Western Midstream Partners, LP (WES) Q1 2017 Earnings Report, Transcript and Summary

Good day and welcome to the Western Gas First Quarter 2017 Earnings Conference Call. All participants will be in listen-only mode. [Operator Instructions] Please note, this event is being recorded. I would now like to turn the conference over to Jon VandenBrand, Director of Investor Relations. Please go ahead.

Thank you. I am glad you could join us today for Western Gas' First Quarter 2017 Conference Call. I'd like to remind you that today's presentation includes forward-looking statements and certain non-GAAP financial measures. Please see the WES and WGP 10-Ks, and other public filings for a description of the factors that could cause actual results to differ materially from what we discuss today. In addition, I encourage you to read our disclosure on forward-looking statements as well as the non-GAAP reconciliations in last nights' earnings release and the slides that we will reference on this call. These materials are posted on the Western Gas website at www.westerngas.com. With that, I'll turn the call over to our CEO, Ben Fink. And following his remarks, we'll open it up for Q&A with Ben and the rest of our executive team. Ben?

Thank you, Jon. Good morning, everyone, and thank you for joining us today. During the quarter, we began executing the largest capital budget in our history. As a reminder, roughly 85% of our expected capital budget of $900 million to $1 billion is focused on the continued build-out of our Delaware Basin infrastructure. Ramsey VI is scheduled to come online in the fourth quarter of this year, with Mentone I and II expected to come online in the second half of 2018. Additionally, we continue to expand our Delaware Basin gathering footprint by placing over 40 miles of new gas gathering pipelines and 32,000 horsepower of compression into service. By the end of this year, we expect to have placed a total of almost 290 miles of new gas pipelines into service. This infrastructure build-out is supported by accelerating activity from Anadarko and third party agreements which now represent over 500 million cubic feet per day of volumetric commitments and over 150,000 dedicated acres. As we discussed in the past, the additional processing capacity in the Delaware should require more residue gas takeaway. We now believe our participation in such a solution will arise from our sponsor's ability to negotiate an equity option to participate in a non-operated project. As we discussed on our last call, sustainable distribution growth is now our primary objective as a large cap MLP. In the first quarter, we closed the DBJV-for-Marcellus asset exchange, a transaction which we believe will enhance our ability to achieve this objective in 2018 and beyond. In addition, Anadarko closed the sale of its Eagleford and Marcellus assets during the quarter and we therefore expect increased drilling activity behind each system. Maintaining financial flexibility is also a key part of our strategy and the deleveraging effect of the conversion of our preferred units supports this goal by eliminating the need for common equity this year. Turning to our first quarter results, we reported adjusted EBITDA of $255 million and distributable cash flow of $216.5 million. These results include $5.8 million of business interruption insurance recoveries. Sequential adjusted EBITDA declines are quite rare for Western Gas, so I'd like to take a moment and explain the key drivers behind our quarterly performance. First of all, as we discussed last quarter, in 2017, the accounting treatment of the Mountain Gas fixed price agreement changed, lowering our adjusted EBITDA by approximately $6 million. The second largest driver was the performance of the Williams operated Marcellus interest. The gathering rate on the largest underlying system, dropped by approximately 20% due to a cost of service rate reset. This impact combined with the March 17 closing of the DBJV-for-Marcellus asset exchange represents about $5 million of the sequential decline. Just to be clear, we no longer own an interest in the Williams operated Marcellus system as of March 17. The final variance driver that I'd like to highlight is that cash distributions from equity investments were lower by approximately $5 million. This was primarily driven by lower volumes at Mont Belvieu and Front Range returning to a normalized distribution schedule. Despite the conversion of 50% of our preferred units into common, our coverage ratio for the quarter was a healthy 1.15 times. While we expect this to compress due primarily to the additional conversion of our remaining preferred units this month, our longer-term coverage ratio target of 1.1 times of higher remains unchanged. Our natural gas throughput decreased slightly as a growth that our Delaware and DJ assets was offset by the impact of the DBJV-for-Marcellus exchange as well as the claims of the Granger Straddle plant and on the Springfield gas gathering system. The decline included natural gas liquid throughput was driven by the Springfield, Mont Belvieu and Texas Express Pipeline assets. As a reminder, in the second quarter this metric will include our two produced water gathering and disposal systems, which was scheduled to come online in this month. Our adjusted gross margin per Mcf for natural gas assets was flat with the previous quarter, and our adjusted gross margin per barrel for crude and NGL assets was $0.17 lower than the fourth quarter of 2016. This sequential decline was driven by the return to more normalized distributions at Front Range, and lower Mont Belvieu distributions per barrel. Turning to our outlook, our 2017 adjusted EBITDA guidance range is unchanged despite the fact that are internal forecast is now approximately 1% lower due to our renegotiated agreement with producer that is filed for bankruptcy behind our Granger complex. With respect to Anadarko decision to shut-in vertical DJ basin wells last week. It's simply too early to discern the financial impact to WES, if any. Based on what I know today, I do not believe there will be any need to adjust our guidance range. Also please note that we are now increasing our range of potential business interruption insurance recoveries to $30 million to $49 million. There are no changes to our ranges for total capital expenditures, maintenance capital expenditures, or WES distribution growth. As for WGP, we have increased the top end of the range to 19% from 18%. For 2017, we believe, we will be add or near the top end of this range. In summary, our first quarter was in line with our internal expectations, and was a quarter in which we completed critical steps towards our objective of sustainable growth. As I look at the remainder of 2017, I'm particularly encouraged by our forecast for the second half of the year. As we expect meaningful growth in the Delaware and DJ basins due to the rig count increases, we saw in late 2016 and early 2017. With that, operator, I'd like to open up the line for your questions.

