Pipeline Safety: Safety of Gas Transmission and Gathering Pipelines

Federal RegisterApr 8, 2016

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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

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 § 192.624 and for verification of pipeline material in accordance with new section § 192.607 for certain onshore, steel, gas transmission pipelines. This includes establishing and documenting MAOP if the pipeline MAOP was established in accordance with § 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.

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

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.

Range reflects uncertainty in defect failure rates for Topic Area 1.

Summary of Average Annual Present Value Benefits and Costs

[Millions; 2015$]

Topic area

7% discount rate

Benefits

Costs

3% discount rate

Benefits

Costs

Re-establish MAOP, verify material properties, and integrity assessments outside HCAs

$196.9-$230.5

$17.8

$247.8-$288.6

$22.0

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.

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.

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.

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.

U.S. Department of Energy, “Appendix B: Natural Gas,”

Quadrennial Energy Review Report: Energy Transmission, Storage, and Distribution Infrastructure,

p. NG-28, April 2015.

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

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

gas gathering, transmission, and distribution systems under minimum Federal safety standards authorized by statute

and codified in the Pipeline Safety Regulations at 49 CFR parts 190-199.

Typically, onshore pipelines involved in the “transportation of gas”—see 49 CFR 192.1 and 192.3 for detailed applicability.

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.

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.

[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.

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.

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

production has increased more than tenfold from 2.7 Bcf/d to about 35.0 Bcf/d in 2014

and now accounts for about half of overall gas production in the U.S.

Id.,

at NG-7.

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,

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.

Id.,

at NG-6.

Id.

Demand Changes

The recent increase in domestic natural gas production has led to decreased gas price volatility and lower average prices.

In 2004, the outlook for natural gas production and demand growth was weak. Monthly average spot prices at Henry Hub

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.

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.

Id.,

at NG-11.

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).

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.

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.

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.

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.

Id.,

at NG-9.

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.

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.

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.

Id.,

at NG-10.

https://www.ferc.gov/market-oversight/mkt-gas/overview/ngas-ovr-lng-wld-pr-est.pdf

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.

Despite this increase in capacity, gas transmission mileage decreased from 299,358 miles in 2010 to 298,287 miles in 2013.

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

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 total fatalities and injuries on the nation's natural gas pipeline system.

Over the 4-year period of 2011-2014, there was only 1 transmission-related fatality. Fortunately, there have been only limited “worst-case scenarios” to evaluate for cost/benefit analysis of measures to improve safety, so there are limited bases for projecting the possible impacts of low-probability, high-consequence events.

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 the Pacific Gas and Electric Company ruptured in a residential area of San Bruno, California. The rupture produced a crater about 72 feet long by 26 feet wide. The section of pipe that ruptured, which was about 28 feet long and weighed about 3,000 pounds, was found 100 feet south of the crater. 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 San Bruno incident exposed several problems in the way data on pipeline conditions is collected and managed, showing that many operators have inadequate records regarding the physical and operational characteristics of their pipelines. Many of these records are necessary for the correct setting and validation of MAOP, which is critically important for providing an appropriate margin of safety to the public.

Much of operator and PHMSA's data is obtained through testing and inspection under IM requirements. However, this testing can be expensive, and the approaches to obtaining data that are most efficient over the long term may require significant upfront costs to modernize pipes and make them suitable for automated inspection. As a result, there continue to be data gaps that make it hard to fully understand the risks to and the integrity of the nation's pipeline system.

To assess a pipeline's integrity, operators generally choose between three methods of testing a pipeline: Inline inspection (ILI), pressure testing, and direct assessment (DA). There is a marked difference in the distribution of assessment methods between interstate and intrastate pipelines. In 2013, we estimate that about two-thirds of interstate pipeline mileage was suitable for in-line inspection, compared to only about half of intrastate pipeline mileage. Because a larger percentage of intrastate pipelines are unable to accommodate ILI tools, intrastate operators use more pressure testing and DA than interstate operators.

ILIs are performed by using special tools, sometimes referred to as “smart pigs,” which are usually pushed through a pipeline by the pressure of the product being transported. As the tool travels through the pipeline, it identifies and records potential pipe defects or anomalies. Because these tests can be performed with product in the pipeline, the pipeline does not have to be taken out of service for testing to occur, which can prevent excessive cost to the operator and possible service disruptions to consumers. Further, ILI is a non-destructive testing technique, and it can be less costly on a per-unit basis to perform than other assessment methods.

Pressure tests are typically used by pipeline operators as a means to determine the integrity (or strength) of the pipeline immediately after construction and before placing the pipeline in service, as well as periodically during a pipeline's operating life. In a pressure test, a test medium inside the pipeline is pressurized to a level greater than the normal operating pressure of the pipeline. This test pressure is held for a number of hours to ensure there are no leaks in the pipeline.

Direct assessment (DA) is the evaluation of various locations on a pipeline for corrosion threats. Operators will review records, indirectly inspect the pipeline, or use mathematical models and environmental surveys to find likely locations on a pipeline where corrosion might be occurring. Areas that are likely to have suffered from corrosion are subsequently excavated and examined. DA can be prohibitively expensive to use unless targeting specific locations, which may not give an accurate representation of the condition of lengths of entire pipeline segments.

Ongoing research and industry response to the ANPRM

appear to indicate that ILI and spike hydrostatic pressure testing is more effective than DA for identifying pipe conditions that are related to stress corrosion cracking defects. Both regulators and operators have expressed interest in improving ILI methods as an alternative to hydrostatic testing for better risk evaluation and management of pipeline safety. Hydrostatic pressure testing can result in substantial costs, occasional disruptions in service, and substantial methane emissions due to the routine evacuation of natural gas from pipelines prior to tests. Further, many operators prefer not to use hydrostatic pressure tests because it can potentially be a

destructive method of testing.

ILI testing can obtain data along a pipeline not otherwise obtainable via other assessment methods, although this method also has certain limitations.

“Pipeline Safety: Safety of Gas Transmission Pipelines—Advanced Notice of Proposed Rulemaking,” 76 FR 5308; August 25, 2011.

National Transportation Safety Board, “Pacific Gas and Electric Company; Natural Gas Transmission Pipeline Rupture and Fire; San Bruno, California; September 9, 2010,”

Pipeline Accident Report NTSB/PAR-11-01,

Page 96, 2011.

In this proposed rulemaking, PHMSA would expand the range of permissible assessment methods while imposing new requirements to guide operators' selection of appropriate methods. Allowing alternatives to hydrostatic testing (including ILI technologies), combined with further research and development to make ILI testing more accurate, could help to drive innovation in pipeline integrity testing technologies. This could eventually lead to improved safety and system reliability through better data collection and assessment.

Increased and Changing Use, Coupled With Age, Exposure to Weather, and Other Factors Can Increase the Risk of Pipeline Incidents

While the existing pipeline network's capacity is expected to bear the brunt of the increasing demand for natural gas in this country, due in part due to the location of new gas resources, new production patterns are causing unique concerns for some pipeline operators. The significant growth of production outside the Gulf Coast region—especially in Pennsylvania and Ohio—is causing a reorientation of the nation's transmission pipeline network. The most significant of these changes will require reversing flows on pipelines to move Marcellus and Utica gas to the southeastern Atlantic region and the Midwest.

Reversing a pipeline's flow can cause added stresses on the system due to changes in pressure gradients, flow rates, and product velocity, which can create new risks of internal corrosion. Occasional failures on natural gas transmission pipelines have occurred after operational changes that include flow reversals and product changes. PHMSA has noticed a large number of recent or proposed flow reversals and product changes on a number of gas transmission lines. In response to this phenomenon, PHMSA issued an Advisory Bulletin notifying operators of the potentially significant impacts such changes may have on the integrity of a pipeline.

“Pipeline Safety: Guidance for Pipeline Flow Reversals, Product Changes, and Conversion to Service,”

ADB PHMSA-2014-0040,

79 FR 56121; September 18, 2014.

Further, the rise of shale gas production is altering not just the extent, but also the characteristics of the nation's gas gathering systems. Gas fields are being developed in new geographic areas, thus requiring entirely new gathering systems and expanded networks of gathering lines. Producers are employing gathering lines with diameters as large as 36 inches and maximum operating pressures up to 1480 psig, far exceeding historical design and operating pressure of typical gathering lines and making them similar to large transmission lines. Most of these new gas gathering lines are unregulated, and PHMSA does not collect incident data or report annual data on these unregulated lines.

However, PHMSA is aware of incidents that show gathering lines are subject to the same sorts of failures common to other pipelines that the agency does regulate. For example, on November 14, 2008, three homes were destroyed and one person was injured when a gas gathering line ruptured in Grady County, OK. On June 8, 2010, two workers died when a bulldozer struck a gas gathering line in Darrouzett, TX, and on June 29, 2010, three men working on a gas gathering line in Grady County, OK, were injured when it ruptured. The dramatic expansion in natural gas production and changes in typical gathering line characteristics require PHMSA to review its regulatory approach to gas gathering pipelines to address new safety and environmental risks.

In addition to demands placed on the nation's pipeline system due to increased and changing use, there are many other factors—including recurring issues that IM was initially developed to address—that affect the integrity of the nation's pipelines.

Data indicate that some pipelines continue to be vulnerable to issues stemming from outdated construction methods or materials. Much of the older line pipe in the nation's gas transmission infrastructure was made before the 1970s using techniques that have proven to contain latent defects due to the manufacturing process. For example, line pipe manufactured using low frequency electric resistance welding is susceptible to seam failure. Because these manufacturing techniques were used during the time before the Federal gas regulations were issued, many of those pipes are subsequently exempt from certain regulations, most notably the requirement to pressure test the pipeline or otherwise verify its integrity to establish MAOP. A substantial amount of this type of pipe is still in service. The IM regulations include specific requirements for evaluating such pipe if located in HCAs, but infrequent-yet-severe failures that are attributed to longitudinal seam defects continue to occur. The NTSB's investigation of the San Bruno incident determined that the pipe failed due to a similar defect. Additionally, between 2010 and 2014, fifteen other reportable incidents were attributed to seam failures, resulting in over $8 million of property damage.

The nation's pipeline system also faces a greater risk from failure due to extreme weather events such as hurricanes, floods, mudslides, tornadoes, and earthquakes. A 2011 crude oil spill into the Yellowstone River near Laurel, MT, was caused by channel migration and river bottom scour, leaving a large span of the pipeline exposed to prolonged current forces and debris washing downstream in the river. Those external forces damaged the exposed pipeline. In October 1994, flooding along the San Jacinto River led to the failure of eight hazardous liquid pipelines and also undermined a number of other pipelines. The escaping products were ignited, leading to smoke inhalation and burn injuries of 547 people. From 2003 to 2013, there were 85 reportable incidents in which storms or other severe natural force conditions damaged pipelines and resulted in their failure. Operators reported total damages of over $104M from these incidents. PHMSA has issued several Advisory Bulletins to operators warning about extreme weather events and the consequences of flooding events, including river scour and river channel migration.

Considering recent incidents and many of the factors outlined above, PHMSA believes IM has led to several improvements in managing pipeline safety, yet the agency believes there is still more to do to improve the safety of natural gas transmission pipelines and ensure public confidence.

Challenges to Modernization and Historical Problems Underscore the Need for a Clear Strategy To Protect the Safety and Integrity of the Nation's Pipeline System

The current IM program is both a set of regulations and an overall regulatory approach to improve pipeline operators' ability to identify and mitigate the risks to their pipeline systems. The objectives of IM are to accelerate and improve the quality of integrity assessments, promote more rigorous and systematic management of integrity, strengthen oversight, and increase public confidence. On the operator level, an IM program consists of multiple

components, including adopting procedures and processes to identify HCAs, determining likely threats to the pipeline within the HCA, evaluating the physical integrity of the pipe within the HCA, and repairing or remediating any pipeline defects found. Because these procedures and processes are complex and interconnected, effective implementation of an IM program relies on continual evaluation and data integration.

