The Dow Chemical Company — Pipeline Safety Interpretation

Page 1U.S. Department ofTransportation Pipeline and Hazardous Materials Safety Administration 1200 New Jersey Avenue SE Washington DC 20590 DEC 0 4 2 0 17 Ms. Jennifer Ashcraft Senior Regulatory Compliance Specialist The Dow Chemical Company 2301 N. Brazosport Blvd., B-101 Freeport, TX 77541-3257 Dear Mr. Ashcraft: In a March 31, 201 7, letter to the Pipeline and Hazardous Materials Safety Administration (PHMSA), you requested an interpretation of 49 CFR Part 192 for your single gas line at Dow Chemical Company(Dow)'s Seadrift Operations manufacturing facility in Seadrift, Texas. You had previously requested an interpretation on these facts from the Railroad Commission of Texas. You provided the following information Seadrift Operations is located on 4, 700 acres with 9 manufacturing plants representing many of Dow's global businesses. Seadrift Operations purchases methane from multiple pipeline operators to use for operating various area of the plant. All of the gas is delivered to Dow on Dow property. Dow is the customer and the consumer of all purchased gas. Dow meets the definition of a" large volume customer" with respect to 49 CFR Part 192. All of the in-plant gas piping that Dow owns and operates is located on Dow property, with the exception of 220-feet of a single 1.5-inch line that crosses a public thoroughfare (TX-185). You stated that the 1.5-inch pipeline carries methane and operates at < 20% SMYS. You provided regulatory information on 49 CFR Part 195 that you believe would exclude this line from Federal pipeline safety regulations if this line were a hazardous liquid line. Therefore, you requested PHMSA's interpretation and position on the applicability of the in-plant piping exemption to this gas line and in general for applying to other Dow situations. Also, you referenced 2010 and 1998 PHMSA interpretations that you believe are applicable to your request. The 2010 interpretation states that "piping operated by the facility operator entirely on the grounds of the facility is considered 'in-plant piping' and would not be subject to the pipeline safety regulations." It continues, however, that the gas pipelines at issue in that interpretation "are not located on the geographically contiguous grounds of a facility. Rather these lines depart [the operator's property] and cross roads and highways accessed by the public, albeit for relatively short distances. To the extent such lines are not on plant property, they are subject to The Pipeline and Hazardous Materials Safety Administration, Office of Pipeline Safety provides written clarifications of the Regulations (49 CFR Parts 190-199) in the form of interpretation letters. These letters reflect the agency's current application of the regulations to the specific facts presented by the person reqµesting the clarification. Interpretations do not create legally-enforceable rights or obligations and are provided to help the public understand how to comply with the regulations.#

Page 22 the pipeline safety laws." (emphasis added). The interpretation also states that although PHMSA has chosen not to enforce the Federal gas pipeline safety regulations in Part 192 on such lines, it would "not object to a State regulating the portions of such lines that are not on plant property." While the "Regulatory Review: Hazardous Liquid and Carbon Dioxide Pipeline Safety Standards" rulemaking (59 FR 33,388 (June 28, 1994)) and 1998 PHMSA interpretation cited by Dow both state there is an exception for in-plant piping that crosses a single public thoroughfare, the scope of the rulemaking and 1998 interpretation was Part 195 of PHMSA's regulations. Many of the Part 192 and 195 regulations are similar, but in this case, the 2010 interpretation clearly shows that the application of in-plant piping is different for Part 192 than the rulemaking and 1998 interpretation treat in-plant piping for Part 195. Because the 2010 interpretation directly addresses Part 192, as does Dow's request, the 2010 interpretation governs Dow's situation. Based upon the 2010 interpretation, Dow's 1.5-inch pipeline is subject to Federal pipeline safety regulations. It leaves Dow's property and crosses a public highway before reentering Dow's property. As pointed out in the 2010 interpretation, "To the extent such lines are not on plant property, they are subject to the pipeline safety laws." Likewise, though PHMSA may choose not to enforce its regulations on these short pipelines, but PHMSA does not object where the state regulating the portions of such lines does enforce the applicable regulations. Therefore, because the Railroad Commission of Texas has regulatory authority over pipeline safety in Texas, it may enforce its pipeline safety regulations on the 1.5-inch pipeline with PHMSA's support. It should be noted that the Railroad Commission of Texas has regulatory authority over intrastate gas pipeline safety in Texas and may impose additional or more stringent safety measures than the Federal regulations. lfwe can be of further assistance, please contact Tewabe Asebe at 202-366-5523. Sincerely, Jo Director, Office of Standards and Rulemaking The Pipeline and Hazardous Materials Safety Administration, Office of Pipeline Safety provides written clarifications of the Regulations (49 CFR Parts 190-199) in the form of interpretation letters. These letters reflect the agency's current application of the regulations to the specific facts presented by the person requesting the clarification. Interpretations do not create legally-enforceable rights or obligations and are provided to help the public understand how to comply with the regulations.#

Page 3March 31, 2017 CERTIFIED MAIL #7015 0640 0001 7680 2104 The Dow Chemical Company 2301 N. Brazosport Blvd. Freeport, Texas 77541 USA Mr. John A. Gale Director, Office of Standards and Rulemaking PHMSA, U.S. Departnient of Transportation 1200 New Jersey Averue, SE Washington, D.C. 2050-0001 APR 052011 Re: Request for Witten Regulatory Interpretation on PHMSA Jurisdiction The Dow Cheiiical Company Dear Mr. Gale: The Dow Chemical Cdmpany, respectfully requests a written interpretation concerning the applicability of PHMSA Pipeline Stfety Regulations contained in 49 CFR § 192 to a single gas line at Dow's Seadrift Operations manufactu4ng facility in Seadrift, Texas. Tn Texas, regulatory authority over pipeline safety is delegated to the Railroad Commission of Texas, who has adopted the federal pipeline safety standards, including 49 CFR § 192, in Texas Administrative Code, Title 16, Part 1, Chapter 8 (referenced as 16 TAC §8). Seadrift Operations is ocated on 4,700 acres with 9 manufacturing plants representing many of Dow's global businesses. Se*lrift Operations purchases methane from multiple pipeline operators to use for operating various area of the plant. All of the gas is delivered to Dow on Dow property. Dow is the customer and the consmer of all purchased gas. Dow meets the definition of a "large volume customer" with respect to 49 CF1 Part 192. All of the in-plant gas piping that Dow owns and operates is located on Dow property, with th exception of 220-feet of a single 1 .5 -inch line that crosses a public thoroughfare (TX-185). A map of this line is provided in Attachment 1. Dow understands that, y definition, transmission ends upon delivery to a large volume customer. Dow also understands that 1irt 192 applies to pipelines operating at >20% SMYS. This 1.5-inch methane line is not involved in transportation in or affecting interstate commerce, and it operates at <20% SMYS; therefore, Dow believes that this line is not a transmission line. This line is also clearly not a gathering line, since it doesn't stjtrt at a production facility. The only other Part 192 definition for a regulated pipeline is distribution line, which is a pipeline other than a transmission or gathering line. PHMSA's Inspector Training & Qualifications Glossary further defines a distribution line as, "A pipeline that carries or controls the supply of natural gas from a town border or city gate and moves the gas to the customer. (A distribution line is network ofpiping downstream ofa distribution center used to supply gas to its customers. In practica terms, the distribution piping ends at the customer's regulator and/or meter.)" littn://www.ohnisa.clot eov/staticfiles/PHMSA/Pioeliiie/TOGlossarv/G!ossarv.htnil#DL. This line is not a distribution line as dfined in PHMSA' s Inspector Training & Qualifications Glossary. If this was a liquid 1in4 it would very simply meet the exemption for "in-plant piping" described in 49 CFR § 195.1(b)(8) for, 'Transportation of hazardous liquid or carbon dioxide through onshore production (including flow lines), efining, or manufacturing facilities or storage or in-plant piping systems associated with such fcilities." In 59 FR 33389 arid PHMSA Interpretation #PI-98-006 (Nov 18, 1998), PHMSA appears to fu9ther clarify that if the grounds of a plant are separated by a single public thoroughfare, transfer piping that crosses the thoroughfare from one part of the plant to the other is on plant grounds for purposes of the in-plant piping definition. Although there is no specific regulatory in-#

Page 4Mr. John A. Gale PHMSA, U.S. Dc March 31, 2017 Page 2 of Transportation plant piping exemption or gas lines, PHMSA' s Interpretation #PI-09-0020 (Aug 11, 2010) appears to address the issue of regilation of "in-plant" gas pipelines, in stating that, "Historically, PHMSA has elected not to apply the Federal gas pipeline safety regulations to such lines if they are associated with the plant, meaning they are perated by plant personnel, run between plant buildings, and are less than one mile in length." (Pleaselsee Attachment 2 for these references.) In summary, Dow belie'yes that this line should not be regulated under the Pipeline Safety regulations, since it is not a gathering line, a transmission line, or a distribution line. The particular facts in this situation also may help 1HMSA to reach the decision that this particular pipeline should not be so regulated. Dow also repectfully requests PHMSA' s interpretation and position on the applicability of the in-plant piping exemptidrn to this gas line and in general for applying to other Dow situations. If you would like to disquss, or need any additional information for your consideration, please do not hesitate to contact me a (979) 238-0361. Sincerely, ershct Sr. Regulatory Complia ce Specialist The Dow Chemical Cor!ipany 2301 N. Brazosport BlvL, B-101 Freeport, Texas 7754 1-257 (979) 238-0361 Enclosures: Attachmeit 1- Map of Seadrift Operations and Pipeline Attachmel* 2- 59 FR 33389; PHMSA Interpretation #PI-98-006 (Nov 18, 1998); PHMSA's Interpretation #PI-09-0020 (Aug 11, 2010) cc: Stephanie Weidman PHMSA Program Manager, Railroad Conmuission of Texas, Austin#

