Safety Standards-Transportation of Gas by Pipeline

PURPOSE: This rule prescribes minimum safety standards regarding the design, fabrication, installation, construction, metering, corrosion control, testing, uprating, operation, maintenance, leak detection, repair, replacement, and integrity management of pipelines used for the transportation of natural and other gas.#

PUBLISHER'S NOTE: The secretary of state has determined that publication of the entire text of the material that is incorporated by reference as a portion of this rule would be unduly cumbersome or expensive. This material as incorporated by reference in this rule shall be maintained by the agency at its headquarters and shall be made available to the public for inspection and copying at no more than the actual cost of reproduction. This note applies only to the reference material. The entire text of the rule is printed here.#

AGENCY NOTE: This rule is similar to the Minimum Federal Safety Standards contained in 49 CFR part 192, Code of Federal Regulations. Parallel citations to Part 192 are provided for gas operator convenience and to promote public safety. Appendix E, contained in this rule, is a Table of Contents for 20 CSR 4240- 40.030.#

(1)General.#

(A)What Is the Scope of this Rule? (192.1)#

1.This rule prescribes minimum safety requirements for pipeline facilities and the transportation of gas in Missouri and under the jurisdiction of the commission. A table of contents is provided in Appendix E, which is included herein (at the end of this rule).#

2.This rule does not apply to-#

A.The gathering of gas-#

(I)Through a pipeline that operates at less than zero#

(0)pounds per square inch gauge (psig) (0 kPa); or#

(II)Through a pipeline that is not a regulated onshore gathering line (as determined in (1)(E)1.); or#

B.Any pipeline system that transports only petroleum gas or petroleum gas/air mixtures to-#

(I)Fewer than ten (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).#

(B)Definitions. (192.3) As used in this rule-#

1.Abandoned means permanently removed from service;#

2.Active corrosion means continuing corrosion that, unless controlled, could result in a condition that is detrimental to public safety;#

3.Administrator means the Administrator of the Pipeline and Hazardous Materials Safety Administration of the United States Department of Transportation to whom authority in the matters of pipeline safety have been delegated by the Secretary of the United States Department of Transportation, or his or her delegate;#

4.Alarm means an audible or visible means of indicating to the controller that equipment or processes are outside operator-defined, safety-related parameters;#

5.Building means any structure that is regularly or periodically occupied by people;#

6.Close interval survey means a series of closely and properly spaced pipe-to-electrolyte potential measurements taken over the pipe to assess the adequacy of cathodic protection or to identify locations where a current may be leaving the pipeline that may cause corrosion and for the purpose of quantifying voltage (IR) drops other than those across the structure electrolyte boundary, such as when performed as a current interrupted, depolarized, or native survey;#

7.Commission means the Missouri Public Service Com- mission;#

8.Composite materials means materials used to make pipe or components manufactured with a combination of either steel and/or plastic and with a reinforcing material to maintain its circumferential or longitudinal strength;#

9.Control room means an operations center staffed by personnel charged with the responsibility for remotely monitoring and controlling a pipeline facility;#

10.Controller means a qualified individual who remotely monitors and controls the safety-related operations of a pipeline facility via a supervisory control and data acquisition (SCADA) system from a control room, and who has operational authority and accountability for the remote operational functions of the pipeline facility;#

11.Customer meter means the meter that measures the transfer of gas from an operator to a consumer;#

12.Designated commission personnel means the pipeline safety program manager at the address contained in 20 CSR 4240-40.020(5)(E) for correspondence;#

13.Distribution center means the initial point where gas enters piping used primarily to deliver gas to customers who purchase it for consumption, as opposed to customers who purchase it for resale, for example-#

A.At a metering location;#

B.A pressure reduction location; or#

C.Where there is a reduction in the volume of gas, such as a lateral off a transmission line;#

14.Distribution line means a pipeline other than a gathering or transmission line;#

15.Dry gas or dry natural gas means gas above its dew point and without condensed liquids;#

16.Electrical survey means a series of closely spaced pipe-to-soil readings over pipelines which are subsequently analyzed to identify locations where a corrosive current is leaving the pipeline, except that other indirect examination tools/methods can be used for an electrical survey included in the federal regulations in 49 CFR part 192, subpart O and#

appendix E (incorporated by reference in section (16));#

17.Engineering critical assessment (ECA) means a documented analytical procedure based on fracture mechanics principles, relevant material properties (mechanical and fracture resistance properties), operating history, operational environment, in-service degradation, possible failure mechanisms, initial and final defect sizes, and usage of future operating and maintenance procedures to determine the maximum tolerable sizes for imperfections based upon the pipeline segment maximum allowable operating pressure;#

18.Entirely replaced transmission pipeline segments means, for the purposes of subsections (4)(U) and (12)(X), where two (2) or more miles, in the aggregate, of transmission pipeline have been replaced within any five (5) contiguous miles of pipeline within any twenty-four- (24-) month period. This definition does not apply to any gathering line;#

19.Feeder line means a distribution line that has a maximum allowable operating pressure (MAOP) greater than 100 psi (689 kPa) gauge that produces hoop stresses less than twenty percent (20%) of specified minimum yield strength (SMYS);#

20.Follow-up inspection means an inspection performed after a repair procedure has been completed in order to determine the effectiveness of the repair and to ensure that all hazardous leaks in the area are corrected;#

21.Fuel line means the customer-owned gas piping downstream from the outlet of the customer meter or operator- owned pipeline, whichever is farther downstream;#

22.Gas means natural gas, flammable gas, manufactured gas, or gas which is toxic or corrosive;#

23.Gathering line means a pipeline that transports gas from a current production facility to a transmission line or main;#

24.Hard spot means an area on steel pipe material with a minimum dimension greater than two inches (2") (50.8 mm) in any direction and hardness greater than or equal to Rockwell 35 HRC (Brinell 327 HB or Vickers 345 HV10);#

25.High-pressure distribution system means a distribution system in which the gas pressure in the main is higher than an equivalent to fourteen inches (14") water column;#

26.Hoop stress means the stress in a pipe wall acting circumferentially in a plane perpendicular to the longitudinal axis of the pipe produced by the pressure in the pipe;#

27.In-line inspection (ILI) means an inspection of a pipeline from the interior of the pipe using an inspection tool also called intelligent or smart pigging. This definition includes tethered and self-propelled inspection tools;#

28.In-line inspection tool or instrumented internal inspection device means an instrumented device or vehicle that uses a non-destructive testing technique to inspect the pipeline from the inside in order to identify and characterize flaws to analyze pipeline integrity; also known as an intelligent or smart pig;#

29.Listed specification means a specification listed in subsection I. of Appendix B, which is included herein (at the end of this rule);#

30.Low-pressure distribution system means a distribution system in which the gas pressure in the main is less than or equal to an equivalent of fourteen inches (14") water column;#

31.Main means a distribution line that serves as a common source of supply for more than one (1) service line;#

32.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.#

33.Maximum actual operating pressure means the maximum pressure that occurs during normal operations over a period of one (1) year;#

34.Maximum allowable operating pressure (MAOP) means the maximum pressure at which a pipeline or segment of a pipeline may be operated under this rule;#

35.Moderate consequence area means-#

A.An onshore area that is within a "potential impact circle" as defined in 49 CFR 192.903 (incorporated by reference in section (16)), containing either-#

(I)Five (5) or more buildings intended for human occupancy; or#

(II)Any portion of the paved surface (including shoulders) of a designated "interstate," "other freeway or expressway," as well as any "other principal arterial" roadway with four (4) or more lanes, as defined in the Federal Highway Administration's Highway Functional Classification Concepts, Criteria and Procedures, Section 3.1 (see: https://www.fhwa. dot.gov/planning/processes/statewide/related/highway_ functional_classifications/fcauab.pdf), and that does not meet the definition of "high consequence area" in 49 CFR 192.903 (incorporated by reference in section (16)); and#

B.The length of the moderate consequence area extends axially along the length of the pipeline from the outermost edge of the first potential impact circle containing either five (5) or more buildings intended for human occupancy; or any portion of the paved surface, including shoulders, of any designated interstate, freeway, or expressway, as well as any other principal arterial roadway with four (4) or more lanes, to the outermost edge of the last contiguous potential impact circle that contains either five (5) or more buildings intended for human occupancy, or any portion of the paved surface, including shoulders, of any designated interstate, freeway, or expressway, as well as any other principal arterial roadway with four (4) or more lanes;#

36.Municipality means a city, village, or town;#

37.Notification of potential rupture means the notification to, or observation by, an operator of indicia identified in subsection (12)(Y) of a potential unintentional or uncontrolled release of a large volume of gas from a pipeline. This definition does not apply to any gathering line;#

38.Operator means a person who engages in the transportation of gas;#

39.Person means any individual, firm, joint venture, partnership, corporation, association, county, state, municipality, political subdivision, cooperative association, or joint stock association, and including any trustee, receiver, assignee, or personal representative of them;#

40.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) gauge at 100°F (38°C);#

41.PHMSA means the Pipeline and Hazardous Materials Safety Administration of the United States Department of Transportation;#

42.Pipe means any pipe or tubing used in the transportation of gas, including pipe-type holders;#

43.Pipeline means all parts of those physical facilities through which gas moves in transportation, including pipe, valves, and other appurtenances attached to pipe, compressor units, metering stations, regulator stations, delivery stations, holders, and fabricated assemblies;#

44.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;#

45.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;#

46.Reading means the highest sustained reading when testing in a bar hole or opening without induced ventilation;#

47.Rupture-mitigation valve (RMV) means an automatic shut-off valve (ASV) or a remote-control valve (RCV) that a pipeline operator uses to minimize the volume of gas released from the pipeline and to mitigate the consequences of a rupture. This definition does not apply to any gathering line;#

48.Service line means a distribution line that transports gas from a common source of supply to an individual customer, to two (2) 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;#

49.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 (1) customer or multiple customers through a meter header or manifold;#

50.SMYS means specified minimum yield strength is-#

A.For steel pipe manufactured in accordance with a listed specification, the yield strength specified as a minimum in that specification; or#

B.For steel pipe manufactured in accordance with an unknown or unlisted specification, the yield strength determined in accordance with paragraph (3)(D)2.;#

51.Supervisory control and data acquisition (SCADA) system means a computer-based system or systems used by a controller in a control room that collects and displays information about a pipeline facility and may have the ability to send commands back to the pipeline facility;#

52.Sustained reading means the reading taken on a combustible gas indicator unit after adequately venting the test hole or opening;#

53.Transmission line means a pipeline or connected series of pipelines, other than a gathering line, that-#

A.Transports gas from a gathering pipeline or storage facility to a distribution center, storage facility, or large volume customer that is not downstream from a distribution center (A large volume customer may receive similar volumes of gas as a distribution center, and includes factories, power plants, and institutional users of gas.);#

B.Has an MAOP of twenty percent (20%) or more of SMYS;#

C.Transports gas within a storage field; or#

D.Is voluntarily designated by the operator as a transmission pipeline;#

54.Transportation of gas means the gathering, transmis- sion, or distribution of gas by pipeline or the storage of gas, in or affecting intrastate, interstate, or foreign commerce;#

55.Tunnel means a subsurface passageway large enough for a man to enter;#

56.Vault or manhole means a subsurface structure that a man can enter;#

57.Weak link means a device or method used when pulling polyethylene pipe, typically through methods such as horizontal directional drilling, to ensure that damage will not occur to the pipeline by exceeding the maximum tensile stresses allowed;#

58.Welder means a person who performs manual or semi- automatic welding;#

59.Welding operator means a person who operates machine or automatic welding equipment;#

60.Wrinkle bend means a bend in the pipe that-#

A.Was formed in the field during construction such that the inside radius of the bend has one (1) or more ripples with-#

(I)An amplitude greater than or equal to one and one- half (1.5) times the wall thickness of the pipe, measured from peak to valley of the ripple; or#

(II)With ripples less than one and one-half (1.5) times the wall thickness of the pipe and with a wrinkle length (peak to peak) to wrinkle height (peak to valley) ratio under twelve (12); and#

B.If the length of the wrinkle bend cannot be reliably determined, then wrinkle bend means a bend in the pipe where (h/D)*100 exceeds 2 when S is less than 37,000 psi (255 MPa), where (h/D)*100 exceeds (47,000-S)/10,000 + 1 for psi [(324- S)/69 + 1 for MPa] when S is greater than 37,000 psi (255 MPa) but less than 47,000 psi (324 MPa), and where (h/D)*100 exceeds 1 when S is 47,000 psi (324 MPa) or more. Where-#

(I)D = Outside diameter of the pipe, in. (mm);#

(II)h = Crest-to-trough height of the ripple, in. (mm); and#

(III)S = Maximum operating hoop stress, psi (S/145, MPa); and#

61.Yard line means an underground fuel line that trans- ports gas from the service line to the customer's building. If multiple buildings are being served, building means the build- ing nearest to the connection to the service line. For purposes of this definition, if aboveground fuel line piping at the meter location is located within five feet (5') of a building being served by that meter, it will be considered to the customer's building and no yard line exists. At meter locations where aboveground fuel line piping is located greater than five feet (5') from the building(s) being served, the underground fuel line from the meter to the entrance into the nearest building served by that meter will be considered the yard line and any other lines are not considered yard lines.#

(C)Class Locations. (192.5)#

1.This subsection classifies pipeline locations for the purpose of this rule. The following criteria apply to classifications under this section:#

A.A "class location unit" is an area that extends two hundred twenty (220) yards (200 meters) on either side of the centerline of any continuous one- (1-) mile (1.6 kilometers) length of pipeline; and#

B.Each separate dwelling unit in a multiple dwelling unit building is counted as a separate building intended for human occupancy.#

2.Except as provided in paragraph (1)(C)3., pipeline locations are classified as follows:#

A.A Class 1 location is any class location unit that has ten (10) or fewer buildings intended for human occupancy;#

B.A Class 2 location is any class location unit that has more than ten (10) but fewer than forty-six (46) buildings intended for human occupancy;#

C.A Class 3 location is-#

(I)Any class location unit that has forty-six (46) or more buildings intended for human occupancy; or#

(II)An area where the pipeline lies within one hundred (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 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); and#

D.A Class 4 location is any class location unit where buildings with four (4) or more stories aboveground are prevalent.#

3.The length of Class locations 2, 3, and 4 may be adjusted as follows:#

A.A Class 4 location ends two hundred twenty (220) yards (200 meters) from the nearest building with four (4) or more stories aboveground; and#

B.When a cluster of buildings intended for human occupancy requires a Class 2 or 3 location, the class location ends two hundred twenty (220) yards (200 meters) from the nearest building in the cluster.#

4.An operator must have records that document the current class location of each gas transmission pipeline segment and that demonstrate how the operator determined each current class location in accordance with this subsection.#

(D)Incorporation By Reference of the Federal Regulation at 49 CFR 192.7. (192.7)#

1.As set forth in the Code of Federal Regulations (CFR) dated October 1, 2024, the federal regulation at 49 CFR 192.7 is incorporated by reference and made a part of this rule. This rule does not incorporate any subsequent amendments to 49 CFR 192.7.#

2.The Code of Federal Regulations and the Federal Register are published by the Office of the Federal Register, National Archives and Records Administration, 8601 Adelphi Road, College Park, MD 20740-6001. The October 1, 2024, version of 49 CFR part 192 is available at https://www.govinfo.gov/content/ pkg/CFR-2024-title49-vol3/pdf/CFR-2024-title49-vol3-part192. pdf.#

