Good morning. And welcome to the Western Gas Fourth Quarter and Full Year 2017 Earnings Conference Call. All participants will be in listen-only mode [Operator Instructions]. After today’s presentation, there will be an opportunity to ask questions [Operator Instructions]. Please note, that today's event is being recorded. I would now like to turn the conference over to Jon VandenBrand. Please go ahead.

Thank you. I'm glad you could join us today for Western Gas' Fourth Quarter and Full Year 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. Those materials are all posted on the Western Gas Web site at www.westerngas.com. Finally I'm pleased to inform you that the WES and WGP K1s will be available online via our Web site beginning February 20th and March 2nd respectively. Hard copies will be mailed at several days later. I would now like to turn the call over to our CEO, Ben Fink, and our CFO, Jaime Casas, and following their prepared remarks we will open up for Q&A. Ben?

Thanks, Jon. And thank you everyone for joining us today. I'm really pleased with our fourth quarter results and I believe we’re well positioned for a strong 2018. I'm going to ask Jaime quickly review these results and then I'll talk some more about the 2018 guidance we issued in December. Jaime?

Thanks, Ben. We delivered another year of solid performance as our full year 2017 adjusted EBITDA of $1.06 billion exceeded the midpoint of our guidance. Additionally, WES and WGP increased full year distributions by 7% and 19% respectively, while WES generated a full year coverage ratio of 1.13 times. Total capital expenditures of $792 million were slightly below the low end of our guidance due to primarily to timing issues. Turning to our fourth quarter results. We reported adjusted EBITDA and distributable cash flow of $273.3 million and $233.4 million respectively, and a coverage ratio of 1.08 times. Our quarter results were driven by strong natural gas throughput growth in the DJ and Delaware Basins. Volumes at our DBM complex continued to ramp and our Ramsey plant was nearing capacity when we brought train six online at the end of the quarter. While gathered volumes on our DBJV system continued to grow, the volumes declined on a reported basis due to a prior period adjustment. This adjustment had no impact on cash flow during the quarter and was the main driver of the sequential increase in adjusted gross margin per MCF. Excluding this adjustment, our gross margin per MCF was inline with last quarter and more indicative of what we expect going forward. The growth in our crude, NGL and produced water throughput was driven by the continued growth of our DBM water services assets. The sequential increase in adjusted gross margin of our liquids assets of $0.18 to $2.21 per barrel was due to the receipt of a one-time payment associated with our DBM water services assets. Similar to our gas margin, this higher gross margin per barrel is also not indicative of our run rate going forward. We continue to be excited about the prospects of our produced water gathering disposal business and recently executed another third party contract that will support development of our third water system later this year. As a reminder, we believe that produced water business is a great complement to our existing business lines as we focus on executing long term commercial contracts with fixed fees and volumetric commitments. Additionally, due to our shared services model with Anadarko, we were able to utilize their sub-surface and drilling expertise to gain a competitive advantage in providing these services. While this business is just getting started, we believe full cycle returns for the water business will be higher than our portfolio average. Before I turn it back to Ben, I would like to remind you that we adopted a new revenue recommission accounting standard on January 1, 2018. While there will be material changes in how we report revenue and cost of product expenses related to percent of proceeds contracts going forward, this new standard would not materially impact net income, adjusted gross margin, adjusted EBITDA or DCF. Now, I'll turn it back to Ben for some thoughts on our near term outlook.

Thanks Jaime. Hopefully, everyone listening today is familiar with the guidance we released in December, and I'd like to take a few minutes to discuss it in more detail. Our key focus for 2018 is the execution of a capital budget of $1 billion to $1.1 billion. Over 90% of our budget will be directed towards our two core operating areas, the DJ and Delaware Basins, with over 50% allocated towards building out our gathering systems and approximately 30% earmarked for the construction of four additional processing trains. Most of what we're doing is in sync with Anadarko's 2018 development plan. And if you haven't had the chance to listen to their outlook call that took place last week, I would strongly encourage you to do so. In the DJ Basin, strong producer economics continued to support high levels of activity by Anadarko and other producers that should push volumes to near system capacity by the end of the year. To support this anticipated growth, we're focusing on the further expansion of our gas gathering system to the areas of the basin that are less developed. We expect to commence construction at the Latham 1 and 2 processing trains by the third quarter, and they're scheduled to be in service during the first and third quarters of 2019. As a reminder, both trains are supported by long term volume commitments from Anadarko. Furthermore, we continue to see opportunities to capture additional third party business in the area and any related capital will be incremental to our current plans. It’s also clear to us that there'll be a basin wide need for incremental takeaway capacity for both NGLs and residue gas. We continue to believe that adding pump stations on the front range in Texas express pipelines is an efficient solution,…

