A recent natural gas leak at the Aliso Canyon Underground Storage Facility in California released 5.4 billion cubic feet of natural gas and caused the temporary relocation of over 2,000 households and two schools. Both the occurrence of the leak, and the length of time it took to stop it, raised concerns about the risks of such facilities and about state regulations to insure their safety. The DOE and PHMSA have since announced an interagency task force to "initiate regulatory actions to help ensure the safety of natural gas storage facilities."

PHMSA has yet to complete key regulatory mandates imposed by the Pipeline Safety Act of 2011, including mandates related to automatic shutoff valves, integrity management expansion, leak detection, and maximum allowable operating pressure. Congress has expressed frustration with the agency's failure to fulfill these mandates. Other issues of concern include the regulation of gathering lines, the effectiveness of PHMSA's safety enforcement, aging gas distribution pipelines, and new methane emissions rules from the Environmental Protection Agency.

To authorize the federal pipeline safety program through FY2019, President Obama signed the SAFE PIPES Act (P.L. 114-183) on June 22, 2016. The act authorizes appropriations for FY2017 slightly higher than in FY2016 with small annual increases thereafter. Among other provisions, the act requires PHMSA to promulgate federal safety standards for underground natural gas storage facilities and would grant PHMSA emergency order authority to address urgent "industry-wide safety conditions" without prior notice. The act also requires PHMSA to report regularly on the progress of outstanding statutory mandates.

Whether ongoing efforts by industry, combined with additional resources for PHMSA and new regulations, will enhance the safety of U.S. pipelines remains to be seen. Pipeline safety necessarily involves many groups: federal and state agencies, pipeline associations, pipeline operators, and local communities. Reviewing how these groups work together to achieve common goals could be an overarching concern for Congress.

Such accidents have generated persistent scrutiny of pipeline regulation and have increased state and community activity related to pipeline safety.

In addition to their vulnerability to accidents, pipelines may also be intentionally damaged by vandals or terrorists. Pipelines may be vulnerable to "cyber-attacks" on supervisory control and data acquisition (SCADA) systems or attacks on electricity grids and communications networks. Although pipeline safety and security are related, pipeline security is under the authority of the Department of Homeland Security and outside the scope of this report.⁹

The NTSB has also made recommendations to PHMSA regarding the definition of a high-consequence area (HCA) in a subsequent West Virginia pipeline accident and has investigated the 2014 accident in New York City. Detailed discussion of the above accident findings and the NTSB's recommendations are publicly available in the NTSB's docket management system.³⁷

As stated earlier, the Pipeline Safety Act (P.L. 112-90) imposed 42 mandates on the agency regarding studies, rules, maps, and other elements of the federal pipeline safety program. While PHMSA has fulfilled many of these mandates, by the agency's own accounting, 16 remain incomplete well beyond the deadlines specified in the act, including several key mandates with potentially large impacts on pipeline operations nationwide.³⁹ The following sections summarize five of the most significant uncompleted mandates, including excerpted statutory language articulating each mandate, its motivation, deadline, and any information provided by PHMSA regarding the mandate's status.

... the Secretary, if appropriate, shall require by regulation 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 on which the Secretary issues the final rule containing such requirement. (§4)

This provision relates to the ability of pipeline operators to quickly stop the uncontrolled flow of a commodity (e.g., crude oil or natural gas) in the event of an accidental pipeline release. Operator delay in shutting down pipeline flow has been an exacerbating factor in a number of recent pipeline accidents, but most prominently in the September 2010 natural gas pipeline release in San Bruno, CA. It took the operator over 90 minutes to stop the flow of natural gas from the pipeline using manual valves. In its subsequent accident report, the NTSB concluded that the damage from the accident could have been reduced if the pipeline operator had installed either automatic shutoff valves (ASVs) or remotely controlled valves (RCVs).⁴⁰ While installing or retrofitting ASVs and RCVs is technically possible on most pipeline systems, cost versus safety benefits has been the subject of debate on this issue.

The statutory deadline for this mandate was January 3, 2014. Prior to passage of the Pipeline Safety Act, in October 2010, PHMSA had already issued an Advance Notice of Proposed Rulemaking (ANPRM) for hazardous liquid transmission pipelines requesting public comments on the use of RCVs. The agency issued a separate ANPRM for gas transmission pipelines in October 2011 requesting public comments on installing ASVs and RCVs. PHMSA held a leak detection and valve workshop in March 2012 and also commissioned an independent valve study from Oak Ridge National Laboratory.⁴¹ PHMSA stated in 2015 it was taking public comments and information from the other sources into consideration as it drafted a Notice of Proposed Rulemaking (NPRM) related to ASV and RCV installation and leak detection.⁴² PHMSA expects to publish its proposed rule on July 27, 2016, with a public comment period ending 60 days thereafter.⁴³ The agency has not set a deadline for issuing a final rule.

