Western Midstream Partners, LP (WES) Q3 2017 Earnings Report, Transcript and Summary

Good day, and welcome to the Western Gas Third Quarter 2017 Earnings Conference Call. [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'm glad you could join us today for Western Gas' Third Quarter 2017 Conference Call. I'd like to remind you that today's presentation includes forward-looking statements and certain non-GAAP financial measures. The accompanying slide deck and last night's earnings release contain important disclosures on forward-looking statements as well as the non-GAAP reconciliations. 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. These materials are all posted on the Western Gas website at www.westerngas.com. After some remarks by our CEO, Ben Fink, and our CFO, Jaime Casas, we'll open it up for Q&A. Ben?

Thank you, Jon. And thank you all for joining us today. There's a lot to talk about this quarter. As predicted, DJ Basin volumes have returned to sequential growth as we see the positive impacts of the rig additions made earlier this year. Delaware Basin volumes were slightly lower on a sequential basis due primarily to two temporal issues: weather and electricity. During the quarter, we experienced Hurricane Harvey as well as other severe storms. While none of our assets were directly hit by Hurricane Harvey, a number of downstream fractionation complexes went offline, which resulted in a significant curtailment of our NGL takeaway capacity. This led to constrained volumes at our DBM complex for approximately two weeks. The later unnamed storms caused flooding around our assets in West and South Texas, which in turn caused some customers to shut in production for a few days. In addition, the Delaware Basin experienced electricity reliability issues during the quarter. The storms directly caused some power outages in the region, but there are also outages simply due to the tremendous demand for electricity in an area without much established infrastructure. Just like what we're doing with respect to oil, gas and water infrastructure, we and our sponsor are taking steps that we believe should help mitigate outages going forward. As we mentioned in our release, we believe the direct impacts of these issues exceeded $3 million in the quarter. Once again, these are temporal issues. On a systemic basis, we continue to love what we see in the Delaware Basin. Activity remains robust as producers test and prove additional formations, and the basin remains a primary, and in some cases, the sole focus of our customer's capital programs. Our Ramsey processing trains are nearing existing capacity as we prepare to bring Ramsey 6 online later this quarter, and we continue to have a line of sight into growth that should fill that train as well as the 400 a day Mentone facility, which will come online in the second half of 2018. Now I’ll ask Jaime to fill you in on some of the details of our quarterly results.

Thanks, Ben. Our adjusted EBITDA of $257.8 million, distributable cash flow of $231.9 million and coverage ratio of 1.09 times were in line with our expectations when adjusted for the temporal issues Ben discussed. When comparing to last quarter, note that our second quarter results included the receipt of the final business interruption insurance payment of more than $24 million. Our natural gas throughput was virtually flat with the second quarter when adjusted for the Helper and Clawson divestitures in June. While Ben already mentioned that we are back to growth in the DJ, we are also back to sequential growth in the Eagle Ford as we are seeing the benefits of the change in upstream ownership earlier this year. The growth in our crude, NGL and produced water throughput was driven by a full quarter of operations at our DBM water services assets. Last quarter, we announced that Anadarko midstream had signed its first third-party water customer, and this quarter, I'm pleased to announce that WES has also signed our first third-party water customer. While we are just getting started in the water business, this further validation of our business plan has our team really excited. Our adjusted gross margin per Mcf on natural gas assets of $0.97 was $0.03 higher than the previous quarter. But I think last quarter's figure of $0.94 is more reflective of our run rate going forward, since we received an annual payment that was recognized entirely in the third quarter. Our adjusted gross margin per barrel for crude, NGL and produced water assets of $2.03 was $0.12 lower in the second quarter of 2017. Some of this was due to returning to normalized distribution per barrel and some was due to the fact that our water business is growing. Our water volumes earn a lower margin than the fractionation and long-haul transportation businesses, which represent the majority of our liquid throughput. We also saw higher distributions per barrel on the Texas Express gathering and Texas Express Pipeline systems as volumetric commitments increased quarter-over-quarter. Now I'll turn it back to Ben for some final thoughts.