3.The regulation at 49 CFR 192.7 provides a listing of the documents that are incorporated by reference partly or wholly in 49 CFR part 192, which is the federal counterpart and foundation for this rule. All incorporated materials are available for inspection from several sources, including the following sources:#

A.The Office of Pipeline Safety, Pipeline and Hazardous Materials Safety Administration, 1200 New Jersey Avenue SE, Washington, DC 20590. For more information, contact 202- 366-4046 or go to the PHMSA website at www.phmsa.dot.gov/ pipeline/regs;#

B.The National Archives and Records Administration (NARA). For information on the availability of this material at NARA, go to the NARA website at www.archives.gov/federal- register/cfr/ibr-locations.html or call 202-741-6030 or 866-272- 6272; and#

C.Copies of standards incorporated by reference can also be purchased or are otherwise made available from the respective standards-developing organizations listed in 49 CFR 192.7.#

4.Federal amendment 192-94 (published in Federal Register on June 14, 2004, page 69 FR 32886) moved the listing of incorporated documents to 49 CFR 192.7 from 49 CFR part 192−Appendix A, which is now "Reserved." This listing of documents was in Appendix A to this rule prior to the 2008 amendment of this rule. As of the 2008 amendment, Appendix A to this rule is also "Reserved" and included herein.#

(E)Gathering Lines.#

1.How are Gathering Pipelines and Regulated Gathering Pipelines Determined? (192.8)#

A.An operator must use API RP 80 (incorporated by reference in 49 CFR 192.7 and adopted in (1)(D)), to determine if a pipeline (or part of a connected series of pipelines) is a gathering line. The determination is subject to the limitations listed below. After making this determination, an operator must determine if the gathering line is a regulated gathering line under paragraph (1)(E)1.#

(I)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.''#

(II)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.#

(III)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 fifty (50) miles from each other, unless the administrator finds a longer separation distance is justified in a particular case (see 49 CFR 190.9).#

(IV)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.#

(V)For new, replaced, relocated, or otherwise changed gas gathering pipelines installed after May 16, 2022, the endpoint of gathering under sections 2.2(a)(1)(E) and 2.2.1.2.6 of API RP 80-also known as ''incidental gathering''-may not be used if the pipeline terminates ten (10) or more miles downstream from the furthermost downstream endpoint as defined in paragraphs 2.2(a)(1)(A) through (a)(1)(D) of API RP 80 and this paragraph. If an ''incidental gathering'' pipeline is ten (10) miles or more in length, the entire portion of the pipeline that is designated as an incidental gathering line under 2.2(a)(1)(E) and 2.2.1.2.6 of API RP 80 shall be classified as a transmission pipeline subject to rules 20 CSR 4240-40.020, 20 CSR 4240-40.030, 20 CSR 4240-40.033, and 20 CSR 4240-40.080.#

B.Each operator must determine and maintain for the life of the pipeline records documenting the methodology by which it calculated the beginning and end points of each gathering pipeline it operates, as described in the second column of table 1 to part (1)(E)1.C.(II), by-#

(I)November 16, 2022, or before the pipeline is placed into operation, whichever is later; or#

(II)An alternative deadline approved by the Pipeline and Hazardous Materials Safety Administration (PHMSA). The operator must notify PHMSA and designated commission personnel no later than ninety (90) days in advance of the deadline in part (1)(E)1.B.(I). The notification must be made in accordance with subsection (1)(M) and must include the following information: (a) Description of the affected facilities and operat- ing environment; (b) Justification for an alternative compliance dead- line; and (c) Proposed alternative deadline.#

C.For purposes of 20 CSR 4240-40.020 and paragraph (1) (E)2., the term ''regulated gathering pipeline'' means-#

(I)Each Type A, Type B, or Type C gathering pipeline (or segment of gathering pipeline) with a feature described in the second column of table 1 to part (1)(E)1.C.(II) that lies in an area described in the third column; and#

(II)As applicable, additional lengths of pipeline de- scribed in the fourth column to provide a safety buffer. Table 1 to Part (1)(E)1.C.(II) C • Type Feature Area Safety Buffer A • • • Metallic and the MAOP produces a hoop stress of twenty percent (20%) or more of SMYS. If the stress level is unknown, an operator must determine the stress level according to the applicable provisions in section (3). Non-metallic and the MAOP is more than one hundred twenty-five#

(125)psig (862 kPa). Class 2, 3, or 4 location (see subsection (1)(C)). None. B • Outside diameter greater than or equal to 8.625 inches and any of the following: -Metallic and the MAOP produces a hoop stress of twenty percent (20%) or more of SMYS; -If the stress level is unknown, segment is metallic and the MAOP is more than one hundred twenty-five#

(125)psig (862 kPa); or -Non-metallic and the MAOP is more than one hundred twenty- five#

(125)psig (862 kPa). Class 1 location. None. • Metallic and the MAOP produces a hoop stress of less than twenty percent (20%) of SMYS. If the stress level is unknown, an operator must determine the stress level according to the applicable provisions in section (3). Non-metallic and the MAOP is one hundred twenty-five#

(125)psig (862 kPa) or less. Area 1. Class 3 or 4 location. Area 2. An area within a Class 2 location the operator determines by using any of the following three (3) methods: (a) A Class 2 location; (b) An area extending one hundred fifty feet (150') (45.7 m) on each side of the centerline of any continuous one#

(1)mile (1.6 km) of pipeline and including more than ten (10) but fewer than forty- six (46) dwellings; or (c) An area extending one hundred fifty feet (150') (45.7 m) on each side of the centerline of any continuous one thousand feet (1000') (305 m) of pipeline and including five (5) or more dwellings. If the gathering pipeline is in Area 2(b) or 2(c), the additional lengths of line extend upstream and downstream from the area to a point where the line is at least one hundred fifty feet (150') (45.7 m) from the nearest dwelling in the area. However, if a cluster of dwellings in Area 2(b) or 2(c) qualifies a pipeline as Type B, the Type B classification ends one hundred fifty feet (150') (45.7 m) from the nearest dwelling in the cluster. R All other gathering lines. Class 1 and Class 2 locations. None.#

(III)A Type R gathering line is subject to reporting requirements under 20 CSR 4240-40.020 but is not a regulated gathering line under this rule.#

(IV)For the purpose of identifying Type C lines in table 1 to part (1)(E)1.C.(II), if an operator has not calculated MAOP consistent with the methods at paragraph (12)(M)1. or subparagraph (12)(M)3.A., the operator must either- (a) Calculate MAOP consistent with the methods at paragraph (12)(M)1. or subparagraph (12)(M)3.A.; or (b) Use as a substitute for MAOP the highest operat- ing pressure to which the segment was subjected during the preceding five (5) operating years.#

2.What Requirements Apply to Gathering Pipelines? (192.9)#

A.Requirements. An operator of a gathering line must follow the safety requirements of this rule as prescribed by this paragraph.#

B.Type A lines. An operator of a Type A regulated gathering line must comply with the requirements of this rule applicable to transmission lines, except the requirements in (1)(G)4., (4)(HH), (6)(H)5., (7)(J)3.-6., (9)(G)6.-9., (9)(I)4. and 6., (9)(M)3., (9)(S)3., (9)(X), (10)(K), (12)(E), (12)(H)3., (12)(M)5., (12)(U), (13)(DD), (13)(EE), (13)(GG), and section (16)-Pipeline Integrity Management for Transmission Lines (Subpart O). However, an operator of a Type A regulated gathering line in a Class 2 location may demonstrate compliance with subsection (12)(D) by describing the processes it uses to determine the qualification of persons performing operations and maintenance tasks. Further, operators of Type A regulated gathering lines are exempt from the requirements of (4)(U)4.-6., (12)(W), (12)(L)2.-4., (12)(X), (12)(Y), (12)(Z), and (13)(U)3.-6. Lastly, operators of Type A regulated gathering lines are exempt from the requirements of subsection (12)(J) (but an operator of a Type A regulated gathering line must comply with the requirements of subsection (12)(J), effective February 28, 2023).#

C.Type B lines. An operator of a Type B regulated gathering line must comply with the following requirements:#

(I)If a line is new, replaced, relocated, or otherwise changed, the design, installation, construction, initial inspec- tion, and initial testing must be in accordance with require- ments of this rule applicable to transmission lines. Compliance with (2)(G), (3)(M), (4)(U)4. and 5., (4)(II), (5)(D)3., (6)(H)5., (7) (J)3.-6., (10)(K), (12)(X), and (12)(Z) is not required;#

(II)If the pipeline is metallic, control corrosion according to requirements of section (9) applicable to transmission lines, except the requirements in (9)(G)6.-9., (9) (I)4. and 6., (9)(M)3., (9)(S)3., and (9)(X);#

(III)If the pipeline contains plastic pipe or components, the operator must comply with all applicable requirements of this rule for plastic pipe components;#

(IV)Carry out a damage prevention program under subsection (12)(I);#

(V)Establish a public education program under subsection (12)(K);#

(VI)Establish the MAOP of the line under paragraphs (12)(M)1., 2., and 3.;#

(VII)Install and maintain line markers according to the requirements for transmission lines in subsection (13)(E); and#

(VIII)Conduct leakage surveys in accordance with the requirements for transmission lines in subsection (13)(D), using leak-detection equipment, and promptly repair hazardous leaks in accordance with paragraph (13)(B)3.#

D.Type C lines. The requirements for Type C gathering lines are as follows:#

(I)An operator of a Type C gathering line with an outside diameter greater than or equal to eight and five-eighths inches (8.625") must comply with the following requirements: (a) Except as provided in subparagraph (1)(E)2.G. for pipe and components made with composite materials, the design, installation, construction, initial inspection, and initial testing of a new, replaced, relocated, or otherwise changed Type C gathering line must be done in accordance with the requirements in sections (2)-(7) and (10) applicable to transmission lines. Compliance with (2)(G), (3)(M), (4)(U)4. and 5., (4)(II), (5)(D)3., (6)(H)5., (7)(J)3.-6., (10)(K), (12)(X), and (12)(Z) is not required; (b) If the pipeline is metallic, control corrosion according to requirements of section (9) applicable to transmission lines, except the requirements in (9)(G)6.-9., (9) (I)4. and 6., (9)(M)3., (9)(S)3., and (9)(X); (c) Carry out a damage prevention program under subsection (12)(I); (d) Develop and implement procedures for emergency plans in accordance with the requirements of subsection (12)(J), effective February 28, 2023; (e) Develop and implement a written public awareness program in accordance with subsection (12)(K); (f) Install and maintain line markers according to the requirements for transmission lines in subsection (13)(E); and (g) Conduct leakage surveys in accordance with the requirements for transmission lines in subsection (13)(D) using leak-detection equipment, and promptly repair hazardous leaks in accordance with paragraph (13)(B)3.; and#

(II)An operator of a Type C gathering line with an outside diameter greater than twelve and three-quarters inches (12.75") must comply with the requirements in part (1) (E)2.D.(I) and the following: (a) If the pipeline contains plastic pipe, the operator must comply with all applicable requirements of this rule for plastic pipe or components. This does not include pipe and components made of composite materials that incorporate plastic in the design; and (b) Establish the MAOP of the pipeline under paragraph (12)(M)1. or 3. and maintain records used to establish the MAOP for the life of the pipeline.#

E.Exceptions.#

(I)Compliance with subparts (1)(E)2.D.(I)(b), (e), (f), and (g) and subparts (1)(E)2.D.(II)(a) and (b) is not required for pipeline segments that are sixteen inches (16") or less in outside diameter if one (1) of the following criteria are met: (a) Method 1. The segment is not located within a potential impact circle containing a building intended for human occupancy or other impacted site. The potential impact circle must be calculated as specified in 49 CFR 192.903 (incorporated by reference in section (16)), except that a factor of 0.73 must be used instead of 0.69. The MAOP used in this calculation must be determined and documented in accordance with subpart (1)(E)2.D.(II)(b); and (b) Method 2. The segment is not located within a class location unit (see subsection (1)(C)) containing a building intended for human occupancy or other impacted site.#

(II)Subpart (1)(E)2.D.(I)(a) is not applicable to pipeline segments forty feet (40') or shorter in length that are replaced, relocated, or changed on a pipeline existing on or before May 16, 2022.#

(III)For purposes of this paragraph, the term ''building intended for human occupancy or other impacted site'' means any of the following: (a) Any building that may be occupied by humans, including homes, office buildings, factories, outside recreation areas, plant facilities, etc.; (b) A small, well-defined outside area (such as a playground, recreation area, outdoor theater, or other place of public assembly) 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); or (c) Any portion of the paved surface, including shoulders, of a designated interstate, other freeway, or expressway, as well as any other principal arterial roadway with four (4) or more lanes.#

F.Compliance deadlines. An operator of a regulated gathering line must comply with the following deadlines, as applicable.#

(I)An operator of a new, replaced, relocated, or otherwise changed line must be in compliance with the applicable requirements of this paragraph by the date the line goes into service, unless an exception in subsection (1)(G) applies.#

(II)If a Type A or Type B regulated gathering pipeline existing on April 14, 2006, was not previously subject to this rule, an operator has until the date stated in the second col- umn to comply with the applicable requirement for the pipe- line listed in the first column, unless the administrator finds a later deadline is justified in a particular case- Requirement Compliance Deadline (i) Control corrosion according to requirements for transmission lines in section (9). (ii) Carry out a damage prevention program under subsection (12)(I). (iii) Establish MAOP under subsection (12)(M). (iv) Install and maintain line markers under subsection (13)(E). (v) Establish a public education program under subsection (12)(K). (vi) Other provisions of this rule as required by subparagraph (1)(E)2.B. for Type A lines. April 15, 2009. October 15, 2007. October 15, 2007. April 15, 2008. April 15, 2008. April 15, 2009.#

(III)If, after April 14, 2006, a change in class location or increase in dwelling density causes a gathering pipeline to become a Type A or Type B regulated gathering line, the operator has one (1) year for Type B lines and two (2) years for Type A lines after the pipeline becomes a regulated gathering pipeline to comply with this paragraph.#

(IV)If a Type C gathering pipeline existing on or before May 16, 2022, was not previously subject to this rule, an operator must comply with the applicable requirements of this paragraph, except for subparagraph (1)(E)2.G., on or before- (a) May 16, 2023; or (b) An alternative deadline approved by PHMSA. The operator must notify PHMSA and designated commission personnel no later than ninety (90) days in advance of the deadline in part (1)(E)1.B.(I). The notification must be made in accordance with subsection (1)(M) and must include a description of the affected facilities and operating environment, the proposed alternative deadline for each affected requirement, the justification for each alternative compliance deadline, and actions the operator will take to ensure the safety of affected facilities.#

(V)If, after May 16, 2022, a change in class location, an increase in dwelling density, or an increase in MAOP causes a pipeline to become a Type C gathering pipeline, or causes a Type C gathering pipeline to become subject to additional Type C requirements (see subparagraph (1)(E)2.E.), the operator has one (1) year after the pipeline becomes subject to the additional requirements to comply with this paragraph.#

G.Composite materials. Pipe and components made with composite materials not otherwise authorized for use under this rule may be used on Type C gathering pipelines if the following requirements are met:#

(I)Steel and plastic pipe and components must meet the installation, construction, initial inspection, and initial testing requirements in sections (2)-(7) and (10) applicable to transmission lines;#

