Good afternoon, everyone, and welcome to the Antero Midstream Partners LP First Quarter 2018 Earnings Conference Call. All participants will be in a listen-only mode. [Operator Instructions] Please also note today’s event is being recorded. At this time, I would like to turn the conference call over to Mr. Michael Kennedy, Senior Vice President of Finance and Chief Financial Officer of Antero Midstream. Sir, please go ahead.

Thank you for joining us for Antero Midstream’s first quarter 2018 investor conference call. We’ll spend a few minutes going through the financial and operating highlights, and then we’ll open it up for Q&A. I would also like to direct you to the homepage of our website at www.anteromidstream.com or www.anteromidstreamgp.com, where we have provided a separate earnings call presentation that will be reviewed during today’s call. Before we start our comments, I would first like to remind you that during this call, Antero management will make forward-looking statements. Such statements are based on our current judgments regarding factors that will impact the future performance of Antero Resources, Antero Midstream and AMGP and are subject to a number of risks and uncertainties, many of which are beyond Antero’s control. Actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. Today’s call may also contain certain non-GAAP financial measures. Please refer to our earnings release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. Before I turn over the call to Paul, I also quickly want to provide a brief update on the special committees that were assembled after soliciting feedback from AR’s largest shareholders. As previously announced, AR formed a special committee consisting of independent directors to evaluate the merits of potential measures to enhance Antero’s valuation. In conjunction with this review, AM and AMGP have also established special committees. I’d like to point out that the independent directors on the three special committees are not directors associated with private equity. All three special committees have hired financial and legal advisors and are working diligently to evaluate a range of potential measures. There’s no definitive timetable for completion of this evaluation and there can be no assurances that any initiatives will be announced or completed in the future. As I hope, you can understand because of the nature of this process, we’ll not be able to address any questions related to it, or discuss it further during today’s call. Joining me on the call today are Paul Rady, Chairman and CEO of Antero Resources and Antero Midstream; and Glen Warren, President and CFO of Antero Resources and President of Antero Midstream. I’ll now turn the call over to Paul.

Thanks, Mike, and thank you to, everyone, for listening in to the call today. I’ll begin my comments today with a discussion on the operational improvements at AR. Mike will then walk through first quarter 2018 results and the five-year outlook at AM. First and foremost, both AR and AM had exceptional quarters on the operational front. Despite difficult operating conditions due to snow and ice in the Northeast processing outages and pipeline downtime, AR was able to deliver record net production of 2.38 Bcf a day. Production for the quarter represented a 11% increase over the prior year period and came in ahead of expectations. In addition to delivering on production, AR built on its momentum from 2017 with respect to drilling and completing efficiencies, including some company operational records, which I’ll highlight on Slide #3 titled First Quarter 2018 Drilling and Completion Execution. Starting on the top left portion of the slide, in the Marcellus, we improved our average drilling days to a 11.5 days from spud to TD, which represents a 4% reduction from 2017 average levels. Completion stages per day in the Marcellus averaged 4.3 stages per day for the full quarter, but increased to a company record of 5.1 stages per day in the month of March, as the increment winter weather subsided. This is particularly impressive, given that we increased proppant per foot in the Marcellus by 23% to over 2,000 pounds per foot and increased lateral lengths by 8%, as compared to year ago levels. In addition, during the quarter, Antero completed its longest lateral to date in the Marcellus at nearly 14,400 feet sideways and for Utica wells averaging 17,400 feet sideways in line. From an AM capital efficiency standpoint, these longer laterals along with more wells per pad result in AM…