We will now begin our question-and-answer session. [Operator Instructions] The first question comes from Kristina Kazarian of Deutsche Bank. Please go ahead.

Good afternoon, guys.

Hi, Kristina.

So quick question on exciting on the residue gas takeaway, and you guys have been talking about this for a while, there are couple of different alternatives that has been proposed out there. Can you talk about just maybe and I'm not going to ask you which one, but you talk about what mix for most compelling investment in a pipe? Or how APC would think about allocating your volumes, and what would be most attractive on the WES side, when you kind of assessing what to be maybe be a part of?

Sure, Kristina. This is Ben. I think the way you think about it is, our belief in the Waha optionality, if you will is unchanged. And our focus has been on getting a solution from the Delaware to Waha, as you know number of these new projects have Waha as a terminus. I think what we are finding is that there are other parties they have existing infrastructure at Waha. And it may be a better solution for our customers to partner someone who has that infrastructure as opposed to building new infrastructure or paying an interconnect to tie into that infrastructure. So hopefully, that's helpful.

Very helpful. And then, there is my second question would be, we've talked in the past about ability to attract third-party volumes onto your systems. In a variety of forms maybe you can just talk a little bit about the opportunities are there over the next 12 to 24 months, and how you're thinking about that?

I think it's quite robust particularly in the Delaware. On the Gathering business, if you have a sizable footprint, you have natural advantage into tying in third-parties, because it's simply less steel you have to lay to tie in that party as opposed to someone who doesn't have as much strong claim and infrastructure. And I think we'll have that advantage on gas, oil and going forward even water. I will remind you that today on the processing side in the Delaware. Our processing business is virtually all third-party, Anadarko represents 5% less - less than 5% of our processing volumes. Obviously, if they move to pad drilling at the end of 2017, we expect that percentage to grow significantly. But we love the fact that we have a really solid base of third party processing business today. And this whole other leg of the stool if you will, coming in 2018 in terms of the Anadarko inflection in production.

Perfect. And then last one for me. Ben, progress on looking for CFO?

Tons of progress, and I expect an announcement in the near future.

Sounds great. Thank you. Nice update, guys.

Thank you.

The next question comes from Brandon Blossman of Tudor. Please go ahead.

Yes. Good morning, guys.

Good morning.

Let's see, Ben, back to the residue gas, I want to make sure that you've divulged all the details on the takeaway project that you're willing to do today. Any color on timing or size of the obligation there?

No, because - as of today, there's no obligation, there is conversations, we've talked in the past that we see potential pinch points in 2018. So it is a near term priority, but there's certainly no specific project that is announceable at this point in time.

