Good day, and welcome to the Antero Resources Q1 2015 Conference Call and Webcast. 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 this event is being recorded. I would now like to turn the conference over to Mr. Michael Kennedy, Vice President of Finance and Head of Investor Relations. Please go ahead, sir.

Thank you for joining us for Antero’s first quarter 2015 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.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 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 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 will now turn the call over to Glen.

Thank you, Mike, and thank you to everyone for listening to the call today. In my comments, I’m going to highlight some of the key achievements from our first quarter 2015 results. Discuss the capital markets transactions we executed during the quarter and provide an update on production expectations for the remainder of 2015. Paul will then discuss service costs reductions we’re currently achieving or review operational highlights from the quarter and provide an update on operational expectations for the remainder of this year. First I would like to touch on some of the key highlights from the quarter as we had tremendous quarter both from an operational and financial standpoint. We achieved record production averaging 1.485 bcfe per day net during the quarter including over 40,000 barrels of liquids a day. This was an increase of 17% and 32% respectively from the fourth quarter of 2014. In the Utica we averaged 274 million cubic feet equivalent per day which was 43% higher than the Utica production in the fourth quarter of 2014. While the growth was tremendous, it’s important to point out that we achieved the record production levels at attractive all in margins driven by our significant hedge book liquids rich development program and diversified firm transport portfolio. Despite low natural gas oil and NGL prices in the first quarter we realized all end pricing on our production of $4.42 per mcfe which was $1.44 higher than the average NYMEX natural gas price during the quarter and 13% higher than the next close of Appalachian peer. Driven by our diversified FT portfolio we sold approximately 64% of our natural gas production at favorable price into seas and realize a natural gas price before hedging of $2.81 per mcf or $0.17 less than the average NYMEX natural gas price…

Thanks, Glen. In my comments today, I’m going to provide a brief update on service costs, discuss the scale and success of first quarter operations and provide further outlook on the remainder of the year. First, to touch on well costs. As we previously mentioned during our year-end earnings call, we met with every major service company at the beginning of this year and reviewed every line item of our AFE for potential savings. As of today’s conference call, we’ve begun to achieve cost savings of at least 10%, which equates to $1 million to $1.5 million savings per well. We also continue to assess service costs and operational efficiencies and expect to gain additional savings throughout the year. The 10% savings on more than 5,000 3P locations would equate to an increase of our 3P PV-10 of approximately $2 billion, which, of course, is quite meaningful. As a reminder, the budget for 2015 had accounted for a portion of the 10% savings, but not all, and again we hope to realize further savings throughout the year. Now, on to the operational highlights from the quarter. As Glen mentioned earlier, our net daily production for the first quarter of 2015 averaged a company record 1.45 – excuse me – 1.485 Bcfe a day, including over 40,000 barrels of liquids a day, or 16% of total volumes. This represented an annual organic production growth rate of 89%, and liquids production for the first quarter of 2015 represented an annual organic production growth rate of 145%. While these production growth rates on a standalone basis are tremendous, I would also like to discuss our debt-adjusted per share production growth since our IPO in the fall of 2013. As you can see on page five of our earnings call presentation, entitled "debt-adjusted per…

Thank you, sir. We will now begin the question-and-answer session. [Operator Instructions] The first question is from Mr. Neal Dingmann of SunTrust. Please go ahead, sir.

Hi. Morning, guys. Say Paul, I’m wondering, given what you see now, I guess, with commodity prices, I guess, year-to-date but what you’re also seeing with your own and some peer dry gas wells versus the liquid wells, what’s your thoughts as far as – it doesn’t sound like you have any plans to change and chase after more dry gas or change the plans, but your thoughts on looking at those further east dry gas wells of yours versus just some others?

Yeah. We are aware and we see certainly others in the industry talking about how dry gas is becoming more competitive with the liquids-rich wells version, of course, it’s because liquids prices are down. We really like our dry gas areas, but we still give the edge to liquids rich. I think others are starting to turn towards the deep dry Utica and we’re keeping an eye on that. I think to assess that we just need a better feel of well costs and actual decline curves. So we’ll watch others as well as possibly do some ourselves in the future. But right now the edge still goes to the liquids-rich and that’s the plan we’re going with.

