{"operation":"document","citation":"81 FR 20722","title":"Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines","source_type":"rulemaking","agency":"Pipeline and Hazardous Materials Safety Administration","status":"proposed","official":true,"published_on":"2016-04-08","effective_on":null,"summary":"This Notice of Proposed Rulemaking (NPRM) proposes to revise the Pipeline Safety Regulations applicable to the safety of onshore gas transmission and gathering pipelines. PHMSA proposes changes to the integrity management (IM) requirements and proposes changes to address issues related to non-IM requirements. This NPRM also proposes modifying the regulation of onshore gas gathering lines.","machine_formats":{"json":"https://regulus.evalyn.ai/document/federal-register-2016-06382.json","markdown":"https://regulus.evalyn.ai/document/federal-register-2016-06382.md"},"app_url":"https://regulus.evalyn.ai/document/federal-register-2016-06382","source_url":"https://www.federalregister.gov/documents/2016/04/08/2016-06382/pipeline-safety-safety-of-gas-transmission-and-gathering-pipelines","body":"Federal Register, Volume 81 Issue 68 (Friday, April 8, 2016) [Federal Register Volume 81, Number 68 (Friday, April 8, 2016)] [Proposed Rules] [Pages 20722-20856] From the Federal Register Online via the Government Publishing Office [ www.gpo.gov ] [FR Doc No: 2016-06382] [[Page 20721]] Vol. 81 Friday, No. 68 April 8, 2016 Part II Department of Transportation ----------------------------------------------------------------------- Pipeline and Hazardous Materials Safety Administration ----------------------------------------------------------------------- 49 CFR Parts 191 and 192 Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines; Proposed Rule Federal Register / Vol. 81 , No. 68 / Friday, April 8, 2016 / Proposed Rules [[Page 20722]] ----------------------------------------------------------------------- DEPARTMENT OF TRANSPORTATION Pipeline and Hazardous Materials Safety Administration 49 CFR Parts 191 and 192 [Docket No. PHMSA-2011-0023] RIN 2137-AE72 Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines AGENCY: Pipeline and Hazardous Materials Safety Administration (PHMSA), Department of Transportation (DOT). ACTION: Notice of proposed rulemaking. ----------------------------------------------------------------------- SUMMARY: This Notice of Proposed Rulemaking (NPRM) proposes to revise the Pipeline Safety Regulations applicable to the safety of onshore gas transmission and gathering pipelines. PHMSA proposes changes to the integrity management (IM) requirements and proposes changes to address issues related to non-IM requirements. This NPRM also proposes modifying the regulation of onshore gas gathering lines. DATES: Persons interested in submitting written comments on this NPRM must do so by June 7, 2016. ADDRESSES: You may submit comments identified by the docket number PHMSA-2011-0023 by any of the following methods: Federal eRulemaking Portal: http://www.regulations.gov . Follow the online instructions for submitting comments. Fax: 1-202-493-2251. Mail: Hand Delivery: U.S. DOT Docket Management System, West Building Ground Floor, Room W12-140, 1200 New Jersey Avenue SE., Washington, DC 20590-0001 between 9 a.m. and 5 p.m., Monday through Friday, except Federal holidays. Instructions: If you submit your comments by mail, submit two copies. To receive confirmation that PHMSA received your comments, include a self-addressed stamped postcard. Note: Comments are posted without changes or edits to http://www.regulations.gov , including any personal information provided. There is a privacy statement published on http://www.regulations.gov . FOR FURTHER INFORMATION CONTACT: Mike Israni, by telephone at 202-366- 4571, or by mail at U.S. DOT, PHMSA, 1200 New Jersey Avenue SE., PHP- 30, Washington, DC 20590-0001. SUPPLEMENTARY INFORMATION: Outline of This Document 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. Advance Notice of Proposed Rulemaking C. National Transportation Safety Board Recommendations D. Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 E. Summary of Each Topic Under Consideration F. Integrity Verification Process Workshop III. Analysis of Comments on the Advance Notice of Proposed Rulemaking A. Modifying the Definition of HCA B. Strengthening Requirements To Implement Preventive and Mitigative Measures for Pipeline Segments in HCAs C. Modifying Repair Criteria D. Improving Requirements for Collecting, Validating, and Integrating Pipeline Data E. Making Requirements Related to the Nature and Application of Risk Models More Prescriptive F. Strengthening Requirements for Applying Knowledge Gained Through the IM Program G. Strengthening Requirements on the Selection and Use of Assessment Methods H. Valve Spacing and the Need for Remotely or Automatically Controlled Valves I. Corrosion Control J. Pipe Manufactured Using Longitudinal Weld Seams K. Establishing Requirements Applicable to Underground Gas Storage L. Management of Change M. Quality Management Systems (QMS) N. Exemption of Facilities Installed Prior to the Regulations O. Modifying the Regulation of Gas Gathering Lines IV. Other Proposals V. Section-by-Section Analysis VI. 