(II)Operators must notify PHMSA in accordance with subsection (1)(M) at least ninety (90) days prior to installing new or replacement pipe or components made of composite materials otherwise not authorized for use under this rule in a Type C gathering pipeline. The notifications required by this paragraph must include a detailed description of the pipeline facilities in which pipe or components made of composite materials would be used, including- (a) The beginning and end points (stationing by footage and mileage with latitude and longitude coordinates) of the pipeline segment containing composite pipeline material and the counties and states in which it is located; (b) A general description of the right-of-way in- cluding high consequence areas, as defined in 49 CFR 192.905 (incorporated by reference in section (16)); (c) Relevant pipeline design and construction infor- mation including the year of installation, the specific compos- ite material, diameter, wall thickness, and any manufacturing and construction specifications for the pipeline; (d) Relevant operating information, including MAOP, leak and failure history, and the most recent pressure test (identification of the actual pipe tested, minimum and maximum test pressure, duration of test, any leaks and any test logs and charts) or assessment results; (e) An explanation of the circumstances that the operator believes make the use of composite pipeline material appropriate and how the design, construction, operations, and maintenance will mitigate safety and environmental risks; (f) An explanation of procedures and tests that will be conducted periodically over the life of the composite pipeline material to document that its strength is being maintained; (g) Operations and maintenance procedures that will be applied to the alternative materials. These include procedures that will be used to evaluate and remediate anomalies and how the operator will determine safe operating pressures for composite pipe when defects are found; (h) An explanation of how the use of composite pipeline material would be in the public interest; and (i) A certification signed by a vice president (or equivalent or higher officer) of the operator's company that operation of the applicant's pipeline using composite pipeline material would be consistent with pipeline safety; and#

(III)Repairs or replacements using materials authorized under this rule do not require notification under this paragraph.#

(F)Petroleum Gas Systems. (192.11)#

1.Each plant that supplies petroleum gas by pipeline to a natural gas distribution system must meet the requirements of this rule and NFPA 58 or NFPA 59 (both incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)), based on the scope and applicability statements in those standards.#

2.Each pipeline system subject to this rule that transports only petroleum gas or petroleum gas/air mixtures must meet the requirements of this rule and NFPA 58 or NFPA 59 (both incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)), based on the scope and applicability statements in those standards.#

3.In the event of a conflict between this rule and NFPA 58 or NFPA 59 (both incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)), NFPA 58 or NFPA 59 shall prevail if applicable based on the scope and applicability statements in those standards.#

(G)What General Requirements Apply to Pipelines Regulated Under this Rule? (192.13)#

1.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-#

A.The pipeline has been designed, installed, constructed, initially inspected, and initially tested in accordance with this rule; or#

B.The pipeline qualifies for use under this rule in accor- dance with subsection (1)(H). Pipeline Date Regulated onshore gathering pipeline to which this rule did not apply until April 14, 2006 (see (1)(E)) March 15, 2007 Regulated onshore gathering pipeline to which this rule did not apply until May 16, 2022 (see (1)(E)) May 16, 2023 All other pipelines March 12, 1971#

2.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 that replacement, relocation, or change has been made according to the requirements in this rule. Pipeline Date Regulated onshore gathering pipeline to which this rule did not apply until April 14, 2006 (see (1)(E)) March 15, 2007 Regulated onshore gathering pipeline to which this rule did not apply until May 16, 2022 (see (1)(E)) May 16, 2023 All other pipelines November 12, 1970#

3.Each operator shall maintain, modify as appropriate, and follow the plans, procedures, and programs that it is required to establish under this rule.#

4.Each operator of a gas transmission pipeline must evaluate and mitigate, as necessary, significant changes that pose a risk to safety or the environment through a management of change process. Each operator of a gas transmission pipeline must develop and follow a management of change process, as outlined in ASME B31.8S, section 11 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)), that addresses technical, design, physical, environmental, procedural, operational, maintenance, and organizational changes to the pipeline or processes, whether permanent or temporary. A management of change process must include the following: reason for change, authority for approving changes, analysis of implications, acquisition of required work permits, documentation, communication of change to affected parties, time limitations, and qualification of staff. For pipeline segments other than those covered in section (16)-Pipeline Integrity Management for Transmission Lines (Subpart O), this management of change process must be implemented by February 26, 2024. The requirements of this paragraph do not apply to gas gathering pipelines. Operators may request an extension of up to one (1) year by submitting a notification to PHMSA at least ninety (90) days before February 26, 2024, in accordance with subsection (1)(M). The notification must include a reasonable and technically justified basis, an up-to-date plan for completing all actions required by this subsection, the reason for the requested extension, current safety or mitigation status of the pipeline segment, the proposed completion date, and any needed temporary safety measures to mitigate the impact on safety.#

5.This section and sections (9) and (11)-(17) apply regard- less of installation date. The requirements within other sec- tions of this rule apply regardless of the installation date only when specifically stated as such.#

(H)Conversion to Service Subject to this Rule. (192.14)#

1.Except as provided in paragraph (1)(H)4., a pipeline previously used in service not subject to this rule qualifies for use under this rule if the operator prepares and follows a written procedure to carry out the following requirements:#

A.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;#

B.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;#

C.All known unsafe defects and conditions must be corrected in accordance with this rule; and#

D.The pipeline must be tested in accordance with section (10) to substantiate the maximum allowable operating pressure ­ permitted by section (12).#

2.Each operator must keep for the life of the pipeline a record of investigations, tests, repairs, replacements, and alterations made under the requirements of paragraph (1)(H)1.#

3.An operator converting a pipeline from service not previously covered by this rule must notify PHMSA and designated commission personnel sixty (60) days before the conversion occurs as required by 20 CSR 4240-40.020(11).#

4.This paragraph lists situations where steel pipe may not be converted to service subject to this rule.#

A.Steel yard lines that are not cathodically protected must be replaced under subsection (15)(C).#

B.Buried steel fuel lines that are not cathodically protected may not be converted to a pipeline as defined in subsection (1)(B), such as a service line or main.#

C.Buried steel pipes that are not cathodically protected may not be converted to a service line.#

D.Buried steel pipes that are not cathodically protected may not be converted to a main in Class 3 and Class 4 locations.#

(I)Rules of Regulatory Construction. (192.15)#

1.As used in this rule-#

A.Includes means including, but not limited to;#

B.May means is permitted to or is authorized to;#

C.May not means is not permitted to or is not authorized to; and#

D.Shall is used in the mandatory and imperative sense.#

2.In this rule-#

A.Words importing the singular include the plural;#

B.Words importing the plural include the singular; and#

C.Words importing the masculine gender include the feminine.#

(J)Filing of Required Plans, Procedures, and Programs.#

1.Each operator shall submit to designated commission personnel all plans, procedures, and programs required by this rule (to include welding and joining procedures, construction standards, control room management procedures, corrosion control procedures, damage prevention program, distribution integrity management plan, emergency procedures, public education program, operator qualification program, replacement programs, transmission integrity management program, and procedural manual for operations, maintenance, and emergencies). In addition, each change must be submitted to designated commission personnel within twenty (20) days after the change is made.#

2.All operators under the pipeline safety jurisdiction of the Missouri Public Service Commission must establish and submit welding procedures, joining procedures, and construction specifications and standards to designated commission personnel before construction activities begin. All other plans, procedures and programs required by rules 20 CSR 4240-40.020, 20 CSR 4240-40.030, and 20 CSR 4240-40.080 must be established and submitted to designated commission personnel before the system is put into operation.#

3.A written plan for drug and alcohol testing in accordance with 20 CSR 4240-40.080 must be submitted to designated commission personnel.#

(K)Customer Notification Required by Section 192.16 of 49 CFR part 192. (192.16)#

1.This subsection 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 subsection, "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 subsection (9)(I) if the customer's buried piping is metallic, survey for leaks according to subsection (13)(M), and if an unsafe condition is found, take action according to paragraph (12)(S)3.#

2.Each operator shall notify each customer once in writing of the following information:#

A.The operator does not maintain the customer's buried piping;#

B.If the customer's buried piping is not maintained, it may be subject to the potential hazards of corrosion and leakage;#

C.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;#

D.When excavating near buried gas piping, the piping should be located in advance, and the excavation done by hand; and#

E.The operator (if applicable), plumbing contractors, and heating contractors can assist in locating, inspecting, and repairing the customer's buried piping.#

3.Each operator shall notify each customer not later than August 14, 1996, or ninety (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.#

4.Each operator must make the following records available for inspection by designated commission personnel:#

A.A copy of the notice currently in use; and#

B.Evidence that notices have been sent to customers within the previous three (3) years.#

(L)Customer Notification, Paragraph (12)(S)2. When providing gas service to a new customer or a customer relocated from a different operating district, see paragraph (12)(S)2. regarding applicable customer notification.#

(M)How to Notify PHMSA and Designated Commission Personnel. (192.18)#

1.An operator must provide any notification required by this rule by-#

A.Sending the notification by electronic mail to InformationResourcesManager@dot.gov; or#

B.Sending the notification by mail to ATTN: Information Resources Manager, DOT/PHMSA/OPS, East Building, 2nd Floor, E22-321, 1200 New Jersey Ave. SE, Washington, DC 20590.#

2.An operator must also notify designated commission personnel by electronic mail to PipelineSafetyProgramMan- ager@psc.mo.gov or by mail to Pipeline Safety Program Man- ager, Missouri Public Service Commission, PO Box 360, Jefferson City, MO 65102.#

3.Unless otherwise specified, if an operator submits, pur- suant to (1)(E), (1)(G)4., (4)(U)4.-6., (7)(J)4., (9)(G)7., (10)(K)2., (12) (E)5.D., (12)(E)5.E., (12)(M)3.B., (12)(U)3.B.(III), (12)(U)3.F., (12)(V)2.C., (12)(X)1., (12)(X)2.C., (12)(X)2.D., (12)(Z)3., (13)(U)5.A., (13)(DD)3.G., (13)(EE)4.C.(IV), (13)(EE)5.B.(I)(e), (13)(GG)5.B., (13)(GG)5.C., 49 CFR 192.921(a)(7) (incorporated by reference in section (16)), or 49 CFR 192.937(c)(7) (incorporated by reference in section (16)), a notification for use of a different integrity assessment method, analytical method, compliance period, sampling approach, pipeline material, or technique (e.g., "other technology" or "al- ternative equivalent technology") than otherwise prescribed in those requirements, that notification must be submitted to PHMSA for review at least ninety (90) days in advance of using the other method, approach, compliance timeline, or technique. An operator may proceed to use the other method, approach, compliance timeline, or technique ninety-one (91) days after submitting the notification unless it receives a letter from the Associate Administrator for Pipeline Safety informing the operator that PHMSA objects to the proposal or that PHMSA requires additional time to conduct its review.#

(2)Materials.#

(A)Scope. (192.51) This section prescribes minimum requirements for the selection and qualification of pipe and components for use in pipelines.#

(B)General. (192.53)#

1.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;#

C.Qualified in accordance with the applicable requirements of this section; and#

D.Only of steel or polyethylene for pipe for the underground construction of pipelines, except-#

(I)Previously qualified materials may be used for repair of pipe constructed of the same material; and#

(II)Composite materials as defined in subsection (1)(B) may be used for pipe in Type C gathering lines when permitted by paragraph (1)(E)2. and subject to prior notifications to PHMSA and designated commission personnel in accordance with paragraph (1)(E)2. and subsection (1)(M).#

2.Other piping materials may be used with approval of the commission.#

(C)Steel Pipe. (192.55)#

1.New steel pipe is qualified for use under this rule if-#

A.It was manufactured in accordance with a listed specification;#

B.It meets the requirements of-#

(I)Subsection II of Appendix B to this rule; or#

(II)If it was manufactured before November 12, 1970, either subsection II or III of Appendix B to this rule; or#

C.It is used in accordance with paragraph (2)(C)3. or 4.#

2.Used steel pipe is qualified for use under this rule if-#

A.It was manufactured in accordance with a listed specification and it meets the requirements of paragraph II-C of Appendix B to this rule;#

B.It meets the requirements of-#

(I)Subsection II of Appendix B to this rule; or#

(II)If it was manufactured before November 12, 1970, either subsection II or III of Appendix B to this rule;#

C.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 rule; or#

D.It is used in accordance with paragraph (2)(C)3.#

3.New or used steel pipe may be used at a pressure resulting in a hoop stress of less than six thousand (6000) pounds per square inch (psi) (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 rule.#

4.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.#

5.New steel pipe that has been cold expanded must comply with the mandatory provisions of API Specification 5L (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).#

(D)Plastic Pipe. (192.59)#

1.New polyethylene pipe is qualified for use under this rule if-#

A.It is manufactured in accordance with a listed specification;#

B.It is resistant to chemicals with which contact may be anticipated; and#

C.It is free of visual defects.#

2.Used plastic pipe is qualified for use under this rule if-#

A.It was manufactured in accordance with a listed specification;#

B.It is resistant to chemicals with which contact may be anticipated;#

C.It has been used only in gas service;#

D.Its dimensions are still within the tolerances of the specification to which it was manufactured; and#

E.It is free of visible defects.#

3.For the purpose of subparagraphs (2)(D)1.A. and 2.A., 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-#

A.Meets the strength and design criteria required of pipe included in that listed specification; and#

B.Is manufactured from plastic compounds which meet the criteria for material required of pipe included in that listed specification.#

4.Rework and/or regrind material is not allowed in plastic pipe produced after March 6, 2015 used under this rule.#

(E)Marking of Materials. (192.63)#

1.Except as provided in paragraphs (2)(E)4. and (2)(E)5., each valve, fitting, length of pipe, and other component must be marked as prescribed in the specification or standard to which it was manufactured.#

2.Surfaces of pipe and components that are subject to stress from internal pressure may not be field die stamped.#

3.If any item is marked by die stamping, the die must have blunt or rounded edges that will minimize stress concentrations.#

4.Paragraph (2)(E)1. does not apply to items manufactured before November 12, 1970, that meet all of the following:#

A.The item is identifiable as to type, manufacturer, and model; and#

B.Specifications or standards giving pressure, temperature, and other appropriate criteria for the use of items are readily available.#

5.All plastic pipe and components must also meet the following requirements:#

A.All markings on plastic pipe prescribed in the listed specification and the requirements of subparagraph (2)(E)5.B. must be repeated at intervals not exceeding two (2) feet;#

B.Plastic pipe and components manufactured after December 31, 2019 must be marked in accordance with the listed specification; and#

C.All physical markings on plastic pipelines prescribed in the listed specification and subparagraph (2)(E)5.B. must be legible until the time of installation.#

(F)Transportation of Pipe. (192.65)#

1.Railroad. In a pipeline to be operated at a hoop stress of twenty percent (20%) or more of SMYS, an operator may not use pipe having an outer diameter to wall thickness ratio of seventy to one (70:1) or more that is transported by railroad unless the transportation is performed in accordance with API RP 5L1 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).#

2.Ship or barge. In a pipeline to be operated at a hoop stress of twenty percent (20%) or more of SMYS, an operator may not use pipe having an outer diameter to wall thickness ratio of seventy to one (70:1) or more that is transported by ship or barge on both inland and marine waterways unless the transportation is performed in accordance with API RP 5LW (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).#

3.Truck. In a pipeline to be operated at a hoop stress of twenty percent (20%) or more of SMYS, an operator may not use pipe having an outer diameter to wall thickness ratio of seventy to one (70:1) or more that is transported by truck unless the transportation is performed in accordance with API RP 5LT (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).#

