威廉斯 (WMB) 2017 Q1 法說會逐字稿

Good day, everyone, and welcome to the Williams, Williams Partners First Quarter 2017 Earnings Call. Today's conference is being recorded.

At this time, for opening remarks and introductions, I would like to turn the call over to Mr. John Porter, Head of Investor Relations. Please go ahead, sir.

Thanks, Amy. Good morning, and thank you for your interest in Williams and Williams Partners. Yesterday afternoon, we released our financial results and posted several important items on our website. These items include press releases and related investor materials, including the slide deck that our President and CEO, Alan Armstrong, will speak to momentarily.

Joining us today is our CFO, Don Chappel; and our Chief Operating Officer, Micheal Dunn. We also have the leaders of our operating areas on as well.

In our presentation materials, you will find an important disclaimer related to forward-looking statements. This disclaimer is important and integral to all of our remarks, and you should review it. Also included in our presentation materials are various non-GAAP measures that we reconciled with Generally Accepted Accounting Principles, and these reconciliation schedules appear at the back of today's presentation materials.

So with that, I will turn it over to Alan Armstrong

Great. Thank you, John, and good morning, everyone. Glad you could join us today. And I plan to keep my remarks pretty brief today to allow as much time as possible for your individual questions and also recognizing we have our Analyst Day coming up next week on May 11 in New York City.

The first quarter of 2017 demonstrated the resilience of our business as we continued to show meaningful growth and stayed on track for our 2017 guidance despite the impact of some significant third-party outages and production freeze-offs in the Rockies. Our natural gas-focused strategy continues to be on the mark as we differentiate ourselves by delivering consistent and sustainable growth on the back of low-cost natural gas demand. Overall, I'm pleased with this quarter's progress. So let's get started on Slide 2 and take a look here at the first quarter.

Starting with WPZ's GAAP results. We saw a sharp increase in net income due to higher investing income on the Permian-for-Marcellus transaction that we completed in the first quarter. Apart from the increase due to this transaction, our ongoing business performed very well, generating an increase in operating income of $141 million compared to the first quarter of 2016.

Moving now to adjusted EBITDA and DCF. WPZ's adjusted EBITDA grew over 5% compared to the first quarter of 2016. This marks 14 consecutive quarters that we've generated year-over-year growth in this measure. We delivered $752 million in DCF for the quarter, which also was up over the first quarter of 2016 and provided a strong coverage ratio at Williams Partners of 1.33.

And now let's take a look at how each of the segments did versus last year. First of all, Atlantic-Gulf delivered another solid quarter. Adjusted EBITDA increased by $48 million or almost 12% over the first quarter of 2016, now reaching up to $453 million for the quarter. There were a couple of third-party incidents on adjacent pipelines near Paradis, Louisiana, and Corpus Christi, Texas that did impact our results. Although there was no direct damage to our facilities from these incidents, both events affected volumes on our Discovery and Markham systems, respectively.

Atlantic-Gulf -- despite this, Atlantic-Gulf increased fee-based revenues by about $43 million for the quarter, and this increase was primarily driven by new projects that we brought online in 2016 and our Gulf Trace project that was put in service during the first quarter of 2017. So again, a really -- another great quarter here for Atlantic-Gulf.

Let's move on to the West, which now includes the predictable Northwest pipeline system and existing Rockies G&P assets, to which we've now added the Conway and Overland Pass Pipeline as well as large-scale gathering systems previously located within our central operating area. The broad-based portfolio underpinning the West, along with a sharp focus on cost control, delivered stable first quarter adjusted EBITDA versus 2016. Overall, the West adjusted EBITDA came in within 3% of the first quarter of 2016. We did see lower fee-based revenues mainly as a result of contract changes and 21% lower volumes in the Barnett area. The Barnett field was impacted by really little to no spending on the production over last year by our previous customers there. So we're excited to see the impact that the -- a new operator in the area, Total, $40 million-plus annual investment will have in the restoration of this production. And they really are just now getting started on figuring out exactly the best places where to place those dollars. And so really excited to work with them and increasing production there.

Despite a mild winter throughout most of the U.S., though, the West experienced some extreme weather in January that caused widespread production freeze-offs in the Rockies. We have seen a pretty good rebound in volumes as things have thawed and several rigs have returned to the area. In fact, already, our overall volumes in the West are tracking 2.4% higher than the average during the first quarter of 2017. On the other side of the coin, we experienced record throughput volumes on Northwest pipeline as a result of the cold weather in the West.

