Good day, and welcome to the Antero Resources Second Quarter 2016 Earnings Conference Call and Webcast. All participants will be in listen-only mode. Please note also that this event is being recorded. I would now like to turn the conference over to Mr. Michael Kennedy, Senior Vice President of Finance and Head of Investor Relations. Please go ahead, sir. Michael N. Kennedy - Senior Vice President, Finance & Chief Financial Officer: Thank you for joining us for Antero's second 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'd also like to direct you to the homepage of our website at www.anteroresources.com where we've provided a separate earnings call presentation that will be reviewed during today's call. Before we start our comments, I would like to first 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 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 on the call today are Paul Rady, Chairman and CEO; and Glen Warren, President and CFO. I'll now turn the call over to Glen. Glen C. Warren - President, CFO, Secretary & Director: Thank you, Mike, and thank you to everyone for listening to our call today. In my comments, I'm going to highlight our second quarter financial results including price realizations and EBITDAX margins, touch on the attractive upside we see in an improving commodity price environment and discuss the recent equity offering we completed during the quarter. Paul will…

We will now begin the question-and-answer session. Our first question comes from Brian Singer of Goldman Sachs. Please go ahead. Brian Singer - Goldman Sachs & Co.: Thank you. Good morning. Glen C. Warren - President, CFO, Secretary & Director: Good morning, Brian. Paul M. Rady - Chairman & Chief Executive Officer: Hi, Brian. Brian Singer - Goldman Sachs & Co.: To the point you made in your comment, natural gas prices are not necessarily the driver given your hedges and FT. So, can you tell us your thoughts based on the extent of your willingness to outspend cash flow and how aggressively you see yourself – or and how aggressively you want to have your balance sheet, where you see investments moving as we go into 2017 and how we should think about that willingness to outspend cash flow. Glen C. Warren - President, CFO, Secretary & Director: Well, Brian. Yeah. This is Glen. Our balance sheet, we expect it to stay in the mid 3s in terms of leverage over the next 12 months to 18 months and then decline over time back into the high 2s just kind of naturally. So, it's something – it's leverage that we're very comfortable with. And in terms of our D&C capital for instance for next year, we expect to be pretty much in line with this year, which this year is $1.3 billion. So, should be in that same neighborhood next year in terms of capital spend for drilling and completions. Brian Singer - Goldman Sachs & Co.: Got it. Great. And then two other small questions. The first is, can you talk to the success that you're having or update us on the success that you're having in off-loading any access to FT and how that that might be…

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

Morning, Paul, Glen and Mike. Paul M. Rady - Chairman & Chief Executive Officer: Good morning. Glen C. Warren - President, CFO, Secretary & Director: Hi, Holly.

First question just on the acquisition, kind of help us think through how that activity on those new properties gets worked in over the next few years. Paul M. Rady - Chairman & Chief Executive Officer: Well, we could divide the acquisition into two parts, the part where the acreage is in and amongst our existing acreage and in and amongst our existing infrastructure, gathering, processing, compression, that will be developed almost immediately over the next 18 months. We have rigs that will include a lot of that acreage within our units. So they are nearby units, where we'll just move the rig over. And then where it's a little further afield where it's in Wetzel County is going to take some time, at least 18 months to begin building our infrastructure to be able to reach that far north. So, it'll be phased in over the next year-and-a-half, two years for the more outlying acreage.

Okay, great. And then, maybe, Glen, on the ethane volumes, just really big ethane volumes really in the second quarter, no change to the guidance that would imply some material changes in the back half of the year. So, is there something we should be thinking about with maybe that occurred in the second quarter or just how we should be thinking about the second half of the year for ethane? Glen C. Warren - President, CFO, Secretary & Director: No. I don't think so. We did not change the guidance, no. But I think you can expect us to exceed that guidance throughout the year. So, the number for the second quarter would not be an unusual number. I think for the rest of the year we just didn't change the guidance there, Holly. So, I would not expect a significant pullback in ethane volumes.