Page 5Attachment 1 Map of Seadrift Operations and Pipeline#

Page 6The Dow Chemical Company, Seadrift Operations Manufacturing Facility, Seadrift, Texas gle Earth mKes1 1 A Zoomed-view Pipeline leaves Dow fence-line, crosses one public thoroughfare (HVVY TX-i 85), and re- enters Dow fence-line. The railroad tracks that this line crosses are on Dow property and are operated by Dow.#

Page 7Attachment 2 59 FR 33389; PHMSA Interpretation #PI-98-006 (Nov 18, 1998); PHMSA's Interpretation #PI-09-0020 (Aug 11, 2010)#

Page 83388 Federal Register I Vol. 59, No.123 / Tuesday, June 28, 1994/ Rules and Regulations DEPARTMENT OF TRANSPORTATION Research and Special Programs Administration 49 CFR Part 195 (Docket P5-127; Amdt. 195-52) R1N2137-AC27 Regulatory Review: Hazardous Liquid and Carbon Dioxide Pipeline Safety Standards AGENCY: Research and Special Programs Administration (RSPA), DOT. ACTION: Final rule. SUMMARY: This rulemaking amends miscellaneous hazardous liquid and carbon dioxide pipeline safety standards to provide clarity, eliminate unnecessary or overly burdensome requirements, and foster economic growth. The changes result from the regulatory review RSPA carried out in response to the President's directive of January 28, 1992, on reducing the burden of government regulation. The changes reduce costs in the liquid pipeline industry without compromising safety. EFFECTIVE DATE This regulation is effective July 28, 1994. The incorporation by reference of certain publications listed in the regulations is approved by the Director of the Federal Register as of July 28, 1994. FOR FURThER INFORMATION CONTACT: J. Willock, (202) 366-2392, regarding the subject matter of this final rulemaking, or the Dockets Unit, (202) 366-5046, regarding copies of this final rtilemaking or other material that is referenced heiein. SUPPLEMENTARY INFORMATION: Background In a January 28, 1992, memorandum, the President wrote to Department and agency heads about the need to reduce the burden imposed by government regulation. The President was concerned that agencies were not doing enough to review and revise existing regulations to eliminate unnecessary and overly burdensome requirements. The President recognized that regulations that donot keep pace with new technologies and innovations impose needless costs and impede economic growth. In response to the President's memorandum, DOT published a notice requesting public comment on the Department's regulatoryprograms (57 FR 4745; Feb. 7, 1992). Commenters were asked to identify regulations that substantially impede economic growth, may no longerbe necessary, are unnecessarily burdensome, impose needless costs or red tape, or overlap or conflict with. other DOT or federal¯ regulations. The deadline for submitting comments was March 2, 1992. RSPA received comments from six organizations about the pipeline safety regulations in part 195. Comments were from three regulated pipeline companies, a pipeline trade association, a state pipeline safety agency, and a federal agency. RSPA considered all comments in its review of the regulations, and these comments are available in the docket. Some comments will be considered in future rulemakings. Additionally, RSPA has published a separate rulemaking "Update of Standards Incorporated by Reference" (58 FR 14519; March 18, 1993) which updates the editions of the industry standards that are incorporated in part 195. On November 27, 1992, RSPA published a Notice of Proposed Rulemaking; NPRM, (57 FR 56304) proposing 18 changes to the regulations based on the comments received from the public and asked for further comments regarding the proposed changes. RSPA received comments from 21 organizations: 15 pipeline companies, 3 pipeline trade associations, 2 environmental organizations, and 1 county government. RSPA considered all comments in preparation of the final rulemaking and the comments are available in the Docket.- Advisory Committee The Technical Hazardous Liquid Pipeline Safety Standards Committee (THLPSSC), consisting of 15 members, was established by statute to consider the feasibility, reasonableness, and practicability of proposed pipeline regulations, RSPA implemented the committee balloting process by mail. After initial balloting, the process allowed each member to review the ballots, including comments, of all other members, and to change his or her vote or initial comment if desired. Although some THLPSSC members did not vote on every proposed change, a tally of the second ballots showed that a large majority of THLPSSC members found all -the proposed chan8es technically feasible, reasonable, and practicable. Nonetheless, in developing the final regulations, RSPA considered all final THLPSSC votes and comments, including minority positions. The following discussion explains how RSPA treated THLPSSC positions and public comments on the proposed amendments in developing the final rule... Changes to Part 195 Safety Standards The following discussion explains the changes to various standards in part 195: Section 195.1 Applicability. Offshore production. Part 15 does not apply to pipelines used in offshore production, whether on the Outer Continental Shelf or in state offshore waters. However, this exception is clearly statedin part 195 only for production on the Outer Continental Shelf ( 195.1(b)(5)). To clarify that all offshore pipelines used in production are outside part 195, RSPA proposed to delete from § 195.1(b)(5) the phrase "on the Outer Continental Shelf'. The 10 THLPSSC members who voted on the proposed amendment to § 195.1(b)(5) all approved the amendment. In addition, RSPA received comments from three operators and two pipeline- related associations in support of the amendment and no adverse comments. Therefore, § 195.1(b)(5) is amended as proposed in the NPRM. ¯ We also requested comments on '.whether there is a gap in the regulation of production lines in state offshore waters. Only one commenter responded. This commenter opined that existing state and federal programs adequately regulate production lines in state waters. In Louisiana, the Departments of Natural Resources and Environmental Quality were said to have comprehensive regulations on facility installation, operation, integrity, and removal, and sufficient authority to address any "gap" that is identified. Since the other states with production lines in state waters have similar regulations, RSPA does not believe there is a gap in the regulation of production lines in state waters. In-plant piping. Part 195 does not apply to pipeline transportation through onshore production, refining, or manufacturing facilities, or storage or in-plant piping systems associated with such facilities ( 195.1(b)(6)). Because the physical distinction between a regulated pipeline serving a plant and unregulated in-plant piping is unclear, RSPA proposed to add a definition of "in-plant piping system" to § 195.2. The definition proposed was: TiiIant piping system means piping that is located on the grounds of a plant and used to transfer hazardous liquid or carbon dioxide between plant facilities or between plant facilities and a pipeline, not including any device and associated piping that are necessary to#