(G)Records: Material Properties. (192.67)#

1.For steel transmission pipelines installed after July 1, 2020, an operator must collect or make, and retain for the life of the pipeline, records that document the physical characteristics of the pipeline, including diameter, yield strength, ultimate tensile strength, wall thickness, seam type, and chemical composition of materials for pipe in accordance with subsections (2)(B) and (2)(C). Records must include tests, inspections, and attributes required by the manufacturing specifications applicable at the time the pipe was manufactured or installed.#

2.For steel transmission pipelines installed on or before July 1, 2020, if operators have records that document tests, in- spections, and attributes required by the manufacturing speci- fications applicable at the time the pipe was manufactured or installed, including diameter, yield strength, ultimate tensile strength, wall thickness, seam type, and chemical composition in accordance with subsections (2)(B) and (2)(C), operators must retain such records for the life of the pipeline.#

3.For steel transmission pipeline segments installed on or before July 1, 2020, if an operator does not have records necessary to establish the MAOP of a pipeline segment, the operator may be subject to the requirements of subsection (12)#

(U)according to the terms of that subsection.#

(H)Storage and Handling of Plastic Pipe and Associated Components. (192.69) Each operator must have and follow written procedures for the storage and handling of plastic pipe and associated components that meet the applicable listed specifications.#

(3)Pipe Design.#

(A)Scope. (192.101) This section prescribes the minimum requirements for the design of pipe.#

(B)General. (192.103) 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.#

(C)Design Formula for Steel Pipe. (192.105)#

1.The design pressure for steel pipe is determined in accordance with the following formula: P = (2 St/D) × F × E × T where- P = Design pressure in pounds per square inch (kPa) gauge; S = Yield strength in pounds per square inch (kPa) determined in accordance with subsection (3)(D); 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 subsection (3)(E). Additional wall thickness required for concurrent external loads in accordance with subsection (3)(B) may not be included in computing design pressure; F = Design factor determined in accordance with subsection (3)(F); E = Longitudinal joint factor determined in accordance with subsection (3)(G); and T = Temperature derating factor determined in accordance with subsection (3)(H).#

2.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 seventy-five percent (75%) of the pressure determined under paragraph (3)(C)1. if the temperature of the pipe exceeds 900 °F (482 °C) at any time or is held above 600 °F (316 °C) for more than one (1) hour.#

(D)Yield Strength (S) for Steel Pipe. (192.107)#

1.For pipe that is manufactured in accordance with a specification listed in subsection I of Appendix B, the yield strength to be used in the design formula in subsection (3)(C) is the SMYS stated in the listed specification, if that value is known.#

2.For pipe that is manufactured in accordance with a specification not listed in subsection I of Appendix B or whose specification or tensile properties are unknown, the yield strength to be used in the design formula in subsection (3)(C) is one (1) of the following:#

A.If the pipe is tensile tested in accordance with paragraph II-D of Appendix B, the lower of the following:#

(I)Eighty percent (80%) of the average yield strength determined by the tensile tests; or#

(II)The lowest yield strength determined by the tensile tests; or#

B.If the pipe is not tensile tested as provided in subparagraph (3)(D)2.A., twenty-four thousand (24,000) psi (165 MPa).#

(E)Nominal Wall Thickness (t) for Steel Pipe. (192.109)#

1.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 (1) end.#

2.However, if the pipe is of uniform grade, size, and thickness and there are more than ten (10) lengths, only ten percent (10%) of the individual lengths, but not less than ten#

(10)lengths, need to 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 subsection (3)(C) 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 one and fourteen-hundredths (1.14) times the smallest measurement taken on pipe less than twenty inches (20") (508 mm) in outside diameter, nor more than one and eleven-hundredths (1.11) times the smallest measurement taken on pipe twenty inches (20") (508 mm) or more in outside diameter.#

(F)Design Factor (F) for Steel Pipe. (192.111)#

1.Except as otherwise provided in paragraphs (3)(F)2.-4., the design factor to be used in the design formula in subsec- tion (3)(C) is determined in accordance with the following table: Class Location Design Factor (F) 1 0.72 2 0.60 3 0.50 4 0.40#

2.A design factor of 0.60 or less must be used in the design formula in subsection (3)(C) for steel pipe in Class 1 locations that-#

A.Crosses the right-of-way of an unimproved public road without a casing;#

B.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;#

C.Is supported by a vehicular, pedestrian, railroad, or pipeline bridge; or#

D.Is used in a fabricated assembly (including separators, mainline valve assemblies, cross-connections, and river crossing headers) or is used within five (5) 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.#

3.For Class 2 locations, a design factor of 0.50 or less must be used in the design formula in subsection (3)(C) for uncased steel pipe that crosses the right-of-way of a hard surfaced road, a highway, a public street, or a railroad.#

4.For Class 1 and Class 2 locations, a design factor of 0.50 or less must be used in the design formula in subsection (3)(C) for-#

A.Steel pipe in a compressor station, regulating station, or measuring station; and#

B.Steel pipe, including a pipe riser, on a platform located in inland navigable waters.#

(G)Longitudinal Joint Factor (E) for Steel Pipe. (192.113)#

1.The longitudinal joint factor to be used in the design formula in subsection (3)(C) is determined in accordance with the Table 1 of this paragraph (3)(G)1. Table 1 to Paragraph (3)(G)1. Specification Pipe Class Longitudinal Joint Factor (E) ASTM A53/A53M (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)) Seamless 1.00 mula in subsection (3)(C) is determined as follows: Gas Temperature in Degrees Temperature Derating Fahrenheit (Celsius) Factor (T) Electric resistance welded Furnace butt welded 1.00 0.60 Seamless 1.00 250 °F (121 °C) or less 1.000 300 °F (149 °C) 0.967 350 °F (177 °C) 0.933 400 °F (204 °C) 0.900 450 °F (232 °C) 0.867 For intermediate gas temperatures, the derating factor is determined by interpolation.#

(I)Design of Plastic Pipe. (192.121)#

1.Design Pressure. The design pressure for plastic pipe is determined in accordance with either of the following formulas: P = 2 S t × DF (D-t) P = 2 S × DF ASTM A106 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)) ASTM A333/A333M (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)) ASTM A381 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)) ASTM A671 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)) ASTM A672 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)) ASTM A691 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)) API 5L (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)) Seamless 1.00 Electric resistance welded 1.00 Double submerged arc welded 1.00 Electric fusion welded 1.00 Electric fusion welded 1.00 Electric fusion welded 1.00 Seamless 1.00 Electric resistance welded 1.00 Electric flash welded 1.00 Submerged arc welded 1.00 Furnace butt welded 0.60 Other Pipe over 4 inches (102 mm) 0.80 Other Pipe 4 inches (102 mm) or less 0.60#

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

(H)Temperature Derating Factor (T) for Steel Pipe. (192.115) The temperature derating factor to be used in the design for- (SDR-1) where- P = Design pressure, psi (kPa) gauge; S = For thermoplastic pipe, the hydrostatic design base (HDB) is determined in accordance with the listed specification at a temperature equal to 73 °F (23 °C), 100 °F (38 °C), 120 °F (49 °C), or 140 °F (60 °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-3/2008, HDB/PDB/SDB/MRS Policies (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)); 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; and DF = Design Factor, a maximum of 0.32 unless otherwise specified for a particular material in this subsection.#

2.General Requirements for Plastic Pipe and Components.#

A.The design pressure may not exceed a gauge pressure of 100 psi (689 kPa) gauge for plastic pipe.#

B.Plastic pipe may not be used where operating temperatures of the pipe will be-#

(I)Below -20 °F (-29 °C), or -40 °F (-40 °C) if all pipe and pipeline components whose operating temperature will be below -20 °F (-29 °C) have a temperature rating by the manufacturer consistent with that operating temperature; or#

(II)Above the temperature at which the HDB used in the design formula under this subsection is determined.#

C.The wall thickness for thermoplastic pipe may not be less than 0.062 inches (1.57 mm).#

D.All plastic pipe must have a listed HDB in accordance with PPI TR-4/2012 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).#

3.Polyethylene (PE) Pipe Requirements.#

A.The federal regulation at 49 CFR 192.121(c)(1) is not adopted in this rule. (This federal regulation permits higher design pressures for certain types of PE pipe.)#

B.For PE pipe produced on or after January 22, 2019, a DF of 0.40 may be used in the design formula, provided-#

(I)The design pressure does not exceed 100 psig;#

(II)The material designation code is PE2708 or PE4710;#

(III)The pipe has a nominal size (IPS or CTS) of 24 inches or less; and#

(IV)The wall thickness for a given outside diameter is not less than that listed in Table 1 to this part (3)(I)3.B.(IV): Table 1 to Part (3)(I)3.B.(IV) PE Pipe: Minimum Wall Thickness and SDR Values Pipe Size (inches) Minimum Wall Thickness (inches) Corresponding Dimension Ratio (values) ½" CTS 0.090 7 ½" IPS 0.090 9.3 ¾" CTS 0.090 9.7 ¾" IPS 0.095 11 1" CTS 0.099 11 1" IPS 0.119 11 1 ¼" CTS 0.121 11 1 ¼" IPS 0.151 11 1 ½" IPS 0.173 11 2" 0.216 11 3" 0.259 13.5 4" 0.265 17 6" 0.315 21 8" 0.411 21 10" 0.512 21 12" 0.607 21 16" 0.762 21 18" 0.857 21 20" 0.952 21 22" 1.048 21 24" 1.143 21#

4.The federal regulations at 49 CFR 192.121(d) through (f) are not adopted in this rule. (Those federal regulations address design requirements for types of plastic pipe other than PE pipe.)#

(J)Reserved. (192.123)#

(K)Design of Copper Pipe for Repairs. (192.125)#

1.Copper pipe used in mains must have a minimum wall thickness of 0.065 inches (1.65 mm) and must be hard drawn.#

2.Copper pipe used in service lines must have a minimum wall thickness not less than that indicated in the following table: Standard Nominal Wall Tolerance Size (inch) O.D. (inch) Thickness (inch) (millimeter) (millimeters) Nominal (millimeter) 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)#

3.Copper pipe used in mains and services lines may not be used at pressures in excess of 100 psi (689 kPa) gauge.#

4.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 ft3 (6.9/m3) under standard conditions. Standard conditions refers to 60 °F and 14.7 psia (38 °C and one atmosphere) of gas.#

(L)Additional Design Requirements for Steel Pipe Using Alternative Maximum Allowable Operating Pressure. (192.112) The federal regulations at 49 CFR 192.112 are not adopted in this rule.#

(M)Records: Pipe Design. (192.127)#

1.For steel transmission pipelines installed after July 1, 2020, an operator must collect or make, and retain for the life of the pipeline, records documenting that the pipe is designed to withstand anticipated external pressures and loads in accordance with subsection (3)(B) and documenting that the determination of design pressure for the pipe is made in accordance with subsection (3)(C).#

2.For steel transmission pipelines installed on or before July 1, 2020, if operators have records documenting pipe design and the determination of design pressure in accordance with subsections (3)(B) and (3)(C), operators must retain such records for the life of the pipeline.#

3.For steel transmission pipeline segments installed on or before July 1, 2020, if an operator does not have records necessary to establish the MAOP of a pipeline segment, the operator may be subject to the requirements of subsection (12)#

(U)according to the terms of that subsection.#

(4)Design of Pipeline Components.#

(A)Scope. (192.141) This section prescribes minimum requirements for the design and installation of pipeline components and facilities. In addition, it prescribes requirements relating to protection against accidental overpressuring.#

(B)General Requirements. (192.143)#

1.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.#

2.The design and installation of pipeline components and facilities must meet applicable requirements for corrosion control found in section (9).#

3.Except for excess flow valves, each plastic pipeline component installed after April 22, 2019, must be able to withstand operating pressures and other anticipated loads in accordance with a listed specification.#

(C)Qualifying Metallic Components. (192.144) Notwithstanding any requirement of this section which incorporates by reference an edition of a document listed in 49 CFR 192.7 (see (1)(D)) or Appendix B, a metallic component manufactured in accordance with any other edition of that document is qualified for use under this rule if-#

1.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#

2.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 49 CFR 192.7 (see (1)(D)) or Appendix B:#

A.Pressure testing;#

B.Materials; and#

C.Pressure and temperature ratings.#

(D)Valves. (192.145)#

1.Except for cast iron and plastic valves, each valve must meet the minimum requirements of API Specification 6D (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)), 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.#

2.Each cast iron and plastic valve must comply with the following:#

A.The valve must have a maximum service pressure rating for temperatures that equal or exceed the maximum service temperature; and#

B.The valve must be tested as part of the manufacturing, as follows:#

(I)With the valve in the fully open position, the shell must be tested with no leakage to a pressure at least one and one-half (1.5) times the maximum service rating;#

(II)After the shell test, the seat must be tested to a pressure not less than one and one-half (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; and#

(III)After the last pressure test is completed, the valve must be operated through its full travel to demonstrate freedom from interference.#

3.Each valve must be able to meet the anticipated operating conditions.#

4.No valve having shell (body, bonnet, cover, and/or end flange) components made of ductile iron may be used at pressures exceeding eighty percent (80%) 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 eighty percent (80%) of the pressure ratings for comparable steel valves at their listed temperature, if-#

A.The temperature-adjusted service pressure does not exceed 1,000 psi (7 MPa) gauge; and#

B.Welding is not used on any ductile iron component in the fabrication of the valve shells or their assembly.#

5.No valve having shell (body, bonnet, cover, and/or end flange) components made of cast iron, malleable iron, or ductile iron may be used in the gas pipe components of compressor stations.#

6.Except for excess flow valves, plastic valves installed after April 22, 2019, must meet the minimum requirements of a listed specification. A valve may not be used under operating conditions that exceed the applicable pressure and temperature ratings contained in the listed specification.#

(E)Flanges and Flange Accessories. (192.147)#

1.Each flange or flange accessory (other than cast iron) must meet the minimum requirements of ASME/ANSI B16.5 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)), or ANSI/MSS SP-44 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)), or the equivalent.#

2.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.#

3.Each flange on a flanged joint in cast iron pipe must conform in dimensions, drilling, face, and gasket design to ASME/ANSI B16.1 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)) and be cast integrally with the pipe, valve, or fitting.#

(F)Standard Fittings. (192.149)#

1.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 rule or their equivalent.#

2.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.#

3.Plastic fittings installed after April 22, 2019, must meet a listed specification.#

(G)Tapping. (192.151)#

1.Each mechanical fitting used to make a hot tap must be designed for at least the operating pressure of the pipeline.#

2.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.#

3.Where a threaded tap is made in cast iron or ductile iron pipe, the diameter of the tapped hole may not be more than twenty-five percent (25%) of the nominal diameter of the pipe unless the pipe is reinforced, except that-#

A.Existing taps may be used for replacement service, if they are free of cracks and have good threads; and#

B.A one and one-fourth inch (1 1/4") (32 mm) tap may be made in a four-inch (4") (102 mm) cast iron or ductile iron pipe, without reinforcement.#

4.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 six-inch (6") (152 mm) or larger pipe.#

(H)Components Fabricated by Welding. (192.153)#

1.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 the ASME Boiler and Pressure Vessel Code (Section VIII, Division 1) (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).#

2.Each prefabricated unit that uses plate and longitudinal seams must be designed, constructed, and tested in accordance with the ASME Boiler and Pressure Vessel Code (Rules for Construction of Pressure Vessels as defined in either Section VIII, Division 1 or 2) (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)), except for the following:#