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 with significant consequences and various causes continue to occur on gas pipeline systems. PHMSA has also identified concerns during inspections of gas pipeline operator programs that indicate a potential need to clarify and enhance some requirements. Based on this experience, this NPRM proposes additional safety measures to increase the level of safety for those pipelines that are not in HCAs as well as clarifications and selected enhancements to integrity management requirements to improve safety in HCAs. On August 25, 2011, PHMSA published an Advance Notice of Proposed Rulemaking (ANPRM) to seek feedback and comments regarding the revision of the Pipeline Safety Regulations applicable to the safety of gas transmission and gas gathering pipelines. In particular, PHMSA requested comments regarding whether integrity management (IM) requirements should be changed and whether other issues related to system integrity should be addressed by strengthening or expanding non- IM requirements. Subsequent to issuance of the ANPRM, the National Transportation Safety Board (NTSB) adopted its report on the San Bruno accident on August 30, 2011. The NTSB issued safety recommendations P-11-1 and P- 11-2 and P-11-8 through -20 to PHMSA, and issued safety recommendations P-10-2 through -4 to Pacific Gas & Electric (PG&E), among others. Several of these NTSB recommendations related directly to the topics addressed in the August 25, 2011 ANPRM and have an impact on the proposed approach to rulemaking. Also subsequent to issuance of the ANPRM, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the Act) was enacted on January 3, 2012. Several of the Act's statutory requirements related directly to the topics addressed in the August 25, 2011 ANPRM and have an impact on the proposed approach to rulemaking. Congress has authorized Federal regulation of the transportation of gas by pipeline in the Pipeline Safety Laws (49 U.S.C. 60101 et seq.), a series of statutes that are administered by the DOT, PHMSA. PHMSA has used that authority to promulgate comprehensive minimum safety standards for the transportation of gas by pipeline. Congress established the current framework for regulating pipelines transporting gas in the Natural Gas Pipeline Safety Act of 1968, Public Law 90-481. That law delegated to DOT the authority to develop, prescribe, and enforce minimum Federal safety standards for the transportation of gas, including natural gas, flammable gas, or toxic or corrosive gas, by pipeline. Congress has since enacted additional legislation that is currently codified in the Pipeline Safety Laws, including: In 1992, Congress required regulations be issued to define the term ``gathering line'' and establish safety standards for certain ``regulated gathering lines,'' Public Law 102-508. In 1996, Congress directed that DOT conduct demonstration projects evaluating the application of risk management principles to pipeline safety regulation, and [[Page 20723]] mandated that regulations be issued for the qualification and testing of certain pipeline personnel, Public Law 104-304. In 2002, Congress required that DOT issue regulations requiring operators of gas transmission pipelines to conduct risk analyses and to implement IM programs under which pipeline segments in high consequence areas (HCA) would be subject to a baseline assessment within 10 years and re-assessments at least every seven years, and required that standards be issued for assessment of pipelines using direct assessment, Public Law 107-355. B. Summary of the Major Provisions of the Regulatory Action in Question PHMSA plans to address several of the topics in the ANPRM in separate rulemakings because of the diverse scope and nature of several NTSB recommendations and the statutory requirements of the Act that were covered in the ANPRM. This proposed rule addresses several IM topics, including: Revision of IM repair criteria for pipeline segments in HCAs to address cracking defects, non-immediate corrosion metal loss anomalies, and other defects; explicitly including functional requirements related to the nature and application of risk models currently invoked by reference to industry standards; explicitly specifying requirements for collecting, validating, and integrating pipeline data models currently invoked by reference to industry standards; strengthening requirements for applying knowledge gained through the IM Program models currently invoked by reference to industry standards; strengthening requirements on the selection and use of direct assessment methods models by incorporating recently issued industry standards by reference; adding requirements for monitoring gas quality and mitigating internal corrosion, and adding requirements for external corrosion management programs including above ground surveys, close interval surveys, and electrical interference surveys; and explicitly including requirements for management of change currently invoked by reference to industry standards. With respect to non-IM requirements, this NPRM proposes: A new ``moderate consequence areas'' definition; adding requirements for monitoring gas quality and mitigating internal corrosion; adding requirements for external corrosion management programs including above ground surveys, close interval surveys, and electrical interference surveys; additional requirements for management of change, including invoking the requirements of ASME/ANSI B31.8S, Section 11; establishing repair criteria for pipeline segments located in areas not in an HCA; and requirements for verification