Gas Pipeline Safety: Stakeholders' and Officials' Views on Federal Odorizing Requirements

The nation's gas pipeline network moves about 74 billion cubic feet of combustible gas to homes and businesses daily. To alert the public of a gas leak before an explosion occurs, PHMSA has different requirements for odorizing gas. All gas transported by distribution pipelines throughout communities must be odorized. Gas transported across many miles by transmission pipelines is required to be odorized only in certain populated areas. There are no requirements to odorize gas in gathering pipelines. Congress included a provision in statute for GAO to review odor requirements for all pipelines.

This report presents the views of federal and state pipeline safety officials and industry and safety stakeholders on: (1) the advantages and disadvantages of odorizing combustible gases in pipelines; and (2) whether and how federal requirements for odorizing pipelines should be modified. GAO reviewed relevant regulations and reports; surveyed officials in 48 states and the District of Columbia; and interviewed PHMSA and NTSB officials. GAO also interviewed 34 stakeholders, including 14 experts identified by the National Academies, and 20 other industry and safety stakeholders.

Pipeline and Hazardous Materials Safety Administration (PHMSA) and National Transportation Safety Board (NTSB) officials, state officials, and stakeholders GAO contacted cited safety as the main advantage to odorizing combustible gases in pipelines, primarily for distribution pipelines in densely populated areas (see figure). Specifically, adding a chemical with a distinctive odor to gas allows the public to generally detect leaks before an explosion can occur. The most frequently cited disadvantage was that commonly used sulfur-based odorants must be removed—primarily from gas in transmission pipelines—before the gas can be used in certain processes, such as producing fertilizer.

While federal odorization requirements follow a risk-based approach by focusing on pipelines in populated areas, the officials and stakeholders GAO contacted disagreed on the need to modify these requirements for some pipelines. Specifically, because distribution pipelines run through populated areas, everyone GAO contacted generally agreed that these pipelines should be odorized for safety, as currently required. For gathering pipelines, the majority of officials and stakeholders did not see a need to modify regulations because these pipelines would be technically challenging to odorize and are primarily located in rural areas. However, about two-thirds of state officials and about half of stakeholders said that additional transmission pipelines should be odorized for public safety.

Conversely, officials from PHMSA and NTSB and about half of the stakeholders contacted noted that, because transmission pipelines operate at high pressure and generally rupture rather than leak, it is unlikely that odorant could mitigate risk. Instead, other required safety practices—such as internal pipeline inspections—can provide more preventative, risk-based safety management, according to PHMSA officials. In this regard, PHMSA officials said that they plan to strengthen risk-based safety requirements for transmission and gathering pipelines as part of on-going rulemakings. PHMSA anticipates issuing these rules in 2019.

In 2017, the nation’s gas pipeline network moved about 73.6 billion cubic  feet per day of dry natural gas to homes, schools, and businesses.  Pipelines are relatively safe when compared with other modes of  transporting hazardous goods. However, a pipeline leak could allow these  colorless, odorless gases to seep undetected into areas where people  live or work, with potentially devastating results. To alert the public of a  dangerous buildup of gas before an explosion can occur, federal pipeline  safety regulations—established by the Department of Transportation’s  Pipeline and Hazardous Materials Safety Administration (PHMSA)— require that combustible gases transported by certain pipelines be  odorized by adding a chemical with a distinctive odor that can be easily  recognizable by a person with a normal sense of smell. Specifically, all  gases in distribution pipelines, which run throughout cities and  communities, must be odorized. Gases transported by large, high- pressure transmission pipelines, which run across the country, are  required to be odorized only in certain populated areas. Gases collected  by gathering pipelines from wells in gas drilling areas are not required to  be odorized.

The Protecting our Infrastructure of Pipelines and Enhancing Safety  (PIPES) Act of 2016 included a provision for us to review the potential  impact of requiring that combustible gases transported by all pipelines be  odorized. This report presents the views of federal and state officials and  industry and safety stakeholders on:  1.  the advantages and disadvantages of odorizing combustible gases  transported by pipeline; and  2.  whether and how federal pipeline odorization requirements should be  modified.