... if the report required by subsection (a) finds that it is practicable to establish technically, operationally, and economically feasible standards for the capability of leak detection systems to detect leaks, the Secretary shall issue final regulations that—(A) require operators of hazardous liquid pipeline facilities to use leak detection systems where practicable; and (B) establish technically, operationally, and economically feasible standards for the capability of such systems to detect leaks. (§8(b))

This leak detection provision arises from the failure of existing pipeline safety systems to quickly and effectively identify uncontrolled releases in a number of recent pipeline accidents. PHMSA states that it had been exploring issues involving leak detection for a number of years prior to passage of the Pipeline Safety Act.⁴⁴ Nonetheless, the NTSB accident report for San Bruno "recommends that PHMSA require that all operators of natural gas transmission and distribution pipelines equip their [control] 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.... "⁴⁵

The statutory deadline for this mandate was as soon as practicable after January 3, 2014. The agency has linked its leak detection rulemaking to its valve rulemaking under section 4 of the Pipeline Safety Act. As stated above, PHMSA held a leak detection and valve workshop in March 2012. In December 2012, PHMSA submitted to Congress a mandated report on leak detection systems and gaps in associated industry standards used by hazardous liquid operators.⁴⁶ The acting administrator testified that PHMSA is taking a two-pronged approach to leak detection: (1) the current rulemaking aimed at improving existing requirements based on currently available technology, and (2) funding a research and development project to improve leak detection system design redundancy and accuracy for the future.⁴⁷ The agency's October 2015 NPRM addressed this mandate. PHMSA plans to issue a final rule in the coming months.⁴⁸

... the Secretary of Transportation shall revise regulations ... to establish specific time limits for telephonic or electronic notice of accidents and incidents involving pipeline facilities to the Secretary and the National Response Center.... In revising the regulations, the Secretary, at a minimum, shall—

(1) establish time limits for telephonic or electronic notification of an accident or incident to require such notification at the earliest practicable moment following confirmed discovery of an accident or incident and not later than 1 hour following the time of such confirmed discovery;

(2) review procedures for owners and operators of pipeline facilities and the National Response Center to provide thorough and coordinated notification to all relevant State and local emergency response officials, including 911 emergency call centers, for the jurisdictions in which those pipeline facilities are located in the event of an accident or incident, and revise such procedures as appropriate; and

(3) require such owners and operators to revise their initial telephonic or electronic notice to the Secretary and the National Response Center with an estimate of the amount of the product released, an estimate of the number of fatalities and injuries, if any, and any other information determined appropriate by the Secretary within 48 hours of the accident or incident, to the extent practicable. (§9)

Timely notification of emergency responders is widely understood to be a key factor in minimizing the impacts of an accidental pipeline release. Current regulations require pipeline operators to notify the National Response Center of a pipeline incident "at the earliest practicable moment following discovery."⁴⁹ For decades prior to passage of the Pipeline Safety Act, this regulatory provision has been interpreted by PHMSA and operators to imply reporting within one to two hours of an incident.⁵⁰ With regard to local responders, in its initial investigation of the San Bruno pipeline accident, the NTSB concluded that "emergency responders in communities around the country may not have the information that they need in order to most effectively react to a pipeline leak or rupture."⁵¹ Therefore, timely communication between the National Response Center and local responders is also important.

Congress required these regulatory changes to be implemented by July 3, 2013. In 2013, PHMSA issued an advisory bulletin reaffirming that operators "should" make a telephonic report of a pipeline incident to the National Response Center within two hours of discovering the incident.⁵² The agency's website currently states that it "expects" such two-hour notification.⁵³ PHMSA has also issued advisory bulletins about communication during emergency situations (in 2012) and emergency preparedness communications (in 2010), both of which apply to local emergency response, including 911 call centers. PHMSA published an advanced notice of a proposed rulemaking (ANPRM) with a one-hour reporting requirement on July 10, 2015, but a final rule has not been issued.⁵⁴ The PHMSA Administrator testified in March 2016 that the agency was considering public comments and planning to present a proposed rule to its advisory committee "this spring," but PHMSA has not set a date for issuing the final rule.⁵⁵

... the Secretary, if appropriate, shall by regulation require the use of excess flow valves, or equivalent technology, where economically, technically, and operationally feasible on new or entirely replaced distribution branch services, multifamily facilities, and small commercial facilities. (§22)

In natural gas distribution systems, which connect directly to gas consumers, "excess flow" valves are safety devices which can automatically shut off pipeline flow in the event of a leak, thereby reducing the likelihood or severity of a fire or explosion. They serve a similar function to automatic shutoff valves in larger natural gas transmission pipelines. PHMSA issued new standards requiring the installation of excess flow valves on new gas distribution lines in single-family homes as part of its final rule for natural gas distribution integrity management programs on December 3, 2009.⁵⁶ The Pipeline Safety Act would extend this requirement "if appropriate," to new distribution lines as well as service lines to multi-family residential buildings and small businesses. Although smaller in scale, automatic valves in distribution lines raise cost and safety tradeoffs similar to those for automatic valves in large diameter pipelines.

The statutory mandate for this provision was January 3, 2014. In 2011, PHMSA issued an ANPRM titled "Expanding the Use of Excess Flow Valves in Gas Distribution Systems to Applications Other Than Single-Family Residences."⁵⁷ PHMSA published a NPRM on July 8, 2015.⁵⁸ The agency expects to publish its final rule in January 2017.⁵⁹

(b) REPORTING.—(1) DOCUMENTATION OF CERTAIN PIPELINES.—Not later than 18 months after the date of enactment of this section, each owner or operator of a pipeline facility shall identify and submit to the Secretary documentation relating to each pipeline segment of the owner or operator described in subsection (a)(1) for which the records of the owner or operator are insufficient to confirm the established maximum allowable operating pressure of the segment....