We will now begin the question-and-answer session [Operator Instructions]. And our first question comes from Jeremy Tonet of JPMorgan. Please go ahead.

Ben, I was hoping you might be able to talk a little bit more on the Ramsey complex and how it's running currently and the ramp there. Just if you could provide more color that would be helpful.

I'm going to let Craig Collins, our COO to take that one.

As we noted in the opening comments, by the time we started up the Ramsey 6 train in late November early December, the plant was nearing capacity at that time. And since we brought trains 6 on throughput has continued to increase through the facility and we expect that to continue to grow through the first half of this year and until we get the mid term plant online.

And turning to the Eagle Ford, some of your peers have indicated a stronger ramp there with the basin recovering. Could you just expand a bit more as far as what type of activity you’re seeing and what your expectations are going forward there?

Well, just to remind you the history lesson. We still feel like we’re playing with house money in the Eagle Ford, because when we bought that asset in the beginning of 2016, we expected three years of decline curves and then a year later, Anadarko sales to Eagle Ford pure play operator and we get back to sequential growth in the basin. And so we really love what we're seeing there. And we do expect more growth in 2018. I don’t think the slope of the curve has changed based on the guidance that we're seeing from the producers, but really happy to getting back to growth in that basin.

And I know I’ve asked this question before and don’t want to be a dead horse, but it seems like the family is in a unique situation given APCs volumes growing rapidly in the Delaware and how that can be parlayed into takeaway solutions be it on the crude oil, NGL side, natural gas side as well. And just wondering if there's anything new that you can share there as far as appetite or interest in the family participating in some of those takeaway solutions and what that could mean for WES.

Nothing that I can share unfortunately. The appetite is there, the interest is there. And by the time everything is said and done, I think we'll have participation options and residue lines, new crude lines and potentially fractionation.

Our next question comes from Colton Bean of Tudor, Pickering, Holt and Co. Please go ahead.

Ben, I just wanted to touch on the O&M step up in Q4. Is that associated with the Eagle Ford field gas provision that you guys mentioned in the prior quarter?

Not very much, tiny little bit but not much. The key driver there is a line item called surface maintenance and repair. Think of that as the expense analog to maintenance capital. So as maintenance capital steps up with increased activity that line which is an expense line also steps up. So you saw a lot of activity in the Fort, you saw maintenance capital step up that line stuff as well that's the key driven in O&M.

And then just switching gears, so Red Bluff looks like it’s still targeted for Q2 '18. Would you guys need to exercise your option by in service or does that extend for a period beyond.

The period beyond in service.

And any clarity on how long beyond that.

Six months.

And then I guess just the final one from me, so looks like APC is adding some permitting activity in the powders, but no immediate outlook on rigs there. Can you guys just remind us of the scale of that dedication and whether the existing asset base could handle an increase in activity.

Appreciate the question Colton, but since the producer is not really talking about it, I'm not sure we should as well. Anything we do will probably be a 2019 and beyond and something we're looking at very closely.

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

Just a couple of questions, some short term some longer term. Just starting with the near term. For 2018, I believe you commented that your guidance for the year, but the shape of it is going to more second half weighted and you expect coverage to be closer to one for the first half. And if I listen to your prepared remarks, clearly the type of gathering system is part of this. So if it comes down hitting your numbers and your expectations effective these appears to come down execution of your CapEx. Do you have the percentage of completion numbers and key signposts for us to track as we think about the tankless gathering system?

And I think what you're specifically referring to are the ROTFs. So let me let Craig give you some color there.