To summarize, stable performance continues in the West with Barnett stabilization, recovery in the Rockies and some growth in areas like the Haynesville, Eagle Ford, Niobrara and potentially Wamsutter Field. Look forward to it as we get into '17 and '18.

Now let's move on to Northeast G&P where year-over-year operating gathering volumes were up nearly 5%. And if you adjust for the sale of a couple of isolated gathering systems last year that gathered about 90 million a day, volume growth would have been closer to 6.5% on that same comparison.

So overall Northeast G&P adjusted EBITDA increased $2 million compared to the same period last year of -- and so $227 million as increases in the Bradford, Susquehanna, Ohio River systems were largely offset by decreases in the Utica. And so overall, our mix of revenue shifted a bit where -- to dry gas, where our total revenue per Mcf is a little bit lower than it is in those rich gas areas.

We think our Utica production is currently at an inflection point where we'll see growth in the volumes going forward. We're also seeing a pickup on well connect request across most of the Northeast as producers prepare for takeaway capacity coming online.

And now I'd like to make a few comments about our NGL-Petchem business. As you know, the streamlining of our operating areas, we've shifted certain assets from NGL-Petchem to other segments. So the first quarter of 2017 results now just include the Geismar olefins plant and our propylene splitter near that same facility.

The first quarter saw overall improvement in prices and margins for propylene and ethylene. These results were offset by lower production volumes primarily due to an unexpected failure at -- on the local utility provider system on March 12. This power failure caused a shutdown of our Geismar plant. Once the repairs were made, the plant was restarted here on April 18. So as a result, Geismar only contributed about $37 million of adjusted EBITDA for this first quarter of 2017. Overall, our NGL & Petchem Services segment reported adjusted EBITDA of about $49 million for the quarter.

And now let's move on and discuss some of the project and operational developments for the first quarter. First of all, we brought Gulf Trace into service on time and under budget. It's one of the 5 key Transco pipeline system expansions that we expect to place into service during 2017. It even contributed fee-based revenues here in the first quarter of nearly $9 million. But as you know, the Gulf Trace serves the Cheniere's Sabine Pass LNG export facility in Cameron Parish, Louisiana. A picture of that facility, in fact, is on the title slide of today's presentation. And in addition to Gulf Trace, we made significant progress on other projects as well.

Construction on the Garden State project is now underway, and we started construction on the mainline facilities of the Atlantic Sunrise project. We're continuing to work on the remaining regulatory approvals for this critical piece of natural gas infrastructure. And just this week, we updated the final permitting data required for the PA DEP 102 state permit and the PA DEP 105 permit. And that update is actually in the process of being delivered as we speak. So great work on the team's part of getting all that new data pulled together and getting those permit applications updated.

We submitted an application for a permit certificate -- sorry, for an application for a FERC certificate for our Northeast Supply Enhancement project, which is a nearly $1 billion fully contracted project that will increase the supply of natural gas to the New York City area by about 400 million a day. Natural gas demand on our systems continues to build. As evidence of the fact, we saw records on 2 of our major interstate pipeline systems, Transco and Northwest Pipeline, during the quarter. We also experienced record gathering volumes in the Northeast G&P, where we achieved a quarterly gathering record of about 6.9 Bcf a day. This represented a 7.5% volume increase for our operated gathering volumes, comparing the first quarter of '17 to the fourth quarter of '16. So really nice jump from the fourth quarter here on -- in the Northeast volumes. And we hit record natural gas liquid transportation volumes on our Overland Pass pipeline system serving the Rockies. All of this occurred despite a relatively warm winter in many areas of the country and particularly in the Northeast. We also closed on the Permian-for-Marcellus transaction, bringing our Bradford Supply Hub average ownership to about 66% as we continue to increase our preference -- or our presence in this prolific supply area.

In terms of increasing our focus on predictable fee-based revenues, we announced on April 17 the agreement to sell the Geismar olefin facility for $2.1 billion to NOVA Chemicals. This sale is expected to close this summer. I want to thank the team that's been working on the Geismar transaction and also the team that operates the plant for their persistence, diligence and their continued focus on safe operations. This transaction is one of the last remaining components of derisking Williams' revenues from direct commodity exposure.