Page 9Federal Register./ Vol. 59, No. 123 I Tuesday, June 28, 1994 I Rules and Regulations control pressure in the pipeline." The NPRM explained that we would consider in-plant piping to extend to the plant boundary in the absence of a necessary pressure control device on plant grounds. All ten THLPSSC members who voted on this proposal supported it. However, four members believed that because the NPRM primarily concerned pipeline transportation rather than production, refining, or manufacturing plants, it did not give plant owners adequate notice that the proposed definition could affect plant piping. These members wanted RSPA to publish a separate NPRM on the subject of in-plant pi,ping. RSPA does not agree that another NPRM is needed. The subject of in-plant piping and the associated issues were clearly discussed in the published NPRM. Also, all interested persons. including plant owners as well as pipeline operators, were given an opportunity to comment on the subject of in-plant piping. ¯ RSPA received comments on the proposed definition from seven operators, two pipeline-related associations, and one state agency. Two operators and one association fully supported the proposal. One operator and a pipeline-related association thought plant owners were not adequately notified of the proposed rule, and that RSPA should treat the subject in a separate NPRM. Our position on this issue is given supra in response to a similar criticism by four THLPSSC members. Another operator was concerned that the proposed definition would cause operator-owned components, such as pipe, meters, instruments, and manifolds, that are located on plant grounds downstream from the operator's pressure control device to fall outside part 195. The operator was worried that other agencies would .rgulate these components as non-transportation related facilities. We are not -persuaded, however, that the potential for such regulation i sufficient reason to exclude the components from the definition of in. p1ant piping system. The aim of the proposed definition was to distinguish unregulated piping, not to limit the jurisdiction of other government agencies.- - ¯ In contrast, an operator of gathering and processing facilities was concerned that part 195 would apply to plant piping that ties between anynecessary - pressure' control device and the connection to a pipeline. This commenter apparently did not realize- that such piping is subject to part 195. RSPA has applied part 195 to such -piping because. it is subject to pressure 33389 which is controlled by idevice operator and association argued that the operators must have to meet off-grounds segments pose minimum § 195.406(b). However, this application risk to public safety and the has had little effect On plant owners, ¯ environment, because the, segments because we hold the pipeline operator, generally are located'in industrial areas, not the plant owner, responsible for roadways, or railways. The association compliance.- further argued that a plant has the same An-operator commenting-on the plant operational control, including response device exclusion in the proposed capability, over the off-grounds definition advised us to change "control segments as it does over piping on plant pressure" to "prevent overpressure." grounds,- This commenter said the change would In response to these comments, we avoid making pipeline operators note that § 195.1(b)(6) echoes section responsible under part 195 for 201(3) of the Hazardous Liquid Pipeline ponessential pressure control devices. Safety Act of 1979 (HLPSA), (49 U.S.C. We agree the suggested 'rewording app. 2001(3)), which excludes certain would better convey the intent of the "in-plant piping systems" from proposal. But, in the final definition, we regulation under the HLPSA; Since have changed "control pressure in the 'neither the HLPSA nor its legislative pipelin&' to "control pressure in the 'history explain "in-plant piping," we pipeline under § 195.406(b)" to convey adopt an ordinary, reasonable the intent even more precisely. understanding of the term. Therefore, The state agency commented that if we do notaccept the interpretation that piping on plant grounds does not the term includes piping that crosses the include a device necessary-to control' property of others outside plant pipeline pressure, the jurisdiction of grounds. However, many plants are part 195 over the pipeline should not separated by a public thoroughfare, and end at the plant boundary. Instead, the plant transfer'piping crosses the- state agency recommended ending thoroughfare. A single public jurisdiction at a component inside the thoroughfare would include any road, plant, such as a flange, where the from a country lane to an interstate pipeline can be isolated for purposes of highway, but it does not include a testing. Although operators may use- railroad. Because transfer piping that such components, part 195 does not crosses such thoroughfares is require that they be on the pipeline. comparable in most respects to other in- Also, we believe the plant boundary is plant piping, RSPA considers the in- a mOre convenient demarcation of in- plant piping exception to include the plant piping than -an unspecific inside- thoroughfare crossings. The the-plant component. Thus, the state thoroughfare exception does not apply agency's comment is not incorporated in to inter-facility lines or delivery lines, the final definition. because these lines are distinct from in- The state agency, an operator, and a ,'plant piping. We did not intend the pipeline-related association were proposed-definition of "in-plant piping concerned that because segments of systems" to expand our present transfer piping located off plant grounds - interpretation of the term. So the final were not included in the proposed definition does not incorporate any of definition, a large number of short the comments concerning piping- pipelines would come under part 195.- 'located off plant grounds other than for RSPA recognizes that production, thoroughfare crossings. refining, or manufacturing plants often However the proposed definition's install transfer piping off plant grounds. first use of the term "pipeline" is A plant may use this piping to transfer changed to "pipeline or other mode of hazardous liquids between its different transportation." This change is needed. facilities located on the same grounds; to include, within the definition, piping between its different facilities located on plant grounds that transfer hazardous on separate grounds'(usually separated liquid or carbon dioxide between plant by a roadway,'railway, waterway, or' facilities and modes of transportation- - industrial area); between its facilities and a transportation system, such as a other than pipeline. Terminalfacilities. Part 195 does not railroad or pipeline; or between its apply to the transportation of hazardous facilities and the facilities of another liquid or carbon dioxide by vessel,' - plant or industrial consumer. The three- - aircraft, tank truck, tank car, or other commenters thought the Off-grounds', vehicle, or by terminal facilities used segments should qualify as in-plant- exclusively to transfer hazardpus liquid piping if they connect facilities of the- or carbon dioxide between such modes same plant. The assOciatiOn 'also wanted of transportation ( 195i(b)(7)). RSPA to include under the definition' off- proposed to amend § 195.1(b)(7) to grounds segments that conned facilities, clarify that terminal facilities lOcated off of different plants. In addition, the terminal grounds are subject to part 195,#

Page 1033390 Fuderal Rester / Vol. 59, No. 123, I Tuesday, June 28, 1994 I Rulas and Regulations and to distinguish unregulated terminal facilities from a regulated pipeline entering or leaving the terminal. As with the proposed in-plant piping definition, any device and associated piping on terminal grounds necalsary to-control pressure in a regulated pipeline would not be excepted from part 195. The THLPSSC voted to approve this proposal, but four members believed the NPRM did not, give terminal owners adequate notice that the proposed¯ amendment could affect their piping. These members wanted RSPA to publish a separate NPRM on the subject. For the reasons stated supra in response to a similar argument by these THLPSSC members concerning implant piping, RSPA does not agree that another NPRM is needed. Five oper tors and two pipeline- related associations commented on the propos&l amendment to § 195.i(b)(7). Of'these commenters, two operators and one association agreed with the proposal. A few commenters eçpressed the same concerns about the proposed amendment to §.195.1(b)(7) as they did, about the proposed in-plant piping definition. These concerns were that the NPRM did not adequately notify plant (terminal) owners of the proposed rule, and that some operator-owned components located on plant (terminal) grounds would fall outside part 195. Our response to these concerns is the same as stated supra regarding in-plant piping. In regard to transfer lines located outside terminal grounds at ports, an operator and a pipeline-related association pointed out that the U.S. Coast Guard regulates transfers between terminal storage and dock facilities.. These commenters suggested that RSPA and Coast Guard develop a memorandum of wuierstanding to limit Coast Guard's regulatipns to dock facilities. We recognize that Coast Guard and RSPA jurisdictions overlap in port areas, but the two agencies have different responsibilities. Also, the overlap does not automatically result in regulatory conflicts, and the commenters did not mention any. Nonetheless, though we have not changed the final rule as a result of this comment, in enforcing part 195 at port areas, RSPA will act appropriately to resolve any unnecessary regulatory burdens. Carbon dioxide injection system. Section 195.1(b)(8) provides that part 195 does not apply to "lt]ransportation' of carbon dioxide downstream from a point in the vicinity of the well site at which carbon dioxide is delivered to a production facihity" RSPA proposed to¯ amend this section to clarify that the exception covers pipelines used in the- injection of carbon dioxidefor oil recovery operations. The THLPSSC approved the proposed amendment (10 voted in favor and 5 did not vote), and w.e received no adverse comments from the-public. The- proposed amendment to § 195.1(b)(8) is, therefore, adopted as final. Section 195.2 Definitions. The proposed revision of the definition of "Secretary" is -not adopted in this rulemaking. Instead, it is being handled in an omnibus rulemaking covering all regulations involving pipeline safety. The definition of "In-plant piping system" is discussed above in § 195.1 Applicability.- - Two commenters objected to the proposed definition for petroleum products because of its use of the terms "flammable", "toxic", and "corrosive" which are not defined-under part 195. The commenters stated that absent specific definitions for these terms, their applicability could be unclear. RSPA agrees with the comments about the lack of clarity in the proposed definition for petroleum products. So, the final rule for this section includes new definitions for "flammable", "toxic", and "corrosive" that come from the definitions contained in 49 CFR part 173 for Transportation and Packaging of Hazardous Materials for the terms "flammable liquid', "poisonous- material", and "corrosivematerial", respectively. RSPA has adopted the definition of "poisonous material" for "toxic" because it considers the terms synonymous.- Sections 1952, i95.W6,.195.112, 195.212 and 195.413 , (Nominal Outside Diameter of the Pipe in Inches) RSPA proposed to standardize the dimensioning of pipe size throughout part 195 (Changes are made to § 195.2, 195.106(b), 195.106(c), 195.112(c),- 195.212(b)(3)(ii) and 195.413(a)). All 10 THLPSSC members who voted were in favor of the proposal and no commenter objected thereto. Accordingly, the proposed amendment is adopted as final.- Section 195.3 Matter incorporated by reference.- Section 195.3 sets out the general requirements for the incorporation in the regulations of industry standards for the design, construction and operation of hazardous liquid and carbon dioxide pipelines. Paragraph 195.3(a) states that incorporation of a -document by reference has -the- same force' as if the document were copiOdin the-- -- - - regulations. Some operatorshave- misinterpreted this-section to mean that they must- comply with all of the terms - contained in a referenced 'document.- - Acäordingly, RSPA hereby revises § 195.3(a) tO clarify that an entire document is not incorporated when the document is incorporated by reference; rather, only those portions specifically referenced in the regulations are incorporated. The rule is being revised to conform to a recent update of references in another rulemaking (Update of Standards Incorporated by Reference (58 FR 14519; March 18, 1993)). Also, references to ASME/ANSI Codes B31 :8 and B31.G are beingadded. The 10- THLPSSC members who voted and 7 commenters favored the revision. Section 195.5 Conversion to service.- subject to this part.- - Section' 195.5 regulates the conversion of steel pipelines to hazardous liquid or' carbon -dioxide service that is subject to part 195. Under § 195 .5(a)(4), a converted pipeline must be hydrostatically tested to substantiate the maximum operatingpressure (MOP) permitted by § 195.406.1 To substantiate the MOP of a converted pipeline, an operator must know the pipe design pressure (see - current § 195.406(a)(1)). Consequently. if pipe design pressure.is unknown, a steel pipeline may not be con earted under § 195.5. Although the design.- pressure of components is an MOP factor under § 195.406(a)(2), pipeline components hre normally designed to be - as strong or stronger than attached pipe. Thus, pipe design is the critical factor in substantiating MOP under § 195.5(a)(4), and lack of knowledge of component design pressure is not a significant safety concern. RSPA proposed to amend § '195.5 to permit conversion using an approach found in section 845.214 and Appendix N of ASME B31.8 for gas pipelines whose design pressure is imknown. Under this proposal, operators would pressim test the pipeline under Appendix N until pipe yield occurs.' Instead of design pressure, this yield test pressure would he used to-compute MOP by applying certain reduction factors to 80 percent of the first pressure that produces pipe yield. All THLPSSC members who voted on the proposed amendment to § 195.5- I Section 195.51a)(4) actually uses the term "maximum allowable operating pressure," but for consistency with 195.406, this term is changed below to MOP byremoving the word "allowable."#

