Good day and welcome to the Antero Resources First Quarter Earnings 2014 Conference Call. (Operator Instructions). I would now like to turn the conference over to Mike Kennedy, Vice President of Finance and Head of Investor Relations. Please go ahead.

Thank you for joining us for Antero’s First Quarter 2014 Investor Conference Call. We will spend a few minutes going through the financial and operational highlights and then we will open it up for Q&A. I would also like to direct you to the homepage of our website at www.anteroresources.com, where we have updated our company presentation for our first quarter 2013 results. 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 would now turn the call over to Glen.

Thank you Mike. Good morning. Thank you for everyone for listening today. We appreciate your participation. First Quarter 2014 of 786 million cubic feet equivalent per day increased 105%, so doubled year-over-year and that was up 16% sequentially quarter-over-quarter. The production included approximately 16,300 barrels a day of liquids or 12% of our total production. That’s a significant increase up 583% for the prior year quarter. So almost six fold from the prior year quarter and up almost 50% sequentially. I have noted that all oil production was over 3000 barrels a day or 18% of the liquids production primarily from the Utica. The midpoint of our guidance for 2014 calls for an average of 25,000 barrels a day of liquids production which equates to 16% of the total production. So this growth should continue throughout the year since we’re 12% in the first quarter. We sold our natural gas during the quarter at an $0.11 per mcf premium to NYMEX. This compares to our guidance of $0.00 to $0.10 premium. We would like to during the quarter to continue to sell the majority of our gas at Appalachian indices, as they exhibited favorable prices due to the cold winter weather. As a reminder we’re looking at southern portion of the Marcellus. So our local index is TCO. We sold approximately 45% of our gas at TCO which traded at a one penny discount to NYMEX for the quarter, but our gas sold at $0.38 premium due to the high BTU content. We’re currently rejecting ethane as we get a nice pick up from leaving the ethane in the gas stream and get paid on a BTU value there. Major of our natural gas is sold at various other index pricing points, at a $0.43 per Mcf differential in NYMEX…

We also believe that in order to capture the most cost efficient transport we have to be forward thinking and so we want to secure both the back haul and the pipeline reversal opportunities when they are available in order to limit the amount of new build transport that we need. These beliefs have resulted in us accumulating an industry leading firm transportation portfolio that grows to approximately 2.6 Bcf a day in 2016. Firm transport provides Antero the ability to direct almost half 49% of it's production to the Gulf Coast, 28% to Appalachia and 23% to Midwest pricing which includes Chicago, Michigan, Detroit, Wisconsin, the Midwest. The ability to direct our gas to the Gulf Coast is strategic as we expect the vast majority of growth in gas demand and NGL demand will occur on the Gulf Coast over the next five years. Obviously the firm transport has a cost but we believe that we’re capturing the most cost efficient transport. Antero was one of the first to recognize the need for firm transport so we initially focused on back haul agreements that was being the least expensive and certain firm sales as they are typically the lowest cost. We recently expanded our efforts to participate in certain projects that involve the reversal of pipelines and we have been quite successful in adding these projects to our portfolio. These reversals have a greater cost than the back hauls but are still quite attractive and costs much less than new build projects. Our firm costs per mmbtu including both demand and commodity charges for the next three years are $0.31 an Mcf, $0.32 an Mcf and $0.42 an Mcf for the year’s 2014, 2015 and 2016 respectively. The firm transportation portfolio based on current future’s pricing and differentials would…

(Operator Instructions). Our first question comes from Neal Dingmann with SunTrust.

A question now that you've got on -- you had mentioned about the compressors. I think Paul or Glen was talking about that. Was just wondering the typical line pressure now how you're flowing these wells, and I guess another way to ask that is how much you're deciding to choke back these wells going forward now that you have ample pressure?

The operating pressures on the interstates is in the 1100 to 1400 pound range, PSI and so now with compression as you say we’re able to bringing the wells on and be able to get into the lines so we’re not bucking that big line pressure anymore. But as to choking back we’re doing choke maintenance or pressure maintenance in the number of pilots in the western area in our condensate region just to see what the behavior is as everybody knows who are in retrograde condensate country on the west edge of our acreage. So that’s the only choking back that we’re doing is just to see what the behavior of the well will be in various pressure modes but in the rich gas area we’re not choking back the wells we’re able to flow those into compression and into the line and no problem getting into the line with the compression backing main line pressure.

Okay. And then on slide 28 you showed your huge midstream footprint. I am just wondering based on this, we don't have ample infrastructure in the Utica even if you added another rigorous so I guess in light of obviously the Gulfport issue today with midstream. Sure seems like you've got more than ample. I'm just wondering if you could give some color on your Utica midstream?

