This week’s Pipeliners Podcast episode features Keith Coyle of Babst Calland returning to the podcast to report his takeaways from the recent GPAC/LPAC committee meetings on the proposed PHMSA rulemaking, Valve Installation and Minimum Rupture Detection Standards.

In this episode hosted by Russel Treat, you will learn about the impetus behind this particular rulemaking, the 2011 Reauthorization of the Pipeline Safety Act and how it has impacted the pipeline industry, the applicability of rupture mitigation valve requirements to gathering lines, and how the November election season could affect rulemaking.

PHMSA Valve & Rupture Rule: Show Notes, Links, and Insider Terms

• Keith Coyle is a shareholder and attorney with the Babst Calland law firm. Mr. Coyle is a member of the firm’s Washington, D.C. office and a shareholder in the Energy and Natural Resources, Environmental and Transportation Safety groups and Pipeline and HazMat Safety practice. [Connect with Mr. Coyle on LinkedIn]
  • Babst Calland is the current underwriting sponsor of the Pipeliners Podcast.
• PHMSA (Pipeline and Hazardous Materials Safety Administration) is responsible for providing pipeline safety oversight through regulatory rulemaking, NTSB recommendations, and other important functions to protect people and the environment through the safe transportation of energy and other hazardous materials.
  • Gas Pipeline Advisory Committee (GPAC) reviews PHMSA’s proposed regulatory initiatives to assure the technical feasibility, reasonableness, cost-effectiveness, and practicability of each proposal. The committee also evaluates the cost-benefit analysis and risk assessment information of the proposals.
  • Liquid Pipeline Advisory Committee (LPAC) reviews PHMSA’s proposed regulatory initiatives to assure the technical feasibility, reasonableness, cost-effectiveness, and practicability of each proposal. The committee also evaluates the cost-benefit analysis and risk assessment information of the proposals.
• The Valve & Rupture Rule (officially Valve Installation and Minimum Rupture Detection Standards) is a proposed rule that PHMSA published to the federal registry in February 2020. PHMSA is proposing to revise the Pipeline Safety Regulations applicable to newly constructed and entirely replaced onshore natural gas transmission and hazardous liquid pipelines to mitigate ruptures. Additionally, PHMSA is revising the regulations regarding rupture detection to shorten pipeline segment isolation times. These proposals address congressional mandates, incorporate recommendations from the National Transportation Safety Board, and are necessary to reduce the consequences of large-volume, uncontrolled releases of natural gas and hazardous liquid pipeline ruptures.
• The Marshall Incident refers to the Enbridge Incorporated Hazardous Liquid Rupture and Release incident, which occurred on July 25, 2010, in Marshall, Michigan. [Read the full NTSB Accident Report]
• The San Bruno or PG&E Incident in September 2010 refers to a ruptured pipeline operated by the Pacific Gas & Electric Company. The rupture created a crater near San Bruno, California, caused an explosion after natural gas was released and ignited, and resulted in fires causing loss to life and property. [Read the full NTSB Accident Report.]
• NTSB (National Transportation Safety Board) is a U.S. government agency responsible for the safe transportation through Aviation, Highway, Marine, Railroad, and Pipeline. 
• 2011 Reauthorization of the Pipeline Safety Act was designed to examine and improve the state of pipeline safety regulation. [Access the full text of the Act.]
• The Oak Ridge National Laboratory Study assessed the effectiveness of block valve closure swiftness in mitigating the consequences of natural gas and hazardous liquid pipeline releases on public and environmental safety. [Read the full report.]
• MAOP (maximum allowable operating pressure) was included in a bulletin issued by PHSMA informing owners and operators of gas transmission pipelines that if the pipeline pressure exceeds MAOP plus the build-up allowed for operation of pressure-limiting or control devices, the owner or operator must report the exceedance to PHMSA on or before the fifth day following the date on which the exceedance occurs. If the pipeline is subject to the regulatory authority of one of the PHMSA State Pipeline Safety Partners, the exceedance must also be reported to the applicable state agency.
• Gathering Lines are pipelines generally used to transport gas and hazardous liquids from production facilities (wells) to central collection points. PHMSA regulations apply to gathering lines that meet certain criteria. [Gathering Pipelines FAQs | PHMSA (dot.gov).]
• Valves are used to control the flow of product moving through a pipeline and support the stop/start function.
  • In the Valve & Rupture Rule, PHMSA is proposing to require the installation of automatic shutoff valves, remote-control valves, or equivalent technology, on all newly constructed or entirely replaced natural gas transmission and hazardous liquid pipelines that have nominal diameters of 6 inches or greater.
  • For transmission line valves, PHMSA noted in the Valve & Rupture Rule that all onshore transmission line segments with diameters greater than or equal to 6 inches that are constructed or entirely replaced after February 2021 must have automatic shutoff valves, remote-control valves, or equivalent technology installed at intervals meeting the appropriate valve spacing requirements.
    • ASV (Automatic Shutoff Valves) are programmed to automatically stop the flow of product using a gauge or sensor in the field. For liquid pipelines, there is concern that the automatic closure of a valve can cause a pressure surge from the liquid traveling through the pipeline, potentially leading to an upstream rupture. For natural gas pipelines, this is typically not the case because of the properties of gas.
    • RCV (Remote-Control Valves) are started or stopped using remote control technology from a separate location, typically a pipeline control room. The key is ensuring that controllers are equipped to understand what action to take when there is an event that could potentially require closure of the valve.

