Good day and welcome to the Antero Midstream Partners LP Second Quarter 2017 Earnings Conference Call and Webcast. [Operator Instructions] Please note that this event is being recorded. I would now like to turn the conference over to Mr. Michael Kennedy, Chief Financial Officer. Please go ahead, sir.

Thank you for joining us for Antero Midstream’s second quarter 2017 investor conference call. We will spend a few minutes going through the financial and operational highlights and then we will 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 forecasted in such statements. 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 will now turn the call over to Paul.

Thanks Mike. Thank you to everyone for listening in to the call today. In my comments, I will focus on the productivity gains at AR and the associated benefit to AM and discuss the continued momentum in the processing and fractionation joint venture with MPLX. Mike will then talk through second quarter results and operational updates at Antero Midstream and finish with the long-term outlook at AM and AMGP. First, I will begin my discussion with the continued improvement of Antero’s higher intensity completions and how it benefits AM. On Slide #2, titled Higher Intensity Completions Driving Outperformance, we’ve illustrated the impact to production performance from various proppant intensity levels. The black dotted line represents our legacy 1.7 Bcf per 1,000 foot of lateral cumulative-type curve, which is the type curve that we have historically used both for internal forecasting and reserve bookings. The black dash line represents an improved 2.0 Bcf per 1,000 type curve, based on results from our advanced completions, dating back to early 2016. And finally, the various colored lines represent the average cumulative wellhead production per well, normalized to a 9,000-foot lateral, corresponding to various levels of proppant intensity. While we are still in the early innings of analyzing the impact from these advanced completions, we do have over a year of production history for wells that were completed with 1,500 pounds of proppant, which is shown in green. This dataset easily supports the 2.0 Bcf per 1,000 type curve outlined on this slide. Towards the end of 2016 and through the first half of this year, we’ve continued testing higher proppant loads, which we put in 2 buckets, 1,875 pounds and 2,500 pounds per foot, shown as red and blue lines, respectively. As illustrated on this slide, these completions, using higher proppant loads, have…

Thank you, Paul. First and foremost, it was a record volumetric quarter for Antero Midstream, which allowed us to announce the second quarter AM distribution of $0.32 per unit, a 28% increase year-over-year and maintain a very attractive DCF coverage of 1.5x. In turn, AMGP announced the distribution of $0.027 per share, which represents the prorated second quarter distribution for the period following the closing of the IPO on May 9. The second quarter distributions at both AM and AMGP keep us on track to achieving our previously provided distribution growth and DCF coverage targets at both entities. Now let’s move to second quarter results, beginning with Slide #5, titled high growth year-over-year midstream throughput. Starting in the top left portion of the page, low pressure gathering volumes were 1.7 Bcf per day in the second quarter, which represents a 24% increase from the prior year quarter and 1% increase sequentially. Compression volumes during the quarter averaged 1.2 Bcf per day, an 81% increase compared to the prior year quarter and a 16% increase sequentially. On average, our compression was over 83% utilized throughout the quarter. High pressure gathering volumes were 1.7 Bcf per day, a 38% increase over the prior year and a 10% increase sequentially. High pressure volumes were slightly higher than low pressure volumes due to Antero Resources utilizing AM high pressure pipelines to avoid third-party downstream pipeline constraints on a temporary basis. Joint venture growth processing volumes were 216 million per day and gross fractionation volumes were over 4,000 barrels per day. Due to the timing of equity distributions received from the joint venture, the financial impact of these volumes on Antero Midstream’s EBITDA will occur beginning in the third quarter of 2017. Moving onto the water business, freshwater delivery volumes averaged 173,000 barrels per day,…

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

Good morning. Just want to touch base with building out the value chain further downstream and asset type for more assets there, there is multiple projects that are being built right now that could be looking for joint venture partners and just wondering your thoughts on the need for incremental NGL mega takeaway out of the Northeast and your appetite to enter into a JV there?

The need for projects – I think Mariner East 2 will be a very significant project with good expansion capabilities. So that should be a primary project that will really help NGLs find their way to market. So there are others that are proposed, but that’s really a prime one. And in terms of downstream infrastructure, whether it’s that or other pipes and gathering, Antero does consider those from time-to-time. So it’s possible, but nothing’s on the front burner.

Okay, great. Thank you. That’s it for me.

Alright. Thank you.

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

I just had a question on the lateral links progression, maybe the implications for midstream CapEx, so I think you guys have been vocal about what that means in terms of potential DMC benefits, but thinking through more on the midstream side, if you are effectively draining more of the reservoir from each pad, is there a chance that we have a slightly reduced capital needs in the midstream side as well, just given less feet on the ground?

Well, that relationship is very true that you are talking about, so more reserves for the build-out CapEx. But we do – so many of our 3,000 plus locations are all engineered out. And so that’s built into future CapEx at this point that’s already being taken account of. So mostly that’s in our numbers, but you are right that the longer the laterals, the more efficient the midstream infrastructure.

Okay, that’s it. Thank you, guys.

Thank you.

Our next question comes from Darren Horowitz of Raymond James. Please go ahead.

Paul, a quick question for you, as you guys continue to experiment with increased completion intensity and obviously, you have spent a lot of time on Slide 2, you are meaningfully outperforming the type curves, how should we think about what that lends itself to with regard to both high and low pressure volume upside in addition to what it could mean for sustainable water demand that’s running higher than what’s in guidance?