After Geismar closes, around 97% of our gross margins will come from predictable fee-based sources. Among those predictable sources will be the new long-term supply and transportation agreement with NOVA that was highlighted in our April announcement of the Geismar sale. Williams Partners subsidiaries will provide feedstock to the Geismar plant via our Bayou Ethane pipeline system in the Gulf Coast. And looking to the balance of the year, we expect to bring the Hillabee Phase I project and the Dalton system into service as planned in mid-2017. We anticipate that the New York Bay and Virginia Southside II projects will come online in the fourth quarter, also as planned. It's certainly been a successful quarter on the execution front, and we're really optimistic about what's coming in terms of growth projects.

So before I wrap up, I want to remind everybody about our Analyst Day next Thursday, May 11, where you'll see that we're on a clear and predictable path to continue delivering leading EBITDA growth in our sector. We'll discuss in more detail the drivers that will allow us to continue delivering DCF growth while sustaining strong cash coverage and credit metrics. We'll also discuss how the financial repositioning we've executed will enable us to capture high-quality fee-based growth opportunities that are going to be funded through a mix of low-cost debt and retained cash flow. And our operational leaders will be highlighting the significant opportunities ahead for Williams and especially how our competitively advantaged asset base is so well positioned to deliver sustained growth through high-return, organic investment opportunities that are now before us.

I'm also looking forward to introducing our new Chief Operating Officer, Micheal Dunn. He's already hit the ground running, and he'll be presenting next week.

So that concludes my prepared remarks. Now I would like to pass it over to the operator so we can address your questions. Operator, let's take our first question.

(Operator Instructions) We'll take our first question from Jeremy Tonet from JPMorgan.

This is Charlie in for Jeremy. Just wanted to follow up on Atlantic Sunrise. I know you said you're in the midst of getting the second permit -- state-level permit. Were there any other requirements there? I thought I remembered there being one from the Corps of Engineers. And then just a second separate question, just on the growth CapEx guidance, $2.1 billion to $2.8 billion. Can you just remind us kind of what may cause us to hit the upper end or lower end of that guidance range?

Yes, sure. I'm going to have Mike Dunn take that permitting question here in just a minute. On the capital piece, the primary variances there is the timing of the Atlantic Sunrise and how soon we're able to get started on that project. But as well, some of the Northeast construction that -- and the gathering system that feeds into that is a bit variable as to timing as well. So it's not really a question of how much in terms of projects really. It's just a matter of the timing of those projects. And Mike, will you take the question on Atlantic Sunrise?

Sure. Thanks, Alan. The Corps of Engineers, we do have a 404 permit update to provide to them, and that will occur later this month. That's very similar to the PADEP updates that we're providing to Pennsylvania in that we're just following up with additional information, and that should be a permit received from the Corps of Engineers shortly after that. We do expect permit receipts from both PADEP and the Corps of Engineers in July, assuming everything goes well. But that's been a pretty large undertaking for our teams to make these updates, but very proud of their effort in getting those submitted this week as we anticipated.

Great. And just one more real quick, shifting over to G&P volumes in the Northeast. Just can you give a little more color on the Utica volumes that kind of caused that shift to a more dry gas exposure?

Yes. Maybe have Jim Scheel hit that question.

I think we've been pretty consistently talking about Chesapeake has moved rigs out of the Utica, specifically the Cardinal wet gas area, over the sort of last couple years. Alan referenced that we've kind of hit an inflection point. With no drilling, we've seen natural declines that have caused us to drop from our high of about 1 Bcf a day to just under 700 as we go into the first quarter. We anticipate volumes ramping up. Chesapeake is moving in additional rigs. Some of that reduction, though, on the wet side has been offset by new drilling in the dry Utica, and we see that volume increasing.

And we'll take our next question from Christine Cho from Barclays.

I wanted to start in Marcellus. We've seen a competitor JV with a producer for some processing plants. And on your acreage, we've seen 1 producer acquire 3 or 4 of your customers, and can probably become somewhat sizable with respect to production. And they've also talked about wanting to be a partner in processing. Is this something that you'd be interested in? Some color on how you think about the strategy in the Northeast going forward. Like how you evaluate whether or not to get an upfront volume commitment on your processing plants in exchange for acreage lease, like we saw with the prior deal, that may cap your upside versus taking on maybe a little more risk and having more upside, especially given the deleveraging you've done to date?

Yes. Thank you, Christine. We're always happy to work with customers that have things to bring to the table. And we certainly have continued that effort in the OVM area and really excited to see the kind of development that is going on. We're getting a tremendous amount of well connect requests that are probably coming in a little faster than we thought. And so we do think that processing capacity we have available in the OVM is very valuable. And so we want to make sure that we maximize the value of that in whatever transaction that we do. But really excited to see all the activity, excited to see EQT out there really getting active on some of that acreage that was somewhat fallow or especially underfunded. And so I think there's some real big promise coming into the Ohio River area as a lot of new activity is occurring in that area.

