{"operation":"document","citation":"84 FR 52180","title":"Pipeline Safety: Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments","source_type":"rulemaking","agency":"Pipeline and Hazardous Materials Safety Administration","status":"historical","official":true,"published_on":"2019-10-01","effective_on":"2020-07-01","summary":"PHMSA is revising the Federal Pipeline Safety Regulations to improve the safety of onshore gas transmission pipelines. This final rule addresses congressional mandates, National Transportation Safety Board recommendations, and responds to public input. The amendments in this final rule address integrity management requirements and other requirements, and they focus on the actions an operator must take to reconfirm the maximum allowable operating pressure of previously untested natural gas transmission pipelines and pipelines lacking certain material or operational records, the periodic assessment of pipelines in populated areas not designated as \"high consequence areas,\" the reporting of exceedances of maximum allowable operating pressure, the consideration of seismicity as a risk factor in integrity management, safety features on in-line inspection launchers and receivers, a 6-month grace period for 7-calendar-year integrity management reassessment intervals, and related recordkeeping provisions.","machine_formats":{"json":"https://regulus.evalyn.ai/document/federal-register-2019-20306.json","markdown":"https://regulus.evalyn.ai/document/federal-register-2019-20306.md"},"app_url":"https://regulus.evalyn.ai/document/federal-register-2019-20306","source_url":"https://www.federalregister.gov/documents/2019/10/01/2019-20306/pipeline-safety-safety-of-gas-transmission-pipelines-maop-reconfirmation-expansion-of-assessment","body":"Federal Register, Volume 84 Issue 190 (Tuesday, October 1, 2019) [Federal Register Volume 84, Number 190 (Tuesday, October 1, 2019)] [Rules and Regulations] [Pages 52180-52257] From the Federal Register Online via the Government Publishing Office [ www.gpo.gov ] [FR Doc No: 2019-20306] [[Page 52179]] Vol. 84 Tuesday, No. 190 October 1, 2019 Part II Department of Transportation ----------------------------------------------------------------------- Pipeline and Hazardous Materials Safety Administration ----------------------------------------------------------------------- 49 CFR Parts 191 and 192 Pipeline Safety: Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments; Final Rule Federal Register / Vol. 84 , No. 190 / Tuesday, October 1, 2019 / Rules and Regulations [[Page 52180]] ----------------------------------------------------------------------- DEPARTMENT OF TRANSPORTATION Pipeline and Hazardous Materials Safety Administration 49 CFR Parts 191 and 192 [Docket No. PHMSA-2011-0023; Amdt. Nos. 191-26; 192-125] RIN 2137-AE72 Pipeline Safety: Safety of Gas Transmission Pipelines: MAOP Reconfirmation, Expansion of Assessment Requirements, and Other Related Amendments AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA), DOT. ACTION: Final rule. ----------------------------------------------------------------------- SUMMARY: PHMSA is revising the Federal Pipeline Safety Regulations to improve the safety of onshore gas transmission pipelines. This final rule addresses congressional mandates, National Transportation Safety Board recommendations, and responds to public input. The amendments in this final rule address integrity management requirements and other requirements, and they focus on the actions an operator must take to reconfirm the maximum allowable operating pressure of previously untested natural gas transmission pipelines and pipelines lacking certain material or operational records, the periodic assessment of pipelines in populated areas not designated as ``high consequence areas,'' the reporting of exceedances of maximum allowable operating pressure, the consideration of seismicity as a risk factor in integrity management, safety features on in-line inspection launchers and receivers, a 6-month grace period for 7-calendar-year integrity management reassessment intervals, and related recordkeeping provisions. DATES: The effective date of this final rule is July 1, 2020. The incorporation by reference of certain publications listed in the rule is approved by the Director of the Federal Register as of July 1, 2020. The incorporation by reference of ASME/ANSI B31.8S was approved by the Director of the Federal Register as of January 14, 2004. FOR FURTHER INFORMATION CONTACT: Technical questions: Steve Nanney, Project Manager, by telephone at 713-272-2855. General information: Robert Jagger, Senior Transportation Specialist, by telephone at 202- 366-4361. SUPPLEMENTARY INFORMATION: I. Executive Summary A. Purpose of the Regulatory Action B. Summary of the Major Provisions of the Regulatory Action in Question C. Costs and Benefits II. Background A. Detailed Overview B. Pacific Gas and Electric Incident of 2010 C. Advance Notice of Proposed Rulemaking D. National Transportation Safety Board Recommendations E. Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 F. Notice of Proposed Rulemaking III. Analysis of Comments, GPAC Recommendations and PHMSA Response A. Verification of Pipeline Material Properties and Attributes-- Sec. 192.607 i. Applicability ii. Method B. MAOP Reconfirmation--Sec. Sec. 192.624, 192.632 i. Applicability ii. Methods iii. Spike Test--Sec. 192.506 iv. Fracture Mechanics--Sec. 192.712 v. Legacy Construction Techniques/Legacy Pipe C. Seismicity and Other Integrity Management Clarifications-- Sec. 192.917 D. 6-Month Grace Period for 7-Calendar-Year Reassessment Intervals--Sec. 192.939 E. ILI Launcher and Receiver Safety--Sec. 192.750 F. MAOP Exceedance Reporting--Sec. Sec. 191.23, 191.25 G. Strengthening Assessment Requirements--Sec. Sec. 192.150, 192.493, 192.921, 192.937, Appendix F i. Industry Standards for ILI--Sec. Sec. 192.150, 192.493 ii. Expand Assessment Methods Allowed for IM--Sec. Sec. 192.921(a) and 192.937(c) iii. Guided Wave Ultrasonic Testing--Appendix F H. Assessing Areas Outside of HCAs--Sec. Sec. 192.3, 192.710 i. MCA Definition--Sec. 192.3 ii. Non-HCA Assessments--Sec. 192.710 I. Miscellaneous Issues i. Legal Comments ii. Records iii. Cost/Benefit Analysis, Information Collection, and Environmental Impact Issues IV. GPAC Recommendations V. Section-by-Section Analysis VI. Standards Incorporated by Reference A. Summary of New and Revised Standards B. Availability of Standards Incorporated by Reference VII. Regulatory Analysis and Notices I. Executive Summary A. Purpose of the Regulatory Action PHMSA believes that the current regulatory requirements applicable to gas pipeline systems have increased the level of safety associated with the transportation of gas. Still, incidents continue to occur on gas pipeline systems resulting in serious risks to life and property. One such incident occurred in San Bruno, CA, on September 9, 2010, killing 8 people, injuring 51, destroying 38 homes, and damaging another 70 homes (PG&E incident). In its investigation of the incident, the National Transportation Safety Board (NTSB) found among several causal factors that the operator, Pacific Gas and Electric (PG&E), had an inadequate integrity management (IM) program that failed to detect and repair or remove the defective pipe section. PG&E was basing its IM program on incomplete and inaccurate pipeline information, which led to, among other things, faulty risk assessments, improper assessment method selection, and internal assessments of the program that were superficial and resulted in no meaningful improvement in the integrity of the pipeline system nor the IM program itself. The PG&E incident underscored the need for PHMSA to extend IM requirements and address other issues related to pipeline system integrity. In response, PHMSA published an ANPRM seeking comment on whether IM and other requirements should be strengthened or expanded, and other related issues, on August 25, 2011 (76 FR 53086). The NTSB adopted its report on the PG&E incident on August 30, 2011, and issued several safety recommendations to PHMSA and other entities. Several of these NTSB recommendations related directly to the topics addressed in the 2011 ANPRM and are addressed in this final rule. Also, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 Pipeline Safety Act) was enacted on January 3, 2012. Several of the 2011 Pipeline Safety Act's statutory requirements related directly to the topics addressed in the 2011 ANPRM and are a focus of this rulemaking. Another incident that influenced this rulemaking was the rupture of a gas transmission pipe operated by Columbia Gas near Sissonville, WV, on December 11, 2012. The escaping gas ignited, and fire damage extended nearly 1,100 feet along the pipeline right-of-way and covered an area roughly 820 feet wide. While there were no fatalities or serious injuries, three houses were destroyed by the fire, and several other houses were damaged. The ruptured pipe was one of three in the area that cross Interstate 77, and the incident closed the highway in both directions for 19 hours until a section of thermally damaged road surface approximately 800 feet long could be replaced. Following this incident, the NTSB finalized an accident report on February 19, 2014, issuing recommendations to PHMSA to include principal arterial roadways, [[Page 52181]] including interstates, other freeways and expressways, and other principal arterial roadways as defined by the Federal Highway Administration, to the list of ``identified sites'' that establish a high consequence area (HCA) for the purposes of an operator's IM program. On April 8, 2016, PHMSA published an NPRM to seek public comments on proposed changes to the gas transmission pipeline safety regulations (81 FR 20722). A summary of those proposed changes, and PHMSA's response to stakeholder feedback on the individual provisions, is provided below in section IV of this document (Analysis of Comments and PHMSA Response). The purpose of this final rule is to increase the level of safety associated with the transportation of gas. PHMSA is finalizing requirements that address the causes of several recent incidents, including the PG&E incident, by clarifying and enhancing existing requirements. PHMSA is also addressing certain statutory mandates of the 2011 Pipeline Safety Act and NTSB recommendations. While the NPRM addressed 16 major topic areas, PHMSA believes the most efficient way to manage the proposals in the NPRM is to divide them into three rulemaking actions. PHMSA is finalizing the provisions in this final rule as a first step. PHMSA anticipates completing a second rulemaking to address the topics in the NPRM regarding repair criteria in HCAs and the creation of new repair criteria for non-HCAs, requirements for inspecting pipelines following extreme events, updates to pipeline corrosion control requirements, codification of a management of change process, clarification of certain other IM requirements, and strengthening IM assessment requirements.