Good day, and welcome to the Antero Midstream Partners Third Quarter 2016 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 today’s event is being recorded. I would now like to turn the conference call over to Chad Green. Please go ahead.

Thank you for joining us for Antero Midstream's third Quarter 2016 investor conference call. We'll spend a few minutes going through the financial and operational highlights and then we'll open it up for Q&A. I would also like to direct you to the home page of our website at www.anteromidstream.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 Midstream management will make forward-looking statements. Such statements are based on our current judgments regarding factors that will impact the future performance of Antero Midstream and its sponsor, Antero Resources, 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. Joining me today on the call today are Paul Rady, Chairman and CEO, of Antero Resource and Antero Midstream; Glen Warren, President and CFO of Antero Resources and President of Antero Midstream; and Mike Kennedy, CFO of Antero Midstream. I’d now like to turn the call over to Mike.

Thanks, Chad, and thank you everyone for listening into the call today. In my comments I’m going to highlight our third quarter results and growth opportunities. Paul will round out our comments by providing an update on AR’s operational improvements and acreage consolidation activity. During our comments today, we will commonly referenced AM and AR in order to more easily make the distinction between Antero Midstream and Antero Resources. First and foremost was another strong quarter for Antero Midstream both operationally and financially. AM announced the third quarter distribution of $0.265 per unit, a 29% year-over-year and a 6% increase sequentially. The distribution marks our seventh consecutive distribution increase since the IPO in November 2014. As you can see on slide number two, titled, top tier distribution growth and coverage, AM continue to deliver top-tier distribution growth while maintaining outstanding DCF coverage of 2 times during the quarter. Well in excess of the targeted coverage ratio of 1.1 times to 1.2 stated at the IPO. Given the amount of growth opportunities we see today, excess coverage has been used to maintain a strong balance sheet and save some dry powder for the attractive growth opportunities that we see at AM. Now let’s move on to our operating results during the third quarter. As a reminder, the quarter’s results and year-over-year comparisons both include contribution from the gathering and compression and water handling and treatment segments on a combined basis after successfully closing the water dropdown transaction at the end of the third quarter of last year. As highlighted on slide number three, titled, high growth midstream throughput, average daily low pressure gathering volumes were 1,431 million per day in third quarter, which represents a 38% increase from the prior year and a 6% increase sequentially. Compression volumes during the quarter…

Thanks Mike. Today I will discuss AR’s results and operational achievement and finish with an overview of AR’s year-to-date consolidation efforts in the Appalachian basin, which in turn provides tremendous opportunities for AM. AR reported another strong quarter producing a record 1.875 Bcf equivalent per day which represents a year-over-year increase of 25% and drove the strong volume metric throughput growth at AM. Additionally, AR's average realized gas price before hedges was $2.86 per Mcf or a $0.05 premium to the NYMEX Henry Hub price and $1.70 higher than the average Dominion South price during the quarter. Dominion South index traded as low as $0.20 per Mcf during the quarter and traded $1.65 back of NYMEX on average due to takeaway constraints in the basin as well as the seasonal impact of the shoulder months. Fortunately, AR has already secured the lowest cost transportation to favorable markets and price nearly all of its gas at favorable markets outside of Dominion South and other similar markets such as TETCO-M2. Looking ahead, AR has ample firm transportation capacity to avoid selling gas into unfavorable markets in order to continue delivering pure leading cash margins and production growth which ultimately benefits Antero midstream. Now let's move on to discuss the operational efficiencies and cost reductions AR has achieved over the last year. On slide number six entitled proven track record of well cost reductions AR has reduced its well cost by 36% in the Marcellus since 2014 to $0.86 million per thousand feet of lateral. The bottom half of the slide illustrates that AR has seen similar success in the Utica with well cost totaling $1.01 million per thousand feet of lateral, 35% decline since 2014. Additionally, current Marcellus and Utica well cost represent an 18% and 15% reduction respectively compared to well…

Thank you. We will now begin the question-and-answer session. [Operator Instructions] The first question comes from Brian Brungardt from Stifel. Please go ahead.

Good morning and thanks for taking my question. On the earlier call, you guys discussed water per foot as you deploy the higher profit designs. If 1,500 pounds per lateral foot is the base case and you are seeing pilots with 1,750 or 2,000 pounds per lateral foot could you provide some color as to what the mix may look like between the different well design plans as you look to complete those 175 wells in 2017?

