Good day, ladies and gentlemen and welcome to Antero Resources Third Quarter 2018 Earnings Conference. Please also note that this meeting is being recorded. I would now like to hand the conference over to Mr. Mike Kennedy. Please go ahead, sir

Thank you for joining us for Antero's third quarter 2018 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'd 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 they're 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 some non-GAAP financial measures. Please refer to our earnings press release for important disclosures regarding such measures including reconciliations for the most comparable GAAP financial measures. Joining me on the call today are Paul Rady, Chairman and CEO and Glen Warren, President and CFO. I will now turn the call over to Paul.

Thank you, Mike, and thank you to everyone for listening to the call today. In my comments, I'm going to highlight our operational execution during the quarter and provide some detail on several of our recently completed liquids-rich pads. Glen will then highlight a number of significant third quarter financial achievements and provide an update on our recent board-approved share repurchase plan, which we plan to begin to execute during the fourth quarter. Let's begin by discussing the efficiency improvements we made during the quarter. Once again, Antero set new operational records during the third quarter. Looking at slide number 4 titled Drilling and Completion Efficiencies starting on the top-left portion of the slide, in the Marcellus, we held our average drilling days flat at 12 days, and in the Utica, we held that flat at 20 days despite the continued trend of increasing our average lateral lengths in the Marcellus to 10,400 feet in the third quarter. Completion stages per day in the Marcellus once again set a quarterly record, averaging 5.5 stages per day including a company record of 6 stages per day in the month of September. This compares to the 4.6 stages per day average in 2017 and 5.0 stages per day average in the prior quarter. These improvements are ahead of our current budget which assumes 4.5 completion stages per day for 2018. As a result of this improvement, we released three completion crews in September as wells are being completed at a quicker pace than the initial development plan. During the third quarter, we turned to sales several outstanding Marcellus liquids-rich pads. One was an eight-well pad that was drilled with an average lateral length of 9,750 feet and produced a 60-day average rate of over 23 million cubic feet equivalent per well. Even…

Thank you, Paul. Good morning, everyone. Let me begin with our key financial achievements from the quarter. I'll then shift focus to the fourth quarter which is a key inflection point for Antero as we began generating sustained free cash flow and returning a significant portion of that capital to shareholders through our recently announced share repurchase program. I'll also finish by touching on 2019 briefly. During the third quarter, net production averaged a record 2.718 Bcfe per day, delivering 17% year-over-year growth and 8% sequential growth, including a record 129,000 barrels a day of liquids. Liquids production increased 14% sequentially, reflecting a continued emphasis on developing our liquids-rich acreage. Liquids production included 10,632 barrels a day of oil, 79,819 barrels a day of C3+ NGLs, and 38,901 barrels a day of ethane, all new records for Antero. During the third quarter, Antero's realized natural gas price was $2.95 per Mcf before hedges, representing a $0.05 per Mcf premium to the average NYMEX Henry Hub price. This marks the 17th consecutive quarter that we've delivered pre-hedged natural gas realizations at a premium to the Henry Hub per MMBtu price. Moving on to liquids pricing during the quarter, we realized an unhedged C3+ NGL price as propane and heavier of $38.41 per barrel, representing a 33% increase from the prior-year quarter. We expect the significant – the strength in NGL prices to continue as we currently forecast ME2 to be operational during the fourth quarter of 2018, which will give us access to the premium price to international markets. As a reminder, every $5 per barrel increase in NGL prices results in an incremental $170 million in revenue to Antero on an annualized basis. As shown on slide number 8, our liquids production growth profile when combined with pricing improvement drives…

Thank you very much, Glen. Our first question is from Subash Chandra of Guggenheim. Please go ahead.

Yeah. Hi, guys. As you look at the macro landscape for liquids in Appalachia, so your competitive situation there, has it changed at all as we see the shift from all the Appalachian players to liquids? When do you think the takeaway constraints are an issue again? And how do you navigate that over your three-, four-year outlook?

Yeah. We continue, Subash, to add liquids-rich acreage. And so, we still have the dominant position. Others are drilling theirs up, but we've stayed pretty steady on our inventory. So, I think we're just as strong if not stronger relative to our peers in the liquids-rich part. When we do have some impediments right now on infrastructure, they're pretty short term, whether it's Mariner East or the Hopedale number 4 fractionator. We expect both of those to be open for business in the next month or two or three. After that, it's pretty smooth sailing for quite a while. I don't see much in the way of logjams over the next several years. Mariner East is built so that it can expand and carry a lot more export capacity. Both the purity lines and the wide grade lines that go to the fractionators both at Houston and Hopedale are in the process of being expanded right now. And so, that'll give us smooth sailing for quite a while. And then we're just having our next de-ethanizer come on at Sherwood. Sherwood 10 just came on yesterday and the de-eth will be there in a couple of weeks so – and then another one in the first quarter of next year. So, if you look at all those elements, whether it's processing, de-ethanization, the purity in Y grade or the fractionators or Mariner East, I think those all get relatively solved over the next six months and so don't really see getting jammed up again for quite a long time.

