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Case number 19-1074, Gulf Sub-Pipeline Company LP Petitioner versus Federal

[00:00:38] Speaker 05:
Mr. McMahon, good morning.

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Good morning.

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My name is Mike McMahon.

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I'm here on behalf of Gulf South Lifeline Company.

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The key issue before the court is determining whether folks finding that Gulf South West Lake Expansion Facilities are integrated with the rest of this system in Lake Charles, Louisiana area.

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If FERC's integration finding is reversed, it also requires the Commission's use of the existing Lake Charles depreciation rate to be set aside.

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There are some facts I don't think are in dispute, which undercut the integration finding.

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The expansion facilities were built solely to serve a new power plant.

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The expansion facilities are located in the northern end of the Lake Charles zone, near the customer's plant to minimize the impacts

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to landowners in the environment.

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The expansion facilities do not provide redundant access to existing Lake Charles points, enhance the reliability of the transmission facilities in that zone, or increase the transportation capacity available to existing customers.

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The expansion facilities are operationally isolated from the rest of the Lake Charles mainline due to pressure concerns.

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The vast majority

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of the expansion costs associated with these facilities is tied up in the new compression.

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Your filings with FERC and your argument now refers to this project as an expansion of the existing pipeline.

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Doesn't that make it integrated?

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If it wasn't integrated, you wouldn't be calling it an expansion of the original pipeline.

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Well, it is an expansion because it's taking the system to a new market.

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The difference here is the new market requires a higher pressure than what the underlying Lake Charles assets can meet.

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So we built a new compressor station.

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The compressor station's sole function is to bump up the pressure of the gas to be delivered to the new facility.

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It is no different than delivering the lateral, which the commission has routinely granted additive pricing when a lateral is built

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from existing facilities to serve a single or few customers.

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And that's exactly what this is.

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We built this project to serve a brand new pipeline that our new power plant is not physically connected to the remaining portion of our system.

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Do you think the question of integration is a question of fact or a question of law?

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I think it's mixed.

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The reason I say it's mixed is

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What the Commission has said in its precedent is if an existing system and expansion system are operationally isolated, then they are not a single system.

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The Commission acknowledges that in its brief.

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Here, because of pressure and pipelines operate based on going from high pressure to low pressure, the mainline system cannot get into the expansion facilities

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because of pressure.

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It's kind of like having a concrete barrier on an entrance ramp.

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The pressures are, they're operated totally different.

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They're totally isolated from each other by pressure.

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And this is a kind of a direct feed into the plant.

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It doesn't help anybody else in the Lake Charles zone.

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So from that, it's a question of fact under their existing precedent.

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And I think it's a question of law too, because in this case,

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The process that they went through and what they ignored does not render a reasonable decision because they haven't distinguished the operations.

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They rely on Equitrans, which has a compressor involved and it has four miles of pipe involved.

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But the difference here is the compressor in Equitrans gave pressure support to both the existing customers and to the new customers.

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The four miles of pipe provided access to existing customers and the expansion customers.

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Here, the four miles of pipe that we used only provides support for this.

[00:05:02] Speaker 01:
I thought it was .3 miles.

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I'm sorry?

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You're saying the lateral was four miles?

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I thought it was .3.

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There is between the compressor station and the lateral, we took a piece of underutilized pipe, took it out and isolated it

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to serve this facility.

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So this four miles of pipe goes up to the .3 mile.

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I just want to be clear about the structure here.

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Under FERC's ruling, the power company is going to be paying a higher rate

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than the other customers, correct?

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And the question that's being debated back and forth is what would the existing customers have to pay if for some reason they started taking gas from the new lateral?

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Or actually trying to deliver to the new lateral.

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Okay.

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So, but the problem that I have with that is that the power company signed a contract for 20 years to take everything

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Right?

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So the prospect of the existing customers coming in is pretty remote, and that leads me to the question, which is why is this case ripe?

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Where's the imminent harm?

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Well, there's two pieces to that, Your Honor.

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One is in your case is each day gas is nominated and scheduled to the power plant.

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If another customer comes in and gets there in the early, the first cycle of the day, and that gas is scheduled, then it can actually bump out the power company's firm contract.