You can see on page 4 of our presentation addresses the pounds of sand per foot and the barrels of water per foot. It is mostly proportional. I think that one can expect that as we go into piloting where we go above what we talked about our base design is 1,500 pounds per foot now but as we pilot 1,750 and 2,000 pounds per foot there is going to be commensurate or proportional increases in water volume. It will be either proportional or slightly less than proportional. Why is that? We see of course whenever you are in these shale plays, these resource plays, you want to keep the frac relatively closer to the well bore when you are on 660 in your lateral distance. And so by using slightly less water it adds what we call more complexity to the fracs which keeps it closer to the wellbore and doesn’t spread it real far away. So it will either be proportional or slightly less than proportional as we go up to the 1,750 and 2,000 pounds a foot.

To follow up on that I guess conceptually and I realize it's preliminary for 2017 at this point but with that be 150 wells using a base case in the remaining pilots or kind of what is the mix there.

I think it's hard to say not to determine yet but the base case is 1,500 pounds per foot. We’ll be piloting, we will continue to pilot, we will not see results on those pilots for some time, you really have to watch the production for a while to see what kind of impact you're getting so I think it's safe to say in the 1500 pounds with some mix of 1750 and 2000 pounds next year.

Yes. And the magnitude of the higher, the 1,750 and 2,000 out of 150 wells, it might be 20 to 30 that are the higher profit loading but we can make a game time decision midyear, next year if we see the early response is going well it could be higher, higher proportion but as Glen said that 1,500 is the base.

Gotcha. Appreciate the color there. And then lastly, you guys have previously discussed the option for developing processing capacity. And you guys earlier commented about the uplift for the parent on improved liquids pricing, there is also the slide looking at the acreage footprint opportunity. I am just curious if you could provide any color on the decision process and when you see the potential opportunity as it relates for the partnership.

I think the timing is hard to say. It's more than a dream. We certainly have a lot of discussions along those lines and it is something that we still are interested in doing in terms of participating and processing fractionation and other downstream activities particularly on the D&G side but also on the regional pipeline side. So it is hard to predict timing at this point but it is something we continue to be focused on for sure.

The next question comes from J.R. Weston from Raymond James, please go ahead.

Thanks. First question here, a lot of talk on the water business today which had another nice quarter 35 wells this quarter and up to 96 now for the year. Just curious what you're signaling for Q4 well service given the original guidance I think was 110 to 130 completions for the year and I think the recent material has been closer to 110.

It will be a similar tempo and cadence to the third quarter, the completions that were talking about when we referenced the water is completions that are actually in progress, 110 was the number of wells to be completed during the year so it would be in excess of 110 but similar to the 35 in Q3.

Great thank you for that clarification and I guess extending out to 2017 again it might be a little bit of a difference there but you talked about the total figure, is there anything else we can look at. It’s kind of help shape the quarterly progression for next year and obviously price probably has something to do with it but also may be take away with any of the projects slated for completion next year is there any other factor.

No we have 180 wells on those slides to help you kind of model that I would have it fairly ratable throughout the year maybe a little frontend loaded in the first half just because of the completions deferred being completed in that timeframe but I would model it out ratable over the four quarters.

Okay, great. That’s helpful. Shifting gears and last one for me kind of touched a little bit on the longer-term perspective on the last question with processing I was just wondering if we could get into kind of the acreage consolidation that AR has been doing and you guys have been giving guidance in the past quantifying what that would mean for AM but just wondering if there is anything different as to how you are thinking about the opportunities there? Just any other conclusion if we try to maybe draw from that.

We certainly we've said that our acquisitions and as we noted we added some 85,000 net acres in the last period this year, so all of that we said our criteria and certainly our preference is to be able to consolidate either base leasing or in groups or packages that we see that it is undedicated and so that of course immediately goes to AM for its dedication and so we've been successful at that with very little exception. So certainly we continue to see opportunities and we strongly prefer on dedicated not only to be able to support AM but also to control the direction of the gas and so sometimes a dedication with some of these packages not only does it go to a third-party provider but then you either end up at TETCO-M2 or Dominion South and can't bring it to the favorable markets. So that's part of our strategy, we will continue to consolidate still see good opportunities but the ones that rise to the top of the list of course geology et cetera plays a large part but also to be able to dedicate it to AM and bring it to the best markets.

Our next question comes from Jeremy Tonet from JPMorgan, please go ahead.

Good morning.

Good morning.

Good morning.