Page 11Federal Register / Vol. 59, No., 123 / Tuesday, June 28, 1994 / Rules and Regulations supported it in concept. However, two members thought the wording of Appendix N should be copied directly into part 195 to avoid referencing a gas pipeline code in liquid pipeline regulations. We believe the principles of Appendix N apply equally to gas and liquid pipelines. And since the B31.8 Code is widely used, operators of hazardous liquid or carbon dioxide pipelines will not find it difficult to obtain and appjy Appendix N. RSPA received five comments on the proposed amendment to § 195.5. Two operators and a pipeline-related association agreed with the proposed amendment. One operator suggested that if pipelines operating at less than 20 percent of specified minimum yield strength (SMYS) are subject to § 195.5, RSPA- should allow operators up to 10 yearsto meet the testing requirements. At present, none of the standards in part 195, including § 195.5, applies to pipehnes operating at less than 20 percent of SMYS (see §.195.1(b)(3)). However, this commenter may have had in mind §206.of the Pipeline Safety Act of 1992 (Pub. L. 102-508), which provides that exceptions to regulations under the Hazardous Liquid Pipeline Safety Act of 1979 (49 U.S.C. app. 2001 et seq.), such as part 195, may not be based solely on low internal stress. Because of this statutory mandate, RSPA has proposed to apply-part 195 to certain low-stress hazardous liquid pipelines (Docket PS-117; 58 FR 12213; March 3, 1993). Still, that proposal would not require any existing low- stress hazardous liquid pipeline to he tested under § 195.5, because such pipelines would not be converted pipelines. Of course, if part 195 becomes applicable to low stress pipelines, any pipeline converted to low stress hazardous liquid service subject to part 195 would have to be tested under § 195.5. But, since testing is the backbone of the conversion process, RSPA does not believe § 195.5 should be amended to extend the time for, testing to 10 years.- A state agency was concerned that if test pressure must be measured at the high elevation point of test segments, the test could stress the low point of the segment beyond yield. However, the Appendix N test method should not result in overstress at the tow elevation, because the method does not require increases in test pressure after the first yield occurs in the test segment. In a separate rulemaking proceeding (Docket No. PS-124; 57 FR 39572; August 31, 1992), RSPA proposed to allow the use of the Appendix N method in converting pipelines to gas service under 49 GFR 192.14. This gas pipeline conversion standard is similar to § 195.5. Comments to that notice argued that pressure testing to yield is unnecessary to qualify certain pipelines that operate at low stress (generally pipelines 12~ inches or less in nominal outside diameter operating at pressures of 200 psig or 'less). RSPA believes these comments are-also relevant to hazardous liquid pipelines All other factors being equal, hazardous liquid pipelines operating at low internal stress present less risk of failure from 'time-dependent defects than higher stress hazardàus liquid pipelines. Because of the lower risk, RSPA has modified the final rule to provide that pipelines 12~ inches or less in nominal outside diameter to be operated at a pressure of 200 psig or less may be converted without testing to yield. The MOP of such pipelines may be determined under § 195.406 by'using 200 psig as pipe design pressure. The proposed rule has been redrafted to improve clarity, to better relate conversion to design pressure and MOP under § 195.406, and to include the changes discussed supra. In the final rule, the proposed amendment to § 195.5(a)(1) is revised and published as an amendment to § 195.406(a)(1). This latter section deals. specifically with pipe design pressure and MOP. 'As set forth Infra, revised § 195.406(a)(1) provides that- when pipe design pressure is unknown for steel pipelines being converted, a reduced value of first yield hydrostatic test pressure may be usOd as design pressure to compute MOP. If the pipeline to be converted is 12/4 inches or less in nominal outside diameter and is not yield tested, 200 psig may be used as design pressure. Section 195.8 Transportation of hazardous liquid or carbon dioxide in pipelines constructed with other than steel pipe. The proposal to replace the word "he" with "the Secretary" to remove any implication'of gender is not adopted in this rulemaking. Instead, this proposal will be handled in an omnibus rulemaking to make minor clarifications and error corrections covering all the pipeline safety regulations. Section 195.50. Reporting accidents and § 195.52 Telephonic notice of certain accidents; - Sections 195.50(1) and 195.52(a)(3)- - require operators to prepare reports and- give telephonic notice of accidents,- respectively, when the estimated property damage due to an accident - exceeds $5,000. RSPA discovered from its regulatory review and previous enforcement cases that a significant 33391 amount of confusion exists among pipeline operators as to which Cost estimates must be included in calculating the "estimated property damage to the property of the operator -or others* * " Frequently, when reporting accidents, pipeline operators fail to include as "property damage" the fair market value of the product released or those costs associated with cIeanup and recovery efforts. RSPA believes - these costs should be included when reporting accidents. Because the $5,000 reporting requirement requires the reporting of minor accidents, RSPA proposed amending § 195.50(f) and 195.52(a)(3) to increase the reporting threshold to $50,000, the same level as required in 49 CFR part 192 and to include as property damage the value of the product released and the costs - associated with clean-up end recovery efforts. The THLPSSC voted 10 toO in favor of the change (5 members did not vote). Two of those favoring the proposed changes recommended that RSPA modify the final rule to limit property damage to fair market value of the lost product and initial clean-up and product recovery costs. One member said that clean-up and recovery costs should not be included in total property damage.- Three commenters disagreed with the proposed changes and recommended that the rule be withdrawn. One complaint was that the statistical base would be discontinuous because, in the future, RSPA would not receive information on accidents costing between $5,000 and $50,000. Another complaint was that the change could affect the developmeyit of environmental protection requirements. RSPA understands that a change in reporting levels will cause a slight skewing due to truncation of the data, but believes requiring operators to report accidents based solely on the $5,000 property damage criterion is unnecessary arid burdensome. Significant accidents will still bereported because the other criteria (especially those that are - environmentally related) requiring reports will be unchanged: (1) Explosion or fire, (2) loss of 50 barrels of liquid. (3) escape of five barrels a day of highly volatile liquids, (4) a death, (5) bodily harm, or (6) resulted in the pollution of any stream. Because these requirements remain unchanged, those operators with more frequent small releases will still be identified. As to a skewing of the data. those organizations that keep track of such statistical data should be able to make adjustments to account for such changes. Also, as explained in the NPRM, this change will make the liquid#

Page 1233392 Federal Register / Vol. 59, No. 123 / Tuesday, June 28, 1994 / Rules and Regulations safety reporting requirements consistent with the gas safety reporting requirements which will eliminate confusion. The rule change should have little, if any, effect on the environment because the same spill volume reporting criteria remain in effect. Only the dollar level of the reporting criterion is being changed. Two commenters supported the rule changes as they were written. Five others favored the changes, but proposed modification of the rules to explain more fully the meaning of "estimated total damage" in order to spell out the items that must be covered. They said that "estimated total damage" is ambiguous and confusing and subject to interpretation. One cominenter stated that the costs of subsurface restoration should be excluded from property damage because it is nearly impossible to estimate the subsurface restoration costs within the time allowed to report the accident. RSPA agrees that early estimates of the costs to clean-up a liquid spill may not be exact; however, the operator should, at a later date, submit a revised report that provides more reliable cost figures for the clean-up. RSPA is clarifying the issue by amending § 195.50(f) to read: "(1) Estimated property damage, including cost of clean-up and recovery, value of lost product, and damage to the property of the operator or others, or both, exceeding $50,000" and § 195.52(a)(3) to read: "(3) Caused estimated property damage, including cost of clean-up and recovery, value of lost product, and damage to the property of the operator or others. or both, exceeding $50,000." Section 195.106 Internal design pressure. Section 195.106(a) prescribes the formula for calculating the design. pressure of steel pipe. In addition, § 195.106(b) regulates the pipe yield strength used in the design pressure formula. When the specified minimum yield strength (SMYS) of pipe is unknown, § 195.106(b) requires that yield strength be derived from tensile tests on random samples of pipe. Based on a comparable gas pipeline safety standard (49 CFR 192.107(b)(2)), RSPA proposed to amend § 195.106(b) to allow operators to use 24,000 psi as yield strength if pipe of unknown SMYS is not tensile tested. Editing changes to § 195.106(b) were also proposed. The 10 THLPSSC members who voted on the proposed amendment of § 195.106(b) supported it (5 did not vote). In addition, RSPA received comments from four operators and one¯ pipeline-related association. The (17th edition). For weld acceptability, association and three of the operators § 195.228(b) now references the agreed with the proposal. One of these standards in Section 6 of API Standard operators suggested further editing, part 1104. of which RSPA has included in the final In a notice of proposed rulemaking rule. involving our review of the gas pipeline One operator was concerned that the safety standards in 49 CFR part 192 proposed rule could unjustiflably (Docket PS-124; 57 FR 39572; August reduce the MOP of its pipelines. The 31, 1992), RSPA proposed to allow gas operator said its pipelines are made of operators to apply the API appendix in Grade B pipe (yield strength at least addition to section 6 criteria. Although 35,000 psi) or better. However, some that proposal was based on a petition by pipelines may contah pipe for which API to incorporate the appendix by documentation of yield strength or reference in both parts 192 and 195, we tensile testing does not exist. For such overlooked the request to include such pipe, without new tensile testing, yield a proposal in the present rulemaking. strength would have to be assumed to be In the part 192 rulemaking, RSPA's 24,000 psi. The operator suggested that gas pipeline safety advisory committee RSPA allow operators to use appropriate voted to support the proposed evidence besides tensile tests to amendment. Also, all but one of the demonstrate the yield strength of pipe. public comments were in favor of In response to this comment, we note, allowing use of the Appendix of API first, that the proposed amendment to Standard 11Y4. - § 195.106(b) would not affect the design The dissenting commenter was pressure of existing pipelines unless concerned that industry inspection they are replaced, relocated, or personnel may not be qualified to apply otherwise changed (see § 195 .100). the appendix. However, this commentër Second, § 195.106(b) currently requires may not have recognized that under operators to use as yield strength either § 192.243(b) and (c), operators must SMYS or a value based on tensile ensure that nondestructive testing is testing. So the operator's apparent performed in accordance with written difficulty in verifying yield strength is a procedures by persons who have been problem of compliance with the current properly trained and qualified. Sections rule. Third, the proposed nile would 195.234(b) and (c) provide similar relax the burden of tensile testing only requirements for nondestructive testing when MOP does not exceed the level of welds on hazardous liquid and that corresponds to a yield strength of carbon dioxide pipelines. RSPA believes 24,000 psi. When a higher MOP is these requirements are adequate to desired, operators must use the tensile assure proper application of the testing option. Finally, RSPA is not aware of any acceptable evidence of the appendix. The Appendix of API Standard 1104 yield strength of pipe of unknown applies equally to girth welds in gas and SMYS apart from appropriate tensile liquid pipelines. This amendment is not testing. Thus, the amendments to mandatory, rather it provides pipeline § 195.106(b), as discussed above, are operators an optional operating adopted. procedure. In view of the prior opportunity for public comment on use Section 195.204 inspection-general. of the appendix for gas pipelines, the The THLPSSC voted 10 to 0 in favor favorable response by public of the proposed change to make the commenters and RSPA's advisory language gender neutral and, except for committee, and the fact that use of the a minor correction, no objections were appendix would not be mandatory, we received from commenters. The' believe that a further opportunity for proposed change is adopted as public comment is unnecessary to allow corrected. use of the appendix under § 195.228(b). We feel this amendment is a logical Section 195.228 Welds; standards of outgrowth of the Notice and furthers our acceptability. efforts to make parts 192 and 195 One of the comments we received on consistent wherever possible. This proposed amendments to amendment will not have a substantial nondestructive testing requirements impact on the regulated community. under § 195.234(e) (discussed infra) Thus, in accordance with 5 U.S.C. concerned the standards for acceptance 553(b)(3)(B), we are amending of weld flaws ( 195.228(b)). A pipeline- 195.228(b) to reference the appendix related association asked us to without further rulemaking notice. incorporate by reference the alternative However, should any person be acceptance standards for girth welds adversely affected by this decision or that are in the Appendix to American wish to change the final rule, that Petroleum Institute (API) Standard 1104 person may submit a petition for#