Thank you, Paul. I’ll first touch on the distributions for AM and AMGP for the first quarter. We recently announced an AM distribution of $0.39 per unit, a 30% increase year-over-year and 7% increase sequentially. Additionally, AMGP announced a distribution of $0.108 per share, or a 44% increase sequentially. The first quarter distribution at AM was the 13th consecutive distribution increase since its IPO and the AMGP distribution was the 3rd consecutive distribution increase since its IPO. Turning to Page 5 titled Delivering on November 2014 AM IPO Promise, I wanted to touch on our track record of delivering on our distribution and coverage targets. We’re extremely proud that we have delivered on all of our distribution growth targets since our 2014 IPO, including through the commodity downturn. In fact, in addition to delivering on our distribution targets, we have exceeded our DCF coverage targets by 22%. This outperformance is driven by our just in time capital investments philosophy, disciplined financial policy, an integrated plan with Antero Resources. Now let’s move on to first quarter results beginning with Slide #6 titled High Growth Year-Over-Year Midstream Throughput. Starting in the top left portion of the page, low pressure gathering volumes were a record 1.8 Bcf per day in the first quarter, which represents an 11% increase from the prior year quarter. Compression volumes during the quarter averaged a record 1.4 Bcf per day, a 37% increase compared to the prior year quarter. The growth in compression volumes was driven by AM adding two new compressor stations, or 440 million per day of incremental compression capacity during the quarter. High pressure gathering volumes were 1.8 Bcf per day, a 12% increase over the prior year. High pressure volumes were 95% of low pressure volumes, which is the typical relationship. Joint venture gross…

Ladies and gentlemen, at this time, we’ll begin the question-and-answer session. [Operator Instructions] And our first question today comes from Jeremy Tonet from JP Morgan. Please go ahead with your question.

Good morning. I want to start off…

Good morning, Jeremy.

…thanks. I want to start off with the frac volumes at the JV. It looks like it came down a little bit quarter-over-quarter here. And I was just wondering if that was related to Mariner East outage, and if you could provide any color and how you think those volumes will trend next quarter? And just kind of thoughts on NGL takeaway from the basin?

Yes, processing, as you know, for Antero, volume is all at Sherwood, which was up. The fractionation volumes, however, have third-party volumes and those were down quarter-over-quarter. And that was really due to the weather and pipeline disruptions and not as much, I mean, one during quarter. But the Hopedale frac number 3 was down due to the third-party volumes.

Gotcha. And do you expect resolution to that? Should we see a bounce back this quarter or?

Yes, you should.

Okay, great. Thanks for that. And just want to see with regards to the fresh water, if you could provide a little bit more color there. I think, 1Q was a bit strong of an uptick than we were thinking not as much over the fourth quarter. Is it just kind of timing there, or any other color that you can provide as far as how you see that ramp goes up across the year versus your guide?

Yes, it is timing. It’s actually, it should be down going forward approximately 10% to 15%. You can really kind of see that in the fresh water wells that were serviced during the quarter. That was – we serviced 46 wells in our guidance for those freshwater with a 150 to 160. So just looking at that and maintaining that guidance, it should be about 35 wells per quarter going forward that’s down about 10% to 15%.

Great, thanks. And then one last one. I think, you noted the high pressure, low pressure relationship being about 95%, and that’s typical I’m just wondering is that a typical level kind of across the forecast period, or how should we think about that?

It is – that was really a comment made, because when we had some issues with Washington Gas and Light, it had to move gas up towards the many in South what we use high pressure lines from Antero Midstream called the bobcat connector. So we had more high pressure volumes and low pressure in the third and fourth quarter of 2017, and that is not typical. The typical relationship is 95%, that returned in the first quarter, as everything was flowing as planned.

Great. And one last one, I’m pretty sure you won’t be able to answer, but maybe try anyway. As far as the committee, is there any timeline is when there might be resolution a certain period when it would be daunt and if we might expect to be something there?

No, there really isn’t. We’ve said a matter of months in terms of resolution rather than quarters. But there is no particular dropdown date on that. It’s underway. They’re working diligently. There’s progress being made as far as all we can say at this point.

That all for me. Thanks for taking my question.

Thanks, Jeremy.

Our next question comes from Matthew Phillips from Guggenheim. Please go ahead with your question.

Thanks, guys. A follow-up NGL question here. I mean, this was discussed briefly on the AR call. But could you elaborate on the IRS, as you see it for dry versus rich development and kind of the decision process over remainder of this year into next year for capital allocation on dry versus wet wells?

Yes, I think it’s safe to say that, we see a multiple in terms of the returns – the rates of return that we see on the rich gas wells versus dry gas wells today. And I think, somewhere best dry gas wells are really going to be the – how you look at dry gas well, the ones we just brought on in December. And even then, if those don’t compete head-to-head with the rich gas returns that we see, particularly 1,250 then 1,300 Btu is kind of our main corner these days, and that’s where we see two and sometimes even three times the returns in the rich gas area that we see in the dry gas. So that’s on a half cycle basis. But similar relationship holds maybe even more so on the full cycle basis.