A.Regularly manufactured butt-welding fittings;#

B.Pipe that has been produced and tested under a specification listed in Appendix B to this rule;#

C.Partial assemblies such as split rings or collars; and#

D.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.#

3.Orange-peel bull plugs and orange-peel swages may not be used on pipelines that are to operate at a hoop stress of twenty percent (20%) or more of the SMYS of the pipe.#

4.Except for flat closures designed in accordance with ASME Boiler and Pressure Vessel Code, Section VIII, Division 1 or Division 2 (both incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)), flat closures and fish tails may not be used on pipe that either operates at 100 psig (689 kilopascals) or more, or that is more than three inches (3") (76 mm) in nominal diameter.#

5.The test requirements for a prefabricated unit or pressure vessel, defined for this paragraph as components with a design pressure established in accordance with paragraph (4) (H)1. or 2., are as follows:#

A.A prefabricated unit or pressure vessel installed after July 14, 2004, is not subject to the strength testing requirements of paragraph (10)(C)2. provided the component has been tested in accordance with paragraph (4)(H)1. or 2. and with a test factor of at least 1.3 times MAOP;#

B.A prefabricated unit or pressure vessel must be tested for a duration specified as follows:#

(I)A prefabricated unit or pressure vessel installed after July 14, 2004, but before October 1, 2021, is exempt from paragraphs (10)(C)3. and 4. and paragraph (10)(D)3. provided it has been tested for a duration consistent with the ASME BPVC requirements referenced in paragraph (4)(H)1. or 2; and#

(II)A prefabricated unit or pressure vessel installed on or after October 1, 2021, must be tested for the duration specified in either paragraph (10)(C)3. or 4., (10)(D)3., or (10) (E)1., whichever is applicable for the pipeline in which the component is being installed;#

C.For any prefabricated unit or pressure vessel permanently or temporarily installed on a pipeline facility, an operator must either-#

(I)Test the prefabricated unit or pressure vessel in accordance with this subsection and section (10) after it has been placed on its support structure at its final installation location. The test may be performed before or after it has been tied-in to the pipeline. Test records that meet paragraph (10)(I)1. must be kept for the operational life of the prefabricated unit or pressure vessel; or#

(II)For a prefabricated unit or pressure vessel that is pressure tested prior to installation or where a manufacturer's pressure test is used in accordance with paragraph (4)(H)5., inspect the prefabricated unit or pressure vessel after it has been placed on its support structure at its final installation location and confirm that the prefabricated unit or pressure vessel was not damaged during any prior operation, transportation, or installation into the pipeline. The inspection procedure and documented inspection must include visual inspection for vessel damage, including, at a minimum, inlets, outlets, and lifting locations. Injurious defects that are an integrity threat may include dents, gouges, bending, corrosion, and cracking. This inspection must be performed prior to operation but may be performed either before or after it has been tied-in to the pipeline. If injurious defects that are an integrity threat are found, the prefabricated unit or pressure vessel must be either non-destructively tested, re-pressure tested, or remediated in accordance with the applicable requirements in this rule for a fabricated unit or with the applicable ASME BPVC requirements referenced in paragraph (4)(H)1. or 2. Test, inspection, and repair records for the fabricated unit or pressure vessel must be kept for the operational life of the component. Test records must meet the requirements in paragraph (10)(I)1.;#

D.An initial pressure test from the prefabricated unit or pressure vessel manufacturer may be used to meet the requirements of this subsection with the following conditions:#

(I)The prefabricated unit or pressure vessel is newly- manufactured and installed on or after October 1, 2021, except as provided in part (4)(H)5.D.(II);#

(II)An initial pressure test from the fabricated unit or pressure vessel manufacturer or other prior test of a new or existing prefabricated unit or pressure vessel may be used for a component that is temporarily installed in a pipeline facility in order to complete a testing, integrity assessment, repair, odorization, or emergency response-related task, including noise or pollution abatement. The temporary component must be promptly removed after that task is completed. If operational and environmental constraints require leaving a temporary prefabricated unit or pressure vessel under this paragraph in place for longer than thirty (30) days, the operator must notify PHMSA and designated commission personnel in accordance with subsection (1)(M);#

(III)The manufacturer's pressure test must meet the minimum requirements of this rule; and#

(IV)The operator inspects and remediates the prefabricated unit or pressure vessel after installation in accordance with part (4)(H)5.C.(II);#

E.An existing prefabricated unit or pressure vessel that is temporarily removed from a pipeline facility to complete a testing, integrity assessment, repair, odorization, or emergency response-related task, including noise or pollution abatement, and then reinstalled at the same location must be inspected in accordance with part (4)(H)5.C.(II); however, a new pressure test is not required provided no damage or threats to the operational integrity of the prefabricated unit or pressure vessel were identified during the inspection and the MAOP of the pipeline is not increased; and#

F.Except as provided in part (4)(H)5.D.(II) and subparagraph (4)(H)5.E., on or after October 1, 2021, an existing prefabricated unit or pressure vessel relocated and operated at a different location must meet the requirements of this rule and the following:#

(I)The prefabricated unit or pressure vessel must be designed and constructed in accordance with the requirements of this rule at the time the vessel is returned to operational service at the new location; and#

(II)The prefabricated unit or pressure vessel must be pressure tested by the operator in accordance with the testing and inspection requirements of this rule applicable to newly installed prefabricated units and pressure vessels.#

(I)Welded Branch Connections. (192.155) 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.#

(J)Extruded Outlets. (192.157) 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.#

(K)Flexibility. (192.159) 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.#

(L)Supports and Anchors. (192.161)#

1.Each pipeline and its associated equipment must have enough anchors or supports to-#

A.Prevent undue strain on connected equipment;#

B.Resist longitudinal forces caused by a bend or offset in the pipe; and#

C.Prevent or damp out excessive vibration.#

2.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.#

3.Each support or anchor on an exposed pipeline must be made of durable, noncombustible material and must be designed and installed as follows:#

A.Free expansion and contraction of the pipeline between supports or anchors may not be restricted;#

B.Provision must be made for the service conditions involved; and#

C.Movement of the pipeline may not cause disengagement of the support equipment.#

4.Each support on an exposed pipeline operated at a stress level of fifty percent (50%) or more of SMYS must comply with the following:#

A.A structural support may not be welded directly to the pipe;#

B.The support must be provided by a member that completely encircles the pipe; and#

C.If an encircling member is welded to a pipe, the weld must be continuous and cover the entire circumference.#

5.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.#

6.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.#

(M)Compressor Stations-Design and Construction. (192.163)#

1.Location of compressor building. Except for a compressor building on a platform located 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 space around the main compressor building to allow the free movement of firefighting equipment.#

2.Building construction. Each building on a compressor station site must be made of noncombustible materials if it contains either-#

A.Pipe more than two inches (2") (51 mm) in diameter that is carrying gas under pressure; or#

B.Gas handling equipment other than gas utilization equipment used for domestic purposes.#

3.Exits. Each operating floor of a main compressor building must have at least two (2) 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.#

4.Fenced areas. Each fence around a compressor station must have at least two (2) 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 two hundred feet (200') (61 m) of any compressor plant building must open outward and, when occupied, must be openable from the inside without a key.#

5.Electrical facilities. Electrical equipment and wiring in- stalled in compressor stations must conform to NFPA 70 (incor- porated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)), so far as that code is applicable.#

(N)Compressor Stations-Liquid Removal. (192.165)#

1.Where entrained vapors in gas may liquefy under the anticipated pressure and temperature conditions, the compressor must be protected against the introduction of liquids in quantities that could cause damage.#

2.Each liquid separator used to remove entrained liquids at a compressor station must-#

A.Have a manually operable means of removing these liquids;#

B.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#

C.Be manufactured in accordance with section VIII of the ASME Boiler and Pressure Vessel Code (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)) and the additional requirements of paragraph (4)(H)5., except that liquid separators constructed of pipe and fittings without internal welding must be fabricated with a design factor of 0.4 or less.#

(O)Compressor Stations-Emergency Shutdown. (192.167)#

1.Except for unattended field compressor stations of one thousand (1,000) horsepower (746 kilowatts) or less, each compressor station must have an emergency shutdown system that meets the following:#

A.It must be able to block gas out of the station and blowdown the station piping;#

B.It must discharge gas from the blowdown piping at a location where the gas will not create a hazard;#

C.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; and#

D.It must be operable from at least two (2) 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 five hundred feet (500') (153 m) from the limits of the station.#

2.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.#

3.On a platform located in inland navigable waters, the emergency shutdown system must be designed and installed to actuate automatically by each of the following events:#

A.In the case of an unattended compressor station-#

(I)When the gas pressure equals the maximum allowable operating pressure plus fifteen percent (15%); or#

(II)When an uncontrolled fire occurs on the platform; and#

B.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 fifty percent (50%) or more of the lower explosive limit in a building which has a source of ignition. For the purpose of part (4) (O)3.B.(II), an electrical facility which conforms to Class 1, Group D of the National Electrical Code is not a source of ignition.#

(P)Compressor Stations-Pressure Limiting Devices. (192.169)#

1.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 ten percent (10%).#

2.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.#

(Q)Compressor Stations-Additional Safety Equipment. (192.171)#

1.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.#

2.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.#

3.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.#

4.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.#

5.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.#

(R)Compressor Stations-Ventilation. (192.173) 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.#

(S)Pipe-Type and Bottle-Type Holders. (192.175)#

1.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.#

2.Each pipe-type or bottle-type holder must have a minimum clearance from other holders in accordance with the following formula: C = (3D × P × F)/1000 (in inches) (C = (3D × P × F)/6,895) (in millimeters) where- 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, psi (kPa) gauge; and F = Design factor as set forth in subsection (3)(F).#

(T)Additional Provisions for Bottle-Type Holders. (192.177)#

1.Each bottle-type holder must be-#

A.Located on a site entirely surrounded by fencing that prevents access by unauthorized persons and with minimum clearance from the fence as follows: Maximum Allowable Minimum Clearance Operating Pressure feet (meters) Less than 1000 psi (7 MPa) gauge 1000 psi (7 MPa) gauge or more 25 (7.6) 100 (31)#

B.Designed using the design factors set forth in subsection (3)(F); and#

C.Buried with a minimum cover in accordance with subsection (7)(N).#

2.Each bottle-type holder manufactured from steel that is not weldable under field conditions must comply with the following:#

A.A bottle-type holder made from alloy steel must meet the chemical and tensile requirements for the various grades of steel in ASTM A372/A372M (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D));#

B.The actual yield-tensile ratio of the steel may not exceed 0.85;#

C.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;#

D.The holder must be given a mill hydrostatic test at a pressure that produces a hoop stress at least equal to eighty- five percent (85%) of the SMYS; and#

E.The holder, connection pipe, and components must be leak tested after installation as required by section (10).#

(U)Transmission Line Valves. (192.179)#

1.Each transmission line 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:#

A.Each point on the pipeline in a Class 4 location must be within two and one-half (2 1/2) miles (4 kilometers) of a valve;#

B.Each point on the pipeline in a Class 3 location must be within four (4) miles (6.4 kilometers) of a valve;#

C.Each point on the pipeline in a Class 2 location must be within seven and one-half (7 1/2) miles (12 kilometers) of a valve; and#

D.Each point on the pipeline in a Class 1 location must be within ten (10) miles (16 kilometers) of a valve.#

2.Each sectionalizing block valve on a transmission line must comply with the following:#

A.The valve and the operating device to open or close the valve must be readily accessible and protected from tampering and damage; and#

B.The valve must be supported to prevent settling of the valve or movement of the pipe to which it is attached.#

3.Each section of a transmission line 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.#

4.For transmission pipeline segments with diameters greater than or equal to six inches (6") that are constructed after April 10, 2023, the operator must install rupture-mitigation valves (RMV) or an alternative equivalent technology whenever a valve must be installed to meet the appropriate valve spacing requirements of this subsection. An operator seeking to use alternative equivalent technology must notify PHMSA in accordance with the procedures set forth in paragraph (4)(U)6. All RMVs and alternative equivalent technologies installed pursuant to this paragraph must meet the requirements of subsection (12)(Z). The installation requirements in this paragraph do not apply to pipe segments with a potential impact radius (PIR), as defined in 49 CFR 192.903 (incorporated by reference in section (16)), that is less than or equal to one hundred fifty feet (150') in either Class 1 or Class 2 locations. An operator may request an extension of the installation compliance deadline requirements of this paragraph if it can demonstrate to PHMSA, in accordance with the notification procedures in subsection (1)(M), that those installation compliance deadlines would be economically, technically, or operationally infeasible for a particular new pipeline.#

5.For entirely replaced transmission pipeline segments, as defined in subsection (1)(B), with diameters greater than or equal to six inches (6") and that are installed after April 10, 2023, the operator must install RMVs or an alternative equivalent technology whenever a valve must be installed to meet the appropriate valve spacing requirements of this subsection. An operator seeking to use alternative equivalent technology must notify PHMSA in accordance with the procedures set forth in paragraph (4)(U)6. All RMVs and alternative equivalent technologies installed pursuant to this paragraph must meet the requirements of subsection (12)(Z). The requirements of this paragraph apply when the applicable pipeline replacement project involves a valve, either through addition, replacement, or removal. The installation requirements in this paragraph do not apply to pipe segments with a PIR, as defined in 49 CFR 192.903 (incorporated by reference in section (16)), that is less than or equal to one hundred fifty feet (150') in either Class 1 or Class 2 locations. An operator may request an extension of the installation compliance deadline requirements of this paragraph if it can demonstrate to PHMSA, in accordance with the notification procedures in subsection (1)(M), that those installation compliance deadlines would be economically, technically, or operationally infeasible for a particular pipeline replacement project.#

6.If an operator elects to use alternative equivalent technology in accordance with paragraph (4)(U)4. or (4)(U)5., the operator must notify PHMSA in accordance with the procedures in subsection (1)(M). The operator must include a technical and safety evaluation in its notice to PHMSA. Valves that are installed as alternative equivalent technology must comply with subsections (12)(X) and (12)(Z). An operator requesting use of manual valves as an alternative equivalent technology must also include within the notification submitted to PHMSA a demonstration that installation of an RMV as otherwise required would be economically, technically, or operationally infeasible. An operator may use a manual compressor station valve at a continuously manned station as an alternative equivalent technology, and use of such valve would not require a notification to PHMSA in accordance with subsection (1)(M), but it must comply with subsection (12)(Z).#

7.The valve spacing requirements of paragraph (4)(U)1. do not apply to pipe replacements on a pipeline if the distance between each point on the pipeline and the nearest valve does not exceed-#

A.Four (4) miles in Class 4 locations, with a total spacing between valves no greater than eight (8) miles;#

B.Seven and one-half (7 1/2) miles in Class 3 locations, with a total spacing between valves no greater than fifteen#

(15)miles; or#

C.Ten (10) miles in Class 1 or 2 locations, with a total spacing between valves no greater than twenty (20) miles.#

(V)Distribution Line Valves. (192.181)#

1.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, but it must at least provide zones of isolation sized so that the operator could relight the lost customer services within a period of eight (8) hours after restoration of system pressure.#

2.Each regulator station controlling the flow or pressure of gas in a distribution system must have a valve installed on the inlet piping and on the outlet piping at a sufficient distance from the regulator station to permit the operation of the valve during an emergency that might preclude access to the station. An outlet valve on regulator stations will not be required on single-feed distribution systems when the outlet piping size is less than or equal to two inches (2") in nominal diameter.#