PHMSA Valve & Rupture Rule: Full Episode Transcript

Russel Treat:  Welcome to the Pipeliners Podcast, episode 151, sponsored by Burns & McDonnell, delivering pipeline projects with an integrated construction and design mindset, connecting all the project elements, design, procurement, sequencing at the site. Burns & McDonnell uses its vast knowledge and the latest technology with an ownership commitment to safely deliver innovative, quality projects. Learn how Burns & McDonnell is on-site through it all at burnsmcd.com.

[background music]

Announcer:  The Pipeliners Podcast, where professionals, Bubba geeks, and industry insiders share their knowledge and experience about technology, projects, and pipeline operations. Now your host, Russel Treat.

Russel:  Thanks for listening to the Pipeliners Podcast. I appreciate you taking the time. To show that appreciation, we give away a customized YETI tumbler to one listener each episode. This week, our winner is Kevin Adams. Congratulations, Kevin, your YETI is on its way. To learn how you can win this signature prize pack, stick around to the end of the episode.

This week, Keith Coyle returns. Keith is our recurring guest and our go-to expert for all things pipeline regulatory rulemaking. We got together to talk about the recent LPAC and GPAC meetings where they discussed the new Valve and Rupture Rule. Keith, welcome back to the Pipeliners Podcast.

Keith Coyle:  Thanks for having me, Russel. I always enjoy the show, and I’m looking forward to today’s conversation.

Russel:  Me too. I’m sure people that follow what’s going on with PHMSA are aware that there was a recent GPAC and LPAC meeting to work through the final stages of what’s being known as the Valve and Rupture Rule. That’s what I asked you to talk about.

Maybe a good place to start, Keith, is to ask you, what is the impetus behind this particular rulemaking?

Keith:  The background for this rule is pretty similar to a lot of the other rules we’ve talked about lately. It’s basically a rule that the genesis for which was in some recent pipeline accidents and then a resulting statutory mandate from Congress. There were two pipeline accidents that really drove the conversation on this rule.

The first was a crude oil pipeline failure in Marshall, Michigan that occurred in July of 2010 and resulted in the release of about 840,000 gallons of crude oil into an environmentally sensitive area and a waterway.  The National Transportation Safety Board investigation of that incident showed that the operator of the pipeline didn’t detect the rupture for more than 17 hours. In the course of operating the system, the operator essentially misinterpreted some alarms as not being indicative of a rupture.  As a result, the operator tried to restart the system two times before learning of the rupture, and those attempted restarts significantly increased the volume of crude oil that was released from the system.