The initial definition for HCAs was finalized on August 6, 2002,

providing concentrations of populations with corridors of protection spanning 300, 660, or 1,000 feet, depending on the diameter and MAOP of the particular pipeline.

In a later NPRM,

PHMSA proposed changes to the definition of a HCA by introducing the concept of a covered segment, which PHMSA defined as the length of gas transmission pipeline that could potentially impact an HCA.

Previously, only distances from the pipeline centerline related to HCA definitions. PHMSA also proposed using Potential Impact Circles, Potential Impact Zones, and Potential Impact Radii (PIR) to identify covered segments instead of a fixed corridor width. The final Gas Transmission Pipeline Integrity Management Rule, incorporating the new HCA definition, was issued on December 15, 2003.

“Pipeline Safety: High Consequence Areas for Gas Transmission Pipelines,”

Final rule,

67 FR 50824; August 6, 2002.

The influence of the existing class location concept on the early definition of HCAs is evident from the use of class locations themselves in the definition, and the use of fixed 660 ft. distances, which corresponds to the corridor width used in the class location definition. This concept was later significantly revised, as discussed later, in favor of a variable corridor width (referred to as the Potential Impact Radius) based on case-specific pipe size and operating pressure.

“Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines),”

Notice of Proposed Rulemaking,

68 FR 4278; January 28, 2003.

HCA and PIR definitions are in 49 CFR 192.903.

“Pipeline Safety: Pipeline Integrity Management in High Consequence Areas (Gas Transmission Pipelines),”

Final rule,

68 FR 69778; December 15, 2003.

The incident at San Bruno in 2010 motivated a comprehensive reexamination of gas transmission pipeline safety. Congress responded to concerns in light of the San Bruno incident by passing the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, which directed the DOT to reexamine many of its safety requirements, including the expansion of IM regulations for transmission pipelines.

Further, both the NTSB and the GAO issued several recommendations to PHMSA to improve its IM program and pipeline safety. The NTSB noted, in a 2015 study,

that IM requirements have reduced the rate of failures due to deterioration of pipe welds, corrosion, and material failures. However, pipeline incidents in high-consequence areas due to other factors increased between 2010 and 2013, and the overall occurrence of gas transmission pipeline incidents in high-consequence areas has remained stable. The NTSB also found many types of basic data necessary to support comprehensive probabilistic modeling of pipeline risks are not currently available.

National Transportation Safety Board, “Safety Study: Integrity Management of Gas Transmission Pipelines in High Consequence Areas,”

NTSB SS-15/01,

January 27, 2015.

Many of these mandates and recommendations caused PHMSA to evaluate whether IM system requirements, or elements thereof, should be expanded beyond HCAs to afford protection to a larger percentage of the nation's population. Additionally, several of these mandates and recommendations asked PHMSA to enhance the existing IM regulations by addressing MAOP verification, inadequate operator records, legacy pipe issues, and inadequate integrity assessments. Further, PHMSA was charged with reducing data gaps and improving data integration, considering the regulatory framework for gas gathering systems, and deleting the “grandfather clause” to require all gas transmission pipelines constructed before 1970 be subjected to a hydrostatic spike pressure test. This proposed rule addresses several of the recommendations from the 2015 study including P-15-18 (IM-ILI capability), P-15-20 (IM-ILI tools), P-15-21 (IM-Direct Assessments), and P-21 (IM-Data Integration).

PHMSA Is Delivering a Comprehensive Strategy To Protect the Nation's Pipeline System While Accounting for a Changing Landscape and a Changing Population

To address these statutory mandates, the post-San Bruno NTSB and GAO recommendations, and other pipeline safety mandates, PHMSA posed a series of questions to the public in the context of an August 2011 ANPRM titled “Pipeline Safety: Safety of Gas Transmission Pipelines” (PHMSA-2011-0023). In that document, PHMSA asked whether the regulations governing the safety of gas transmission pipelines needed changing. In particular, PHMSA asked whether IM requirements should be changed, including through adding more prescriptive language in some areas, and whether other issues related to system integrity should be addressed by strengthening or expanding non-IM requirements. Among the specific issues PHMSA considered concerning IM requirements were whether the definition of an HCA should be revised, and whether additional restrictions should be placed on the use of specific pipeline assessment methods. In the ANPRM, PHMSA also considered changes to non-IM requirements, including valve spacing and installation, corrosion control, and whether regulations for gathering lines needed to be modified.

PHMSA received 103 comments in response to the ANPRM, which are summarized in more detail later in this document. Feedback from the ANPRM helped to identify a series of common-sense improvements to IM, including improvements to assessment goals such as integrity verification, MAOP verification, and material documentation; clarified repair criteria; clarified protocol for identifying threats, risk assessments and management, and prevention and mitigation measures; expanded and enhanced corrosion control; requirements for inspecting pipelines after incidents of extreme weather; and new guidance on how to calculate MAOP in order to set operating parameters more accurately and predict the risks of an incident.

Many of these aspects of IM have been an integral part of PHMSA's expectations since the inception of the IM program. As specified in the first IM rule, PHMSA expects operators to start with an IM framework, evolve a more detailed and comprehensive IM program, and continually improve their IM programs as they learn more about the IM process and the material condition of their pipelines through integrity assessments. This NPRM's proposals regarding operators' processes for implementing IM reflect PHMSA's expectations regarding the degree of progress operators should be making, or should have made, during the first 10 years of IM program implementation.

To address issues involving the increased risk posed by larger-diameter, higher-pressure gathering lines, PHMSA is proposing to issue requirements for certain currently unregulated gas gathering pipelines that are intended to prevent the most frequent causes of failure—corrosion and excavation damage—and to improve emergency response preparedness. Minimum Federal safety standards would also bring an appropriate level of consistency to the current mix of regulations that differ from state to state.

PHMSA believes these proposed changes will improve the safety and protection of pipeline workers, the public, property, and the environment by improving the detection and remediation of unsafe conditions, ensuring that certain currently unregulated pipelines are subject to appropriate regulatory oversight, and speeding mitigation of adverse effects of pipeline failures. In addition to safety benefits, the rule is expected to improve the performance and extend the economic life of critical pipeline infrastructure that transports domestically produced natural gas energy, thus supporting national economic and security energy objectives.

Looking at Risk Beyond HCAs

In addition to the common sense improvements to IM, responses to the ANPRM reinforced the importance of carefully reconsidering the scope of areas covered by IM. While PHMSA's IM program manages risks primarily by focusing oversight on areas with the greatest population density, responses to the ANPRM highlight the imperative of protecting the safety of communities throughout the country in light of a changing landscape of production, consumption, and product movement that merits a refreshed look at the current scope of IM coverage.

In the 2011 Act, Congress required PHMSA to have pipeline operators conduct a records verification to ensure that their records accurately reflect the physical and operational characteristics of pipelines in certain HCAs and class locations, and to confirm the established MAOP of the pipelines. The results of that action indicate that problems similar to the contributing factors of the San Bruno incident are more widespread than previously believed, affecting both HCA and non-HCA segments. This indicates that a rupture on the scale of San Bruno, with the potential to affect populations, the environment, or commerce, could occur elsewhere on the nation's pipeline system.

In fact, devastating incidents have occurred outside of HCAs in rural areas where populations are sparse but present. On August 19, 2000, a 30-inch-diameter gas transmission pipeline ruptured adjacent to the Pecos River near Carlsbad, NM. The released gas ignited and burned for 55 minutes. Twelve persons who were camping under a concrete-decked steel bridge that supported the pipeline across the river were killed, and their vehicles were destroyed. Two nearby steel suspension bridges for gas pipelines crossing the river were damaged extensively.

On December 14, 2007, two men were driving in a pickup truck on Interstate 20 near Delhi, LA, when a 30-inch gas transmission pipeline ruptured. One of the men was killed, and the other was injured.

On December 11, 2012, a 20-inch-diameter gas transmission line ruptured in a sparsely populated area about 106 feet west of Interstate 77 (I-77) in Sissonville, WV. An area of fire damage about 820 feet wide extended nearly 1,100 feet along the pipeline right-of-way. Three houses were destroyed by the fire, and several other houses were damaged. Reported losses, repairs, and upgrades from this incident totaled over $8.5 million, and major transportation delays occurred. I-77 was closed in both directions because of the fire and resulting damage to the road surface. The northbound lanes were closed for about 14 hours, and the southbound lanes were closed for about 19 hours while the road was resurfaced, causing delays to both travelers and commercial shipping.

Because the nation's population is growing, moving, and dispersing, population density is a changing measure, and we need to be prepared for further shifts in the coming decades. The current definition of an HCA uses building density as a proxy for approximating the presence of communities and surrounding infrastructure. This can be a meaningful metric for prioritizing implementation of safety and risk management protocols for areas where an accident would have the greatest likelihood of putting human life in danger, but it is not necessarily an accurate reflection of whether an incident will have a significant impact on people. Requiring assessment and repair criteria for pipelines that, if ruptured, could pose a threat to areas where any people live, work, or congregate would improve public safety and would improve public confidence in the nation's natural gas pipeline system.

Feedback from industry indicated that some pipeline operators are already moving towards expanding the protections of IM beyond HCAs. In 2012, the Interstate Natural Gas Association of America (INGAA) issued a “Commitment to Pipeline Safety,”

underscoring its efforts towards a goal of zero incidents, a committed safety culture, a pursuit of constant improvement, and applying IM principles on a system-wide basis. INGAA divides the commitment into four stages:

Letter from Terry D. Boss, Senior Vice President of Environment, Safety and Operations to Mike Israni, Pipeline and Hazardous Materials Safety Administration, U.S. Department of Transportation, dated January 20, 2012, “

Safety of Gas Transmission Pipelines,

Docket No. PHMSA-2011-0023.” INGAA represents companies that operate approximately 65 percent of the gas transmission pipelines, but INGAA does not represent all pipeline operators subject to 49 CFR part 192.

• Stage 1—INGAA members will complete an initial assessment using some degree of IM on their pipelines, covering 90% of the population living, working, or congregating along INGAA member pipelines, by the end of 2012. This represents roughly 64% of INGAA member pipeline mileage, including the 4% of pipelines that are in HCAs.

• Stage 2—By 2020, INGAA members will consistently and comprehensively apply IM principles to those pipelines.

• Stage 3—By 2030, INGAA members will apply IM principles to pipelines, extending IM protection to 100% of the population living along INGAA member pipelines. This stage would cover roughly 16% of pipeline mileage, bringing the total coverage by 2030 to approximately 80% of INGAA's pipeline mileage.

• Stage 4—Beyond 2030, INGAA members will apply IM principles to the remaining 20% of pipeline mileage where no population resides.

To accomplish this commitment, INGAA's members are performing actions that include applying risk management beyond HCAs; raising the standards for corrosion management; demonstrating “fitness for service” on pre-regulation pipelines; and evaluating, refining, and improving operators' ability to assess and mitigate safety threats. Ultimately, these actions aim to extend protection to people who live near pipelines but not within defined HCAs.

INGAA's commitment and other stakeholder feedback on this issue have triggered an important exchange about measuring the risks that exist in less-densely populated areas and the impacts of expanding greater protections to those areas. If constant improvement and zero incidents are goals for pipeline operators, INGAA's plan to extend and prioritize IM assessments and principles to all parts of their pipeline networks that are located near any concentrations of population is an effective way to achieve those goals. Such an approach is needed to help clarify vulnerabilities and prioritize improvements, and this proposed rulemaking takes important steps forward towards developing such an approach.

The question then, is how to implement risk management standards that most accurately target the safety of communities, while also providing sufficient ability to prioritize areas of greatest possible risk and/or impact. Addressing that question has been, and remains, an important part of this proposed rule, recognizing that the answer will remain fluid based on factors that continue to change.