To address both objectives, we reviewed relevant statutes, regulations,  and our prior work related to federal and state gas pipeline odorization  requirements. We also collected data from PHMSA on pipeline miles by  pipeline type, the gases odorized, and the odorant types for fiscal year  2016 through 2018. We assessed the reliability of these data by  interviewing PHMSA officials on how it was collected and verified and  determined that the data were sufficiently reliable for our purposes. We  interviewed PHMSA and National Transportation Safety Board (NTSB)  officials on the current federal odorization requirements, as well as  whether and how they should be modified.

We also surveyed pipeline safety officials in the contiguous 48 states and  the District of Columbia to collect information on both objectives. We  received a 100 percent response rate. To develop the survey questions,  we conducted initial interviews with state pipeline safety officials and  stakeholders to identify issues regarding pipeline odorization  requirements. We also reviewed key literature to ascertain the  advantages and disadvantages of odorizing gas transported by pipelines.  The survey was reviewed by an internal, independent survey expert and  pretested with three potential respondents from state pipeline safety  agencies. We did this to ensure that:  1.  the questions were clear and unambiguous,  2.  the terms we used were precise,  3.  the survey did not place an undue burden on the agency officials  4.  the survey was independent and unbiased.

We took steps in survey design, data collection, and analysis to minimize  non-sampling errors. Our results are not subject to sampling error  because we administered our survey to all 48 lower contiguous state  pipeline safety agencies and the District of Columbia. The survey data  were collected from September through November 2017.

In addition, we interviewed 34 stakeholders. We worked with the National  Academies of Science to identify 14 experts that we interviewed to  discuss their views on both objectives. These experts were selected  based on their expertise in the following areas: chemistry, gas industry,  odorant industry, chemical manufacturing industry, and public health and  safety, with all areas of expertise balanced to obtain a wide variety of  viewpoints. Finally, we interviewed 20 other industry and safety  stakeholders including: representatives from chemical manufacturing  associations, gas pipeline operators, odorant manufacturers, and pipeline  safety groups to discuss both objectives. These interviews with experts  and stakeholders are not generalizable to the entire population of  possible experts and stakeholders. For reporting purposes, we developed  the following series of indefinite quantifiers to describe the 34 total  stakeholder responses from the 14 experts and 20 other industry and  safety stakeholders we interviewed:

6 or less of the 34 total is described as “a few”;

See appendix II for a list of experts and other stakeholders interviewed.

We conducted this performance audit from June 2017 to April 2018 in  accordance with generally accepted government auditing standards.  Those standards require that we plan and perform the audit to obtain  sufficient, appropriate evidence to provide a reasonable basis for our  findings and conclusions based on our audit objectives. We believe that  the evidence obtained provides a reasonable basis for our findings and  conclusions based on our audit objectives.

Roughly two-thirds of domestic energy supplies are transported through  over 2.6 million miles of pipelines throughout the United States. These  pipelines carry hazardous liquids and natural gas from producing wells to  end users (residences and businesses). Natural gas, which is  combustible, accounts for 99.8 percent of all gas distributed in the United  States. Other combustible gases transported by pipeline include  hydrogen, landfill gas, synthetic gas, and propane. Within this nationwide  system, three main types of pipelines serve different purposes and users  (see fig. 1):

Gathering pipelines. The estimated 11,500 miles of onshore gas  gathering pipelines subject to PHMSA regulation collect natural gas  from wells in production areas. These pipelines then typically  transport the gas to processing facilities, which in turn refine it and  send the gas to transmission pipelines. Gathering pipelines range in  diameter from about 2 to 12 inches and operate at pressures that  range from about 5 to 1,400 pounds per square inch (psi). These  pipelines tend to be located in rural areas but can also be located in  urban areas. PHMSA estimates that another 230,000 miles of gas  gathering pipelines are not subject to federal regulation based on their  generally rural location and low operating pressures.