Shneur, we continue to see progress out in the Delaware and completing both the pipes and the facilities. Those facilities and the corresponding pipe are still on track for second quarter completion. I think by the time that first ROTF comes on line, we will have approximately 100 miles of pipe, new pipe in service associated with that.

And so to the weather issues have slowed things down, you’re on schedule or ahead of schedule?

We feel really good about the second quarter delivery there.

And then with respect to margins going forward with increasing water being part of it. Is there a scenario where the margin overtime leads lower on the crude oil side, just because of the difference in terms of between two. Is that a fair way to be thinking about it from a long term modeling perspective?

More than a fraction. Water is a lower margin business than long haul transportation, because it's a gathering business. And you'll see more overall volume, so it will trend lower. But remember it's a higher return on investment business as well, because we see a slightly above gas gathering and processing.

Absolutely, I just wanted -- because they reported together, I wanted to make sure that we got that right. And then finally just on a longer term basis, you're looking at 13% to 14% growth year-over-year this year versus last year. And obviously, that's part of the big capital spend last year and you’re gettting some capital spend this year. And so I assume you'll see some growth into next year as a result of the capital you're spending this year. But you made scenario where let's say you stopped spending CapEx, and you didn't execute on any dropdowns. My understanding is and I think you touched on this in your prepared remarks about how you’ve overbuilt this system. I was just wondering what kind of operating leverage this excess build is done. Could this be another 10% straight up earnings growth without any capital investments or dropdowns? I was wondering if you’ve some thoughts on sensitivity about the type of operating leverage that you've created?

Okay, I'll do my best, Shneur. Keep in mind that in our business you’ll never go to zero CapEx, not only because maintenance because you have to connect wells. If there is a well connect by definition, there is capital. What I'll say is a typical way that some other basins have been developed in the past is producer acts works with third party why and try to keep the capital spend low. And one way to keep capital spend low is by having bringing our diameter pipeline, which is fine it keeps initial spend low. But then when the production really gets going, those lines need to be looped if it can't support that growth. And so while the early stage capital may have been lower, you’re seeing capital really on an annual basis throughout the production cycle. The beauty of being sponsor led and really having unique visibility into your largest customer is that you can spend a little more capital on the front end, but then once it's built it's built. And you won't have that back end capital of needing to loop those lines. And so as long as you’re confident that the drilling will take place and the production growth will show up, it is a much more efficient way over the long term to be able to handle that growth. Now, eventually processing plant is still up and you’ll need new plants, but there is no way around there. Does that answer your question?

It does. And effective is my question, just like I guess what I'm trying to figure out and I realized that there is never a period where you actually hoping best since it’s a hypothetical question. But I guess what the capital avoidance related to, I mean, is this something that your earnings can grow by without capital is that the way to think about it. And it drives to the 2020 organic number that doesn’t require capital effectively.

Absolutely, the right way to think about it is that you can have a lot more growth in later years without the analogous CapEx spend, so that improves your returns overtime.

Our next question comes from Dennis Coleman of Bank of America Merrill Lynch. Please go ahead.

I have just a question about the dropdowns, you talked about the $300 million. On the APC call, there was some commentary about maturing those assets. And so I wonder if you might just talk a little bit about how you -- what the conversation is with the sponsor as to when they see that becoming more of a free cash flow asset that you might consider for drop down?

Yes, I appreciate the question Dennis. And I remmber those comments, I was in the room when they were made. I think all I heard was a reiteration of the strategy that Anadarko had been executing for the last 10 years with Western Gas. In the early days, our growth is primarily through dropdown and now it's primarily on organic growth story. Dropdowns historically are decision of when WES would like to do them. And as you know, we've decided not to do any last year or this year, because we have enough organic growth in the portfolio and wanted to let that inventory mature a little bit. So as point about maturity is just because of that decision that by definition that inventory gets more mature. I mean it was a very immature asset last year. And as you know, approaching free cash flow positivity. But WES is at a scale today where it can aquire an asset in the early stage and the late stage capital maturity is not a prerequisite for dropping an asset to WES.