of maximum allowable operating pressure (MAOP) in accordance with new Sec. 192.624 and for verification of pipeline material in accordance with new section Sec. 192.607 for certain onshore, steel, gas transmission pipelines. This includes establishing and documenting MAOP if the pipeline MAOP was established in accordance with Sec. 192.619(c) or the pipeline meets other criteria indicating a need for establishing MAOP. In addition, this NPRM proposes modifying the regulation of onshore gas gathering lines. The proposed rulemaking would repeal the exemption for reporting requirements for gas gathering line operators and repeal the use of API RP 80 for determining regulated onshore gathering lines and add a new definition for ``onshore production facility/operation'' and a revised definition for ``gathering lines.'' The proposed rulemaking would also extend certain part 192 regulatory requirements to Type A lines in Class 1 locations for lines 8 inches or greater. Requirements that would apply to previously unregulated pipelines meeting these criteria would be limited to damage prevention, corrosion control (for metallic pipe), public education program, maximum allowable operating pressure limits, line markers, and emergency planning. This NPRM also proposes requirements for additional topics that have arisen since issuance of the ANPRM. These include: (1) Requiring inspections by onshore pipeline operators of areas affected by an extreme weather event such as a hurricane or flood, landslide, an earthquake, a natural disaster, or other similar event; (2) revising the regulations to allow extension of the IM 7-year reassessment interval upon written notice per Section 5 of the Act; (3) adding a requirement to report each exceedance of the MAOP that exceeds the margin (build-up) allowed for operation of pressure-limiting or control devices per Section 23 of the Act; (4) adding requirements to ensure consideration of seismicity of the area in identifying and evaluating all potential threats per Section 29 of the Act; (5) adding regulations to require safety features on launchers and receivers for in-line inspection, scraper, and sphere facilities; and (6) incorporating consensus standards into the regulations for assessing the physical condition of in-service pipelines using in-line inspection, internal corrosion direct assessment, and stress corrosion cracking direct assessment. The overall goal of this proposed rule is to increase the level of safety associated with the transportation of gas by proposing requirements to address the causes of recent incidents with significant consequences, clarify and enhance some existing requirements, and address certain statutory mandates of the Act and NTSB recommendations.\\1\\ --------------------------------------------------------------------------- \\1\\ PHMSA plans to initiative separate rulemaking to address other topics included in the ANPRM and that would implement other requirements of the Act and NTSB recommendations. --------------------------------------------------------------------------- C. Costs and Benefits Consistent with Executive Orders 12866 and 13563, PHMSA has prepared an assessment of the benefits and costs of the proposed rule as well as reasonable alternatives. PHMSA is publishing the Preliminary Regulatory Impact Analysis (PRIA) for this proposed rule simultaneously with this document, and it is available in the docket. PHMSA estimates the total (15-year) present value of benefits from the proposed rule to be approximately $3,234 to $3,738 million \\2\\ using a 7% discount rate ($4,050 to $4,663 million using a 3% discount rate) and the present value of costs to be approximately $597 million using a 7% discount rate ($711 million using a 3% discount rate). The table below summarizes the average annual present value benefits and costs by topic area. The majority of benefits reflect cost savings from material verification (processes to determine maximum allowable operating pressure for segments for which records are inadequate) under the proposed rule compared to existing regulations; the range in these benefits reflects different effectiveness assumptions for estimating safety benefits. Costs reflect primarily integrity verification and assessment costs (pressure tests, inline inspection, and direct assessments). The proposed gas gathering regulations account for the next largest portion of benefits and costs and primarily reflect safety provisions and associated risk reductions on previously unregulated lines. --------------------------------------------------------------------------- \\2\\ Range reflects uncertainty in defect failure rates for Topic Area 1. [[Page 20724]] Summary of Average Annual Present Value Benefits and Costs \\1\\ [Millions; 2015$] ---------------------------------------------------------------------------------------------------------------- 7% discount rate 3% discount rate Topic area ----------------------------------------------------- Benefits Costs Benefits Costs ---------------------------------------------------------------------------------------------------------------- Re-establish MAOP, verify material properties, and $196.9-$230.5 $17.8 $247.8-$288.6 $22.0 integrity assessments outside HCAs....................... Integrity management process clarifications............... n.e. 2.2 n.e. 1.3 Management of change process improvement.................. 