Okay. Great. And then one final one for me if I could. On slide 10, you're showing with the advanced completions you're really outperforming the type curve. I know it's still early, but any thoughts on when you might be updating those curves? Paul M. Rady - Chairman & Chief Executive Officer: Well, certainly on updating the curves and our expectations we get greater confidence, of course, with every well, with every pad and that'll lift our expectations, but as to how we would do lift the reserve bookings more area wide, we're pretty conservative there. And so, one needs quite a bit of production history, probably a year or more to gain confidence and then it'll begin just with direct and diagonal offset type of reserve booking. What we have done, once you have a statistical sampling that covers a much broader area then, we with the reserve auditors can book many of the locations in between. So, it can be a larger uptick, but that's probably a year, year-and-a-half out to upsize the bookings in broad areas. It's going to be on a pad by pad basis for probably the next year. Glen C. Warren - President, CFO, Secretary & Director: And I think just to add to that, reserve bookings are one topic certainly, but the other is, I think, you can assume that our expectation in that red outline that you see on our maps now is to see 2 Bcf per 1,000 that's certainly the target and the expectation going forward, and hopefully it's even better than that as we said.

Got it. Thanks, guys. Paul M. Rady - Chairman & Chief Executive Officer: Thank you.

Our next question comes from Neal Dingmann from SunTrust. Please go ahead.

Good morning, guys. So... Paul M. Rady - Chairman & Chief Executive Officer: Good morning.

May be questions quickly for Glen first or maybe for you, Paul. Just on the outspend, again, obviously, it's translated very quickly into production in future upside. How comfortable are you with kind of when you look into 2017 and exiting that year forward on the outspend? Glen C. Warren - President, CFO, Secretary & Director: Given our rates of return and the fact that leverage is expected to actually decline through the rest of the decade, we're quite comfortable outspending as long as we continue to see stability in natural gas prices and hopefully some recovery again in oil and NGL prices. So, a longer range plan is to outspend over the next few years given the kind of rates of return that we're looking at. And we haven't really modeled in ourselves hitting 2 Bcf per 1,000 or higher in the Marcellus. So, I think if we can consistently do that then the outspend actually shrinks even further, so, time will tell.

No. That just certainly makes sense. And then just two others if I could. Paul, you mentioned on, this new property that you all are building out, some pipe there, what's the timing there and how much you need to build out? I guess, I'm just wondering when you look at Wetzel and Tyler and Doddridge, to me it's quite perspective, obviously, for both Utica and Marcellus, but is that just going to be mostly infrastructure-dependent here in the next several quarters? Paul M. Rady - Chairman & Chief Executive Officer: We're quite well built out already in Doddridge, and pretty well built out in Tyler. So, it's really Wetzel that is more far afield. So, a lot of the infrastructure is already underway for Doddridge and Tyler. And we'll be able to fold that in pretty quickly. But it is Wetzel, and as we were saying, it's probably a year-and-a-half to reach the northern part, maybe two years to reach northern Wetzel and it'll be a phased-in well. We'll build the southern Wetzel first and be developing that and then make the jump across. So, it's going to take some time to get up to northern Wetzel.

Will that be mostly Utica-focused, Paul? Paul M. Rady - Chairman & Chief Executive Officer: No, it'll be mostly Marcellus-focused.

Okay. That's what I thought. And then, just lastly, you guys have had, obviously, great – just we're seeing when you continue to push the proppant, it seems to be more and more just pushing the economics on these wells. How do you see kind of going forward, will you continue to push the proppant loading on a lot of these wells? Paul M. Rady - Chairman & Chief Executive Officer: We will. We've got the pilots we mentioned, 1,750 pounds and 2,000 pounds and corresponding water volumes, and we'll see how those work out. We don't want to juggle too many parameters at once, too many variables, but yeah, we'll test 1,750 pounds and 2,000 pounds and see if that gives us another good bump. And so, right now, I think our standard design is going to be 1,500 pounds with the piloting to go up to at least 2,000 pounds. And we'll probably step beyond that as well over time.

Very good. Thank you all. Paul M. Rady - Chairman & Chief Executive Officer: Thank you. Glen C. Warren - President, CFO, Secretary & Director: Thank you.