Page 13Federal Register I Vol. 59, No. 123 / Tuesday, June 28, 1994 / Rules and Regulations reconsideration under RSPA's Sections 195.246 Installation ofpipe rulemaldng procedures in 49 CFR in a ditch and 195.248 Cover over 106.35. buried pipeline. The final rule provides that the Section 195.246(b) is inconsistent appendixmay be used only for girth with § 195.413(b)(3) for pipe in the Gulf welds to which the appendix applies. of Mexico and its inlets (See § 105.2 For example, as section A.1 of the Definitions) under water less than 15 appendix states, neither welds in pump stations nor welds used to connect feet deep but at least 12 feet deep, fittings and valves are covered by the because § 195.246(b) permits the pipe to be without cover or to be above the appendix. Also, the appendix applies only to girth welds between pipe of seabed if properly protected. Such pipe equal nominal wall thickness. is a "hazard to navigafion" under the definition of that teWn in § 195.2, and Section 195.234 Welds: must have the minimum cover required Nondestructive testing. by § 195.413(b)(3). In addition, Section 195.234(e) requires that' 100 § 195.248(a) and (b)are Inconsistent percent of each day's girth welds with § 195.413(b)(3) for pipe in the Gulf installed in* * * [certain) locations of Mexico and its inlets under water less must be nondestructively tested 100 than 12 feet deep. Section 195.248(a) percent unless impracticable, in which allows pipe to be less than 12 inches case at least 90 percent must be tested." below the seabed (i.e., a hazard to RSPA proposed to amend § 195.234(e) navigation). In certain instances, to clarify that "90 percent" pertains to § 195.248(b) allows pipe to be without the number of girth welds that must be cover or less than 12 inches below the tested over their entire circumference. seabed. Neither condition is allowed In addition, § 195.234(g) requires: "At under § 195.413(b)(3). In light of these pipeline tie-ins 100 percent of the girth inconsistences, RSPA proposed in the welds must be nondestructively tested." NPRM to amend §5195.246(b) and RSPA proposed to clarify that this 195.248(a) and (b) to correct the standard applies to tie-ins of problem. replacement sections of pipeline. Ten THLPSSC members favored the The THLPSSC supported the proposed changes (5 members did not proposed amendments, although one vote). One of the members favoring the member thought part 195 should define changes said it would make more sense the word 'impracticable." We did not to retain the existing regulation which adopt this recommendation because the operators have adhered to for years. In word is used in its ordinary dictionary similar manner, two commenters and sense. one pipeline -related organization agreed Three operators and two pipeline- with the proposal. One cominenter and related associations commented on the two pipeline-related organizations proposed amendments. Three disagreed and suggested that references commenters agreed with the proposal, to a depth of 15 feet in the rule be one suggested editing changes, and one eliminated. RSPA proposed changes to made a related proposal discussed supra §5195.246(b), 195.248(a) and 195.248(b) under the heading, "fi 195.228(b) Welds; so these sections would conform with standards of acceptability." Although Public Law 101-599 (section 1, 104 Stat. we did not adopt all the editing 3038 (1990)) which requires burial of suggestions, these comments helped us pipe where the subsurface is under 15 provide clarity to the final rule. feet of water as measured from mean In addition, one commenter thought low water. Therefore, §5195.246(b), the proposed amendment of § 195.234(g) 195.248(a) and 195.248(b) are adopted was unnecessary because § 195.200 as proposed in the NPRM. already indicates that § 195 .234(g) applies to replacement sections. Section 195.262 Pumping equipment. Moreover, the cominenter thought Section 195.262(d) regulates the adding the proposed phrase to location of pumping equipment. The § 195.234(g) would create confusion rule prohibits the installation of over whether § 195.234(a) through (I) pumping equipment on property not apply to replacement sections. While under the operator's control. It also these observations have theoretical prohibits installation less than 50 feet merit, in practice, some operators have from the pump station boundary. RSPA failed to recognize that "pipeline tie- proposed to amend § 195.262(d) to ins" include tie-ins of replacement clarify that these two restraints on sections. The clarifying phrase adds location apply conjünctively not emphasis where it is apparently needed to assure compliance th the full alternatively. The THLPSSC members who voted on extent of the rule. Section 195.234(g) is, the proposed amendment supported it therefore, adopted as proposed. in concept, but 5 members 33393 recommended further editing of the rule for clarity. Although three of the five. persons who commented on the proposal supported it as proposed, the other two commenters thought further clarifying changes were needed. In view of these comments and THLPSSC views, we have modified the final rule based on identical wording suggested by five THLPSSC members and one commenter. Section 1953O4 Testing of components. Section 195.304(b) excludes from hydrostatic testing under part 195 any component that is the only item being replaced or added to a pipeline system if the component or a prototype was tested at the factory. RSPA proposed to amend § 195.304(b) to clarify that the excluded components do not include pipe. The THLPSSC fully supported the proposed amendment. Of the six comments from the public on the proposal, a pipeline-related association and two operators agreed with it, whIle three operators suggested changes. An operator suggested that instead of amending § 195.304(b). we should revise the definition of "component" to exclude pipe. We did not adopt this suggestion because the revision would affect every rule in part 195 that uses the term "component." Editing suggested by another operator was not adopted because it concerned matters not addressed in the NPRM. One operator felt pipe should be excluded from hydrostatic testing under § 195.304(b) to the same extent as other components. The operator said that. hydrostatically testing short sections of mill tested pipe is duplicative, costly, and not needed for safety. Although the NPRM did not propose to alter the existing requirement that replacement sections of pipe of any length must be hydrostatically tested to part 195 standards before operation, we do not agree with this commenter's contention. Normal pipe mill tests are not duplicative of part 195 tests, and are not a proven safe alternative to part 195 requirements. However, for short sections of replacement pipe, part 195 test requirements could be met anywhere, including, by prior arrangement with the operator, in the pipe mill. So if an operator wishes to avoid field testing of short replacement sections of pipe, it only needs to assure that the mill tests of those sections were done in accordance with part 195 test requirements.#