The other significant incident occurred a couple of months later, in September of 2010, in San Bruno, California. This was a natural gas transmission line failure that occurred in a residential area. The gas ignited and there was an ensuing fire. The operator of the system was not able to manually close the valves that were necessary to isolate the ruptured segment for more than 90 minutes.

From both of those events and the NTSB investigations that followed, NTSB made some recommendations to PHMSA and to those operators about steps that should be taken to improve incident response, rupture mitigation valve installation and valve closure.

Congress picked up those recommendations from the NTSB in the 2011 Reauthorization of the Pipeline Safety Act. Congress included what’s known as a statutory mandate in the Pipeline Safety Act, directing PHMSA to issue regulations that would require the installation of automatic shutoff valves, remotely control valves, or equivalent technology on new or entirely replaced transmission lines within two years.

Russel:  I think, Keith, that most people that work in the business are familiar with both the Marshall incident and the San Bruno incident. They both got national media attention, and in both cases, for an extended period of time. Certainly, that moved Congress to include their mandate in the reauthorization.

It’s interesting to me. As we record this here, it’s September of 2020. It’s been almost exactly 10 years ago that these two incidents occurred. It gives you an indication of the time it takes for these kinds of rulemakings to work their way through the process.

Keith:  It’s also indicative of the impact that those two significant pipeline incidents had on the entire regulatory structure. We’re just talking today about one rule that PHMSA is issuing related to valve installation and rupture detection.  As you know, we’ve talked about this before, there were other rules that PHMSA recently completed related to those two incidents. There were also changes that occurred in other states related to these incidents as well as litigation and other things. It shows the long lasting impact that significant events like these can have on the entire regime.

Russel:  I would absolutely agree. I would even assert that to some degree the public resistance to pipelines is at some level related to their memory of incidents like this and others. It creates a certain public perception.

I’ve said this on other podcasts, too. There’s a disconnect a bit between what the public expects that we should do and what we’re capable of doing. That all gets addressed in these rulemaking processes.

Keith:  These kinds of events, we always tell the people who are involved in this business that they’re extremely rare, but they leave scars that last a long time. Even I’m surprised. If you go back in time and look at some other events that were significant as well, they didn’t play out as long as these two have.

They didn’t dominate the conversation as long as these two have. This, hopefully, is the last rulemaking that PHMSA will be handling relating to these two events. Maybe we’ll have some closure, at least, on the regulatory front.

Russel:  That would certainly be my expectation. We ought to talk a little bit about the Oak Ridge National Laboratory study. With this rule, like many others, when you start talking about automatic shutdown valves, remotely operated valves, and detecting rupture    when you say those words — it all seems to make clear sense that, yes, those are all things that we should do.

When you start trying to do the engineering and determine, “Well, how are we going to do this?” these things tend to get way more complex very quickly. Maybe you could tell us a little bit about the study, what was in it, and how that set the stage for the content of the rule.

Keith:  Sure. PHMSA reached out to Oak Ridge because one of the requirements in the statutory mandate was to determine if the installation of automatic shutoff valves or remote control valves was technically, operationally, and economically feasible.

It’s good from a PHMSA perspective to reach out to another government entity with some expertise that has background in these things or has the ability to conduct these kinds of analyses and studies to pull something together that you can use as an expert study to guide your decision making in the rulemaking process.

PHMSA had looked in the past at the installation of automatic shutoff valves, remote control valves in previous studies. One of the challenges that came up when it comes to these valves is that particularly on the gas pipeline side, so much of the immediate damage that’s caused by an incident occurs very quickly.

You have a rupture. You have an ignition. That’s where the impact is in the immediate aftermath. Even if you have the best rupture mitigation or automatic shutoff valve in the world, you’re not going to close fast enough to stop the immediate impact of an incident, particularly a significant incident.

One of the things that Oak Ridge looked at that has been emphasized by PHMSA as a result of these studies is that there are other consequences that play out even if you don’t isolate or shut off the segment immediately.