1.1 0.7 1.2 0.8 Corrosion control......................................... 5.5 6.3 5.9 7.9 Pipeline inspection following extreme events.............. 0.3 0.1 0.3 0.1 MAOP exceedance reports and records verification.......... n.e. 0.2 n.e. 0.2 Launcher/receiver pressure relief......................... 0.4 0.0 0.6 0.0 Gas gathering regulations................................. 11.3 12.6 14.2 15.1 ----------------------------------------------------- Total................................................. 215.6-249.2 39.8 270-310.8 47.4 ---------------------------------------------------------------------------------------------------------------- HCA = high consequence area. MAOP = maximum allowable operating pressure. n.e. = not estimated. \\1\\ Total over 15-year study period divided by 15. Additional costs to states estimated not to exceed $1.5 million per year. Range of benefits reflects range in estimated defect failure rates. \\2\\ Break even value of benefits, based on the average consequences for incidents in high consequence areas, would equate to less than one incident averted over the 15-year study period. For the seven percent discount rate scenario, approximately 13 percent of benefits are due to safety benefits from incidents averted, 82 percent represent cost savings from MAOP verification in Topic Area 1, and four percent are attributable to reductions in greenhouse gas emissions. (For the three percent discount rate scenario, these percentages are approximately 13, 83, and 3 percent, respectively.) II. Background A. Detailed Overview Introduction The significant and expected 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. With changing spatial patterns of natural gas production and use and an aging pipeline network, improved documentation and data collection are 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 Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, calling for an examination of a broad range 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 ``integrity management'' (IM). This proposed rulemaking advances the goals established by Congress in the 2011 Act, which are consistent with the emerging needs of the natural gas pipeline system. This proposed rule also advances an important discussion about the need to adapt and expand risk-based safety practices in light of changing markets and a growing national population whose location choices increasingly encroach on existing pipelines. As some severe pipeline accidents have occurred in areas outside of high consequence areas (HCA) where the application of IM principles is not required, and as gas pipelines continue to experience failures from causes that IM was intended to address, this conversation is increasingly important. This proposed rule strengthens protocols for IM, including protocols for inspections and repairs, and improves and streamlines information collection to help drive risk-based identification of the areas with the greatest safety deficiencies. Further, this proposed rule establishes requirements to periodically assess and extend aspects of IM to pipeline segments in locations where the surrounding population is expected to potentially be at risk from an incident. Even though these segments are not within currently defined HCAs, they could be located in areas with significant populations where incidents could have serious consequences. This change would facilitate prompt identification and remediation of potentially hazardous defects and anomalies 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 supplies of natural gas.\\3\\ To envision the scope of the nation's natural gas pipeline infrastructure, it is best to consider it in three interconnected parts 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. These three parts are referred to as gathering, transmission, and distribution systems. Because this proposed rule applies only to gas gathering and transmission lines, this document will not discuss natural gas distribution infrastructure and its associated issues. Currently, there are over 11,000 miles of onshore gas gathering pipelines and 297,814 miles of onshore gas transmission pipelines throughout the U.S.\\4\\ --------------------------------------------------------------------------- \\3\\ U.S. Department of Energy, ``Appendix B: Natural Gas,'' Quadrennial Energy Review Report: Energy Transmission, Storage, and Distribution Infrastructure, p. NG-28, April 2015. \\4\\ US DOT Pipeline and Hazardous Materials Safety Administration Data as of 9/25/2015. --------------------------------------------------------------------------- Gas gathering lines are pipelines used to transport natural gas from production sites to central collection points, which are often gas treatment plants where pipeline-quality gas is separated from petroleum liquids and various impurities. Historically, these lines were of smaller diameters than gas transmission lines and operated at lower pressures. However, due to changing demand factors, some gathering lines are being constructed with diameters equal to or larger than typical transmission lines and are being operated at much higher pressures. Transmission pipelines primarily transport natural gas from gas treatment [[Page 20725]] plants and gathering systems to bulk customers, local distribution networks, and storage facilities. Transmission pipelines are typically made of steel and can range in size