\\1\\ A third rulemaking is expected to address requirements related to gas gathering lines that were proposed in the NPRM.\\2\\ --------------------------------------------------------------------------- \\1\\ RIN 2137-AF39. \\2\\ RIN 2137-AF38. --------------------------------------------------------------------------- B. Summary of the Major Provisions of the Regulatory Action in Question Several of the amendments made in this rule are related to congressional legislation from the 2011 Pipeline Safety Act. The Act provides a 6-month grace period, with written notice, for the completion of periodic integrity management reassessments that otherwise would be completed no later than every 7 calendar years.\\3\\ Another requirement is that operators explicitly consider and account for seismicity in identifying and evaluating potential threats.\\4\\ The Act also requires operators to report exceedances of the maximum allowable operating pressure (MAOP) of gas transmission pipelines. 5 6 PHMSA is incorporating these changes into the PSR at 49 CFR parts 190-199 in this final rule. --------------------------------------------------------------------------- \\3\\ 2011 Pipeline Safety Act Sec. 5(e). \\4\\ 2011 Pipeline Safety Act Sec. 29. \\5\\ 2011 Pipeline Safety Act Sec. 23. \\6\\ MAOP means the maximum pressure at which a pipeline or segment of a pipeline may be operated under this part. --------------------------------------------------------------------------- This rule also requires operators of certain onshore steel gas transmission pipeline segments to reconfirm the MAOP of those segments and gather any necessary material property records they might need to do so, where the records needed to substantiate the MAOP are not traceable, verifiable, and complete. This includes previously untested pipelines, which are commonly referred to as ``grandfathered'' pipelines, operating at or above 30 percent of specified minimum yield strength (SMYS). Records to confirm MAOP include pressure test records or material property records (mechanical properties) that verify the MAOP is appropriate for the class location.\\7\\ Operators with missing records can choose one of six methods to reconfirm their MAOP and must keep the record that is generated by this exercise for the life of the pipeline. PHMSA has also created an opportunistic method by which operators with insufficient material property records can obtain such records. These physical material property and attribute records include the pipeline segment's diameter, wall thickness, seam type, grade (the minimum yield strength and ultimate tensile strength of the pipe), and Charpy V-notch toughness values (full-size specimen and based on the lowest operational temperatures),\\8\\ if applicable or required. PHMSA considers ``insufficient'' material property records to be those records where the pipeline's physical material properties and attributes are not documented in traceable, verifiable, and complete records. --------------------------------------------------------------------------- \\7\\ PHMSA uses class locations throughout part 192 to provide safety margins and standards commensurate with the potential consequence of a pipeline failure based on the surrounding population. Class locations are defined at Sec. 192.5. A Class 1 location is an offshore area or a class location unit with 10 or fewer buildings intended for human occupancy. A Class 2 location is a class location unit with more than 10 but fewer than 46 buildings intended for human occupancy. A Class 3 location is a class location unit with 46 or more buildings intended for human occupancy, and a Class 4 location is where buildings with 4-or-more stories above ground are prevalent. \\8\\ A Charpy V-notch impact test and its values indicate the toughness of a given material at a specified temperature and is used in fracture mechanics analysis. --------------------------------------------------------------------------- PHMSA is requiring operators to perform integrity assessments on certain pipelines outside of HCAs, whereas prior to this rule's publication, integrity assessments were only required for pipelines in HCAs. Pipelines in Class 3 locations, Class 4 locations, and in the newly defined ``moderate consequence areas'' (MCA) \\9\\ must be assessed initially within 14 years of this rule's publication date and then must be reassessed at least once every 10 years thereafter. These assessments will provide important information to