Yes we feel that we have got most of the elements in place that we could add another rig, we have got excess capacity in processing as the compressor stations come on and condensate stabilization. We can handle more production, we flow our NGLs to the north to Harrison County, where they are fractionated at Hopedale, and there is plenty of room at Hopedale in the fracs that are there. So we think that at the moment we could accelerate a little bit.

Good and then lastly, just besides Piedmont how aggressive are you all adding Utica acreage including both Ohio and West Virginia?

Well we have a large land team and they are working every day but it's very tight, it's not easy to pry loose acreage. A lot of it has been leased so we continue to add acreage overall as a company, we’re adding it on the order to 4000 or 5000 acres a month but it's tough sweating right in the very heart of the Utica fair way.

The next question comes from David Tameron with Wells Fargo Securities.

If we think about Harrison or just as the play moves east, how far east do you think you can push this in Harrison County?

Of course there is Harrison Counties, are you talking about Harrison County, Ohio or West Virginia?

West Virginia.

It's possible, there are geologic indicators that would say that the Point Pleasant goes that far east. Certainly it's going to be down deep, will it be tighter? There is just not enough well control to know but in terms of depositional faces indications are that Point Pleasant will be over there in Harrison County but we will start naturally the lowest risk and for us to start under our Marcellus acreage is to start in the Northwest corner. But it's possible that it will work in Harrison County too.

Okay. Can you just talk about -- you've obviously been out front of the midstream I guess let's call it the infrastructure. You guys a been out front and have locked in. I know you've done the same maybe a little more aggressive than some of your counterparts in some of the gas hedging. Can you guys talk about how you think about locking that in today which some people might say is a little bit more expensive than perhaps given the optionality later as infrastructure is built out? I know some operators have taken a different tack in the plan maybe because they do not have the infrastructure locked in today? Can you just talk about how you think about that as far as when you plan the business strategically?

Yes, you know I think to take the big picture view of course, everyone knows that the center of the natural gas business, the source of natural gas is shifting to Appalachia both the Marcellus and the Utica, huge resources and so that is where the very lowest cost and the biggest resources are going to be. So, I think one wants to take advantage as we said in our remarks on back haul and reversals in the first place and then talk about new builds after that. What we have learned over this last winter as production has grown is that if you don’t have firm capacity you’re going to be curtailed so you can look at it in a couple of ways, you can say well maybe if you don’t commit to these projects but others do and get them of the ground and you will be able to flow interruptably and that’s the risk that you take if you don’t have your firm then you will be able to -- that the pipes won't be full but the game has changed and I think the pipeline builders, the pipeline operators certainly are not willing to go at risk to build speculative pipe. They are going to want to have them fully subscribed or is close to it as possible in order to build the new builds and so they are getting a lot of full subscriptions. Now if you didn’t think the gas supply was there then the bet you could make would be well, they will get fully subscribed but gas prices will go down not as much gas will be developed and there will be room in the pipe for my gas to flow interruptably on a spec basis. The way that we see the Appalachian basin is there is just such a huge volume that is readily available to be developed at reasonable gas prices that the pipes are going to fill up. So we’re on this side of -- we feel good about the cost that we’re taking firm transportation and feel good about our economics, our cost structure and it's the safest thing to do to make sure that we can move our gas to markets and then focus very much on which markets we’re going to both on the gas side and the NGL side to maximize the price. So, we look at it, we’re very confident in our resource. We feel we have the gas there and gas to last for decades and so we more than perhaps the smaller players that have lesser balance sheets and lower resource we’re willing to step in and take that capacity and then tie it end to end to LNG markets, to liquids markets and to end users.

Okay, and then just one final question. I'll ask this knowing -- I'm not meaning to put you on the spot I just want to see if you have any comment. Gulfport, your shares have come back a little bit but you were getting beat up this morning, and we got a number of calls asking is this Company specific? Is this more call in the Utica, or how should we think about this? We've indicate we thought it more company specific? Any comment on Gulfport's release? And I will leave it out there and see if you have any comment on that.