Thanks, Jaime. There's a lot going on in our space right now, and I'd be remiss if I didn't share my thoughts on the state of our market. There are many valid questions being raised about whether growth is being valued by unitholders, and whether MLPs need to become less reliant on equity market access to fund their capital programs. We welcome these questions, and we believe we've shown leadership on these issues as our industry continues to transform. Our current distribution growth is less than half of what it was 25 years ago, and we resisted calls by some earlier this year to boost our near-term growth rate by utilizing our dropdown inventory. We've managed our business so that we would minimize capital market access. Our last overnight equity raise was in November of 2014, and the last sale on our ATM program was in June of 2015. We did issue convertible preferred units to private investors to fund an acquisition in February of 2016, when the public markets were effectively closed. While there are some in our sector that require equity market access to fund their ongoing capital needs, it would be inaccurate to put Western Gas on that list. We expect to continue our tradition of prudent balance sheet management that will serve to mitigate the risk of overreliance on capital market access. We greatly value the feedback we receive from our unitholders, and many of you know that we actively solicit it. We cannot forget the large segment of our unitholder base that values the current income they receive, nor do we wish to turn a deaf ear to the institutions who use other metrics when making investment decisions. So I describe our current thinking on distribution growth as ever so slightly revised. When we set the two-year WES distribution growth range of 7% to 9%, we felt comfortable in our portfolio's ability to generate a base growth rate of $0.015 per quarter, which is approximately 7% a year. We felt we could add to that base rate of growth during periods in which our assets generated additional cash flow. Now we believe that the right balance is to stick with the $0.015 quarterly growth rate and reinvest any additional cash flows above that. Another way of saying all this is that we now intend to be at the low end of our previously stated distribution growth guidance range. There's another important trend out there that warrants discussion, and that's the actions that many of our customers are taking to spend within cash flow. I want to be clear on this point. This is a good thing. It helps alleviate downward commodity price pressure that comes with increased supply, and it leads to improved customer financial health, both of which should provide stability in the energy capital markets. It's good for the energy industry, and a healthy energy industry is nothing but positive for our business. Investors with short time horizons will see a downside to this trend as a producer who outspends cash flow will likely deliver more short-term growth than one who exercises capital discipline. But Western Gas is designed to deliver for years not just quarters, and we're therefore highly encouraged by this development. We plan to release our official 2018 outlook later this year, but it's fair to say there are some shorter-term implications that I want you to be aware of. For example, the next couple of quarters look like they'll be tighter than usual, with distribution coverage closer to 1.0 than 1.1. This will be particularly noticeable next quarter, as we expect to record up to $7 million of higher operating expenses in the Eagle Ford related to the provision of lean fuel gas. This is a result of an updated commercial agreement under which these expenses will be incorporated into our cost of service rate calculations starting in 2018. We still expect that 2018 will have full year distribution coverage in line with our longer-term goals as volumes ramp following the startup of critical West Texas infrastructure in the first half of the year. Additionally, our capital program next year will be robust, as we will be in various stages of development of four processing trains, two in the Delaware and two in the DJ, as well as completing our buildout of our West Texas gas infrastructure. Keep in mind the pipelines we are installing today are sized to avoid having to loop them tomorrow. We have great conviction around this strategy, given the tremendous underlying resource space in the Delaware that is years away from peak production. It should therefore be no surprise that we anticipate higher CapEx in 2018 than in 2017. I'm quite proud of the team's achievements on capital efficiency, particularly with respect to well connection capital, which has driven some of the reductions in our 2017 capital spending. Above and beyond the capital needs for our existing assets, we have options to participate in a variety of third-party projects, two of which, the Red Bluff pipeline in the Delaware and the Cheyenne Connector pipeline in the DJ, have already been publicly announced, and we expect more to come. Our willingness to exercise any option will be a function of our estimate of the project return as well as our ability to comfortably fund the additional capital. Finally, since we continue to get questions about our thoughts on our structure, I thought I'd take a brief moment to address the topic. There's an increasingly contentious debate in our marketplace. Some believe IDRs have proven to be an effective means of incentivizing sponsors to grow distributions, while others believe the impact on equity cost of capital more than outweighs any such incentive. Frankly, we think both these have merit. Since our inception in 2008, we've been fully aware that IDRs have a finite lifespan, and the length of such lifespan is a function of what is essentially a mathematical exercise. As I say it a couple of quarters ago, when an MLP's weighted average cost of capital approaches its returns on capital, it needs to take steps to address it. We will proactively do so at the appropriate time. Thanks to all of you for your support of Western Gas. We still believe we have the best footprints in the two premier basins in America, and the most supportive MLP sponsor, all supplemented by a high-class inventory of droppable assets. We're built to deliver stable growth over longer-term horizons, and look forward to engaging with each of you as we continue our current buildout that will set us up for years to come. With that, operator, I'd like to open up the line for questions.