from several inches to several feet in diameter. They can operate over a wide range of pressures, from relatively low (200 pounds per square inch) to over 1,500 pounds per square inch gage (psig). They can operate within the geographic boundaries of a single State, or span hundreds of miles, crossing one or more State lines. Regulatory History PHMSA and its State partners regulate pipeline safety for jurisdictional \\5\\ gas gathering, transmission, and distribution systems under minimum Federal safety standards authorized by statute \\6\\ and codified in the Pipeline Safety Regulations at 49 CFR parts 190-199. --------------------------------------------------------------------------- \\5\\ Typically, onshore pipelines involved in the ``transportation of gas''--see 49 CFR 192.1 and 192.3 for detailed applicability. \\6\\ Title 49, United States Code, Subtitle VIII, Pipelines, Sections 60101, et. seq. --------------------------------------------------------------------------- Federal regulation of gas pipeline safety began in 1968 with the creation of the Office of Pipeline Safety and their subsequent issuance of interim minimum Federal safety standards for gas pipeline facilities and the transportation of natural and other gas in accordance with the Natural Gas Pipeline Safety Act of 1968 (Pub. L. 90-481). These Federal safety standards were upgraded 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 maximum allowable operating pressure (MAOP). These original Pipeline Safety Regulations were not designed with risk-based regulations in mind. 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 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 minimum standards or requirements. In response to a hazardous liquid incident in Bellingham, WA, in 1999 that killed 3 people and a gas transmission incident in Carlsbad, NM, in 2000 that killed 12, IM regulations for gas transmission pipelines were finalized in 2004.\\7\\ The primary goal of the 2004 IM regulations was to provide a structure to operators for focusing their resources on improving pipeline integrity in the areas where a failure would have the greatest impact on public safety. Further objectives included accelerating the integrity assessment of pipelines in HCAs, improving IM systems within companies, improving the government's ability to review the adequacy of integrity programs and plans, thus providing increased public assurance in pipeline safety. --------------------------------------------------------------------------- \\7\\ [68 FR 69778, Dec. 15, 2003] 49 CFR part 192 [Docket No. RSPA-00-7666; Amendment 192-95] Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines). --------------------------------------------------------------------------- The IM regulations specify how pipeline operators must conduct comprehensive analyses to identify, prioritize, assess, evaluate, repair, and validate the integrity of gas transmission pipelines in HCAs, which are typically areas where population is highly concentrated. Currently, approximately 7 percent of onshore gas transmission pipeline mileage is located in HCAs. PHMSA and state inspectors review operators' written 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. Since the implementation of the IM regulations more than 10 years ago, many factors have changed. Most importantly, sweeping changes in the natural gas industry have caused significant shifts in supply and demand, and the nation's relatively safe but aging pipeline network faces increased pressures from these changes as well as from the increased exposure caused by a growing and geographically dispersing population. Long-identified pipeline safety issues, some of which IM set out to address, remain problems. Infrequent but severe accidents indicate that some pipelines continue to be vulnerable to failures stemming from outdated construction methods or materials. Some severe pipeline accidents have occurred in areas outside HCAs where the application of IM principles is not required. Gas pipelines continue to experience failures from causes that IM was intended to address, such as corrosion, and the measures currently in use have not always been effective in identifying and preventing these causes of pipeline damage. There is a pressing need for an improved strategy to protect the safety and integrity of the nation's pipeline system. Following a significant pipeline incident in 2010 at San Bruno, CA, in which 8 people died and more than 50 people were injured, Congress, the National Transportation Safety Board (NTSB), and the Government Accountability Office (GAO) charged PHMSA with improving IM. Comments from a 2011 advanced notice of proposed rulemaking (ANPRM) 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 not now 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 clearly underscores the common understanding of the need for this strategy. Through this proposed rule, PHMSA is taking action to deliver a comprehensive strategy to improve gas transmission pipeline safety and reliability, through both immediate improvements to IM and 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 has undergone changes of unprecedented magnitude and pace, increasing production by 33 percent between 2005 and 2013, from 19.5 trillion cubic feet per year to 25.7 trillion cubic feet per year.