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That's under existing FERC policy and our tariff.

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So we have the opportunity for shippers to actually come in, and we've seen this at other places on our system where we don't have the rate disparage, to come in in an earlier cycle and try to grab the capacity

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for their own benefit on a day-to-day basis and use that for their own benefit and profit because they're paying substantially less than what the power company has under its contract.

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The second is, if this finding is upheld, then you have a depreciation problem which says that at the end of the 20-year contract, under what they've said is 74% of the value of those facilities are going to be remained

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to be collected when we only have a 20-year contract.

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So we have potential for stranded cost because of the depreciation based solely on the integration finding.

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And then what becomes integrated so as we plan what is an integrated facility, what is not an integrated facility because here where we have operational isolation, it's very hard for us to say,

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Okay, what's the next one going to look like?

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So for those reasons, Your Honor, I believe this case is right.

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Can you explain to me maybe, so the depreciation rate you suggest should be based on the contract length, but the contract length is 20 years, but you're proposing a 35-year

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depreciation schedule.

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I didn't see anything in the record explaining that disparity.

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The reason we selected the 35 years is it says, okay, what is a typical power plant operational life?

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What is a typical power plant?

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It's about 30 years, 35 years.

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So that's what we did.

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It's somewhere between the 76 and the 20.

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We knew the 20 probably wasn't the right answer, but 30 is

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five seem to be a more practical and realistic answer given the nature of the facilities and that these facilities are set to only serve one customer.

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Can you also just explain to me the relationship between the shippers and the power plant?

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So here we have a situation where the power plant has contracted for 100 percent of its capacity with

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You know, the energy power plant has contracted with energy.

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So how then does another shipper nominate to send that power plant gas?

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If you could just explain that in relationship to me.

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Sure.

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Once you have a point established on your system under the open access principles of the commission, every shipper, regardless of whether they have that contract under that point under their contract, has the right to nominate on either a primary basis, which they would not have,

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or a secondary basis, which any shipper is granted.

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And so they can nominate on a day-to-day basis to see if they can get their gas schedule to that plant.

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And the plant has to take that gas?

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If they confirm the nomination, they do.

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There are no other questions.

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I actually did have one other question.

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In your request for hearing before FERC, Gulf South made an argument under HOPE natural gas.

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Why was that argument not made here on appeal in the petition for review?

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That's what I think.

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The concept of HOPE goes back to are you given a reasonable opportunity to recover your cost?

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And without citing hope, in the same way we did underneath at the commission, I believe we've been making the argument under the cost causation and under the cost causation that this does not give us a reasonable opportunity.

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That's a slightly different argument than the stronger constitutional argument underlying hope.

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Right.

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But we kind of moved to that direction under cost causation.

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Thank you.

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Ms.

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Pacella.

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Good morning, Your Honors.

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Beth Pacella for the Commission.

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I'm going to talk first about the integration issue, if that's all right.

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The Commission found that the project facilities here were integrated for four reasons.

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It pointed out four factors.

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First, that the project gas will enter Gulf South facilities via existing and new Lake Charles zone receipt points.

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So all of the receipt points for the gas, the project gas, will enter on existing receipt points on the existing system, excuse me.

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Then it's going to be transported, all of the gas will be transported on existing Lake Charles zone facilities.

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Then it will be compressed at the project's new compressor station, which is located

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in the existing Lake Charles zone.

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And then it will be transported again on existing facilities and delivered to the .3 mile lateral.

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So what Petitioner wants you to do is ignore all those other factors and just say well there's a compressor station and ignoring that it's on the facilities and that there's this .3 mile lateral.

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But the bulk of the facility, the bulk of the project is the compressor station and they chose to put it on the

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on existing facilities and now those facts do exist.

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And so all of the project gas will move on existing facilities.

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This is a surely integrated facilities and the commission is the expert here, not the petitioner who has a more myopic view, but the commission with its experience and knowledge of its own policies and fact finding deserves deference to that determination here.

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Pressurization, the commission found that we're hearing order of JA198 paragraph 11 doesn't change the integration finding because of the fact that all of the gas is received on the existing facilities.

