Greetings, and welcome to the Antero Resources First Quarter 2019 Earnings Call. At this time, all participants are in a listen only mode. A brief question-and-answer session will follow the formal presentation. [Operator Instructions] As a reminder, this conference is being recorded. It is now my pleasure to introduce your host Mr. Michael Kennedy, Senior Vice President of Finance. Thank you. You may begin.

Thank you for joining us for Antero's first quarter 2019 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 homepage of our new website at www.anteroresources.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 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. Today's call may also contain certain non-GAAP financial measures. Please refer to our earnings press release for important disclosures regarding such measures, including reconciliations to 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 provide an update on our firm transportation portfolio both for natural gas and natural gas liquids, then discuss 2019 operations and round out my comments by providing color on our operational execution during the quarter. Glen will then briefly touch on the implications of the deconsolidation event as a result of the simplification, transaction that closed in March and highlight our first quarter financial achievements including strong realized pricing and further leverage reduction. He will finish with the discussion of Antero's strong position and outlook for the future. Let's begin with the discussion on our firm transportation position both for natural gas and natural gas liquids. I'll first touch on the natural gas liquids firm transportation given the recent start-up of Mariner East 2. As outlined on slide 3 titled inflection point in NGL Marketing and Pricing. We began shipping volumes for the first time in February through our commitment on our Mariner East 2 pipeline, a pipeline that transports NGL volumes from fractionators in Southwest Appalachia to the market sub-facility in Philadelphia for exports into the global markets. We have 50,000 barrels a day of propane and butane capacity contracted on the pipeline, which equates to about one-third of the available capacity on ME2 today. As the largest shipper on ME2 and with approximately 50% of our NGL production being sold into premium international markets today, we are well positioned to deliver peer-leading NGL price realizations going forward. As you can see from the table, on the left-hand side of the page, our NGL realizations increased from 52% of WTI before ME2 was in service in January, to an average of 61% of WTI after it came in service.…

Thank you, Paul. In my comments today, I will discuss our first quarter financial results, provide additional color on the uplift to our NGL price realizations with the start-up of the ME2 pipeline, and conclude with comments around our competitive advantage that we have built through our large-scale liquids inventory product diversity and exposure to the growing demand markets for both liquids and natural gas. This provides us with multiple ways to win going forward. Before I get into these topics, I did want to provide a reminder that with the closing of the midstream simplification transaction in March, AR will no longer consolidate AM on its GAAP financial statements but will rather record its interest in AM through the equity method of accounting. We are excited about this change as we believe it will provide several benefits. First it improves the transparency and disclosure for AR on a stand-alone E&P basis. This will enable investors to more easily compare and contrast AR with its peers. Importantly, this transition will minimize future inconsistencies among analysts, investors, and financial screening services on AR's leverage, EBITDAX, capital, and free cash flow just to name a few, and therefore, significantly simplify the story. As you can see on slide number 8, our consolidated -- deconsolidated metrics are extremely attractive with leverage at 2.1 times and our enterprise value to EBITDAX at just 2.8 times on a hedged basis. Since the transaction closed mid quarter, our first quarter 2019 financial statements still included consolidation up through the closing date on March 12th. However, all subsequent quarters will treat the Antero Midstream ownership through the equity method of accounting. Now, moving on to the first quarter results. During the quarter, net production averaged 3.1 Bcfe per day, delivering 30% year-over-year growth, including 148,000 barrels a…

Thank you. We will now be conducting a question-and-answer session. [Operator Instructions] Our first question comes from the line of Jane Trotsenko with Stifel. Please proceed with your question.

Good morning. My first question is on NGL fundamentals. I'm curious if you could share your thoughts on the Mont Belvieu pricing outlook and maybe on international demand and how it's going to evolve during 2019? Thanks.

Yes. Jane, let me turn the call over to Dave Cannelongo, our Vice President of NGLs and International Markets.

Yeah, Jane. We saw a fair amount of weakness in Mont Belvieu in the first quarter as a result of some of the challenges they had with fog that they see down there seasonally as well as a fire that occurred at the ITC terminal on the Houston Ship Channel. But in addition to that, we've started to see a limit on the amount of production that's able to get out of the caverns to the water and that is really dependent on some expansions of terminals there. There are a couple of projects in the third quarter for a few of the midstream players down there that will increase their ability to access those markets. And so at that point in time, we would see some support from Mont Belvieu pricing coming on then. We do continue to see growth internationally in the petrochemical market in particular in Asia, although there are a couple of PDH projects slated for Northwest Europe. And growing res com demand coming from Southeast Asia as well as in the others that's been in support of the international pricing. So all those things wind up together to allow us to have a very strong winter and spring so far on Mariner East 2.

Got it. So it would be fair to say that you would see that -- you expect to see NGLs fundamentals to improve from this point on in terms of domestic NGL pricing I would say, right?