Given INGAA's commitment, feedback from the ANPRM, the results of incident investigations, and IM considerations, PHMSA has determined it is appropriate to improve aspects of the current IM program and codify requirements for additional gas transmission pipelines to receive integrity assessments on a periodic basis to monitor for, detect, and remediate pipeline defects and anomalies. In addition, in order to achieve the desired outcome of performing assessments in areas where people live, work, or congregate, while minimizing the cost of identifying such locations, PHMSA proposes to base the requirements for identifying those locations on processes already being implemented by pipeline operators and that protect people on a risk-prioritized basis.

Establishing integrity assessment requirements and associated repair conditions for non-HCA pipe segments is important for providing safety to the public. Although those segments are not within defined HCAs, they will usually be located in populated areas, and pipeline accidents in these areas may cause fatalities, significant property damage, or disrupt livelihoods. This rulemaking proposes a newly defined moderate consequence area (MCA) to identify additional non-HCA pipeline segments that would require integrity assessments, thus assuring timely discovery and repair of pipeline defects in MCA segments. These changes would ensure prompt remediation of anomalous conditions that could potentially impact people, property, or the environment, and commensurate with the severity of the defects, while at the same time allowing operators to allocate their resources to HCAs on a higher-priority basis. INGAA's commitment and PHMSA's MCA definition are comparable, which shows a common understanding of the importance of this issue and a path towards a solution.

B. Advance Notice of Proposed Rulemaking

On August 25, 2011, PHMSA published an Advance Notice of Proposed Rulemaking (ANPRM) to seek public comments regarding the revision of the Pipeline Safety Regulations applicable to the safety of gas transmission 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. The ANPRM may be viewed at

http://www.regulations.gov

by searching for Docket ID PHMSA-2011-0023. As mentioned above, pursuant to the related issues raised by the NTSB recommendations and statutory requirements of the Act, PHMSA is issuing separate rulemaking for several of the topics in the ANPRM. These topics are so designated in the following list. Specifically, the ANPRM sought comments on the following topics:

A. Modifying the Definition of HCA (to be addressed in separate rulemaking),

B. Strengthening Requirements to Implement Preventive and Mitigative Measures for Pipeline Segments in HCAs (partially addressed in separate rulemaking—aspects related to Remote Control Valves and Leak Detection will be addressed in separate rulemaking, other aspects are being addressed in this NPRM),

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 (to be addressed in separate rulemaking),

I. Corrosion Control,

J. Pipe Manufactured Using Longitudinal Weld Seams,

K. Establishing Requirements Applicable to Underground Gas Storage (to be considered for separate rulemaking),

L. Management of Change,

M. Quality Management Systems (QMS) (to be considered for separate rulemaking),

N. Exemption of Facilities Installed Prior to the Regulations,

O. Modifying the Regulation of Gas Gathering Lines.

A summary of comments and responses to those comments are provided later in the document.

C. National Transportation Safety Board Recommendations

On August 30, 2011, following the issuance of the ANPRM, the NTSB adopted its report on the gas pipeline accident that occurred on September 9, 2010, in San Bruno, California. On September 26, 2011, the NTSB issued safety recommendations P-11-8 through -20 to PHMSA, and issued safety recommendations P-10-2 through -4 to Pacific Gas & Electric (PG&E), among others. The NTSB made these recommendations following its investigation of the tragic September 9, 2010 natural gas pipeline rupture in the city of San Bruno, California. Several of the NTSB recommendations related directly to the topics addressed in the August 25, 2011 ANPRM and impacted the proposed approach to rulemaking. The potentially impacted topics and the related NTSB recommendations include, but are not limited to:

• Topic B—Strengthening Requirements to Implement Preventive and Mitigative Measures for Pipeline Segments in HCAs. NTSB Recommendation P-11-10: “

Require that all operators of natural gas transmission and distribution pipelines equip their supervisory control and data acquisition systems with tools to assist in recognizing and pinpointing the location of leaks, including line breaks; such tools could include a real-time leak detection system and appropriately spaced flow and pressure transmitters along covered transmission lines.

”

• Topic D—Improving Requirements for Collecting, Validating, and Integrating Pipeline Data. NTSB Recommendation P-11-19: “

(1) Develop and implement standards for integrity management and other performance-based safety programs that require operators of all types of pipeline systems to regularly assess the effectiveness of their programs using clear and meaningful metrics, and to identify and then correct deficiencies; and (2) make those metrics available in a centralized database.

”

• Topic G—Strengthening Requirements on the Selection and Use of Assessment Methods. NTSB Recommendation P-11-17: “

Require that all natural gas transmission pipelines be configured so as to accommodate in-line inspection tools, with priority given to older pipelines.

”

• Topic H—Valve Spacing and the Need for Remotely or Automatically Controlled Valves. NTSB Recommendation P-11-11: “

Amend Title 49 Code of Federal Regulations Section 192.935(c) to directly require that automatic shutoff valves or remote

control valves in high consequence areas and in class 3 and 4 locations be installed and spaced at intervals that consider the population factors listed in the regulations.

”

• Topic J—Pipe Manufactured Using Longitudinal Weld Seams. NTSB Recommendation P-11-15: “

Amend Title 49 Code of Federal Regulations Part 192 of the Federal pipeline safety regulations so that manufacturing- and construction-related defects can only be considered stable if a gas pipeline has been subjected to a post-construction hydrostatic pressure test of at least 1.25 times the maximum allowable operating pressure.

”

• Topic N—Exemption of Facilities Installed Prior to the Regulations. NTSB Recommendation P-11-14:

Amend title 49 Code of Federal Regulations 192.619 to repeal exemptions from pressure test requirements and require that all gas transmission pipelines constructed before 1970 be subjected to a hydrostatic pressure test that incorporates a spike test.

”

D. Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011

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 relate directly to the topics addressed in the August 25, 2011 ANPRM. The related topics and statutory citations include, but are not limited to:

○ Section 5(e)—Allow periodic reassessments to be extended for an additional 6 months if the operator submits sufficient justification.

○ Section 5(f)—Requires regulations issued by the Secretary, if any, to expand integrity management system requirements, or elements thereof, beyond high-consequence areas.

○ Section 21—Regulation of Gas (and Hazardous Liquid) Gathering Lines

○ Section 23—Testing regulations to confirm the material strength of previously untested natural gas transmission pipelines.

○ Section 29—Consider seismicity when evaluating pipeline threats.

E. Summary of Each Topic Under Consideration

This NPRM proposes new requirements and revisions to existing requirements to address topics discussed in the ANPRM, including some topics from the Act and the NTSB recommendations. Each topic area discussed in the ANPRM, as well as additional topics that have arisen since issuance of the ANPRM, is summarized below. Details of the changes proposed in this rule are discussed below in section V. Section-by-Section Analysis.

• Topic A—Modifying the Definition of HCA. The ANPRM requested comments regarding expanding the definition of an HCA so that more miles of pipe would be subject to IM requirements and so that all Class 3 and 4 locations would be subject to the IM requirements. The Act, Section 5, requires that the Secretary of Transportation complete an evaluation and issue a report on whether integrity management requirements should be expanded beyond HCAs and whether such expansion would mitigate the need for class location requirements. PHMSA has prepared the class location report and a copy is available in the docket (

www.regulations.gov

) for this proposed rulemaking. PHMSA invites commenters to review the class location report when formulating their comments.

Although PHMSA is not proposing to expand the definition of an HCA, PHMSA is proposing to expand certain IM requirements beyond HCAs by creating a new “moderate consequence areas (MCA).” MCAs would be used to define the subset of non-HCA pipeline locations where periodic integrity assessments are required (§ 192.710), where material documentation verification is required (§ 192.607), and where MAOP verification is required (§§ 192.619(e) and 192.624). The proposed criteria for determining MCA locations would use the same process and the same definitions as currently used to identify HCAs, except that the threshold for buildings intended for human occupancy and the threshold for persons that occupy other defined sites, that are located within the potential impact radius, would both be lowered from 20 to 5. The intention is that any pipeline location at which persons are normally expected to be located would be afforded extra safety protections described above. In addition, as a result of the Sissonville, West Virginia incident, NTSB issued recommendation P-14-01, to revise the gas regulations to add principal arterial roadways including interstates, other freeways and expressways, and other principal arterial roadways as defined in the Federal Highway Administration's

Highway Functional Classification Concepts, Criteria and Procedures

to the list of “identified sites” that establish a high consequence area. PHMSA proposes to meet the intent of NTSB's recommendation by incorporating designated interstates, freeways, expressways, and other principal 4-lane arterial roadways (as opposed to NTSB's all “other principal arterial roadways”) within the new definition of MCAs. PHMSA believes this approach would be cost-beneficial. The Sissonville, WV, incident location would not meet the current definition of an HCA, but would, however, meet the proposed definition of an MCA. PHMSA considered expanding the scope of HCAs instead of creating Moderate Consequence Areas. Such an approach was contemplated in the 2011 ANPRM and PHMSA received a number of comments on this approach. PHMSA concluded that this approach would be counter to a graded approach based on risk (

i.e.,

risk based gradation of requirements to apply progressively more protection for progressively greater consequence locations). By simply expanding HCAs, PHMSA would be simply lowering the threshold for what is considered “high consequence.” Expanding HCAs would require that all integrity management program elements (specified in subpart O) be applied to pipe located in a newly designated HCA. The proposed rule would only apply three IM program elements (assessment, periodic reassessment, and remediation of discovered defects) to the category of pipe that has lesser consequences than HCAs (

i.e.,

MCAs), but not to segments without any structure or site within the PIR (arguably “low consequence areas”). There would be additional significant costs to apply all other integrity management program elements (most notably the risk analysis and preventive/mitigative measures program elements) to additional segments currently not designated as HCA. Also, if HCAs were expanded, long term reassessment costs would approximately triple (compared to the proposed MCA requirements) based on an almost 3:1 ratio of reassessment interval. For the above reasons, PHMSA is not proposing to expand HCAs. Instead, PHMSA is proposing to create and apply selected integrity management requirements to a category of lesser consequence areas defined as MCAs. With regard to the criteria for defining HCAs, PHMSA also considered several alternatives, including more relaxed population density and excluding small pipe diameters.

In addition, a major constituency of the pipeline industry (INGAA) has committed to apply IM principles to all segments where any persons are located. This is comparable to PHMSA's proposed MCA definition. PHMSA seeks comment on the relative merits of expanding High Consequence Areas

versus creating a new category of “Moderate Consequence Areas.”

Another alternative PHMSA considered was a shorter a compliance deadline (10 years) and a shorter reassessment interval (15 years) for MCA assessments. The assessment timeframes in the proposed rule were selected based on a graded approach which would apply relaxed timeframes to MCAs, as compared to HCAs. The industry was originally required to perform baseline assessments for approximately 20,000 miles of HCA pipe within approximately 8 years from the effective date of the integrity management rule. PHMSA estimates that approximately 41,000 miles of pipe would require an assessment within 15 years under this proposed rule, thus constituting a comparable level of effort on the part of industry. The maximum HCA reassessment interval is 20 years for low stress pipe. The 20 year interval was selected to align with the longest interval allowed for any HCA pipe, which is 20 years for pipe operating less than 30% SMYS. A reassessment interval of 15 years for MCAs would be shorter than the reassessment interval for some HCAs. PHMSA also considered that compliance with the proposed rule would be performed in parallel with ongoing HCA reassessments at the same time, thus resulting in greater demand for ILI tools and industry resources than during the original IM baseline assessment period. In addition, the proposed rule incorporates other assessment goals, including integrity verification, maximum allowable operating pressure (MAOP) verification, and material documentation, thus constituting a larger/more costly assessment effort than originally required under IM rules. For the above reasons, PHMSA believes that this proposed rule would require full utilization or expansion of industry resources devoted to assessments. Therefore, PHMSA believes that compressing the timeframes would place unreasonably high demands on the industry's assessment capabilities. PHMSA also considered the possibility that placing burdensome demands on the industry's assessment capability might drive assessment costs higher. PHMSA seeks comments on the potential safety benefits, avoided lost gas, economic costs, and operational considerations involved in longer or shorter compliance periods for initial MCA assessment periods and re-assessment intervals.