Page 14fl3394 Federal Register / Vol. 59, No. 123 I Tuesday, June 28, 1994 / Rules and Regulations Section 195.406 Maximum operating pressure. The changes to § 195.406 are discussed supra under § 195.5. Section 195.412 Inspection ofrights- of-way and crossings under navigable waters. Section l95.12(a) requires an operator, at intervals not exceeding 3 weeks, but at least 26 times each. calendar-year, to inspect the surface conditions on or adjacent to each pipeline right-of-way. Because some surface condition activities that affect the safety and operation of pipelines are more visible from aerial patrols than from walking or driving the right-of- way, RSPA proposed thafthe section be changed to clarify that anrial patrols are an optional method of compliance. No comments were received regarding the change and the THLPSSC voted 10 to 0 in favor of the change (5 members did not vote). Accordingly, the change to § 195.412(a) is adopted as proposed. Section (b) requires operators, at intervals not exceeding 5 years, to inspect each crossing under a navigable waterway (except offshore) to determine the condition of the crossing. The purpose of the inspection is to look for any damage, unanticipated loading, or loss of protection that could threaten the safety of the pipeline. We stated in the NPRM that bored crossings are usually so deep that there is little likelihood the pipeline could be affected by waterway- related events, such as scouring or anchor dragging. We proposed to add an exception to § 195.412(b) to cover bored crossings that are too deep to be subject to waterway-related damage. The THLPSSC voted 10 to 0 in favor of the rule (5 members did not vote). However, a state pipeline agency suggested the existing regulation be retained. The agency stated that a pipeline operator cannot be 100 percent sure a bored crossing is so deep it cannot be affected as stated. RSPA received four additional- comments, three of which expressed an opinion that the phrase "too deep to anticipate damage from waterway conditions or vessel traffic" is vague and inappropriate. The other commenter said the proposal is unduly restrictive and should be refocused from bored crossings to a more generic performance standard potentially including all crossings. In view of the comments received, RSPA agrees with those who opined that "too deep to anticipate damage from waterway conditions or vessel traffic" is too vague. In the absence of a recognized standard on the subject, it is too speculative to judge when bored crossings are buried at a sufficient depth to be safe from damage by external- forces. Therefore, it is in the interest of public safety that the current rule requiring inspection at intervals not exceeding 5 years be retained. Accordingly, the proposed change to § 195.412(b) is not adopted. Section 195.416 External Corrosion Control. Section 195.416( tates that each operator shall, at in rvals not exceeding 15 months, but at least once each calendar year, conduct tests on each underground facility that is under cathodic protection to determine whether protection is adequate. RSPA is clarifying the rule to reduce any misunderstanding regarding what is meant by "underground." The word "underground" in this paragraph has meant any facility that is burie4 or in contact with,the ground. This rule clarification will not change the burden on operators because RSPA compliance inspectors have consistently required any facility in contact with the ground to be cathodically protected. RSPA received two comments regarding the change to § 195.416(a). One commenter recommended that offshore pipelines be excluded from annual testing requirements. RSPA' believes there is no acceptable substitute for regular testing to determine if corrosion protection of all lines, both onshore and offshore, is adequate. Accordingly, "in contact with the ground or submerged" is added to the rule to assure that all underwater pipelines, both onshore and offshore, are included in the definition. The other corrunenter suggested requiring the testing of "carrier pipes" in casings. "Carrier pipes" are normally buried and subject to the rule. The THLPSSC voted 10 to 0 in favor of the proposed change (5 members did not vote). The revision to § 195.416(a) is adopted as modified. Section 195.416(1) requires that any pipe found to be generallycorroded so that the remaining wall thickness is less than the minimum thickness required by the pipe specification tolerances must either be replaced with coated pipe that meets the requirements of part 195 or, if the area is small, must be repaired. However, the operator need not replace generally corroded pipe if. the operating pressure is reduced to.b commensurate with the limits on operating pressure specified in § 195.406, based on the actual remaining wall thickness. Section 195.416(g) states that if localized corrosion pitting is found to exist to a degree where leakage might result, the pipe must be replaced or repaired or the operating pressure must be reduced commensurate with the strength of the pipe based on the actual remaining wall thickness in the pits. RSPA recpgnizes that paragraphs (f) and (g) do not provide guidance for an operator's use in determining the strength of the actual remaining wall thickness of corroded steel pipe. To provide such guidance, RSPA proposed amending § 195.416(h) to adopt the ASMIE Manual B3IG procedure for determining the remaining strength of corroded steel pipe in existing pipelines. Application of the procedure was proposed to be in accordance with the limitations set out in the B31G Manual. The rule would provide guidance as to whether a corroded region (not penetrating the pipe wall) may be left in service; this option might require a reduction in maximum allowable operating pressure, but may be more economical than replacement or repair of the corroded pipe. Ten THLPSSC members voted for the proposal (5 members did not vote). Comments relative to § 195.416(h) were received from five commenters. One commenter said the proposal to change § 195.416(h) is inappropriate and should be redone to be consistent with § 192.485. Others stated that the proposal was unnecessarily restrictive because it did not allow the use of other proven industry developed methods for determining the remaining strength of corroded pipelines. The most noteworthy method mentioned was "A Modified Criterion for Evaluating the Remaining Strength of Corroded Pipe (with RSTRENG disk)" developed by Battelle under the Pipeline Research Committee of the American Gas Association (AGA). (Project PR 3-805, December 1989, AGA catalog No. L51609). Project PR 3-805 was undertaken to devise a modified criterion that, while still assuring pipeline integrity, would eliminate as much as possible the excessive specifications embodied in the ASME B3IG manual. The AGA modied criterion, using a complex analysis approach, can be carried out by means of a PC-based program called RSTRENG. The modified criterion can a1sobe applied via tables or curves or a long- hand equation if a simplified analysis is preferred. The addition of the modified criterion to the rule does not compromise safety because it merely accepts an established pipeline industry guideline, and does not impose new requirements on the operators. Accord!hgly, RSPA is amending § 195.416(h) to include the AGA/Battelle-A Modified Criterion for#

Page 15Federal Register / Vol. 59, No. 123 / Tuesday, June 28, 1994 / Rules and Regulations 33395 Evaluating the Remaining Strength of RSTRENG). Corroded Pipe (with the computer disk the original rulemaking processes. covered by OMB Control Numbers Currently, regulations in part 195 are the injection of carbon dioxide for oil (i) The inlet of a compressor used in • Rulemaking Analyses 2137-0047 (approved through May 31, recovery operations, or the point where Impact Assessment 1994), 2137-0578 (approved through injection system, whichever is farther recycled carbon dioxide enters the signiticant regulatory action under This final rule is not considered a (approved through May 31, 1994). There October 31, 1994) and 2137-0583 upstream; or and, therefore, was not subject to review section 3(f) of Executive Order 12866 requirements in this final rule. are no new information collection pipeline in the production field that (ii) The connection of the first branch wells or to headers or manifolds from transports carbon dioxide to injection by the Office of Management and List of Subjects in 49 CFR Part 195 significant under the regulatory policies Budget. The rule is not considered Ammonia, Carbon dioxide; which pipelines branch to injection "Transportation (44 FR 11034). and procedures of the Department of Incorporation by reference, Petroleum, * wells. Pipeline safety, Reporting and * * prepared and is available in the docket. A Regulatory Evaluation has been recordkeeping requirements. republished, definitions for Corrosive 3. In § 195.2, the introductory text is RSPA is amending 49 CFR part 195 as In consideration of the foregoing. product, Flammable product, In-plant existing rules would result in an RSPA estimates the proposed changes to product, and Toxic product are added in piping system, Petroleum, Petroleum for the hazardous liquid pipeline estimated savings of $1,534,000 per year. PART 195- (AMENDED] alphabetical order to read as follows: industry at no cost to the industry, and continues to read as follows: 1. The authority citation for part 195 § 195.2 Definitions. discussed above, these savings would with no adverse effect on safety. As As used in this part- come largely from the use of new and 49 CFR 1.53. Authority: 49 app. U.S.C. 2002 and 2015; material" as defined by § 173.136 Class Corrosive product means "corrosive technology, greater flexibility in constructing and operating pipelines, paragraph (b) is republished, paragraph 2. In § 195.1, the introductory text of 8-Definitions of this chapter. and the elimination of unnecessary (b)(5) is revised, in paragraph (b)(6) a 'in" and "plant", and paragraphs (b)(7) hyphen is added between the words "flammable liquid" as defined by Flammable product means RSPA has analyzed the proposed and (b) 8) are revised to read as follows: chapter. § 173.120 Class 3-Definitions of this Order 12612 (52 FR 41685; October 30, rules under the criteria of Executive § 195.1 Applicability. substantial effects on the states, on the 1987). The regulations have no * (b) This part does not apply to that is located on the grounds of a plant In-plant piping system means piping current federal-state relationship, or on or carbon dioxide in offshore pipelines (5) Transportation of hazardous liquid and used to transfer hazardous liquid or responsibilities among the various the current distribution of power and carbon dioxide between plant facilities outlet flange of each facility where which are located upstream from the or between plant facilities and a levels of government. Thus, preparation transportation, not including any device pipeline or other mode of of a federalism assessment is not warranted. hydrocarbons or carbon dioxide are produced or where produced to control pressure in the pipeline under and associated piping that are necessary Regulatory Flexibility Act hydrocarbons or carbon dioxide are first entities are those with less than RSPA criteria for small companies or processed, whichever facility is farther separated, dehydrated, or otherwise § 195.406(b). $1,000,000 in revenues and are downstream; condensate, natural gasoline, natural gas Petroleum means crude oil, Few of the companies subject to this independently owned and operated. (7) Transportation of hazardous liquid liquids, and liquefied petroleum gas. Accordingly, based on the facts rulemaking meet these criteria. or carbon dioxide- toxic, or corrosive products obtained Petroleum product means flammable, available concerning the impact of this (i) By vessel, aircraft, tank truck, tank the Regulatory Flexibility Act that this proposal, I certify under Section 605 oi car, or other non-pipeline mode of from distilling and processing of crude oil, unfinished oils, natural gas liquids, economic impact on a substantial proposal would not have a significant. grounds of a materials transportation (ii) Through facilities located on the blend stocks and other miscellaneous hydrocarbon compounds. applies to intrastate and interstate number of small entities. This rule terminal that are used exclusively to transfer hazardous liquid or carbon material' Toxic product means "poisonous pipeline facilities used in the transportation or between a non- dioxide between non-pipeline modes of 6, Division 6.1-Definitions of this as defined by § 173.132 Class transportation of hazardous liquids or carbon dioxide. including any device and associated pipeline mode and a pipeline, not chapter. piping that are necessary to control §§ 195.2, 195.112, 195.212, 195.413 Paperwork Reduction Act § 195.406 b; and pressure in the pipeline under [Amended] information collection requirements for The documentation for the 4. In the list below, for each section downstream from the following point, (8) Transportation of carbon dioxide indicated in the left column, the phrase Management and Budget (OMB) during part 195 was submitted to the Office of indicated in the middle column is as applicable: removed and the phrase indicated in the right column is added:#