In the case of a transmission line of an owner or operator of a pipeline facility identified under subsection (b)(1), the Secretary shall—(A) require the owner or operator to reconfirm a maximum allowable operating pressure as expeditiously as economically feasible; and (B) determine what actions are appropriate for the pipeline owner or operator to take to maintain safety until a maximum allowable operating pressure is confirmed. (§23)

Inadequate records for older natural gas transmission pipelines have been a long-standing concern among pipeline safety advocates. In its San Bruno investigation, the NTSB found that the pipeline operator's records for the ruptured pipeline—originally constructed in the 1940s—were inaccurate and incomplete, failing to document its original maximum allowable operating pressure (MAOP) and using flawed methods to determine MAOP in later years.⁶⁰ In 2011, as a response to its initial investigation of the San Bruno accident, the NTSB issued urgent new safety recommendations "to address record-keeping problems that could create conditions in which a pipeline is operated at a higher pressure than the pipe was built to withstand."⁶¹ The NTSB has also recommended that all natural gas transmission pipelines be configured to accommodate internal inspection tools ("smart pigs") and that pipelines constructed before 1970 be subjected to hydrostatic pressure tests (filling a pipeline with water under pressure) to verify MAOP. However, experts note that there are different pipeline inspection techniques with overlapping capabilities and different strengths which should be considered in a portfolio of maintenance practices.

The statutory mandate for this provision was July 3, 2013. PHMSA's acting administrator testified in May 2015 that the agency had taken steps involving pipeline operator verification of records, reporting, determination of MAOP, and testing regulations. PHMSA now requires all operators to report pipelines without sufficient MAOP records. According to the agency, this information collection has provided an inventory of pipelines without sufficient records and has helped define the potential impact of any potential new regulations.⁶² In 2012 PHMSA also issued advisory bulletins reminding pipeline operators (gas and liquid) to verify their MAOP records under existing regulations⁶³ and requiring gas pipeline operators to report when they exceed MAOP.⁶⁴ PHMSA has engaged stakeholders in developing a fitness for service concept for pipelines (the "Integrity Verification Process"), including a 2013 public workshop, and has solicited public comments prior to commencing rulemaking.⁶⁵ A proposed rule was submitted to the President's Office of Management and Budget for review on April 27, 2015.⁶⁶ PHMSA issued an NPRM addressing this mandate on March 17, 2016.⁶⁷ The agency has not set a deadline for issuance of its final rule.

In addition to the outstanding mandates of the Pipeline Safety Act, other, long-standing concerns, such as PHMSA inspector staffing, underground natural gas storage safety, and the safety of unregulated pipelines, continue to evolve and receive attention from stakeholders. In the context of its continuing oversight of federal pipeline safety, and in light of findings from recent pipeline accidents, the 114^th Congress may focus on certain key issues as it considers PHMSA's reauthorization.

The U.S. pipeline safety program employs a combination of federal and state staff to implement and enforce federal pipeline safety regulations. To date, PHMSA has relied heavily on state agencies for pipeline inspections, with nearly three-fourths of inspectors being state employees. Some in Congress have criticized inspector staffing at PHMSA as being insufficient to adequately cover pipelines under the agency's jurisdiction, notwithstanding state agency cooperation. In considering PHMSA staff levels, three distinct issues are the overall number of federal inspectors, the agency's historical use of staff funding, and the staffing of pipeline safety inspectors among the states.

In FY2016, PHMSA is funded for 302 full-time equivalent (FTE) employees. As noted earlier, PHMSA actually employed 266 pipeline safety staff as of May 2, 2016, based on the agency's organizational chart, which lists every staff position.⁶⁸ According to PHMSA officials, the agency continues hiring and anticipates employing additional staff in the second half of the fiscal year.⁶⁹ S. 2276 authorizes approximately $150 million in FY2017, rising to approximately $157 million in FY2019.

PHMSA officials have offered a number of reasons for the persistent shortfall in inspector staffing. These reasons include a scarcity of qualified inspector job applicants, delays in the federal hiring process during which applicants accept other job offers, and PHMSA inspector turnover—especially to pipeline companies which often hire away PHMSA inspectors for their corporate safety programs. Because PHMSA pipeline inspectors are extensively trained by the agency (typically for two years before being allowed to operate independently), they are highly valued by pipeline operators seeking to comply with federal safety regulations. The agency has stated that it is challenged by industry recruitment of the same candidates it is recruiting, especially with the rapid development of unconventional oil and gas shales, for which the skill sets PHMSA seeks (primarily engineers) have been in high demand.⁷⁰

To overcome its pipeline inspector hiring challenges, PHMSA states that it has a "robust recruitment and outreach strategy" that includes certain non-competitive hiring authorities (e.g., Veterans Employment Opportunities Act) and the Pathways and Presidential Management Fellows programs. The agency offers recruitment, relocation and retention incentives, and is expanding its use of the student loan repayment program. In addition to posting vacancy announcements on USAJOBS, PHMSA posts job announcements using social media (Twitter and LinkedIn), conducts outreach to professional organizations and veterans groups, and attends career fairs and on-campus hiring events. PHMSA also plans to explore partnerships with engineering schools to help the agency recruit for inspector and enforcement positions.⁷¹