Any color or guidance as to when you might think that it's reasonable to reach the finish line on those conversations?

I would say more likely than not, by the time we get together next quarter there'll be something to talk about. I think that's a fair assessment.

Perfect. That's what I was looking for. Thank you on that. Have a just broad question in terms of construction progress on the three processing plants. Any cost inflation, any issues with labor in the basin, yet?

Now I'm going to hand it over to our COO, Craig Collins to talk about that. Craig?

Yes. We're making a really good progress on Ramsey VI. The mechanical components of that project have by and large been completed, and we're focused on getting the electrical and instrumentation components installed from now until through the end of the summer until we - to get the plant finished and ready for startup in the fall. And as to Mentone I and II, we're still early stages, but the long lead equipment has been ordered and in terms of cost inflation. We really haven't seen much in the way of an increase there. It hasn't come down a whole lot, but in this environment with operators picking up rigs, you always worry about cost inflation. And we been able to hold cost pretty stable as to these processing facilities. And I would just go a step further, and talk a little bit about the pipelines that we're putting in this year, we're putting in as noted in the opening remarks, several hundred miles of pipeline and the majority of that pipe was ordered early in the first quarter before there were some price increases that kind of rolled through the market. And so we feel like at least for our 2017 program. We got an early jump on that and are pretty well positioned.

Yes, Brad. Craig is being humble. Craig and his team did a great job of ordering most of our steel in advance before the recent price increases.

Good news. And I appreciate all of the detailed color. Last question, so you're bumping up GP guidance or the top end of the distribution growth guidance, any color on the driver there?

The conversion of the preferred is the key driver. That's over 20 million common units that are going to be resultant from that conversion and that that obviously helps WGP.

And then, that was finished yesterday, is that correct?

It finishes this week.

Okay. All right. Thank you. That's all for me.

The next question comes from Jeremy Tonet of JPMorgan. Please go ahead.

Good morning.

Good morning, Jeremy.

Ben, just wanted to follow-up on Permian gas prices a bit here. We've seen the Waha basis really kind of expand a bit. I was just wondering if you could share any thoughts as far as what stops that from widening out? And what opportunities that might present for you guys?

Well, Jeremy, we're somewhat indifferent because it - we're most tied to the drilling activity of our customers. And that seems to be much more highly correlated to the price of WTI than it does gas no matter what the basis is. You're seeing a lot of projects come online, right? And as you have more takeaway options from the Waha Hub, that should affect Waha basis. But in terms of our development plan and the key drivers for WES, I don't see much correlation at all to the basis differential there.

Great. That makes sense. And then, you mentioned kind of equity interests in takeaway pipes that APC could take ownership stakes in, in the coming future. Just wondering, if that just for the Permian or if that DJ as well on the gas side, or any other color that you could share on your thoughts there. That would be great?

Absolutely, and I appreciate the question. I've said time and time again, I believe Anadarko is the best sponsor in the industry, and one of the reasons - of the many reasons I believe that is they have the commercial wherewithal to request an equity interest in an infrastructure project that they are committing volumes to. You saw that with White Cliffs, you saw that with Texas Express, you saw that with Front Range, you saw that with Mont Belvieu fractionators. So it is very much in their DNA that if they're being asked to commit volumes to a pipeline to see if they can get an interest in that pipeline. If they are successful in doing so, we've had instances in the past where they've built it out, drop it to WES. We've had instances where they just basically transferred that option to WES, and had WES incur the capital, and there's been options where they negotiated a rate that was so skinny that we thought it was in the best interest of the partnership not to exercise the option. So really all three are in play, but that certainly creates a lot of potential opportunities going forward as you start to analyze Anadarko's position, and their ability to be a key shipper on some of these new pipes.

That's a really helpful color. That's it for me. Thanks.

Thanks.

The next question comes from Andrew Weisel of Macquarie. Please go ahead.

Thanks. Hi, everybody. First question, just to clarify, I think you said your internal forecast for this year, EBITDA was down about 1% from a renegotiated agreement. Should we think about it as a one-time hit? Or would that be more of a slightly lower run rate beyond this year?