That’s helpful. It’s just that those comments struck me as a little bit different as you said from what you've had in the past. And then just a more of a detailed point of interest. You did do some work on your credit facilities in the quarter, and you reduced the WGP facility to almost nothing. Why even to keep it at $35 million?

Well, there was $28 million drawn on it, so wanted to keep at least that. I’ll give you a little historic context there. We put that in place in the February of 2016 in conjunction with the Springfield dropdown, which as you know is a very challenging time in the energy markets. The purpose of that was two-fold. One, we were working with private equity firms to give us private capital at the time, but we needed a Plan B in case they change their minds. And so really wanted to keep them on and that facility would have been a way to get that dropdown done. Then we kept it in place as almost like an insurance policy for WES that god forbid the equity capital market shut down again and WES absolutely needed equity, there would be a way to that facility then have WGP buy WES units. Since that time we put ourselves in a position to not need any equity. And so we don’t really need that insurance policy in any more. So we reduced the size of that facility so that WGP unit holders don’t have to bear the commitment fees over the larger facility. And then when it expires, we’ll deal with it then.

Our next question comes from [indiscernible] of Citigroup. Please go ahead.

Regarding the first ROTF coming online in a few months. Can you give us an idea of how much potentially pent up Anadarko production that's being held back right now will be released at that point, which I'd imagine will result in more of a step change in volumes at that point that you probably wouldn't expect to see when the second ROTF comes online.

I would say that right now, there's several wells that are waiting to flow. And as APC has guided, its near term production volumes out of Delaware until the ROTF comes on are going to remain relatively flat. And so we expect once that ROTF does start up that that capacity will be essentially fully utilized soon thereafter. So I think we're going to see a significant step change in volumes, the initial ROTFs comes online and then again once the second ROTF in North Webbing comes on line.

It sounds like you're asking about Anadarko volumes I would guide you to both fourth quarter operations report, as well as their guidance lines. I think you'll find some helpful info in there.

And on the NGL takeaway at the DJ, you mentioned additional pump should be adequate for now. So how much additional capacity do you think you can get out of those pumps. And with the latent plants coming on line next year, how long do you think that takeaway capacity is going to be sufficient?

These are approximate numbers. And to be clear, the capital project of adding the pumps has not been sanctioned, so that is not a live project. Although, we're public in saying we're in favor of it. On approximate basis, nameplate capacity of 160-ish goes to about 230-ish when you add the pumps.

And would you -- if that does move forward, do you think that would be sufficient even with latent plants coming online next year?

For our barrels.

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

I wanted to follow-on on the NGL expansions that you’ve talked about, and it sounded like you have reserved some CapEx amount, although this project hasn't been FID. Can you disclose what the CapEx amount in the '18 budget is?

Not until the partners sanction the project unfortunately.

But it is in there, your share of that pump expansion?

It is.

And then, Ben, more of a big picture stepping back question on the Delaware. If you think about the non-APC business, but it sounds like you're getting increasingly comfortable going after. But can you just characterize the difference in margin or maybe it’s really the dynamic between return and cost of capital for that third party business versus what you get from Anadarko? And then I guess more importantly, just strategically, how do you position yourself to win that business in what is obviously a very competitive basin?

Yes, that was very diplomatic of you saying it’s very competitive. It’s probably an understatement. I'll say that our attitudes to risk versus return cost of capital are somewhat similar, Anadarko versus third party. Whether its Anadarko or anyone else, anyone that's willing to enter into a longer term contract with the high MVC component, you feel comfortable perhaps having a lower base case return, because there is less risk associated with that contract. Obviously, the sponsor led MLP might be more comfortable than a third party might. And so that would affect returns there. But in terms of our target mid-teens unlevered for any capital we deploy, that’s true no matter where we are, who we’re serving. What we are finding in the Delaware is we have a competitive advantage in our ability to leverage our existing infrastructure. You've seen the math of the 600,000 gross acres and you’ve see the math of the gathering backbone that we're laying strictly for it to finance by our sponsor just to serve their needs. Just by virtue of doing that, we are on the doorstep of dozens of our set producers. And so our ability to serve them with relatively very little seal to lead to tie them in, I think is a really healthy competitive advantage.