Whether funding for pipeline safety staff under P.L. 114-183 would yield the optimal number of pipeline safety inspectors remains to be seen. However, filling new positions, in addition to filling all previously authorized positions, and retaining employees, may continue to pose practical challenges for the agency. Accordingly, P.L. 114-183 includes a mandatory review of PHMSA's staff resource management, including:

(1) geographic allocation plans, hiring and time-to-hire challenges, and expected retirement rates and recruitment and retention strategies;

(2) an identification and description of any previous periods of macroeconomic and pipeline industry conditions under which the Pipeline and Hazardous Materials Safety Administration has encountered difficulty in filling vacancies, and the degree to which special hiring authorities, including direct hiring authority authorized by the Office of Personnel Management, could have ameliorated such difficulty; and

(3) recommendations to address hiring challenges, training needs, and any other identified staff resource challenges (§9(a)).

The study is to be completed within one year of enactment by the Inspector General of the Department of Transportation.

One specific remedy PHMSA has pursued in its efforts to recruit pipeline inspectors is to seek direct-hire authority (DHA) from the Office of Personnel Management (OPM). This authority can expedite hiring, for example, by eliminating competitive rating and ranking, or not requiring veterans' preference. OPM can grant DHA to federal agencies in cases of critical hiring need or a severe shortage of candidates.⁷³

In its 2013 appropriations report, the House Appropriations Committee stated

The Committee is aware of several challenges PHMSA faces in hiring pipeline safety inspectors. One such challenge is the delay caused by the federal hiring process, which is compounded by other market dynamics. The Committee encourages the Office of Personnel Management to give strong consideration to PHMSA's request for direct-hire authority for its pipeline safety inspection and enforcement personnel. Such authority may enable PHMSA to increase its personnel to authorized levels and thereby demonstrate the need for additional resources.⁷⁴

The same language appears in the committee's 2014 appropriations report. Consistent with the committee's recommendations, PHMSA applied to the OPM for direct-hire authority in April 2015 but was denied. According to PHMSA, the OPM informed agency officials of the denial verbally, but did not provide a formal, written explanation for the denial at the time.⁷⁵ In 2016, the PHMSA administrator reiterated the agency's desire for DHA, stating that it "would complement our recruitment efforts by reducing the agency's time to hire from more than 100 days to less than 30 days."⁷⁶ P.L. 114-183 does not grant PHMSA direct-hire authority, but would allow the agency to apply to the OPM for it upon identification of a period of macroeconomic and pipeline industry conditions creating difficulty in filling pipeline safety job vacancies (§9b). Given the overall employment challenges facing PHMSA, such direct-hire authority could help alleviate understaffing, but may not resolve it.

Because state agencies would continue to account for the majority of U.S. pipeline safety inspectors, even under the President's FY2017 budget request, an important consideration is how the number of state inspectors has been affected by budget constraints faced by many states during the ongoing recovery from the recent U.S. economic recession. Under P.L. 109-468 (§2(c)), PHMSA is authorized to award grants reimbursing state governments for up to 80% of the cost of the staff, personnel, and activities required to support the federal pipeline safety program. According to DOT, these grants have been essential to "enable the states to continue their current programs and hire additional inspectors ... [and] assure that states do not turn over responsibility for distribution pipeline systems to the Federal inspectors," among other reasons.⁷⁷

Notwithstanding federal pipeline safety grants, inspector staffing at state pipeline safety agencies is not assured. During the recent recession, state inspectors were negatively affected by state budget deficits, for example, by being temporarily furloughed without pay.⁷⁸ PHMSA officials in the past have also reportedly cited unfilled positions among state pipeline safety agencies as a risk to state pipeline safety programs.⁷⁹ The possibility that some states may have staffing limitations affecting their roles as agents for the federal pipeline safety program may warrant continued attention from Congress.

Between October 23, 2015, and February 11, 2016, the Aliso Canyon Underground Storage Facility near the Porter Ranch community in Los Angeles County, CA, experienced a massive natural gas leak. The Aliso Canyon facility is a depleted oil field that was converted to a natural gas storage reservoir in the 1970s. It is owned and operated by Southern California Gas Company, an investor-owned utility in California regulated by the California Public Utilities Commission (CPUC). The leak was reportedly caused by damage to a well casing approximately 500 feet underground.⁸⁰ The incident released an estimated 5.4 billion cubic feet of natural gas into the atmosphere—equivalent to 94,000 metric tons of methane, a potent greenhouse gas.⁸¹ The risk to safety from the fugitive methane and the presence of odorants and other chemicals in the gas led to the temporary relocation of over 2,000 households and two schools.⁸² Both the occurrence of the leak, and the length of time it took to stop it, raised serious concerns in Congress about the risks of such facilities and about regulations to insure their safe operation.⁸³

As a result of the Aliso Canyon leak, California has adopted safety regulations for all underground natural gas storage facilities in the state under an emergency rulemaking process.⁸⁶ President Obama also reportedly committed to direct PHMSA to promulgate safety standards under the agency's existing statutory authority.⁸⁷ On April 1, 2016, the Department of Energy and PHMSA jointly announced a new Interagency Task Force on Natural Gas Storage Safety. According to the announcement PHMSA will "initiate regulatory actions to help ensure the safety of natural gas storage facilities across the country, which may include requiring operators to follow some or all of the industry consensus standards recommended by PHMSA's recent safety bulletin."⁸⁸ PHMSA also is currently considering adopting the voluntary provisions of the recommended practices "in a manner that would make them mandatory, except that operators would be permitted to deviate from the [recommended practices] if they provide justification."⁸⁹ PHMSA expects to publish an Interim Final Rule by November 25, 2016.⁹⁰ Notwithstanding the above actions by the Obama Administration, P.L. 114-183 requires PHMSA to promulgate minimum federal safety standards for underground natural gas storage facilities nationwide within two years of enactment (§16). The act would also mandate the formation of a federal inter-agency task force to assess and report on (1) the cause of and response to the Aliso Canyon leak and (2) federal efforts to ensure the safety of underground gas storage facilities (§31).