Transmission pipelines. The estimated 298,000 miles of onshore  transmission pipelines carry natural gas, sometimes over hundreds of  miles, to communities and large-volume users (e.g., factories).  Transmission pipelines tend to have the largest diameters and  pressures of any type of pipeline, generally ranging from 12 inches to  42 inches in diameter and operating at higher pressures ranging from  400 to 1,440 psi.

Distribution pipelines. The estimated 2,170,000 miles of natural gas  distribution and service pipelines transport natural gas from  transmission pipelines to residential, commercial, and industrial  customers. These pipelines tend to be smaller, sometimes less than 1  inch in diameter, and operate at lower pressures, from 0.25 to 100 psi.

A specific pipeline only carries one type of gas. These gases may be  colorless and odorless, which is why odorizing them may be necessary to  safely alert people of a leak.

All odorants used in the United States contain sulfur. According to  PHMSA officials, there are nine primary sulfur-based odorants used  domestically for transporting combustible gas, all but one contain  mercaptan—a type of chemical with a distinctive sulfur smell—which is  blended with other chemicals for stability. Pipeline operators select the  odorant blend that works best for their pipeline network. Distribution  pipeline operators add the odorant to their gas, usually at the “city gate”,  or the place where transmission pipelines connect to a distribution  pipeline network. The odorant is transported and stored in a concentrated  liquid form that has a strong smell, is flammable, and is toxic. The odorant  is injected into the gas stream at the “city gate” odorization station and  vaporizes into the gas. In its diluted form, the odorants are nontoxic.

PHMSA, within the Department of Transportation (DOT), administers  DOT’s national regulatory program to ensure the safe transportation of  natural gas by pipeline. PHMSA oversees and enforces pipeline  operators’ compliance with federal odorization requirements for interstate  pipelines, which are primarily transmission pipelines. Most states have  agreements with PHMSA to oversee and enforce pipeline operators’  compliance with federal requirements—including odorization  requirements—for intrastate pipelines, which are primarily distribution  pipelines. These states may also impose safety requirements that are  more stringent than federal requirements. Under the current regulatory  system, most gathering pipelines are not subject to federal safety  requirements, based on their location. Only gathering pipelines close to  populated areas or waterways are currently subject to federal  requirements.

In March 2012, we reported that land use changes have resulted in  development encroaching on existing gathering pipelines and the  increased extraction of oil and natural gas from shale deposits has  resulted in the development of new gathering pipelines, some of which  are larger in diameter and operate at higher pressure than older pipelines.  Therefore, we recommended that PHMSA collect data on gathering  pipelines to help determine whether to expand regulation of these  pipelines. In April, 2016, PHMSA issued the Gas Transmission and  Gathering Notice of Proposed Rulemaking that would: 1) require all gas  gathering pipeline operators to submit operating and accident data to  PHMSA, 2) more clearly define “gathering pipeline” to better identify  pipelines subject to PHMSA’s requirements, and 3) increase the number  of gathering pipeline miles under PHMSA’s jurisdiction. PHMSA  estimates that the new rule would increase the number of gathering  pipeline miles with reporting requirements by 344,000 and the number of  gathering pipeline miles subject to additional safety measures by almost  70,000.

The overall framework for federal gas pipeline regulations—including  odorization requirements—is designed to mitigate risk. All pipelines  regulated by PHMSA are required to meet uniform, minimum safety  standards. Regarding odorization, these minimum standards prescribe  that a combustible gas must be odorized so that at a concentration in air  of one-fifth of the lower explosive limit, the gas is readily detectable by a  person with a normal sense of smell. The proximity of pipelines to  populated areas, where leaks present the greatest risk, determines  whether or not the gas needs to be odorized. Since 1970, PHMSA has  categorized pipelines into four classes based on their proximity to  populated areas to determine the odorization requirements for gas  transported by distribution and transmission pipeline. Class 1 locations  are in rural areas and Class 4 locations are in densely populated areas  (see table 1.). All combustible gases transported by distribution pipelines  are required to be odorized because these pipelines are primarily in  populated areas. Some transmission pipelines in highly populated—Class  3 and 4—areas are also required to be odorized.

