This week’s Pipeliners Podcast episode features Keith Coyle of Babst Calland returning to the podcast to discuss the timely news of PHMSA publishing the long-awaited Gas Gathering Final Rule.

In this episode, you will gain insights into what is contained in the Gas Gathering Final Rule, including the significant legal deadlines and dates associated with the rule, the categories of gas gathering lines and their diameter limitations, what’s expected of the new classification of Type C and Type R operators, and the new limitations on incidental gathering.

To keep up with the new requirements and classifications, access this Client Alert (PHMSA Releases Long-Awaited Final Rule for Onshore Gas Gathering Lines – Babst Calland Attorneys at Law) that Keith and his associate, Chris Kuhman, created at Babst Calland. Included is the referenced chart that illustrates the applicable requirements.

PHMSA Gas Gathering Final Rule: Show Notes, Links, and Insider Terms

• Keith Coyle is a Shareholder with the law firm of Babst Calland. Mr. Coyle is a member of the firm’s Washington, D.C. office and a Shareholder in the Pipeline and HazMat Safety practice. Connect with Keith Coyle on LinkedIn.
  • Babst Calland is the current underwriting sponsor of the Pipeliners Podcast.
  • Access the latest Babst Calland Alerts & Reports under regulatory updates in the Pipeliners Podcast Resources library.
  • Listen to Keith’s previous podcast appearances discussing key pipeline regulations topics.
• PHMSA (Pipeline and Hazardous Materials Safety Administration) is the federal agency within USDOT 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.
• The Gas Gathering Final Rule (Safety of Gas Transmission and Gathering Pipelines) was initiated in 2016 when PHMSA issued a notice seeking comments on changes to the pipeline safety regulations for gas transmission and gathering pipelines. The proposed rulemaking advanced through various stages before being published as a final rule in November 2021.
  • Access the new Babst Calland Pipeline Safety Alert, “PHMSA Releases Long-Awaited Final Rule for Onshore Gas Gathering Lines.”
• 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 PHMSA’s State Pipeline Safety Partners, the exceedance must also be reported to the applicable state agency.
• SMYS (Specified Minimum Yield Strength) is a measurement of a pipe’s strength, as determined by the manufacturing specifications of the pipe.
• Gathering Lines transport gases and liquids from the commodity’s source – like rock formations located far below the drilling site – to a processing facility, refinery or a transmission line. Types include Type A and Type B.
  • Type A: Metallic and the MAOP is more than 20% of SYMS, or non-metallic and MAOP is more than 125 psig.
  • Type B: Metallic and the MAOP is less than 20% of SYMS, or non-metallic and MAOP is less than 125 psig.
  • New Type C: operate with an MAOP of 20 percent or greater of SMYS for the metallic lines or above 125 PSIG for the non metallic.
    • Type C gathering lines are gathering lines located in Class 1 locations that have an outer diameter of 8.625 inches or more and operate at higher-stress levels of pressures.
  • New Type R: include any onshore gas gathering lines in Class 1 or Class 2 locations that do not meet the definition of a Type A, Type B, or Type C line.  Operators of Type R lines must comply with the certain incident and annual reporting requirements.
  • The new Gas Gathering Final Rule covers the following classifications:
    • Type A in Class 2, 3, or 4.
    • Type B in Class 2, 3 or 4.
    • Type C in Class 1
    • Type R Class 1 lines that don’t meet criteria of type A, B, or C. 
    • Original: Type A in Class 1 — diameter greater than or equal to 8.625.
    • In discussion: Type A, Class 1 diameter > 12.75 and at least one dwelling, or Class 1, and greater than 16”.
• Class location is an onshore area that extends 220 yards on either side of any continuous 1 mile of pipeline. Also, each unit in a multi-unit building is counted as a separate building. [View this detailed presentation on how to determine class location.]
  • Class 1: Offshore, or has 10 or fewer buildings for human occupancy (e.g., rural).
  • Class 2: More than 10 buildings, but less than 46.
  • Class 3: More than 46 buildings; or an area where the pipeline lies within 100 yards of a place where people gather (20 or more people, at least 5 days a week for 10 weeks in any 12 month period).
  • Class 4: Buildings with 4 or more stories above ground are prevalent.
• Incidental Gathering Line: PHMSA considers “incidental gathering” to include only lines that directly connect a transmission line to one of the endpoints (A) through (D), as limited by this final rule. Lines that connect a transmission line to one of these endpoints by way of another facility are not considered “incidental gathering.”
• Integrity Management (Pipeline Integrity Management) is a systematic approach to operate and manage pipelines in a safe manner that complies with PHMSA regulations.
• PIR (Potential Impact Radius) is defined by PHMSA (49 CFR subpart 192.903) as the radius of a circle within which the potential failure of a pipeline could have significant impact on people or property.
  • PIR Calculation: PIR is determined by the formula r = 0.69* (square root of (p*d 2)), where ‘r’ is the radius of a circular area in feet surrounding the point of failure, ‘p’ is the maximum allowable operating pressure (MAOP) in the pipeline segment in pounds per square inch, ‘d’ is the nominal diameter of the pipeline in inches, and 0.69 is the number for natural gas (the number will vary for other gases depending upon their heat of combustion).
    • The formula that an operator must use in calculating the potential impact radius and potential impact circle for a pipeline is explained in the definitions provided in 49 CFR 192.903.
      • A diagram displaying how a potential impact circle looks can be found in Appendix E to Part 192, Title 49 (Guidance on Determining High Consequence Areas and on Carrying out Requirements in the Integrity Management Rule). This guidance is for the integrity management rules for gas transmission lines, but the diagram displays the same basic concept as the potential impact circle for a regulated gathering line.
• Gas Pipeline Advisory Committee (GPAC) is a statutorily mandated advisory committee that provides PHMSA and the Secretary of Transportation with recommendations on proposed standards for the transportation of natural gas or hazardous liquids by pipeline.
• RP 80 & 1182: API Recommended Practices 1182 and 80 have been published in conjunction to enhance safety and operational efficiency of large diameter gathering pipelines. RP 1182, Construction, Operation, and Maintenance of Large Diameter Rural Gas Gathering Lines is complemented by the 2nd edition of RP 80, Definition of Onshore Gas Gathering Lines. The recommended practices will help ensure integrity management practices are properly implemented to meet regulatory and safety needs.
• CFR 192 provides regulatory guidance on the pipeline transport of natural gas. Part 192 prescribes the minimum safety requirements for pipeline facilities and the transportation of gas, including pipeline facilities and the transportation of gas within the limits of the outer continental shelf.
  • Subpart I (Requirements for Corrosion Control) prescribes the minimum requirements for the protection of metallic pipelines from external, internal, and atmospheric corrosion.