Thank you. [Operator Instructions] The first question will come from Jeremy Tonet of JPMorgan. Please go ahead.

Good morning. Just wanted to touch base a bit more on the CapEx, coming down a little bit this year and it sounds like maybe that's just sliding into 2018 a bit, but I was wondering if you could provide a little bit more color on what that is exactly. And if that's the correct understanding.

Sure, Jeremy. And I think you're right, the primary driver is slippage into 2018, and let me stress the fact that there really is no change in scope. If you look at our IR presentation, you will see a map of the gas infrastructure that we're building in the Delaware. The final results of that map is unchanged. And as you know, we're also building 400 a day in the Delaware and another 400 a day in the DJ. That is unchanged, and that is all on schedule. When we started this year getting after building that infrastructure, I think what we found is securing right-of-way takes a little longer than one might expect. You've got some large landowners in the region that require some negotiation and smaller landowners that you need to track down to be able to secure that right-of-way. And so as it takes longer to secure right-of-way, that will just push everything out to the right, and capital doesn't know when a quarter ends, and that seems to be what's happening. But in terms of what we're building and why we're building it, the scope of that project is exactly what it was at the beginning of the year. Why don't I let Craig give you a little more detail on some of that? Craig?

Yes. Just to add to that, Jeremy. Earlier this year, we announced that we're going to put in approximately 200 miles of pipe out in Reeves County, in the Delaware Basin. And by the end of this year, we expect to have about 50 miles installed, but that – the remainder of that pipe will be contained to be installed – or completed, actually, through the first quarter of 2018. And so we have right-of-way acquired. As we think about the various stages of putting pipes in, obviously, the first step is acquiring the right-of-away, getting the pipe in the ground and then testing the pipe. And so we're making significant progress and feel good about having all that wrapped up by the end of the first quarter. And just to add to that, that there's the corresponding compression that's going in, and that's progressing well. And then, of course, further downstream, the Mentone facility is on track. Ramsey VI is still scheduled to start up this quarter, here in the fourth quarter. And so we feel really good about how everything's coming together so that we can bring incremental volumes online in 2018.

While slippage – this is Ben, again, Jeremy. While slippage is the key driver, I think Craig and his team deserve a lot of credit for what they've done on the efficiency side. They brought some cost down, they managed their capital in a way that as trunk line gets built out, incremental well connection is a shorter line. Therefore, less steel and more efficient to bring the well connection cost down. And I don't want to get away from the fact that Craig and his team have done a good job just being more efficient with dollars as well.

That's helpful. I wanted to touch base as well, Anadarko, seems like they've done a great job in the past as far as leveraging equity barrels and to commitments into equity stakes in new projects. And it seems like there's opportunity for that going forward in the near term here with regards to residue pipes in the DJ and the Delaware and as well the possibility with the Permian crude oil barrels that APC is going to be moving and to leverage that into an equity commitment in the project there. I was wondering if there's anything else you could share on these fronts because it seems like this could be some real meaningful opportunities for Western Gas.

Yes, Jeremy, it's a fair question. I'm not sure what I can say above on what I said on the script, which is we've announced two and we expect more to come. In terms of the more to come, there's nothing to announce right now, but I see potential opportunities on residue, on crude and, potentially, fractionation.

Got you, that makes sense. And just going back to your IDR comments that you made at the end of the call there. And was just wondering if WES' growth rate comes down a bit and then WGP's growth rate comes down a bit, does that make the exercise of the eventual collapse a little bit easier to facilitate, if – from the Anadarko perspective, anyways, maybe, as far as how that calculus could work?

I don't think so, Jeremy. I mean, I think the way we're viewing it in this hall – in these hallways is a laser-like focus on what is our return on capital versus what is our cost of capital. And do we feel that we can earn returns in significant excess above our cost of capital. That is certainly true today. It's something we monitor. It's something we want to get out in front of. And that will drive any decision around this issue, not where the securities trade.

Great, thank you for taking my question.

The next question will come from Colton Bean of Tudor, Pickering, Holt. Please go ahead.

Good morning, everyone.

Good morning.