More generally, PHMSA seeks comment on the approach and scope of the proposed rule with respect to applying integrity management program elements to additional pipe segments not currently designated as HCA, including,

inter alia,

alternative definitions of “Moderate Consequence Area” and limits on the categories of pipeline to be regulated within this new area.

• Topic B—Strengthening Requirements to Implement Preventive and Mitigative Measures for Pipeline Segments in HCAs. The ANPRM requested comments regarding whether the requirements of Section 49 CFR 192.935 for pipelines in HCAs should be more prescriptive and whether these requirements, or other requirements for additional preventive and mitigative measures, should apply to pipelines outside of HCAs. Section 5 of the Act requires the Secretary of Transportation to evaluate and report to Congress on expanding IM requirements to non-HCA pipelines. PHMSA will further evaluate applying P&M measures to non-HCA areas after this evaluation is complete.

This NPRM proposes rulemaking for amending the integrity management rule to add requirements for selected preventive and mitigative measures (internal and external corrosion control).

Two special topics associated with preventive and mitigative measures, leak detection and automatic valve upgrades, were addressed by the NTSB and Congress. The NTSB recommended that all operators of natural gas transmission and distribution pipelines equip their supervisory control and data acquisition systems with tools to assist in recognizing and pinpointing the location of leaks, including line breaks; such tools could include a real-time leak detection system and appropriately spaced flow and pressure transmitters along covered transmission lines (recommendation P-11-10). In addition, Section 8 of the Act requires issuance of a report on leak detection systems used by operators of hazardous liquid pipelines which was completed and submitted to Congress in December 2012. Although that study is specific to hazardous liquid pipelines, its analysis and conclusions could influence PHMSA's approach to leak detection for gas pipelines. In response to the NTSB recommendations, PHMSA conducted as part of a larger study on pipeline leak detection technology a public workshop in 2012. This study, among other things, examined how enhancements to SCADA systems can improve recognition of pipeline leak locations. Additionally, in 2012 PHMSA held a pipeline research forum to identify technological gaps, potentially including the advancement of leak detection methodologies. PHMSA is developing a rulemaking with respect to leak detection in consideration of these studies and ongoing research. In addition, PHMSA is focusing this rulemaking on regulations oriented toward preventing incidents. Leak detection (in the context of mitigating pipe breaks as described in NTSB P-11-10)

and automatic valve upgrades are features that serve to mitigate the consequences of incidents after they occur but do not prevent them. In order to not delay the important requirements proposed in this NPRM, PHMSA will address the topic of incident mitigation later in a separate rulemaking. It is anticipated that advancing rulemaking to address the NTSB recommendations will follow assessment of the results of these actions.

Leak detection in the context of detecting small, latent leaks such as leaks at fittings typical of gas distribution systems, and is outside the scope of the ANPRM, Topic B.

PHMSA completed and submitted the valve study to congress in December 2012. PHMSA is developing a separate rulemaking related to the need for remotely or automatically controlled valves to addresses the NTSB recommendations and statutory requirements related to this topic as discussed under Topic H.

• Topic C—Modifying Repair Criteria. The ANPRM requested comments regarding amending the integrity management regulations by revising the repair criteria for pipelines in HCAs to provide greater assurance that injurious anomalies and defects are repaired before the defect can grow to a size that leads to a leak or rupture. PHMSA is proposing in this rule to revise the repair criteria for pipelines in HCAs. Revisions include repair criteria for cracks and crack-like defects, corrosion metal loss for defects less severe than an immediate condition (already included), and mechanical damage defects.

In addition, the ANPRM requested comments regarding establishing repair criteria for pipeline segments located in areas that are not in HCAs. PHMSA is proposing rulemaking for establishing repair criteria for pipelines that are not in HCAs. Such repair criteria would be similar to the repair criteria for HCAs, with more relaxed deadlines for non-immediate conditions. It is acknowledged that applying repair criteria to pipelines that are not in HCAs is one of the factors to be considered in the integrity management evaluation required in the Act, as discussed in Topic A above.

• Topic D—Improving Requirements for Collecting, Validating, and Integrating Pipeline Data. The ANPRM

requested comments regarding whether more prescriptive requirements for collecting, validating, integrating, and reporting pipeline data are necessary. PHMSA also discussed this topic in a 2012 pipeline safety data workshop.

PHMSA issued Advisory Bulletin 12-06 to remind operators of gas pipeline facilities to verify their records relating to operating specifications for maximum allowable operating pressure (MAOP) required by 49 CFR 192.517. On January 10, 2011, PHMSA also issued Advisory Bulletin 11-01, which reminded operators that if they are relying on the review of design, construction, inspection, testing and other related data to establish MAOP, they must ensure that the records used are reliable, traceable, verifiable, and complete. PHMSA is proposing in this rule to add specificity to the data integration language in the IM rule to establish a number of pipeline attributes that must be included in these analyses, by explicitly requiring that operators integrate analyzed information, and by requiring that data be verified and validated. In addition, PHMSA has determined that additional rules are needed to ensure that records used to establish MAOP are reliable, traceable, verifiable, and complete. The proposed rule would add a new paragraph (e) to section 192.619 to codify this requirement and to require that such records be retained for the life of the pipeline.

• Topic E—Making Requirements Related to the Nature and Application of Risk Models More Detailed. The ANPRM requested comments regarding making requirements related to the nature and application of risk models more specific to improve the usefulness of these analyses in informing decisions to control risks from pipelines. This NPRM contains proposed requirements that address this topic.

• Topic F—Strengthening Requirements for Applying Knowledge Gained Through the IM Program. The ANPRM requested comments regarding strengthening requirements related to operators' use of insights gained from implementation of its IM program. In this NPRM, PHMSA proposes detailed requirements for strengthening integrity management requirements for applying knowledge gained through the IM Program. These requirements include provisions for analyzing interacting threats, potential failures, and worst-case incident scenarios from initial failure to incident termination. Though not proposed, PHMSA seeks comment on whether a time period for updating aerial photography and patrol information should be established.

• Topic G—Strengthening Requirements on the Selection and Use of Assessment Methods for pipelines requiring assessment. The ANPRM requested comments regarding the applicability, selection, and use of assessment methods, including the application of existing consensus standards. NTSB recommendation P-11-17 related to this topic, recommends that all gas pipelines be upgraded to accommodate ILI tools. PHMSA will consider separate rulemaking for upgrading pipelines pending further evaluation of the issue from new data being collected in the annual reports.

This NPRM proposes to strengthen requirements for the selection and use of assessment methods. The proposed rule would provide more detailed guidance for the selection of assessment methods, including the requirements in new § 192.493 when performing an assessment using an in-line inspection tool. This NPRM also proposes to add more specific requirements for use of internal inspection tools to require that an operator using this method must explicitly consider uncertainties in reported results when identifying anomalies. In addition, the proposed rulemaking would add a “spike” hydrostatic pressure test, which is particularly well suited to address SCC and other cracking or crack-like defects, guided wave ultrasonic testing (GWUT), which is particularly appropriate in cases where short segments, such as roads or railroad crossings, are difficult to assess, and excavation and

in situ

direct examination, which is well suited to address crossovers and other short, easily accessible segments that are impractical to assess by remote technology, as allowed assessment methods and would revise the requirements for direct assessment to allow its use only if a line is not capable of inspection by internal inspection tools.

The issue of selection and use of assessment methods is related to the statutory mandate in the Act for the Comptroller General of the United States to evaluate whether risk-based reassessment intervals are a more effective alternative. The Act requires an evaluation of reassessment intervals and the anomalies found in reassessments. While not directly addressing selection of assessment methods, the results of the evaluation will have an influence on the general approach for conducting future integrity assessments. PHMSA will consider the Comptroller General's evaluation when it becomes available. Additional rulemaking may be considered after PHMSA considers the results of the evaluation.

• Topic H—Valve Spacing and the Need for Remotely or Automatically Controlled Valves. The ANPRM requested comments regarding proposed changes to the requirements for sectionalizing block valves. In response to the NTSB recommendations, PHMSA held a public workshop in 2012 on pipeline valve issues, which included the need for additional valve installation on both natural gas and hazardous liquid transmission pipelines. PHMSA also included this topic in the 2012 Pipeline Research Forum. In addition, Section 4 of the Act requires issuance of regulations on the use of automatic or remote-controlled shut-off valves, or equivalent technology, where economically, technically, and operationally feasible on transmission pipeline facilities constructed or entirely replaced after the date of the final rule. The Act also requires completion of a study by the Comptroller General of the United States on the ability of transmission pipeline facility operators to respond to a hazardous liquid or gas release from a pipeline segment located in an HCA. Separate rulemaking on this topic will be considered based on the results of the study.

• Topic I—Corrosion Control. The ANPRM requested comments regarding proposed revisions to subpart I to improve the specificity of existing requirements. This NPRM proposes to revise subpart I, including a general update to the technical requirements in appendix D to part 192 for cathodic protection.

• Topic J—Pipe Manufactured Using Longitudinal Weld Seams. In recommendation P-11-15, the NTSB recommended that PHMSA amend its regulations to require that any longitudinal seam in an HCA be pressure tested in order to consider the seam to be “stable.” This issue is addressed in Topic N. PHMSA proposes to address this issue by revising the integrity management requirements in § 192.917(e)(3) to specify that longitudinal seams may not be treated as stable defects unless the segment has been pressure tested (and therefore would require an integrity assessment for seam threats). Also, PHMSA proposes to add new requirements for verification of maximum allowable operating pressure (MAOP) in new § 192.624.

• Topic K—Establishing Requirements Applicable to Underground Gas Storage. The ANPRM requested comments regarding establishing requirements within part 192 applicable to underground gas storage in order to help assure safety of

underground storage and to provide a firm basis for safety regulation. PHMSA will consider proposing a separate rulemaking that specifically focuses on improving the safety of underground natural gas storage facilities will allow PHMSA to fully consider the impacts of incidents that have occurred since the close of the initial comment period. It will also allow the Agency to consider voluntary consensus standards that were developed after the close of the comment period for this ANPRM, and to solicit feedback from additional stakeholders and members of the public to inform the development of potential regulations.

• Topic L—Management of Change. The ANPRM requested comments regarding adding requirements for management of change to provide a greater degree of control over this element of pipeline risk. This NPRM contains proposed requirements that address this topic. Specifically, PHMSA proposes to revise the general applicability requirements in § 192.13 to require each operator of an onshore gas transmission pipeline to develop and follow a management of change process, as outlined in ASME/ANSI B31.8S, section 11, that addresses technical, design, physical, environmental, procedural, operational, maintenance, and organizational changes to the pipeline or processes, whether permanent or temporary.

• Topic M—Quality Management Systems (QMS). The ANPRM requested comments regarding whether and how to impose requirements related to quality management systems. PHMSA will consider separate rulemaking for this topic.

• Topic N—Exemption of Facilities Installed Prior to the Regulations. The ANPRM requested comments regarding proposed changes to part 192 regulations that would repeal exemptions to pressure test requirements. The NTSB recommended that PHMSA repeal 49 CFR 192.619(c) and require that all gas transmission pipelines be pressure tested to establish MAOP (recommendation P-11-14). In addition, section 23 of the Act requires issuance of regulations requiring tests to confirm the material strength of previously untested natural gas transmission lines. In response to the NTSB recommendation and the Act, this NPRM proposes requirements for verification of maximum allowable operating pressure (MAOP) in accordance with new § 192.624 for certain onshore, steel, gas transmission pipelines, including establishing and documenting MAOP if the pipeline MAOP was established in accordance with § 192.619(c).