Yes, I would consider it a run rate. And I'm happy to give you a little more color there. What we had behind our Granger system, which service Jonah, Pinedale, is a producer that - for which provide processing services that filed for bankruptcy protection. In that, when they were looking at their contracts, they were delivering us to - delivering processing to us. The gathering system that delivered that gas to us was also connected to other processors with excess capacity. And so to enable to keep that business and keep that relationship, we renegotiated a rate lower than what we previously had. Now that doesn't have a material impact on our business. As I said, it only takes down our 2017 forecast by 1%, but that's going forward, right? I don't expect that rate to increase to previous levels.

Okay. Thank you for explaining. Next question on capital spending here, so as your CapEx rises. How should we think about your appetite for M&A, historically it's been lumpy of course, but more or less 50-50. Should we think of M&A dollars dropping as your expansion spending rises or to be more of a percentage change? And that's both third party and dropdowns I'm talking?

It's a great question, Andrew. And I can see, why you're assuming some historic correlation there, but there isn't one. And what you need to realize is that in the past, our primary focus of growth was through drop down. And by the past, I mean, kind of the 2008 to 2013 range. It was really in 2013 or actually 2012 where we really started to put a lot more organic capital into the portfolio. Where we are today as a large cap MLP is we've got a ton of organic capital in our budget, you know our budgeted figure of $900 million to $1 billion. And so our goal is to not touch that drop down inventory unless needed. If we can achieve our desired growth targets solely with organic projects, that's what we're going to do, because as we said in the past, if you ever get into a situation like you got into 2016 where that organic growth looks like it was disappearing, you want that safety net of a dropdown inventory there. So that's how to look at it vis-à-vis organic versus drop down. On third party M&A, the assets that have always been really attracted to us are assets in areas where we feel it's highly strategic to our sponsor, where we feel we're buying infrastructure that we would potentially would need to build over time anyway. And our risk mitigation in that M&A if you will is to be able to bring our own volumes to the system in case the third parties don't show up. And so we'll continue to look at opportunities like that. Those have been attractive to us. They always will be attractive to us, really no matter what our organic capital budget is. So I hope that's helpful.

It is, yes, thank you. Then one last one, this might be a tougher one, a question on the house explosion in Firestone. I know you mentioned it's early to discuss the impact. My question is, between you and Anadarko, who owned the line from the well to the tank battery? At what point in the chain could there potentially be a liability for Western Gas as opposed to Anadarko? And then, who owns the line from tank battery to the local processing facility?

Okay, I appreciate you need to ask the question. And first and foremost, let's just not forget, this is a tragedy, and all of our feelings go out to the families involved. The direct answer to your question is there's no WES infrastructure involved in the incident. There aren't WES lines near that location. So if you're worried about direct impact to WES infrastructure, there is none. Don't know if you meant to - if you were looking for a broader impact, I'll tell you what I can, which admittedly isn't much. Anadarko shut in its vertical wells, 13,000 barrels a day. We estimate the gross gas production of those being about 67 million cubic feet per day. Now, obviously, WES doesn't gather all of that, so the impact to the WES will be less. Too early to tell what the impact will be to WES there. There have been instances in the past, where vertical wells got shut in and the horizontal wells just flowed more. But again, it's too early to tell if that will be the case in this instance. So let me stop there and see if you have any follow-up.

No, that's great. I appreciate the detail. And I agree that it's very unfortunate accident, very tragic to hear, but appreciate the commentary you're able to provide. Thank you.

The next question comes from Shneur Gershuni of UBS. Please go ahead.

Hi, good morning, Ben.

Hi.

Lot of my questions got asked and answered. Just one sort of like kind of housekeeping type question, in your prepared remarks you mentioned how the first quarter was in line with your internal objective. And you sort of have this string of beating the Street. And the first quarter was kind of disappointing relatively speaking. But if I remember correctly, you had in some of your slides that there was kind of like a $32 million step-down with respect to the asset swap that you had executed with Williams. Is it fair to say that the cadence of 4Q 2016 to the quarter that was just reported and then how we move throughout the year has always been contemplated and nothing is really off path and you're expecting a second half ramp? Or has anything changed kind of as a result of the first quarter.