PHMSA Gas Gathering Final Rule: Full Episode Transcript

Russel Treat: Welcome to the Pipeliners Podcast, episode 207, sponsored by EnerSys Corporation, providers of POEMS, the Pipeline Operations Excellence Management System, compliance and operations software for the pipeline control center to address control room management, SCADA, and audit readiness. Find out more about POEMS at EnerSysCorp.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, and to show that appreciation, we give away a customized YETI tumbler to one listener every episode. This week, our winner is Matt Brewer with Phillips 66 Pipeline. Congratulations, Matt. Your YETI is on its way. To learn how you can win this signature prize, stick around till the end of the episode.

This week, Keith Coyle with Babst Calland returns to talk to us about the recently finalized Gas Gathering Rule. Hey Keith, welcome back to the Pipeliners Podcast.

Keith Coyle:  Thanks for having me on again, Russell. I would have to say, given the topic, I’m probably here a little bit sooner than I anticipated. I wasn’t quite expecting to get a final rule out of PHMSA before I had my turkey on Thanksgiving, but I’ll take it.

Russel:  As always, you’re the first guy I go to when there’s a new rule that comes out so that we can have the conversation, and I can get myself educated after you do all the hard work of figuring out what they actually said when they published the rule.

Keith:  That’s a scary proposition for everybody, but let’s give it a shot.

Russel:  Let’s update the listeners. We’re here to talk about the new Gas Gathering Final Rule, which was just published on November 2nd, as we sit here recording it, November 11th, Veterans Day. How do we start this? What are people needing to be aware of?

Keith:  Let’s start with what happened on November 2nd. On November 2nd, PHMSA released a prepublication version of the final rule for onshore gas gathering lines.