The Act also requires verification of records to ensure they accurately reflect the physical and operational characteristics of the pipelines and to confirm the established maximum allowable operating pressure of the pipelines. PHMSA issued Advisory Bulletin 12-06 on May 7, 2012 to notify operators of this required action. PHMSA has initiated an information collection effort to gather data needed to accurately characterize the quantity and location of pre-1970 gas transmission pipeline operating under an MAOP established by 49 CFR 192.619(c). This NPRM proposes requirements in new § 192.607 for certain onshore, steel, gas transmission pipelines to confirm and record the physical and operational characteristics of pipelines for which adequate records are not available.

• Topic O—Modifying the Regulation of Gas Gathering Lines. The ANPRM requested comments regarding modifying the regulations relative to gas gathering lines. The Act required several actions related to this topic, including: review existing regulations for gathering lines; provide a report to Congress; and make recommendations on: (1) The sufficiency of existing regulations, (2) the economic impacts, technical practicability, and challenges of applying existing federal regulations to gathering lines, and (3) subject to a risk-based assessment, the need to modify or revoke existing exemptions from Federal regulation for gas and hazardous liquid gathering lines. PHMSA proposes to address aspects of this topic identified before enactment of the Act in this NPRM. The report submitted to Congress will be evaluated to determine the need for any future rulemaking, specifically the need to apply integrity management concepts to gas gathering lines.

In addition, on August 20, 2014, the Government Accountability Office (GAO) released a report (GAO Report 14-667) to address the increased risk posed by new gathering pipeline construction in shale development areas. The GAO recommended that rulemaking be pursued for gathering pipeline safety that addresses the risks of larger-diameter, higher-pressure gathering pipelines, including subjecting such pipelines to emergency response planning requirements that currently do not apply. PHMSA proposes to address this recommendation as described below in the “Section-by-Section Analysis” under § 192.9.

Additional Topics

• Inspection of Pipelines Following a Severe Weather Event. Existing pipeline regulations prescribe requirements for surveillance periodically patrolling of pipeline to observe surface conditions on and adjacent to the transmission line right-of-way for indications of leaks, construction activity, and other factors affecting safety and operation, including unusual operating and maintenance conditions. The cause of the 2011 hazardous liquid pipeline accident resulting in a crude oil spill into the Yellowstone River near Laurel, Montana was scouring at the river crossing due to flooding. In this case, annual heavy flooding occurred in the Spring of the 2011. In late May, the operator shut down the pipeline for several hours to assess the state of the pipeline. Following the assessment, the operator restarted the pipeline and agreed to monitor the river area on a daily basis. On July 1, 2011 the pipeline ruptured which resulted in the release of 1,500 barrels of crude oil into the Yellowstone River. A second break, due to exposure to flood conditions, occurred several years later on the same pipeline led to an additional spill in the Yellowstone River. Other examples include Hurricane Katrina (2005) which resulted in significant damage to the oil and gas production structures and the San Jacinto flood (1994) which resulted in 8 ruptures and undermining of 29 other pipelines. In the context of the San Jacinto flood, “undermining” occurred when support material for the pipelines was removed due to erosion driven by the floodwaters. As a result, the unsupported pipelines were subjected to stress from the floodwaters that resulted in fatigue cracks in the pipe walls. Based on these examples of extreme weather events that did result, or could have resulted, in pipeline incidents, PHMSA has determined that additional regulations are needed to require, and establish standards for, inspection of the pipeline and right-of-way for “other factors affecting safety and operation” following an extreme weather event, such as a hurricane or flood, an earthquake, a natural disaster, or other similar event that has the likelihood of damage to infrastructure. The proposed rule would require such inspections, specify the timeframe in which such inspections should commence, and specify the appropriate remedial actions that must be taken to ensure safe pipeline operations. The new regulation would apply to onshore transmission pipelines and their rights-of-way.

• Notification for 7-Year Reassessment Interval Extension. Subsection 5(e) of the Act identifies a technical correction amending section 60109(c)(3)(B) of title 49 of the United States Code to allow the Secretary of Transportation to extend the 7- calendar year reassessment interval for an additional 6 months if the operator submits written notice to the Secretary with sufficient justification of the need for the extension. PHMSA would expect that any justification, at a minimum, would need to demonstrate that the extension does not pose a safety risk. PHMSA proposes to codify this statutory requirement.

• Reporting Exceedances of Maximum Allowable Operating Pressure. Section 23 of the Act requires operators to report to PHMSA each exceedance of the maximum allowable operating pressure (MAOP) that exceeds the margin (build-up) allowed for operation of pressure-limiting or control devices. Implicit in § 192.605 is the intent for operators to establish operational and maintenance controls and procedures to effectively preclude operation at pressures that exceed MAOP. PHMSA expects that operators' procedures should already address this aspect of operations and maintenance, as it is a long-standing, critical aspect of safe pipeline operations. PHMSA issued ADB 12-11 to address exceedances of MAOP. However, PHMSA proposes to codify this statutory requirement in § 192.605.

• Consideration of Seismicity. Section 29 of the Act states that in identifying and evaluating all potential threats to each pipeline segment, an operator of a pipeline facility must consider the seismicity of the area. PHMSA proposes to codify this statutory requirement by adding requirements to explicitly reference seismicity for data gathering and integration, threat identification, and implementation of preventive and mitigative measures.

• Safety Regulations for In-line Inspection (ILI), Scraper, and Sphere Facilities. PHMSA is proposing to add explicit requirements for safety features on launchers and receivers associated with ILI, scraper and sphere facilities.

• Consensus Standards for Pipeline Assessments. The proposed rule would incorporate by reference industry standards for assessing the physical condition of in-service pipelines using in-line inspection, internal corrosion direct assessment, and stress corrosion cracking direct assessment. Periodic assessment of the condition of gas transmission pipelines in HCAs is required by 49 CFR 192.921 and 192.937. The regulations provide minimal requirements for the use of these assessment techniques since at the time these regulations were established, industry standards did not exist addressing how these techniques should be applied. Incorporation of standards subsequently published by the American Petroleum Institute (API), the National Association of Corrosion Engineers (NACE), and the American Society of Nondestructive Testing (ASNT) would assure better consistency, accuracy and quality in pipeline assessments conducted using these techniques.

F. Integrity Verification Process Workshop

An Integrity Verification Process (IVP) workshop was held on August 7, 2013. At the workshop, PHMSA, the National Association of State Pipeline Safety Representatives and various other stakeholders presented information and comments were sought on a proposed IVP that will help address mandates set forth in Section 23, Maximum Allowable Operating Pressure, of the Act and the NTSB Recommendations P-11-14 (repeal pressure test exemptions) and P-11-15 (stability of manufacturing and construction defects). Key aspects of the proposed IVP process include criteria for establishing which pipe segments would be subject to the IVP, technical requirements for verifying material properties where adequate records are not available, and technical requirements for re-establishing MAOP where adequate records are not available or the existing MAOP was established under § 192.619(c). Comments were received from the American Gas Association, the Interstate Natural Gas Association of America, and other stakeholders addressing the draft IVP flow chart, technical concerns for implementing the proposed IVP, and other issues. The detailed comments are available under Docket No. PHMSA-2013-0119. PHMSA considered and incorporated the stakeholder input, as appropriate, into this NPRM, which proposes requirements to address the current exemptions to pressure test requirements, manufacturing and construction defect stability, verification of MAOP where records to establish MAOP are not available or inadequate (new §§ 192.619(e) and 192.624), and verification and documentation of pipeline material for certain onshore, steel, gas transmission pipelines (new § 192.607).

III. Analysis of Comments on the ANPRM

In Section II of the ANPRM, PHMSA sought comments concerning the significance of the proposed issues to pipeline safety; whether new/revised regulations are needed and, if so, suggestions as to what changes are needed; and likely costs that would be associated with implementing any new/revised requirements. PHMSA posed specific questions to solicit stakeholder input. These included questions related to 15 specific topic areas in two broad categories:

1. Should IM requirements be revised and strengthened to bring more pipeline mileage under IM requirements and to better assure safety of pipeline segments in HCAs? Specific topics included:

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.

2. Should non-IM requirements be strengthened or expanded to address other issues associated with pipeline system integrity. Specific topics included:

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.

PHMSA received a total of 1,463 comments; 1,080 from industry sources (Trade Associations/Unions, Pipeline Operators and Consultants); 316 comments from the public (Environmental Groups, Government Agencies/Municipalities, NAPSR and individual members of the general public); and 67 general comments not directly related to the ANPRM questions or categories. Commenters included:

• Citizen Groups

○ Environmental Defense Fund (EDF)

○ League of Women Voters of Pennsylvania (LWV)

○ Pipeline Safety Trust (PST)

○ State of Washington Citizens Advisory Committee on Pipeline Safety (CCOPS)

• Consultants

○ Accufacts Inc.

○ Oleksa and Associates, Inc.

○ Thomas M. Lael

○ WKM Consultancy, LLC

• Government Agencies

○ California Public Utilities Commission (CPUC)

○ City and County of San Francisco (CCSF)

○ Federal Energy Regulatory Commission (FERC)

○ Harris County Fire Marshal's Office (HCFM)

○ Interstate Oil and Gas Compact Commission (IOGCC)

○ Iowa Utilities Board

○ Kansas Corporation Commission (KCC)

○ Kansas Department of Health and Environment (KDHE)

○ National Association of Pipeline Safety Representatives (NAPSR)

○ National Transportation Safety Board (NTSB)

○ Railroad Commission of Texas (TRRC)

○ State of Alaska—AK Natural Gas Development Authority (AKN)

○ State of Alaska Dept. of Natural Resources (AKDNR)

○ Wyoming County Commissioners of Pennsylvania (WYCTY)

• Pipeline Industry

○ Air Products and Chemicals, Inc.

○ Alliance Pipeline

○ Ameren Illinois (AmerenIL)

○ Atmos Energy

○ Avista Corporation

○ CenterPoint Energy

○ CenterPoint Energy Resources Corp.

○ Chevron

○ Dominion East Ohio Gas (DEOG)

○ El Paso (EPPG)

○ ITT Exelis Geospatial Systems

○ Kern River Gas Transmission Company

○ MidAmerican Energy Company

○ National Fuel Gas Supply Corporation

○ National Grid

○ Nicor Gas

○ NiSource Gas Transmission & Storage

○ Northern Natural Gas

○ Paiute Pipeline Company

○ Panhandle Energy

○ Questar Gas Company

○ Questar Pipeline Company

○ SCGC and SDG&E (Sempra)

○ Southern Star Central Gas Pipeline, Inc.

○ Southwest Gas Corporation

○ Spectra Energy

○ TransCanada

○ TransCanada Corporation

○ Waste Management, Inc

○ Williams Gas Pipeline

• Municipalities

○ Delaware Solid Waste Authority (DSWA)

○ Iowa Association of Municipal Utilities (IAMU)

• Trade Associations

○ American Gas Association (AGA)

○ American Public Gas Association (APGA)

○ Gas Processors Association (GPA)

○ Gas Piping Technology Committee (GPTC)

○ Independent Petroleum Association of America, its Cooperating Associations, and the American Petroleum Institute (IPAA/API)

○ Interstate Natural Gas Association of America (INGAA)

○ NACE International

○ National Solid Waste Management Association (NSWMA)

○ National Utility Locating Contractors Association (Locators)

○ Oklahoma Independent Petroleum Association (OKIPA)

○ Texas Oil and Gas Association (TXOGA)

○ Texas Pipeline Association (TPA)

• Trade Unions

○ Professional Engineers in California Government (PECG)

• 31 Private Citizens

Commenters responded to ANPRM questions, but also submitted comments on subjects generally related to gas pipeline safety regulation (but not related to an ANPRM topic) and general comments related to a topic but not in response to any specific question. This NPRM presents a summary of the comments received (similar or duplicate comments are consolidated). The general (no-topic) comments are presented first under the heading “General Comments.” Comments on each topic follow under the heading “Comments on ANPRM Section II Topics on Which PHMSA Sought Comment,” beginning with general comments related to the topic and then proceeding to each individual question.