3.Each valve on a main installed for operating or emergency purposes must comply with the following:#

A.The valve must be placed in a readily accessible location so as to facilitate its operation in an emergency;#

B.The operating stem or mechanism must be readily accessible; and#

C.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.#

(W)Vaults-Structural Design Requirements. (192.183)#

1.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.#

2.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.#

3.Each pipe entering, or within, a regulator vault or pit must be steel for sizes ten inches (10") (254 mm), and less, except that control and gauge 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.#

(X)Vaults-Accessibility. (192.185) Each vault must be located in an accessible location and, so far as practical, away from-#

1.Street intersections or points where traffic is heavy or dense;#

2.Points of minimum elevation, catch basins or places where the access cover will be in the course of surface waters; and#

3.Water, electric, steam, or other facilities.#

(Y)Vaults-Sealing, Venting, and Ventilation. (192.187) 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:#

1.When the internal volume exceeds two hundred (200) cubic feet (5.7 cubic meters)-#

A.The vault or pit must be ventilated with two (2) ducts, each having at least the ventilating effect of a pipe four inches (4") (102 mm) in diameter;#

B.The ventilation must be enough to minimize the formation of combustible atmosphere in the vault or pit; and#

C.The ducts must be high enough above grade to disperse any gas-air mixtures that might be discharged;#

2.When the internal volume is more than seventy-five (75) cubic feet (2.1 cubic meters) but less than two hundred (200) cubic feet (5.7 cubic meters)-#

A.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;#

B.If the vault or pit is vented, there must be a means of preventing external sources of ignition from reaching the vault atmosphere; or#

C.If the vault or pit is ventilated, paragraph (4)(Y)1. or 3. applies; and#

3.If a vault or pit covered by paragraph (4)(Y)2. 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 twenty to one (20:1), no additional ventilation is required.#

(Z)Vaults-Drainage and Waterproofing. (192.189)#

1.Each vault must be designed so as to minimize the entrance of water.#

2.A vault containing gas piping may not be connected by means of a drain connection to any other underground structure.#

3.All electrical equipment in vaults must conform to the applicable requirements of Class 1, Group D, of the National Electrical Code, NFPA-70 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)). (AA) Risers Installed After January 22, 2019. (192.204)#

1.Riser designs must be tested to ensure safe performance under anticipated external and internal loads acting on the assembly.#

2.Factory assembled anodeless risers must be designed and tested in accordance with ASTM F1973-13 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).#

3.All risers used to connect regulator stations to plastic mains must be rigid and designed to provide adequate support and resist lateral movement. Anodeless risers used in accordance with this paragraph must have a rigid riser casing. (BB) Valve Installation in Plastic Pipe. (192.193) 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. (CC) Protection Against Accidental Overpressuring. (192.195)#

1.General requirements. Except as provided in subsection (4)(DD), 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 subsections (4) (EE) and (FF).#

2.Additional requirements for distributions 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-#

A.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#

B.Be designed so as to prevent accidental overpressur- ing. (DD) Control of the Pressure of Gas Delivered from Transmission Lines and High-Pressure Distribution Systems to Service Equipment. (192.197) If the maximum allowable operating pressure of the system exceeds fourteen inches (14") water column, one (1) 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 with a suitable over-pressure protection device set to limit, to a maximum safe value, the pressure of the gas delivered to the customer and another regulator located upstream from the service regulator. The upstream regulator may not be set to maintain a pressure higher than sixty (60) psi (414 kPa) gauge. 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 sixty (60) psi (414 kPa) gauge or less in case the upstream regulator fails to function properly. This device may be either a relief valve or an automatic shutoff that shuts and remains closed until manually reset, if the pressure on the inlet of the service regulator exceeds the set pressure (sixty (60) psi (414 kPa) gauge or less);#

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. A device or method that indicates the failure of the service regulator must also be provided. The service regulator must be monitored at intervals not exceeding fifteen (15) months, but at least once each calendar year for detection of a failure;#

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 sixty (60) psi (414 kPa) gauge. For higher inlet pressure, the methods in paragraph (4)(DD)1. or 2. must be used; or#

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. (EE) Requirements for Design of Pressure Relief and Limiting Devices. (192.199) Except for rupture discs, each pressure relief or pressure limiting device must-#

1.Be constructed of materials so that the operation of the device will not be impaired by corrosion;#

2.Have valves and valve seats that are designed not to stick in a position that will make the device inoperative;#

3.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;#

4.Have support made of noncombustible material;#

5.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;#

6.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;#

7.Where installed at a district regulator station to pro- tect a pipeline system from overpressuring, be designed and installed to prevent any single incident, for instance, an ex- plosion in a vault or damage by a vehicle, from affecting the operation of both the overpressure protective device and the district regulator;#

8.Except for a valve that will isolate the system under protection from its source of pressure, be designed to prevent unauthorized access to or operation of the following stop valves regardless of installation date:#

A.Any valve that will make the pressure relief valve or pressure limiting device inoperative;#

B.Valves that would bypass the regulator or relief devices; and#

C.Shut-off valves in control lines that, if operated, would cause the regulator or overpressure protection device to be inoperative;#

9.Be designed and installed so that adequate overpressure protection is provided for all town border stations and district regulator stations regardless of installation date;#

10.Where a monitor regulator is used for overpressure protection, be designed and installed to include an internal or separate device or method that indicates a failure of the operating regulator regardless of installation date. The operating regulator must be monitored at least monthly for regulator stations for detection of a failure; and#

11.Where regulators in series or working monitors are used for overpressure protection, be designed and installed to include an internal or separate device or method that indicates a failure of each regulator regardless of installation date. Each regulator must be monitored at least monthly for regulator stations for detection of a failure. When the operator chooses to use a pressure gauge as the separate device to comply with paragraph (4)(EE)10. or 11., the pressure gauge must have the capability to record the high pressure, such as a recording chart or "tattle-tale" needle (a standard sight gauge is not adequate for this purpose). (FF) Required Capacity of Pressure Relieving and Limiting Stations. (192.201)#

1.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 ensure the following:#

A.In a low pressure distribution system, the pressure may not cause the unsafe operation of any connected and properly adjusted gas utilization equipment; and#

B.In pipelines other than a low pressure distribution system-#

(I)If the maximum allowable operating pressure is sixty (60) psi (414 kPa) gauge or more, the pressure may not exceed the maximum allowable operating pressure plus ten percent (10%) or the pressure that produces a hoop stress of seventy-five percent (75%) of SMYS, whichever is lower;#

(II)If the maximum allowable operating pressure is twelve (12) psi (83 kPa) gauge or more, but less than sixty (60) psi (414 kPa) gauge, the pressure may not exceed the maximum allowable operating pressure plus six (6) psi (41 kPa) gauge; or#

(III)If the maximum allowable operating pressure is less than twelve (12) psi (83 kPa) gauge, the pressure may not exceed the maximum allowable operating pressure plus fifty percent (50%).#

2.When more than one (1) 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.#

3.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. (GG) Instrument, Control, and Sampling Pipe and Components. (192.203)#

1.Applicability. This subsection 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.#

2.Materials and design. All materials employed for pipe and components must be designed to meet the particular conditions of service and the following:#

A.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;#

B.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;#

C.Brass or copper material may not be used for metal temperatures greater than four hundred degrees Fahrenheit (400 °F) (204 °C);#

D.Pipe or components that may contain liquids must be protected by heating or other means from damage due to freezing;#

E.Pipe or components in which liquids may accumulate must have drains or drips;#

F.Pipe or components subject to clogging from solids or deposits must have suitable connections for cleaning;#

G.The arrangement of pipe, components, and supports must provide safety under anticipated operating stresses;#

H.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; and#

I.Each control line must be protected from anticipated causes of damage and must be designed and installed to prevent damage to any one (1) control line from making both the regulator and the overpressure protective device inoperative. (HH) Passage of Internal Inspection Devices. (192.150)#

1.Except as provided in paragraphs (4)(HH)2. and (4)(HH)3., 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 in accordance with NACE SP0102, section 7 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).#

2.This subsection does not apply to-#

A.Manifolds;#

B.Station piping such as at compressor stations, meter stations, or regulator stations;#

C.Piping associated with storage facilities, other than a continuous run of transmission line between a compressor station and storage facilities;#

D.Cross-overs;#

E.Sizes of pipe for which an instrumented internal inspection device is not commercially available;#

F.Transmission lines, operated in conjunction with a distribution system which are installed in Class 4 locations;#

G.Gathering lines; and#

H.Other piping that, under 49 CFR 190.9, the administrator finds in a particular case would be impracticable to design and construct to accommodate the passage of instrumented internal inspection devices.#

3.An operator encountering emergencies, construction time constraints, or other unforeseen construction problems need not construct a new or replacement segment of a trans- mission line to meet paragraph (4)(HH)1., if the operator de- termines and documents why an impracticability prohibits compliance with paragraph (4)(HH)1. Within thirty (30) days of discovering the emergency or construction problem, the oper- ator must petition, under 49 CFR 190.9, for approval that design and construction to accommodate passage of instrumented internal inspection devices would be impracticable. If the pe- tition is denied, within one (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.#

(II)Records: Pipeline Components. (192.205)#

1.For steel transmission pipelines installed after July 1, 2020, an operator must collect or make, and retain for the life of the pipeline, records documenting the manufacturing standard and pressure rating to which each valve was manufactured and tested in accordance with this section. Flanges, fittings, branch connections, extruded outlets, anchor forgings, and other components with material yield strength grades of forty- two thousand (42,000) psi (X42) or greater and with nominal diameters of greater than two inches (2") must have records documenting the manufacturing specification in effect at the time of manufacture, including yield strength, ultimate tensile strength, and chemical composition of materials.#

2.For steel transmission pipelines installed on or before July 1, 2020, if operators have records documenting the manufacturing standard and pressure rating for valves, flanges, fittings, branch connections, extruded outlets, anchor forgings, and other components with material yield strength grades of forty-two thousand (42,000) psi (X42) or greater and with nominal diameters of greater than two inches (2"), operators must retain such records for the life of the pipeline.#

3.For steel transmission pipeline segments installed on or before July 1, 2020, if an operator does not have records necessary to establish the MAOP of a pipeline segment, the operator may be subject to the requirements of subsection (12)#

(U)according to the terms of that subsection.#

(5)Welding of Steel in Pipelines.#

(A)Scope. (192.221)#

1.This section prescribes minimum requirements for welding steel materials in pipelines.#

2.This section does not apply to welding that occurs during the manufacture of steel pipe or steel pipeline components.#

(B)General.#

1.Welding is only to be performed in accordance with established written welding procedures that have been qualified under subsection (5)(C) to produce sound, ductile welds.#

2.Welding is only to be performed by welders who are qualified under subsections (5)(D) and (E) for the welding procedure to be used.#

(C)Welding Procedures. (192.225)#

1.Welding must be performed by a qualified welder or welding operator in accordance with welding procedures qualified under section 5 (except for Note 2 in section 5.4.2.2), section 12, Appendix A, or Appendix B of API Standard 1104 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)) or section IX of the ASME Boiler and Pressure Vessel Code (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)) to produce welds meeting the requirements of section (5) of this rule. The quality of the test welds used to qualify welding procedures must be determined by destructive testing in accordance with the referenced welding standard(s).#

2.Each welding procedure must be recorded in detail, in- cluding the results of the qualifying tests. This record must be retained and followed whenever the procedure is used.#

(D)Qualification of Welders and Welding Operators. (192.227)#

1.Except as provided in paragraph (5)(D)2., each welder or welding operator must be qualified in accordance with section 6, section 12, Appendix A, or Appendix B of API Standard 1104 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)) or section IX of the ASME Boiler and Pressure Vessel Code (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)). However, a welder or welding operator qualified under an earlier edition of a standard listed in 49 CFR 192.7 (see subsection (1)(D)) may weld but may not requalify under that earlier edition.#

2.A welder may qualify to perform welding on pipe to be operated at a pressure that produces a hoop stress of less than twenty percent (20%) of SMYS by performing an acceptable test weld, for the process to be used, under the test set forth in subsection I. of Appendix C, which is included herein (at the end of this rule). Each welder who is to make a welded service line connection to a main must first perform an acceptable test weld under subsection II. of Appendix C as a requirement of the qualifying test.#

3.For steel transmission pipe installed after July 1, 2021, records demonstrating each individual welder qualification at the time of construction in accordance with this section must be retained for a minimum of five (5) years following construction.#

(E)Limitations on Welders and Welding Operators. (192.229)#

1.No welder or welding operator whose qualification is based on nondestructive testing may weld compressor station pipe and components.#

2.A welder or welding operator may not weld with a particular welding process unless, within the preceding six#

(6)calendar months, the welder or welding operator was engaged in welding with that process. Alternatively, welders or welding operators may demonstrate they have engaged in a specific welding process if they have performed a weld with that process that was tested and found acceptable under section 6, section 9, section 12, or Appendix A of API Standard 1104 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)) within the preceding seven and one-half (7 1/2) months.#

3.A welder or welding operator qualified under paragraph (5)(D)1.-#

A.May not weld on pipe to be operated at a pressure that produces a hoop stress of twenty percent (20%) or more of SMYS unless within the preceding six (6) calendar months the welder or welding operator has had one (1) weld tested and found acceptable under section 6, section 9, section 12, or#

Appendix A of API Standard 1104 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)). Alternatively, welders or welding operators 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 seven and one-half (7 1/2) months. A welder or welding operator qualified under an earlier edition of a standard listed in 49 CFR 192.7 (see subsection (1)(D)) may weld, but may not requalify under that earlier edition; and#

B.May not weld on pipe to be operated at a pressure that produces a hoop stress of less than twenty percent (20%) of SMYS unless the welder or welding operator is tested in accordance with subparagraph (5)(E)3.A. or requalifies under subparagraph (5)(E)4.A. or B.#

4.A welder or welding operator qualified under paragraph (5)(D)2. may not weld unless-#

A.Within the preceding fifteen (15) calendar months, but at least once each calendar year, the welder or welding operator has requalified under paragraph (5)(D)2.; or#

B.Within the preceding seven and one-half (7 1/2) calendar months, but at least twice each calendar year, the welder or welding operator has had-#

(I)A production weld cut out, tested, and found acceptable in accordance with the qualifying test; or#

(II)For a welder who works only on service lines two inches (2") (51 mm) or smaller in diameter, two (2) sample welds tested and found acceptable in accordance with the test in subsection III. of Appendix C to this rule.#

(F)Protection From Weather. (192.231) The welding operation must be protected from weather conditions that would impair the quality of the completed weld.#

(G)Miter Joints. (192.233)#

1.A miter joint on steel pipe to be operated at a pressure that produces a hoop stress of thirty percent (30%) or more of SMYS may not deflect the pipe more than three degrees (3°).#

2.A miter joint on steel pipe to be operated at a pressure that produces a hoop stress of less than thirty percent (30%), but more than ten percent (10%), of SMYS may not deflect the pipe more than twelve and one-half degrees (12 1/2°) and must be a distance equal to one (1) pipe diameter or more away from any other miter joint, as measured from the crotch of each joint.#

3.A miter joint on steel pipe to be operated at a pressure that produces a hoop stress of ten percent (10%) or less of SMYS may not deflect the pipe more than ninety degrees (90°).#

(H)Preparation for Welding. (192.235) 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.#

(I)Inspection and Test of Welds. (192.241)#

1.Visual inspection of welding must be conducted by an individual qualified by appropriate training and experience to ensure that-#