Got it. And then, just looking, I think it’s actually after April 15 presentation where you dive in there and talk about some of the realization margins, and then that one I think you call your realized price roadmap. You continue to have among, if not, the best realizations of the Appalachia. I guess as you kind of continue to see the roadmap develop and see more exposure of the favorable indices, how do you see just the – I would call it your non-hedge differential, how to you potentially see that continuing to shape up through the remainder of the year?

Yeah, Neal, we do see that improving over time. I’m not sure you’ll see a whole lot of change this year, we’d forecast $0.20 to $0.30 kind of differentials to NYMEX for the remainder of the year or for the full year. So I think we’ll be in that realm until we get that gathering pipeline in that will take us to additional markets, both TCO and NYMEX later in this year, and that’s probably near year end when that happens. We will see some increasing exposure to the Mid Continent as we grow our volumes in the Utica throughout the year. I think about 80% of our completions in the Marcellus for the year we’re done in the first half of the year as we laid on that regional pipeline whereas in the Utica about 80% of our completions for the year are in the back half of 2015 to give you some color on that. So you will see some shifting towards gas going to the mid-continent and Chicago out of the Utica throughout the year.

Okay. And then lastly if I could, just how do you guys feel now obviously after the prior equity deal on your current liquidity position certainly seems to be more than adequate but there is a bit of it out spend just how you guys view the kind of financial position as far as when you look at where you would like the ideal leverage or financial position for the -- call it how you maybe exit this year?

Yeah, I think we are very well positioned now with that – the equity dilution we took was only about 5%. We were comfortable doing that back when we did that in early March. Hard to say, where commodity prices were going. You’ve had some improvement since then on the oil side and hopefully the NGL side along with it. So that certainly helping the outlook and we are sticking with our capital plan for the year being very disciplined with that. But we feel very good about having that level of liquidity that gives us a lot of optionality whether or not we see opportunities come to us on the land side or not. We are positioned to do that and we are very well positioned to certainly accelerate once we do develop comfort with the commodity price outlook particularly on the gas side with that kind of, liquidity and our hedge position, which goes hand-in-hand with the leverage position here.

Makes sense. Thanks, gentlemen.

Thanks you.

The next question is from Holly Stewart of Howard Weil. Please go ahead, Madam.

Good morning, gentlemen. Just a couple of quick questions. One maybe first on the marketing side, kind of, two prong question. You did a lot better than your guidance on the net marketing expense in the first quarter. So I guess the first part would be is there anything to note for Q1 and then maybe how do you see that market kind of, developing over the second half of the year?

Yeah. I think in the 1Q Holly and good morning, thank you for the questions. In 1Q there were sort of, two factors, one was just, I think we did a great job of moving third-party gas on the REX capacity and capturing some of that spread between TETCO and Chicago in the mid-continent. So I think we did a great job there but then also one of the factors that was driving our forecast for the year of $0.20 to $0.30 net marketing cost was the A&R pipeline capacity to the Gulf coast and we expected that to be available in March and ended up not being available until April, so that cost got pushed into the second quarter. So no cost from that in the first quarter, so those were the primary factors driving it down to that $0.12 cost level. But going forward we expected average for the year $0.20 to $0.30 and still our expectation.

Okay. And then maybe along the same lines Glen on just the overall production cost guidance. I mean again you did a better job in the first quarter. Is there something to think about from an uptick in the back half?

I think, you know, that was primarily driven by low production taxes due to low commodity prices. So I mean that’s going to fluctuate with the commodity price throughout the year and hopefully we all see some uptick throughout the year in commodity prices and a bit higher production tax. So we are not changing the guidance. I did like where it came in and LOE stayed nice and low, which is terrific and we certainly continue to focus on the operating cost there’s and we’re optimistic but I think we’re going to stay with the $1.50 to $1.60 guidance for now.

Okay. And then my final one would just be, maybe Paul, on just the infrastructure side and kind of what you guys are seeing now for new pipes being proposed in 2018 and beyond. I mean, what we are hearing on the cost side is pretty high. So just maybe how you guys are viewing that market sort of developing and what you are thinking on additional capacity?