The Emergency Powers provisions of Section 303 of the Clean Air Act, codified at 42 U.S.C. 7603, authorizes the Environmental Protection Agency (EPA) to bring suit, issue orders, or take other action as necessary—in consultation with appropriate state and local authorities—"upon receipt of evidence that a pollution source ... is presenting an imminent and substantial endangerment to public health or welfare, or the environment." Additional enforcement authorities to respond to an actual or threatened accidental release of a regulated substance from a stationary source are provided under Section 112(r)(9) of the Clean Air Act, codified at 42 U.S.C. 7412. Herein, methane is designated as a regulated flammable substance. The EPA Administrator reportedly has stated an intent for the agency to "do more" to curb methane emissions from existing sources in the oil and gas industry.⁹¹ On May 12, 2016, the EPA issued a final rule setting new source performance standards for the sector in the summer.⁹² However, the rules do not cover the Aliso Canyon facility, because, among other reasons, (1) the standards apply to new and modified sources of emissions, not existing ones, and (2) the standards do not list underground storage facilities as a covered source category.

As Congress continues its oversight of underground natural gas storage safety, it may examine any regulatory schemes for storage that emerge either from new legislation or under existing statutory authorities. As part of this oversight, Congress may focus on the relationship between PHMSA, the EPA, and state agencies which may play cooperative roles in implementing a new federal program to ensure underground natural gas storage safety.

Apart from their levels of inspector staffing, state pipeline safety programs have come under recent scrutiny regarding their overall effectiveness. In the wake of the San Bruno pipeline accident, the California state pipeline safety program—which had regulatory responsibility for the pipeline that ruptured—was criticized by the NTSB for its failure to detect the pipeline's problems. The NTSB was also critical of PHMSA's oversight because the agency had not "incorporated the use of effective and meaningful metrics as part of its guidance for performance-based management" of state pipeline safety programs.⁹³ A 2014 investigation by the DOT Office of Inspector General (IG) assessed the effectiveness of PHMSA's state program oversight as recommended by the NTSB. The IG report stated

PHMSA's oversight of State pipeline safety programs is not sufficient to ensure States comply with program evaluation requirements and properly use suspension grant funds. Lapses in oversight have resulted in undisclosed safety weaknesses in State programs.⁹⁴

The IG report recommended that PHMSA "take actions to further refine its policies and procedures for managing the program, including its guidelines to the States and improve its oversight to ensure States fulfill their role in pipeline safety."⁹⁵ The report made seven specific programmatic recommendations to achieve these goals. In its response to a draft version of the IG report, PHMSA officials concurred or partially concurred with all of the IG reports' recommendations, describing actions it had taken to address the IG's concerns.⁹⁶ The IG report therefore considered all but two of its recommendations resolved, but urged PHMSA to reconsider and clarify its response to the remaining two recommendations. These recommendations pertained to PHMSA's staffing formula and its annual evaluations of inspection procedures among the states.⁹⁷ How PHMSA has implemented changes to its evaluation of state agents and the performance of those state pipeline safety agencies may be an oversight issue for Congress.

The adequacy of PHMSA's enforcement strategy has been an ongoing focus of congressional interest.⁹⁸ Provisions in P.L. 107-355 put added scrutiny on the effectiveness of the agency's enforcement strategy and assessment of civil penalties (§8). In April 2006, PHMSA officials testified before Congress that the agency had institutionalized a "tough-but-fair" approach to enforcement, "imposing and collecting larger penalties, while guiding pipeline operators to enhance higher performance."⁹⁹ According to the agency, $4.6 million in proposed civil penalties in 2005 was three times greater than penalties proposed in 2003, the first year higher penalties could be imposed under P.L. 107-355 (§8(a)).¹⁰⁰ P.L. 112-90 increased the maximum civil penalty from $1.0 million to $2.0 million for a related series of major consequence violations, such as those causing serious injuries, deaths, or environmental harm (§2(a)).

Although PHMSA's imposition of pipeline safety penalties increased quickly after P.L. 107-355 was enacted, and despite the higher penalty ceiling under P.L. 112-90, the role of federal penalties in promoting greater operator compliance with pipeline safety regulations is not always clear. To understand the potential influence of penalties on operators, it can be helpful to put PHMSA fines in the context of the overall costs to operators of a pipeline release.

