March 2017, Vol. 244, No. 3



By Stephen Barlas, Washington Correspondent

PHMSA Makes Some Positive Changes in Final Safety Rule

The Pipelines and Hazardous Materials Safety Administration (PHMSA) made several changes in pipeline safety laws in a final rule covering several provisions in the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011.

Key provisions dealt with the timeframe for notification of accidents or incidents and new fees companies would pay PHMSA for its design review work on projects totaling over $2.5 billion or which use new or novel technologies. PHMSA made some changes in the final rule in response to industry concerns but in some cases ignored industry entreaties. The new requirements are effective March 24.

A spokeswoman for the Interstate Natural Gas Association of America (INGAA) said the group is very supportive of this rulemaking. “There may be small things that we wished were different, but we believe it’s a good rule that incorporates a lot of important safety improvements.”

PHMSA delayed finalizing a controversial expansion of the operator qualification (OQ) requirements authorized by Congress in the 2011 law. The agency said it will publish a broader final rule including construction and emergency response tasks in the OQ requirements “in the near future.” INGAA supported the expansion in theory but balked at the costs, arguing they needed to be commensurate with the anticipated benefits.

“We appreciate PHMSA is taking additional time to consider feedback on its proposed changes to Subpart N – Qualification of Pipeline Personnel, which has the potential to significantly impact pipeline operations and construction,” said C.J. Osman, INGAA’s pipeline safety director.

On notification, PHMSA essentially followed the language of the 2011 act limiting the timeframe in which the operator must electronically or telephonically report notice of an accident or incident to within one hour of confirmed discovery of the event. The pushback here concerned PHMSA’s use of the words “confirmed discovery,” and INGAA’s argument that only significant events be reported within one hour.

The agency defined “confirmed discovery” as there being “sufficient information to determine that a reportable event may have occurred even if an evaluation has not been completed.” The use of the modifier “may have” was criticized because it could be viewed as casting doubt on whether a “confirmed discovery” had been made. PHMSA did revise the definition of confirmed discovery to mean “when it can be reasonably determined, based on information available to the operator at the time a reportable event has occurred, even if only based on a preliminary evaluation.” But there was no allusion to significant events.

A second element in the notification requirement is that within 48 hours after the confirmed discovery of an incident an operator must revise or confirm its initial telephonic notice with more information. INGAA unsuccessfully pressed PHMSA to eliminate the 48-hour notification, saying the National Response Center (NRC), to which both the one-hour and 48-hour reports are to be made, does not have the means to accept supplemental reports. That request also fell on deaf ears.

However, in sticking with the 48-hour notification requirement, PHMSA also rebuffed the National Transportation Safety Board (NTSB), which complained the two-day respite for a follow-up report allowed pipelines to “provide incomplete information initially” in the one-hour report, knowing they could be more accurate in the 48-hour report. This would delay receipt of information by NTSB or other responding agencies that is needed to decide whether to mobilize a response.

NTSB suggested the second notification requirement would be significantly improved if PHMSA established a follow-up reporting requirement triggered only “when the pipeline operator has confirmed that previously reported information has significantly changed.” PHMSA declined to follow NTSB’s advice.

There was much industry concern around PHMSA’s proposed structure for design review fees. One of the hot spots was the 2011 law’s application of these new design review fees when “new and novel technologies” were being deployed. INGAA said the definition was “overbroad and far exceeds the intent of Congress’s authorization.” The American Gas Association (AGA) also criticized the language in the proposed rule.

In response, PHMSA tacked “new construction” to the definition, which now reads “New and novel technologies means any products, designs, materials, testing, construction, inspection, or operational procedures that are not addressed in 49 CFR Parts 192, 193 or 195, due to technology or design advances and innovation for new construction. Technologies that are addressed in consensus standards that are incorporated by reference into Parts 192, 193, and 195 are not ‘new or novel technologies.’” The second sentence in that definition responds to requests from some pipelines to add it.

Christina Sames, vice president, Operations and Engineering, AGA, said the final definition tracks with the recommendation of a PHMSA advisory committee, and pretty much parallels the AGA’s suggested definition. She said AGA is generally happy with the entire final rule, although disappointed with one provision – farm taps. PHMSA revised the regulations to exclude farm taps from distribution integrity management programs (DIMPs) and moved them to simple prescriptive inspection.

“We believe that including farm taps under DIMP is a more holistic risk-based approach, but we understood that transmission operators of farm taps might not want to create a DIMP program simply for farm taps so we were not opposed to PHMSA allowing operators to choose between including them in DIMP or simply inspecting periodically,” she said.

API Unhappy with Liquids Rule 

In its rush to complete rules prior to the Trump administration taking office, PHMSA also finalized a new safety rule that affects onshore hazardous liquid pipelines. The rule strengthens the standards that determine how operators repair aging and high-risk infrastructure, increases the quality and frequency of tests that assess the condition of pipelines, and extends leak detection requirements to onshore, non-HCA transmission hazardous liquid pipelines.

“We are concerned that this rule has the potential to decrease pipeline safety rather than improve it,” said Robin Rorick, director of the American Petroleum Institute (API) Midstream Group. “We appreciate PHMSA taking into account our comments during the rulemaking process, and while this rule is an improvement over previous versions, the agency’s ‘one size fits all’ approach in portions of the final pipeline rule creates situations where industry will be forced to redirect its attention away from areas that present higher risks to those that are lower in risk.”

The rule includes an increased focus on a data and risk-informed approach to pipeline safety by requiring operators to integrate available data, including operating environment, pipeline condition, and known manufacturing and construction defects. The rule requires operators to have a system for detecting leaks and to establish a timeline for inspecting affected pipelines following an extreme weather event or natural disaster. The inspections will allow operators to quickly identify damage to pipelines and make appropriate fixes.

The rule also requires operators to annually evaluate the protective measures they are already required to implement on pipeline segments that operate in high-consequence areas (HCA) and implement additional measures as necessary. The rule sets a deadline for operators to use internal inspection tools where possible for any new and replaced pipeline that could affect an HCA. The rule improves the quality and frequency of tests used to assess threats and condition of pipelines.

The rule updates repair criteria under PHMSA’s risk-based management framework by expanding the list of conditions that require immediate repair.


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