Good morning, and welcome to the Antero Resources Third Quarter 2013 Investor Conference Call. [Operator Instructions] Please note that this event is being recorded. I would now like to turn the conference over to Mr. Michael Kennedy, Vice President, Finance. Please go ahead, sir.

Thanks, Sandy, and thanks to everyone for joining us for Antero's Third Quarter 2013 Investor Conference Call. We'll spend a few minutes going through the financial and operational highlights, and then we'll open it up to Q&A. I'd also like to direct you to the home page of our website at www.anteroresources.com, where we have updated our company presentation for our Q3 results. Before we go to 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 or 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, everyone, for joining us today. While we have been doing high-yield conference calls for about 4 years on a quarterly basis to operate our screen. This is really our first call as a -- the public company, so we appreciate you joining us, and we're very excited to report our results for the third quarter. Third quarter 2013 production of 566 million cubic feet a day equivalent increased 128% year-over-year and 25% quarter-over-quarter, sequentially. The production included approximately 7,900 barrels of liquids, which was also a significant increase as we did not produce any liquids in last year's third quarter. We didn't have processing last year, third quarter, and it was up 89% sequentially. Decompression results were dry from our transition in the Marcellus Shale BTU drawing and first production from our liquids-rich Utica area as well, which kicked off in August of this year. Paul will give a little bit more detail in a few moments. We saw our natural gas during the quarter at a $0.22 per Mcf premium to NYMEX. The $0.04 being the southern core of the Marcellus, which allows us to sell the majority of our gas with a TCO index price. TCO traded a $0.07 discount NYMEX in the quarter. Hard gas sold as a premium due to the high BTU content. The company has ethane rejection, so we did a nice pick up in price from leaving ethane in that stream. We also received attractive prices for our NGL barrel. Our NGL barrel is C3+, so propane-plus containing the ethane. This results in a much more valuable barrel, MS5 [ph], $50 a barrel for our NGL products this quarter, and that's been average, roughly, for the past year or so. Realized $47 million or $0.91 per Mcf just…

Thanks, Glen. During the third quarter, we ran 19 rigs in the Appalachian Basin. And we also ran an average of 4 frac spreads, so -- on the frac-ing side. They drilled and completed 44 wells. This firmly equated us as the most asset operator in the Marcellus, as we have the highest growth trajectory with a triple-digit continuous annual growth rate for the last 4 years. We've been at the last strategy is to pursue this rapid pace of development, and the answers is pretty simple. If we're generating the types of returns that the Appalachian Basin, of course, I'm talking about Marcellus and Utica, we're getting the types of returns that this yields, and we want to bring that value forward. Our rates of return at Marcellus range about 40% in the rich gas area to 90% in the highly rich condensate area. These rates of return do not factor in the SSL completions, and those appear to enhance these returns by approximately 15% to 25%, as Glen mentioned. In the Utica shale, we believe our rates of return range from approximately 100% in the rich gas area to over 200% in the highly rich condensate area. Obviously, with these types of returns, we wanted to develop as quickly as possible. Now, of course, in order to take care of our production and do what we have to do to be able to move what we have to be forward thinking versus we've jumped out, we have secured the rigs, we've secured the frac fleets, and -- but just as importantly, we want to make sure that we can get our product to market at the economic levels that we plan. We've done that not only by the hedge book that Glen has mentioned just now. And those…

[Operator Instructions] And our first question comes from Neal Dingmann of SunTrust.

Say, Paul -- I was wondering, for you and Glen, if you could talk a little bit, over in the Utica, you, obviously, had some outstanding test rates. Just if you could talk a little bit -- anything you could give us. I know your wells haven't been on a whole long time, but just how you see the 30-day and 120-day kind of rates on those wells that have been on for a little while, stacking up versus those initial test rates?

Well, we would say that the rates look encouraging, that we developed tight curves based -- before we started flowing our wells based on early test results of our own, as well as test rates of other people and what we could download from the state of Ohio, so develop some tight curves. And I'm pleased to say that now that we've got our wells online, they look like they've been formed at the tight curves, so pretty close to our expectations. And so these are, as you've seen in our press releases as well as others, these can be hellacious wells. The really high flow rate and quite strong pressure, they come in at about the BTUs that we have mapped. And so, the way we have the gas composition, they perform, of course, going through the plant to give us the liquids composition that we expect, so, so far so good.