I was just wondering about the guidance it seems like it was unchanged there and if I am looking at it right, it looks like Q4 maybe a little step down versus Q3 here and I imagine that it may be related to the water business so I'm just wondering with the water business is it going to be kind of lumpy here any other thoughts that you can share with us on that.

Jeremy I think the guidance is based on AR's risking of their development plan and risking of the field and infrastructure required. So I think there is some conservative around that and AM is just following that from a throughput consideration and also from a completion pace. Glen mentioned earlier some of the deferred completions will start to have activity in Q4 that will obviously benefit the water business. So we do not see really a step down in Q4, I think there is some conservatism built into the guidance.

Okay great. And then just kind of a higher-level question and you guys are very well hedged and situated in general but you know there's been concerns over regulatory process and environmental issues kind of slowing down pipeline development in the Northeast. I was just wondering if you could share any thoughts on how you see that impacting your business model again recognizing that you guys are very well hedged and have a lot of take away capacity locked in so far.

We are very well hedged, quite fully hedged through Cal 19 and significant volumes in 20-22 hedged the NYMEX side generally. We used to hedge basis as an aside but since our pipe now takes us to the premium markets we are comfortable and just hedging NYMEX. But back to regional pipes, yes there is a number of them the further you go Northeast the more difficult the situation is whether it's Constitution, Atlantic sunrise, pen East they all have their issues permitting issues regulatory. I think generally the market feels that they will get those through in time it may be a little slower than expected. Other slightly more important projects that don't directly affect us but could indirectly would be Dominion's Atlantic coast pipeline and EQT mountain valley pipeline taking gas to the Southeast. Those we are not shippers on but those are – they have different characteristics but they are you can call them straws into the pot into the pool that could help to drain the TETCO-M2 and indirectly TETCO-M3 and further East. So draining the pool can help to have more market outlooks and that will make higher prices there not as much distress gas both of those pipes come right through our areas and especially Atlantic Coast is a utility pole you are aware that it's utilities that hold the transport on Atlantic Coast and they hope to be buyers in our area and a little bit further north. So if the prices are favorable than we could definitely be selling gas into those, if not indirectly it just helps in draining the overall pool. So we see Appalachian basin unlocking over time. Certainly the timetable the ramp for these you know they are scheduled to be late 2018 or 2019, it is hard to say they are going to be later than that and to handicap it. So I think there are experts that are out there projecting that and we don't disagree that it could happen in the time of late 2018 and 2019 and it will be overall beneficial for Appalachia but as I say we are not direct shippers on any of those. We are pretty well taking care of in fact we are very well taking care of through Cal 20 with our own FT going to premium markets. So as I say it only indirectly affects the overall environment that we are taking care of.

Great thanks for your thoughts there, that's it for me.

Thanks.

Next question comes from Ethan Bellamy from Baird. Please go ahead.

Hello gentlemen, with well cost reductions really impressive but also coincident with a collapse in oilfield services market, if we get back into recovery whether that's 2017 or 2018 particularly in the Northeast, how much of that are you going to give back on the upside as you're getting ready to go up? And then along the same lines, you’ve had really good cost control in the midstream side of the business. Are those sustainable and is there anything exposed on the upside in terms of inflation at midstream?

We are Glen made the point earlier in our previous call that one can do so much more with less with rigs and with frac crews, with rigs it the penetration rate and pad drilling in with frac crews it is super fracs instead of fracs where you can frac up to nine or 10 stages a day versus a more traditional two, three, four stages a day. So we don't see the pressure on the service side that there are still lots of rigs and lots of completion crews that are available. We have been locking in longer-term rig rates that are roughly 60% of what they were on our legacy contracts that we entered into at least four years ago. So there's some savings there how much what we need to give back on either drilling or completions I don't know maybe 10% or so that we could be giving back over the next number of years. We are doing what we can do lock-in and lock-in the rates that we see right now. Are we at the low not sure obviously depends on product prices. I would say we might have to give back a little but not go back to where we were four years ago.

Okay and on midstream?

Midstream seeing the same things that you know we’ve rung a lot of costs out of the system and don’t see it will have to give much back that it's good cost control as we become more and more experienced in our area. We just are better at executing the projects and with advanced design and mitigation and so on, so don't see us giving a lot back there either.

Okay. And then going back to the dead horse of export capacity out of the basin, your FT at AR seems to have oscillated between an asset and a liability for investors, it’s pretty clearly an asset right now in terms of net backs. If you were to re-contract on Rover today, is that capacity worth more or less than you’d signed up for it and specifically on Rover have you been approached about taking over the commitments from any of the other potential shippers particularly sent and then lastly has there been any serious talk of consolidation of maybe Nexus and Rover and would you be in favor of something like that?