Got it. Okay. And I understand if you don't want to comment on a third-party project. But if you could on sort of the Kinder Morgan project that got canceled earlier this week, I think, or last week, sort of – was that a reflection that there was – this capacity you're talking about, there was just enough of it? Or that really, the route that producers want to take is the export route versus the Gulf Coast route on future takeaway?

Yeah. The export route does, it does get one premium to Belvieu, but I think the producers look and see that Mariner East is expandable. Several times, it can really be bulked up. So, it's favorable to Belvieu and competitive, and it's there, so I think producers are happy just to align behind that one. And so, the speculation is that Kinder, the one that they're going back to maybe using it as a line reversal for gas instead of liquids, as you know.

Got you. Okay. If I could just ask one final one. On de-levering, I mean, do you feel like any of the maturities need to be paid off, or that the path towards sub-2 times is all we need to know on the de-levering?

Yeah. I mean, we assume that the maturities naturally roll off just based on our cash flow forecasts using strip commodity pricing. So, not a big need to refi those notes. It's possible that it gets more favorable over time, particularly if we move to investment grade over the next year or so. But, right now, we just assume the maturities roll off and we put the payoff onto our credit facility which is quite sizable. So, that's the plan right now for AR.

Okay. Thank you.

Thank you, Subash.

Thank you, Subash.

Thank you very much. The next question is from Jane Trotsenko of Stifel. Please go ahead. Jane Trotsenko - Stifel, Nicolaus & Co., Inc.: Good morning. You have been guiding to 60% of WTI for C3+ price realizations for 2018 and 72% of WTI for 2019 through 2021. So, given the strong backwardation in both WTI and NGL forecasts, are you still expecting to achieve 72% of WTI for C3+ in the coming years?

Yeah. Hi, Jane, this is Mike. Yes, we do expect the same percentages that we've guided to if you look at the actual by-product, our barrel, it comes out to those percentages assuming ME2 is on in the fourth quarter of 2018. And obviously on through the time period through 2022. Jane Trotsenko - Stifel, Nicolaus & Co., Inc.: Okay. So, it's Mariner East 2 which will be like the key driver for your confidence in those?

Correct. Yes. Jane Trotsenko - Stifel, Nicolaus & Co., Inc.: Okay. Perfect.

When you look at the international pricing, that really gives you an uplift compared to Mont Belvieu pricing, so that really drives that realization increasing over that time period. Jane Trotsenko - Stifel, Nicolaus & Co., Inc.: Okay. Got it. And then on Mariner East 2 pipeline, there were some reports about possible delay. Could you please update us on the status of the pipeline and if it's going to be brought online in phases?

Well, as Subash just said, it's always a danger commenting on third-party projects. But our standing is that they're moving along, that it will be brought on in phases with the smaller amounts with their using some of the repurposed bypasses early on that's going to allow production of on the order of 150,000 barrels a day. And then once they get it worked out within the next year then it can expand quite a bit more. So, I think two phases, the early one is in the next few months and then the next one after that is within the next year. But again, of course, that's our view from afar. We couldn't say we know more than the general public. Jane Trotsenko - Stifel, Nicolaus & Co., Inc.: Okay. Okay. Maybe related to this, how should we think about ramp up in Antero's, let's say, NGL flows on Mariner East 2? Is it going to be like gradual ramp up in pipeline flows on that pipeline?

I think we assume by January 1, in January 2019, we'll be flowing our 50,000 barrels a day of propane and butane just per MVC. And then what Energy Transfer has stated is that they plan to have the entire pipeline on by third quarter of 2019. So, those are the assumptions that we're using right now that by 2019, we're able to flow more than 50,000 barrels a day of the MVC by the third quarter of 2019, and essentially flow all of our liquids to the extent we want to on ME2, all of our propane, butane that is. Jane Trotsenko - Stifel, Nicolaus & Co., Inc.: Thank you so much.

Thank you.

Thank you. The next question is from Holly Stewart of Scotia Howard Weil. Please go ahead.