Okay. And then moving over to Barnett. There's been some talk about directing STACK gas volumes to excess capacity that sits on Barnett plants. Could this be an opportunity for you? Or are there contractual or logistical impediments that would prevent you from doing this? And if you could actually remind us what the residue gas and NGL pipes are out of the back end of those plants, that would be great, too.

Yes, Christine, we don't have any processing capacity in the Barnett. All we have there is gathering, compression and a dehy. So we don't have any processing facilities there in Barnett. So really not in a position to take advantage of that -- of any of that in the Barnett, if I understood your question correctly.

Okay. And then last one for me. Have you disclosed how much capacity and how long the long-term contract is going to be with NOVA?

No, we haven't. We haven't disclosed that as yet. We'll be providing some more detail around that at our Analyst Day coming up. So I do think we've said, Christine -- I do think we've said that it's for the full requirements of the plant. So -- and that historically has been 50,000 to 55,000 barrels a day depending on whether we're in ethane or propane -- or depending on if we're cracking all ethane or not.

Okay. And what's the capacity of the line? It looked like you were doing an expansion that was supposed to take effect second half of this year.

Yes, that's very dependent on where the ethane's coming in. And remember, we also have ethane supply points coming in from our Baton Rouge frac as well as at Port Allen as well from our Paradis system as well. So we can actually pick up ethane from 3 different points to supply under that contract. And so -- but it's -- the capacity is very dependent on where that production is coming in. But we did complete a pretty significant expansion earlier this year. And so we're well positioned to supply the Mississippi River with ethane.

And next from Goldman Sachs, we have Ted Durbin.

Maybe we can start with Northeast Supply Enhancement, that project. So $1 billion of CapEx. Are the returns sort of similar to what you guided to on some of your other projects? And then just remind us of the in-service date that. I think it's 2020, but thinking about timing there.

Rory, you want to take that?

Yes, I'd say the multiples -- and we

are going to do a little bit, I think, updating you in Analyst Day on the multiples of some of these historical projects that we've been doing. But I would say this is kind of in that same sweet spot. It's been a good position for us to be in. We've been able to leverage our existing system. And so the returns have kind of stayed in that range for projects where we've had some brownfield scope to them. That -- I think in terms of in-service, I thought that one was in 2020. I don't have it right in front of me. But that -- like we've been doing on all of our projects, the stated in-service dates are going to be part of a P90. And of course, our target in-service date, we're trying to beat that if we can.

Great. And then on your other -- your Southeastern Trail open season. Maybe just -- can you talk about what exactly are you doing there? Looks like it's a backhaul. How much capital associated there? And then how do we think about that relative to the sort of displacing existing contracts? Or was there actually a meaningful revenue uplift on Southeastern Trail?

Yes, on Southeastern Trail, this would be capacity that we're selling that would either be latent in the system itself because it is flowing north to south, or we'd be adding new facilities to provide that capacity. We're right in the middle of the sausage making right now on Southeastern Trail. We did have an open season. And although I'm not going to get into the details of that, I would tell you that the requests far exceeded what we have capability to offer. So we're going through the process, doing all the technical work, trying to understand what's the most efficient way to expand the system and take advantage of some of that latent capacity. And then we'll be generating rates, going back to the customer. Just haven't entered a process to settle in on an actual capital size capacity and then get the deals closed. So we're probably right in the middle of that process. I don't think it's 1 week or 2. It's -- I'd say, we're more at the midpoint in getting that sorted and settled.

Got it. That's great. And then if I could just ask one more. I think, Alan, you sort of alluded to this notion that you do have strong growth over a multiyear period. I guess I'm wondering where your head is on providing multiyear guidance. I know you use to do that, and you've kind of backed away from that. But kind of maybe even just a little bit of a preview of what we should look for at Analyst Day next week.

Yes, I think what you're going to see is, particularly in -- from each of the OA leads, you're going to see the drivers of growth and the leverage, for instance, the operating leverage we have in the Northeast and what volumes mean to us in terms of EBITDA there. You'll also see a little more portfolio of the kind of opportunities we're pursuing in -- along the Transco system. And then finally, you'll see some -- in Don's presentation, you'll see some of the drivers of growth into '18 as well. So we're not going to be providing guidance like we used to. But we are going to be putting some pretty specific terms out there on what those drivers are and give you a lot better opportunity to make your own assessment.