It's an excellent question, Shneur. And no, nothing has changed. This was always going to be driven by buy back half of 2017. And I think we made some comments last quarter. The key driver of that is the DJ Basin. And just - and I'll talk about the swap you referred to in a minute. But let's keep in mind our largest customer there ran one rig for most of 2016. The accelerated activity levels at the end of 2016. But just due to pad cycle times, you're not going to see the impact of that for 4 to 6 months. And so, I think we're all reasonably confident in that there'll be material growth in the second half of 2017. That's our largest asset. That's one of our most profitable assets. So that very much shapes the course of our year. You're correct that DBJV Marcellus exchange has an impact, we've already disclosed what we thought the impact in 2017 will be keep in mind, we think this will be accretive in 2018 and beyond. And that's not only EBITDA, that's that volumes as well, Shneur, right, because you're taking an asset - a very low margin asset in the Marcellus that was running over 700 a day, right. And you're swapping out for a very high margin asset in the Delaware that's running call it 120 to 150 a day, right. But obviously, we believe the growth rate of the Delaware is exponentially higher than that of the Marcellus asset. So you're seeing on the throughput line, you're certainly going to see that next quarter, when you see a full quarter impact of that trade as well. So I think those are the key drivers, also keep in mind in the Delaware, which is our area of greatest growth is that. The first half of the year is driven mostly by operator capture, Anadarko said it believes it's on pace to capture about 70% operatorship of its gross acreage. And it's not until the end of the year, where they really move to a pad drilling, which is more a manufacturing type operation. And that from a midstream perspective is where you really see an inflection point in terms of volumes. So hopefully there's an answer to your question in there.

No. It does perfect there, really appreciate the color.

Sure.

The next question comes from David Amoss of Heikkinen Energy. Please go ahead.

Good morning, guys. In the Delaware Basin specifically, obviously, there's a big opportunity there longer term to continue to build processing. Just curious, Ben, if you can walk through the strategy to capture third-party into the excess capacity that you may have in the future. And then how do you think longer term about the full build out of the Mentone facility, anything you can say about the timing past the first two trains?

Well, I'll answer - Well, first of all, good morning, David. I'll answer your last question first is that probably too early to talk about anything beyond Mentone II. But certainly, it's something that we talk in the hallways about quite a bit. But we're not far off along to make any type of announcement on this call. I think our strategy vis-à-vis third party is what it always was. Keep in mind that our entry into the Delaware Basin is a little different than it had been historically. I think historically in other basins, we're following the Anadarko build drill bid, and building enough capacity for third parties as well. And what we're finding is that if we can have service levels, and run times, and liquid recoveries that were good enough for Anadarko, they were good enough for third parties as well. And I think we were proven right in a lot of areas. In the Delaware, most notably, through the Nuevo acquisition, an acquisition which frankly is looking better and better with every transaction that's been cleared in the Delaware. We started with a really high quality third party book of business, and really high quality acreage dedications. And what our team has done, and you see it in the slides in our investment presentation is done a great job in a moving a lot of contracts to firm volume commitments. As we said, that was a key approach once we've bought Nuevo, and we went - we're now up to over 500 a day a firm. And then taking the acreage dedication, and doing what we can with that now we're up to over 150,000 dedicated acres. The Delaware Basin is highly competitive there are a number of RSPs every week or two that are out there. We are very, very competitive, and as I mentioned on earlier question part of the reason we think we're very competitive is just because of the size and significant of our footprint, which enables us to offer an integrated gathering and processing solution competitively.

Okay, thanks. And then on the earlier comment about potential dropdowns and the change in thinking that that's really more of a safety net, but it is a growth engine going forward, because you have the organic opportunity. So we - can we think about that is it will impact the price that you'll pay for drops, basically that you will be closer to the Springfield prices - call it six times versus historical multiples that are closer to eight.