I think, Ben, you touched on the capital spend expectations for 2018. Fairly full slate there and a couple of outstanding equity options that could add to that. When you think about trying to avoid or at least not having to rely on capital markets access, do asset sales factor into that at all? I mean, we've had some repositioning of the asset base here year-to-date. Just wanted to get your thoughts on that going forward.

There's – no, we are not looking at asset sales as a way of funding our capital program. And as you know, Colton, there have been times in the past, where, in conjunction with a sponsor-led upstream divestiture, we've chosen to participate with midstream. There's times we've chosen not to participate. And as those opportunities materialize, we'll evaluate them as they go forward. There may be divestitures of small non-core stuff, just because we think the risk, reward of operating something that small may not be in balance. But in terms of divesting something material to fund the capital plan, that's not something we're looking at right now.

Okay. That makes sense. And then I – just to touch on the water systems. You guys have talked about the build-out there. I think, previously, you had messaged that you had three disposable wells online, with a fourth to come online. I guess, is that well online? And then, as you look forward into 2018, maybe a bit premature, but any kind of high-level expectations around what that build-out needs to look like to satisfy the volumes that you expected?

Sure. Let me let Craig give you some details on that.

Yes, we've got three wells in service today, and the fourth is scheduled to come online in the first quarter of 2018. Beyond that, if you'll keep – if you'll recall, most of the water infrastructure on a go-forward basis is going to be developed by Anadarko. And so from a Western Gas standpoint, we've got essentially two systems. Each of those systems designed to have two wells in them, with three of those four wells in service today.

Okay. So very little to do – or I guess, in terms of needed expansion on the water system, most of that will be coming through dropdowns from APC going forward?

Yes. And I guess, just the final thought there would be, with those systems that we do have in service as well as the fourth well that we expect to bring online, there's incremental growth available within those facilities today that we expect to see filled up over time.

Okay, that’s helpful.

Colton, just to follow-on. We often get the question, and not sure if this is where you were going about. Why don't you just put that water capital on WES? Or any additional capital, why don't you just put it on WES? And I think we've been quite prudent in how we manage WES' capital. We put as much as we can to service our own assets, while maintaining investment-grade rating, while trying to minimize capital market reliance and covering distribution in turn with our long-term goals, right. And I think we're quite full, and just putting that additional capital on WES, and therefore, requiring WES to have to go to the equity markets to fund that capital, I don't think that's in the best interest of our unitholders, and I think most of our unitholders would agree. So I wanted to give you that color.

Understood. Thanks, Ben.

The next question comes from Tom Abrams of Morgan Stanley. Please go ahead.

Thank you. So I know you don't want to – or can't, maybe, even talk about Anadarko's plans, but – and they'll tell you more in November. But is it logical that you're spending, over the next several years, to feed and to support their growth, which was, I think, 15% or something like that for five years. I think that's what they were talking about earlier this year, that if they – if production becomes more of an output to their equation rather than the driver, that whatever you were going to spend is now stretched out over time. Is that a reasonable way to think about your spending side over the next several years?

I’m not sure. I mean, I think what Anadarko talked about in their call this morning, which for everyone on the call, I highly recommend you listen to, is this integration between upstream and midstream in being one of the family's competitive advantages. I think they mentioned that they'll talk about growth rates when they give guidance next year. But regardless of the timing of when these regional oil treating facilities come online next year, which is going to drive the volume ramp next year, the scope of what we're building is going to be needed, right. So if you look at our presentation, you look at the gas infrastructure, the oil infrastructure, the water infrastructure, none of that is being materially altered in any way. The timing of the inflection point will be tied to when those regional oil treating facilities come online, but I don't think there's much of an impact on our 2017 and 2018 aggregate build-out because we're actually building out to support that longer-term growth. As I mentioned in the script, is we are sizing these pipelines today, so that we don't have to loop them tomorrow. Does that answer your question, Tom?

Yes, it does, and I appreciate that color. And I guess, along the way, we've got, I don't know, $200 million of dropped inventory left of EBITDA up top to come to you. How do you think about using that in 2018 to kind of supplement the cash flow generation side? And if you did envision some of that, how do you think you'd fund it? Do you think the parent would take back units?