The longer that these events propagate, the more environmental damage, the more property damage. They talked a lot about with San Bruno how the fire continued to burn because there was still a supply of gas.

As with Marshall, Michigan, where you saw longer term environmental impacts and consequences that occurred after the immediate rupture because the crude oil continued to leak into the environment, the operator tried to restart the pipeline a couple of times, and that increased the volume of the release.

One of the nuances that PHMSA was looking at in this rulemaking or considering was, can we still mitigate the consequences of an event through the installation of these valves? Even if the valves don’t close in the immediate aftermath of the event, is there still a benefit?

What PHMSA said in this rule and what Oak Ridge found is there are consequences that can be mitigated through the installation of these valves in terms of some of the longer term impacts that knock off from the immediate rupture themselves.

Russel:  We’re going to talk about this in a second. One of the things that became very clear if you sat through the GPAC meeting and the LPAC meeting where they’re discussing this rule is that the gas issues and the liquid issues are quite different in these cases. I’ll talk a little bit about this, and I’ll give you an opportunity to respond.

The nature of most gas systems particularly in gas utilities is they have been developed, built, and are operated to ensure deliverability. There’s consequences to cutting the gas off quickly, particularly, for things like power plants and other expensive infrastructure that others rely on that can have some pretty bad consequences if you shut those things off quickly and without warning.

That adds some complexity when you start thinking about, what are you trying to do in a gas system if you’re going to detect a rupture and shut down quickly is the fact that most natural gas systems are built to ensure that the gas stays on, not that it can be quickly turned off. Those two goals compete with one another.

Keith:  If you shut down the gas supply to a major power plant with no warning, you could be taking an entire community off the grid. If you stop the gas supply into a distribution network in the middle of winter, not only are you taking away potential heat but you have to go back in, restart the system, relight all of those things. There are consequences to shutting down, too.

Russel:  If you shut the gas off to a boiler in a power plant, you can crash the boiler tube bundle. If you crash the boiler tube bundle, they’re not off while the gas is off, they’re off until they get a new boiler in place. It’s like everything else. The more you think it through, the more complex it becomes. You made the point about gas being localized.

Gas goes up into the atmosphere so it tends to be localized where liquids tend to flow and accumulate in the lowest point they can get to from wherever they rupture occurs. There’s environmental remediation problems with liquid ruptures that don’t exist with gas.

They’re very different, not to mention the hydraulics of the fluids themselves are quite different as well, which leads into the thing that PHMSA did when they were proposing the rule and they said, “Here’s some key topics,” one of those being rupture definition.

Keith:  PHMSA included in the rulemaking proposal a definition of a rupture. From a high level, what PHMSA was trying to do was to put some more quantitative metrics or some more fixed thresholds into the definition of rupture. The concern being that operators in the past had failed to identify events that should have qualified as ruptures.

In their proposed definition of a rupture, one of the things that PHMSA included was this 10 percent, 15-minute metric in the proposed definition, basically, telling operators, “Look, if you have an unplanned flowrate change of 10 percent or greater or pressure loss of 10 percent or greater within a 15-minute interval, you have to treat that as a rupture unless you’ve documented something in advance that shows why that shouldn’t be treated as a rupture.”

One of the things that industry latched onto with that definition was, those two metrics are probably not feasible in a large majority of gas pipeline systems. Treating a 10 percent change over a 15-minute interval, immediately that must be treated as a rupture is problematic for a lot of systems, particularly for the liquid systems.

The way this rule is written, once you identify something as a rupture, other regulatory obligations kick in that you can’t unwind. If you have a rupture, you have to start the process of closing all the rupture mitigation valves. There’s a timeline for that. There are events that would happen under this rulemaking proposal that gave folks a lot of pause with that proposed definition of rupture.

PHMSA wanted to push this quantitative approach or these hard and fast metrics. What you heard from industry was, “Look, we don’t understand the technical basis for those criteria and also they’re just not achievable if you’re doing this out in the field.”