No. I don't see a correlation between our strategy to provide sustainable distribution growth and prices of dropdowns. Prices of dropdowns maybe to give your some historic perspective, A, are always based on the facts and circumstances of the specific asset, right. But what you're trying to do is using the combination of the cash consideration, and the residual economics the sponsors get through their ownership and through the GP economics coming up with something of equivalent value than what they get to a third party. So it really depends much more with the growth profile of the asset, the capital maturity of the asset than it does our strategy, I hope that makes sense.

Okay. Thanks. And then last one on the produced water system in the Del. How are you guys deciding between Anadarko and WES, who builds that network with the salt water disposal? And has your thinking about that opportunity changed at all over the last six months?

We kind of - we made our initial decision when we released our budget, right. You'll recall that last year, we decided to build two systems at WES, and those are coming online in the second quarter of this year. Because we were so full up on gathering and processing opportunities, the decision was made to take the rest of the produced water for 2017, and spend it at the Anadarko level. And Anadarko is going to spend $200 million to $300 million range building out that. That produced water gathering and disposal system. I think going forward, it'll be a function of what are WES's other opportunities, does it have the ability to absorb more of that capital, while staying investment grade, helpfully covering its distribution et cetera, all the variables that we've looked at since our IPO in 2008. And so, 2018 and beyond, it's more like - if we have the capacity to take more of it at the WES level we'll do it. If not, this is critical infrastructure for Anadarko. And I would think they would be happy to do it at their level as well.

That's really helpful. Thanks, Ben.

Sure.

The next question comes from John Edwards of Credit Suisse. Please go ahead.

Yes, good morning.

Good morning.

Ben, just can you remind us just the spread on the low versus the high guidance, the things that you see swinging that either way?

Sure. DJ Basin ramp is probably timing when we see that inflection in volumes, absolute level of volumes. That being our largest asset, highest margin asset, that's going to be a key driver. Trajectory of Delaware ramp, how quickly we move from, say, an operator capture type drilling to a development drilling strategy. We've talked about pad drillings coming in latter part of this year, exactly when, exactly which quarter. There is still a pretty wide business interruption range, which could impact that as well. So when you have a combination of all these factors. And then, let's not forget the upside we've discovered in the Eagleford, in the Marcellus as a result of Anadarko's divestments in those areas. Depending on what those new operators do, how quickly they either complete wells or get back to drilling, that could have an impact on 2017. Just speaking of Eagleford, because you made me think of it, we're really outperforming our initial expectations. The last questioner mentioned the Springfield drop. You'll recall at that drop, we talked about an estimated 2016 multiple of 5.8 times and an estimated 2017 multiple in the high-7s. By now, my estimated 2017 multiple now is the mid-6s, so we're really outperforming our initial guidance there, which is some we're happy to see.

That's awesome. That's great. Good to hear that. So I don't know quite how to structure this question. But I'll make a try. So it's kind of a game theory question, is in relation - you said obviously you only want to rely on dropdowns if you have to for sustaining the growth trajectory. So then, I started thinking, well, strategically if you start dropping down or people are going to think, aha, things are not looking so good. And they might be inclined to short your stock or whatever. So I'm just thinking, just kind of thinking out loud here a little bit. So in light of that, would you be inclined to do some supplemental tuck-ins here and there, so to avoid sort of people sort of gaming dropdowns versus organic, that kind of thing?

Well, first of all, let me tell you that I'm really pleased what I'm seeing on the organic side. And we are not working on a dropdown at this point just to be very clear on that. One of my motivations - my motivations for not wanting to touch the dropdown inventory in the near term are twofold. One as I mentioned, is just the experience that we had in 2016 and how valuable it was for us going into that year with such an uncertain macro environment being able to dip into that safety net. And it set the tone for, what by any metric was a phenomenal year for us. But the second is that that inventory is so high quality that I believe we are going to see some significant growth out of it. To remind you, over 80% are DJ and Delaware assets. And last year we had a range of run rate EBITDA in the $150 million to $200 million range. And then Anadarko went out and sold part of that inventory. And it took about $40 million EBITDA out of that range. Yet, here we are in 2017 with the same exact range. That inventory replenished about $40 million of EBITDA. And that's because it's very high growth. It's Delaware Basin crude gathering. It's DJ Basin crude gathering. And now it's Delaware Basin water. Keep in mind Anadarko's midstream spend last year, which led to that replenishment growth, was sub-$200 million. And a big chunk of that was our own pipeline. Now, we're talking about an Anadarko spend in the $600 million to $700 million range, right? So I think we'll be very well served by letting that marinate for a bit. But I think the market can take a lot of comfort, knowing that it's there, if something goes bump in the night, as things tend to do in the gathering and processing world.