Yes. I think – well, the answer to your question is, we're managing our business to use that dropped inventory as a safety net. And forgive me repeating myself, but if there was a lesson to be learned from what we went through at the beginning of 2018 is that, should you get into an environment where that organic growth doesn't show up because of some shock to the system, you're going to be glad you had as big a safety net as possible. And our base case operation is to try to grow that safety net into something more meaningful should we need it someday. So in terms of our plans for 2018, there is nothing being contemplated for 2018. You asked a hypothetical, if we did – if something were to change and there was a shock to the system. I think, Anadarko has shown the MLP market time and time again over the past nine years that it's been incredibly supportive of the MLP, that, that can be – you can throw drop-down prices, drop-down structure, financing structures – I mean, I think they've really been a leader in the sector of showing support for the MLP.

Good. Two quick ones. One is an intra-basin gas line to Waha, which I think you talked about in the past. Is that one of the equity projects that you might be able to get into? Where is that right now?

We have an option to purchase up to a 30% interest in a residue line that will go from the Northern Delaware to Waha, and that will be operated by energy transfer.

Is that one that you've – was included in your earlier remarks or one that's still kind of pending out of the…

Yes. That's one of the two that's publicly we think about.

Okay. And then, the – lastly, the Eagle Ford. Really good volumes, I think, at Springfield. So was that specific to your operations or was something, some blanket Eagle Ford commentary you can make, what you're seeing there?

The commentary on the Eagle Ford is that we're back to sequential growth. As just a reminder, what happened is, when we bought the asset, Anadarko was the operator of the upstream. Great asset, but that asset was not competing for capital with DJ and Delaware. And so they divested the upstream to an operator who likes the Eagle Ford a lot, and is a, I believe, an Eagle Ford pure play. And so they've gotten back to drilling and completing, and we went from riding decline curves back to sequential growth.

Excellent. Okay. Thanks a lot.

Sure.

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

Hi, Ben.

Hey, Shneur.

Just a couple of quick questions, not to sort of re-go over everything again. But the Anadarko made kind of a pivot change, but maybe it really wasn't a pivot change at the end of August, talking about focusing on returns, which I think they've mostly have done in the past. I was wondering if you could sort of talk about how that impacts WES? Are we seeing more productivity from their activity and that's why they can sort of run with fewer rigs if they wanted to? Is there a huge backlog of uncompleted wells and that sort of makes sense as well too? I was just wondering if you can sort of walk us through how we should think about Anadarko's actions and how it impacts volume activity at WES and how it impacts your operating leverage, given that you're oversizing a lot of your CapEx?

Okay. I wouldn't view it as a pivot change. I think, if you look at the calls transcript, they made a point of saying they're being very consistent with how they've approached things in the past. Using the broad statement of investing within cash flow, any producer that invests within cash flow is in a $50 to $55 world is going to have more stable, steady growth than near-term growth, right? And so what you're trading is you're getting energy market stability, less pressure on the macro, more stability over multiple years versus a lot of growth in the next 12 months, that maybe isn't replicable two years or three years out. So I think that is, not only what Western Gas is seeing, but what the entire industry is seeing. I'll repeat my statements from the prepared remarks that this is a good thing and I think we should all be highly encouraging of this trend because it's good for our industry and good for price stability. And I think you're seeing that in oil price movements today, given the draws on global storage or global inventories, rather. And we're quite encouraged by it. Yes. I'll leave it there and you can ask your follow-up.

So I guess, effectively, the trade-off is, you give up some growth, but you have more stability in volume expectations, but should arguably be better for your equity risk premium longer-term?

You said it better than I did. Thank you.

Cool. Next question, just with respect to your robust capital program for next year. Just curious about overall plans to finance it. Yes, coverage is tight but it also seems like you're underleveraged as well, too. Is it possible to completely stay out of the equity markets, just given that you probably have room to take your leverage up a little bit?

That's where I want to be, and we'll give guidance – we're going to give guidance earlier than we have in the past. We'll do it later this year, where normally we do it in the first quarter. So we'll talk more about it this time. But the idea is to fund it similarly to how we did this year, and you're right. One of the things I'm most proud of was having the foresight to really enter this year by converting those preferreds into a really underleveraged position, which allowed us to take on this robust two-year capital program without reliance on equity markets to do it.

All right. Perfect. That wraps up my question. Thank you.

The next question will come from Barrett Blaschke of MUFG Securities. Please go ahead.