Pipeline companies, seeking to generate financial returns for their owners, are motivated to operate their pipelines safely (and securely) for a range of financial reasons. While these financial considerations certainly include possible PHMSA penalties, the costs of a pipeline accident may also include fines for violations of environmental laws (federal and state), the costs of spill response and remediation, penalties from civil litigation, the value of lost product, costs for pipeline repairs and modifications (e.g., to resolve federal regulatory interventions), and other costs. Depending upon the severity of a pipeline release, these other costs may far exceed pipeline safety fines, as illustrated by the following examples. Therefore, it is not clear how large an effect increasing PHMSA's authorized fines, alone, might have on operator compliance.

• Kinder Morgan. In April 2006 Kinder Morgan Energy Partners entered into a consent agreement with PHMSA to resolve a corrective action order stemming from three hazardous liquid spills in 2004 and 2005 from the company's Pacific Operations pipeline unit.¹⁰¹ According to the company, the agreement would require Kinder Morgan to spend approximately $26 million on additional integrity management activities, among other requirements.¹⁰² Under a 2007 settlement agreement with the U.S. Justice Department and the State of California, Kinder Morgan also agreed to pay approximately $3.8 million in civil penalties for violations of environmental laws and approximately $1.5 million related to response and remediation associated with these spills. The spills collectively released approximately 200,000 gallons of diesel fuel, jet fuel, and gasoline.¹⁰³ This volume of fuel would have a product value on the order of $0.5 million based on typical wholesale market prices at the time of the spills.
• Plains All American. In 2010, Plains All American Pipeline agreed to spend approximately $41 million to upgrade 10,420 miles of U.S. oil pipeline to resolve Clean Water Act (CWA) violations for 10 crude oil spills in Texas, Louisiana, Oklahoma, and Kansas from 2004 through 2007. Among these upgrades, the company agreed to spend at least $6 million on equipment and materials for internal corrosion control and surveys on at least 2,400 miles of pipeline. The company was required to pay a $3.25 million civil penalty associated with the CWA violations.¹⁰⁴
• Enbridge. Enbridge Energy Partners estimated expenses exceeding $1.2 billion to clean up oil spilled on its Lakehead pipeline system in 2010 in Marshall, MI.¹⁰⁵ The pipeline operator also reported $16 million in lost revenue from pipeline shipments it could not redirect to other lines while the Lakehead system was out of service.¹⁰⁶ The full impact of these expenditures on the company's business is unclear, however. Enbridge stated in a quarterly report that "a majority of the costs" related to its oil spill in Marshall were covered by insurance, but that the company had exceeded the aggregate limit of $650 million for pollution liability under its insurance policy.¹⁰⁷
• Olympic Pipe Line. After the 1999 Bellingham, WA, pipeline accident, Olympic Pipe Line Company and associated defendants reportedly agreed to pay a $75 million settlement to the families of two children killed in the accident.¹⁰⁸
• El Paso. In 2002, El Paso Corporation settled wrongful death and personal injury lawsuits stemming from the 2000 natural gas pipeline explosion near Carlsbad, NM, which killed 12 campers.¹⁰⁹ Although the terms of those settlements were not disclosed, two additional lawsuits sought a total of $171 million in damages.¹¹⁰ However, El Paso's June 2003 quarterly financial report stated that "our costs and legal exposure ... will be fully covered by insurance."¹¹¹
• Pacific Gas and Electric Company (PG&E). On April 9, 2015, the California Public Utility Commission imposed on PG&E a fine, along with other penalties and remedies, totaling $1.6 billion stemming from the San Bruno pipeline accident.¹¹² According to media reports, the company had previously signed settlements for $70 million with the city of San Bruno and over $500 million with victims' families because of the accident.¹¹³

The threat of safety enforcement penalties is often considered one of the primary tools available to pipeline safety regulators to ensure operator compliance with safety requirements. However, as the examples above suggest, pipeline safety fines on the order of $2.0 million for major violations, could still account for only a limited share of the financial impact of future pipeline releases. On the other hand, the authority of PHMSA to influence pipeline operations directly—for example, through corrective action orders or shutdown orders in the event of a pipeline failure—can have a large financial impact on a pipeline operator in terms of capital expenditures or lost revenues. Indeed, some have suggested that this operational authority is the most influential component of PHMSA's pipeline safety enforcement strategy.

As discussed earlier, PHMSA has authority to issue corrective action orders involving an individual pipeline operator or system in the event of an accident or safety violation. In recent testimony before Congress, the PHMSA Administrator advocated for emergency order authority as a "comprehensive enforcement tool to address time-sensitive, industry-wide safety conditions."¹¹⁴ Such an emergency order could be issued without prior notice and would apply to all operators and/or pipeline systems facing a common safety concern. Such authority is currently granted to the Federal Railroad Administration, another agency within DOT, where an unsafe condition or practice "causes an emergency situation involving a hazard of death, personal injury, or significant harm to the environment'' (49 U.S.C. 20104).

Outside advocates of emergency order authority for PHMSA have cited the San Bruno pipeline accident as a case where such authority could have been invoked to address safety concerns affecting "potentially a significant portion of the entire industry" which may not have been following necessary safety procedures.¹¹⁵ In this case, PHMSA had authority only to issue its 2012 industry-wide advisory bulletins regarding MAOP records and reporting. Pipeline operators reportedly have expressed concerns about emergency order authority for PHMSA because such authority could, in their view, deprive pipeline operators of due process protections.¹¹⁶ P.L. 114-183 (§16) grants PHMSA emergency order authority "only to the extent necessary to abate the imminent hazard." Upon a petition from an affected pipeline operator, such orders would be subject to initial review by the Secretary of Transportation and, if necessary, subsequent review in a federal district court on an expedited basis.