operators about the conditions of their pipelines, including the existence of internal and external corrosion and other anomalies, and will provide an elevated level of safety for the populations in MCAs while continuing to allow operators to prioritize the safety of HCAs. This action fulfills the section 5 mandate from the 2011 Pipeline Safety Act to expand elements of the IM requirements beyond HCAs where appropriate. --------------------------------------------------------------------------- \\9\\ A MCA is defined in Sec. 191.3 as an onshore area within a potential impact circle, as that term is defined in Sec. 192.903, containing either (1) 5 or more buildings intended for human occupancy or (2) 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 4 or more lanes, as defined in the Federal Highway Administration's Highway Functional Classification Concepts, Criteria and Procedures, Section 3.1. --------------------------------------------------------------------------- This rule also explicitly requires devices on in-line inspection (ILI), launcher or receiver facilities that can safely relieve pressure in the barrel before inserting or removing ILI tools, and requires the use of a device that can indicate whether the pressure has been relieved in the barrel or can otherwise prevent the barrel from being opened if the pressure is not relieved. PHMSA is finalizing this requirement in this final rule because it is aware of incidents where operator personnel have been killed or seriously injured due to pressure build-up at these stations. C. Costs and Benefits Consistent with Executive Order 12866, PHMSA has prepared an assessment of the benefits and costs of the final rule as well as reasonable alternatives. PHMSA estimates the annual costs of the rule to be approximately $32.7 million, calculated using a 7 percent discount rate. The costs reflect additional integrity assessments, MAOP reconfirmation, and ILI launcher and receiver upgrades. PHMSA is publishing the Regulatory Impact Analysis (RIA) for this rule in the public docket. The table below [[Page 52182]] provides a summary of the estimated costs for the major provisions in this rulemaking (see the RIA for further detail on these estimates). PHMSA finds that the other final rule requirements will not result in incremental costs. PHMSA did not quantify the cost savings from material properties verification under the final rule compared to existing regulations. PHMSA also elected to not quantify the benefits of this rulemaking and instead discusses them qualitatively. PHMSA estimated total annual costs of the rule of $31.4 million using a 3 percent discount rate, and $32.7 million using a 7 percent discount rate. Summary of Annualized Costs, 2019-2039 [$2017 thousands] ------------------------------------------------------------------------ Annualized cost ------------------------------- Provision 3% Discount 7% Discount rate rate ------------------------------------------------------------------------ 1. MAOP Reconfirmation & Material $25,848 $27,899 Properties Verification................ 2. Seismicity........................... 0.00 0.00 3. Six-Month Grace Period for Seven 0.00 0.00 Calendar-Year Reassessment Intervals... 4. In-Line Inspection Launcher/Receiver 27.4 37.5 Safety................................. 5. MAOP Exceedance Reports.............. 0.00 0.00 6. Strengthening requirements for 0.00 0.00 assessment methods..................... 7. Assessments outside HCAs............. 5,482 4,713 8. Related Records Provisions........... 0.00 0.00 ------------------------------- Total............................... 31,357 32,650 ------------------------------------------------------------------------ II. Background A. Detailed Overview Introduction Recent significant growth in the nation's production and use of natural gas is placing unprecedented demands on the Nation's pipeline system, underscoring the importance of moving this energy product safely and efficiently. Changing spatial patterns of natural gas production and use and an aging pipeline network has made improved documentation and data collection increasingly necessary for the industry to make reasoned safety choices and for preserving public confidence in its ability to do so. Congress recognized these needs when passing the 2011 Pipeline Safety Act, calling for an examination of issues pertaining to the safety of the Nation's pipeline network, including a thorough application of the risk-based integrity assessment, repair, and validation system known as IM.