Our next call comes from James Sullivan from Alembic Global Advisors. Please go ahead.

Hey. Good morning, guys. Paul M. Rady - Chairman & Chief Executive Officer: Good morning, James.

Just very quick, obviously, you guys highlighted some great deliverability potential on the ethane side. Obviously, looking at the spot market right now, just back under $0.17 a gallon, that's kind of despite the Morgan's Point startup. Do you guys have any sense or can you comment a little bit just on how you see that market evolving over the next 12 months or 18 months. I know that the startup at Morgan's Point seems to be pretty slow, they're not going to really hit capacity till late 2017, but there was a lot of line fill with Mariner and doesn't seem to be much at Morgan's Point. Can you just give us your feel on that? Paul M. Rady - Chairman & Chief Executive Officer: Well, I think, we're optimistic longer term. We all probably read the same reports on the petrochems, the ethane crackers that are being built along the Gulf and the added demand there, call it 400,000 barrels or 500,000 barrels a day over the next one year to two years. So that's going to help, as you mentioned, Morgan's Point. And certainly we've talked with some of the ethane buyers that are shipping out of Morgan's Point to sell directly. So, I think, it will improve, but it's still under stress at $0.17 you're right on the margin whether you want to recover or leave it in the stream. In fact, you probably disregard if not for some cost you definitely be leaving it in the stream.

Okay, great. Thanks for that. Just shifting over then. If I look at to something on the Utica drilling side, if I look at your slide eight from your presentation, you guys driven obviously phenomenal D&C cost reductions. But if I just look at it, it looks like the Utica drilling costs with the four elements drilling and completion between the two basins that have come down the least. Now on the other hand, your drilling days have come down on an order of magnitude same magnitude at the Marcellus, 45% versus 48% I think. Is there another factor that would account for the absolute dollar cost coming down a bit less in the Utica? And I'm thinking here maybe depth or legacy rig costs and if it is the latter legacy rig cost, is there a time when that starts to roll-off and you might get better re-contracted rates? Paul M. Rady - Chairman & Chief Executive Officer: Yeah, there are some legacy costs in there, but our rigs are rolling off in the next six months to 18 months and so that will help. But we haven't had as much, I guess, you'd call it, practice at the Utica. We haven't drilled as many wells. So, a lot of the great efficiencies, the great operating techniques that we're working out in the Marcellus we just haven't done enough of those yet in the Utica. So, do expect that cost can come down further in the Utica, but we just haven't been as active there. As we say fewer rigs drilling there and less capital planned until Rover goes into service, which is a year to a year-and-a-half away. So, it'll be a little bit more subdued in our experimentation.

Okay great. Something to look forward to then. Thanks guys. Appreciate it. Paul M. Rady - Chairman & Chief Executive Officer: Okay. Thank you. Glen C. Warren - President, CFO, Secretary & Director: Thank you.

Our next question comes from Jon Wolff with Jefferies. Please go ahead.

Good morning. Glen C. Warren - President, CFO, Secretary & Director: Hi, Jon. Paul M. Rady - Chairman & Chief Executive Officer: Hi, Jon.

Hey, how are you? Curious, so, Stonewall has sort of a volume transitioned from sending gas north versus going towards TCO, sort of, how much volumes were reallocated? And then if you had any thoughts on why M2 TETCO point, Dominion South point is still so weak given that some volumes have been diverted and production in the basin has fallen? Paul M. Rady - Chairman & Chief Executive Officer: Yes. So let me tackle that second one first. TETCO M2 and Dominion South continue to stand out when you look at indices really across the country. It's really Pennsylvania, Southwest PA and Northeast PA that are in distress whether its Leidy hub or TETCO M3 is Eastern PA. And so there's a lot of gas trying to escape and just not enough straws in the pot in that area. That's a reason why we can buy distressed third-party gas and move it down on our TCO capacity. But I think there's just a lot of gas that's trying to move out of the northeast Marcellus, so it comes around the horn. It comes from Northeast PA and comes down and tries to get out of Eastern PA. The markets are also distressed there...