Russel:  I would characterize what I heard in the GPAC that they did get to some consensus about the level of a pressure change and the timeframe that it occurs. They did get to some consensus around that. They got to, at least on the gas side, what I thought was a pretty clear definition of something that was agreed to that that’s what a rupture looks like.

It was quite different when you went to LPAC. They immediately said, “That’s just completely unworkable.” If you think about the hydraulics of gas, gas pressure doesn’t tend to change a lot quickly in a pipeline. A pipeline operates like a big vessel and you’re keeping the pressure in that vessel at current, putting in as much as you’re taking out.

Very different in a liquid system because of the transience, you get transience with pump starts, pump stops, valve opens, and flow control valves, set point changes, all of those things create transience. Each of those can cause fairly significant pressure transience as they’re executed. It’s a completely different problem on the liquid side versus the gas side.

Keith:  You saw those concerns raised in the public comments that were submitted. Even among the industry members on the Liquid Pipeline Advisory Committee, one of them talked about a new pipeline system that they had just put into service. It was something like dozens of events.

They went back and analyzed their system over a 12-hour period. They came up with dozens of events that would have qualified as ruptures if you used that 10 percent, 15-minute criteria on a brand new pipeline system. If that’s the result that you’re getting, there’s something wrong with the way that the definition has been proposed.

What PHMSA said was, “Look, we also provided some flexibility in the definition to allow you to document alternative criteria for rupture in your procedures.” What a response to that would be, “Well, the rules shouldn’t be honored more in the breach. We need to rework the rule.”

If we have these metrics that everybody is essentially documenting themselves out of, we need to go back and look at the metrics and think about, “Are these the right numbers? Are these the right criteria to use? Or, should we be using something else?”

Russel:  Then the next thing they also talked about was valve installation and valve spacing. Where should they be? Then again, it’s interesting because the issues are quite different for the gas guys versus the liquid guys.

In the liquid world, you’re looking, where do I put these valves so that if I have a rupture, I don’t drain someplace I wouldn’t want to drain? With the gas guys, it’s more, “How do I minimize the amount of gas that I’m going to vent before I have the issue sealed off and contained?” It’s quite a different requirement for the gas or the liquid guys.

Keith:  The way that PHMSA approached the statutory mandate was they looked at, you know, Congress said, assuming it’s feasible and technical, and operational. PHMSA looked at it, “Okay, we’ve got two categories of kinds of pipelines that we can require these valves on. There’s new and then there’s entire replacements.”

For the new lines, PHMSA looked at it and they said, “We’re going to require these kinds of valves on newly constructed lines that are six inches in diameter or greater.” They went with a diameter threshold. They said, “Look, the smaller lines, below six inches, we don’t think that the installation of rupture mitigation valves is going to get much from a public safety perspective.”

On the replacements, what they originally proposed was the same 6-inch diameter cutoff. They also folded in this requirement that said, “If you replace two or more contiguous miles of pipe in an existing system, we’re going to treat that as an entire replacement.”

That’s a little bit more controversial. The original proposal of PHMSA was basically saying, “Look, we have to pick a point where we think an entire replacement happens. We’re picking two contiguous miles.”

When they got into the advisory committee process, PHMSA proposed an alternative metric, which was basically, “We think an entire replacement occurs if you replace at least two miles in any five mile segment.” From my perspective, that’s a harder position to defend. Congress talked about entire replacements in the statute.

I don’t know how you get to something being entirely replaced if you’re only replacing two miles out of five miles. That’s the breakpoint in the rule. There’s less concern probably with installing rupture mitigation valves on newer systems. You can plan that out and make it more orderly.

On some of these where you’re going in and you’re replacing shorter segments, it’s a lot trickier. The cost is increased. You have to think about, is it feasible to put a rupture mitigation valve in that location? Then you got to look at the new spacing requirements, things like that.