And we'll hear next from Faisel Khan with Citigroup.

It's Faisel from Citi. Just a little more clarity on the Geismar feedstock agreement. Are you doing anything different in that agreement than what you were doing before for Geismar? I'm just trying to figure out if there's a net uplift to your cash flows from your logistics -- provider-level logistics contract versus what you were doing before.

Yes, that's a -- there's a really, really complicated answer to that, Faisel. Well, let me just say that we did have -- in before, we did have both the cost of operating the pipeline and we had revenues. A lot of that just showed up, if you will, in -- coming out of the margin of Geismar. So it's a little bit complicated when you think about trying to pull out the Geismar revenue. I will say, though, that we do expect a pretty modest uplift in revenues from that transaction as a result of it. So we'll provide a little more detail and color on that at Analyst Day. But it is a positive for us, and it will be showing up now as third-party, fee-based revenue and dropping all the way to the bottom line where previously, it kind of would've been buried in that Geismar margin.

Okay, got it. And then on the balance sheet, now with the sales that are under way, what's your expectation for consolidated EBITDA at the end of the year for the entire company?

Don?

Faisel, we don't have an update for you today. But obviously, it's coming down. I think we indicated that we would use the proceeds from the Geismar sale to pay off the $850 million term loan and prefund the CapEx. That's still the plan. You can run the numbers. We'll provide some additional commentary next week, but we don't have any guidance update per se.

Okay. And then last question for me. Can you give us an update on all the legal battles that are taking place, one with -- your first one with Energy Transfer, how that -- when do you expect a sort of a decision? Or how's that's going? And then also on Constitution, how is that appeal process sort of trending?

Sure. First of all, on the ETE piece, there was a hearing around the process -- discovery process on that a couple of weeks ago, I guess. And so that the judge came back and said he wanted to consider that a little further in terms of what that discovery process, and so there's motions coming forward on that. So that wages on, if you will. On the Constitution piece, we continue to work with the administration on that, continue to feel good about that. And as well, the court process continues on Constitution as well. And so Constitution, we feel like is an upside to us, but we're optimistic that there's a lot of people, including the unions have been a big support for us on that, labor unions, who really want to see projects like that go forward. And of course, the State of New York's denial on the 401 certificate for Northern Access for National Fuels also turned the heat up a little bit on this issue as well. And so -- which appears to be a pretty similar situation. And so I would say that the pressure is mounting on the issue, and you've got projects there that are both important to New England and to New York as well as important to jobs and getting some of the regulatory morass out of the way of getting the infrastructure built, all of which is a top priority for the administration. So I feel like we've got a lot of people on our side on that, and we're going to continue to push forward on it.

But there's no date on the appeal process of when that will conclude for that -- for Constitution?

No, there's not. But we are thinking it's in the not-too-distant future, though. So -- but if things go like we would expect them to.

Next, we'll hear from Craig Shere with Tuohy Brothers.

Picking up on Faisel's questions around the long-term feedstock agreement using the pipeline heading into Geismar. If I understood that there was the possibility that pipeline might be sold as a part of the Geismar asset divestiture, could you talk through the thinking behind retaining the asset and signing a long-term agreement and maybe its impacts from a tax standpoint long term, accretion benefit towards Williams?

Well, it's certainly very positive for us. We're really excited about the transaction because it did allow us to obtain very reliable, long-term fee-based revenues out of the transaction. And so we're really excited about what that looks like and the terms of that contract. So we think that was a very smart transaction in that regard. There's really nothing much more complicated than that, frankly, about the transaction other than the fact that it allowed us to retain some fee-based revenue. We do have other customers on the system, and we think that system is extremely well positioned to continue to expand as our customers expand. And so we're really excited to be able to serve NOVA. And of course, they've got big plans for expansions in the Gulf Coast. And we want to be there and be a good, reliable provider to them and grow with them. So I would say it's really nothing more than continue to have stable fee-based revenues and taking -- and retaining a bit of that, if you will, out of the Geismar EBITDA.

Do you see expansion upside on the pipeline system there within -- announced maybe within the next couple of years? Or is that very hazy longer term?

There are some opportunities as some of the projects expand there in the Beaumont/Port Arthur area. But we don't have anything that we're planning to announce here in the near future.

Okay. And one question on the quarterly impact from those third-party outages affecting Discovery and Markham. What would you estimate the proportional EBITDA effect of that was?

