indicating an alcohol concentration of less than 
0.02.
    (d) Follow-up testing. (1) Following a determination under Sec. 
199.243(b) that a covered employee is in need of assistance in resolving 
problems associated with alcohol misuse, each operator shall ensure that 
the employee is subject to unannounced follow-up alcohol testing as 
directed by a substance abuse professional in accordance with the 
provisions of Sec. 199.243(c)(2)(ii).
    (2) Follow-up testing shall be conducted when the covered employee 
is performing covered functions; just before the employee is to perform 
covered functions; or just after the employee has ceased performing such 
functions.
    (e) Retesting of covered employees with an alcohol concentration of 
0.02 or greater but less than 0.04. Each operator shall retest a covered 
employee to ensure compliance with the provisions of Sec. 199.237, if 
an operator chooses to permit the employee to perform a covered function 
within 8 hours following the administration of an alcohol test 
indicating an alcohol concentration of 0.02 or greater but less than 
0.04.

[Amdt. 199-9, 59 FR 7430, Feb. 15, 1994, as amended at 59 FR 62239 and 
62246, Dec. 2, 1994; Amdt. 199-19, 66 FR 47119, Sept. 11, 2001; 70 FR 
11140, Mar. 8, 2005]



Sec. 199.227  Retention of records.

    (a) General requirement. Each operator shall maintain records of its 
alcohol misuse prevention program as provided in this section. The 
records shall be maintained in a secure location with controlled access.
    (b) Period of retention. Each operator shall maintain the records in 
accordance with the following schedule:
    (1) Five years. Records of employee alcohol test results with 
results indicating an alcohol concentration of 0.02 or greater, 
documentation of refusals to take required alcohol tests, calibration 
documentation, employee evaluation and referrals, and MIS annual repor