Good day and welcome to the Antero Resources Second Quarter Earnings 2014 Conference Call and Webcast. All participants will be in listen-only mode. (Operator Instructions) Please note this even has been recorded. I would now like to turn the conference call over to Mike Kennedy, Vice President of Finance Mr. Kennedy the floor is yours sir.

Thank you for joining us for Antero’s second quarter 2014 investor conference call. We’ll 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 Web site at www.anteroresources.com, where we have provided a separate conference call presentation under the quick link section that will be reviewed in today’s call. These materials along with the updated company presentation can be located on the homepage of our Web site. 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. And thank you everyone for listening to our call today. In my comment I am going to cover the status of our guidance, provide a review of our price utilizations and touch on reserves a bit. Paul will then review our firm transportation portfolio and the operational results for the quarter. Our guidance for the year was based on a plan that assumed our development program to run an average of 18 drilling rigs during the year. This plan factored in certain risking on the midstream infrastructure build out necessary to move the production from those rigs. As we progressed throughout the year the timing of the midstream build out have exceeded our risk and expectations. We’re currently waiting on a fourth processing train at MarkWest Sherwood facility to be completed, which right now is resulting in about 400 million cubic feet a day equivalent of curtailed production. This 200 million cubic feet today facility, processing facility is expected to be placed into service over the next month. With the completion of this facility and the expected completion of Sherwood V in the fourth quarter of this year substantially all of the midstream infrastructure necessary to move our production for the remainder of 2014 would be complete. Thus we're now reviewing our plan to determine whether we want to further accelerate the development of our assets as we head into 2015. The production targets of 45% to 50% growth in 2015 and 16 assumes an approximate two rig increase in each of those years, so we may want to get a head start on the program if we can get comfortable with the infrastructure and capital needs there. Now onto realizations. I will be covering a few slides that are located in conference call presentation as Mike…

Thanks Glen. In my comments today I’m going to address couple of our recent developments. Glen has already covered our significant profitability and reserve growth. So I’m going to focus on our firm transportation strategy and our operational update. We have an industry leading portfolio of firm gas and NGL takeaway which is detailed on Slide 5, entitled integrated portfolio of firm gas and NGL takeaway. Antero made significant additions to its transportation portfolio during the second quarter of 2014 resulting in an Appalachian E&P industry leading for 4 Bcf a day of residue gas firm transportation in sales. This portfolio provides us with the ability to move a substantial portion of our Appalachian basin gas production to more favorably priced indices. The firm transport provides Antero the ability to direct 48% of its production to the Gulf Coast. 20% of its production to Midwest pricing including Chicago and Michigan, Detroit, Midwest and 19% to Appalachia and finally 13% to the Atlantic seaboard. The ability to direct our gas is the Gulf Coast is strategic as we expect the vast majority of growth in gas and NGL demand to occur on the Gulf Coast over the next five years. From a liquids perspective we’ve entered into a agreements with the proposed regional ethane crackers both in West Virginia and Pennsylvania for a total of 55,000 barrels a day of ethane. We also have 20,000 barrels a day of ethane takeaway capacity on Atex which brings out total ethane capacity both in local demand and regional transport to 75,000 barrels a day. Now during the quarter we signed up our first international customer for ethane sales at price that's expected to be a premium to gas Btu value and this will continue to be a focus for us going forward. We…

and:

Thank you, sir. We will now begin the question-and-answer session. (Operator Instructions) The first question we have comes from Neal Dingmann of SunTrust. Please go ahead.

Hey, guys, good update. This is actually Will for Neal. Quick question on the -- overall when we look at pricing in the basin what are you all's thoughts overall activity? Over the next call it a year to 18 months, obviously you're running more rigs right now than you had originally planned, but with pricing exposure in the basin, how do you think about that?

Hey, guys, good update. This is actually Will for Neal. Quick question on the -- overall when we look at pricing in the basin what are you all's thoughts overall activity? Over the next call it a year to 18 months, obviously you're running more rigs right now than you had originally planned, but with pricing exposure in the basin, how do you think about that?