Okay. And then touching the well cost, I know a couple of your earlier wells, I know you did some science and some things, so maybe -- we don't have to talk a little bit around that $12.3 million cost -- your thoughts on that going forward as you don't do as much science and run on a go-forward basis on the Utica wells?

Yes, well, we're always, of course, working to try and optimize. Early on, you're right. We've done a lot of R&D, I would say. We've done such things as pilot wells, where we drilled vertical, all the way down through to Utica and kind of core, and do testing capture certain gases in pressure chambers, so that we can work out their PVT relationships, pressure volume temperature, the phase relationships, so a lot of R&D early on. We are in an area where one must run 2 strings of pipes, so 2 intermediates, because of a certain -- a zone down the 67,000 foot range. So they have a little bit higher cost in this core part of the Utica than they may have up north. We'll we be able to get our cost down? Yes, I think so. How much will it be? Well, it remains to be seen. Can we take $1 million or $2 million off of it, I think that's a reasonable target, but time will tell.

Okay. And then last one, if I could. I know it's still early. Your thoughts on sort of optimal spacing or at least what you think you can maybe take some of these Utica wells down to, as well as I know you are testing, sounds like now one significant lateral that I know of. Just wondering your thoughts on different lateral lengths, what -- if you think you have an idea of what is optimal, you're still sort of testing that. So that and downspacing?

Yes, as far as lateral lengths, the Utica is even more smooth, I guess I would say more plainer than the Marcellus, virtually no ripples in it or anything. And so in terms of long laterals, we use a certain downhole tool, where we can make at least a couple of thousand feet a day in the lateral, the acre, auto track. And so we see that we can go quite long in the Utica. Right now, we've only gone in the mid 5s to mid 8s range of lateral feet, but we feel we can go quite a bit longer than that. There'll always be a little bit of a limit on frac-ing the tow and pressures required and so on. But in terms of that aspect of it, of course, our economics improve as we go longer, spreading that vertical across over more bcfs. So this advances, I expect to still be made on longer laterals. We've got a number of longer ones planned. In terms of interlateral distance, I think we're pretty comfortable with 1,000 foot in our lateral distance. And as we told the market, we've got 1 pilot, the Wayne pilot, where we drilled 3 wells at 500 foot inter lateral distance. Looks good so far, but it's still early, so I think we could say we're pretty comfortable with 1,000 foot, and we'll see about 500 foot. The locations that -- the number of locations that we talked about to the market is about 700 or so laterals that we have planned so far on our acreage, and that's all on 1,000 foot interlateral distance. But so far so good, maybe on tighter, but I think we feel pretty good about 1,000 foot.

Our next question comes from David Tameron of Wells Fargo.

Can you just talk about -- to hit your 2014 target, that 75%, can you talk about what you need to see happen as part of the midstream, whether that's processing or pipelines? Or I know it's not a simple answer, but what are the 3 or 4 big guideposts, I guess, that we should be looking for on this side?

You're talking about just specific infrastructure improvements that...

Yes, I guess what are the going to be the biggest hurdles to get the infrastructure in so you guys can execute on your plan in '14?

Well, the -- it's a handful of smaller projects in different parts of our Marcellus. And so it'll be compressor stations here, it'll be looping there, it'll be tabs in another spot. And so there's not really one big project, and -- though they get completed month by month. If they get delayed by weather or something else, then that can slow down our production. So it's -- but we feel pretty good about the major projects that we have, the firm transportation on the mainline and so on. It's really getting locally out of our field that can have some bumps in it. And we follow of course day-to-day and week-to-week. But that's the kind of thing we're looking at between now and 2014, going into the first and second quarters, compressor stations, low pressure, high pressure gathering, looping and tabs.

Okay. And then just stepping back, bigger picture for the industry as a whole, particularly, with regard to the Utica, what do you think the biggest hurdle is going to be on the takeaway capacity side, just if we look out 12 months or 18 months?