Russel:  This last LPAC and GPAC was virtual. I started getting lost in some of the back and forth between the various members on the committee when they were talking about the spacing and installation requirements.

Certainly, there was a little bit of, I won’t say disagreement but some different viewpoints between the public advocates and the industry advocates on those two committees and a little bit different take.

The industry was saying, “For this to be practical and feasible, then a project has to be of adequate scale to justify doing this additional engineering and having the additional cost of the valves, and I don’t want to not replace pipe because the cost is too high because of valves because I want to get a safety benefit by replacing pipe.”

Then the public, I would frame their viewpoint, again this is just my perspective from listening, as, “Yeah, but we need to get these valves in.”

Keith:  Yeah, I think that’s right. The public advocates want the rupture mitigation valves installed more broadly, more quickly. The problem that you run into there is the language of the statute is pretty specific in terms of entire replacements. PHMSA’s going to have some play in the joints there.

They’re going to have some discretion to interpret the statute in a way that they think is appropriate or consistent with the text. At the end of the day, hopefully, we’ll come to a good resolution on the replacements. There doesn’t appear to be as much concern with the newer systems. There’s lead time. You can plan. You can order things.

PHMSA provided some request for approval process where you could ask to not have a valve installed at a particular location. Those things are easier to get over if you’re talking about a new project because of the lead time, whereas if you’re talking about replacing an existing system, those challenges are more difficult.

Russel:  No doubt. You can certainly go to the PHMSA site and you can download the voting sides and what the committee recommendations were related to the proposed final rule. Where do you think this is going to land as it relates to these things we’re talking about in terms of rupture definition, and installation, and so forth?

Keith:  My hope on the rupture definition is that PHMSA moves away from the metrics that they proposed and provides something that gives operators more discretion to determine how to define a rupture for their particular system. When defining a rupture, they would need to do that in their operation and maintenance requirements.

They would be enforced to that requirement. That’s my hope is that they get away from the metrics that they had in the proposal and maybe shift to something that allows operators more discretion.

On the installation of the rupture mitigation valves, one of the things that PHMSA was asked to look at was, do we need to consider other scenarios beyond just this 6-inch pipe diameter limitation where a rupture mitigation valve might not make sense? One of the things that PHMSA’s looking at is low stress pipelines.

Low stress pipelines almost by definition, these are pipelines that are not going to rupture or only in very rare circumstances would they have something that would qualify as a rupture. Take a look at that and say, “Is this a scenario where we really need to require the installation of these valves, or can we adjust the mandates so that it focuses only on the higher stress lines?”

Then in terms of some of the other things on the operation and maintenance requirements, PHMSA had originally proposed this 10-minute deadline for identifying ruptures from the point of notification.

PHMSA and the advisory committees indicated that it probably makes sense to drop that 10-minute identification deadline and go with a 30-minute deadline from the point of identification for closing the valve.

In essence, take away this additional deadline that PHMSA had proposed, 10 minutes from the receipt of information that could be indicative of a rupture to identify it as a rupture and just go with one timeline, that 30-minute timeline.

At least my understanding from talking to a lot of operators is 30 minutes to close the valves is going to be achievable particularly if you’re talking about the ASVs or the RCVs. That shouldn’t be a problem.

The one thing that we don’t want to do is put an artificial deadline on the rupture determinations because then you’re putting operators in this box where they’re being forced to make decisions too quickly. Maybe they end up treating something as a rupture that they shouldn’t.

Then they have all of those adverse effects that we talked about before in terms of loss of gas supply to communities, challenges related to liquid systems when you shut things down. Those are some of the things.

Russel:  It’s interesting, Keith. My take is a little different. I think that on the gas side they’re going to end up with something looking fairly prescriptive, a pressure change of some amount within a period of time type thing. That’s where they’ll land on the gas side. That could work well on the gas side. Again, it’s my opinion. I’m not necessarily an expert on all the hydrology of gas systems.

To me, that’s more workable in a gas system given the way they work. I do think that on the liquid side, it’s quite a bit more complex and you’ve got to give the operators more latitude as to how they define a rupture.