Page 1633396 Federal Register / Vol. 59, No. 123 / Tuesday, June 28, 1994 / Rules and Regulations Section Remove Add 195.2, Gathering line 3 inches or less in nominal diameter 219.1 mm (8% in) or less nominal outside di- 195.112 (c) An outside diameter of 4 inches or more …...... A nominal outside diameter of 114.3 mm (4½ ameter: 195.212(b)(3)(ii) The pipe is 12 inches or less in outside diam- The pipe is 323.8 mm (12¾ in) or less nomi- in) or more. 195.413(a) Except for gathering lines of 4-inch nominal eter. Except for gathering lines of 114.3 mm (4½ nal outside diameter. diameter or smaller. in) nominal outside diameter or smaller. to read as follows: -5. In § 195.3, paragraph (a) is revised Determining the Remaining Strength of (iv) ASME/ANSI B31G, "Manual for 10. Section 195.50(f) is revised to read • Corroded Pipelines" (1991) as follows: § 195.3 Matter Incorporated by reference. incorporated by reference in this part is (a) Any document or portion thereof 8. In $ 195.3, paragraphs (c)(1) $ 195.50 Reporting accidents. included in this part as though it were through (c)(4) are redesignated as (f) Estimated property damage, printed in full. When only a portion of paragraph (c)(1) is added to read as paragraphs (c)(2) through (c)(5) and • including cost of clean-up and récovery incorporates only that referenced a document is referenced, then this part follows: property of the operator or others, o value of lost product, and damage to the • portion of the document and the § 195.3 Matter incorporated by reference. both, exceeding $50,000 Applicable editions are listed in remainder is not incorporated. read as follows: 11. Section 195.52(a)(3) is revised to (1) American Gas Association (AGA): (c) * * parentheses following the title of the paragraph (c) of this section in. AGA Pipeline Research Committee, § 195.52 Telephonic notice of certain accidents. listed in previous editions of this referenced material. Earlier editions Criterion for Evaluating the Remaining Project PR-3-805, "A Modified (3) Caused estimated property (a)** section may be used for components 1989). The RSTRENG program may be Strength of Corroded Pipe" (December manufactured, designed, or installed in damage, including cost of cleanup and accordance with those earlier editions at used for calculating remaining strength. recovery, value of lost product, and refer to the appropriate previous edition the time they were listed. The user must .* damage to the property of the operator 9. Section 195.5 is amended by * or others, or both, exceeding $50,000; editions. of 49 CFR for a listing of the earlier read as follows: revising paragraphs (a)(1) and (a)(4) to read as follows: 12. Section 195.106(b) is revised to * through (b)(5) are redesignated as 6. In § 195.3, paragraphs (b)(1) this part. § 195.5 Conversion to service subject to (a) * * * $ 195.106 Internal design pressure. paragraphs (b)(2) through (b)(6) and (1) The design, construction, (b) The yield strength to be used in follows: paragraph (b)(1) is added to read as operation, and maintenance history of determining the internal design pressure the pipeline must be reviewed and, under paragraph (a) of this section is the * § 195.3 Matter incorporated by reference. where sufficient historical records are specified minimum yield strength. If the not available, appropriate tests must be specified minimum yield strength is not performed to determine if the pipeline known, the yield strength to be used in (b) * * * is in satisfactory condition for safe following: . the design formula is one of the 1515 Wilson Boulevard, Arlington, VA (1) American Gas Association (AGA), necessary to verify the design pressure operation. If one or more of the variables (1)(i) The yield strength determined 22209. under § 195.106 or to perform the y performing all of the tensile tests ( * testing under paragraph (a)(4) of this Pi Specification 5L on randoml (c)(2)(iv) are redesignated as paragraphs 7. In $195.3, paragraphs (c)(2)(iii) and section is unknown, the design pressure may be verified and the maximum suece of lessens with the following (c)(2)(v) and (c)(2) (vi) and paragraphs operating pressure determined by- as follows: (c)(2)(iii) and (c)(2)(iv) are added to read (i) Testing the pipeline in accordance Pipe size No. of tests with ASME B31.8, Appendix N, to produce a stress equal to the yield . Less than 168.3 mm (6% in) nominal out- ne test for ear strength; and 00 lengt § 195.3 Matter incorporated by reference. (i) Applying, to not more than 80 side diameter. percent of the first pressure that One test for eact (c) * 100 lengths (2) * * * in § 195.106(a) and the appropriate produces a yielding, the design factor F Transmission and Distribution Piping (iii) ASME/ANSI B31.8 "Gas factors in § 195.106(e). Larger than 323.8 mm (12¾ in) nominal out- One test for each side diameter. 50 lengths. B31.8a-1990, B31.8b-1990, B31.8C- Systems" (1989 with ASME/ANSI accordance with subpart E of this part (4) The pipeline must be tested in 1992 Addenda and Special Errata issued to substantiate the maximum operating exceeds 0.85, the yield strength shall be (il) If the average yield-tensile ratio issued February 28, 1991). July 6, 1990 and Special Errata (Second) pressure permitted by § 195.406. taken as 165,474 kPa (24,000 psi). If the average yield-tensile ratio is 0.85 or less.#

Page 17Federal Register / Vol. 59, No. 123 / Tuesday, June 28, 1994 / Rules and Regulations 33397 the yield strength of the pipe is taken as the lower of the following: of the girth welds must be strength determined by the tensile tests. (A) Eighty percent of the average yield nondestructively tested. no operator may operate a pipeline at a 17. Section 195.246 is amended by pressure that exceeds any of the determined by the tensile tests. • (B) The lowest vield strength revising paragraph (b) to read as follows: pipe determined in accordance with -(1) The internal design pressure of the § 195.246 Installation of pipe in a ditch. provided in paragraph (b) of this (2) If the pipe is not tensile tested as § 195.106. However, for steel pipe in as 165,474 kPa (24,000 psi). section, the yield strength shall be taken Mexico and its inlets, all offshore pipe (b) Except for pipe in the Gulf of ipelines being converted under $ 195.5. formula (§ 195.106) are unknown, one of I one or more factors of the design in water at least 3.7 m 12-ft-deep but not 13. In § 195.106(c), the last sentence is more than 61 m (200 ft) deep, as design pressure: the following pressures is to be used as be installed so that the top of the pipe measured from the mean low tide, must pressure that produces yield under (i) Eighty percent of the first test § 195.106 Intemal design pressure. pipe is supported by stanchions, held in is below the natural bottom unless the section N5.0 of Appendix N of ASME thickness may not be more than 1.14 (c) * * * However, the nominal wall coating, or protected by an equivalent place by anchors or heavy concrete B31.8, reduced by the appropriate factors in S$ 195.106 (a) and (e); or • or less outside diameter and is not • (ii) If the pipe is 323.8mm (12¾ in) on pipe that is less than 508mm (20 in) times the smallest measurement taken revising in the first column of the table 18. Section 195.248 is amended bv tested to yield under this paragraph, nominal outside diameter, nor more than 1.11 times the smallest in paragraph (a) the language "Other 1379 kPa (200 psig). mm (20 in) or more in nominal outside measurement taken on pipe that is 508 ft-deep as measured from the mean low ofishore areas under water less than 12- read as follows: 22. Section 195.412(a) is revised to tide" to read "Gulf of Mexico and its water less than 12-ft-deep as measured inlets and other offshore areas under § 195.412 Inspection of rights-of-way and crossings under navigable waters. 14. In § 195.204, the last sentence is from the mean low tide" and by revising not exceeding 3 weeks, but at least 26 (a) Each operator shall, at intervals. the introductory text of paragraph (b) to § 195.204 Inspection-generat. times each calendar year, inspect the pertorm inspections unless that person * No person may be used to § 195.248 Cover over buried pipeline. each pipeline right-of-way. Methods of surface conditions on or adjacent to (b) Except for the Gulf of Mexico and .* * * flying or other appropriate means of inspection include walking, driving, phase of construction to be inspected. has been trained and is qualified in the read as follows: 15. Section 195.228(b) is revised to its inlets, less cover than the minimum required by paragraph (a) of this section traversing the reht-of-way. and § 195.210 may be used if— follows: adding a new paragraph (h) to read as paragraph (h) as paragraph (i) and revising paragraph (a), redesignating 23. Section 195.416 is amended by * * * § 195.228 Welds and welding Inspection: Standards of acceptability. read as follows: 19. Section 195.262(d) is revised to determined according to the standards • (b) The acceptability of a weld is § 195.262 Pumping equipment. * * § 195.416 External corrosion control. in section 6 of API Standard 1104. pumping equipment must be installed (d) Except for offshore pipelines, not exceeding 15 months, but at least (a) Each operator shall, at intervals However, if a girth weld is unacceptable than a crack, and if the Appendix to API under those standards for a reason other on property that is under the control of once each calendar year, conduct tests from the boundary of the pump station. the operator and at least 15.2 m (50 ft) • ground, or submerged pipeline facility on each buried, in contact with the Standard 1104 applies to the weld, the acceptability of the weld may be in its pipeline system that is under determined under that appendix. § 195.304(b) is revised to read as 20. The introductory text of whether the protection is adequate. cathodic protection to determine revising the introductory text of 16. Section 195.234 is amended by paragraph (e) and by revising paragraph follows: § 195.304 Testing of components. actual remaining wall thickness, for (h) The strength of the pipe, based on $ 195.234 Wolds: Nondestructivo testing. (b) A component, other than pipe, that may be determined by the procedure in paragraphs (f) and (g) of this section in the following locations must be (e) All girth welds installed each day is the only item being replaced or added ASME B31G manual for Determining to the pipeline system need not be the Remaining Strength of Corroded nondestructively tested over their entire hydrostatically tested under paragraph (a) of this section if the manufacturer by AGA/Battelle-A Modified Criterion Pipelines or by the procedure developed nondestructive testing is impracticable circumference, except that when certifies that either- of Corroded Pipe (with RSTRENG disk). for Evaluating the Remaining Strength for a girth weld, it need not be tested if testine is impracticable does not exceed the number of girth welds for which republishing the introductory text of 21. Section 195.406 is amended by ASME B31G manual or the AGA/ Application of the procedure in the 10 percent of the girth welds installed (a)(1) to read as follows: paragraph (a) and revising paragraph to corroded regions (not penetrating the Battelle Modified Criterion is applicable that day: § 195.406 Maximum operating pressure. accordance with limitations set out in pipe wall) in existing steel pipelines in. ins of replacement sections, 100 percent (g) At pipeline tie-ins, including tie- other variations from normal operations, (a) Except for surge pressures and the respective procedures.#