Well, the hurdles will be a few things. It'll be producers like ourselves giving compression and condensate stabilization put in ahead of the wells. It will be more processing, and so as we've described, we've got successive trains coming in at Seneca, but there's timelines on that. There are a number of parties going with either Tesco or some of the more local lines. And so one might be referring to Btu issues, we think that we and others are okay right now with BTU going into Tesco. There's been more of a move with Rex to bring dry gas over to Clarington to blend out into Tesco and solve that problem. So there's infrastructure projects up and down the line, again, from local to long term, but we don't see any barriers. There's discussion of Rex right now. It's backhauling, but by middle of next year, it could be forward hauling through the west, so producing ourselves. And others look at moving gas away from the region or in Chicago, the Midwest. So all those things take a little time, but there's no one big barrier that we see coming up through 2014. We think the infrastructure will keep pace of -- ahead of industry production.

Okay. That's helpful color. And just one final question, if you could address the potential for an MLP, I know you upsized the offering and have the debt deal done. Is that still on the table for '14? And if so, any color you care to give us on that?

Yes, it is very much so on the table. And those kinds of things take a lot of background work, and that's where we are now just preparing carve out, financials and those kinds of things and talking to various folks about the valuation and process and those kind of things, so I'd say we're still early stage but very much on the table for 2014.

Our next question comes from Hsulin Peng of Robert Baird.

I was wondering if you can give us an update on production constraints? I know last quarter you said there was a minimal amount of constrain, and it sounds like you're still waiting for some compressor in -- coming out in November? So where are you currently?

Yes, we have certainly seen some of those constraints come off and then production grow since the third quarter numbers that you see in the report there, so that's -- we're working through that, and we continue to have at least 100 million a day constrained in both areas. But those are quite methodical fixes, I think, as Paul is referring to. It's a compressor station in the Utica that we expect to be online by the end of this month. We'll have compression there for the first time, so we're still seeing some constraints because of that. We have some wells that are waiting on that particular compressor station, because they don't have the dehive[ph] on the pad. So once that compressor station's up and running along with the dehive [ph], then we'll be able to bring on the 6 wells that we're bringing right now in the Utica. So that's one key piece. And then over the Marcellus, we have a number of projects underway. Anything from -- anywhere from production to processing like Paul said, the third processing plant there. At Sherwood, should come online at least by year end this year. And we'll need that as we're bumping up against the full capacity of 400 million a day that's out there right now. So we continue to bring on wells, I think we're going to be bringing something like 20 wells between now and the year end between the 2 plays. So expect to see quite a bit of growth, but you need that infrastructure completed to actually see the incremental production growth.

Right, sounds good. And then second question, just a follow-up on your downspacing. So given that you have that one pilot testing in Utica, I was wondering if you have plenty to do more pilot in Utica? And also, are you testing downspacing in Marcellus?

We don't have any plans right now to do more of the 500-foot interlateral on Utica. Again, as I have said, that the wells are so young there and the infrastructure has partially curtailed us at the Utica, i.e. we're producing against big back pressure that we'd like to just see unconstrained production, so that we can dredge our curves, performance and evaluate the pilot project better. So there's certainly room to do plenty of that. And we have sticks out on the map where we can do it, but we haven't committed to another pilot yet. We just want to see the results of the first one. In terms of the Marcellus, much of what we developed is on 660-foot interlateral distance, but we have some areas where we try 1,000 foot or a 1,320 foot to observe, but we feel very good about our 660-foot interlateral distance. And our planning is virtually all 660 foot and feel good about that. We, of course, have 200 wells, some of which go back 40 years that are not 660-foot interlateral. And they definitely support the tight curves as we judge them and as K&M judges them too. So feel good that, that's a very good interlateral distance for us.

Okay. And then my last question, and I'll go back in the queue is the -- on the short stage lengths. Even the well performance, I was wondering how much production history do you think you need to -- before you update your EUR tight curve and also research bookings later on?

Well, the longest well, probably -- or the longest duration or production history of SSL wells that we have might be 4 months or so. I might remind people that we have that certain NGL line break due to a landslide coming out of the plant a couple of months ago. And so with that, that curtailed our production, we tried to preferentially flow our SSL's as best we could, but a little bit choppy. So we'd like to see probably another 6 months of -- now that the line has been repaired and that constrain has been removed, I'd like to see probably another 6 months and -- but we're looking at it every day and every week and comparing the tight curve, comparing the offset. And so, we are encouraged, but probably 6 months more.