Good morning, gentlemen.

Good morning.

Hi, Holly.

Maybe just the first one on sort of CapEx trends and all the efficiencies that you guys are seeing. Can you update us on that D&C capital transparency slide? I'm just trying to think through the average stages per day has gone down. So I guess the question is, are there any changes at this point to highlight on well costs just given those trends?

No. Hi, Holly. The 0.86 or $860,000 per 1,000 feet still holds. We're just obviously doing the stages much quicker than we thought, so that the capital has actually been accelerated into earlier periods, but the same well cost.

Okay. Okay. And I'm assuming that just the shift that you guys have outlined here today, that TIL schedule still stays?

It does. Yeah. The shift of capital will result in wells coming on quicker in 2019, that McKim pad, those nine wells come on in January of 2019 instead of more kind of midyear-ish 2019. So that's the change in the well schedule, but the actual TILs for 2018 are unchanged.

Got it. Okay. Thanks. And then, just there's been several pipeline projects where you guys have some capacity that's come on here as of late. So can you just update us on what you are currently utilizing and then what you are still anticipating to come on over the next couple of months?

Yeah. Let me go through the list, Holly. So, new things that have come on in recent times, a Columbia pipe called WB and Westbound WB has come on now for their full 800 million a day. So we're utilizing that. And that ties to our Tennessee that was upgraded from 590 million to 790 million a day. So, the 800 million more or less ties with the 790 million that goes to the Gulf. So, two projects there that have just come on. We've upgraded our TCO T System to another 100 million a day. We're using all of that that goes to the TCO pool. We expect WB Eastbound which goes over to the Cove Point area. We have 330 million a day on that, and that is going to be on line as soon as November 15, so just a couple of weeks away. And then, one that we're certainly looking forward to that should be within the next month is Rover Phase 2. It's 800 million a day that comes down from Clarington area down to Sherwood. So what that will do is allow us – we're not shut in or anything but it will allow us to redirect our gas to Chicago and Gulf markets on Rover. That capacity now – those gas volumes are going to TETCO M2 and Down South. So there will be an upgrade there on netbacks. And then the next one that is yet to come on line is called Mountaineer. It's a TCO, TransCanada project, and we have 700 million a day on that. And that's due to come on in January of this year. So, I think that's – not sure I've missed any, but those are the big ones, and so it allows us both to keep growing and also to redirect our volumes to the better markets.

Yeah. No, that's perfect. Thank you, Paul. And then maybe just another, right, a bigger picture question for you. I know you've been focused here as of late on the simplification, but I'm sure you're watching the markets, and we had a lot of M&A deals happen, gosh, in the last week or so and on the oil side. So, just kind of curious as to what you're seeing right now in the basin?

Yeah. Holly, in the basin, we have seen several deals over the past year. They tended to be smaller deals following the EQT, Rice deal, which was obviously a large deal. But you have had a number of consolidations occurring kind of around the basin, four or five of them. I wouldn't be surprised to see more of that happen here over the next year. That's certainly the trend, and we agree with that. It makes sense in a lot of cases. So, I think you'll see some in Appalachia.

Great. Thank you, guys.

Thank you.

Thanks Holly.

Thank you very much. Our next question is from Kevin MacCurdy of Heikkinen Energy Advisors. Please go ahead.

Good morning, guys.

Good morning.

Looking at slide 13, it seems to imply around $400 million of free cash flow to Antero. Just curious what CapEx number that's based on, and does that include the fully burdened water cost?

Yeah. It does. The stand-alone CapEx number is kind of $1.5 billion to $1.6 billion and the consolidated number is $1.3 billion, the difference being the water.

Great. That's certainly compelling free cash flow. And to follow up on our earlier question, thanks for the clarity on the C3+ prices. Just to get a little bit more color, are you saying that Antero's realizations will be better than Mont Belvieu forward prices?

Yeah. I mean, the calculation is not based on Mont Belvieu. It's based on Northwest Europe, mainly, and where the actual volumes would go. So, those are ahead of Mont Belvieu pricing.

Great. Thanks, guys.

So, yeah, comparing Marcus Hook as the export facility to Belvieu, we expect to see a premium at Marcus Hook compared to Belvieu. That's right.

Thanks.

Thank you.

Thank you very much. Ladies and gentlemen, that then completes our question-and-answer session. I'd like to turn the conference back over to Mike Kennedy for some closing remarks.

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

Thank you very much, sir. Ladies and gentlemen, that concludes this conference call. Thank you for attending, and you may now disconnect your lines.