Yes. Well, I think you are headed in the right direction, which is yes, as we increased the proppant intensity, the recoveries will be higher, so there will be more volume for the midstream. And as one boosts the proppant intensity, you add water, so the water goes up. And so there will be more water and throughput in our midstream infrastructure. So both headed in that direction, we don’t know where the point of diminishing returns are, but we will eventually get there. We are inching our way up, knowing we are pretty conservative and deliberate in our methodology. So we are starting on the low side and just doing increments and not changing too many variables at a time. But we will figure out where the optimum is, but it’s headed in a direction of more gas volumes and more water throughput.

Thank you. That’s all I had.

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

Hi guys. What in-service states are you modeling and expecting for Rover and ME 2?

I would say we are closer to Rover. Certainly we are in contact being anchor shipper with Energy Transfer. So we do get updates. We get updates from the company. We also get updates from their regulatory agencies that in broad brush regulatory processes are going on and they are working with Energy Transfer and vice versa. So we see their projects progressing. We risk at that Rover Phase 1, which is the Seneca in the Utica will be in service September, October. And then Phase 2 for Rover, which is to make it to Sherwood, is a couple of months behind that, so in the October to December range. Mariner East 2, we are not as close to, certainly we are following it, but don’t have a date. Certainly, their target is fourth quarter of this year.

Do you want to buy a stake in ME 2?

Not today, we will see where that goes, but we are always interested in looking at downstream projects and with the idea that maybe we would participate, but there is nothing on the front burner there or with other projects at this point. But we consider all of them, whether we are invited or we just think about it as we consider committing volumes, whether it’s gas or liquids. We will consider whether we want to invest in it. It really depends on the economics of the specific projects.

Okay. And I apologize if this was mentioned on the AR call, I was otherwise engaged, but have you talked about the implications of the EQT-Rice merger on the basin and what if any impacts you think that might have on service costs or overall production and kind of how you approach the business?

Well, we acknowledged. We mentioned the EQT-Rice merger on the AR call, but we didn’t talk about it in the context of service costs and I think I am not sure what I would say to that. I think the overall growth of the combined entity is not going to be equal to the two separate ones. So will there be fewer rigs needed and fewer completion crews that – I don’t know if it’s one plus one equals 1.75 or what their plans are exactly. But don’t see that as a big impact. It’s going to suck up a lot of rigs and completion crews. We are seeing the situation right now is not too – not overly tight in Appalachia for either rigs or completion crews. We are able to get quality rigs and crews. And of course, there is need for fewer of them, just because of the operational – the advances that have been made, both in drilling more off of pads and being able to have higher penetration rates. And then with zipper fracking instead of stack fracking, being able to accomplish so much more with the completion crew. So not really fearing a big tightness resulting from either overall environment or that merger.

Okay. One last question, when could we expect to see you sanction – the future processing complex that you mentioned, is the gating factor finishing the Sherwood build-out first or could that get going in advance of completing the Sherwood build-out?

Yes. It will definitely get going in advance, just because there is plenty of advance work that needs to be done before one starts putting in plans. There will be obviously excavation, but siding it near takeaway and NGL lines coming in. So it’s probably going to happen in the next six months to nine months. And there will still be several years of build-out at Sherwood, where we are finishing out the plants there. Our line of sight now is for Sherwood 9 in January of 2018, but we think there is room for 11 plants or 12 plants at Sherwood in total, maybe even 13 plants. So still have some build-out to go at Sherwood, but we will start doing the preparation at the second site once we decide where it is.

Great. And would that be a JV project as well or would you do that all in-house?

That will be a JV project.

Okay. Thank you.

Thank you.

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

Good morning guys. Just one, maybe quick follow-up on the available capacity for initial third-party volumes at the water facility, I recall there is a point where you will need that whole facility at AR, but just kind of trying to think through what you could market initially to third-parties and how long that timeframe would be?

Yes. Holly, we have that graph of actually in our presentation. Initially, we will have up to 60,000 barrels a day of capacity and there will be about half fall upon – we are starting in the fourth quarter. So starting with 30,000 barrels, you have 30,000 barrels of additional capacity. We fill that within 2 years, so by mid-‘19 that’s full. So we will have that window of time during those 2 years, where we will be able to market it to third-parties and have opportunities there.

Okay. And then Michael, there is conversation ongoing now?

Yes. We have a fairly active water business development group that’s looking into all those opportunities. So we will try to hit the ground running there.

Great, that’s all I had. Thanks guys.

Our next question comes from Barrett Blaschke of MUFG Securities. Please go ahead.

Hey guys. Just a quick question on the JV and sort of any updates on what you see the scope of this turning into over time, obviously now looking at Sherwood 11, I mean how much further out – how much more runway is there to continue to grow the JV?

There is good runway. There will be a number of other plants. So we feel good about – through Sherwood 11 and whether – as you just heard, whether we put 12 or 13 there, put them at the second site, not sure. But there will be probably multiple plants beyond what we feel at Sherwood. So I am not sure whether it will be 3, 4, or 5 plants, but somewhere in that range beyond what we do at Sherwood.

It contemplated, it covers about 11 plants in total, so that is sort of the build-out. And as we continue to add acreage, that number grows. So the first 2 of the 11 are online and full, and 9 more to go anyway under the arrangement.

Just a quick follow-up if I can and that is, at what point in that process do you – does it ever become an issue that you have to start looking at owning some of the downstream, just on the takeaway side?

No, I think there is enough third-party providers that – now are you talking liquids or are you talking residue gas, Barrett?

Particularly liquids, I think?

Yes. I think there will be enough providers and an up takeaway between Mariner and some of the other projects ATEX [ph], of course. I don’t see that we have to own anything.

Okay. Thanks.

Thank you.

This concludes our question-and-answer session. I would like to turn the conference back over to Mr. Michael Kennedy for any closing remarks.

Yes. Thanks everyone for joining us on our conference call today. If you have any further questions please feel free to contact us. Thanks again.

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