What’s a prepublication version of a rule? It’s, basically, a version of the rule that the agency releases before it goes over to the Federal Register for publication in the Federal Register. When a rule publishes in the actual Federal Register, that’s when things start to have legal significance.

At this point, if you were to pick up the prepublication version of the rule, you’d see some spaces that say insert date here or insert date there. Those spaces exist because it hasn’t published yet in the Federal Register.

When it does, those dates will start to get filled in, which is important, because there are some very significant legal deadlines that will be included in the final rule when you see it published. We’ve heard from PHMSA that it should publish on the 15th of November.

One of the first significant legal deadlines is going to be the effective date of this final rule. The effective date of the final rule is when you will actually see the text of the regulations and the code of Federal Register change. That’s going to happen six months from the date of publication.

Even though you’ll see this rule in the Federal Register, and you can pick it up and read it, when you actually go to the code of federal regulations, you won’t see any changes yet. In the online version, you’ll probably see a notation that changes may be coming. The rules themselves, you won’t see any changes until six months, on or about May 15th of next year.

Russel:  Interesting. How did we land? We’ve had a couple of conversations after the GPAC meeting and as this rule was working its way through the process. Where did we land?

Keith:  Where we landed is we have two new categories of gathering lines that we can talk about a little bit. We have a change to one of the provisions and the definition for what qualifies as a gathering line, and then we have some other ins and out embedded within the rules.

From a big picture perspective, where we landed is every onshore gas gathering line in the country is going to fall into one of four categories. It’s either going to be a Type A gathering line, a Type B gathering line, or one of the two new categories, a Type C gathering line, or a Type R gathering line. I know that sounds a little bit like an episode of Sesame Street, and maybe it does.

Russel:  [laughs]

Keith:  We can walk through a little bit about what those different types are. From a big picture perspective, that’s what PHMSA did. Within those types, there are diameter cutoffs. There are pressure limitations, other things that create compliance obligations that will vary depending on the type, and location, and those things.

Russel:  I read the prepublication rule, and I was reading through all of the words about A, B, and C, and the requirements for A, B, and C, and all that kind of stuff. I got to tell you, man, I got twisted in knots trying to read through that and understand it all. Maybe you could walk us through at a high level what is a Type A, B, C, and R gathering line.

Keith:  That’s a good place to start. Under the existing rules, there are two types of regulated onshore gas gathering lines, Type A and Type B. Type A gathering lines are going to be your higher stress or your higher pressure gathering lines in Class 2 locations, Class 3 locations, or Class 4 locations.

Type A gathering lines are the most stringently regulated gathering lines under the code right now. Generally, you need to follow the requirements for gas transmission lines subject to certain exceptions, including for integrity management.

The second category of the existing gathering line is what’s known as a Type B gathering line. These are going to be your lower stress or lower pressure gathering lines. They’re going to be in those Class 2, Class 3, or Class 4 locations. They’re not subject to all of the same rules for gas transmission as Type A lines are.

For new lines, you’re going to have to follow the design construction, initial installation, inspection, and testing requirements, but then you’re only going to have to follow certain specified provisions in the remainder of the code in terms of your operation and maintenance activities determining your MAOP, things like that, so not as strictly regulated as Type A line.

Those are two existing types of regulated gathering lines.

Russel:  What are the diameter limitations on A and B?

Keith:  That is a good question. There are no diameter limitations included in the current requirements for Type A or Type B. The relevant criteria that are used are stress level or pressure, whether you’re high stress, or low stress, or high pressure, or low pressure, and then the class location where the line is located, 2, 3, or 4.

Russel:  Got it. Let’s keep going. What about Type B and Type C, or Type C and Type R, I should say?

Keith:  We’re already tripping you up here.

Russel:  I know.

Keith:  [laughs]

Russel:  I told you I got twisted in knots trying to understand all of this. I thought I had it. Then they put the new rule out, and it turns out I didn’t have it at all.

Keith:  Now that we’re getting into Type C, we’re really going to go on a mindbender here. The new category of regulated, onshore, gas gathering line is called a Type C line.

The first feature that’s relevant for a Type C line is that it has to be in a Class 1 location. That’s the first criteria. These lines also have to be the higher stress level or higher operating pressure lines. We’re talking about lines with us, operate with an MAOP of 20 percent or greater of SMYS for the metallic lines or above 125 PSIG for the non-metallic.