So is your question, are we concerned about the pricing in the basin and would that slow us down, is that what you’re asking?

Exactly, yes. How would that change your thoughts and where you would focus activity across your acreage?

Exactly, yes. How would that change your thoughts and where you would focus activity across your acreage?

Now, I mean we’re still seeing outstanding rates of return. Every rig running in the Marcellus is drilling processable gas 1150 and above and the same for the Utica, so we have 20 rigs drilling processable gas along with condensate many areas. So if you look at the rates return slides in our August presentation on the Web site, there is a sensitivity analysis in there where you can -- if you want to $0.50 off the share price or whatever you can see that, you can see that there is still quite outstanding rates returned. So that’s not falling us down plus some of our comments we made as we go forward in the second half of the year about two-thirds of our gas will be priced favorable indices and so that includes Chicago of course but also TCO is also about $0.12 off of NYMEX for the rest of the year, so none of that indicates us that we should slow down or be concerned about our rates of return.

Okay, great. And then also when you -- in your West Virginia dry gas for Utica area, what are you all's thoughts, I know you have a well coming up soon, what are your thoughts on activity there potentially for next year?

Okay, great. And then also when you -- in your West Virginia dry gas for Utica area, what are you all's thoughts, I know you have a well coming up soon, what are your thoughts on activity there potentially for next year?

Well, we still want to just drill our initial test and test it we’re surrounded by other industry tests well that are both down dip and up tip of our locations, so fully expect it to be good it’s just a question of at what rate. We’re still working on infrastructure takeaway to the best markets for the Utica dry gas test so as to whether we’ll get into a full scale Utica dry gas development program that’s probably further on down the road I think it’s to drill our test first and so that’s where our focus is, so most of our all of our Utica activity, as Glen was saying, will be over in the rich, highly rich, high rich condensate areas of the Utica fairway.

The next question we have comes from the location of Joe Allman of JPMorgan.

I noticed in your latest slide presentation, the August corporate presentation that the Utica shale type curve slide went away, so what's the plan with that going forward? And could you talk about what the data looks -- what the performance looks like recently? JPMorgan: I noticed in your latest slide presentation, the August corporate presentation that the Utica shale type curve slide went away, so what's the plan with that going forward? And could you talk about what the data looks -- what the performance looks like recently?

No changes to the type curve, Joe. As we mentioned in some of the commentary, we’re seeing results that are consistent with the type curve and I think we’ve covered that in the reserve press released that, if you want to go back and look at, we kind of highlight by area what we’re seeing and what we booked at midyear. So no changes there and we don’t plan the really kind of chase the type curve around quarter-to-quarter, if you will, we’re very satisfied with the results, we’re seeing outstanding wells.

Got you and could also talk about your choke management program in the Utica shale especially in the gassier areas? JPMorgan: Got you and could also talk about your choke management program in the Utica shale especially in the gassier areas?

We continue to do choke management in the Utica. We like other operators are seeing favorable results. We see more liquids. By the time you get to a certain point on gas production by doing choke management, we see a higher proportion of liquids on the choked wells. So, we are still doing pilots on any pad we might have too choked and too un-chocked, but it looks favorable.

Next, we have Holly Stewart of Howard Weil.

Let me switch to the midstream side, what's the latest on the private letter ruling and should that continue to get delayed? What's your thought about potentially moving forward without the water infrastructure assets? Howard Weil: Let me switch to the midstream side, what's the latest on the private letter ruling and should that continue to get delayed? What's your thought about potentially moving forward without the water infrastructure assets?