We do. And in particular I'd want to mention as well the ethane market just with some of the new petrochemical facilities that are coming online here as we speak and three additional ones later this year that we'll see if it can really improve the demand for ethane down the Gulf Coast complex.

Okay, got it. My second question is on Ohio, Utica. Could you please remind us how you view this asset in terms of capital allocation and in terms of production trajectory going forward?

Yeah. We like our Ohio, Utica project both on the rich side as NGLs have gotten stronger, our rich gas trend has become more economic and also in the dry gas areas where we have accumulated acreage in a very good reservoir quality areas. So we like the project quite well but it still doesn't compete with Marcellus and so that is our focus that still the Marcellus economics are better. Therefore, our capital is almost 100% dedicated to the Marcellus at this time but very much likely Utica still.

Okay. But should we think about Utica as kind of flat for the production trajectory or will it be declining?

It'll probably be flattish I would say that we drill a half of a pad or a full pad every year. And so that can keep production flat.

Got it. Thanks a lot.

Thank you

Thank you. Our next question comes from the line of Holly Stewart with Scotia Howard Weil. Please proceed with your question.

Good morning, gentlemen.

Good morning.

Maybe just first let's start off on the sort of production guidance wedge I would call it the 10% at $50 and $2.85 and then 15% at $65 and $3.15. I know you guys are noting in the slides like likely somewhere in between just given the markets. I think probably until this week we would have thought that crude would be at the high-end and gas at the low. So maybe Glen, could you just make some comments around if the scenario were to play out sort of how you guys are thinking about that wedge and sort of the production going forward?

Well as Dave mentioned, I think we feel really good about the NGL markets and think that that's going to continue to strengthen and so that makes up for softness in gas in the near term. We still are firm believers in gas over the medium and longer term. We just need to get through this shelter season and see how the injections look through the summertime and see what kind of summer weather we have as well. But we're still on that 10% growth line for now. We're not -- you don't see us accelerating capital just due to oil prices and NGL prices being higher. We're very comfortable in that 10% line for now and we'll evaluate that really every quarter as we go forward Holly.

Okay. That's great. And then maybe I thought slide 19 did a good job of just the waterfall of well cost in the Marcellus. Could you just maybe provide a little bit of color around the inflation that you have seen and then some of those renegotiated completion contracts?

Yes. We do see certainly pressure. We do a lot of water hauling of course from the well sites both flow back water and produced water. And so there's -- there has been pressure on trucking cost especially driver cost, but we've been able to trim back and use fewer trucks as we've gotten more efficient in call-outs and so on. So yes, there is some pressure there. But on the other hand the renegotiation of certain contracts like the self-sourcing have been very beneficial. Right now, we are self-sourcing at least 70% approaching 80% of our sand needs for this year, it's working out quite well. We're contracted with suppliers that can actually barge up the Ohio River which is quite a cost savings from -- railing from the traditional Northern White trends, we saved quite a bit there. And we have staging facilities on the Ohio River right next to our acreage. We do have in case that there are ice dams and so on, on the Ohio. In the winter, we do have quite a good amount of sand set aside to fall on if there are any logistical hitches. So that has really reduced our sand cost, which are significant by about one-third so far and expect to see that translate through. So I'm talking about not only the sand itself, but the last mile. So we're getting those costs down. Those add up to the several hundred thousand dollars per well. So seeing those efficiencies with bigger pads as you know we can get off more stages a day just to the logistics on the pad. So a lot of efficiencies that are helping to bring our well costs down.

That's great. Thanks guys.

Thank you.

Thank you. [Operator Instructions] Our next question comes from the line of Subash Chandra with Guggenheim Partners. Please proceed with your question.

Yes. Curious a couple of things. The drop in the rig in the Marcellus through the balance of the year, is that something you could continue through 2020 while keeping the 10% CAGR? Or do you anticipate bringing activity levels back up next year?

We expect to have a similar number of completions next year, but with a bit longer laterals on the completion front and probably drill a few more wells as well as we grow next year. So we expect to spend a little more capital next year, but not much. So I don't know I'm not sure it's a full rig, but at least a half a rig more probably.

Okay. Is there an update I think Paul you were mentioning anecdotally a number of places you're achieving cost savings. Is there a way to sort of phrase that? $1 per foot or maybe some $1 per foot exit forecast for this year?

Well you can see on slide 19 Subash that quantifies on $1 per foot going from $0.95 million per thousand feet a lateral down to $0.93 million, so obviously that's just around a 2% reduction. Continue to work on that to try and get it lower. It would be great as a target to get into the high $0.8 million. So we'll where it goes. Naturally, the reason we drop the rig in part is that we're just getting so much more efficient, so much faster as we highlighted in our comments on average. And the average lateral feet per day as well as the record setters not only did we have the recent one above 9,000 feet that we're drilling. There are a number them that are in the 7,000 and 8,000 feet per day. And so with that, you can accomplish that much more with much less drilling time. So yeah that would be our target. And if you're going to achieve at least 2% or so on that per-foot cost, where will it go from there? Well, we keep striving for 2% and 3% and 4% as we go forward. It's not over yet.