Hey, Ben. A couple of months back, we talked about sort of the differences in your outlook for the world as we saw oil at $45, $50 and kind of $55. We're a lot closer to that $55 today, and can you give us a little bit of a picture on where the opportunities had changes if we continue to see crude oil creeping up? And then, on that natural – NGLs creeping up as well?

Fair enough. I wouldn't call myself a commodity price bull. I think this $45 to $60 range is probably where we're all planning towards. I think, Anadarko had some interesting commentary around that in their call this morning. Obviously, if we're living in a world where producers are living within cash flow, they will have more cash flow at that higher oil prices than they would at lower prices, which means more well connections for us, more accelerated growth in the near term. However, given that our program is focused on what I would argue are the two best basins in America, two of the lowest breakevens in America, I'm not sure the scope of what we're building really changes as long as we're in that range, because we have the confidence between the quality of the rock and the producers who are actually behind our systems, we'll have a pretty stable drilling program, depending on which quartile you're in, in that range.

Okay. I know you're wanting to kind of keep your dropdowns to more of a safety net approach to growth at this point. But if you were to do one, would you still be able to stay out of the equity markets? Or would that be something that would probably push you in?

I think any acquisition, whether from our sponsor or third-party, would need to be financed with a variety of securities.

Okay. Fair enough. Thank you.

The next question will come from Sel Akyol from Stifel. Please go ahead.

Thanks. I guess, you might have addressed this a little bit, but on the APC call, they talked about a tankless battery. And I guess I'm wondering what is – how is that impacting you as being the midstream provider for them? Is that putting incremental pressure on you? And then, they also talked about pushing pad drilling out, either into the back half of 2019 or really for the back half of 2018, before really moving up into 2019. So in terms of that volume ramp that you'd be getting, how is that also sort of affecting your planning and thinking?

Sure. I think there’s two dates, I don't know what the exact dates are, but that will be inflection points for the WES volume ramp. One is on the oil side. When you go to a tankless system, that means the oil is being treated regionally, not at the wellhead. So you actually have to build these ROTFs, R-O-T-F, regional oil treating facilities. So when that facility comes online, you see a step up in volumes, right? And that is currently being built at the Anadarko midstream level, there's a couple of them coming online in various states in 2018. And when they come online, volumes should follow. The second, as you rightly pointed out, is the move to pad drilling of any operator, going from appraisal mode to development mode. And what you've seen in the Delaware, historically, is drilling being driven by an operatorship capture program, so that has a wide geographic scope, all right, and then moving from that to a much narrower scope, which is multiple well pads. And as they mentioned, that's the second half of 2018 event, and so that will be another inflection point for volumes for WES.

Okay. And then, on the oil volume growth, that will be then reflected then for you guys as well? Maybe not so much in the actual asset itself on the regional processing pipeline?

Right now, the oil gathering still sits at Anadarko, right? So that growth that you'll see at WES is the associated gas with those oil volumes.

Okay. Thank you very much.

Sure.

The next question comes from Faisel Khan of Citigroup. Please go ahead.

Hi. Good morning, it’s Faisel from Citigroup. Just a couple of technical – one technical question, actually. When you guys quote the cost of building a processing facility, does that include the ownership and possession of the compression equipment? Because I know Anadarko does lease a lot of their compression equipment for some of their infield sort of gathering and processes. I'm just trying to figure out if – when you guys quote the cost of plant, does it include that or do you guys lease out that compression?

Yes, Faisel, this is Craig. And I'll try to answer your question there. On our gas processing plants, we own all of the residue compression inside those facilities. You're correct in that there is some lease compression out in the field. We have – we manage that between what – how much we own versus lease, based on what the projected volume profile looks like for the asset, so that we can use the compression for – on a long-term basis, where we own it and re-lease it back if we're renting it. But within our processing facilities, we view those as long-term assets, and we own all of that compression…

Okay. Including the ones that you guys are building out too, right?

That’s correct.

Okay. Great. Thanks, guys.

Faisel, we haven’t done a dropdown in a while, but back when we were doing one to two a year, one of the things we would always do to prepare an asset for dropdown is buy out the compressor leases, so that you would have owned compressions coming to WES.

Okay. So you would just have to buy out the contract or would you wait for the lease to end?

Usually jus buy out the contract.

Okay. Got it.

Again, we haven't had a drop in a while.

Makes sense. Thanks.

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

Now once again, I want to thank you all for your support and taking time to join us today. We’ll see you next quarter.