And then one last one. Just curious on a little bit more detail on the water business, if you could breakout where you are in terms of utilization of this first two water systems that you built out. And then how much of a third system with the third party contracts in the budget for '18 and when you would expect it to come online?

I’ll let Craig give you that detail.

We're really excited about the early success that we've seen on the water side. As you've noted, we had two systems that we put in. One of those systems has two wells in service and that system is essentially full. The other system has one well in service, which is full and the fact that well it’s going online here the next couple of weeks. And so once that comes online, we expect there will be significant ramp in volume there as well. So whatever we're putting in right now is getting seeing really high utilization. And as we continue to build on the book of business that we'd established so far as noted earlier, we have a new customer that we're building up system for later this year. And the intent there is that we'll have that infrastructure in place by the end of the year and have a very attractive contract associated with that.

Our next question is from Sharon Lui of Wells Fargo. Please go ahead.

You mentioned I guess there is no update on the WES restructuring and IDRs due to the spread between your returns and your cost of capital. I was just wondering if you can maybe provide some color on I guess the expected value spread on your $1 billion CapEx budget this year. And how you see that may change going forward in terms of an improvement?

Sure. I mean and some of this is a reiteration of what we said in the past. But all capital we spend usually has a base case of mid-teens unlevered. Our [WAC], which is around -- we calculated around 11% today is a little higher than our historic average. But that spread between those two are quite healthy. Now, if you think about our contracts in which we're deploying the bulk of our capital, take Delaware Basin gathering for example, that's a cost of service contract with a prescribed rate of return. The plants that we're building are under-veined by MVCs to give us those mid-teens unlevered returns from investment grade customers. And so we feel quite confident in our ability to deliver upon that. Now probably the premise to your question is that cost of capital goes up overtime, we all know that everyone in the MLP space is aware of that, and that's something we’re going to have to track on a real time basis and address at the appropriate time.

Our next question comes from Chris Tillett of Barclays. Please go ahead.

Just a quick one from me here. You mentioned at the top of the call that the unit margin on the gas side would have been in line with 3Q, had it not been from prior period volumetric adjustments. Just curious if that's consistent with what we should expect going forward? And then whether or not we should think about that margin is changing at all further end of the year as some of the capital you guys are putting to work comes into service?

Yes, I think it's a fair expectation of run rate going forward. I mean, you’re always going to have changes in the throughput mix. So there’s always going to be some variance if you have growth in the higher margin asset, the lower margin is on decline or vice versa. So there is always some movement in there. But in terms of a general run rate, I think that previous quarter is there.

Our next question comes from Selman Akyol of Stifel. Please go ahead.

This is Tim on for Selman, thanks for taking our question. I want to follow up Dave’s question regarding third party business in the Delaware. Is there anything we should look for or key infrastructures that needs to be in place for you to source it this business. Do you guys have any internal expectations of when maybe something would be sanctioned that you could release. Just want to get a better feel for what you guys are expecting?

Well, we needed Ramsey 6 to come online when it did, and then that was on time and on budget, because that third party business had built 235, so that was key. And I think in terms of the ramp between Ramsey 6 and Mentone 1 coming online, that's a mix between Anadarko and third party growth.

I thought you guys were referring to like incremental beyond what was already in Ramsey. Did I just hear that wrong?

We were talking about critical infrastructure really relates to Anadarko's volumes. Anadarko has volumes that is waiting for treating capacity to come online units in Anadarko specific issue. And so when all that treating capacity comes online with the oil growth and then all the associated gas with that, which is why we're going to need Mentone 1 and 2, and why there is a pretty short gap between Mentone 1 and 2.

I thought you were just saying that your assets are very close to third party acreage they could attract additional business. I guess I just heard it wrong, is that all…

Our existing infrastructure is very close to third party and we are factoring in that growth and the timing of our processing ads.

This concludes our question-and-answer session. I would like to turn the conference back over to Benjamin Fink, CEO for any closing remarks.

Sure. We appreciate everyone joining us on the day before a long weekend. We hope you're able to enjoy that long weekend. I can assure you we will. And look forward to talking to you next quarter.

The conference has now concluded. Thank you for attending today's presentation. You may now disconnect.