\\10\\ --------------------------------------------------------------------------- \\10\\ The IM regulations specify how pipeline operators must identify, prioritize, assess, evaluate, repair, and validate the integrity of gas transmission pipelines in HCAs that could, in the event of a leak or failure, affect high consequence areas in the United States. These areas include certain populated and occupied areas. See Sec. 192.903. --------------------------------------------------------------------------- This final rule advances the goals established by Congress in the 2011 Pipeline Safety Act and is consistent with the emerging needs of the natural gas pipeline system. This final rule also advances the important discussion about the need to adapt and expand risk-based safety practices. As some severe pipeline incidents have occurred in areas outside HCAs \\11\\ where the application of IM principles are not required, and as gas pipelines continue to experience failures from causes that IM was intended to address, this conversation is increasingly important. --------------------------------------------------------------------------- \\11\\ HCAs are defined at Sec. 192.903. There are two methods that can be used to determine and HCA, the specific differences of which we do not address here. Very broadly and regardless of which method used, operators must calculate the potential impact radius for all points along their pipelines and evaluate corresponding impact circles to identify what populations are contained within each circle. Potential impact circles with 20 or more structures intended for human occupancy, or those circles with ``identified sites'' such as stadiums, playgrounds, office buildings, and religious centers, are defined as HCAs. --------------------------------------------------------------------------- This final rule strengthens IM requirements, including to ensure operators select the appropriate inspection tool or tools to address the pertinent identified threats to their pipeline segments, and clarifies and expands recordkeeping requirements to ensure operators have and retain the basic physical and operational attributes and characteristics of their pipelines. Further, this final rule establishes requirements to periodically assess pipeline segments in locations outside of HCAs where the surrounding population is expected to potentially be at risk from an incident, which are defined in the rule as MCAs. Even though these pipeline segments are not within currently defined HCAs, they could be located in areas with significant populations. This change facilitates prompt identification and remediation of potentially hazardous defects while still allowing operators to make risk-based decisions on where to allocate their maintenance and repair resources. Natural Gas Infrastructure Overview The U.S. natural gas pipeline network is designed to transport natural gas to and from most locations in the lower 48 States. Approximately two-thirds of the lower 48 States depend almost entirely on the interstate transmission pipeline system for their supply of natural gas.\\12\\ One can consider the Nation's natural gas pipeline infrastructure as three interconnected parts--gathering, transmission, and distribution--that together transport natural gas from the production field, where gas is extracted from underground, to its end users, where the gas is used as an energy fuel or chemical feedstock. This final rule applies only to gas transmission lines and does not address gas gathering or natural gas distribution infrastructure and its associated issues. Currently, there are over 300,000 miles of onshore gas transmission pipelines throughout the U.S.\\13\\ --------------------------------------------------------------------------- \\12\\ U.S. Department of Energy, ``Appendix B: Natural Gas,'' Quadrennial Energy Review Report: Energy Transmission, Storage, and Distribution Infrastructure, p. NG-28, April 2015. \\13\\ U.S. DOT Pipeline and Hazardous Materials Safety Administration Data as of 4/26/2018. --------------------------------------------------------------------------- Transmission pipelines primarily transport natural gas from gas treatment plants and gathering systems to bulk customers, local distribution networks, and storage facilities. Transmission pipelines can range in size from several inches to several feet in diameter. They can operate over a wide range of pressures, from a relatively low 200 pounds per square inch gage (psig) to [[Page 52183]] over 1,500 psig. They can be hundreds of miles long, and can operate within the geographic boundaries of a single State, or cross one or more State lines. Regulatory History PHMSA and its State partners regulate and enforce the minimum Federal safety standards authorized by statute \\14\\ and codified in the PSR for jurisdictional \\15\\ gas gathering, transmission, and distribution systems. --------------------------------------------------------------------------- \\14\\ Title 49, United States Code, Subtitle VIII, Pipelines, Sections 60101, et. seq. \\15\\ Typically, onshore pipelines involved in the ``transportation of gas''--see 49 CFR 192.1 and 192.3 for detailed applicability. --------------------------------------------------------------------------- Federal regulation of gas pipeline safety began in 1968 with the creation of the Office of Pipeline Safety and the passage of the Natural Gas Pipeline Safety Act of 1968 (Pub. L. 90-481). The Office of Pipeline Safety issued interim minimum Federal safety standards for gas pipeline facilities and the transportation of natural and other gas by pipeline on November 13, 1968, and subsequently codified broad-based gas pipeline regulations on August 19, 1970 (35 FR 13248). The PSR were revised several times over the following decades to address