As we understand from through the Grapevine, there has been discussion between Nex and Rover – Nexus and Rover and that would be okay. I think we’re advantaged by having more takeaway out of the basin from what we understand those parties haven’t gotten together and energy transfer – both parties are quite happy and going their own way and doing their own projects. In terms of what our tariff would be, I think, it depends on at what time. So as Rover opens for business, there will be some excess capacity. So if we were going to be filling our capacity and moving gas around, buying third-party gas, but if we were to try and release some capacity early on with the tariff be less than what we have, yeah, probably, but it does not take that long to fill it, we see that there are large constraints. And so we see that Rover and – now Rover, I think, they may build it in a couple of phases of 1.6 Bcf a day right off the bat and another 1.6 within six months or so. But we see at least the first phase as filling relatively quickly. So we do think then that our tariff will be evenly matched or even at a discount market prices when you see what Rover has for its walk-up rate and what the latest Rex expansion their power up as they call it, they are quite a bit higher than our tariff for Rover, quite a bit higher, we’re probably at 60% of what the market rate is on the other pipes.

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

Hi, guys. Just a couple more. Paul has given a great deal of detail on the pipes and maybe specific ones. Would you care to share your sort of yours internal forecast on capacity additions for 2017 and 2018 just given that we’ve seen a lot of regulatory delays here over the last six months or so?

So our own capacity additions, we are feeling good about, what others capacity additions in 2017, 2018, it's really Mountaineer Express and the Columbia site going from north to south and so that comes through our area and goes to the TCO pool and then there is an additional project that’s associated with the Gulf Express that takes more of that gas and moves it down to the Gulf. And so feel good on timing there that's third quarter of 2018. We also have a smaller project called the WB line, which is the Washington Baltimore line, that’s an east-west project that we are shippers on and that has an expansion on it right now and we expect that to come on the first part of it in the end of 2017 and the second part of it in 2018. So the ones that affect us most in our Marcellus play, the Mountaineer Gulf and the WB are on target as we see it, we feel pretty good about those. We’ve talked about Rover a little bit, Holly, and that again we project as mid-2017 to mid-2018 and feel good about that. We will have better clarity by first quarter of 2017 as do they have their permit to build and how is the construction progressing. So for our own projects feel that they are on schedule, there is no great environmental uprising or lack of cooperation by government agencies to try and slow it down.

Any thoughts on just the entire basin?

Yeah, the entire basin, it's the projects that I named and all of those straws in the pot are going to pull gas away. What are those important once again it’s Constitution, Pan East [ph] and Atlantic Sunrise over on the east side of the Marcellus, it's Atlantic Coast and Mountain Valley on the southeast side, to the northwest it's Rover and Nexus. So what does that add up to at least seven projects plus the Mountaineer, Gulf, Leach Express, so 10 projects in total. I think our total capacity is 15 Bcf a day between those 10 projects that I named that will be between now and the end of calendar year 2019 and those 15 Bcf per day should make a dent one would hope in the Marcellus and Utica. That is quite a bit. And about half of them definitely have a cloud over them in terms of permitting constraints, but the other half look like pretty clear sailing.

Our next question comes from Erik Stevens from TPH. Please go ahead.

Hey, guys. Just a couple of questions on our end. First is on distribution growth, so kind of where you are sitting today is 2 times coverage and plenty of growth to come from additional AR volumes and increased completions intensity from AR as well as the waste water facility. Could you talk a little bit about just how you guys are thinking about distribution growth going forward?

Yeah, we have distribution growth guidance out there 28% and 30% through 2017. We haven’t gone beyond that, but obviously that level of growth is an area where we are comfortable with and the amount of opportunities that we have in front of us would support that type of growth going forward as well. The 2 times coverage we've obviously exceeded our expectations from the IPO. We had a 1.1 times to 1.2 times coverage target, we’ve been above that every quarter since the IPO and continues to increase as we continue to have more throughput and expected from these advanced completions and more water usage from the advanced completions as well. So our trend above that will probably continue to grow at those levels from distribution growth and have coverage in excess of our ratio for the next couple of years.

Okay, great. And I guess maybe as a follow-up to that, is there any sense of timing as to when you guys would think to extend that distribution growth further maybe into 2018 or 2019?