That hydrology, at least, in my opinion, is a lot more complex, particularly if you’re dealing with batch pipelines, pipelines with lots of elevation changes, if they have to operate slackline, or any of those kind of things. In those cases, what you’re going to have to do is ask the operators to each define what a rupture is and how they identify it.

Keith:  If the rule plays out that way, that would certainly be consistent with the way that the two days of the advisory committee went. On the gas side, there was less concern or less of a focus on the metrics and there was more of that focus on the liquid side. Maybe the rule will shake out that way.

Russel:  The other part about that, too, is on the gas side, particularly in these older distribution systems, they have less automation on their valves. They’re more concerned about valve closure speed than they are about rupture determination.

The liquid side, it’s the opposite. They’re more concerned about defining what a rupture is and less concerned about valve operation. Typically, they already have that kind of valve in place on the liquid systems.

Keith:  One other thing that I wanted to bring up because it’s near and dear to my heart is gathering lines.

Russel:  Thank you. We needed to cover that. Thank you.

Keith:  There was a significant discussion about applicability of these rupture mitigation valve requirements to gathering lines. Industry came into the comments on the original rulemaking proposal and said, “Look, we don’t see anything in this rule that talks about gathering lines. We understand that the way that the rules are written with cross-referencing, you could argue that gathering lines should be following transmission requirements, therefore, should be subject to these rules.”

What we saw from the industry comments and then the GPAC and LPAC process was — this was very unique from my perspective; I’ve never seen anything like this from the advisory committees — the advisory committees basically said to PHMSA, “Look, there was a lack of public notice of any intent on your part to require gathering lines to have these rupture mitigation valves. We want you to consider the appropriateness of applying these rules to gathering lines because of the lack of public notice.”

I was very pleased to hear that from the advisory committee. We spent a lot of time going through not just the rulemaking proposal itself but also all of the underlying documentation, the statute itself. There were no references in any of those documents to requiring gathering lines to have these valves.

The challenges that would go with applying this kind of rule to gathering lines would be even greater because most gathering line systems that are regulated tend to be regulated on a piecemeal basis, like segment by segment, depending on where they’re located.

To apply this rupture mitigation valve to these very short segments on gathering systems would be extremely challenging. Oak Ridge didn’t look at that issue when they did their study, and there was no indication in the rulemaking documents that PHMSA had ever looked at it.

In fact, the first time that PHMSA ever really came out and said they wanted gathering lines to have these valves was the day before the GPAC and LPAC meetings themselves.

At that point, the industry folks are basically like, “Look, we’re just hearing about this now. This hasn’t been properly analyzed. We don’t think it’s appropriate to move forward with a recommendation to apply those valves to gathering lines.” I think that that was another good result from the advisory committee process.

Russel:  I would agree with that. I think it’s interesting, too, that at the same time that this rule’s coming through and working through the final process, you also have the Gas Gathering Rule going through.

I think that the fact you have that rule working its way to final at the same time you’re adding this, it could cause a lot of confusion thrashing, potentially, for the gathering operators trying to reconcile all that at the same time.

They’re going to have a big enough challenge just addressing whatever the final version of the Gathering Rule’s going to be. I’m with you. I think that those remarks were very appropriate.

I would also say that I think that, at least, in my understanding and the experience I have with PHMSA and its leadership, they’re very committed to appropriate thorough public comment on anything they’re doing. I suspect that they’re going to fall in line with that.

Keith:  I hope so. Look, even the people who commented on behalf of gathering, we’re not saying that necessarily everyone is opposed to the requirement. I think what we wanted to be sure of is there’s a proper analysis, we know what PHMSA wants to do and that PHMSA is considering the unique circumstances that apply to gathering systems.

Particularly, the segmentation in terms of regulated/unregulated segments, these changing gathering rules that are coming. All of a sudden, we’re going to have more jurisdictional pipelines and then this other set of rules on top of it.