Well I think we certainly think Gulfport is a good company. The things we can comment on is there enough processing capacity or fractionation capacity? We feel good about the fracs. We have our firm processing capacity ourselves and feel good about those volumes for us going forward just not familiar enough with Gulfport’s committed capacity to comment on that. So I think maybe they have gotten hurt in the market for some temporary curtailment there on the other aspect, the communication between wells or what we would call the frac hits. We feel pretty good about what we’re doing just to reminder to the market we have been shale players and pioneers for the last dozen years now and have had a lot of opportunity along the way. We have drilled and completed more the 500 horizontal wells. So we have learned a lot going back to our Barnett days, our Woodford days and so on and so we routinely have frac hits that is communication between wells certainly in our Marcellus where we drilled and completed over 200 wells. As a reminder we’re developing Marcellus on 660 foot inter-lateral distance and so we see plenty of frac hits. We have certain rules of thumb. Of course we have been very studious in first of all in microseismic, we use chemical and radioactive tracers to track interference between wells. And of course production history and we map out any communication between wells. We know which way the fractures are going and so on and so we have rules of thumb that we won't offset a well if it's made a certain amount of production. We will leave an open slot, or if it's made a certain amount we will move to a 1000 foot inter-lateral distance but in virtually all of our cases whenever we have a frac hit there maybe a delay as the well I guess you can say resuscitates itself. It comes back as pressure builds up that the well has come back to their original tight curves, you lose a little bit of PV because the wells go down for a little bit but longer term their performance is just fine on frac. So we don’t have the density in the Utica yet to be able to say but we would expect that the performance would be about the same that as we honor our rules of thumb and everything we have learned that frac hits will be okay and the wells will be able to recover. So I think that’s the perspective we can lend on horizontal wells in the region and whether you really suffer on overall performance or whether it's a temporary thing. We think it's more temporary.

The next question comes from Subash Chandra with Jefferies.

Did you share a Q2 Marcellus number? I might have missed it.

No we did not, we just gave an indicator of quarter to-date Utica production just to show the confidence that we have in our execution there and we’re averaging about 120 million a day equivalent net to the second quarter to-date, that’s the only comment we had on the second quarter there Subash.

Back to David's point of view same caveat here, I'm sorry same disclaimer here don't want to put you on the spot for another company, but the other thing they did talk about that your commentary on frac interference is very helpful. I was hoping maybe if you can add a bit more context to liquids fallouts and in the wet gas area in particular and if you think this compression that you sort of line up ahead of time if that sort of prevents all this from happening for you?

Subash, no I don’t think the compression will prevent the liquids fallout from happening. So there is (technical difficulty) have some of that liquids fall out and so what choke maintenance and pressure maintenance will do to enhance productivity, I don’t think anyone quite knows yet but time will tell on that but I don’t think just adding compression is going to be a solution for it. We have adjusted for that phenomenon in our tight curve. So it's contained in our book there on page 27 on the website. Those are our recently adjusted tight curves we put that information out in our operating update, April.

So just to understand that line of concern, you're obviously in the referring I think to the condensate. Within the wet gas area, I think answering a prior question, you were talking about being comfortable flowing these wells on fairly open chokes. So trying to understand how the behavior changes in the wet gas window? Or how you, yes. If that made sense?

Yes, so in the wet gas window you have higher reservoir pressure and you’ve a much lower dewpoint in the rich gas or wet gas areas so you’ve a much larger delta P, and furthermore when you start approaching the dewpoint or you get below the dewpoint there are far fewer of the large molecules the condensate just because it isn't as rich gas to fall out within the formation so you don’t get nearly the blockage. So we don’t think pressure maintenance is a big issue in the rich gas portion of the trend but it is on the condensate side so.

Got it. Okay.

Did that answer your question Subash?

Yes, yes, absolutely, that did and just one quick one for me, the split quarter fracs what is your sort of current, I think you are using a mix of things and if that frac design or completion design was evolving?

Yes I think fracking of course has been around 30 years, it's been actually around quite a bit more than that since the late 40s but in our careers it's been around 30 plus years and I don’t think you ever reach perfection in your frac design but there is major evolution, so 80s and 90s was much more of a gel frac era and now it's gone to slick water. We continually adjust but we have our favorite formulas or recipes that we do both in the Utica and the Marcellus. In general we’re much more slick water but we tail in with gel, so as we get into higher and higher sand concentrations within a stage then we start putting in guar [ph] gel and the reason for that is we do have limits on what we like to pump in terms of volume and so we use gel in the tail end in order to move the stand up into the fractures and away from the formation gel. It just has greater viscosity and carrying capacity. So where early slick water, late gel in each frac I guess would be the summary.

The next question comes from Holly Stewart with Howard Weil.

I had a question, you mentioned your move into the highly rich/condensate and then the highly rich gas area of the Utica compared to your activity in the condensate area. So can you talk about your rig allocation for the remainder of the year and then maybe into 2015 for those three areas?