So possibly some gas that was behind pipe that came on when you might have diverted, I think, several hundred million that were going north towards that direction? Paul M. Rady - Chairman & Chief Executive Officer: Yeah. That's true. And that gets to your second question is, it was several hundred million that we were sending before Stonewall opened, which was last November. Before that, we were moving gas up EQT and Momentum to TETCO and selling into that distressed market. And you can see, today's price, TCO is very close to NYMEX. It's maybe $0.13 off, and so that would be in the $2.60-ish, $2.70 range, whereas TETCO M2 and Dom South are $1.35 to $1.40. So, it makes a big difference obviously, and, so the big picture is still...

How many volumes do you think Stonewall were able to provide you to TCO, sorry, with the expansion? Paul M. Rady - Chairman & Chief Executive Officer: Well. We're moving...

Incrementally. Paul M. Rady - Chairman & Chief Executive Officer: ...more than 1 Bcf a day right now. And so it's going to either to the TCO pool or the TCO based sales contract, so.

All right. Paul M. Rady - Chairman & Chief Executive Officer: So, a lot of it, at least 300-million plus a day that was going to TETCO a few quarters ago is coming into the TCO pricing.

Got it. That's what I was looking for. I don't think you talked about the REX reversal, which I think is still scheduled for towards year-end or early next year? Paul M. Rady - Chairman & Chief Executive Officer: Yeah. That's right. Yeah. That's...

Do you feel good about that? And does that help, because I remember in the last call you said to expect Marcellus to be the driver of growth and Utica to be fairly flat. And does the REX reversal, if it comes on in time, does that change that math or does that allow Utica to grow a little more? Paul M. Rady - Chairman & Chief Executive Officer: Yeah. Well, there's another complication there. So, the REX reversal – REX right now is, westbound is 1.8 Bcf a day and they've just done a short shutdown to get prepared for the increase of another 800 million a day. And that's expected to come on in either the fourth quarter or the first quarter of next year. And so, there will be westbound capacity out of Clarington, for example. And so that's going to help to "drain the pool" of Southwest PA and Eastern Ohio. But the complication for Antero is, we have our Seneca processing plant and the residue gas, of course, comes out of there. But it flows on the Seneca lateral, which is also maxed out at 600 million a day. So really we don't see relief until Rover comes to the Seneca plant. So, others will be able to take advantage of REX westbound once the new capacity is added. But we will still be constrained, because we can't get up to and into the REX lateral or into the REX pipeline. So that won't make a difference for us.

That makes sense. Last one was on – I noticed in the last release that you had some success in laying off some of FT to third parties. Was that the case, and is that an ongoing process for maybe the FT that's less preferred in your mind? Paul M. Rady - Chairman & Chief Executive Officer: Well, there's both. And so the FT that we have remaining, especially in and around the TCO pool area and south to the Gulf, kind of the east side of our FT, that's where we are making good returns on buying the distressed third-party gas from Southwest PA and moving it through either to the TCO pool or to the Gulf and offsetting FT costs and making a margin on that. So, we haven't let go of that, and that's good and that's desirable. And then, as I mentioned, a big amount is the FT that under the pre-negotiated agreement with Energy Transfer, which we've had for at least a year-and-a-half, as we signed up for Rover, it was the agreement that they'd take over ANR Southbound until – beginning July 1. So, last month, July 1, 2016 until Rover is in service, which is – that's a big factor in reduction of FT costs.

Understood. Certainly helpful. Thanks. Paul M. Rady - Chairman & Chief Executive Officer: Okay. Thank you.

Our next question comes from David Deckelbaum from KeyBanc. Please go ahead. Paul M. Rady - Chairman & Chief Executive Officer: Hi, David.

Good morning, Paul. Good morning. How are you? Thanks for taking my questions. Paul M. Rady - Chairman & Chief Executive Officer: Sure.