Yes, Holly, that’s a good question. We don’t have a lot of clarity. I think there has been some press on this over the summer where I believe the IRS has completed their process and now they’re waiting on treasury to sort of sign off on the policy but that doesn’t really tell us when the PLR is going to be issued, so we probably don’t know much more than you do on that even though we have been in contact with all of them. The parties there but to take the water out, we think it’s such an integral component to it and there is certainly nothing that we have heard from either IRS or treasury to think that water would be excluded from future PLR. So IRS has issued about a dozen PRLs in the past for water to MLPs, so this will be quite a change in approach if they said that freshwater distribution which is very integral to our fraction stimulations is excluded. As you probably know sand has been included and that’s also big part of that fracing and there is bit PRL issued for that. So we don’t have any real concerns, no reason to be concerned that would be excluded. So we’re trying to be patient with this and wait see how it plays out over the next couple of months. That’s all we can say about at this point.

Okay, great, that's helpful. And then noticing that you've outlined these two big projects one on the gathering side and then one on the interstate pipeline side in which you've got the potential for an equity partnership. Can you maybe walk us through how those options came about and then the timing for those decisions that you have to make? Howard Weil: Okay, great, that's helpful. And then noticing that you've outlined these two big projects one on the gathering side and then one on the interstate pipeline side in which you've got the potential for an equity partnership. Can you maybe walk us through how those options came about and then the timing for those decisions that you have to make?

Yes, Holly, as we build our midstream business and forecast how our MLP looks going forward, it made a lot of sense to us to make sure we had those options and we’re anchor shippers in both of those projects so that opportunity came to us. This is one of those things I think is being a big player and the most active driller in Appalachia, these kind of opportunities can come to you and so we have enjoyed that put those in place. The option period varies but we have got some time, we consider it’s not something we have to do right away and obviously there are big capital commitments particularly for the Rover pipeline. So let’s see how that plays out. They just completed their open season and we’ll wait to in the final project looks like and decide whether or not we want to participate in that. But we think those are great add-ons to our MLP business, give us long-term regional pipeline capacity participation. So we think that’s kind of a nice add-on to our current just water and compression and gathering business. So that’s kind of the way we view that and the processing is something we think about too maybe we participate in that eventually as well in the midstream business for the MLP.

The next question comes from David Cameron of Wells Fargo.

Hi. A couple of questions on reserves, your mid-year reserve bookings, I know you guys talk about that at one point, I think you referenced 1.9 Bcf for 1,000 foot of lateral, were you allowed to book -- whether the engineers allow you to book at that rate, and then if so, I’ll start there and go from there.

Hi. A couple of questions on reserves, your mid-year reserve bookings, I know you guys talk about that at one point, I think you referenced 1.9 Bcf for 1,000 foot of lateral, were you allowed to book -- whether the engineers allow you to book at that rate, and then if so, I’ll start there and go from there.

David I think the 1.9 Bcfe versus 1.7 is the well ahead booking, 1.7 Bcf per 1,000.

Okay.

Okay.

What they want to say they tied together. And yes, definitely the engineering guidelines allow for that booking.

Okay. Yes, I didn’t know how far be enough data in there far enough long in the process to give you 100% credit for that.

Okay. Yes, I didn’t know how far be enough data in there far enough long in the process to give you 100% credit for that.

That’s, we make percentage earlier but at which 35% of our proved or booked with SSL so hence that 1.7 Bcf well ahead but it’s only 60% something about two-thirds of our 3P is booked with SSL. So that implication there is the remainder is booked at the old type curve which was 1.5 Bcf. So there is upside there overtime as we continue to roll out the SSL.

Okay, that’s helpful. And then on CapEx, I know in the press release you referenced the 20 rigs and you referenced that in your prepared remarks versus you expected a slowdown, now you’re not going to see that slowdown I mean is the right way for us to think about it two additional rigs for half of the year versus your original budget or can you give us any framework around that?

Okay, that’s helpful. And then on CapEx, I know in the press release you referenced the 20 rigs and you referenced that in your prepared remarks versus you expected a slowdown, now you’re not going to see that slowdown I mean is the right way for us to think about it two additional rigs for half of the year versus your original budget or can you give us any framework around that?