In addition, PHMSA has a supplemental risk-based regulatory program  termed “integrity management” for pipelines in “high-consequence areas”  where an incident would have greater consequences for public safety or  the environment. Integrity management has been a part of PHMSA’s risk- based regulatory approach for natural gas transmission pipelines since  2004, and for natural gas distribution pipelines since 2011. The risk- based integrity management programs for natural gas transmission  pipelines require operators to systematically identify and mitigate risks to  pipeline segments located in high-consequence areas. For example, in  these areas operators must monitor their pipelines for signs of corrosion  and repair corroded lines within a specified period of time. High- consequence areas for natural gas pipelines include highly populated or  frequently used areas, such as parks. These areas may overlap with  Class 3 or Class 4 locations. The integrity management program for  distribution pipelines applies to all distribution pipelines due to their  proximity to populated areas.

Officials and Stakeholders Said That Odorizing Gas in Pipelines Improves Public Safety, but Can Impede Some Industrial Processes

Pipeline Gas Odorization Facilitates Early Detection, Particularly in Populated Areas

Almost all officials and stakeholders we interviewed and the state pipeline  safety officials we surveyed told us that the advantage of using sulfur- based odorants to odorize combustible gas transported by pipeline is  public safety. Sulfur-based odorants have a low-odor threshold, so are  easily detected at low concentrations. With a smell similar to that of rotten  eggs, this odor is particularly advantageous when used in distribution  pipelines that are located in areas where people congregate (e.g., homes,  businesses and hospitals). If individuals smell an odorant, they can call  emergency services and alert those nearby of a potential gas leak,  possibly helping to prevent an explosion that could result in the loss of life  and property.

According to federal regulations, all local distribution companies must  conduct outreach to educate the public and others on what to do when  they smell a gas leak. To this end, the 2017 American Gas Association  Odorization Manual (manual) states that some local distribution  companies have gone beyond placing the traditional scratch-and-sniff  insert in customers’ billing statements—to inform them about gas leaks and odor—to implementing “Smell Gas Act Fast!” campaigns. According  to the manual, these campaigns are designed to better educate the public  on the smell and nature of natural gas, along with the need to quickly take  action if the odor is detected. Responding immediately to the smell of  natural gas can help to prevent possible accidents. For example, when  authorities were reportedly called to a Rockville, Maryland home in  November 2017 to investigate an odor from a natural gas leak, authorities  evacuated several nearby homes as a safety precaution in the event of  an explosion, until the source of the leak could be identified and  addressed.

While nearly all stakeholders we interviewed said that public safety was  the key advantage associated with odorizing combustible gases (in  particular, combustible gases transported by distribution pipeline), some  experts expressed differing opinions on the use of handheld electronic  combustible gas detection devices as an alternative to detect gas leaks.  According to one expert, these devices are better suited to detect gas at  levels much lower than an individual’s sense of smell would allow. This  expert also noted that odor does not wake a sleeping individual so a gas  leak could go undetected for hours. However, a second expert noted that  during his experience with pipeline accident investigations over the past  40 years, he was aware of about 10 cases in which deceased individuals  were found after a gas leak accident holding a portable combustible gas  detector because (1) the device may not have indicated the presence of  gas in one location while a nearby location may have been explosive due  to a gas leak; or (2) the user may not have been properly trained on the  instrument’s limitations to identify a safe area. Accordingly, that expert  stated that odorization is the most effective safety method for alerting the  public of a possible gas leak. Additionally, a third expert noted that (1)  electronic detectors can be difficult to place in certain areas and (2)  odorants allow the public to quickly detect gas leaks without acquiring or  maintaining external equipment.