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And that, the commission found to be paramount over this pressurization argument.

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Regarding the five, yeah, I'm sorry.

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If the system is integrated, though, why not, why wouldn't Gulf South be entitled to a separate rate zone?

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They're not under the argument of Texas Eastern.

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They're not entitled to it.

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Well, first of all, Your Honor, we believe that they waived that issue because they raised it for the first time to the Commission Army hearing.

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And contrary to the statute, which is jurisdictional, they didn't raise it again to the Commission Army.

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Well, say we determined that that issue is properly the source.

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Of course.

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Commission permits new rate zones for substantial system extensions that are operationally and geographically distinct from the pipeline's mainlines.

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And we don't have that circumstance here.

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And that was true in Texas Eastern as well, which the commission explained at Rehearing Order JA 200, paragraph 15, that the expansion in Texas Eastern was a 15-mile continuous extension that was easily distinguishable from the rest of the mainline system.

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The bulk of the project there was this 15-mile lateral.

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that contrast to here where the project isn't readily distinguishable for all the factors that I've already explained.

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It seems perhaps more similar than the commission has explained in its order.

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I'm sorry.

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It seems more similar to Texas Eastern.

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I mean, I think just saying that something is integrated doesn't necessarily determine how the facts apply to the law.

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I mean, integrated is a statutory standard.

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So the commission,

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looked at this and again we have circumstances here again where all of the receipt points are on the existing main line.

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All of the gas will be moved on existing facilities.

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The compressor station is on the main line and then again all of the gas will move on the existing facilities.

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In that circumstance where you have a point three there is no there is no case that I know of and certainly known that

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that Gulf South decided and none that's been addressed that is anything similar to a 0.3 mile lateral and the Commission found that there was integration.

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They found that they were not integrated.

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For example,

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The situation in which the Commission finds that there is nonintegration in Wyoming Interstate, for example, and in East Tennessee, which the Commission cited, at J.A.

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198, paragraph 12.

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In those circumstances, the receipt and delivery points could be distinguished from the main line.

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So this is really the factor that matters so much to the Commission.

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Could you give me that citation?

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Sure.

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Yes, Your Honor.

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It's rehearing order J.A.

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198, paragraph 12.

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Thank you.

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And the commission explains, again, receipt and delivery points in circumstances where it's not integrated can be distinguished, and here they're not.

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Yes, there is a different delivery point, but not different receipt points.

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All the receipt points are on the main line.

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And I'm happy to talk about depreciation as well, which came up.

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The commission found that depreciation rate would

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would be determined based on the general rule because the facilities were integrated.

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The commission rejected the claim that the project functions like a delivery lateral since it will provide service to a single power plant because the record shows it doesn't function like a delivery lateral.

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Rather, unlike the delivery lateral, the project is divided by and relies on and is therefore integrated with existing mainline facilities.

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So there was no exception, either an existing exception or some new exception that Gulf South wanted.

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And as Your Honor pointed out, they didn't ask for what the normal exception would be, which would be the life of the contract 20 years.

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And that kind of shows how this really isn't a back of the envelope issue as Gulf South is arguing the depreciation rate matter.

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Because the commission would then have to say, just like Your Honor did,

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Why 35 years?

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What is that about?

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And in Section 7, initial rate proceedings, we have this general rule because things need to be done more quickly without having discussion and fact-finding regarding what is the right number.

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We already know what the right number is.

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And it's the number that was established in the 2015 settlement.

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It's the existing number that applies on the system.

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The commission was not arbitrary.

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It was very reasonable here and its determination was based on substantial evidence in the record and consistent with its policies.

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All right.

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Thank you.

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Thank you very much.

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Does Mr. McMahon have any time?

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Why don't you take a minute if you want to reply.

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The one point I do want to

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address is your view on Texas Eastern because Texas Eastern is addictive.

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In that case, what the commission was really concerned about was a two times rate differential between the expansion and the underlying interruptible transportation rate.

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Here, we have a four times difference in rates between the expansion rate and the underlying interruptible rate.

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Not today, not in its brief, not in the orders because the commission never addressed that factor and why a four-time trade was not given the similar consideration as a two-time trade.

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Thank you.