Good morning and welcome to the Antero Resources Third Quarter 2014 Earnings Conference Call. 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 also note this event is being recorded. I’d now like to turn the conference over to Michael Kennedy, VP of Finance. Please go ahead.

Thank you for joining us for Antero’s third 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’d also like to direct you to the homepage of our Web site at www.anteroresources.com, where we’ve provided a separate earnings call presentation 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’d 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’ll now turn the call over to Glen.

Paul will then review our firm transportation portfolio, including all-in costs and utilization numbers, operational results for the quarter as well. Lastly, during our comments, both Paul and I will periodically refer you to a handful slides that are located in a separate conference call presentation on the home page of our Web site that was just now uploaded in the last few minutes, third quarter 2014 earnings call presentation. This is separate from our monthly investor presentation also located on the Web site. So please make sure you’re reviewing the correct slide deck during the call. As you’re probably aware we successfully priced the IPO of our Midstream business Antero Midstream Partners LP, earlier this week. The common units of Antero Midstream trade on the New York Stock Exchange under the symbol AM. It was a great outcome for us and the market response was tremendous. Turning to page one of the earnings release that I just refer to, presentation on the Web site, the Page 1 titled -- entitled Successful Midstream IPO. AM priced $25 per unit or 25% above the midpoint of the 19 to 21 range. So great reception there and that resulted in a 2.72% IPO yield on the distributions and that’s based on a minimum quarterly distribution of $0.68 per unit. The closing price of Antero Midstream on its first day of trading which was yesterday, closed with a market value, enterprise value about $4 billion including the $250 million of cash proceeds that will be retained at the general partnership for general corporate purposes. Now looking at Slide number 2, entitled Antero AM IPO compared to other IPOs. You will see that the AM IPO represented the largest LP MLP IPO ever and the lowest yielding IPO ever. So you can see that…

Thanks, Glen. In my comments today I’m going to address our firm transport strategy, including its low-cost nature and our expected utilization of the portfolio we’ve assembled as well as to give an operational update. Let me start with firm transportation. We have an industry-leading portfolio of firm gas and NGL takeaway, which is detailed on Slide number 6, in your -- on the Web. And that is entitled Largest Portfolio of Firm Processing and Gas and NGL Takeaway in Appalachia. We made additions to our natural gas FT portfolio during the third quarter of 2014, resulting in an Appalachian E&P industry-leading 4 Bcf a day of firm transportation and sales. To complement our Gulf Coast directed firm transport, we’ve entered into an agreement to sell 200,000 MMBtu a day of natural gas at NYMEX based pricing to Cheniere at Sabine Pass for LNG export. From a liquids perspective, as reported in our third quarter operations update, we’ve increased our commitment to Sunoco’s Mariner East 2 project from 51,500 barrels a day to 61,500 barrels per day. The 61,500 barrels per day consist of 11,500 barrels of ethane, 35,000 barrels of propane, and 15,000 barrels of butane. In conjunction with our ethane commitment, we executed an ethane export agreement for 11,500 barrels a day with Borealis that will begin once Mariner East 2 is in service. You may have noticed that Sunoco announced today that it has reached final investment decision, FID on Mariner East 2. So the project is committed and expected to be placed in service by the end of 2016. Additionally, we’ve committed 55,000 barrels a day of ethane to the two crackers that have been announced ethane crackers announced by Odebrecht Braskem and Shell respectively, which are currently pending final investment decision. To focus on natural…

Thank you. (Operator Instructions) The first question comes from Neal Dingmann with SunTrust. Please go ahead.

Good morning, guys, and good details. Glen or Paul, just how do you think about for -- going into next year with a pricing environment, I guess it's a nice problem to have. When I look at sort of this capital allocation, sort of two questions here around that. One, just would we see the mix between the Marcellus and the Utica potentially shift a bit next year based on returns you’re seeing? And then secondly, around allocation, obviously you’re set up very well now with Midstream capacity. So is it safe to say on a percent basis, we will see much more diluted or actually appropriated towards the upstream versus the Midstream?

Thanks, Neal. We are always considering shifting, that’s the beauty of only being 50 miles apart within our two projects is that we’re always looking at shifting a rig back and forth between those two projects just to optimize the very best locations and so I don’t think you will see a wholesale of shift back and forth with capital spending between the two projects. They’re pretty well optimized right now, but there might be a rig in one direction or another. Yes, we’re having good results and so I think Glen can cover our budget here, but -- go ahead Glen, for CapEx.