Okay. That's helpful. And just my last question, I mean, you obviously sound pretty bullish. I'm just curious, particularly looking any insight regarding third party volumes for sort of the overall production trajectory out of the Permian. How should we be thinking about that? I mean various forecasts out there are Permian gets to above 4 million barrels a day by 2020, sort of 3.5 million ranges for 2018. And then obviously some people are saying, beyond 2020 it's going to continue, really growing pretty rapidly. So just curious in terms of upside type surprise is what seems to be the order of the day. Are you seeing confirmation of that or any insights you can provide along those lines would be really helpful?

I think it's a great question. I think if you look at the prices at which assets are clearing, there is a very strong conviction around that supply growth out of the Permian, especially in the Delaware. And that's really the quality of the resource. And we're very fortunate to have the significant footprint that we do. I think that it was just last quarter we announced two new trains, right, not one, but two new trains. I think that speaks as much to our belief in our ability to capture third party business, as it does our sponsor activity. And I would say stay tuned. I think as we continue our build-out and look at potential plans in the future, that will be as driven by third party of as much as Anadarko.

Okay. Thank you. That's it for me.

The next question comes from Sharon Lui of Wells Fargo. Please go ahead.

Hi, good morning.

Hi, Sharon.

Hi, so just to touch on, I guess, your previous comments about processing, maybe you could talk about the sequential performance of Q1 processing volume. What was the utilization of the existing Ramsey plants? And maybe you can share what your expectations are for the volume ramp for Ramsey VI based on Anadarko's current plans.

Well, I'll share with you what I can. Obviously, we're very encouraged by the continued ramp that we're seeing in the Delaware Basin and our continued fullness if you will in the DJ Basin. Just to level set, where we have about 700 a day of capacity, today Ramsey VI will make 900 a day. We're continuing to ramp quickly toward 700. I think I made this comment last quarter that, so much so that we're aware of a couple of producers that are looking at making potential arrangements for interruptible capacity in those late summer months, because we might be full before Ramsey VI comes online. And there's certainly a scenario that would indicate that. That would tell you that that the Ramsey VI ramp would be quicker than what we've seen in the past. And we're expecting that, which is why we're adding additional capacity in the second half of 2018. Now, I don't know if you were talking about processing in other areas. But since you asked the question, one thing I'll point out is that, our sequential processing throughput was down 80 a day at a plant called the Granger straddle plant. And being nature of the straddle plant, throughput tends to swing wildly. We've seen throughput swings of this magnitude before. The thing to keep in mind in that is literally our lowest gross margin per Mcf asset. Our gross margin per Mcf is less than $0.10, right, compared to our portfolio average of about $0.85. So while you see wide swings in throughput number you really don't in the cash flow number, because there's just not a huge cash flow impact there.

Okay. That was very helpful. And then, I guess, just trying to think about the potential cash flow impact from the Colorado incident. Would it be reasonable to maybe look at your average gross margin of like $0.85 per Mcf to try to quantify the potential high end, like how should we think about that?

I don't mind telling you that. I've said before, DJ Basin is one of our higher gross margin asset. So it's certainly higher than the portfolio average. But I don't know what else I could tell you above and beyond that.

Okay. And at this time, you had mentioned that West doesn't gather 100% of the volume. Do you have like a ballpark percentage?

I'm not able to isolate specifically the vertical wells what percentage. I'll tell you, when I do my own swag for my own modeling purposes, I tend to approximate 75% to 85%, right. But, again, that's a swag. And with respect to these verticals, I don't have the exact number for you.

Okay. Thanks, Ben.

This concludes the question-and-answer session. I would now like to turn the conference back over to Ben Fink for any closing remarks.

Just want to thank you all for your questions and your ongoing support. And I look forward to talking to you next quarter.