The two first features you need to know are it’s got to be in a Class 1, and it’s got to be one of these higher operating pressure or higher stress lines.

Then we get into where the diameter is relevant, and it’s relevant in a few different ways in Type C world. The first thing is to be a Type C the line has to be eight inches or greater in diameter. If you’re a Class 1, and you’re a two-inch line, or a four-inch line, or a six-inch line, it can’t be Type C because you’re not big enough. If you’re eight inches or greater and then meet the first two criteria that I talked about, you meet the general definition of a Type C line.

Within the regulatory obligations that apply to Type C lines, PHMSA made distinctions based on additional diameter thresholds as well as whether the line is located near a building intended for human occupancy or other impacted sites.

They basically staggered the requirements within the Type C world based on the diameter and also, basically, proximity to buildings intended for human occupancy or other impacted sites.

Russel:  What about Type R?

Keith:  Type R is everything else. A Type R line is a gathering line that does not meet the definition of a Type A, Type B, or Type C. For the most part, your Type R lines are going to be Class 1 lines that don’t meet all of the criteria to qualify as Type C. They’re either too small. They operate at a low-stress level or low pressure.

There is this small category of Class 2 lines that fall out of Type B regulation due to a narrower exemption that also gets folded in. For the most part, we’re talking about Class 1 lines that don’t meet the Type C definition, but there are scenarios where a Class 2 line that would otherwise be regulated as Type B falls into the Type R category.

Russel:  I’m going to summarize this whole conversation because I have to try to understand it. [laughs] There’s no longer anything that’s a gathering line that is not regulated. At this point, all gathering lines are regulated. It’s just a question of what are the requirements for the line?

Keith:  Yes. The one caution I would put on that is the use of the term regulated gathering lines. There are some knockoff legal effects under the Pipeline Safety Act if you treat a gathering line as “regulated under the statute.”

My understanding of what PHMSA intended in this rule was that Type A, Type B, and Type C are going to be treated as “regulated” subject to requirements in 192. Then we have this Type R category that’s reporting only regulated.

I would say for that category, I wouldn’t want to say, at least not right now, that Type R line is regulated. I would say it’s subject to reporting requirements, which is a legal distinction.

Russel:  It’s a very important distinction because that means I’ve got to report but there’s nothing else I have to do that’s required in 192.

Keith:  That’s an important distinction, just because if you’re treated as a regulated gathering line under this statute, there are other mechanisms within the statute which could apply to you, things like PHMSA issuing a CAO [Corrective Action Order] or other statutory mandates and the statute taking kick in.

It’s pretty clear from the preamble. PHMSA was pretty open that they were using this provision that allows them to collect information about non-jurisdictional gathering lines for this Type R category. It’s an open legal question. At least in my mind, I’m trying to treat those as reporting gathering lines. I know PHMSA says reporting is only regulated, but again, it’s just a minor distinction.

Russel:  I’m recalling the conversations that occurred in the GPAC meeting about the need for information about all gathering lines. To begin to track, what is the actual risk associated with the operations of these Type R lines? At that time, they weren’t calling a Type R, but it was like, “Well, what about everything else?” was kind of the conversation.

Keith:  That’s right. Under the statute, you need to make different determinations when you’re deciding whether something qualifies as a “regulated gathering line” under the Pipeline Safety Act. There are specific legal provisions that you need to follow.

What they do on these Type R is like, “We’re going to gather some information.” This is a good part in the conversation to segue into, “Okay, what is the Type R operator need to do?” As part of this information collection, data gathering effort, operators of Type R lines will need to submit incident reports to PHMSA starting as of the effective date of the final rule.

Then they’ll also need to submit an abbreviated version of the annual report. Because of the way the deadlines for annual reporting run, while that obligation will exist on the effective date of the final rule, your first report won’t be due until the next reporting deadlines cycle runs, which is in March of 2023.

Russel:  That’s actually a nice transition. As I listen to all this, one of the big efforts that anybody with gathering lines is going to have to undertake is they’re going to have to look at their lines, and they’re going to have to make determinations of are they Type A, B, C, or R? What are they going to do with them based on that determination?