\\8\\ Driving these changes has been a shift towards the production of ``unconventional'' natural gas supplies using improved technology to extract gas from low permeability shales. The increased use of directional drilling and improvements to a long- existing industrial technique--hydraulic fracturing, which began as an experiment in 1947--made the recovery of unconventional natural gas easier and economically viable. This shift in production has decreased prices and spurred tremendous increases in the use of natural gas. --------------------------------------------------------------------------- \\8\\ U.S. Department of Energy, ``Appendix B: Natural Gas,'' Quadrennial Energy Review Report: Energy Transmission, Storage, and Distribution Infrastructure, p. NG-2, April 2015. --------------------------------------------------------------------------- While conventional natural gas production in the U.S. has fallen over the past decade by about 14 billion cubic feet per day, overall natural gas production has grown due to increased unconventional shale gas production. In 2004, unconventional shale gas accounted for about 5 percent of the total natural gas production in the U.S. Since then, unconventional shale gas [[Page 20726]] production has increased more than tenfold from 2.7 Bcf/d to about 35.0 Bcf/d in 2014 \\9\\ and now accounts for about half of overall gas production in the U.S.\\10\\ --------------------------------------------------------------------------- \\9\\ Id., at NG-7. \\10\\ Id. --------------------------------------------------------------------------- This increase in unconventional natural gas production shifted production away from traditional gas-rich regions towards onshore shale gas regions. In 2004, the Gulf of Mexico produced about 20 percent of the nation's natural gas supply, but by2013, that number had fallen to 5 percent. During that same time, Pennsylvania's share of production grew from 1 percent to 13 percent. An analysis conducted by the Department of Energy's (DOE) 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,\\11\\ which will continue to fuel growth in natural gas production from current levels of 66.5 Bcf/d to more than 93.5 Bcf/ d.\\12\\ --------------------------------------------------------------------------- \\11\\ Id., at NG-6. \\12\\ Id. --------------------------------------------------------------------------- Demand Changes The recent increase in domestic natural gas production has led to decreased gas price volatility and lower average prices.\\13\\ In 2004, the outlook for natural gas production and demand growth was weak. Monthly average spot prices at Henry Hub \\14\\ were high, 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.\\15\\ 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.\\16\\ --------------------------------------------------------------------------- \\13\\ Id., at NG-11. \\14\\ 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). \\15\\ Energy Information Administration, Natural Gas Spot and Futures Prices, http://www.eia.gov/dnav/ng/ng_pri_fut_s1_m.htm , retrieved 14 October 2015. \\16\\ Id., at NG-11. --------------------------------------------------------------------------- These historically low prices for this commodity are fueling tremendous consumption growth and changes in markets and spatial patterns of consumption. A shift towards natural gas-fueled electric power generation is helping to serve the needs of the nation's growing population while helping reduce greenhouse gas emissions, and American industries are taking advantage of cheap energy by investing in onshore production capacity, while also exploring economic opportunities for international energy export. Plentiful domestic natural gas supply and comparatively low natural gas prices have changed the economics of electric power markets.\\17\\ Further, new environmental standards at the local, state, regional, and Federal levels have encouraged switching to fuels with lower emissions profiles, including natural gas and renewables. U.S. natural gas consumption for power generation grew from 15.8 billion cubic feet per day (Bcf/d) in 2005 to 22.2 Bcf/d in 2013, and demand is projected to increase by another 8.9 Bcf/d by 2030.\\18\\ Net gas-fired electricity generation increased 73 percent nationally from 2003 to 2013, and natural gas-fired power plants accounted for more than 50 percent of new utility-scale generating capacity added in 2013. To accommodate continued future growth in natural gas-fueled power, changes in pipeline infrastructure will be needed, including reversals of existing pipelines; additional lines to gas-fired generators; looping of the existing network, where pipelines are laid parallel to one another along a single right-of-way to increase capacity; and potentially new pipelines as well. --------------------------------------------------------------------------- \\17\\ Id., at NG-9. \\18\\ Id. --------------------------------------------------------------------------- Further, the increased availability of low-cost natural gas has brought jobs back to American soil, and increasing investment in projects designed to take advantage of the significant increase in supplies of low-cost gas available in the U.S. suggests this trend will continue.\\19\\ Moreover, low domestic prices and high international prices have made natural gas export increasingly attractive to American businesses. The Federal Energy Regulatory Commission, as of September 2015, estimated U.S. LNG prices at $2.25-$2.41 per million Btu, while prices in areas of Asia, Europe, and South America ranged from $6.30 to $7.62 per million Btu.