The Primary Disadvantages Officials and Stakeholders Cited Are Odor Removal for Some Industries and False Alarms

The most common disadvantage of sulfur-based odorants cited by  officials and stakeholders we contacted is the need to remove the odorant  for some industrial processes. Officials from both federal safety regulatory  agencies we interviewed (PHMSA and NTSB); approximately half of state  pipeline safety officials surveyed; and about half of the stakeholders  interviewed reported that sulfur-based odorants used in transmission  pipelines can cause an adverse chemical reaction during processing for  some industries. For example, sulfur in natural gas can be detrimental in  the production of electricity, fertilizer, and glass because it interferes with  the catalyst used during production. PHMSA and NTSB officials and  about half of the stakeholders said that before these items are produced,  operators must remove any added (or naturally occurring) sulfur from  their combustible gas, adding another step to production. One expert and  three stakeholders told us that removing the odorant also resulted in  added cost for some operators. However, because most transmission  pipelines are in less populated areas and not odorized, many  manufacturers currently receive unodorized gas from transmission  pipelines and do not need to remove odorant, according to the industry  associations we interviewed.

In addition, some stakeholders warned that accidental spills of  concentrated odorant, using more odorant than needed, or releasing  excessive amounts of odorant during operators’ maintenance activities  can lead to false alarm calls. One pipeline operator told us that an  employee spilled odorant on a glove and the public made several false  alarm calls due to the odorant’s potent smell as the employee drove  through town with the glove on the back of a truck. Officials from PHMSA,  an official from a pipeline safety organization and representatives from  two pipeline industry associations told us that the public could get  accustomed to these types of odorant leaks and begin to ignore them or  have a false sense of security when a real gas leak does occur. For  example, the official from the pipeline safety organization told us that he  has heard of at least one location where odorant leaks frequently  occurred, and the public began to ignore the smell.

Additionally, under certain conditions, sulfur-based odorants can be  hazardous to human health and the environment. A few stakeholders told  us that odorants released in excessive amounts may cause health  concerns. For example, during a presentation before the Pipeline Safety  Trust, a Los Angeles County public health official stated that it appears a  sulfur-based odorant was related to public health complaints made in  2015 after a 4-month long natural gas leak from a natural gas storage  facility in California’s Aliso Canyon. Many of the reported symptoms  matched those made after a 2008 natural gas storage tank leak in  Alabama, which included respiratory problems; eye, nose, and throat  irritation; headache; nausea; and dizziness. While at least one study has  been conducted and another is planned on the long-term effects of sulfur- based odorants on human health, no direct cause and effect relationships  have been established.

Finally, a few stakeholders noted potential environmental hazards  regarding the use of odorants. For example, one stakeholder told us that  odorants can become a hazardous waste depending on the quantity used  and the amount of time the chemical remains in one location prior to use;  one expert and another stakeholder noted that sulfur-based odorants  when spilled may contaminate waterways; and four experts and two  stakeholders warned that when combusted, sulfur-based odorants can  produce acid rain. Also, according to PHMSA officials, these odorants are  both toxic and flammable in their concentrated state. However, none of  the stakeholders provided specific examples of when an odorant caused  environmental damage.

Officials and Stakeholders Had Mixed Views on Need to Modify Odorization Requirements

Many Officials and Stakeholders Agreed That Federal Distribution Pipeline Odorization Regulations Do Not Need to be Modified

General consensus exists among those we spoke with (including federal  regulatory and safety officials, experts identified by the National  Academies, and industry stakeholders) that federal requirements to  odorize all gases in distribution pipelines are sufficient as written and do  not need to be modified. PHMSA and NTSB officials we interviewed and  many commenting stakeholders articulated this view. In addition, state  pipeline officials we surveyed generally did not indicate a need to change  federal regulations for odorizing distribution pipelines. Due to the  proximity of distribution pipelines to areas where people live and work,  officials, experts, and stakeholders we interviewed emphasized the  importance of odorizing gas in distribution pipelines to reduce the safety  risk to the public.