Right now we’re running five rigs in the Utica, five big rigs. And as we said earlier we started a little bit more on the condensate side that was some of our earliest acreage was a little more mature meaning it was blacked up and we could permit there and put the pads together and drill there. So our drilling started out little bit earlier there and we started building infrastructure there. Now as our planners and geology and engineering put it together, we have more and more pads that are just slightly eased in the rich gas area. So today we’re running one of those five rigs in the condensate area and four of those rigs in the rich gas area and that’s the proportion that will stay at through this year. As we add more rigs it will still be on the order of 20% in the condensate and 80% in the rich gas.

Given your activity in the Utica how are you thinking about takeaway in the play as just the Utica evolves in general?

Well we think similar to our comments just over all for Appalachia that the Utica is going to be quite prolific both dry and rich and there is going to be -- when wells can make 20 million or 30 million a day and each company has lots of locations, the volume can build pretty quickly. And it's an area that doesn’t have that many long haul pipes, some are crisscross it but quite a few more are being proposed and so producers like ourselves and others are just looking at all the different projects whether it's reversal such as we have done with REX, first it was backhauled and reversal and now possible new builds and so we do think the Utica both rich and dry as it goes down deep into Eastern Ohio and Western Pennsylvania and West Virginia is going to be very prolific so we have the same view that it's going to be under piped and it's important to make sure that you’ve firm take away.

The next question comes from Adam Michael with Miller Tabak.

I noticed on this slide 28 that you have a new bullet point. In Q1 you generated EBITDA of about $25 million from the gathering systems and the water infrastructure in place. I am wondering how much of that, was that 100% Antero or are you taking any third party into that system?

That’s virtually all Antero, we’re starting to see some water revenues from moving waters to some third parties but it's close to 100% Antero.

Okay and then as the dry gas window continues to emerge in West Virginia, how much overlap is the Marcellus infrastructure -- how much overlap is there with Marcellus infrastructure and the Utica dry gas kind of emerging window in northwest West Virginia?

Well they will definitely in the sense, they will be overlapped. The corridors will be probably the same but remember that the Western side of the Marcellus is rich, very rich gas and so the gathering of the main lines through there will be rich gas gathering to get to processing plants where as the Utica will be dry and so one is not going to mix those two gas streams into the same gathering infrastructure. But beyond that there will be bullet lines that will be residue gas and coming out of plants and then dry gas lines and so those can be used for the same gas more or less but wet and dry gathering will not mix but let’s say can put two pipes in about the same ditch or the same right away and so there will be overlap that way, not only midstream but just surface access between roads and pads and water systems and containment frac, sourcing ponds and so that will all work for both plays.

The next question comes from Jeoffrey Lambujon with Tudor Pickering & Holt. Jeoffrey Lambujon - Tudor Pickering & Holt: Just real quick on the density in the Utica. You mentioned 660 foot spacing in the Marcellus. Could you remind me what your current down spacing assumption is across your Utica?

All of our numbers that we site for a number of locations and, cataloging, the resources all on 1000 foot inter-lateral distance. We are piloting right now both on 750 foot and 500 foot inter-lateral distance but all the numbers that we talk about are 1000 foot and so we’re doing these pilots. It will probably take a year or more to just as we build up our tight curves and be able to compare and contrast. It will take at least a year to figure out what the right density is, but in that range. Jeoffrey Lambujon - Tudor Pickering & Holt: Okay and on your type curves, are there any updates to your thoughts there? It sounds like it's early, but are you seeing any benefits from the pressure maintenance you are conducting in the condensate window?

Too soon to tell. Just only have been doing it for 60 days or less so too soon to tell. Jeoffrey Lambujon - Tudor Pickering & Holt: Okay just one last one for me, I know this has been hit on a lot. On the midstream I know you have been ahead of constraints. It sounds like you feel comfortable with the capacity you've locked in so far. Could you talk a bit more about how you see that ramping over time as you accelerate in the play?

Well on the Antero midstream infrastructure, yes, we try to stay ahead of the production and the drilling and I think we’re doing that. We don’t see a lot of constraints today, really we have maybe two wells waiting on pipe in the Marcellus. So it's pretty free flowing, get line pressures and such. On the take away, on the gas side you have seen this ramp up to now 2.6 Bcf a day and we continue to look at all the projects and there is real advantage there to be in the early mover. You end up with the we think the lowest cost take away and we think we have done a good job with that. There is a slide in the presentation on that and then now we started to focus on the liquids side as you've seen with supporting Mariner East II which is still in open season. But we are confident that that project will go forward as well as we will be looking at Y-grade pipeline projects to Bellview. So that’s kind of the next area of focus.

This now concludes our question and answer session. I would like to turn the conference back over to Michael Kennedy for any closing remarks.

Thanks everyone for joining us today. If you’ve any follow-up 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.