You know, as you Holly, there is a lot of projects that get floated and some look like they are a go in the 2018-2019 range, so some that can affect us incorrectly if not directly. But -- so EQT or EQM’s pipes going towards the Carolinas, same with Dominion’s, those look like they will probably fly. I think they have enough support. There is certainly others that get passed by us all the time. That also can help drain the area is surpluses develop. You do see even during these lower priced times that a number of the projects that have gotten floated recently are "selling out" in their open seasons. They are definitely finding E&P companies that are signing up to be shippers. So I think there is still -- people are still looking at their projected growth curves and seeing that they are going to need more firm transport out of the area. There is also -- as you know, quite an LNG market that’s developing both on the East Coast, but particularly on the Gulf and so we and others are seeing LNG buyers that are -- LNG buyers that are also supporting the pull, so some of them are taking firm transport on some of the pipelines also to help drain the area. So I think there is -- it slowed down a little bit with the industry activity going down. But I think there is still interest both by producers and by buyers.

Great color. Thanks, guys.

The next question is from Mr. Dan Guffey of Stifle. Please go ahead, sir.

Hey, guys. You touched on your liquidity position, just curious from your seat what is the M&A look like in Appalachia currently? Have you seen a lot of opportunities and I guess what’s your appetite for acreage acquisitions?

Well, we’ve really created a lot of value by just a holding in on the small acreage doing base leasing and so on, taking deep rights, we’ve really been able to create value that way just high grading and picking our points. So, in terms of M&A certainly as across the industry, but in Appalachia there are some companies that are under pressure. I think if we did anything on that front it would be more buy some acreage from slightly distressed producer. Probably wouldn’t be on the M&A front in the corporate sense.

Thank you.

And we are seeing good opportunities. Acreage prices have gone down pretty much across the board on the base leasing. There is just not as much competition.

Okay. Thanks. And you mentioned on dry Utica, you are looking at competitors, you are looking at state data. I guess, how much data do you need and how many wells do you need to actually see results on before you guys decide for your first test and will that be in Tyler County in West Virginia as previously planned and I guess at what point might you test the 42,000 net acres you had in Monroe and Noble over in Ohio?

Well, you know, as to Monroe and Noble we are starting to drill more dryish things, 1,100 BTU or 1,150. So that’s on our rig schedule for this year. It is right on strike with Gulfport and others so it is not a big mystery as to one expect to get. So they are pretty much development wells over in Monroe and Noble. Along the Ohio River, there has been a lot of tests and a lot of pretty spectacular results in terms of initial rates from what we hear and then when we can pull off of the state websites. They hold up well. But all of that takes time to build the decline curves and then there is still the uncertainty of the costs you never, you know, we just don’t have a good handle yet. People declare what their costs might be, but is that what they actually did or is that what they hoped to be able to do once they get the costs down and the methods more routine. So, we are watching it. As we have said before, we are waiting for at least for the Rover Pipeline, which comes in mid-2017 for a better market take away solution. And so will we do anything before that? Well, maybe if we see some other market solutions that can work for us. But we are being patient just trying to assess what the reserves and costs look like. So not sure it will be this year.

Okay. Great. One last one for me. You guys drilled some of the longest laterals Appalachia on average. How much of your acreage is conducive for drilling 9,000 foot laterals which you guys have in your type curve and how much is limited due to either lose integration or geologic restrictions?

Most it is conducive to it. And -- so most of it. We have now a five-year drilling plan with specifically identified slots, specifically identified units and they already -- these units have quite high working interests that we unitize all of the tracks. We may not be at 100%, but usually by the time we spud we have nearly 100%. So we are quite blocked up. Don’t see any reasons geologically why we can’t go further. There is no faulting in either of our plays to speak of. There is that one technical matter we have talked about before which is what might a technical limit be. We have been out towards 12,000 plus feet in a lateral. When you get to 13,000 or 14,000 is the friction loss as you try and frac those distant stages is the friction -- we have well blocked up and don’t see a problem there.

Thanks for the color today, guys.

The next question is from Subash Chandra of Guggenheim. Please go ahead.

Yeah, hi. Question on pricing here, first on, NGLs even though you’re sort of slated for the second expansion or Mariner East II, how do you see exports this year helping out in the basin and I will start there?