Keith:  That is a very good point. At this preliminary phase of the rule, as the rule comes out, figuring out, “Okay, now we’ve got this new criteria for Type C lines. Do I have a Type C line? If not, does it qualify as a Type R line? If it is a Type R line, I need to make sure I’m ready to comply with incident reporting. If I have an event on the Type R line that meets the incident reporting criteria,” and then starts your effort to gather the information that you’re going to need for this initial round of annual reporting.

I know 2023 seems like a long time away, but for operators that were previously unregulated that need to figure out what data they need to start collecting to fill in these reports, that’s going to be one of the things that’s going to occupy their time in the near future.

Russel:  That actually is a nice segue as well, because part of what’s been going on, as this rule has been working its way through, is the API has been revising the Recommended Practice 80. We have a new RP 80. It’s 1182 that goes to definition of what is a gathering line. Those are at least 80. I know it was incorporated by reference, right?

Keith:  Yeah. As the rulemaking process was running along, API went out and worked on a second edition of RP 80. That included some clarifications to the first edition of RP 80.

The first edition of RP 80 is what is currently incorporated by reference into PHMSA’s regulations. That’s the edition that operators follow in going out and determining if the pipeline model operating qualifies as an onshore gas gathering line.

PHMSA did not adopt the second edition of RP 80 in this rulemaking. They talked about it. One of the things they looked at, as a new addition rolled out, was how the second edition of RP 80 handled incidental gathering. The one change that PHMSA made to the definitions dealt with the incidental gathering provision.

If I could just take a little segue here and maybe provide the listeners a little bit about what an incidental gathering line is. Under RP 80, an incidental gathering line is basically a pipeline that takes gas from another potential endpoint in a gathering system, like a compressor station or point of commingling, and it connects to another pipeline, typically a transmission line, but in some cases, it can be a distribution line.

An incidental gathering line is a fancy way of saying, “It’s the last leg of piping in a gathering system.” In some cases, those incidental gathering lines can extend longer distances. One of the concerns that PHMSA has expressed, and is now adopted in this rule, is trying to impose a length limitation on incidental gathering. You’ll see in this rule a provision that limits incidental gathering lines to 10 miles in length starting as of the effective date of the final rule.

I feel pretty confident, at least if you build a new incidental gathering line after the effective date of this final rule and the gathering line extends more than 10 miles, the effect of that 10-mile limitation is to make the entire pipeline a transmission line.

What’s a little more interesting is if I have an existing incidental gathering line that runs 11/12 miles. Let’s say, I go replace, mile at 11, does that have the effect of making the remainder of the pipeline regulated transmission? I hope the answer to that’s no. I think that was the intent of the rule, but that’s one of the things we’ll have to look at as we go forward.

Russel:  Ultimately, with this rule, like every rule, we don’t really know until it’s been audited for a while. That’s when we actually know how all this shakes out.

Keith:  That’s really one of the intricacies of the laws that it has to be read and implemented by human beings.

As we get out into the field, and we start seeing some guidance from PHMSA and audits and inspections, and I’m always surprised, I think you are, too. Even a rule like this, which I’ve lived with for longer than I care to advertise, you think you know everything about a rule, and then you realize you probably don’t. Something comes up and you’re just like, “You know what, I never thought of that.”

Russel:  That is always, always the case. My programmer friends would call these edge conditions. It’s the things you don’t contemplate that are those unique situations that have to be addressed.

Keith:  Yeah. Something always comes up that’s unexpected. This rule, like all of these rules, there are going to be things that come that are unexpected down the road. That’s the basic framework that’s been laid out. We’ve got these four categories of gathering lines. We’ve got this 10-mile limitation on incidental gathering lines.

I know we jumped over this, and we could walk back a little bit on the Type C front, because I know we spoke briefly about general characteristics for Type C. Within the Type C rule itself, people when they pull up the language of the final rule, they’re going to see a long list of things you got to do and then a bunch of exceptions and limitations, reading a little bit like the tax code.

It’s a lot to chew on. When I saw it the first time, I was like I’m not really sure what I’m buying here. I had to go back and read through it a few times and make a chart. If I was going to describe things at a high level for Type C, I would say if you’re Type C and you’re over 16 inches, you’re going to have to follow all the requirements that apply to Type B gathering plus emergency response. That’s for over 16 inch Type C lines.