Page 18L3398 Federal Register./ Vol. 59, No. 123 / Tuesday, June 28, 1994 1 Rules and Regulations Issued in Washington, DC, on June 9, 1994. Ana Sol Gutiérrez, Acting Administrator, Research and Special PrograinsAdministràtion. [FR Doc. 4-1551O Filed 6-27--94; 845 amj BILLING CODE 4910-60-,P#

Page 19November 18, 1998 Ms. Gweneyette Broussard Shell Oil Products Company P0 Box 2463 Houston TX 77252 Dear Ms. Broussard: This responds to your inquiry on our interpretation ofthe term, "in-plant piping system," as defined in 49 CFR 195.2. You asked us to expand the interpretation to include in-plant transfer piping that crosses railroad mainlines. The request arises because some refinery or petrochemical plants are separated by a railroad mainline over which trains travel at a reduced speed through the plant. A typical plant is said to have 3 0-50 transfer lines up to 16 inches in diameter that cross a railroad. The crossings may be up to 500 feet long, with a 6 to 10-foot clearance between overhead crossings and trains. As with other in-plant piping, the railroad crossings are designed and inspected in accordance with ANSI B3 1.3 standards for chemical plants and refineries and are subject to the Process Safety Management regulations ofthe Occupational Safety and Health Administration (29 CFR 1910.119). The safety standards in 49 CFR Part 195 do not apply to transportation through onshore production, refining, or manufacturing facilities, or storage or in-plant piping systems associated with such facilities ( 195.1(b)(6)). To clarify the limits ofPart 195 for in-plant piping systems, we defined the term and stated that it includes pipeline crossings of single public thoroughfares that divide plants (59 FR 33389; June 28, 1994). We further explained that by thoroughfare we meant a road but not a railroad. Although we considered road crossings to be comparable in most respects to other in-plant piping, we were apprehensive about the risk oftrain-related accidents at railroad crossings. Your request has caused us to reconsider whether railroad crossings fall under the in-plant piping exception from Part 195. The information you provided about design, maintenance, and regulation demonstrates that in-plant railroad crossings are subject to the same safety standards as other in-plant piping. And our increased familiarity with in-plant railroad crossings confirms that the risk oftrain-related accidents does not jus6tify distinguishing these crossings from road crossings. It follows that, like road crossings, in-plant railroad crossings are comparable in most respects to other in-plant piping. Therefore, we will consider the thoroughfare interpretation of in-plant piping system to include in-plant railroad crossings. Sincerely, Richard B. Felder Associate Administrator for Pipeline Safety Page 1 of 1#

Page 20C U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration 1200 New Jersey Avenue, SE Washington, D.C. 20590 AUG 112010 Mr. Darin R. Burk Manager, Pipeline Safety Illinois Commerce Commission 527 East Capitol Avenue Springfield, IL 62701 Dear Mr. Burk: In a letter to the Pipeline and Hazardous Materials Safety Administration (PHMSA) dated October 14, 2009, you requested an interpretation regarding the applicability ofthe pipeline safety regulations to certain pipelines operated by United States Steel Corporation (USS) in the vicinity of its Granite City Works (GCW) steelmaking complex in southern Illinois. These pipelines consist of: (1) natural gas pipelines transporting natural gas supplied by Centerpoint Energy's Mississippi River Transmission (MRT) pipeline to various GCW facilities; and (2) a pipeline transporting coke oven gas produced in one GCW facility and transported to another GCW facility for processing and burning. You stated that the GCW complex consists of a number of facilities separated by one State highway and several public streets which are accessible to the public. You asked whether the pipeline safety regulations applied to these lines and if so whether they should be classified as distribution lines or transmission lines. Natural Gas Pipelines With respect to the natural gas pipelines, you stated that the GCW complex receives the natural gas through four taps from the MRT pipeline. Three of the taps are located on the grounds of GCW facilities and connect to an interconnected system of pipes within and between the facilities. You stated that the system ofpiping that connects to the three taps leave the GCW property boundaries six times. You stated the fourth tap is off of a separate MRT transmission line and is located outside of the facility's property. You stated that you had no indication that the natural gas pipelines operate above 20 percent of specified minimum yield strength (SMYS). The Federal pipeline safety laws in 49U.S.C. 60101 et seq. apply to the gathering, transmission, and distribution of natural and other gas by pipeline. Typically, a transmission pipeline transporting gas to a destination facility such as a large volume customer is subject to the pipeline safety laws and regulations up to the point where pressure control changes from the pipeline operator to the destination facility operator (which can be on the grounds of the facility). Beyond that point, piping operated by the facility operator entirely on the grounds ofthe facility is considered "in-plant piping" and would not be subject to the pipeline safety regulations although it may be subject to State building codes or other regulations. In this case, however, the natural gas pipelines operated by GCW are not located entirely on the geographically contiguous grounds of a facility. Rather, these lines depart GCW facilities and cross roads and highways The Pipeline and Hazardous Materials Safety Administration, Office of Pipeline Safety provides written clarifications of the Regulations (49 CFR Parts 190-199) in the form of interpretation letters. These letters reflect the agencys current application ofthe regulations to the specific facts presented by the person requesting the clarification. Interpretations do not create legally-enforceable rights or obligations and are provided to help the public understand how to comply with the regulations.#

Page 212 accessed by the public, albeit for relatively short distances. To the extent such lines are not on plant property they are subject to the pipeline safety laws. Historically, PHMSA has elected not to apply the Federal gas pipeline safety regulations to such lines if they are associated with the plant, meaning they are operated by plant personnel, run between plant buildings, and are less than one mile in length. PHMSA, however, would not object to a State regulating the portions of such lines that are not on plant property ifthe State determined there was a need. Note that a State that regulates its intrastate gas pipelines under a Public Utility Commission (PUC) may need to determine whether the PUC is restricted to only regulating "public utilities" which GCW presumably is not. With respect to the question of whether such a line is a transmission line or a distribution line, PFIMSA has not taken a position on that since we currently do not regulate such lines as stated above. If a State decided to begin regulating such lines, one possible approach the State could take would be to provide advance notice to operators of such lines that it would treat a line operated below 20% SMYS as a distribution line and a line operated above 20% SMYS as a transmission line, provide an opportunity for comment as appropriate under State procedures, and publish a final policy. Coke Oven Gas Pipeline With respect to the coke oven gas pipeline, you stated that a mixture of gaseous hydrocarbons produced by the facility is transported several thousand linear feet before it is burned. You further stated that most ofthis distance is located under the public right of way, some of which runs beneath a public sidewalk outside the fence from the facility in which the gas is burned. Because the coke oven gas is produced in one GCW facility and is transported to another GCW facility under public right-of-way and public sidewalk, this pipeline is subject to the pipeline safety regulations. With respect to classifring such a line as a transmission or a distribution line, you could take a similar approach as the one suggested above. We were pleased to see that you secured a commitment by USS to comply with Illinois' pipeline safety requirements as evidenced by its letter of May 1, 2009. Your participation in the FederallState pipeline safety program is greatly appreciated. I hope that this information is helpful to you. 1ff can be of further assistance, please contact me at (202) 366-4046. Director, Office of Regulations The Pipeline and Hazardous Materials Safety Administration, Office ofPipeline Safety provides written clarifications ofthe Regulations (49 CFR Parts 190-199) in the form of interpretation letters. These letters reflect the agency's current application ofthe regulations to the specific facts presented by the person requesting the clarification. Interpretations do not create legally-enforceable rights or obligations and are provided to help the public understand how to comply with the regulations.#