As we have previously reported, the operating characteristics of  distribution pipelines make odorant a key factor in reducing safety risk. In  2012 we reported that distribution pipelines operate at lower pressures,  so pipeline failures are more likely to involve slow leaks rather than  explosive ruptures. Leaking gas can accumulate in confined spaces, or  migrate away from the pipeline until it finds an ignition source and  potentially causes injury, death, and/or property damage. These slow  leaks are difficult to see or hear, so odorants provide a critical warning to  call emergency services and inform those nearby of a potential gas leak  before it ignites.

Many Officials and Stakeholders Agreed That Odorizing Gathering Pipelines Could Be Technically Challenging with Little Added Safety Benefit

Of those we interviewed or surveyed, about half of stakeholders and a  third of state pipeline safety officials did not indicate a need to modify  existing regulations for odorizing gas in gathering pipelines. Further, a  few commenting experts said odorizing those pipelines would be  technically challenging. According to the experts, technological  challenges stem from the fact that gas contains natural sulfur at many of  the wells where gathering pipelines collect the raw gas. The natural sulfur  in the raw gas could counteract the added chemical sulfur odorant,  masking the smell of each and lowering the effectiveness of the odorant.  Further, one stakeholder said that odorizing gathering pipelines would be  logistically difficult and expensive given the number of wells that would  each need an odorization station. For example, according to this  stakeholder, there are roughly 500,000 gas wells nationwide and each  odorizer would cost $2,000 as a capital investment. In addition, this  stakeholder said that any safety benefit of adding odorant would be  limited because most gas wellheads and gathering pipelines are located  in sparsely populated rural areas.

While the majority of stakeholders and state survey respondents did not  see a need to odorize gas in gathering pipelines, a third of the state  safety officials and three other stakeholders said all gathering pipelines  should be odorized for additional safety regardless of any technical  challenge. However, requiring all gathering pipelines to be odorized at  the federal level would have to be consistent with federal pipeline safety  regulations. According to the safety regulations, a risk assessment,  including an assessment of the benefits and costs of proposed regulatory  standards, is required to be considered in any decision on whether to  impose a new safety standard. According to PHMSA officials, they do  not have the data to report on any incidents on gathering pipelines where  odorant may have made a difference. Moreover, PHMSA officials stated  that they do not have the data to formulate an educated opinion or  viewpoint as to the need to odorize gathering pipelines. To address this  lack of data, the Pipeline Safety -Safety of Gas Gathering Pipelines  rulemaking, if approved, will provide PHMSA with more data on gas  gathering pipeline infrastructure and incident data. According to PHMSA  officials, the data collected will inform PHMSA on the best path forward  regarding further regulation of gas gathering pipelines, including the need  for odorization. Officials anticipate publishing the final rule in summer  2019.

Officials’ and Stakeholders’ Views Differed on Need to Odorize Transmission Pipeline Gas

Officials, stakeholders and survey respondents generally disagreed about  the need to odorize all transmission pipelines. Officials from NTSB as well  as about half of the stakeholders we contacted said the current  regulations for odorizing gas in certain transmission pipelines in  populated areas were sufficient. Additionally, NTSB officials said they  were not aware of incidents where odorants in a transmission pipeline  would have alerted the public in time to prevent the incident. These  officials and stakeholders generally said that odorizing gas in  transmission pipelines is not an effective means of reducing the risk of an  incident. For example, one stakeholder said that at the typically high  pressure at which most transmission pipelines operate, even a relatively  small hole in the pipeline would cause a rupture that would excavate the  earth around it so people would hear and see the evidence of the leak.  Some experts also said that odorizing gas in all transmission pipelines  could have increased costs and other challenges for pipeline operators or  gas end users. For example, one expert said that odorizing all gas  transported in the transmission pipeline system would require tens of  thousands of odorization facilities. This expert also said that if gas is  odorized in transmission pipelines, some industries currently receiving  unodorized gas will be affected negatively because they either must incur  the additional processing and cost of removing the odorant or find new  ways to receive gas that is not odorized.

