Welcome to the Antero Resources Q2 2015 Conference Call and Webcast. [Operator Instructions]. I would now like to turn the conference over to Michael Kennedy, Vice President of Finance and Head of Investor Relations. Please go ahead.

Thank you for joining us for Antero second quarter 2015 investor conference call. We will spend a few minutes going to 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 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.

Thanks, Mike and thank you to everyone for listening to our call today. In my comments are going to highlight some of the key achievements from the second quarter 2015 results. Discuss our expectations for the remainder of the year and provide color around our preliminary year-over-year net production growth target of 25% to 30% for 2016. Paul, will then highlight service cost reductions and operational efficiencies that we have achieved year-to-date outlined in Tower County, West Virginia, bolt on acreage acquisition we completed during the quarter and touch on our first Utica dry gas exploratory well that we spud in West Virginia earlier this week. On the production front, we had another outstanding quarter producing 1.484 Bcf per day net which was above expectations and in-line with the record quarterly production level achieved in the first quarter of 2015. Liquids production averaged almost 46,000 barrels a day for the quarter and made up 18% of the production stream. As we look ahead to the remainder of the year, we expect a slight decline in production during the third quarter driven by the deferral of 50 completions in the Marcellus into 2016 but expect to ramp up in completion of production during the fourth quarter as we head into 2016. As a reminder, we're referring the completion of 50 Marcellus well until the new regional gathering pipeline is in service expected by the end of the fourth quarter of this year. Once the pipeline is operational we expect an approximate $0.80 per Mcf improvement in gas pricing relative to Dominion South and Tedco M2 pricing resulting in approximately $150 million of incremental EBITDA during 2016. As you can see on Page 1 of the earnings call presentation, hopefully you've had a chance to pull it up, title that completion deferrals…

Thanks, Glen. In my comments today I'm going to provide more detail around the well cost reductions we've achieved to date, provide an overview of the bolt-on acreage acquisition we completed during the quarter, discuss our Utica dry gas test well in Tyler County, West Virginia that we spud earlier this week and finally touch on the potential integrated water business drop-down to Antero Midstream. First let me discuss our well costs. As Glenn mentioned and as illustrated on slide 7, entitled AR well cost reductions; we have reduced well cost in both the Marcellus and Utica by 16% and 18% respectively as compared to 2014 cost. Approximately half of the savings in the Marcellus are from service cost reductions and the other half are from operational efficiencies. We averaged 22 drilling days per well for a 9,000 foot lateral which is an improvement of seven days versus the 2014 Marcellus average of 29 drilling days per well. Similarly on the completion side of things, we were able to increase the completed number of stages per day by over 25%; to 3.9 stages per day during the second quarter which of course, decreases overall completion cost per stage. The reduction in drilling days and increasing completed stages per day, in turn reduces our daily rental cost for tools and other spread cost which amplifies the overall cost reductions. In the Utica approximately 65% of the well cost savings are from service cost reductions and 35% are from operational efficiencies. Similar to the Marcellus we improved the number of drilling days per well from 34 days in 2014 to 30 days in the second quarter of 2015 for a 9000-foot lateral and increase the completed stages per day by 34% over the 2014 development program to 4.3 stages per day. We…

[Operator Instructions]. The first question comes from Neal Dingmann of SunTrust. Please go ahead.

With the recent success we obviously [indiscernible] other guys in Southwest PA your thoughts about perhaps expediting some of the drilling, you obviously have a sizable amount of acres there yourselves, your thoughts about either drilling that or just redirecting some of your drilling efforts?

We're certainly following the activities of all of our peers in the play and, you are right, they are pretty impressive flow rates. So our view right now is to drill at least one well ourselves and learn more about the technique, more about the well cost and then produce the well and see what the decline curve actually is. We're still in learning mode so it is still uncertain as to what the economics will be, but with good results and it is quite possible that we will do more.

What is your -- do you have take-away in that area, is that any issue?

We can move the gas through our Rich gas system and that's what we're going to do with our first well is move the dry gas through so we have capacity. It is not as efficient, but it is the best direction to go to send it through the plant and then to better markets. Further on down the road, by the end of next year, then Rover will be operational or mid 17 and so we will be able to move gas in the Northwest direction. So better take away situation in about a year and a half. In the meantime, we can move it to our infrastructure to the better markets but it is not quite as efficient but certainly better than going to Dominion South or TETCO M2.

Just last question on -- you talked I think in the press release about the component [indiscernible] expense that was attributable to the underutilized [indiscernible] pipeline capacity. Just your thoughts on that going forward, will that continue to be about the same as far as what's underutilized or how will you think about that?

We will continue to see some cost there. We certainly try to mitigate those costs each quarter by using the capacity in capturing differentials where we can or buy and selling gas. So it is a little bit of a wild card but we will continue to see that until we fill the capacity which by 2017, those numbers start to get pretty minimized relative to the overall cash flow and revenues of the company. But it will continue to be an issue for the next year and a half which we think that's a fair price to pay for a position that bills toward 4.8 Bcf a day. And I think our demand charge on that whole position average I think we disclosed in 2016 is about $0.33 then it bills in the high $0.30 per demand charges by 2018, 2019 when all of that is online. Very reasonable cost of transport so we were early mover and you pay a little bit of a price on that certainly during a commodity downturn where you scale back a bit, but we think it is certainly a fair trade.