General Comments

General Industry Comments

1. A number of commenters associated with the pipeline industry suggested that PHMSA should defer action on the changes discussed in the ANPRM until the studies required by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 are completed. They contended the Act presents critical issues that require priority attention. They believe the questions raised by Congress, and to which the studies are addressed, could lead to fundamental changes in how pipeline safety is regulated and these changes need to be understood before new rules are written. Several commenters also suggested PHMSA lacks the resources to pursue simultaneously the required studies and complicated rulemakings. The Railroad Commission of Texas also suggested no new requirements be proposed until the effects of the new Act are understood, since they believe that the Act will change the scope of regulatory authority and impose additional costs on industry and regulators.

Response

PHMSA has placed studies and evaluations that relate to the topics in this proposed rulemaking on the docket. PHMSA seeks public comment on those reports and will consider comments before finalizing this rule. Other topics not addressed in this rulemaking that require additional study or evaluation will be addressed separately. Areas for safety improvement that have previously been identified and that are not dependent on the outcome of the required studies are also the subject of the proposals in this Notice.

2. INGAA, AGA, and several pipeline operators and consultants commented that the ANPRM suggested that PHMSA intends to pursue prescriptive regulation in a number of areas. They objected to this approach. They prefer performance-based regulation, under which operators have greater flexibility in deciding how the required safety goal can be met, considering the specific circumstances of their pipeline systems. They noted that integrity management, a performance-based approach, has greatly improved pipeline safety, and suggested PHMSA consider expanding the elements to be covered in an IM plan and providing more well-defined guidelines on how these expanded plans should evolve over time. They noted that implementing pipeline safety regulations is a complex process and implementing prescriptive requirements is usually inefficient. They also noted that prescriptive requirements tend to discourage technological advancements which can lead to improved means to assure safety.

Response

PHMSA believes performance-based regulations are central to improving pipeline performance. In some instances, however, prescriptive

requirements may be necessary to provide the requisite improvement to pipeline safety performance; for example, requirements for corrosion control, repair conditions, and repair criteria to more specifically address significant corrosion issues. In these cases, the unsafe condition can be clearly specified, and steps necessary to remediate the risk are well-understood engineering practice. PHMSA is committed to an efficient and effective approach to pipeline safety, and using prescriptive regulatory requirements only where necessary.

3. AGA, Texas Pipeline Association, Texas Oil and Gas Association, and a number of pipeline operators objected to the scope and pace of change in pipeline safety regulation. These commenters noted that the ANPRM covered a number of complex issues. In addition, they noted that pipeline operators are still implementing a number of large new initiatives including control room management, public awareness, distribution integrity management, and damage prevention. They commented that the industry needs time to complete implementing these other new regulations and PHMSA and the industry need time to evaluate the effect they have on pipeline safety. AGA specifically expressed concern that the pace of change could result in unintended adverse consequences. The Texas Associations suggested that any expansion of non-HCA regulations should address highest risks first and be structured to tailor requirements to different pipeline conditions because other approaches are likely to result in increased costs with little safety benefit. MidAmerican commented that the ANPRM appeared to be based on an incorrect assumption that there are no current requirements applicable to non-HCA pipe; they noted that part 192 includes many requirements applicable to non-HCA segments and that they assure safety. Atmos suggested PHMSA avoid the “one size fits all” approach to pipeline safety regulations.

Response

PHMSA understands that assimilation of change is an important consideration and agrees that the ANPRM covers a number of complex issues. Many of the more complex issues contemplated in the ANPRM, such as leak detection and automatic valves, will be addressed by separate rulemaking so that more careful and detailed analysis can be completed. However, PHMSA is proposing rulemaking in a number of areas to assure that the regulations continue to provide an adequate level of safety for both HCAs and non-HCAs. Additional discussion of the basis for the proposed rulemaking is presented in the response to comments received for each ANPRM topic and in Section V below (Section-by-Section Analysis).

4. A number of industry commenters suggested that PHMSA exercise care in developing broad requirements that may be inappropriate for some types of pipelines. In particular, APGA noted that “transmission” pipeline operated by local distribution companies is very different from long-distance transmission lines. They are typically smaller diameter, operate at lower pressures, and are often made of plastic. AGA and distribution pipeline operators noted that leaks are a routine management issue for distribution pipelines and those requirements appropriate to leak response for transmission pipelines would not be appropriate in a distribution context. The Texas Oil & Gas Association requested that any changes be examined for possible unexpected impact on gathering lines, which also differ from transmission pipelines.

Response

PHMSA is aware of the varying nature of pipeline systems. One aspect of performance-based requirements is the ability of operators to customize the integrity management program so that it is appropriate to its circumstances.

5. AGA and some pipeline operators noted that the ANPRM suggested that PHMSA intends to extrapolate hazardous liquid pipeline experience to gas pipelines. In particular, they expressed concern regarding the discussion of leak detection. They noted pin-point leak detection may be practical for non-compressible liquids but is not for gas.

Response

PHMSA appreciates the significant differences between hazardous liquid pipelines and gas pipelines with respect to leak detection. PHMSA is sponsoring studies and research to address leak detection in a responsible way, while still being responsive to related NTSB recommendations. PHMSA is considering separate rulemaking for leak detection that will address these studies and research.

6. Pipeline industry trade associations reported that their members plan to implement voluntary approaches to improve pipeline safety. INGAA reported it has implemented a strategy to achieve a goal of zero pipeline incidents. This strategy includes voluntary application of IM principles to non-HCA pipeline segments where people live. Their goal is to apply ASME/ANSI B31.8S, Managing System Integrity of Gas Pipelines, principles to 90 percent of people who live or work in close proximity to pipelines by 2020, and 100 percent by 2030. INGAA's strategy also includes assuring the fitness for service of pipelines installed before federal safety regulations were promulgated, improving incident response time (to less than one hour in populated areas), and implementing the Pipelines and Informed Planning Alliance (PIPA) guidelines. AGA similarly reported their intentions to address improvements to safety proactively by applying Operator Qualification to new construction, continuing to advance IM principles (including developing industry guidelines for data management and data quality), and working with a coalition of PIPA stakeholders to adopt PIPA-recommended best practices, among other initiatives.

Response

PHMSA commends the pipeline industry for these initiatives and is committed to working with the industry to improve performance toward the goal of zero pipeline incidents.

7. A number of comments addressed the cost-benefit analyses that will be required in support of rulemaking that results from this ANPRM. AGA noted that a detailed estimate has not been completed but that preliminary evaluations suggest that the cost of implementing the initiatives included in the ANPRM could well exceed the cost of implementing the 2003 gas transmission IM rule. APGA agreed that some of the concepts discussed in the ANPRM are potentially very costly and must be considered carefully. Accufacts cautioned PHMSA to be wary of efforts to distort the cost-benefit analyses by hyper inflating costs. As an example, Accufacts pointed to estimates of costs to perform hydrostatic tests ranging from $500,000 to $1,000,000 per mile compared to costs of $29,400 to $40,000 per mile cited in the NTSB report on the San Bruno accident.

Response

PHMSA acknowledges that estimates of hydrostatic test costs can vary and that there is risk in using overstated estimates in the analysis of benefits and costs since regulatory decisions regarding public safety can be based on these results. For the Preliminary Regulatory Impact Assessment (PRIA) for this proposed rule PHMSA used vendor pricing data to develop unit costs for pressure testing. These costs represent the contractor's costs to complete an eight hour pressure test for

various segment diameters and lengths. PHMSA applied a multiplier to account for other operator costs, such as manifold installation and operational oversight, and also added estimated costs to provide temporary gas supplies and the market value of lost gas. Based on these data and assumptions, PHMSA estimated per mile pressure test costs range from approximately $60,000 per mile (12″ diameter, 10 mile segment) to 630,000 (36″ diameter, one mile segment). Detailed explanations of these unit costs are available in the PRIA, provided in the regulatory docket.

8. AGA and several pipeline operators suggested PHMSA should establish jointly with industry a committee to evaluate pipeline data and to determine whether more data is needed. They commented industry has repeatedly made this request and PHMSA has, to date, not responded. They contended PHMSA's current analysis of pipeline safety performance data is inadequate. Similarly, Panhandle Energy noted a number of the questions in the ANPRM requested data on various subjects; Panhandle expressed its belief that PHMSA collects and has access to at least some of data requested, and this data, collected pursuant to regulatory requirements, should be more complete, and consistently collected and reported, than piecemeal collections of data in response to this ANPRM. Expressing a somewhat contrary view, El Paso suggested more data should be collected and analyzed before notices of proposed rulemakings are prepared; PHMSA needs to collect and analyze data to determine the proper path for future requirements, if any.

Response

In response to NTSB recommendation P-11-19, PHMSA held a pipeline safety data workshop in January 2013. The workshop: (1) Summarized the data OPS collects, who it is collected from, and why it is collected; (2) addressed how stakeholders, including OPS, industry, and the public use the data; (3) addressed data quality improvement efforts and performance measures; and (4) discussed the best method(s) for collecting, analyzing, and ensuring transparency of additional data needed to improve performance measures. PHMSA considered the results of the workshop as well as the comments to the ANPRM related to pipeline safety performance data.

9. APGA suggested PHMSA revise the definitions of transmission and distribution pipelines to be more risk-based. APGA contended that the current definitions are not risk-based and lead to inappropriate outcomes. In particular, classification of some pipelines as “transmission” based on functional aspects of the current definition leads to inappropriate application of requirements. In a similar vein, Oleksa and Associates suggested it may be time to reduce IM requirements on low-stress transmission pipelines, which pose lower risk than high-stress lines. Texas Pipeline Association and Texas Oil & Gas Association commented PHMSA should not extrapolate experience with interstate pipelines to intrastate lines, which differ in design and operation.

Response

The definition of transmission vs. distribution pipelines and the applicability requirements for integrity management in High Consequence Areas is not within the scope of this proposed rule. The general topic of the scope and applicability of integrity management is addressed in the class location report which available in the docket.

10. Northern Natural Gas recommended all exemptions from one-call requirements be eliminated. They noted excavation damage remains, by far, the single greatest threat to pipeline safety and management of excavation damage, through one-call programs, has been demonstrated to be an effective means of countering that threat.

Response

This comment is not within the scope of the ANPRM topics. However, PHMSA has revised the pipeline safety regulations related to pipeline damage prevention programs, which includes one-call programs, in an final rule issued July 23, 2015 (80 FR 43836).

11. The Gas Processors Association, Texas Pipeline Association, and Texas Oil & Gas Association commented regarding current efforts to clarify the applicability of part 192 requirements, particularly requirements for distribution integrity management, to farm taps. They suggested PHMSA is engaged in an expansion of requirements in this area without notice or a demonstrated safety need. They suggested PHMSA initiate a rulemaking specifically to clarify requirements applicable to farm taps.

Response

Treatment of farm taps is not within the scope of the ANPRM topics. However, PHMSA has engaged in dialogue with industry on this topic and will continue to consider options to address this issue in a separate action.

12. Northern Natural Gas suggested PHMSA reduce the time allowed for conducting a baseline assessment in cases where a new HCA is found, tailored to the circumstances of the particular segment. Northern expressed its belief this would address threats to integrity in areas affecting population more quickly than current requirements.

Response

Currently, § 192.905(c) requires that newly identified HCAs be incorporated into the baseline assessment plan within one year. PHMSA does not currently have plans to address this requirement. However, periodically DOT or PHMSA seeks public input on retrospective review of existing regulations under Executive Order 13563. PHMSA encourages the commenter to raise this issue the next time DOT or PHMSA solicits comments on retrospective review of existing regulations.

13. Alliance Pipeline suggested many pipeline safety questions can be answered by applying INGAA's five guiding principles of pipeline safety. They noted INGAA has developed the Integrity Management-Continuous Improvement (IMCI) Initiative to implement these principles and suggested PHMSA actively engage with INGAA in developing workable solutions to pipeline safety issues.

Response

PHMSA appreciates the industry efforts to improve pipeline safety and is committed to working with all stakeholders toward this end.