I think that’s probably the starting part we haven’t decided yet we’re still working on that detail we’ll cover all that in due time here in the quarter we will roll that out as to what the final budget is for the year and the guidance on production that goes with that both for this year and rolling into next.

Okay and last question, are you guys, is there anything new as far as on the completion if anything you’re trying different out in the Utica, Marcellus other than choke management or pad drilling, is anything new and different that you care to share with us?

Okay and last question, are you guys, is there anything new as far as on the completion if anything you’re trying different out in the Utica, Marcellus other than choke management or pad drilling, is anything new and different that you care to share with us?

I think you’ve touched on the main ones David there is SSLs there is chock management there is density. So at this point within our reach gas area the Utica were developed 500 foot inner lateral distance and so far so good so I would say as we’ve made the point we’re long time share players so we have our techniques to prevent or limit frac hits offset wells we have guidelines there to limit and bring back wells as they get hit by a frac pretty quickly. So that’s pretty standard at this point I’d say one thing that we will test in our deep Utica will be ceramic proppant probably cargo ceramic high strength, high pressure ceramic proppant on the deep high pressure Utica and which part of the recipe of the frac stages we put in there we were gotten that so it won’t all be ceramic proppant but we’ll definitely put it to a good test.

Okay. I appreciate it. Thanks guys.

Okay. I appreciate it. Thanks guys.

Thanks David.

(Operator Instructions) We have a follow up question from Holly Stewart of Howard Weil. Please go ahead.

Sorry, just one more. You’ve obviously done a great job on the marketing side with both natural gas end markets and then the NGL take away, but is there anything that you feel right now that you’re kind of still missing in the portfolio as you kind of look out over the next few years? Howard Weil: Sorry, just one more. You’ve obviously done a great job on the marketing side with both natural gas end markets and then the NGL take away, but is there anything that you feel right now that you’re kind of still missing in the portfolio as you kind of look out over the next few years?

No, although there, Holly there will be more pieces to add as time goes on the opportunities are there whether it’s a long haul residue gas transport, developing export markets international for both residue gas and for liquids, there is a piece out there at some point will there be a NGL Y-grade pipeline to the Gulf, time will tell where we’re quite happy with our export capacity out of Marcus Hook and the net backs there relative to Bellevue or the Gulf Coast but that’s one element that I think as a regional group of producers, the Appalachian group will they look to support a y-grade project that will transport y-grade liquids all the way to Gulf to get fractionated and going to the petro chems there, that element has not been answered yet.

And that’s right not just a Kinder project? Howard Weil: And that’s right not just a Kinder project?

There is several out there Kinder is certainly an important open, I think Energy Transfer has one as well.

Okay. Thanks for the help. Howard Weil: Okay. Thanks for the help.

Thank you.

Next we have David Beard of IBERIA.

I just want to talk a little bit about the excess capacity that you have on your system, I noticed you sold some, but you're also paying for capacity. Could you talk just about your strategy of how you're dealing with excess capacity and leasing it out and how we should think of that financially going forward? IBERIA Capital Partners: I just want to talk a little bit about the excess capacity that you have on your system, I noticed you sold some, but you're also paying for capacity. Could you talk just about your strategy of how you're dealing with excess capacity and leasing it out and how we should think of that financially going forward?

Sure. For starters David we are -- as we stated in our press release we aren’t buying access firm capacity to speculate within the market world it’s just that the capacity comes on in steps whereas the production grows in more of a ramp and so from time to time we’ll have access capacity. And so what we’re looking for of course is the others that don’t have firm that want to go better market we’ll buy that gas and transport it and we’ll get an uptick and we will reward the producer where we buy the gas with a little bit of a premium and then hold on to the premium Marcellus as well. So that’s the intent. And it’s part of that -- part of that in the marketing expense of course is our Atex capacity which as of yes, we haven’t use but we did some opportunity to utilize some of that Atex capacity going forward.

Well, this time we will conclude our question and answer session. I would now like to turn the conference back over to management for any closing remarks.