Further, PHMSA officials and representatives from the Interstate Natural  Gas Association of America said that the integrity management program  for transmission pipelines provides more preventative, risk-based safety  management than odorants, which rely on reducing risk through early  detection of a leak that has already occurred. The integrity management  program requires operators to assess the integrity of their pipelines within  high consequence areas—which, by definition, encompass Class 3 and 4  locations—on a regular basis using any of three approved methods: (1)  running an in-line inspection tool, or “smart pig”, through the pipeline to  detect anomalies, such as corrosion, that can cause leaks (2) conducting  a direct assessment using data and direct examination of the pipeline  from aboveground to identify problem areas, or (3) hydrostatically testing  a portion of the pipeline by removing the gas product, replacing it with  water, and increasing the pressure of the water above the maximum  allowable operating pressure of the pipeline to test its integrity. These  inspection methods are designed to detect issues that could cause a gas  leak before the leak occurs. Following the assessments, pipeline  operators are required to prioritize and repair anomalies found during  assessments.

While odorants could be added in addition to integrity management  requirements, PHMSA officials said that integrity management more  effectively helps assure an acceptable level of safety for transmission  pipelines than an odorant could because the risk assessments focus on  the potential causes of leaks and ruptures for these types of pipelines  and, therefore, are more preventative than odorizing. In a September  2006 report, we found that PHMSA’s gas pipeline integrity management  program benefits public safety by incorporating risk-based management  principles into pipeline safety oversight, and in June 2013, we reported  that transmission pipeline operators were conducting periodic  assessments and making repairs to pipelines in high consequence  areas.

Transmission pipeline operators are also required through the integrity  management program to proactively take measures to reduce the risk or  potential impact of an accident. Based on inspections of interstate  transmission operators’ integrity management programs, PHMSA officials  noted that—while transmission pipeline operators could opt to odorize  gas in a transmission pipeline—they are not aware of any operator to  date that has concluded that odorizing transmission pipelines was  necessary to reduce risk. Instead, operators use tools such as electronic  leak detection and remotely-controlled valves to detect potential leaks  and shut down the pipeline if needed.

While the preventative safety practices required under the gas  transmission pipeline integrity management program are designed to  mitigate risk without requiring the use of odorant, officials from two states  and one stakeholder questioned the sufficiency of integrity management  practices. However, as part of the ongoing two rulemakings: the Pipeline  Safety: Safety of Gas Transmission Pipelines, MAOP Reconfirmation,  Expansion of Assessment Requirements and Other Related Amendments  and the Pipeline Safety - Safety of Gas Transmission Pipelines, Repair  Criteria, Integrity Management Improvements, Cathodic Protection,  Management of Change, and Other Related Amendments Rulemaking,  PHMSA also plans to strengthen and expand requirements for the gas  integrity management program for transmission pipelines. For example,  PHMSA plans to expand the requirements for periodic assessments and  subsequent repairs to additional pipeline mileage beyond that located in  high consequence areas. PHMSA plans to publish these rulemaking in  March and June, 2019, respectively. The 2016 PIPES Act includes a  mandate for GAO to review PHMSA’s gas integrity management program  as soon as PHMSA publishes the final rule.

In contrast to the opinions expressed above that transmission pipeline  odorization requirements are sufficient, 31 of 49 state pipeline safety  officials surveyed responded that these requirements are not stringent  enough for safety. Of these respondents, several said that exemptions  that currently apply to some operators with transmission pipelines in  Class 3 and Class 4 locations should not be allowed. There are several  exemptions, determined by the overall class location of the pipeline or  end use of the gas. For example, one class location exemption is that  when at least 50 percent of the length of the pipeline downstream from  the more populated Class 3 or Class 4 location is in a less populated  Class 1 or Class 2 location, the gas does not need to be odorized (see  fig. 2).