Yes, Neal thanks. I'll just point out that with this new Midstream vehicle MLP, that’s where all the Midstream CapEx is carried going forward. It’s well capitalized with over $1 billion of capacity there right out of the gate, at the Midstream business. So I think that certainly helps a lot liquidity now if you included all the borrowing base that we’ve pro forma for all of this as of September 30, liquidity is up around $4 billion. So great liquidity position and due to our hedges and increasing hedge position for 2015, we don’t see any need to pullback on our capital budget as to what we’re planning for the year. So continue with our guidance of $2.3 billion to $2.5 billion for 2015 for drilling and completion CapEx.

That makes sense. And then, just lastly, just your thoughts on the Utica dry gas. Obviously, certainly, with you starting to enter there and some great peer results, just your thoughts as far as potentially the increase in activity there?

Yes, you’re right. The -- Neal, the results of the dry down dip, we would call it, deeper Utica dry gas play have been fairly spectacular and the most recent test come to within our acreage in Northwestern West Virginia. And we certainly like the looks of it. We’ve got about 150,000 net acres that are right in that vicinity in the Northwestern portion of our block, it of course have the deep rights for Utica. So it looks good. Can it compete for capital with our liquids? Time will tell. We haven’t seen the declines on the wells yet, but for the near-term we’re just going to stay focused on liquids. But certainly have that in the back of our mind that we could add some developments both on the upstream side with drilling and the Midstream side it will need new infrastructure gathering and compression to lead into the takeaway points over time. But it’s probably going to be a little while before we shift and mass to the deep drilling of the Utica and I think we’re talking years.

Certainly a nice optionality to have. Thank you.

Yes, thank you.

Thank you.

The next question comes from Jeffrey Lamberjohn with Tudor, Pickering Holt & Co. Please go ahead. Jeffrey Lamberjohn - Tudor, Pickering Holt & Co.: Good morning, guys. Just one from me, on leasing going forward. Just wondering how you’re thinking about that and how you’re looking at budgeting for that next year?

Yes, leasing going forward our focus, Jeffrey, is on the base leasing. So we’ve more than 850 lease brokers that are working everyday for us and they’re doing things like setting up drilling units and so on, but they’re also working the records and so I think that’s where we obtain quite a lot of value is doing the base leasing that pulls all of our fragments together and builds them into drilling blocks.

Yes, Jeffrey we see that land initiative continuing. We haven’t come up with a budget yet for what next year for land, but the momentum continue certainly in the core area and the rich gas core area. Jeffrey Lamberjohn - Tudor, Pickering Holt & Co.: Thank you.

Thank you. (Operator Instructions) The next question comes from Dan Guffey with Stifel. Please go ahead. Mr. Guffey, your line is now live. Dan Guffey - Stifel Nicolaus & Company: Sorry about that, guys. Thanks for all the color today. You’ve been moving rigs into the liquids rich portion of the Marcellus. I’m curious; across that acreage is there a point where you are going to be forced to extract ethane, because of the BTU content and pipeline restrictions? And if so, at what point or what time do you think that may happen?

Our models say that we don’t see that in anytime in the near-term. Our guess is -- just I guess at the right BTU that coming out of the plant, it comes at about 1,100 BTU residue gas and that meets the spec requirements of the regional lines that our gas flows into. So, we don’t see ourselves in a must recover situation. We do have the opportunity or the right through MarkWest infrastructure to recover ethane if we need to and if we did, we put that into our ethane capacity on ATEX that goes to Belleview. Right now the ATEX capacity is being sublet to others that are in the must recover mode. But don’t see ourselves being in must recover for the foreseeable future. Dan Guffey - Stifel Nicolaus & Company: Okay, great. And then I’m curious just on well completion design, obviously 7,900 foot laterals, you guys continue to drill some of the longest wells in the basin and then also even incorporated SSL completion pretty much across the board. Wondering, I guess, what else you guys are doing to increase deficiencies, what else you guys are testing and if you see any upside from the current type curves that you guys have published?

Well, I’ve said this before, but I don’t think you ever reach perfection in completion design. Our folks, they’re not changing every single frac or every single well, but every six months or so there might be a little tweaking that seems to improve things. So we will see on the completion side what more can be added. Our standard SSL is 200 feet stage length in the Marcellus. We have piloted some 150s and we will see how that does over time. Dan Guffey - Stifel Nicolaus & Company: Okay. Thanks for all the color, guys.

Thank you.

Thank you. This concludes our question-and-answer session. I’d like to turn the conference back over to Mr. Kennedy for any closing remarks.

I want to thank everyone for participating in our conference call today. If you have any further 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 your lines.