A.The welding is performed in accordance with the welding procedure; and#

B.The weld is acceptable under paragraph (5)(I)3.#

2.The welds on a pipeline to be operated at a pressure that produces a hoop stress of twenty percent (20%) or more of SMYS must be nondestructively tested in accordance with subsection (5)(J), except that welds that are visually inspected and approved by a qualified welding inspector need not be nondestructively tested if-#

A.The pipe has a nominal diameter of less than six inches (6") (152 mm); or#

B.The pipeline is to be operated at a pressure that produces a hoop stress of less than forty percent (40%) of SMYS and the welds are so limited in number that nondestructive testing is impractical.#

3.The acceptability of a weld that is nondestructively tested or visually inspected is determined according to the standards in section 9 or Appendix A of API Standard 1104 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)). Appendix A of API Standard 1104 may not be used to accept cracks.#

(J)Nondestructive Testing. (192.243)#

1.Nondestructive testing of welds must be performed by any process, other than trepanning, that will clearly indicate the defects that may affect the integrity of the weld.#

2.Nondestructive testing of welds must be performed-#

A.In accordance with written procedures; and#

B.By persons who have been trained and qualified in the established procedures and with the equipment employed in testing.#

3.Procedures must be established for the proper interpretation of each nondestructive test of a weld to ensure the acceptability of the weld under paragraph (5)(I)3.#

4.When nondestructive testing is required under paragraph (5)(I)2., the following percentages of each day's field butt welds, selected at random by the operator, must be nondestructively tested over their entire circumference:#

A.In Class 1 locations, at least ten percent (10%);#

B.In Class 2 locations, at least fifteen percent (15%);#

C.In Class 3 and Class 4 locations, at crossings of major or navigable rivers and within railroad or public highway rights-of-way, including tunnels, bridges, and overhead road crossings, one hundred percent (100%) unless impracticable, in which case at least ninety percent (90%). Nondestructive testing must be impracticable for each girth weld not tested; and#

D.At pipeline tie-ins, including tie-ins of replacement sections, one hundred percent (100%).#

5.Except for a welder or welding operator whose work is isolated from the principal welding activity, a sample of each welder or welding operator's work for each day must be nondestructively tested, when that testing is required under paragraph (5)(I)2.#

6.When nondestructive testing is required under paragraph (5)(I)2., 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.#

(K)Repair or Removal of Defects. (192.245)#

1.Each weld that is unacceptable under paragraph (5)(I)3. must be removed or repaired. A weld must be removed if it has a crack that is more than eight percent (8%) of the weld length.#

2.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.#

3.Repair of a crack or of any defect in a previously repaired area must be in accordance with written weld repair proce- dures that have been qualified under subsection (5)(C). Repair procedures must provide that the minimum mechanical prop- erties specified for the welding procedure used to make the original weld are met upon completion of the final weld repair.#

(6)Joining of Materials Other Than by Welding.#

(A)Scope. (192.271)#

1.This section prescribes minimum requirements for joining materials in pipelines, other than by welding.#

2.This section does not apply to joining during the manufacture of pipe or pipeline components.#

(B)General. (192.273)#

1.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.#

2.Each joint must be made in accordance with written procedures that have been proved by test or experience to produce strong gastight joints.#

3.Each joint must be inspected to ensure compliance with this section.#

(C)Cast Iron Pipe. (192.275)#

1.Each caulked bell and spigot joint in cast iron pipe must be sealed with mechanical leak clamps.#

2.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.#

3.Cast iron pipe may not be joined by threaded joints.#

4.Cast iron pipe may not be joined by brazing.#

(D)Ductile Iron Pipe. (192.277)#

1.Ductile iron pipe may not be joined by threaded joints.#

2.Ductile iron pipe may not be joined by brazing.#

(E)Copper Pipe. (192.279) Copper pipe may not be threaded except copper pipe used for joining screw fittings or valves, which may be threaded if the wall thickness is equivalent to the comparable size of Schedule 40 or heavier wall pipe listed in ASME B36.10M (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)).#

(F)Plastic Pipe (192.281)#

1.General. A plastic pipe joint that is joined by solvent cement, adhesive, 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.#

2.Solvent cement joints. Each solvent cement joint on plastic pipe must comply with the following:#

A.The mating surfaces of the joint must be clean, dry, and free of material which might be detrimental to the joint;#

B.The solvent cement must conform to ASTM D 2564-12 for PVC (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)); and#

C.The joint may not be heated or cooled to accelerate the setting of the cement.#

3.Heat-fusion joints. Each heat-fusion joint on a PE pipe or component, except for electrofusion joints, must comply with ASTM F2620 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)), or an alternative written procedure that has been demonstrated to provide an equivalent or superior level of safety and has been proven by test or experience to produce strong gastight joints, and the following:#

A.A butt heat-fusion joint must be joined by a device that holds the heater element square to the ends of the pipe or component, compresses the heated ends together, and holds the pipe in proper alignment in accordance with the appropriate procedure qualified under subsection (6)(G);#

B.A socket heat-fusion joint must be joined by a device that heats the mating surfaces of the pipe or component uniformly and simultaneously to establish the same temperature. The device used must be the same device specified in the operator's joining procedure for socket fusion;#

C.An electrofusion joint must be made using the equipment and techniques prescribed by the fitting manufacturer or using equipment and techniques shown, by testing joints to the requirements of part (6)(G)1.A.(III), to be equivalent or better than the requirements of the fitting manufacturer; and#

D.Heat may not be applied with a torch or other open flame.#

4.Mechanical joints. Each compression type mechanical joint on plastic pipe must comply with the following:#

A.The gasket material in the coupling must be compatible with the plastic;#

B.A rigid internal tubular stiffener, other than a split tubular stiffener, must be used in conjunction with the coupling;#

C.All mechanical fittings must meet a listed specification based upon the applicable material; and#

D.All mechanical joints or fittings installed after April 22, 2019, must be Category 1 as defined by a listed specification for the applicable material, providing a seal plus resistance to a force on the pipe joint equal to or greater than that which will cause no less than twenty-five percent (25%) elongation of pipe, or the pipe fails outside the joint area if tested in accordance with the applicable standard.#

(G)Plastic Pipe-Qualifying Joining Procedures. (192.283)#

1.Heat fusion, solvent cement, and adhesive joints. Before any written procedure established under paragraph (6)(B)2. 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, as applicable:#

A.The test requirements of-#

(I)In the case of thermoplastic pipe, based on the pipe material, the Sustained Pressure Test or the Minimum Hydrostatic Burst Test per the listed specification requirements. Additionally, for electrofusion joints, based on the pipe material, the Tensile Strength Test or the Joint Integrity Test per the listed specification;#

(II)(Reserved);#

(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 F1055-98(2006) (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D));#

B.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#

C.For procedures intended for non-lateral pipe connections, perform tensile testing in accordance with a listed specification. If the test specimen elongates no less than twenty-five percent (25%) or failure initiates outside the joint area, the procedure qualifies for use.#

2.Mechanical joints. Before any written procedure established under paragraph (6)(B)2. is used for making mechanical plastic pipe joints, the procedure must be qualified in accordance with a listed specification based upon the pipe material.#

3.A copy of each written procedure being used for joining plastic pipe must be available to the persons making and inspecting joints.#

(H)Plastic Pipe-Qualifying Persons to Make Joints. (192.285)#

1.No person may make a plastic pipe joint unless that person has been qualified under the applicable joining procedure by-#

A.Appropriate training or experience in the use of the procedure; and#

B.Making a specimen joint from pipe sections joined according to the procedure that passes the inspection and test set forth in paragraph (6)(H)2.#

2.The specimen joint must be-#

A.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#

B.In the case of a heat fusion, solvent cement, or adhesive joint-#

(I)Tested under any one (1) of the test methods listed under paragraph (6)(G)1., and for polyethylene heat fusion joints (except for electrofusion joints) visually inspected in accordance with ASTM F2620 (incorporated by reference in 49 CFR 192.7 and adopted in subsection (1)(D)), or a written procedure that has been demonstrated to provide an equivalent or superior level of safety, 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 three (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.#

3.A person must be requalified under an applicable procedure once each calendar year at intervals not exceeding fifteen (15) months, or after any production joint is found unacceptable by testing under subsection (10)(G).#

4.Each operator shall establish a method to determine that each person making joints in plastic pipelines in the operator's system is qualified in accordance with this subsection.#

5.For transmission pipe installed after July 1, 2021, records demonstrating each person's plastic pipe joining qualifications at the time of construction in accordance with this section must be retained for a minimum of five (5) years following construction.#

(I)Plastic Pipe-Inspection of Joints. (192.287) No person may carry out the inspection of joints in plastic pipes required by paragraphs (6)(B)3. and (6)(H)2. unless that person has been qualified by appropriate training or experience in evaluating the acceptability of plastic pipe joints made under the applica- ble joining procedure.#

(7)General Construction Requirements for Transmission Lines and Mains.#

(A)Scope. (192.301) This section prescribes minimum requirements for constructing transmission lines and mains.#

(B)Compliance With Specifications or Standards. (192.303) Each transmission line or main must be constructed in accordance with comprehensive written specifications or standards that are consistent with this rule.#

(C)Inspection-General. (192.305) Each transmission line or main must be inspected to ensure that it is constructed in accordance with this rule.#

(D)Inspection of Materials. (192.307) 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.#

(E)Repair of Steel Pipe. (192.309)#

1.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-#

A.The minimum thickness required by the tolerances in the specification to which the pipe was manufactured; or#

B.The nominal wall thickness required for the design pressure of the pipeline.#

2.Each of the following dents must be removed from steel pipe to be operated at a pressure that produces a hoop stress of twenty percent (20%) 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:#

A.A dent that contains a stress concentrator such as a scratch, gouge, groove, or arc burn;#

B.A dent that affects the longitudinal weld or a circumferential weld; and#

C.In pipe to be operated at a pressure that produces a hoop stress of forty percent (40%) or more of SMYS, a dent that has a depth of-#

(I)More than one-quarter inch (1/4") (6.4 mm) in pipe twelve and three-quarters inches (12 3/4") (324 mm) or less in outer diameter; or#

(II)More than two percent (2%) of the nominal pipe diameter in pipe over twelve and three-quarters inches (12 3/4") (324 mm) in outer diameter. For the purpose of this subsection, 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.#

3.Each arc burn on steel pipe to be operated at a pressure that produces a hoop stress of forty percent (40%) 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-#

A.The minimum wall thickness required by the tolerances in the specification to which the pipe was manufactured; or#

B.The nominal wall thickness required for the design pressure of the pipeline.#

4.A gouge, groove, arc burn, or dent may not be repaired by insert patching or by pounding out.#

5.Each gouge, groove, arc burn, or dent that is removed from a length of pipe must be removed by cutting out the damaged portion as a cylinder.#

(F)Repair of Plastic Pipe During Construction. (192.311) Each pipe segment containing imperfection or damage that would impair the serviceability of plastic pipe must be removed. For repair of plastic pipe other than during construction, see subsection (13)(AA).#

(G)Bends and Elbows. (192.313)#

1.Each field bend in steel pipe, other than a wrinkle bend made in accordance with subsection (7)(H), must comply with the following:#

A.A bend must not impair the serviceability of the pipe;#

B.Each bend must have a smooth contour and be free from buckling, cracks, or any other mechanical damage; and#

C.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 twelve inches (12") (305 mm) or less in outside diameter or has a diameter-to-wall thickness ratio less than seventy (70).#

2.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.#

3.Wrought-steel welding elbows and transverse segments of these elbows may not be used for changes in direction on steel pipe that is two inches (2") (51 mm) or more in diameter unless the arc length, as measured along the crotch, is at least one inch (1") (25 mm).#

4.An operator may not install plastic pipe with a bend radius that is less than the minimum bend radius specified by the manufacturer for the diameter of the pipe being installed.#

(H)Wrinkle Bends in Steel Pipe. (192.315)#

1.A wrinkle bend may not be made on steel pipe to be operated at a pressure that produces a hoop stress of thirty percent (30%), or more, of SMYS.#

2.Each wrinkle bend on steel pipe must comply with the following:#

A.The bend must not have any sharp kinks;#

B.When measured along the crotch of the bend, the wrinkles must be a distance of at least one (1) pipe diameter;#

C.On pipe sixteen inches (16") (406 mm) or larger in diameter, the bend may not have a deflection of more than one and one-half degrees (1 1/2°) for each wrinkle; and#

D.On pipe containing a longitudinal weld, the longitudinal seam must be as near as practicable to the neutral axis of the bend.#

(I)Protection From Hazards. (192.317)#

1.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.#

2.Each aboveground transmission line or main, not located 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.#

3.Pipelines, including pipe risers, on each platform located in inland navigable waters must be protected from accidental damage by vessels.#

(J)Installation of Pipe in a Ditch. (192.319)#

1.When installed in a ditch, each transmission line that is to be operated at a pressure producing a hoop stress of twenty percent (20%) 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.#

2.When a ditch for a transmission line or main 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.#

3.Promptly after a ditch for a steel transmission line is backfilled (if the construction project involves one thousand feet (1,000') or more of continuous backfill length along the pipeline), but not later than six (6) months after placing the pipeline in service, the operator must perform an assessment to assess any coating damage and ensure integrity of the coating using direct current voltage gradient (DCVG), alternating current voltage gradient (ACVG), or other technology that provides comparable information about the integrity of the coating. Coating surveys must be conducted, except in locations where effective coating surveys are precluded by geographical, technical, or safety reasons.#

4.An operator must notify PHMSA in accordance with subsection (1)(M) at least ninety (90) days in advance of using other technology to assess integrity of the coating under paragraph (7)(J)3.#

5.An operator of a steel transmission pipeline must develop a remedial action plan and apply for any necessary permits within six (6) months of completing the assessment that identified the deficiency. An operator must repair any coating damage classified as severe (voltage drop greater than sixty percent (60%) for DCVG or 70 dBµV for ACVG) in accordance with section 4 of NACE SP0502 (incorporated by reference in 49 CFR 192.7 and adopted in (1)(D)) within six#

(6)months of the assessment, or as soon as practicable after obtaining necessary permits, not to exceed six (6) months after the receipt of permits.#

6.An operator of a steel transmission pipeline must make and retain for the life of the pipeline records documenting the coating assessment findings and remedial actions performed under paragraphs (7)(J)3.-5.#

(K)Installation of Plastic Pipe. (192.321)#

1.Plastic pipe must be installed below ground level except as provided by paragraphs (7)(K)7., (7)(K)8., and (7)(K)9.#

2.Plastic pipe that is installed in a vault or any other below grade enclosure must be completely encased in gastight metal pipe and fittings that are adequately protected from corrosion.#

3.Plastic pipe must be installed so as to minimize shear or tensile stresses.#

4.Plastic pipe must have a minimum wall thickness in accordance with subsection (3)(I).#

5.Plastic pipe that is not encased must have an electrically conductive 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.#

6.Plastic pipe that is being encased must be inserted into the casing pipe in a manner that will protect the plastic. Plastic pipe that is being encased must be protected from damage at all entrance and all exit points of the casing. The leading end of the plastic must be closed before insertion.#

7.Uncased plastic pipe may be temporarily installed above-ground level under the following conditions:#

A.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 two (2) years, whichever is less;#

B.The pipe either is located where damage by external forces is unlikely or is otherwise protected against such damage; and#