I'm just curious to follow up on the M&A. You guys had successful bolt-ons and you've pointed out that you now control kind of a majority of that southwest Marcellus core area. You also talked about the build out required in Wetzel. I guess, in terms of the opportunity there, how much more opportunity is there to sort of fold in acreage or pick up acreage that's sort of already set along your Midstream facilities there? And is there a strong desire to pursue things like that now, or getting back, I guess, to your earlier conversations of comfortable growing production, you had the large hedge book, outspending cash flow keeping the balance sheet clean. I guess, if you're able to pull off similar deals like the one that we just saw, should we expect you to pursue those pretty aggressively this year? Glen C. Warren - President, CFO, Secretary & Director: Well, there's the base load leasing that that's a continuing effort, and so the acres that we are acquiring in this pending acquisition, it's not completely blocked up. So there is an effort to continue to block that up, so that's one aspect. And then, yes, we are continuing to monitor and engage around additional consolidation, and time will tell as to whether or not more of that gets done in a material fashion or not. It's just kind of hard to say, but we do still have an appetite for that. And while we're not ramping up the rig count dramatically, with as Paul mentioned earlier and we're kind of taking a moderate approach to this sort of adding one rig driven by that southwestern acquisition here next year. I think you're going to see them over time as we expand the platform with a larger and larger resource base and activities going to expand commensurate with that. We're not looking to just add more locations to extend sort of the life of the drilling program. It's really more about building a bigger company and building it more rapidly, but keep in leverage and check. So there are lots of factors that you take into consideration when you're negotiating these deals, but there still are some attractive opportunities out there.

That's helpful. And then the last one for me, and maybe it's a little bit of an oddball question, but I suppose that we go into the end of the year here and we do see supply declines persisting demand pickup on the gas side, you see Henry Hub pricing spiking above where your hedge book is in 2017, you're 100% hedged. And in that sort of framework, is that just become as we get closer to where your hedge book is, is that just a trigger to increase production further? Or how do you guys think about capturing potential near-term spikes in the market that might persist for 12 months or so? Paul M. Rady - Chairman & Chief Executive Officer: Yeah, I think that's a good way to think about it. It'll be a measured approach, but if we were to see sustained $4 gas then that would certainly, and maybe even below that, stimulate more drilling beyond what we've talked about in our D&C budget similar to this year. We could certainly increase that fairly easily. We have lots and lots of inventory to drill. So, that's an opportunity.

Thanks, guys. Paul M. Rady - Chairman & Chief Executive Officer: Thanks, David. Glen C. Warren - President, CFO, Secretary & Director: Thank you.

Our next question comes from Drew Venker from Morgan Stanley. Please go ahead. Drew E. Venker - Morgan Stanley & Co. LLC: Good morning, everyone. Paul M. Rady - Chairman & Chief Executive Officer: Good morning. Glen C. Warren - President, CFO, Secretary & Director: Good morning. Drew E. Venker - Morgan Stanley & Co. LLC: I just wanted to ask couple questions about the longer term planning. You guys have been drilling longer laterals than a lot of your peers for quite some time now in Appalachia. And we've seen some industry test that are actually much, much longer closer to 20,000 feet drilled successfully. Do you feel like that is something that's technically feasible for you or that would be practical to implement on a widespread basis, given, I guess, physical limitations or acreage lease geometry, things like that? Paul M. Rady - Chairman & Chief Executive Officer: That's a good question. The longest we've drilled so far is out to 14,000 feet sideways, and we did that pretty trouble-free. We know of the wells over in the Utica that have gone out towards that 20,000 feet. The good news for us is, we don't have the acreage limitations where we need to go to 20,000 feet if something is unreachable. So, would that be a money saver versus a concentration problem? I think you'd say that if you go extra long like that, now we haven't junked any wellbores in a long time, but if something went wrong on the mechanical side is that higher risk. So, we are going longer and longer. We're in the mid-9,000s feet these days as an average lateral of 9,000-plus feet. We feel quite comfortable and have a lot on the schedule that are in the 11,000 feet to 14,000 feet…

This concludes our question-and-answer session. I would like to turn the conference back over to Mr. Michael Kennedy for any closing remarks. Michael N. Kennedy - Senior Vice President, Finance & Chief Financial Officer: Thank you for joining us on the 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.