Recent expansion of U.S. natural gas resources extracted from unconventional sources, primarily shale, has resulted in an unprecedented expansion of U.S. natural gas production. This rapid growth of natural gas production is driving massive infrastructure investments by the U.S. gas industry. Such infrastructure includes new roads to access gas fields, well sites, drilling equipment, gathering pipelines to collect produced gas from the wells, processing facilities to separate the natural gas from other products, transmission pipelines to transport the gas long distances, and natural gas storage facilities. Intrastate gas gathering pipelines may account for a substantial share of these new investments. A 2014 INGAA Foundation study estimated that around 14,000 miles of new gas gathering lines would be constructed each year, on average, through 2035.¹¹⁷

Gathering pipelines in conventional natural gas production are typically smaller than interstate transmission pipelines—usually 20 inches or less in diameter. Lines of this size were expected to account for 45% of planned gas pipeline mileage in the United States in 2013.¹¹⁸ However, due to differences in extraction techniques, gathering lines in some shale gas production areas exceed 20 inches in diameter and operate at higher pressure. Adding these larger gathering lines to the planned mileage above suggests that gathering lines overall actually may account for well above 50% of new pipeline mileage nationwide during the shale gas expansion.

The construction of shale gas gathering lines has raised safety concerns among federal officials because they may present a greater risk than older gathering lines due to their greater size and pressure. However, as noted earlier in this report, the vast majority of gas gathering lines—over 220,000 miles, mostly in rural areas—are excluded from federal pipeline safety regulations. As a PHMSA briefing paper stated in 2011, "the framework for regulating gas gathering lines may no longer be appropriate" because the physical characteristics of new shale gas gathering lines were "far exceeding the historical operating parameters of such lines."¹¹⁹ The PHMSA website also states

The lines being put into service in the various shale plays like Marcellus, Utica, Barnett and Bakken are generally of much larger diameter and operating at higher pressure than traditional rural gas gathering lines, increasing the concern for safety of the environment and people near operations.¹²⁰

In a 2014 report, the Government Accountability Office (GAO) similarly concluded that recent increases in the size and pressure of shale gas gathering lines "raises safety concerns because they could affect a greater area in the event of an incident."¹²¹ Federally unregulated shale gas gathering lines have also become an increasing concern among local governments and the general public in regions with heavy shale gas development.¹²² The GAO report recommended that PHMSA move forward with new regulations to address the safety risks of larger-diameter, higher-pressure gathering lines, including emergency response planning requirements that currently do not apply.¹²³

In 2011, PHMSA published in the Federal Register an ANPRM to begin examining, among other things, whether new regulations are needed to govern the safety of natural gas gathering lines—with specific reference to shale gas lines.¹²⁴ Accordingly, PHMSA accepted written comments on potential rural gathering line regulations (through January 20, 2012). Among other comments, community stakeholders argued that new safety regulations are needed to take account of increased gathering line size and pressure. Some pipeline operators countered that gathering lines constructed in rural areas pose a minimal public risk, regardless of size or pressure, and that proximity to population—which already determines the regulatory status of a gathering line—should be the primary consideration. They further argued that the risk posed by any specific rural gathering line can be reclassified under current regulations should there be future encroachment of residential development on historically rural tracts where the pipelines had been constructed. Some gas producers are particularly concerned that increased safety costs could cause producers to cease producing from marginally profitable wells.

On March 17, 2016, PHMSA issued an NPRM which, among other provisions, would modify the regulation of onshore natural gas gathering lines. The proposed rules would repeal the existing reporting exemption for gas gathering lines and revise the definition of "gathering lines." The proposal would also extend to certain gathering lines with a diameter of eight inches or greater rules related to damage prevention, corrosion control, public education, maximum allowable operating pressure limits, line markers, and emergency planning.¹²⁵

As the growth in shale gas gathering lines proceeds, related safety issues may remain a policy consideration for Congress. In particular, imposing and enforcing new safety regulations on thousands of miles of previously unregulated pipeline could require more funding for PHMSA and state pipeline safety agencies. In addition, because the safety impacts of gathering pipeline expansion are concentrated in areas of the country where shale gas is produced, balancing safety risks in these areas against the economic benefits may be an issue for Congress.

As discussed earlier in this report, PHMSA has yet to complete a number of key mandates imposed by the Pipeline Safety Act. Some Members of Congress and other stakeholders have expressed frustration with the agency's failure to fulfill these mandates, in part because this failure delays important new safety regulations and in part because it does not allow Congress to evaluate the effectiveness of all the provisions in the Pipeline Safety Act as it considers PHMSA's reauthorization and new pipeline-related proposals.¹²⁶ PHMSA officials have testified that the delays do not reflect a lack of commitment but rather the complexity of the issues involved, the agency's rulemaking process, and limited staff resources.¹²⁷ P.L. 114-183 requires PHMSA to report regularly on outstanding statutory mandates (§3).

In addition to the items mentioned above, Congress may consider several issues related to the federal pipeline safety program.