14. Paiute Pipeline and Southwest Gas commented integrity management requirements have not been in effect long enough to gauge their effectiveness and decide whether additional changes are needed. The companies noted the first, baseline assessments of pipeline segments subject to those requirements are only now being completed. AGA and other pipeline operators agreed, noting IM is still new, operators are still refining their processes, and PHMSA should approach change with caution.

Response

While the first round of baseline assessments are only now being completed, the gas IM rule has been in place approximately 10 years. PHMSA expects that operator IM programs should have significantly matured in this timeframe.

15. Panhandle Energy suggested that PHMSA evaluate rule changes that could have prevented incidents which occurred in recent years. Any initiatives that would not have contributed to improved safety, they suggest, should be postponed or treated as lower priority activities. Panhandle suggested rulemaking without a sound basis is not

only ineffective but counterproductive in that it diverts resources that could have been used to improve safety. Questar Gas similarly commented PHMSA needs to minimize unnecessary activities that inappropriately divert safety resources. Questar also recommended that PHMSA explicitly consider the diversity within the regulated community.

Response

One of the major motivations for PHMSA's issuance of the ANPRM was to solicit information useful to ensuring that pipeline safety reforms have a sound basis. PHMSA is also required by Executive Orders 12866 and 13563 to ensure that the benefits of its rules justify the costs, to the extent permitted by law. PHMSA has prepared an initial regulatory impact analysis for this proposed rule, which is available in the docket for this rule. PHMSA encourages the commenter as well as other members of the public to review the analysis and provide input for improving the final rule.

16. AGA and several pipeline operators commented that, while enhancements can be made, IM requirements need not be subjected to wholesale change. They cited GAO and NTSB reports on the efficacy of transmission pipeline integrity management and the lack of pipeline safety issues among the NTSB's “Most Wanted” issues.

Response

While PHMSA believes that IM has led to improvements in managing pipeline integrity, recent incidents and accidents demonstrate that much work remains to improve pipeline safety.

17. AGA and pipeline operators noted that transmission and distribution integrity management are not distinct activities for most intrastate pipeline operators. They contended that the ANPRM seemed to be based on a presumption that operators manage their transmission and distribution pipeline safety differently, and that this assumption is without basis.

Response

PHMSA has promulgated specific IM rules for both transmission and distribution systems with a view toward allowing operators to customize their performance based programs as appropriate to their specific systems.

18. AGA and several pipeline operators suggested that any changes to public awareness requirements should be made at the state level. They noted that federal requirements in this area are new and that effectiveness reviews are still in progress.

Response

This issue is not within the scope of the ANPRM. However, PHMSA has revised the pipeline safety regulations related to pipeline damage prevention programs in a final rule issued July 23, 2015 (80 FR 43836).

19. NACE International suggested that adopting its standards for corrosion control would be the best means to accomplish the goal of maintaining pipelines safe and functional for long periods of time.

Response

This NPRM proposes to incorporate industry 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. In addition, this NPRM proposes to enhance subpart I requirements for corrosion control and to revise Appendix D to improve requirements for cathodic protection.

20. The NTSB commented that regulations for gas transmission pipelines can and should be improved and expressed its support for the overall intent of the ANPRM. The NTSB noted publication of the ANPRM prior to its recommendations resulting from the San Bruno incident investigation precluded any mention in the ANPRM of these NTSB safety recommendations. The NTSB suggested PHMSA should seek comment on its recommendations.

Response

PHMSA has reviewed the NTSB recommendations that were issued on September 26, 2011 and found that several recommendations related directly to the topics addressed in the ANPRM and that may impact the proposed approach to rulemaking. The topics impacted are discussed above in the Background section above, in sections II.C and II.E, and include NTSB Recommendations P-11-10, P-11-11, P-11-14, P-11-15, P-11-17, and P-11-19. The NTSB's other recommendations will be addressed in separate proceedings.

21. El Paso suggested that the proper approach to attain the highest pipeline safety levels is through a structured, deliberate rulemaking that closely examines all issue aspects prior to making informed decisions.

Response

PHMSA agrees and is taking a careful, structured, and phased approach to enhancing pipeline safety regulations and IM performance standards.

22. Thomas M. Lael, a pipeline industry consultant, suggested any new regulations be concise and clear. He contended past lack of clarity has created the need for many re-interpretations and enforcement problems.

Response

PHMSA concurs but also notes that performance-based regulations, by their nature, are not as specific, nor as easily measurable, as prescriptive regulations, but are more likely to improve safety and the cost-effectiveness of regulations. PHMSA provides guidance to help stakeholders understand the intent and scope of performance-based regulations.

General Public Comments

1. A member of the public stated that the ANPRM did not provide specific options for consideration. As written, only those with direct involvement in the industry could understand it well enough to comment. Presenting the options more specifically would allow for better informed public comment. The discussion should also include a regional component, since issues affecting different states/regions are not the same.

Response

By its nature, the ANPRM did not propose specific alternatives or rules, but solicited input to help inform future proposals. This NPRM provides specific proposed rules for public comment.

2. The Alaska Natural Gas Development Authority stated that the regulations should require consideration of earthquakes, as recent history shows they can be very important to safety of high-pressure gas lines.

Response

Section 29 of the Act states that in identifying and evaluating all potential threats to each pipeline segment, an operator of a pipeline facility shall consider the seismicity of the area. Rulemaking for this issue is addressed in this NPRM and would add requirements to explicitly reference seismicity for data gathering and integration, threat identification and implementation of preventive and mitigative measures.

3. The Environmental Defense Fund pointed out that methane is a very potent greenhouse gas. They commented that PHMSA should consider and minimize the potential environmental effects of any future rulemaking. They suggested EPA's Natural Gas Star program as a model.

Response

The proposals in this rulemaking are designed to minimize the risk of pipeline failures, which will result in environmental benefits. The draft environmental assessment addresses the environmental effects of this rulemaking.

In addition, the RIA provides estimates of the environmental benefits of this proposed rule. Natural gas transported in transmission pipelines contains heat-trapping gases that contribute to global climate change and its attendant societal costs. Of these gases, of primary importance for evaluation are methane—by far, the largest constituent of natural gas—and carbon dioxide. Other natural gas components (ethane, propane, etc.) contribute as well, but they account for a much smaller percentage of the natural gas mixture and, as a result, are much less significant than methane in terms of their environmental impact. The proposed rule is expected to prevent incidents, leaks, and other types of failures that might occur, thereby preventing future releases of greenhouse gases (GHG) to the atmosphere, thus avoiding additional contributions to global climate change. PHMSA estimated net GHG emissions abatement over 15 years of 69,000 to 122,000 metric tons of methane and 14,000 to 22,000 metric tons of carbon dioxide, based on the estimated number of incidents averted and emissions from pressure tests and ILI upgrades.

4. A member of the public questioned the openness and clarity of PHMSA's enforcement of pipeline safety regulations, and the use of civil penalty revenues.

Response

This comment is not within the scope of the ANPRM topics, however, it should be noted that PHMSA embraces transparency in its regulatory oversight program and has established a Pipeline Safety Stakeholder Communications Web site,

http://primis.phmsa.dot.gov/comm/

, which presents a variety of reports detailing enforcement activity. These reports are offered on both nationwide and operator-specific bases.

5. One member of the public suggested that DOT define “safe corridors” for above-ground construction of pipelines. The commenter suggested this would be similar, in principle, to the interstate highway system. It would help to keep pipelines separated from residences, avoid corrosive environments, and make pipelines available for routine direct examination. At a minimum, this commenter suggested the regulations should specify a minimum separation between new pipelines and residences, as does the New Jersey state code, or homebuyers be informed when a home is within the potential impact radius of a gas transmission pipeline so they may make an informed buying decision.

Response

This comment addresses pipeline siting and routing, which is outside the scope of PHMSA's statutory authority. As specified in 49 U.S.C. 60104, Requirements and Limitations of the Act, PHMSA is prohibited from regulating activities associated with locating and routing pipelines. Paragraph (e) of the statute states “Location and routing of facilities.—This chapter does not authorize the Secretary of Transportation to prescribe the location or routing of a pipeline facility.” However, PHMSA is an active participant in the Pipeline and Informed Planning Alliance (PIPA) and encourages all stakeholders to learn about, and become involved with, PIPA. More information can be obtained online at:

http://primis.phmsa.dot.gov/comm/pipa/landuseplanning.htm

6. One member of the public noted there is an increasing trend in significant incidents and suggested that this trend may be related to undue influence of the pipeline industry on the regulations under which it operates. The commenter recommended regulations should not be weakened in favor of industry. The League of Women Voters of Pennsylvania also recommended that regulatory agencies be insulated from political and other influences of natural gas pipeline companies to avoid the appearance of a conflict of interest.

Response

PHMSA appreciates these comments. PHMSA is committed to improving pipeline safety, and that is the goal of this endeavor. Significant incidents on Gas Transmission (GT) pipelines have averaged between 70 and 80 incidents per year over the past 9 years. The existing integrity management regulations in 49 CFR part 192, subpart O, addresses pipeline integrity in HCAs, which is only about 7 percent of the GT pipeline mileage. This proposed NPRM is focused on strengthening requirements in HCAs and applying integrity management principles to areas outside HCAs to better address safety issues. In addition, the proposed rule seeks to address significant issues that caused or contributed to the San Bruno accident, which include lack of pressure test, inadequate records, poor materials, and inadequate integrity assessment. The operator reports submitted to PHMSA as mandated by the Act confirm that these issues are widespread for both HCA and non-HCA pipe segments.

7. The Harris County Fire Marshall's Office (HCFM) suggested stiffer regulations are needed for gas transmission pipeline safety, because of the large potential for negative impact and catastrophic consequences. HCFM expressed concern about corrosion control and current inspection practices for aging transmission infrastructure.

Response

This NPRM proposes enhanced corrosion control requirements, including periodic close interval surveys, post construction surveys for coating damage, and interference current surveys. This NPRM also proposes enhanced requirements for internal corrosion and external corrosion management programs.

8. The Pipeline Safety Trust (PST) commented that the ANPRM, itself, may heighten and fuel existing public concerns about pipeline safety. PST noted that many of the questions asked the industry to provide information they believe the public would believe PHMSA should already have. PST expressed its view that the number and types of questions asked in the ANPRM reflect gaps in PHMSA's knowledge of gas transmission pipeline systems and operator practices.

Response

PHMSA appreciates these comments. PHMSA is committed to improving pipeline safety and stakeholder input is valuable to the regulatory process.

9. Professional Engineers in California Government (PECG) commented that private companies should not be solely responsible for the safety of their pipelines. PECG contended that this approach has not worked. PECG also suggested PHMSA examine options for increasing the number of inspectors at state pipeline regulatory agencies and require public inspectors be on site for pipeline construction and testing. They contended such inspection is necessary to assure that older pipelines are tested adequately and replaced when needed.

Response

PHMSA appreciates these comments. PHMSA is committed to ensuring that operators maintain and operate their pipelines safely. This rulemaking contains a number of measures aimed at enhancing oversight.

10. The City and County of San Francisco (CCSF) noted the scope of potential rulemaking discussed in the

ANPRM did not include consideration of PHMSA's coordination with and oversight of state certified agencies. In order to ensure the proper oversight over natural gas transmission operators and the safe operation of natural gas transmission lines, CCSF believes PHMSA must address its state certification program and its oversight of state enforcement of pipeline safety standards. CCSF recommended PHMSA publish regulations for certification of state programs. They cited NTSB recommendation P-11-20 and asserted PHMSA has not corrected inadequate practices of the California Public Utilities Commission.

Response

This comment is outside the scope of this rulemaking. PHMSA is addressing NTSB recommendation P-11-20 separately.