Got it. So I mean, even if we were to see NGL prices, it’s come off a bit here. It wouldn’t necessarily impact the decision to switch primarily over to dry, it sounds like, I mean, there’s a pretty big cushion there?

Yes, that’s correct. We stick with the rich.

Got it. That’s all for me. Thank You.

Thank you.

Okay. Thanks, Matthew.

Our next question comes from J.R. Weston from Raymond James. Please go ahead with your question.

Hey, good morning.

Hi.

I just want to ask about Clearwater for the rest of the year. It sounds like commissioning was fine-tuned a little bit in the first quarter. Just wondering, if there’s any color on kind of the ramp up, I guess, if you want to call it that in the second quarter and then for the balance of the year. And then just any updated thoughts on the possibility for third-party business, given the excess capacity?

Yes, we expect that to come on in the second quarter when we deem it to be in operation, it should be around 40,000 barrels of water per foot. That’s actually ahead of our initial projections a couple of years back when we thought it would come online with 30,000 barrels of water. But that’s because the advanced completions, however, using or using more water. So we have more produced flow back quarter. So 40,000 barrels a day of water throughout the year starting sometime mid-second quarterish.

And so in terms of third-party volumes, the plant can ultimately process 60,000 barrels a day. So there’s a delta of 20. The time period is not that long before we fill it with all Antero volumes. So we do have the potential to take third-party volumes in the meantime, which would be maybe over the next six or eight months. And the cost that third parties compete with is – their alternative is to haul the water to Eastern Ohio for injection in general and that’s more expensive. So we are optimistic that we’ll be able to fill the void for that interim period with third-party volumes.

Thanks for that helpful color. I guess, maybe kind of switching gears a little bit. Just wonder there any updated thoughts on the outlook at AR just based on the obstacles that Rover and Mariner East have kind of faced over in the last several months. Just wondering if there’s any change at AR and what that could mean on the midstream side? And maybe if you could talk about some of the takeaway capacity alternatives if those projects are further delayed?

Yes. So we’re very close with Rover. Rover Phase 1 has already made it to Clarington and to Sherwood. So it has made it to the Utica, and it’s in the final throws, the next month or two of making that to Sherwood. And so in the meantime, we do have enough capacity before Rover comes to Sherwood to move our gas to – we have enough FTE to take into other markets. The alternatives generally, it would be to TETCO, Dominion and some going to the Gulf through our Tennessee. So should be good. We do have those good alternatives on the gas side. We are looking forward to Mariner East 2 on the liquids side, of course, and the estimates are second quarter to maybe risk third quarter. And so we’d like to see that. I think, Glen spoke in the last conference call that there could be a get to cash flow of its delay through the end of the third quarter cash flow to AR, roughly $30 million. So we’d rather have it and not during the summer. The winter, where the Northeast region can absorb a lot of the liquids. So there are good local markets. But once you get into the third quarter, then you do have to rail to Conway and so you do see a price decrease, and that’s what hits the EBITDA cash flow. And that $30 million was further delayed to year-end, so we certainly don’t anticipate that. But if it were delayed six months towards year-end then AR could see a hit somewhere in the $30 million ranges because we’d have to rail that product rather than ship it by pipeline.

I appreciate all the color. Thank you.

Yes. Thanks, J R.

Our next question comes from Vikram Bagri from Citi. Please go ahead with your question.

Good morning guys. The first question I have is, AM and AMGP entered into these amended and restated indemnification agreements with the executives recently. Can you talk about what the major changes were and if that is related to the special committees and maybe I’m reading too much into it, but does that mean special committees are making progress sooner than expected?

Yes, I would say that those were just clean-up items as the outside council of a special committees looked at the indemnity agreements to make sure that there’s plenty of protection for independent board members and all that, so that often happens when you have a different set of legalize looking into documents. So I would just phrase that as or put in a box of just cleanup work so and I wouldn’t read anything into that relative to progress or anything material, no.

Great. Switching gears, the second question I have is about maintenance CapEx. The D&C maintenance CapEx at AR is somewhere around $500 million. How should we think about number of maintenance [Technical Difficulty]?