I was encouraged by the recommendation from the advisory committee, and quite frankly, by the comments that PHMSA made as well during the process. They understood the concerns, and they seemed, from my perspective, to be accommodating.

Russel:  Keith, if you were to pull out your crystal ball and say, “Here’s what needs to happen next and when this rule will actually become final,” what is your crystal ball telling you?

Keith:  Crystal ball would probably say, “Outcome uncertain.”

Russel:  [laughs] That’s the Magic 8 Ball, buddy.

Keith:  Yeah, right. I will say this. PHMSA has moved incredibly quickly through a lot of big rulemakings during the last couple of years. I give a tremendous amount of credit to PHMSA leadership, the administrator, and his staff.

They have managed to move rulemakings through, including rulemakings to conclusion that seem to be bogged down for several years. I think that’s a great credit to the agency. If you look at what they did with this rule, they proposed the rule back in February.

They had the advisory committee in July. That is incredibly fast. I think they’re doing everything in their power to try to move this rule forward. I would be pretty surprised if we saw a final rule anytime in the next few months.

We do have an election coming up, and elections tend to impact the ability of federal agencies to move rulemakings to the finish line. I think, depending on the outcome of the election, we could see things head one of two ways.

If the current administration stays in power, I think the path to a final rule is more certain. I think we’d be unlikely to see significant, substantive changes. I think that the timing would be a little more certain. We’d be on a better glide path to getting a final rule.

If there’s a change in administration, I think there’s much greater uncertainty. As you know, when a new administration comes into power, there’s a pause on all pending rulemakings. They do a policy review, and in some cases, they decide to take rules back and go in a different direction.

During the early days of the Trump Administration, there was an Obama Era hazardous liquid pipeline safety rule that the President pulled back from the federal register. They reworked it, and it didn’t end up coming out for more than two years after that. I think the election will affect substance and timing.

Russel:  Always does. [laughs] I think you could summarize that by saying, if the current administration is re-elected, things tend to accelerate. If the current administration is replaced, then things tend to slow down and get revised. That’s regardless which way the pendulum is swinging.

Keith:  I think that’s right.

Russel:  Just the way our process works.

Keith:  I think, given where this rulemaking stands right now and it being so close, that that’s the most likely result.

Russel:  Any final thoughts for the listeners?

Keith:  Yeah, I think my closing thoughts would be similar to some of the closing thoughts that I’ve given on some of our other recent episodes. The first is we continue to see the impact that significant pipeline incidents have on the rulemaking process.

This case, like so many others, we had a significant pipeline incident that led to an NTSB investigation and recommendations that led to a congressional mandate that led to new PHMSA rules. I think we’re going to continue to see that theme in the pipeline safety regulatory process.

The other thing that I will say is what we talked about at the top of the show, which is those two incidents, the Marshall, Michigan event and the San Bruno incident, I think this rule may mark the end, at least of the federal rulemakings related to those two events.

The fact that we’re here 10 years later, hopefully trying to close out the rulemaking process, just shows how significant those events were and how much of an impact big events can have on the rulemaking process, and how long it can take sometimes for PHMSA and other federal agencies to close the book on all of the things that can be churned up as a result of significant events.

I think those are my two key takeaways for this rulemaking. I look forward to coming back and doing another episode in the future.

Russel:  Keith, as always, my appreciation to you for coming on board. Thanks to your employer, Babst Calland, for making you available. We really appreciate your insight. I know we often get a lot of comments from listeners about your episodes.

They tend to be well listened to because I think we’re all interested in what rulemakings are getting made and what are we going to be dealing with in the future. Again, thank you very much, and look forward to having you back.

Keith:  Sounds great, Russel. Talk to you soon.

Russel:  I hope you enjoyed this week’s episode of the Pipeliners Podcast and our conversation with Keith. Just a reminder before you go. You should register to win our customized Pipeliners Podcast YETI tumbler. Simply visit pipelinepodcastnetwork.com/win to enter yourself in the drawing.

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Transcription by CastingWords