I don't know that we've disclosed that. I'll tell you more specifically what it amounted to as it took quite a bit of volume out of Markham that gets fed up from some of the Eagle Ford volumes that gets fed by a competitor's pipeline into Markham. So it took some of the volumes out of Markham, the rich gas volumes coming into Markham. And on the Discovery system, even though it didn't impact our volumes, it actually shut down the whole system for, I think, 4, 5 days.

Six days.

Six days. So we lost 6 days of Discovery in the quarter, which is pretty significant. And so it wasn't just the processing and fractionation facility. It took the whole facility -- the whole system out for a bit. So anyway, great job by our team of helping the third party there safely recover and getting our Discovery system. We were able to move some volumes around and keep some of our customer volumes flowing, but it certainly impacted our revenues pretty significantly on Discovery in the quarter.

And from U.S. Capital Advisors, we have Becca Followill.

On the Northeast gathering, the unconsolidated volumes were up about 11%, yet equity earnings were flat. Was that due to what you talked about, Alan, with the shift to dry gas versus wet gas and the lower margins? Or why don't we see a pickup in the equity earnings there?

I'll ask Jim Scheel maybe to take that. Do you follow the question?

Yes, I guess, just coming in. We didn't really have a decline of 11%. We had some systems that were off. But overall on our consolidated volume, from a -- let me --

Well, actually, Jim, I said that it's unconsolidated volumes were up 11% yet equity...

Oh, upward.

Yet equity earnings were flat. So why the disconnect?

Yes, again, that really goes back to the base story that we just talked about, which is the Utica volumes were down primarily, and those were offset by higher volumes in the dry gas areas, primarily around Susquehanna Supply Hub and Bradford. And so those balanced out effectively from an EBITDA perspective, and we were able to overcome those volume decline on an EBITDA basis.

So the -- remember, Becca, the Barnett system shows up in that unconsolidated numbers, and so growth on Bradford.

The Bradford area, yes. And then UEOM is the big Utica system that's in the unconsolidated that would be part of that lower Utica volume story.

Okay. So it's the wet versus the dry gas margins then.

Yes, that's exactly right.

And then on the West, you talked about a couple of things impacting you, one being weather in the West. Talking about on volumes being down 8% year-over-year. One was the West and the other was Barnett. Can you quantify how much of that was Barnett?

I don't think we're showing that level of detail. What we did report and I'd even follow that through. But we did show a 21% decline, as I mentioned in my comments, in the Barnett. So it's a pretty significant decline in the Barnett.

And from BMO Capital Markets, we do have Danilo Juvane.

Most of my questions have been hit, but I did have a couple of follow-ups. So on the Atlantic Sunrise pipeline, the second half start on the mainline, have you quantified or will you quantify at the Analyst Day what that EBITDA impact will be?

We have not given detail on that. I would say stay tuned for our Analyst Day, and we'll give you a little better idea there at Analyst Day, kind of the full package on that.

Appreciate that. And secondly, on the West segment, there was, I think, a G&P contract restructure with a producer. Did that have anything to do with the shortfall relative to last year?

Well, in the Barnett, it certainly did because of the -- we were fixed on our MBC based on what the cash we got paid last year. So that restructure of Barnett was the most significant. There was -- so -- of the restructure, that was the biggest. And sorry, on -- maybe I didn't understand your question. On LINN Energy, we did have them reject a processing contract that we had at OPPL as well. So it's fairly low-margin contract, but they (inaudible) input volumes (inaudible) in the West.

Okay. But to your point, the biggest driver was the Barnett restructuring.

Yes, right.

We'll now hear from Chris Sighinolfi from Jefferies.

I just had a couple of follow-ups. I appreciate all the color on the supply agreement to NOVA. It's helpful. I was just curious. Given you said that the 37-day outage in the quarter was attributable to a local utility provider issue, just curious, and maybe it's a moot point with a sale pending, but is there any recovery on that if it was a third party responsible for it?

We wish. But no, there is not any avenue for recovery on that.

Okay. Okay. And then second, just sort of more thematic, which I'm assuming this will be addressed at the Analyst Day. I know we discussed it in the past, but just would appreciate any updated thought on -- we hear a lot this earnings season and over the last several weeks and months about producer activities in sort of prolific shale plays that may have high associated gas cuts coming with them, and just what that might mean for domestic natural gas supply demand. And in turn, what that might mean for Transco expansion opportunities into the southeast Gulf Coast markets. I'm just curious if that is a legitimate concern for sort of your legacy avenue of growth. Or I guess, if you could speak at all about sort of the appetite for like the next tranche of expansions beyond those that we know. Is there any change in counterparties' view on what they've been asking you guys to construct for them given that change in producer activity? Or is it consistent with what you've been experiencing to date?