Vikram, you cut out, I don’t know, if you’re still in the line. But if so, could you repeat that last part of the question?

You cut out just at the how should we think about maintenance CapEx?

Yes, I guess, I anticipate his question, but it generally runs about 10% to 12% of EBITDA for Antero Midstream going out, so that same $500 million you referenced for AR for the five years, if you’d put kind of 10% and 12% on the – of EBITDA that’s generally in the range where it comes out at.

[Operator Instructions] Our next question comes from Ethan Bellamy from Baird. Please go ahead with your question.

Gentlemen, any further thought on third-party midstream service opportunities and separately potential M&A at the midstream level?

Third-party I think it really falls, Ethan, into that, the water category, whether it’s fresh water or wastewater treatment, I think that’s the – those are the most near-term third-party opportunities for us. As far as M&A at the midstream, the organic growth story is so prevalent here. I’d say it’s not highly likely, but we do keep on our eye on that assets in Appalachia and there is always that potential.

Okay thanks, Glen.

Thank you.

Thanks Ethan.

Our next question comes from Holly Stewart from Scotia Howard Weil. Please go ahead with your question.

Good morning gentlemen. Maybe just a quick focus on ME2 and I guess I apologize if I missed this earlier on, but what has been causing the delay to get that project in service?

What has been causing the delay Holly is – the difficulty is they get down on the east end of the line so their end of the suburbs of Philadelphia as they get towards Marcus Hook and so because there is culture there, the preferable way to do the stream crossings and other crossings is to bore it, so horizontal directional drilling to go underground rather than open trench. So, the more straightforward way in a lot of cases is to do open trench crossings, but in an area with a lot of population it’s harder to do that. And so I’ll put my geologics land on it that over in that Philadelphia area the bedrock that they have to drill into is anamorphic rock it shifts and so it’s highly fractured. And so, as you’re drilling a horizontal directional boring, you’re trying to – you use drilling mud in order to clean out the cuttings and it all comes back to the surface in a well-behaved system. But if you have fractures down there then the mud starts seeping away and it can come up anywhere along the fracture and that’s what they call inadvertent return. So I don’t know where it comes up. They monitor and it sounds as though, the quantity is quite small, but still they’re very sensitive there that – and the drilling mud is natural ingredients usually, it’s Bay right, which is a clay, which is just mind out of the earth. But it stops the leakage or they go into fractures. But when it’s highly fractured, then it’s hard to control that. So they’ve had these inadvertent returns. And so with abundance of caution, they get shutdown until they can develop a new plan and there’s a waiting period. Each time they get shutdown, there’s a time period, it might be 360 days to appraise the situation, consider the solution and then go forward, again. So they’re in the final throes, but it’s not easy for them, so we understand.

Okay. So we’re still in a waiting period, I guess, on moving forward?

Right. Yes, optimistically, the end of this quarter and risk then in – sometime in the third quarter.

Okay. And then, I think, you’ve referenced in the past the potential investment in that project. Is that something that you’re still considering sort of post-in-service, or how do – is there a timeline that you would have to make a decision on that, or how should we think about that?

Yes, we said in the past, Holly, that’s one of the – ones downstream that we’ve had our eye on. I think, there’s still potential for that and time will tell.

Okay.

We’d like to see it get completed and them maybe something happens there we’ll see.

Okay. That’s great. Thanks, guys.

Yes. Thanks, Holly.

And our next question is a follow-up from Jeremy Tonet from JP Morgan.

All right. Thanks for taking one last one.

Sure.

For modeling purposes, thinking forward as far as AR production growth goes, is there – how should we think about what volume goes towards the JV processing side versus kind of maybe legacy MPLX processing units? Is there any guides that you can provide there?

All incremental growth goes to our JV.

Gotcha. That’s it for me. Thank you.

Thank you, Jeremy.

Thank you.

And at this time, I’m showing no additional questions. I’d like to turn the conference call back over to management for any closing remarks.

Thank you for joining us for our call today. If you have any further questions, please feel free to contact us. Thanks, again.

Ladies and gentlemen, that does conclude today’s conference call. We do thank you for attending. You may now disconnect your lines.