When you’re dealing with the lines that are between 8 inches up to 16 inches, that’s where the nature of the compliance obligations will vary depending on the size of the pipe and whether or not there are buildings intended for human occupancy or other impacted sites in proximity to the line.

The way that those provisions work, they rely on some concepts, one from the gas transmission world, which I’m sure you’re familiar with, and that’s a potential impact radius calculation. Some of the folks who operate these lines that don’t have regulated transmission maybe aren’t as familiar with that. There’s a formula in the PHMSA regulations that you can use to make a calculation that tells you what the potential impact radius of the pipeline is.

The way this rule is structured is you use that PIR calculation to create a circle around the pipeline. If you have a building intended for human occupancy and other impacted site within that circle, then you’ll be subject to what I’ll say either by way of an exception or way of a limitation. You’re going to have some more regulatory obligations in those scenarios.

Russel:  For the listeners, Keith wrote this great little document, and he put a table in the document that is really helpful in clarifying all this stuff. I’m going to make sure that we get this linked up in the show notes, because I think there’s going to be some people that want to [laughs] download this to try and get some kind of interpretation of how this is actually going to impact me.

Keith:  People who know Keith will know my skills at creating anything beyond basic text is limited, so I will credit my fine associate, Chris Kuhman, who just came over to us from API. He did a lot of the heavy lifting on the chart creation. I knew we needed a chart.

Russel:  [laughs]

Keith:  I knew I couldn’t do it, so I turned to Chris, and kudos to him. The PIR concept is one of the new wrinkles that emerged, and this other alternative that they allow you to use where you just use the standard classification method.

These are concepts that emerged during the rulemaking process, and it’s one of the things that I’m not quite sure all operators have fully vetted through or fully understand the impact of applying the potential impact radius concept and attaching regulatory requirements to all of their pipe.

Particularly when we get to the lower diameter pipe, at least what I’ve heard from some of our clients is people are still trying to sort out exactly what effects these requirements will have and how these potential impact radius calculations will affect their regulatory obligations.

Then even more detailed things like, let’s assume I have a 100-foot segment that falls within the potential impact radius and I need to comply with some rule because of that. There are going to be scenarios where you’re going to have to apply those regulatory requirements beyond the 100 feet. My understanding is you can’t do corrosion control under subpart I on just 100 feet of pipe.

You’re probably going to end up doing things on segments that don’t meet the Type C definition to meet obligations that do apply or segments that do meet Type C but that are outside the PIR. There’s going to be some interesting analysis that goes on over the next few days unpacking exactly what this means for me as a company and how am I affected.

Some of these wrinkles aren’t things that I don’t think people fully expected during the rulemaking process.

Russel:  I’m reflecting back to the GPAC meeting when this was getting discussed. That particular meeting, more so than others I’ve been to, turned into high theater because where the industry was versus where the public was, there was a bit of a gap there. That’s part of where these questions are landing is in that gap that showed up in that GPAC conversation.

What I mean by that is there was a pretty strong public push for, shouldn’t we be doing something for all gathering lines. Some of these requirements are we can agree that we need to do something, but we shouldn’t be doing everything because it’s not warranted. It’s not cost-effective.

What the outcome of that is for the industry’s two things. One, every gatherer’s going to have to do a reassessment of classifying their pipe. They’re also going to likewise have to do a reassessment of what links of pipe have to have what practices applied.

It’s not as simple as you’re mentioning here as just what class pipe it is or what type pipe it is. You’ve got to do these PIR calculations and really assess all that out.

Keith:  There are obviously differences in industry views on the diameter requirement, for instance. PHMSA, in the final rule, went down to eight inches. A lot of the industry trade organizations wanted that limitation to stay greater than 12.

Even within that universe of lines that got picked up in this rulemaking, it wasn’t like people thoroughly vetted a PIR exception or a class location exception with these attached requirements linked to it as part of the rulemaking process because these specific requirements weren’t proposed in the Notice of Proposed Rulemaking.

Some of the concepts were discussed at the GPAC, and some of the concepts are included in the new API RP 1182 for gathering lines, but specific application of the concept to the smaller diameter pipe, linking it to specific rules in 192, those are newer wrinkles that are going to require more analysis by companies and figuring out how things go forward.