Yes. No, I think about people -- if you're thinking about -- if you're a buyer of natural gas -- if you're a big LDC and you're converting over to gas off of coal, or if you're building an industrial facility, you likely -- if you're in that pathway, you really want to connect to something that's a long-term, low-cost supply. And so we continue to see that dependence, and people really looking at those low-cost supplies as something that they would much prefer to connect with, either through long-term gas purchase contracts that we've seen quite a bit of and where a producer knows what they can produce and the cost they can produce at. I think if you're -- if that's the business you're in, you really want to be focused on something that's not at the whims of oil prices in terms of development. And so I think that what we're seeing is a very consistent theme, which is people continuing to focus on the very low-cost resources and being able to contract through for those for their long-term dependence on that fuel. So I'd say things remain very healthy there, and we continue to see a lot of demand. As Rory pointed out on our Southeastern Trail, we're kind of sometimes shocked by the degree of demand that we're seeing in trying to get gas out of these very low-cost resources into these growing markets.

From Raymond James, we have J.R. Weston.

You mentioned during the prepared commentary the positive weather impact on the Northwest pipelines' throughput for the quarter. Just wondering how to think about the progression there for the rest of the year. And then I think in the 4Q materials, there kind of some mention of some longer-dated projects up in that region. Just wondering if there's any type of update there.

Yes, sure. I'll take that first, and then I'm going to send that second part of that to Walt. But on the first, the good news and the bad news on these fully contracted pipelines, there's just not that much variability. We did see a little bit of uplift in IT revenues on Northwest pipeline. But when you have these fully contracted pipelines like Transco, Northwest and Gulfstream, you just don't see much movement in -- from quarter-to-quarter other than a little bit of IT revenues because they're fully sold out versus some of the pipelines -- some of the other interstate pipelines you see that are more dependent on actual volumes flowing. And so our volumes are up, which is healthy because it says that there's demand growing in the systems which ultimately leads to expansions. But in terms of what the revenues we take in, it really doesn't move all that much, as you can see looking at history. And Walt, maybe you'll take the question on the longer-lead projects.

Sure. Thanks for the question. In terms of the projects on Northwest Pipeline, we do have projects that we're pursuing right now with our customers that are increasing lateral capacity to serve them, and we're going to give some more detail around that on Analyst Day. But that will be a little bit of an uptick when those get built in terms of the lateral fees and has really essentially optimized all the capacity on the existing mainline capacity in Northwest pipeline. And so beyond that, what we see is that as additional demand comes on, then we're going to be also looking at working with our customers on increasing mainline capacity on Northwest, which will be a good uptick in revenue on Northwest. And we'll be providing some more color on that on Analyst Day.

Okay, great. That's helpful. I guess just one more for me, kind of switching gears quite a bit. But just with the Geismar transaction announced now and there was all the other positive steps that you've made over the last year or 2, I was just kind of wondering what else is going into the equation moving forward, even just anything kind of from a thought process perspective as you're looking at the dividend, the distribution growth outlook, especially at WMB where the guided range is a little wider fairway at 10% to 15%.

Yes. Well, obviously, as we continue to execute well, that would move us towards the upper end ultimately on that as we continue to execute well. But I think in terms of the question around what we do with excess cash, certainly the first thing we've talked about is taking down the revolver debt at WMB. That's really about the only thing we can easily take out in terms of debt at WMB and well on our way to doing that. But beyond that, we'll determine -- when we come to that point and we got that down, then we'll determine what we think the very best use of that cash is from a shareholder perspective. And so that will be a consideration towards the back end of the year likely.

And from UBS, we do have Shneur Gershuni.

Just a couple questions, and I think they're kind of a bit of follow-ups. For starters, and I think Chris kind of touched on this a little bit here. But when you've got the amount of gas that's coming out of the Permian basin and sort of starting to impact spreads and so forth, how do we think about the competitive nature of the Marcellus, which needs to obviously move gas down there? Do you think basis does contract and presents an opportunity? Or is there a risk that, that step-up that we are all hoping for doesn't materialize because of all the production downstream? When I look at spreads further out, it looks like it does contract. But I'm kind of interested in kind of your thoughts about it.