Our next question comes from David Deckelbaum of KeyBanc.

My question is related to the ramps of 5 rigs now in the Utica. As you reconcile that with the amount of processing capacity, yet there isn't a play right now with -- having 350 by next year out of Seneca, is it fair to say that this would sort of be the max run rate until you get significantly more processing capacity, perhaps with -- even beyond the Seneca III expansion, now into Seneca IV 4 in '15, with 5 rigs. I guess, will there be any reason to accelerate beyond 5 rigs given the amount of infrastructure in place right now?

Well, one of the things -- 2 answers to that, David. One is that we're always looking at our production forecast of stacking processing against it to make sure that we have enough. Obviously, we don't want to have production that can't get processed. But what's a more limiting factor in putting more rigs into the Utica, just to reminder, that we've only been in the Utica for less than 2 years. And so our acreage position is pretty young there relative to the Marcellus. And so we've got groups that are doing lots of planning. But it takes the planning group time to work out where the pads can be, working with landowners, forming units where we pool the different tracks together to form big unit that we can drill long laterals. And then planning out where the gathering is going to be, the compression, the condensate stabilization. So it's -- it will just be pretty mature to put more rigs in and try to accelerate more. So that's why we're holding it -- the 5 rigs for the time being, and we'll just see how things unfold relative to production. But we do think that we are -- for everything that we foresee through 2014, we're ahead of the game on processing. And again, we don't think we're going to probably be stopping at Seneca III. There's -- more trainings that are under discussion, but we'll see where those go. So possibilities for more overtime, but we're just being prudent I think in designing our exploitation program to be realistic though, like all the things we need to do in advance.

Got you. And you -- sweeping over to the leasing side, you guys picked up the 3,000 additional acres or so this quarter in the Utica core. Was that new acreage, or are you guys just filling in the working interest? I know prior to this year, your working interest is around 70%. You guys seem to be drilling stuff at a much higher working interest, and I assume that we should expect that working interest, the leasehold level to increase overtime. I just wanted to get a sense if you're just kind of filling in your interest right now, or there's some other pieces that you're picking up along the way?

Well, it's a little bit of both, but I think you see that natural progression in what we've done for a number of years now in the Marcellus that we do in the Utica, which is we have quite a lamb staff that's working on these this things and we'll design a unit, get a pad, work out the lateral length and then we may have a relatively low working interest, say 65% or so in that unit as we put it on the map. But then our brokers and our land men build enough of a position that's mostly base leasing, sometimes it might be a trade, but mostly base leasing to add and move our working interest up. And so that's a pattern you see both in the Marcellus of the Utica that on day 1 that they're relatively lower interest, but we just keep building. I will say that our expectations for additional acreage in the Utica, it's gotten very tight. So we'll see how much we grow it. We would like to be able to grow it more, but in a lower pace maybe than the Marcellus'.

Then the last one I have. I know before you mentioned that basically you're going to use the shortest stage length completions, on effectively all of your completions going forward in the Marcellus for this year. And I assume that would be for 2014 as well. But would you still exclude, I guess, some of the dryer portion of the Marcellus from an SSL completion? Or are you going to be using SSL as sort of a blanket for the entire program?

Well, it might -- the reality is that in 2014 will be -- most of our rigs will have shifted -- and they pretty much already have less of the 1,100 BTU line. And maybe they'll all be over into the 1,150 concrete by then. So we -- but we wouldn't exclude doing SSLs over on the East side, on the dryer side. The point on a pilot basis. But as I say, our -- the amount of drilling we'll do over on the dryer side is definitely lower. We have through the last number of months had SSLs over on the dryer side, and they can make an impact as well. So we would drill that out, just to -- if you have an uptick x percent, so you get more molecules, those molecules are more valuable over on the Westside. So I think it's just a cautious approach to say whatever the bump is going to be, it's a more valuable bump and a higher rate of return bump when you're -- into more of the liquid side. So that's about the way our thinking goes.

But even on sort of like the 1,150 Btu when do -- and the Marcellus, we should be thinking entirely SSL for next year?