As noted earlier, on May 12, 2016, the Environmental Protection Agency (EPA) issued new rules for reducing emissions of methane and volatile organic compounds (VOCs) from within the oil and natural gas industries.¹²⁸ These rules include sources of emissions from oil and gas pipelines. Although the EPA's objectives may be primarily directed at reducing greenhouse gas emissions, any regulation of uncontrolled methane or VOC releases from pipelines would likely have safety implications as well. These implications could affect both the pipeline operations and the costs to pipeline companies of fugitive emissions controls. The latter could be significant, as suggested by FERC and other stakeholders.¹²⁹ As implementation of EPA's new rules begins, Congress may seek to understand the implications of compliance on pipeline safety and any issues that may arise from imposing new EPA operational regulations on pipeline systems already regulated by PHMSA.

According to the American Gas Association and other stakeholders, antiquated cast iron pipes in natural gas distribution systems, many over 50 years old, "have long been recognized as warranting attention in terms of management, replacement and/or reconditioning."¹³⁰ Old distribution pipes have also been identified as a significant source of methane leakage, which poses safety risks and contributes to U.S. greenhouse gas emissions.¹³¹ In April 2015, Secretary of Energy Moniz reportedly stated that safety and environmental risks from old, leaky distribution lines were "a big issue."¹³² Natural gas distribution system operators all have ongoing programs for the replacement of antiquated pipes in their systems, although some are constrained by state regulators who are reluctant to approve significant rate increases to pay for these upgrades. According to the Department of Energy, the total cost of replacing cast iron and bare steel distribution pipes is approximately $270 billion.¹³³ Practical barriers, such as urban excavation and disruption of gas supplies, also limit annual replacement. Although the federal role in natural gas distribution systems is limited, because they are under state jurisdiction, there have been proposals in Congress and in the QER to provide federal support for the management and replacement of old cast iron pipe.¹³⁴ The Pipeline Safety Act mandated a survey (with follow-up every two years thereafter) of pipeline operator progress in adopting and implementing plans for the management and replacement of cast iron pipes (§7(a)). Congress may wish to examine the industry's progress in addressing the safety of antiquated distribution lines and opportunities for federal support of those efforts.

Some stakeholders have argued that public perceptions of improved pipeline safety and control are the highest perceived benefit of remotely controlled or automatic valves.¹³⁵ Although the value of these perceptions is hard to quantify (and, therefore, not typically reflected in cost-effectiveness studies), the importance of public perception and community acceptance of pipeline infrastructure has long been a significant consideration in pipeline design, expansion, and regulation. In 2001, a representative of the National Association of Regulatory Utility Commissioners testified before Congress that "the main impediment to siting energy infrastructure is the great difficulty getting public acceptance for needed facilities."¹³⁶ Likewise, the National Commission on Energy Policy stated in its 2006 report that energy facility siting is "a major cross-cutting challenge for U.S. energy policy," largely because of public opposition to new energy projects and other major infrastructure.¹³⁷

One result of public concern about pipeline safety has been to prevent new pipeline siting in certain localities, and to increase pipeline development time and costs in others. In a 2006 report, for example, the Energy Information Administration (EIA) stated that "several major projects in the Northeast, although approved by FERC, have been held up because of public opposition or non-FERC regulatory interventions."¹³⁸ In the specific case of the Millennium Pipeline, proposed in 1997 to transport Canadian natural gas to metropolitan New York, developers did not receive final construction approval for nine years, largely because of community resistance to the pipeline route.¹³⁹ Numerous other proposed pipelines, especially in more densely-populated areas such as New England, have faced similar public acceptance barriers. Controversy surrounding the proposed Keystone XL Pipeline project, the Algonquin Incremental Market (AIM) project, and the Constitution Pipeline are three recent examples of how the development of major pipeline projects may be influenced by public opinion. Even where there is federal siting authority, as is the case for interstate natural gas pipelines, community stakeholders retain many statutory and regulatory avenues to affect energy infrastructure decisions. Consequently, the public perception value of changes to safety regulation may need to be accounted for, especially with respect to its implications for general pipeline development and operations.

Both government and industry have taken numerous steps to improve pipeline safety over the last 10 years, but major pipeline incidents since 2010 suggest that there continues to be opportunity for improvement. The NTSB identified improvement of federal pipeline safety oversight as a "top ten" priority for 2013. The leading pipeline industry associations have concurred. The American Gas Association states that "its members are dedicated to the continued enhancement of pipeline safety."¹⁴⁰ The Association of Oil Pipe Lines likewise has stated that "the oil and natural gas industry is committed to achieving zero incidents throughout our operations."¹⁴¹ Whether the ongoing efforts by industry, combined with additional oversight by federal agencies, will further enhance the safety of U.S. pipelines remains to be seen.

As Congress continues its oversight of the federal pipeline safety program, specific issues of interest may be the adequacy of PHMSA resources and staffing, safety of natural gas storage facilities, the use of emergency order authority, and the effectiveness of the agency's overall enforcement activities. An important focus may be the practical effects of the many changes being made to particular aspects of PHMSA's pipeline safety regulations. In addition to these specific issues, Congress may assess how the various elements of U.S. pipeline safety activity fit together in the nation's overall strategy to protect the public and the environment. Pipeline safety necessarily involves many groups: federal agencies, pipeline associations, large and small pipeline operators, and local communities. Reviewing how these groups work together to achieve common goals could be an overarching concern for Congress.

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