Russel:  All that is true. The other thing that’s also true is there’s a lot of producers out there that own gathering lines that don’t really have pipeline regulatory compliance as a competency in their company. They’re going to be in a position where they have to have that competency at some level.

Keith:  One of the things that didn’t change as a result of this rule was a change to the definition of RP 80, which qualifies as production operations. In the rulemaking proposal, they wanted to offer some alternative language that would have swept in more producers in terms of, is the piping that they’re operating is it gathering and not production?

I do think there was some good news for the producers on that front in the sense that at least you’re still analyzing what qualifies as a production operation under the first edition of RP 80 the same way you’ve been since 2006.

The other question becomes if I’m a producer that does have gathering in my system on the backend, and I was mostly out in Class 1, now I’m going to have some of these Type R lines for incident reporting and annual reporting, I may have some of these Type C lines or I’m going to need to start looking at these DOT PHMSA rules. I’m not quite sure this is the first rule I’d want to pick up, and take a look at, and figure out.

[laughter]

Keith:  It’s going to be a new experience for a lot of companies, producers, gatherers who had small systems that were largely in rural areas, even some of the bigger companies that have a lot of pipe. They’re going to have to allocate resources maybe in a different way or figure things out. It’s a big change.

Russel:  Yeah, it is a big change. Like with all these things, we really won’t know the full impact of the change until we’ve been living with it for a while. The learning curve is steepening for a period of time.

Keith:  One of the other things they did in this role was they shortened the compliance deadlines. At certain points in the GPAC process, they were talking about two years or three years or something along those lines, where PHMSA landed in this rule was they gave you six months for the effective date, but then, once the rule goes into effect, the other timelines either become effective on the date of the rule for reporting.

Some of the provisions in 192, you get six months, and the other ones, you get a year. Stuff is going to happen pretty quickly. We’re talking 18 months from the date of publication in the Federal Register to when your last compliance obligation and 192 runs in 18 months. That’s a condensed schedule.

PHMSA did provide some mechanisms in the rule where you could ask for alternative compliance deadlines for some of the 192 deadlines. They provided some safety valves there.

That’s one of the things we’ll see, how does PHMSA handle those requests when some of these deadlines start to arrive from individual companies because that’s a provision that affords individualized relief to a particular company. It’s not something that a class of operators or things like tech can come in and ask for.

Russel:  Here’s the most important question for many of the listeners. How do they find you if they need help?

Keith:  [laughs] You can go on the website. In a lot of ways, I’ve been working on this rule for quite a long time now. It’s good that at least we’ve seen the final rule now. I do think there are mechanisms that still exist in the rulemaking process.

There is an allowance for interested parties to seek reconsideration from the agency, and a petition needs to be filed within 30 days of publication. We’ll see if any of the industry trade organizations or individual operators seek changes to the rule.

Then there’s another mechanism where you can seek judicial review in the federal courts, which is it’s pretty rare in PHMSA land for things to go to federal court. Good to see the final rule come out. There were some surprises in the rule, things that I wasn’t expecting, things that I was happy to see, but we’ll see how things go from here.

Russel:  Anybody who wants to find Keith, you can go to the Pipeliners Podcast website and go to his profile page and find his contact information.

He’s certainly a guy I go to when I have questions. Before we got on the microphone, I was quizzing him about what this means for control room management. We’ll save that conversation for another day and just leave it there. How’s that?

Keith:  Russel always saves the hardest questions for me for the end. We’ll do that as a teaser for the next iteration of the gathering podcast.

Russel:  There you go. Hey Keith, thank you very much, as always. It’s a pleasure.

Keith:  Thanks, Russel. I always enjoy chatting with you.

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 pipelinerspodcast.com/win to enter yourself in the drawing.

If you’d like to support the podcast, please leave us a review on Apple Podcast, Google Play, or on your smart device podcast app. You could find instructions at pipelinerspodcast.com.

Russel:  If you have ideas, questions, or topics you’d be interested in, please let me know on the Contact Us page at pipelinerspodcast.com or reach out to me on LinkedIn. Thanks for listening. I’ll talk to you next week.

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Transcription by CastingWords