\\20\\ Due to high capital investment barriers and coordination difficulties between pipeline shippers, the maritime shipping industry, and pipeline operators, there are not enough ships and processing facilities to transport enough LNG to equalize prices. Taking advantage of these price differentials, liquefied natural gas exporting terminals in the U.S. and British Columbia, Canada, are projected to demand between 5.1 Bcf/d and 8.3 Bcf/d of gas by 2030.\\21\\ --------------------------------------------------------------------------- \\19\\ Id., at NG-10. \\20\\ https://www.ferc.gov/market-oversight/mkt-gas/overview/ngas-ovr-lng-wld-pr-est.pdf . \\21\\ U.S. Department of Energy, ``Appendix B: Natural Gas,'' Quadrennial Energy Review Report: Energy Transmission, Storage, and Distribution Infrastructure, p. NG-11, April 2015. --------------------------------------------------------------------------- Increasing Pressures on the Existing Pipeline System Due to Supply and Demand Changes Despite the significant increase in domestic gas production, the widespread distribution of domestic gas demand, combined with significant flexibility and capacity in the existing transmission system, mitigates the level of pipeline expansion and investment required to accommodate growing and shifting demand. 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 pipelines are needed, the network is being expanded by participants pursuing lowest- cost options to move product to market--often making investments to enhance network capacity on existing lines rather than increasing coverage through new infrastructure. Where this capacity is not increasing via additional mileage, it is increasing through larger pipeline diameters or higher operating pressures. In short, the nation's existing, and in many cases, aging, pipeline system is facing the full brunt of this dramatic increase in natural gas supply and the shifting energy needs of the country. The U.S. Energy Information Administration estimates that between 2004 and 2013, the natural gas industry spent about $56 billion expanding the natural gas pipeline network. Between 2008 and 2013, pipeline capacity additions totaled more than 110 Bcf/d.\\22\\ Despite this increase in capacity, gas transmission mileage decreased from 299,358 miles in 2010 to 298,287 miles in 2013. --------------------------------------------------------------------------- \\22\\ Id., at NG-31. --------------------------------------------------------------------------- Building new infrastructure, or replacing and modernizing old infrastructure, is expensive and requires a long lead-time for planning. Frequently, the most inexpensive way to move new production to demand centers is by using available existing infrastructure. For several reasons, the U.S.'s extensive pre-existing gas network is currently underutilized: (1) Pipelines are long-lived assets that reflect historic supply and demand trends; (2) pipelines often are sized to meet high initial production levels and [[Page 20727]] have excess long-term capacity due to changing economics; and (3) pipelines that were built specifically to provide gas to residential and commercial consumers in cold-weather regions but not for power generation are often under-utilized during off-peak seasons. In cases where utilization of the existing pipeline network is high, the next most cost-effective solution is to add capacity to existing lines via compression. While this is technically a form of infrastructure investment, it is less costly, faster, and simpler for market participants in comparison to building a new pipeline. Adding compression, however, may raise average pipeline operating pressures, exposing previously hidden defects. Developers also recognize that building new pipelines is challenging due to societal fears and cost, so new pipelines are typically designed in such a way that they can handle additional capacity if needed. In New England, new pipeline projects have been proposed to address pending supply constraints and higher prices. However, public acceptance presents a substantial challenge to natural gas pipeline development. Investments and proposals to pay for new natural gas transmission pipeline capacity and services often face significant challenges in determining feasible rights of way and developing community support for the projects. Data Challenges Because there is so much emphasis on using the existing pipeline system to meet the country's energy needs, it is increasingly important for that system to be safe and efficient. In order to keep the public safe and to assure the nation's energy security, operators and regulators must have an intimate understanding of the threats to and operations of the entire pipeline system. Data gathering and integration are important elements of good IM practices, and while many strides have been made over the years to collect more and better data, several data gaps still exist. Ironically, the comparatively positive safety record of the nation's pipeline system to date makes it harder to quantify some of these gaps. Over the 20-year period of 1995-2014, transmission facilities accounted for 42 fatalities and 174 injuries, or about one-seventh of the tota","truncated":true,"body_characters":931265}