different aspects of natural gas transportation by pipeline, including construction standards, pipeline materials, design standards, class locations, corrosion control, and MAOP. In the mid-1990s, following models from other industries such as nuclear power, PHMSA started to explore whether a risk-based approach to regulation could improve safety of the public and reduce damage to the environment. During this time, PHMSA found that many operators were performing forms of IM that varied in scope and sophistication but that there were no uniform standards or requirements. PHMSA began developing minimum IM regulations for both hazardous liquid and gas transmission pipelines in response to a hazardous liquid accident in Bellingham, WA, in 1999 that killed 3 people and a gas transmission incident in Carlsbad, NM, in 2000 that killed 12. PHMSA finalized IM regulations for gas transmission pipelines in a 2003 final rule.\\16\\ The IM regulations are intended to provide a structure to operators to focus resources on improving pipeline integrity in the areas where a failure would have the greatest impact on public safety. The IM final rule accelerated the integrity assessment of pipelines in HCAs, improved IM systems, and improved the government's ability to review the adequacy of IM plans. --------------------------------------------------------------------------- \\16\\ ``Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines).'' 68 FR 69778; December 15, 2003. Corrected April 6, 2004 (69 FR 18227) and May 26, 2004 (69 FR 29903). --------------------------------------------------------------------------- The IM regulations require that operators conduct comprehensive analyses to identify, prioritize, assess, evaluate, repair, and validate the integrity of gas transmission pipelines in HCAs. Approximately 7 percent of onshore gas transmission pipeline mileage is located in HCAs.\\17\\ PHMSA and State inspectors review operators' IM programs and associated records to verify that the operators have used all available information about their pipelines to assess risks and take appropriate actions to mitigate those risks. --------------------------------------------------------------------------- \\17\\ Per PHMSA's 2018 Annual Report, accessed April 9, 2019, 20,435 of the 301,227 miles of gas transmission pipelines are classified as being in HCAs. --------------------------------------------------------------------------- Since the implementation of the IM regulations, sweeping changes in the natural gas industry have caused significant shifts in supply and demand, and the Nation's pipeline network faces increased pressures from these changes as well as from the increased exposure caused by a growing and geographically dispersing population. Also, long-identified pipeline safety issues, some of which IM set out to address, remain problems. A records search following the PG&E incident required by Congress in the 2011 Pipeline Safety Act, showed that some pipeline operators do not have the records they need to substantiate the current MAOP of their pipelines, as required under existing regulations, and lacked other critical information needed to properly assess risks and threats and perform effective IM.\\18\\ PHMSA's inspection experience indicates pipelines continue to be vulnerable to failures stemming from outdated construction methods or materials. Finally, some severe pipeline incidents have occurred in areas outside HCAs where the application of IM principles is not required. --------------------------------------------------------------------------- \\18\\ An effective IM program requires operators to analyze many data points regarding threats to their systems in addition to pipe attributes, including, but not limited to, construction data (year of installation, pipe bending method, joining method, depth of cover, coating type, pressure test records, etc.), operational data (maximum and minimum operating pressures, leak and failure history, corrosion monitoring, excavation data, corrosion surveys, ILI data, etc.). --------------------------------------------------------------------------- Following the significant pipeline incident in 2010 at San Bruno, CA, in which 8 people died and more than 50 people were injured, Congress charged PHMSA with improving the IM regulations. Additionally, the NTSB and Government Accountability Office (GAO) issued recommendations regarding IM.\\19\\ Comments in response to a 2011 ANPRM on these and related topics suggested there were many common-sense improvements that could be made to IM, as well as a clear need to extend certain IM provisions to pipelines outside of HCAs that were not covered by the IM regulations. A large portion of the transmission pipeline industry has voluntarily committed to extending certain IM provisions to non-HCA pipe, which demonstrates a common understanding of the need for this strategy. --------------------------------------------------------------------------- \\19\\ More information on the NTSB recommendations being addressed in this rule are discussed in further detail in Section II. D. of this document ``National Transportation Safety Board Recommendations.'' See also, GAO-06-946, Natural Gas Pipeline Safety: Integrity Management Benefits Public Safety, but Consistency of Performance Measures Should be Improved,'' September 8, 2006. --------------------------------------------------------------------------- Through this final rule, PHMSA is making improvements to IM and is improving the ability of operators to engage in a long-range review of risk management and information needs, while also accounting for a changing landscape and a changing population. Supply Changes The U.S. natural gas industry increased production dramatically between 2005 and 2017, from 19.5 trillion cubic feet per year to 28.8 trillion cubic feet per year.