Well, you know, the exports out of the East you know Mariner East does not have that bigger quantity yet. And so Mariner East II will expand that Mariner West as you know is export to Serenia certainly that all of that helps in the tension and the dynamics in Appalachia. I think as time goes on more and more of these projects whether it’s a Sunoco project or some of the others that are being floated that those will certainly help clear the market. It’s being cleared somewhat right now a lot of people don’t realize certainly there is the ethane pipeline ATEX but there’s a lot of rail that is clearing the market and going to the Mid Continent and to a lot of different places to Western Canada to the Midwest. So there is some clearing right now but definitely future pipelines will help and I do think some of them will come to pass. I think there will probably be enough producer support.

And Subash you know our NGL pricing is net of that rail cost. So that’s all factored in. And if you look at the overall basin or the two plays the Marcellus and Utica Rich we don’t expect to see a whole lot of growth in the NGLs here throughout the year as producers have pulled back on their drilling. So that’s actually a good factor in terms of pressure on NGL pricing and more rail etcetera. So it looks pretty stable right now.

Got it. And when you think about your capacity in Mariner East II should we think about it the same as ATEX like you will load it according to the economics at that given time or should we think about that being sort of a -- you know -- a permanent home for volumes at the stated levels?

I think it’s more of the latter, Subash. It’s probably going to be more of a permanent home. Yes, the bottom has dropped out of ethane and so we will use some of that space ourselves. But in the meantime we have been subletting it to a release capacity deals. But the international markets for propane, butane are healthier and have a number of parties that are interested in buying. So you know, odds are we will be able to fill it with our own equity liquids.

Got it. Okay. And then final one for me. Just on Midwest pricing. Do you sort of see any threat to the differential if, say, Trans Canada reroutes gas from Eastern Canada into the Midwest?

Yes, yeah, there is definitely could be pressure, you know, a lot of folks we read their research reports as well and gas is coming in from Rockies, from Western Canada and now from Appalachia into those regions. So what you know -- what will come of it, it is a pretty deep market, pretty liquid. There are pipes that have been reversed, pipes such as our own with A&R that go from roughly the Michigan and Chicago area south as well as NGPL and so going south. So and on those variable costs to the shippers not all that high so the differential Midwest to Gulf can’t get all that high before those pipes fill up and drain that area a little bit. But, yeah, there could about pressure. Not sure how much drilling there will be in Western Canada at the lower prices to take it to Chicago, but that is a point where three different directions are bringing gas in the near future.

But I will add you have seen differentials tightened a bit in Chicago here off late. They have widened out $0.16 or so I believe in the out years and now around a dime and essentially flat to NYNEX next year. So kind of moves the other way.

Yeah. Lots of moving parts. Thanks Paul. Thanks Glen.

The net question is from Jeoffrey Lambujon of Tudor, Pickering, Holt & Co. Please go ahead sir.

Good morning. Just one follow-up for me, on the longer term gas infrastructure thoughts as you think about the out-years and potential mid stream projects come online beyond 2015 that will take your production to better priced hubs, how do you balance the idea of bringing on new volumes to fill the capacity versus just diverting existing production away from weaker priced hubs?

Well the latter will be the first thing we do and so that begins at the end of this year. We have certain firm sales deals that take us to Dominion South and to TETCO M2 up to the north and southwestern Pennsylvania. And so those deals were done to keep our gas flowing. They were done at you know at better times when Dominion South and TETCO M2 were healthier, but those are quantities that we’ll be able to begin pulling away as soon as our regional gathering system comes on. So that will be the first step to use our infrastructure to move away from the lesser markets, but then the infrastructure the firm transport continues to grow over the next several years and so that will be mostly intended for Antero gas and what we aren’t using ourselves, of course will be doing third-party deals to offset some of that cost. So early one it will be moved away from less favorable markets but it’s mostly intended for Antero equity production.

Thank you.

And this concludes our question and answer session. Be, I would like to turn the conference back over to you for any closing remarks.

And we would like to thank everyone for joining us on the conference call today. If you have further questions please feel free to reach out to me. Thanks again for joining us.

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