Good day. And welcome to the Antero Resources Year End and Fourth Quarter 2013 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 note this event is being recorded. I would now like to turn the conference over to Mike Kennedy, Vice President of Finance. Please go ahead.

Thank you for joining us for Antero's fourth quarter 2013 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 fourth 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.

Thanks Mike. And thank you to everyone for joining us today for the call. Fourth quarter 2013, net daily production increased quite dramatically to $678 million cubic feet equivalent per day on a net basis that was up 115% year-over-year and 20% sequentially. The production included approximately 11,200 barrels a day of liquids that's up 42% sequentially and really up from nil the prior year because our first processing came online in late 2012. So a very dramatic step-up there at 11,200 barrels a day in the quarter. This liquids growth was achieved despite couple of delays, we had two major delays in compression facilities – new compression facilities in the Utica, and then we disclosed just recently that that first compressor session came on in late January in the second –should come on now by the end of the quarter, early in the second quarter. We sold our natural gas during the quarter at $0.19 per Mcf premium to NYMEX and that's very important relative to some of the disclosures that you have seen by some of the operators in the play taking quite a hit to NYMEX. So we have been well-positioned in that respect and part of that is the fact that we are selling higher BTU gas at the tailgate of our plants. We are fortunate to be in the Southwester core of the Marcellus in Northwestern West Virginia. And that allows us to sell majority of our gas at the TCO index price, at least historically. TCO traded at a $0.04 that's $0.04 per Mcf discount to NYMEX for the quarter for the fourth quarter, but our gas sold at a premium due to the high BTU content, as I mentioned. We are currently in ethane rejection, so we get a nice pick-up from leaving…

Thanks Glen. In my comments today I'm going to address a couple of our recent developments. Glen has already covered the financials and the 2014 guidance, so I'm going to focus on our year end 2013 reserves and Q4 operational update. We had excellent reserve growth during the year, our proved reserves increased 78% during the year to 7.6 Tcfe although only 23% of our total 450,000 net acres had proved reserves associated with it at year end 2013. So we do have a lot of growth ahead of us. All sources finding and development costs, including acreage costs were $0.58 per Mcfe and we had development costs of $1.14 per Mcfe, both of these costs are best-in-class for the industry and when compared to the 339 per Mcfe EBITDAX margin Glen talked about a little bit earlier, we generated results that are best in class recycle ratios. Marcellus shale accounted for 95% of our proved reserve volumes, but the remainder attributed to the Utica shale. We were able to add 3.7 Tcf equivalent of proved reserves to increase the total proved reserves to 7.2 Tcfe in the Marcellus this year. And importantly 1.1 Tcfe of that addition was in the proved developed category as we completed some 113 wells in the Marcellus during the year. Just to talk about the percentages for a moment, we are now at 27% PDP out of total proved, up from 22% last year. When you look at the 1.1 Tcfe of PDP addition on those 113 wells, that computes to an EUR per well up 10.6 Bcf that we drilled during the year or 1.5 Bcf per 1000 feet of lateral. Now although that's prolific EUR per well and very respectable results, during the year, we shifted over to shorter stage length, SSLs…

[Operator Instructions] Our first question comes from Neal Dingmann with SunTrust. Please go ahead.

Good morning, guys, say going to Paul, just a question obviously great news about all the capacity coming on with Seneca, just wondering based on all that capacity coming on your thoughts, is that just enough to handle the – sort of the current plan with the five rigs running, or is there anticipation of may be perhaps adding some rigs there. Just want to know what you're planning out.

Yes. Neal, hi, there is a plan to continue to add rigs and I think over the next several years you'll see us grow that rig count to five rigs to eight or nine rigs, anyway over the next several years.

Okay. And then around the same area in Utica what's the status these days, I know for a little while you had a bit of compression issue didn't seem to be much of an impact these days your thoughts on the – going on the compression?

In Utica the -- yes, we are getting fairly full up again here during the month of March coming month, but we're expecting that second compressor stations to come on either end of March or early April. So we feel like it should match pretty well and then we have a third station that should come on this summer getting us up to that full capacity. And of course, we have further stations planned out into the future later in the year, but those are the three critical ones and one is on now so that's good news.

Okay. And then Paul, you mentioned about perhaps drilling a dry gas Utica well in that, I guess West Virginia or PA area second half this year, your thoughts if that's successful would that sort of change your thoughts about drilling those up or you will just kind of because of how positive economics the Marcellus is will you sort of stay the course there?

Probably more of the later, Neal. So it will be in West Virginia, and we have some 130,000 acres of deep rights under our Marcellus position over that we think our perspective for the deep Utica for the dry gas play. So I think it remains to be seen just how strong it is and whether it can compete with Marcellus rich and Utica rich, if it can then we may change our minds. But right now we're expecting to be still good rates of return for the deep Utica drive, but not as strong as the liquid. So if it works out the way we would expect then well we'll just have to see, but probably the liquid side will still take preference.

Okay. And then lastly, just on the Marcellus pretty evident, how economic these returns are. Are you still toying with expanding some laterals, I know there are some others around you that have done 9,000, 10,000 foot laterals in some of these Marcellus areas? Your thoughts on maybe just the frac and lateral design there?

Yes. I guess that we probably drilled the longest in the Marcellus as well the Utica. We've gone out changing the subject slightly but to 11,600 feet in the Utica and to about 10,800 in the Marcellus and have a lot planned in that range. So we feel pretty good going out to roughly 11,000 feet in the Marcellus, have a fair amount of those scheduled. And the ones that we'd done so far that are above 10,000 are good results we're not seeing that we can't frac the toes or anything like that. So its, we've got a pretty elaborate design of all the units already in place and pads that have been available, so that governs to some extent the length of our laterals, but I don't think we'd hesitate going out into that 10,000 foot range as the need arises.

Okay. Very good. Great results guys.

Thank you.

The next question comes from David Beard with Iberia. Please go ahead.

Good morning, gentlemen. Would you care to share any exit rates of production this year, so far this year?

Good morning, David. No, we're going to stay away from that for now just stay with our guidance.

I absolutely understand. And how about timing of all the wells behind pipe whether they will be all tied in this quarter or next quarter can you give me any color there?

Yes. I think 80 something wells that we have that are in various stages of development some of those are just drilling with the current rig count 20 rigs. So the vast majority of those will be on by the end of the second quarter, but we're pad drilling and up to four or five wells on a pad, so some of that takes quite a bit of time. So it depends on what stage you're in with each one so.

Okay. No, that's helpful. And lastly, could you give us some color on, I know you've given total guidance on liquids but maybe the mix from liquids out of the Marcellus and the Utica and how we should expect that to shift over time?

Yes. The liquids certainly see a higher percentage in the Utica. So we're tending to drill on average more richer wells that tend to yield more liquids. But, I think a good kind of mix overall is kind of 85, 15 between NGLs and oil as a company.

Okay. That's helpful. I appreciate the time. Thank you.

Thank you.

[Operator Instructions] As we have no further questions, this concludes our question-and-answer session. I would like to turn the conference back over to Mike Kennedy for any closing remarks.

Sure. This concludes our conference call. And I want to thank everyone for participating in it. And if there are any further questions please feel free to contact us. Thanks again.

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