The next question comes from Jeoffrey Lambujon of Tudor, Pickering, Holt and Company. Please go ahead.

Just first on in Q2 production, you mentioned your Marcellus well to date as the best Marcellus well to date for you guys. Anything else contribute to the beat that could be expected to continue going forward maybe better than expected decline rates? Anything on the timing of completion? Just anything of that nature?

Well we certainly try to be conservative in our outlook so we hope that we can exceed expectations going forward. But it really is a situational thing quarter by quarter as to where you have constraints here and there and pipeline downtime and that type of thing. But we're optimistic and feel good about our guidance.

Just given the run rate so far, how does that jive with what the current full-year guidance and then previous guidance for April through December being about at the 1.4 Bcfe a day level at the midpoint? How does this change that if at all or are you still sticking to that number?

We do expect net production to be down a bit in the third quarter, so we still feel good about that 1.4 Bcfe a day number for the year. And, like I said, we're optimistic that we will exceed that and that's one of the guidance is 40% plus production growth for the year.

And last question for me looking into 2016, you guys have laid out the well cost, but could you provide more color on assumptions going into that preliminary 25% to 30% target for next year in terms of rig activity, capital allocation and efficiencies that kind of go in to that assumption?

Yes, we're baking our efficiencies into our thinking for next year's budget and that's why we have the comment there that modest increase in what does that mean for this year's budget. It is probably in the 5% to 15% range, something like that depending on where we end up on that production target spectrum for next year. But we have baked those efficiencies into that and the well cost reductions so far. We do think all of that continues, it is not static, so hopefully that will actually improve by the time we get to 2016.

The next question comes from Dan Guffey of Stifel. Please go ahead.

In 2013 you guys began utilizing the SSLs and saw a nice bump in recoveries and then you subsequently increased your Marcellus URs per 1000 lateral foot near year end 2013. Over the past 18 months, those UR per 1000 foot estimates have been essentially stable. I'm curious, could you guys provide any detail if you see any changes you are making in your completion design and if you see any potential uplifts for higher incremental recoveries on your West Virginia acreage?

The company never reaches perfection where all these tweaking our completion designs but we have pretty well settled on the SSL, the shorter stage length. As we're now we've got some pilots that have been going on for at least the last six months, have a little bit shorter, but we continue to watch production and see if we can optimize further. But feel pretty good about where we're now.

Okay. You guys have been one of the most aggressive in building your acreage foothold throughout the basin. I guess can you discuss how many additional large-scale opportunities that are currently on your radar?

We still have a very active leasing program. We're pleased that we have seen the lease cost go down quite a bit during this downturn, but we have lots of things on our radar, both big and small. We focus on where we see, of course, the best potential geologically and in terms of results and we factor take away and those things into. So have a lot of things that are going on, but I think the best value right now is the base leasing that we continue to do.

And then last one for me. I guess with commodity prices headwinds persisting, could you guys anticipate you could see any borrowing base reductions on your upcoming October redetermination or should the increase in PDP offset any of the commodity price decreases?

I don't think we're in that category in the box of seeing a step down in our borrowing base. We would expect it to be neutral to up with added quarters. We did that determination off of year-end reserves so that was the $4 billion borrowing base. So we will be looking at three quarters of additional PDPs less production, so we feel pretty good about that being neutral to positive step up and actual borrowing base and whether or not we choose to use all that, that's another matter. But we're very solid there and certainly the hedge book helps buffer that and we continue to add hedges and that buffers that situation.

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

Quickly, Paul I think last quarter you mentioned you still give the edge to liquids development just that we've been under continued NGL pressure, just curious if you had an update on your thoughts there?

We continue to look at that. We have shifted a little bit over in our Utica fairway a little bit toward drier side, feel good about that where it is more of a known entity. We know the decline curves and the well cost and, after we drilled this deeper Utica test in the Marcellus, we will certainly weigh that against liquids. So still subject to rethinking it, but for the time being, we still see that our best well economics are in the liquids fairway in the Marcellus.

Okay, great and then maybe kind of sticking with the Utica activity. I think most of your Utica completions were set the second half of the year. Can you help us better forecast the division I guess between 3Q in 4Q with the Utica completions?

Yes, I think a good measure would be probably 75% of our completions in the Utica are happening in a second half of year, Holly. So it is very much back-end loaded where you have the opposite phenomena in the Marcellus where it is flip the other side.

Any help between 3Q and 4Q?

Between the two plays, when you balance it out, they're fairly equivalent in terms of number of completions expected each quarter. You see more of the production show up in the fourth quarter, hence the bit of a step down in production expected in the third quarter.

And then maybe a last one just on some help with modeling for NGL pricing. Is there a way to think about the discount that the basins receiving right now on NGLs? Just maybe a rule of thumb or something?

It's certainly volatile and I think it is going to be hard to predict here for the next year or so for us until we get into the Mariner East and the International market. But we do expect to see improvement seasonally as you go into the fall/winter months. We're optimistic about that. But it is difficult to predict and we have our forecast out there of 30% to 35% of WTI for the year. But that's taking into account quite a bit of volatility from quarter to quarter. Second quarter expected to be soft and it was. And third quarter similar with improvement in the fourth quarter, seasonally.

There are no further questions at this time. This concludes our question-and-answer session. I would now like to turn the conference back over to Michael Kennedy for any closing remarks.

Thank you for joining us on today's conference call. If you have any further questions please feel free to contact us. Thanks again. Goodbye.

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