\\20\\ This growth was enabled by the production of ``unconventional'' natural gas supplies using improved technology to extract gas from low permeability shales. The increased use of directional drilling \\21\\ and improvements to a long-existing industrial technique--hydraulic fracturing,\\22\\ which began as an experiment in 1947--made the recovery of unconventional natural gas easier and economically viable. This has led to decreased prices and increased use of natural gas, despite a reduction in the production of conventional natural gas of about 14 billion cubic feet per day. Unconventional shale gas production now accounts for nearly 70 percent of overall gas production in the U.S. --------------------------------------------------------------------------- \\20\\ U.S. Department of Energy, Energy Information Administration, ``U.S. Natural Gas marketed Production'' https://www.eia.gov/dnav/ng/hist/n9050us2a.htm , accessed 6/28/18. \\21\\ Directional drilling is the practice of drilling non- vertical wells. \\22\\ The extraction of oil or gas deposits performed by forcing open fissures in subterranean rocks by introducing liquid at high pressures. --------------------------------------------------------------------------- Growth in unconventional natural gas production has shifted production away from traditionally gas-rich regions towards inland shale gas regions. To illustrate, in 2004, wells in the Gulf of Mexico's produced 5,066,000 million [[Page 52184]] cubic feet of natural gas per year (Mcf/year), approximately 20 percent of the Nation's natural gas production at the time. By 2016, that number had fallen to 1,220,000 Mcf/year, and approximately 4 percent of natural gas production in the U.S. During that same period, Pennsylvania's share of production grew from 197,217 Mcf/year to 5,463,783 Mcf/year, or approximately 17 percent of total natural gas production in the U.S. 23 24 An analysis conducted by the Department of Energy's Office of Energy Policy and Systems Analysis projects that the most significant increases in production through 2030 will occur in the Marcellus and Utica Basins in the Appalachian Basin,\\25\\ and natural gas production is projected to grow from the 2015 levels of 66.5 Bcf/d to more than 93.5 Bcf/d.\\26\\ --------------------------------------------------------------------------- \\23\\ U.S. Department of Energy, Energy Information Administration, ``Gulf of Mexico--Offshore Natural Gas Withdrawals,'' https://www.eia.gov/dnav/ng/hist/na1060_r3fmtf_2a.htm , accessed 6/28/18. \\24\\ U.S. Department of Energy, Energy Information Administration, ``Pennsylvania Natural Gas Gross Withdrawals,'' https://www.eia.gov/dnav/ng/hist/n9010pa2a.htm , accessed 6/28/18. \\25\\ U.S. Department of Energy, ``Appendix B: Natural Gas,'' Quadrennial Energy Review Report: Energy Transmission, Storage, and Distribution Infrastructure, p. NG-28, April 2015. \\26\\ Id., at NG-6. --------------------------------------------------------------------------- Demand Changes The increase in domestic natural gas production has led to lower average natural gas prices.\\27\\ In 2004, the outlook for natural gas production and demand growth was weak. Monthly average spot prices at Henry Hub \\28\\ were high based on historic comparison of prices, fluctuating between $4 per million British thermal units (Btu) and $7 per million Btu. Prices rose above $11 per million Btu for several months in both 2005 and 2008.\\29\\ Since 2008, after production shifted to onshore unconventional shale resources, and price volatility fell away following the Great Recession, natural gas has traded between about $2 per million Btu and $5 per million Btu.\\30\\ --------------------------------------------------------------------------- \\27\\ Id., at NG-11. \\28\\ Henry Hub is a Louisiana natural gas distribution hub where conventional Gulf of Mexico natural gas can be directed to gas transmission lines running to different parts of the country. Gas bought and sold at the Henry hub serves as the national benchmark for U.S. natural gas prices. (Id., at NG-29, NG-30). \\29\\ Energy Information Administration, Natural Gas Spot and Futures Prices, http://www.eia.gov/dnav/ng/ng_pri_fut_s1_m.htm , retrieved August 2018. \\30\\ U.S. Department of Energy, ``Appendix B: Natural Gas,'' Quadrennial Energy Review Report: Energy Transmission, Storage, and Distribution Infrastructure, p. NG-11, April 2015. --------------------------------------------------------------------------- These low prices have fueled consumption growth and changes in markets and spatial patterns of consumption. A shift towards natural gas-fueled electric power generation, cleaner than other types of fossil fuels, is helping to serve the needs of the Nation's growing population, and increased gas production and lower domestic prices have created opportunities for international export. Plentiful domestic natural gas supply and comparatively low natural gas prices have changed the economics of electric power markets.