No, we haven’t determined that yet. In years past it is been in around our budgeting process, which is generally the first quarter of the year as it relates to but we haven’t determined that yet.

Okay, great. And switching gears a little bit here, in the quarter you initiated a $250 million equity distribution program, it looks like you used about $20 million of that in the quarter. Could you maybe just kind of walk me through the thought process there, was that more of an opportunistic type of move and then also how should we think about the usage of that going forward?

Yeah, we put the ATM in place to fund the external opportunities kind of outside of our basic gathering and compression and water business. We did execute on one of those external opportunities when we purchased the 15% non-op interest in the Stonewall pipeline that was for about $45 million back in May. So the current use of the ATM is to fund that. We do see future opportunities outside of our base business are constantly and continuously evaluating those, that’s kind of what the ATM was put in place for.

All right. That it for me. Thanks guys.

Thank you.

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

Hi, everybody. Thanks you for taking my questions. Just a couple for me, just sort of following on Ethan's question in terms of the midstream savings, I think you were talking about 40% services savings of just percentagewise on midstream what have you been seeing?

I think our numbers were more 40% reduction and in upstream that is drilling and completion that's what we were talking about and our cost have gone down in midstream, but I'm not sure it's 40% down.

Maybe half of that somewhere in that range would be the savings we’ve seen on the midstream side from – efficiency is there as well as we get better and better at pipelining and building compression stations in the Marcellus and Utica, but also some decreasing cost from a construction standpoint, more competitive situation on the construction side.

Okay, yeah, that’s helpful. And apologies, I meant completions, sorry, about that. And then I'm just curious looking at your deck like your slide, I think it's six and seven, I'm just curious, I'm pushing the technology curve, I guess, a, how much more efficiency do you think is realistic and in terms of the production per thousand foot, you got your target there and you've got the bubble, some comments considerably above that, so I'm just curious how much better do you think that could get and how do you think it might translate into additional volumes for AM?

Well, we haven't seen the limits yet. What would be a conservative estimate as to how much further the cost could go down, could they go down 10%, maybe to 20%, what could the response be on the bigger fracs, could it be 10% to 20% higher from that 2.0 Bcf per thousand, but it’s not infinite, so maybe it's in that 10% or 15% range down on the cost and up on the results.

Our next question comes from Brian Brungardt from Stifel. Please go ahead.

Thanks. Let me jump back on here. To address the regulatory angle a little differently, you guys touched on the earlier call potentially shifting around plans if there were to be a significant delay to Rover, how should we think about the impact of the partnership if any?

Let's see, so I think we were talking actually about if Rover comes early and there's a lot of unused capacity then we can shift our Rex volumes over to Rover and by distressed gas through Rex, so it’s kind of an internal way to offset some unused capacity in terms of – if Rover is further delayed from what we estimate then we can shift more capital to the Marcellus and take advantage of some of that capacity that is unused and that we can fill that, so that would be the strategy.

Great. Thank you so much, guys.

As I mentioned we do have quite a bit of available outtake excess to go both to the TETCO and Dominion markets on the Marcellus side and TETCO on the Utica side. Should those prices heal at all then there would be take away there as well if Rover is late.

Our next question comes from Jeremy Tonet from JPMorgan. Please go ahead.

Hi, thank you for taking my question. At the risk of getting too far ahead of myself here, I was just wondering incentive distribution rates and the long-term strategy, there is a topical point among investors and AM being early in its lifespan, it is pretty low take right now, but given the rapid distribution growth that you guys could be doing next year, you could see over $0.20 on the $1 going up to the GP and the burden of continuing to move up in there and obviously with your coverage and leverage you are in a tremendous situation right now, but just wondering if you could share anything with us philosophically about how you look at idea longer term?

Yeah, I think it is important to put that in context and you don't really see other MLPs out that are completely organically growth driven like we are and if you focus on some of those rates of return pages that we have in our website presentation that's what enables us to both grow the distributions at a rapid rate for the LP, but also payout those 50% split ultimately to the IDRs. So it's really not a current issue and as long as we keep delivering those kinds of returns on the projects it's just not something that is very topical sort of internally at this point. It is hard to beat 28% to 30% distribution growth. As Mike intimated that's not something that we see going away right away.

Okay, great. That's it from me. Thanks.

Thank you.

This concludes our question-and-answer session. I would like to turn the conference back over to Chad Green for closing remarks.

Thank you everyone for joining our call today. Please feel free to reach out to us if you have any further questions. Thank you.