Yes. I think certainly, with all the new pipeline capacity that's underway and systems like ours that are fully contracted, the pipeline capacity is getting built. As you'll see in our presentation next week, there's also a lot of power gen demand coming on for the Northeast as well, right within the circle of pain, if you will, where people are trying to take advantage of all that low-cost supply in the power generation market. So we think very positive things in terms of demand for the Northeast is coming. And I think -- as I mentioned earlier, I think the big, long-term gas demands really want to try to take advantage of the low-cost -- big low-cost supply. And even if you get out on the outer end of ranges that I've seen of around 5 Bcf a day of incremental growth through 2021, it's just not near enough to really stay up -- from the Permian, excuse me, it's just not near enough to stay up with the kind of demand growth that we're seeing in the balance. And so we'll hit that next week in some detail, but I would just say that the kind of demand we're seeing come on is really going to take a big low-cost gas resource, like the Marcellus and the Utica, that people can count on that production being there through the valleys and peaks that tend to occur in the oil business. So we think the Marcellus and Utica certainly established itself as the supply basin for a lot of this incremental demand, and it's really the only one that can come on with that kind of scale.

That definitely makes sense. And then you completed some offshore investments last year. Just wondering if you can sort of give us a sense of how they're running at this stage right now. Is there a further ramp? Just any color on how we think about how they're doing and where they're going at this stage.

Rory, take that.

Yes, I'll take that. Maybe starting with Keathley Canyon Connector, that facility is running fully loaded. The South Hadrian gas field and Lucius are making up most of the volumes in there. But it continues to run fully loaded, and our downstream plant at Larose is running right at nameplate capacity. So great performance there. I would say over in the eastern Gulf, some other noteworthy projects that we've had over the last couple of years are our Gulfstar project. And I also would characterize that as a bit of a slow start. The operator had some challenges, downhole challenges and others, some subsea or a downhole valve litigation that was all part of that. But the fields actually, the Tubular Bells field and then that tieback that we made at Gunflint, those are really starting to line out and produce nicely. In fact, a couple of days ago, we hit 50,000 barrels a day through the facility. It's been averaging a little bit below that, but it's performing very well. I would say this year, it's really hitting its stride, performing better than it did last year. The other thing I'll mention, we had a tieback to our old Devils Towers spar with a field called Kodiak. It was a one-well tieback, and they recently recompleted into another zone. So it's being comingled. And they almost doubled production out of that well. So really good performance over in the eastern Gulf. Of course, there are always declines in -- but I feel like this year, the operations have -- not only on our side but on the producers' side, has kind of hit their stride, and we think that's pretty solid.

And we do hear from Brandon Blossman with Tudor, Pickering, Holt & Co., and he's next.

I have a couple of quick ones. One, we're hearing some producer -- renewed producer interest in Powder River Basin development. Any thoughts in terms of trajectory for you guys going forward there?

Sure. Walt, you want to hit that?

Sure. Yes, we have seen some renewed interest in that area on our Jackalope system. And this year, this has been included in some of the guidance in -- that -- some of the public statements. But anticipate a number of wells coming on in that area with some -- 2 or 3 rigs that are going to be working that hadn't been in the area previously and also exploring some new formations, the Sussex, the Turner and the Parkman. So that brings some optimism to that area, and we're looking forward to seeing the results of those wells. And hopefully, we'll have a strong growth trajectory from there.

And then broader picture. So Gulf Trace, under budget. Any thoughts about where we are today and expectations for the future in terms of pipe or

labor costs inflation?

Yes, good question. I would say on our major projects that we have right now, we're under construction. And some of the big projects, like the (inaudible) project that Rory talked about earlier, pretty unique labor set there because you're right in very heavily congested area and you're in some of -- quite a bit of that work is actually in Raritan Bay in offshore. So pretty unique contractor set that will be on that project. But overall, I would say our team's done a really good job of anticipating a lot of increase in construction and have done a good job of getting out in front of that in terms of contracting. So we feel pretty comfortable there right now in terms of how we're positioned. But certainly, we could see some pressure in the large-diameter market as some of these big projects, like Mountain Valley and Atlantic Coast pipeline start -- and Rover start to take hold.

That concludes today's question-and-answer sessions. Mr. Porter, at this time, I would like to turn the conference back to you and the other speakers for any additional or closing remarks.

Great. Well, thank you all very much. Appreciate everybody joining us today. Really excited about the way the team's executing, and really excited about the prospects ahead of us. And we look forward to talking to you about that next week. So thanks again for joining us.

This concludes today's conference. Thank you for your participation. You may now disconnect.