11. Two members of the public suggested the processes of the Federal Energy Regulatory Commission (FERC) for siting pipelines should be revised. One suggested a Commission on Public Accountability and Safety Standards be established, consisting of a majority of local public officials, first responder experts, and independent qualified engineers, to make recommendations for FERC's pre-application process and standards. The purpose would be to assure standards require public accountability for review and vetting of pipeline safety issues with local authorities when pipelines are proposed. The other commenter suggested the relationship between FERC and DOT should be clarified, that a company's enforcement history be taken into account in siting decisions, and PHMSA be a full party to all FERC proceedings. The commenter believes this is necessary because FERC does not have a public safety mandate.

Response

PHMSA is a separate agency from FERC and has no statutory authority with respect to pipeline siting or approval. As specified in 49 U.S.C. 60104, Requirements and Limitations of the Act, PHMSA is prohibited from regulating activities associated with locating and routing pipelines. Paragraph (e) of the statute states “Location and routing of facilities.—This chapter does not authorize the Secretary of Transportation to prescribe the location or routing of a pipeline facility.” However, PHMSA is an active participant in the Pipeline and Informed Planning Alliance (PIPA) and encourages all stakeholders to learn about, and become involved with, PIPA. More information can be obtained online at:

http://primis.phmsa.dot.gov/comm/pipa/landuseplanning.htm

12. Two members of the public commented federal regulations should not override local ordinances. They noted the concern of local authorities is safety, while others are concerned about industry costs. They believe federal regulations that allow operators significant discretion are a poor basis to supersede specific local requirements.

Response

PHMSA appreciates these comments. Federal regulations provide for a uniform body of standards and requirements related to pipeline safety. PHMSA is receptive to input from state and local authorities on pipeline safety issues. States and local authorities may adopt requirements that are more stringent than and consistent with the federal regulations for their intrastate pipelines if they have a 49 U.S.C. 60105 certification.

13. One member of the public suggested regulations require periodic safety audits by an auditor not selected by the pipeline operator. The commenter further suggested that local authorities should have approval authority in the choice of the auditor. The commenter contended this approach would strengthen public confidence in pipeline safety.

Response

PHMSA appreciates this comment. Highly trained federal and state pipeline inspectors conduct inspections of pipeline operators, their facilities, and their compliance programs on a regular basis.

Comments on ANPRM Section II Topics on Which PHMSA Sought Comment

In section II of the ANPRM, commenters were urged to consider whether additional safety measures are necessary to increase the level of safety for those pipelines that are in non-HCA areas as well as whether the current IM requirements need to be clarified and in some cases enhanced to assure that they continue to provide an adequate level of safety in HCAs. PHMSA posed specific questions to solicit stakeholder input. These included questions related to the following topics:

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.

Each topic is summarized as presented in the ANPRM, then general comments related to the topic are presented, followed by each individual question and comments received for the question.

A. Modifying the Definition of HCA

The ANPRM stated that “IM requirements in subpart O of part 192 specify how pipeline operators must identify, prioritize, assess, evaluate, repair and validate;

[sic]

through comprehensive analyses, the integrity of gas transmission pipelines in HCAs. Although operators may voluntarily apply IM practices to pipeline segments that are not in HCAs, the regulations do not require operators to do so. A gas transmission pipeline ruptured in San Bruno, California on September 9, 2010, resulting in eight deaths and considerable property damage. As a result of this event, public concern has been raised regarding whether safety requirements applicable to pipe in populated areas can be improved. PHMSA is thus considering expanding the definition of an HCA so that more miles of pipe are subject to IM requirements.” The ANPRM then listed questions for consideration and comment. The following are general comments received related to the topic as well as comments related to the specific questions:

General Comments for Topic A

1. INGAA and a number of pipeline operators noted this is an opportune time for considering the next steps in integrity management, since baseline assessments under the current IM rules are now being completed. INGAA noted its policy goal is to apply IM principles

(as described in ASME/ANSI B31.8S) beyond HCAs, covering 90 percent of people living near transmission pipelines by 2020 and 100 percent by 2030. TransCanada submitted information in support of INGAA's proposal, noting that by the end of 2012 the company will have assessed more than 85 percent of its US pipeline mileage covering more than 95 percent of people living near their pipelines. Thus, the current IM rules are having a significant positive impact on pipeline safety. TransCanada believes significant technological challenges would be encountered if IM regulations were extended to all pipelines.

2. MidAmerican commented it would be reasonable to differentiate between transmission pipelines operating above and below 30 percent specified minimum yield strength (SMYS) in terms of IM requirements. They estimated that less than 3 percent of local distribution company (LDC) transmission lines operate at greater than 30 percent SMYS.

3. MidAmerican and a member of the public suggested PHMSA eliminate class locations in favor of better-defined HCAs. They contend such a change would result in administrative savings for pipeline operators.

4. Southwest Gas and Paiute commented no new regulations should be promulgated in this area until the study required by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 is completed.

Response to General Comments for Topic A

PHMSA appreciates the information provided by the commenters. Section 5 of the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the Act) (Pub. L. 112-90) requires the Secretary of Transportation to “evaluate (1) whether integrity management system requirements, or elements thereof, should be expanded beyond high-consequence areas; and (2) with respect to gas transmission pipeline facilities, whether applying integrity management program requirements, or elements thereof, to additional areas would mitigate the need for class location requirements.” PHMSA has completed the report mandated by the Act that documents that evaluation and addresses whether integrity management (IM) program requirements should be expanded beyond high consequence areas (HCAs) and, specifically for gas transmission pipelines regulated under 49 Code of Federal Regulations (CFR) part 192, whether such expansion would mitigate the need for class location designations and corresponding requirements. The class location report is available for review in the docket.

In October 2010 and August 2011, the Pipeline and Hazardous Materials Safety Administration (PHMSA) published notices in the

Federal Register

to solicit comments on revising the pipeline safety regulations applicable to hazardous liquid and natural gas transmission pipelines including expansion of IM program requirements beyond HCAs. In general, industry representatives and pipeline operators were opposed to any expansion of HCAs and in favor of eliminating class locations on newly constructed pipelines, whereas public interest groups were in favor of expanding HCA but against curtailing class location requirements.

PHMSA has carefully considered the input and comments. At this time PHMSA plans to propose an approach that balances the need to provide additional protections for persons within the potential impact radius (PIR) of a pipeline rupture (outside of a defined HCA), and the need to prudently apply IM resources in a fashion that continues to emphasize the risk priority of HCAs. PHMSA, therefore, is considering an approach that would require selected aspects of IM programs (namely, integrity assessments and repair criteria) to be applicable for non-HCA segments. For hazardous liquid pipelines, PHMSA would propose to apply these requirements to non-HCA pipeline segments. For gas transmission pipelines, PHMSA would propose to apply these requirements where persons live and work and could reasonably be expected to be located within a pipeline PIR. Under this approach, PHMSA would propose requirements that integrity assessments be conducted, and that injurious anomalies and defects be repaired in a timely manner, using similar standards in place for HCAs. However, the other program elements of a full IM program contained in 49 CFR part 192, subpart O, or 49 CFR 195.452 (as applicable) would not be required for non-HCA segments.

The Act also required the Secretary of Transportation to evaluate if expanding IM outside of HCAs, as discussed above, would mitigate the need for class location requirements. In August 2013, PHMSA published a notice in the

Federal Register

(78 FR 53086) soliciting comments on expanding IM program requirements and mitigating class location requirements. In addition, PHMSA held a Class Location Workshop on April 16, 2014, to discuss the notice and comments were received from stakeholders, including industry representatives, pipeline operators, state regulatory agencies, and the public. Overall, the majority of stakeholder responses suggested that PHMSA not change the current class location approach for class locations and class location changes as population increases used for establishing MAOP and operation and maintenance (O&M) surveys for existing pipelines. For new transmission pipelines, some industry groups and operators supported some type of bifurcated approach for existing and new pipelines as described above.

Based upon stakeholder input and findings from lessons learned, incident investigations, assessments, IM, and operating, maintenance, design and construction considerations, PHMSA believes the application of integrity management assessment and remediation requirements to MCAs does not warrant elimination of class locations. Class locations affect all gas pipelines, including transmission (interstate and intrastate), gathering, and distribution pipelines, whether they are constructed of steel pipe or plastic pipe. Class location is integral to determining MAOPs, design pressures, pipeline repairs, high consequence areas (HCAs), and operating and maintenance inspections and surveillance intervals. Class locations affect 12 subparts and 28 sections of 49 CFR part 192 for gas pipelines. The subparts and sections are listed and discussed in Sections 3.1.2.4 and 3.7.2.2. While assessment and remediation of defects on gas transmission pipelines is an important risk mitigation program, it does not adequately compensate for other aspects of class location as it relates to other types of gas pipelines and as it relates (for all gas pipelines) to the original pipeline design and construction such as the design factor, initial pressure testing, establishment of MAOP, O&M activities, and other aspects of pipeline safety, that are based on class location. Thus, PHMSA has determined not to eliminate class location requirements.

With respect to the application of gas transmission IM requirements to pipeline operating at less than 30% SMYS, as part of its consideration of the issues discussed in Topics J and N, PHMSA considered but rejected the suggestion that pipelines operating less than 30% SMYS be differentiated from those operating at higher stress levels.

Comments submitted for questions in Topic A.

A.1—Should PHMSA revise the existing criteria for identifying HCAs to expand the miles of pipeline included in HCAs? If so, what amendments to the criteria should PHMSA consider (e.g.,

increasing the number of buildings intended for human occupancy in Method 2?) Have improvements in assessment technology during the past few years led to changes in the cost of assessing pipelines? Given that most non-HCA mileage is already subjected to in-line inspection (ILI), does the contemplated expansion of HCAs represent any additional cost for conducting integrity assessments? If so, what are those costs? How would amendments to the current criteria impact state and local governments and other entities?

1. INGAA, industry consultant Thomas Lael, and a number of pipeline operators commented that modification of the HCA definition is unnecessary. They contended that the current definition is already risk-based and provides an effective basis for IM requirements along with a reasonable point from which to expand the application of IM principles by voluntary action. Accufacts commented that PHMSA should focus on closing gaps and loopholes rather than increasing HCA mileage, and that increasing covered mileage would only create the illusion of more safety.

2. AGA, APGA, and a number of gas distribution pipeline operators also opposed changes to the definition. They commented that other requirements of part 192 already address the primary threats for pipe outside HCA. They noted that much effort went into establishing the current definition, there is no safety rationale to abandon it, and change would be inconsistent with risk-based principles and would dilute safety efforts. AGA further noted that imprudent expansion would be contrary to Congressional intent, in that it would dilute the focus on densely populated and environmentally sensitive areas. AGA commented that PHMSA should make no change in this area before completing the related studies required by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011.

3. Taking a contrary position, a number of commenters not affiliated with the pipeline industry supported increasing the pipeline mileage classified as HCA. One private citizen suggested that all pipelines in cities with population greater than 100,000 should be classified as HCA. This commenter believes that existing regulations result in insufficient requirements for urban pipelines. Another citizen suggested that all high-stress lines with a “receptor,” which he defines as “something which needs to be protected,” should be assessed. If changes to the HCA definition are needed to accomplish this, then he contended those changes should be made. The Pipeline Safety Trust would strengthen IM requirements and expand them to all transmission pipelines, although they allow that the details could be different for pipelines not currently classified as HCA. PST believes this would be an effective way to identify and eliminate threats.

4. The Oklahoma Independent Petroleum Association (OKIPA) commented that any changes to the HCA definition must be supported by a scientifically-valid assessment of risks and a complete cost-benefit analysis.

5. The Iowa Association of Municipal Utilities commented that PHMSA should not revise the HCA definition without taking into account the differences between high-pressure transmission pipelines and low-pressure, low-risk lines that are also classified as transmission. IAMU reported “transmission lines” operated by Iowa Municipal Utilities are typically 2 to 4 inches in diameter and have potential impact radii less than 90 feet.

6. The Texas Pipeline Association and Texas Oil & Gas Association contended that expanding HCA pipeline mileage would increase assessment costs, particularly if the arbitrary requirement fo

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