C.The pipe adequately resists exposure to ultraviolet light and high and low temperatures.#

8.Plastic pipe may be installed on bridges provided that it is-#

A.Installed with protection from mechanical damage, such as installation in a metallic casing;#

B.Protected from ultraviolet radiation; and#

C.Not allowed to exceed the pipe temperature limits specified in subsection (3)(I).#

9.Plastic mains may terminate above ground level provided they comply with the following:#

A.The above-ground level part of the plastic main is protected against deterioration and external damage;#

B.The plastic main is not used to support external loads; and#

C.Installations of risers at regulator stations must meet the design requirements of subsection (4)(AA).#

(L)Casing. (192.323) Each casing used on a transmission line or main under a railroad or highway must comply with the following:#

1.The casing must be designed to withstand the superimposed loads;#

2.If there is a possibility of water entering the casing, the ends must be sealed;#

3.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 seventy-two percent (72%) of SMYS; and#

4.If vents are installed on a casing, the vents must be protected from the weather to prevent water from entering the casing.#

(M)Underground Clearance. (192.325)#

1.Each transmission line must be installed with at least twelve inches (12") (305 mm) 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.#

2.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.#

3.In addition to meeting the requirements of paragraph (7)(M)1. or 2., 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.#

4.Each pipe-type or bottle-type holder must be installed with a minimum clearance from any other holder as prescribed in paragraph (4)(S)2.#

(N)Cover. (192.327)#

1.Except as provided in paragraphs (7)(N)3. and 5., each buried transmission line must be installed with a minimum cover as follows: Normal Consolidated Soil Rock Location 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 crossings 36 (914) 24 (610)#

2.Except as provided in paragraphs (7)(N)3. and 4., each buried main must be installed with at least twenty-four inches (24") (610 mm) of cover.#

3.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.#

4.A main may be installed with less than twenty-four inches (24") (610 mm) of cover if the law of the state or municipality-#

A.Establishes a minimum cover of less than twenty-four inches (24") (610 mm);#

B.Requires that mains be installed in a common trench with other utility lines; and#

C.Provides adequately for prevention of damage to the pipe by external forces.#

5.Except as provided in paragraph (7)(N)3., all pipe installed in a navigable river, stream, or harbor must be installed with a minimum cover of forty-eight inches (48") (1219 mm) in soil or twenty-four inches (24") (610 mm) in consolidated rock between the top of the pipe and the underwater natural bottom (as determined by recognized and generally accepted practices).#

(O)Additional Construction Requirements for Steel Pipe Using Alternative Maximum Allowable Operating Pressure. (192.328). The federal regulations at 49 CFR 192.328 are not adopted in this rule.#

(P)Installation of Plastic Pipelines by Trenchless Excavation. (192.329) Plastic pipelines installed by trenchless excavation must comply with the following:#

1.Each operator must take practicable steps to provide sufficient clearance for installation and maintenance activities from other underground utilities and/or structures at the time of installation; and#

2.For each pipeline section, plastic pipe and components that are pulled through the ground must use a weak link, as defined in subsection (1)(B), to ensure the pipeline will not be damaged by any excessive forces during the pulling process.#

(8)Customer Meters, Service Regulators, and Service Lines.#

(A)Scope, Compliance with Specifications or Standards, and Inspections. (192.351) This section prescribes minimum requirements for installing customer meters, service regulators, service lines, service line valves, and service line connections to mains. Service lines must be constructed in accordance with comprehensive written specifications or standards that are consistent with this rule. Service lines must be inspected to ensure they are constructed in accordance with this rule. Each service line 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.#

(B)Service Lines and Yard Lines.#

1.All service line installations and residential/small commercial yard line replacements made after December 15, 1989, must be installed, owned, operated, and maintained by the operator regardless of meter location. Installations of customer-owned service lines and residential/small commercial yard lines, as defined in (1)(B), will not be permitted. If the customer meter is not located within five feet (5') of the building wall, the service line to the customer's nearest building shall be installed, owned, operated, and maintained by the operator. Installation and maintenance may be performed by representatives approved by the operator and the operator must assure that the work performed by approved representatives is in compliance with the requirements of this rule.#

2.Yard lines for large commercial/industrial customers may be installed or replaced, owned, and maintained, except for leak surveys, by the customer, provided the new yard line is cathodically protected, coated steel, or polyethylene pipe and the operator's installation standards are met.#

(C)Customer Meters and Regulators-Location. (192.353)#

1.Each meter and service regulator, whether inside or outside of 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.#

2.Each service regulator installed within a building must be located as near as practical to the point of service line entrance.#

3.Each meter installed within a building must be located in a ventilated place and not less than three feet (3') (914 mm) from any source of ignition or any source of heat which might damage the meter.#

4.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.#

(D)Customer Meters and Regulators-Protection From Damage. (192.355)#

1.Protection from vacuum or back pressure. If the customer's equipment might create either a vacuum or a back pressure, a device must be installed to protect the system.#

2.Service regulator vents and relief vents. Service regulator vents and relief vents must terminate outdoors and the outdoor terminal must-#

A.Be rain and insect resistant;#

B.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#

C.Be protected from damage caused by submergence in areas where flooding may occur.#

3.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.#

(E)Customer Meters and Regulators-Installation. (192.357)#

1.Each meter and each regulator must be installed so as to minimize ­ anticipated stresses upon the connecting piping and the meter.#

2.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 rule.#

3.Connections made of lead and other easily damaged material may not be used in the installation of meters or regulators.#

4.Each regulator equipped with a vent must be vented to the atmosphere outside the building.#

(F)Customer Meter Installations-Operating Pressure. (192.359)#

1.A meter may not be used at a pressure that is more than sixty-seven percent (67%) of the manufacturer's shell test pressure.#

2.Each newly installed meter manufactured after November 12, 1970, must have been tested to a minimum of ten (10) psi (69 kPa) gauge.#

3.A rebuilt or repaired tinned steel case meter may not be used at a pressure that is more than fifty percent (50%) of the pressure used to test the meter after rebuilding or repairing.#

(G)Service Lines-Installation. (192.361)#

1.Depth. Each buried service line must be installed with at least twelve inches (12") (305 mm) of cover in private property and at least eighteen inches (18") (457 mm) of cover in streets and roads, except a plastic service line that is not inserted in a metallic casing must be installed with at least eighteen inches (18") (457 mm) of cover in all locations. However, where an underground structure prevents installation at those depths, the service line must be able to withstand any anticipated external load.#

2.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.#

3.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.#

4.Protection against piping strain and external loading. Each service line must be installed so as to minimize anticipated piping strain and external loading.#

5.Installation of service lines into buildings. Each underground service line installed below grade through the outer foundation wall of a building must-#

A.In the case of a metal service line, be protected against corrosion;#

B.In the case of a plastic service line, be protected from shearing action and backfill settlement; and#

C.Be sealed at the foundation wall to prevent leakage into the building.#

6.Installation of service lines under buildings. Where an underground service line is installed under a building-#

A.It must be encased in a gastight conduit;#

B.The conduit and the service line must extend, if the service line supplies the building it underlies, into a normally usable and accessible part of the building; and#

C.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 above grade, terminating in a rain and insect resistant fitting.#

7.Locating underground service lines. Each underground nonmetallic service line that is not encased must have a means of locating the pipe that complies with paragraph (7)(K)5.#

(H)Service Lines-Valve Requirements. (192.363)#

1.Each service line must have a service line valve that meets the applicable requirements of sections (2) and (4) of this rule. A valve incorporated in a meter bar, that allows the meter to be bypassed, may not be used as a service line valve.#

2.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.#

3.Each service line valve on a high-pressure service line, installed aboveground 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.#

(I)Service Lines-Location of Valves. (192.365)#

1.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.#

2.Outside valves. Each service line must have a shut-off valve in a readily accessible location that is outside of the building.#

3.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.#

(J)Service Lines-General Requirements for Connections to Main Piping. (192.367)#

1.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.#

2.Compression-type connection to main. Each compression-type service line to main connection must-#

A.Be designed and installed to effectively sustain the longitudinal pullout or thrust forces caused by contraction or expansion of the piping, or by anticipated external or internal loading;#

B.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; and#

C.If used on pipelines comprised of plastic, be a Category 1 connection as defined by a listed specification for the applicable material, providing a seal plus resistance to a force on the pipe joint equal to or greater than that which will cause no less than 25% elongation of pipe, or the pipe fails outside the joint area if tested in accordance with the applicable standard.#

(K)Service Lines-Connections to Cast Iron or Ductile Iron Mains. (192.369)#

1.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 subsection (6)(B).#

2.If a threaded tap is being inserted, the requirements of paragraphs (4)(G)2. and 3. must also be met.#

(L)Service Lines-Steel. (192.371) Each steel service line to be operated at less than one hundred (100) psi (689 kPa) gauge must be constructed of pipe designed for a minimum of one hundred (100) psi (689 kPa) gauge.#

(M)Service Lines-Plastic. (192.375)#

1.Each plastic service line outside a building must be installed below ground level, except that-#

A.It may be installed in accordance with paragraph (7) (K)7.; and#

B.It may terminate aboveground level and outside the building, if-#

(I)The aboveground level part of the plastic service line is protected against deterioration and external damage;#

(II)The plastic service line is not used to support external loads; and#

(III)The riser portion of the service line meets the design requirements of (4)(AA).#

2.Plastic service lines shall not be installed inside a building.#

3.Plastic pipe that is installed in a below grade vault or pit must be completely encased in gastight metal pipe and fittings that are adequately protected from corrosion.#

4.Plastic pipe must be installed so as to minimize shear or tensile stresses.#

5.Thermoplastic pipe that is not encased must have a minimum wall thickness of 0.090 inches (0.090"), except that pipe with an outside diameter of 0.875 inches (0.875") or less may have a minimum wall thickness of 0.062 inches (0.062").#

6.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.#

7.For requirements pertaining to installation of plastic service lines by trenchless excavation, see subsection (8)(R).#

(N)New Service Lines Not in Use. (192.379) Each service line that is not placed in service upon completion of installation must comply with one (1) of the following until the customer is supplied with gas:#

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; or#

3.The customer's piping must be physically disconnected from the gas supply and the open pipe ends sealed.#

(O)Service Lines-Excess Flow Valve Performance Standards. (192.381)#

1.Excess flow valves to be used on service lines that operate continuously throughout the year at a pressure not less than ten (10) psi (69 kPa) 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-#

A.Function properly up to the maximum operating pressure at which the valve is rated;#

B.Function properly at all temperatures reasonably expected in the operating environment of the service line;#

C.At ten (10) psi (69 kPa) gauge:#

(I)Close at, or not more than fifty percent (50%) 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 five percent (5%) of the manufacturer's specified closure flow rate, up to a maximum of twenty (20) cubic feet per hour (0.57 cubic meters per hours); 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 (0.01 cubic meters per hour); and#

D.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.#

2.An excess flow valve must meet the applicable requirements of sections (2) and (4).#

3.An operator must mark or otherwise identify the presence of an excess flow valve in the service line.#

4.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.#

5.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 line, such as blowing liquids from the service line.#

(P)Excess Flow Valve Installation. (192.383)#

1.Definitions for subsection (8)(P).#

A.Branched service line means a gas service line that begins at the existing service line or is installed concurrently with the primary service line but serves a separate residence.#

B.Replaced service line means a 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.#

C.Service line serving single-family residence means a gas service line that begins at the fitting that connects the service line to the main and serves only one (1) single-family residence.#

2.Installation required. An excess flow valve (EFV) installation must comply with the performance standards in subsection (8)(O). After April 14, 2017, each operator must install an EFV on any new or replaced service line serving the following types of services before the line is activated:#

A.A single service line to one (1) single family residence;#

B.A branched service line to a single family residence installed concurrently with the primary single family residence service line (i.e., a single EFV may be installed to protect both service lines);#

C.A branched service line to a single family residence installed off a previously installed single family residence service line that does not contain an EFV;#

D.Multifamily residences with known customer loads not exceeding one thousand standard cubic feet per hour (1,000 SCFH) per service, at time of service installation, based on installed meter capacity; and#

E.A single, small commercial customer served by a single service line with a known customer load not exceeding one thousand standard cubic feet per hour (1,000 SCFH), at the time of meter installation, based on installed meter capacity.#

3.Exceptions to excess flow valve installation requirement. An operator need not install an excess flow valve if one (1) or more of the following conditions are present:#

A.The service line does not operate at a pressure of ten#

(10)psi gauge or greater throughout the year;#

B.The operator has prior experience with contaminants in the gas stream that could interfere with the EFV's operation or cause loss of service to a residence;#

C.An EFV could interfere with necessary operation or maintenance activities, such as blowing liquids from the line; or#

D.An EFV meeting performance standards in subsection (8)(O) is not commercially available to the operator.#

4.Customer's right to request an EFV. Existing service line customers who desire an EFV on service lines not exceeding one thousand standard cubic feet per hour (1,000 SCFH) and who do not qualify for one (1) of the exceptions in paragraph (8)(P)3. may request an EFV to be installed on their service lines. If an eligible service line customer requests an EFV installation, an operator must install the EFV at a mutually agreeable date. The operator's rate-setter determines how and to whom the costs of the requested EFVs are distributed.#

5.Operator notification of customers concerning EFV installation. Operators must notify customers of their right to request an EFV in the following manner:#

A.Except as specified in (8)(P)3. and (8)(P)5.E., each operator must provide written or electronic notification to customers of their right to request the installation of an EFV. Electronic notification can include emails, website postings, and e-billing notices;#

B.The notification must include an explanation for the service line customer of the potential safety benefits that may be derived from installing an EFV. The explanation must include information that an EFV is designed to shut off the flow of natural gas automatically if the service line breaks;#

C.The notification must include a description of EFV installation and replacement costs. 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.The notification must indicate that if a service line customer requests installation of an EFV and the load does not exceed one thousand standard cubic feet per hour (1,000 SCFH) and the conditions of paragraph (8)(P)3. are not present, the operator must install an EFV at a mutually agreeable date; and#

E.Operators of master-meter systems may continuously post a general notification in a prominent location frequented by customers.#

6.Operator evidence of customer notification. An operator must make a copy of the notice or notices currently in use available during inspections conducted by designated commission personnel.#

7.Reporting. Except for operators of master meter systems, each operator must report the EFV measures detailed in the annual report required by 20 CSR 4240-40.020(7)(A).#

(Q)Manual Service Line Shut-Off Valve Installation (192.385)#

1.Definitions for subsection (8)(Q). Manual service line shut-off valve means a curb valve or other manually operated valve located near the service line that is safely accessible to operator personnel or other personnel authorized by the operator to manually shut off gas flow to the service line, if needed.#

2.Installation requirement. The operator must install either a manual service line shut-off valve or, if possible, based on sound engineering analysis and availability, an EFV for any new or replaced service line with installed meter capacity exceeding 1,000 SCFH, where replaced service line is defined in paragraph (8)(P)1.#

3.Accessibility and maintenance. Manual service line shut-off valves for any new or replaced service line must be installed in such a way as to allow accessibility during emer- gencies. Manual service shut-off valves installed under this subsection are subject to regular scheduled maintenance, as documented by the operator and consistent with the valve manufacturer's specification.#

(R)Installation of Plastic Service Lines by Trenchless Excavation. (192.376) Plastic service lines installed by trenchless excavation must comply with the following:#

1.Each operator shall take practicable steps to provide sufficient clearance for installation and maintenance activities from other underground utilities and structures at the time of installation; and#