Yeah. Right. Yeah. I wasn't clear if slide 19 was updated for the CapEx reduction that you talked about in the quarter.

Yeah, it is.

Yeah. Got it. And then the slide on drilling -- D&C efficiencies. Slide 7, shows Utica results, is there Utica activity underway?

Hi. Subash, this is Mike. We do not have a drilling rig in the Utica, we did have one completion crew there for part of the first quarter where we completed one pad. But there's no further activity throughout 2019.

Okay. Got it. And a final one. Just philosophically where you stand on your plans for AM and using that as a source of funds?

Well, it's - AM is obviously a great asset for AR and we'll just see how that checks out over time. We expect to see a lot of value improvement, price improvement at AM, as it seasons here and gets added to some indices over the next few months. So, very optimistic there, but no direct plans to do anything with that position at this point.

Okay. Thank you.

Thank you. Our next question is a follow-up from Jane Trotsenko with Stifel. Please proceed with your question.

I have a natural gas macro question that, I need to ask. I'm curious, if you are seeing lower future levels from private investments in Utica Marcellus given where natural gas prices are? Or do you think like we need to stay in that 250 range for a little bit longer to see the privates come back?

I'm sorry could you repeat that? Are you asking whether or not the privately equity-backed activity has slowed down or –

Exactly.

Yeah. Yeah. We're not seeing a lot of slowing yet, I think that's something that we will see over the next year whether that change will – or Utica Marcellus. So the privates have continued to be fairly active. And I think the last time, we looked at it the private equity-backed portfolio of companies they constituted maybe 40% of the rigs running in the – on the gas side. And I think sometimes they are not at the same scrutiny as public companies and are probably drilling for other reasons than just direct well economics in some of these areas. So I think that would be a healthy development to see the private scale back on their drilling activity and completion activity of course in the dry gas plays.

But you don't see it just yet, right? It seems to me like we need to see this weaken for a little bit longer before it translates into more activity levels for privates, right?

Price should drive that decision making over time you're right. But it's hard to predict.

Okay. Okay. Got it. And I wanted to ask a question a follow-up. Obviously, you're making great progress in terms of capital efficiency and dropping rig without changing -- you're reducing the CapEx to the low-end of the guidance without changing production outlook. I'm just curious are there certain read-throughs from those efficiencies through 2020, let's say CapEx might not be as high as expected or something in that type of direction?

I think that's certainly possible. We think the inflation is a non-issue today with services in our space, so that's good news. We think that's really been tamped down. The only inflation, we've seen as Paul mentioned that sort of continued through last year was just the rates charged to incentivize truck drivers to move water oil you name it. But I think that's leveled out now and activity is flat to down in Appalachia, so that's all good news there. And the efficiencies are still running as you heard. To get up to 5,300 feet a day on average on the lateral in the first quarter that's great progress. So you need fewer and fewer rigs to generate the number of spuds that you want to get going each quarter. And then on the completion side, we think there's still, lots of upside in terms of stages per day. And we saw well over five stages a day in the first quarter which as we said is normally a fairly slow quarter due to winter logistics and we didn't really have much problem with that this time. So we expect that to pick up throughout the year and into next year and maybe a good target is to get up to eight stages a day or so here over the next year or 2. So we still see lots of room for improvement there on the efficiency side.

Do you see laterals getting longer year-over-year? And then in terms of proppant lodgings is it going to change next year?

Yes. We have such a strong inventory that we have our program planned out for the next five or six years in terms of which specific laterals, which specific units we are going to drill and they do get longer year by year how much per year? If they're averaging 11,000 to 12,000 this year they get out into the mid to high 13000s over the next several years. But we have just found that it's more efficient in terms of cycle time and so on to -- that's the sweet spot in the 13,000, 14000-foot range. A little longer than that and there's just such delays in completing the wells. So we're happy with that. And what was the second part of your question again Jane sorry?

Proppant intensity. How much proppant are you going to use? Is it going to change? Or is it going to remain the same?

It will probably remain the same. We feel good about 2000s in some of our step-out areas. We sometimes go to 2500 pounds per foot. But generally we're happy in that scenario of 2000 pounds per foot. Every now and again we do 17.50 pilots to check that out. And so we continue to learn, but I'd say it has mostly stabilized around 2000 pounds per foot.

That's very helpful. And the last question if I may on M&A, if you have like any general comments about M&A activity in the basin?

Yes. We do think you'll continue to see some consolidation over time in the basin, but not hearing a whole lot of activity right now. I think they'll probably be some asset situations maybe private equity backed first. But we keep an eye on that as well. Yes.

Awesome. Thank you so much for taking my questions.

We have reached the end of our question-and-answer session. I would like to turn the floor back over to Mr. Kennedy for any closing remarks.

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

Thank you. This concludes today's teleconference. You may disconnect your lines at this time. Thank you for your participation and have a wonderful day.