\\31\\ To accommodate recent growth and expected future growth in natural gas- fueled power, changes in pipeline infrastructure will be needed, including flow reversals of existing pipelines; additional lines to gas-fired generators; looping of existing networks, where multiple pipelines are laid parallel to one another along a single right-of-way to increase the capacity of a single system; and, potentially, new pipelines as well. --------------------------------------------------------------------------- \\31\\ Id., at NG-9. --------------------------------------------------------------------------- Increasing Pressures on the Existing Pipeline System Due to Supply and Demand Changes Despite the significant increase in domestic gas production and the widespread distribution of domestic gas demand, significant flexibility and capacity in the existing transmission system mitigates the level of pipeline expansion and investment required. Some of the new gas production is located near existing or emerging sources of demand, which reduces the need for additional natural gas pipeline infrastructure. In many instances where new natural gas transmission capacity is needed, the network is being expanded by pipeline investments to enhance network capacity on existing lines rather than increasing coverage through new infrastructure. Additionally, operators have avoided building new pipelines by increasing pipeline diameters or operating pressures. In short, the nation's existing pipeline system is facing the brunt of this dramatic increase in natural gas supply and the shifting energy needs of the country. In cases where use of the existing pipeline network is high, the next most cost-effective solution is to add capacity to existing lines via compression.\\32\\ Compression requires infrastructure investment in the form of more compressor stations along the pipeline route, but it can be less costly, faster, and simpler for market participants in comparison to building a new pipeline. Adding compression, however, raises pipeline operating pressures and can expose previously hidden defects. --------------------------------------------------------------------------- \\32\\ Gas can be reduced in volume by increasing its pressure. Therefore, operators can pack more gas into their lines if they can increase the pressure of the gas being transported. --------------------------------------------------------------------------- New pipeline projects have been proposed to address pending supply constraints and higher prices. However, gaining public acceptance for natural gas pipeline construction has proved to be a substantial challenge. Pipeline expansion and construction projects often face significant challenges in determining feasible right-of-ways and developing community support for the projects. Data Challenges Operators and regulators must have an intimate understanding of the threats to, and operations of, their entire pipeline system. Data gathering and integration are important elements of good IM practices, and while operators have made many strides over the years to collect more and better data, several data gaps still exist. Ironically, the comparatively positive safety record of the Nation's gas transmission pipelines to date makes it harder to quantify some of these gaps. Over the 20-year period of 1998-2017, transmission facilities accounted for 50 fatalities and 179 injuries, or about one-sixth to one-seventh of the total fatalities and injuries caused by natural gas pipeline incidents in the U.S.\\33\\ Given the relatively limited number of significant incidents that occur, it can be challenging to project the possible impact of low-probability but high-consequence events. See the RIA included in the public docket for a more detailed analysis of key types of incidents that may be mitigated by this final rule. --------------------------------------------------------------------------- \\33\\ PHMSA, Pipeline Incident 20-Year Trends, http://www.phmsa.dot.gov/pipeline/library/data-stats/pipelineincidenttrends . --------------------------------------------------------------------------- On September 9, 2010, a 30-inch-diameter segment of an intrastate natural gas transmission pipeline owned and operated by PG&E ruptured in a residential area of San Bruno, CA. The natural gas that was released subsequently ignited, resulting in a fire that destroyed 38 homes and damaged 70. Eight people were killed, many were injured, and many more were evacuated from the area. The PG&E incident exposed several problems in the way data on pipeline conditions is collecte","truncated":true,"body_characters":567957}