Eliminating the current regulatory exemptions for certain transmission  pipelines and requiring operators to odorize all gas transported by  transmission pipeline through Class 3 or Class 4 locations may not be  cost-beneficial under federal regulatory risk assessment principles, which  direct the agency to assess the benefits and costs of changes in  regulatory standards. For example, while four states cited increased  public safety as the reason to remove the existing exemption, PHMSA  and NTSB officials could not identify any incidents where odorants in a  transmission pipeline would have prevented damage. In addition, as  described above, some experts told us that removing the exemptions could have increased costs and other challenges for pipeline operators or  gas end users. PHMSA officials also said that the definition of a high- consequence area under the gas integrity management program  encompasses all Class 3 and Class 4 locations, so the risk-based  preventative measures required under that program apply to the areas  exempt from odorization requirements.

We provided a draft of this product to DOT for review and comment. DOT  provided technical comments that were incorporated, as appropriate.

We are sending copies of this report to the appropriate congressional  committees, the Secretary of the Department of Transportation, and other  interested parties. In addition, the report is available at no charge on the  GAO website at http://www.gao.gov.

If you or your staff have any questions about this report, please contact  me at (202) 512-2834 or FlemingS@gao.gov. Contact points for our  Offices of Congressional Relations and Public Affairs may be found on  the last page of this report. GAO staff who made key contributions to this  report are listed in appendix III.

Appendix I: Advantages and Disadvantages of Non-sulfur Based Odorants

While our report focuses on sulfur-based odorants, which are used in the  United States, we also asked experts and stakeholders about the  advantages and disadvantages of non-sulfur based odorants. According  to a German-based manufacturer of non-sulfur odorants, these odorants  are used in some European countries, including Germany and Austria.  This manufacturer also told us that the German energy industry has  embraced using non-sulfur based odorants, in part, to meet German  emissions regulations, as these odorants do not produce sulfur dioxide  and contribute to acid rain when burned.

Most of the experts and stakeholders that we interviewed were generally  unfamiliar with non-sulfur based odorants. Those with some familiarity  offered the following advantages and disadvantages.

Three experts and stakeholders reported that non-sulfur based odorants: have less adverse impact on the environment; for example, no acid may cost less for some operators because less product may be  needed than sulfur-based odorants; and do not adversely impact some operators’ processes.

Four experts noted that non-sulfur based odorants: have a smell that the American public does not associate with a gas  leak.

Two experts commented that non-sulfur based odorants: may be chemically unstable; and  can react with other compounds.

Two experts noted that non-sulfur based odorants: may have a higher level of toxicity.

Appendix II: Experts and Other Industry and Safety Stakeholders Interviewed by GAO

Appendix III: Contact and Staff Acknowledgements

Susan Fleming, (202) 512-2834 or FlemingS@gao.gov.

In addition to the individual named above, other key contributors to this  report were Sara Vermillion, Assistant Director; Sarah Jones, Analyst in  Charge; Jennifer W. Clayborne; Timothy J. Guinane; David K. Hooper;  Delwen A. Jones; Josh Ormond; Rebecca R. Parkhurst; and Kelly L.  Rubin.

A sulfur-like odor can be added to natural gas to help people detect leaks and prevent explosions. Gas is odorized in certain pipelines according to risk-based federal requirements.

Half of stakeholders and 2/3 of state officials we spoke to said that more transmission pipelines should be odorized. These are the pipelines that run between gas processing plants and more populated areas.

Federal officials and the remaining stakeholders noted that transmission pipelines are pressurized and usually rupture rather than leak, so other required safety practices such as inspections could better address risks.