Probably, virtually. I don't have those numbers in front of us, but, yes. That's probably the case. But again, it's early. We may decide to shift back, and in some areas we want to do it, in some other areas, we try different techniques. So just want to be conservative, and so we need to see the production unconstrained for at least 6 months and see how we're doing.

Our next question comes from John Freeman of Raymond James.

I know that you alluded to -- you're going to draw your first dry gas West Virginia Utica well first half '14, do you have any plans to test upper Devonian next year?

No, we don't. We drilled our Upper Devonian for cat tests and have done pilots, and although those are reasonably good, they don't compete with the Marcellus. They are just not as strong, so they're scheduled for further out on the tail of our Marcellus plan. So if we have several thousand locations to drill at Marcellus, that's probably what the focus will be, and the Upper Devonians will probably be on that, probably.

Okay. And then you cited the average completed well cost in the Utica at $12.3 million. Can you give me a sense of kind of how much that could drop once these wells have access to the freshwater distribution system and you start to more aggressively move to pad drilling either over the next couple of years, kind of where that number can go?

Well, given a broad range or we have, maybe we could drop $1 million or $2 million off of it, $12 million plus cost. You're right, there's the water system, good rule of thumb for us, is it saves about $600,000 on a well that has a 7,000 foot lateral. If you go longer, then it pays more, if you do tighter stage lengths, tighter stage lengths to use more water, so proportionately, save more than that $600,000. But I think we can put our finger on that element. But talk about certain things like 2 strings of intermediate casing that are just a safe way to go -- a safer way to go to drill the rest of couple of strings, which requires bigger hole and bigger pipe. So we don't want to overpromise that we can shave many, many millions off. But we'll just take stepwise improvements, and see where we go there.

Our next question comes from David Beard of Iberia.

Would you mind talking as specific as you can a little bit about your completion thoughts and designs in the Utica, just relative to resting period and choke and how you open that up? Just give us a sense of how you're thinking about developing your wells.

Well, we -- the Utica, that's really -- the Point Pleasant is a little bit thicker than the Marcellus, the pay zones and little higher pressure. Our amount of water and sand per foot of completion is more in the Utica than it is at the Marcellus. But I think the way we're -- we're looking at things -- Glen, go ahead.

We're trying a lot of different things. And I think suffice it to say, it's going to take some time for all that to play out, to come up with a formulaic approach. And yes, we really see differences in the raw too and the performance as well as you move across the Btu regime. So I think it's hard to give a hard and fast answer on that.

Our next question comes from Adam Michael of Miller Tabak.

I was wondering if you could maybe comment a little bit on the shorter stage lateral length, the SSLs and how those might relate to the Utica? And maybe if you could compare what you're doing in the Marcellus versus what you're currently doing in the Utica on stage length?

Yes, our standard had been in the Marcellus 350 foot stage lengths, and we've gone down to 200. And then in R&D mode, we've even gone down to 150, but feel pretty good about that shortening from 350 to 200 as maybe approaching optimized. And because of -- as I was mentioning, it's thicker in the Utica, the Point Pleasant takes more both water and sand, so we have more to frac. We were already at shorter stage length, just our -- what we designed was more like 225 in the Utica. And now we're experimenting with as short as 175. So working those back and forth just to bear results.

And now our last question comes from Mark Lear of Credit Suisse.

Just overall, there's been concern out there regarding Northeast basis. Given all the growth, you guys and your peers are delivering, I know not a big ding to, what are some pretty big economics for you guys. We just wanted your thoughts on how you think your positioned regarding those risks?

Well, as we've said, we feel pretty good that our acreage is at the southern part of the Marcellus core. And so we have a little less infrastructure that's required to escape the logjam, which is really in Southwestern Pennsylvania, so we can tie into TCO to move away to the south and west towards the Gulf. And some of the other pipes, too. So I think we have a little bit of an advantage there that -- and we now are Colombia's, biggest customer, biggest firm shipper, so a lot of gas firm. And then we sell to a lot of firm shippers that are on those pipes at either a NYMEX or a TCO basis. And so if you look at the future's curve or a basis differentials, and we have that on our website in our presentation, TCO has had the mildest discount, I would say, to the NYMEX over time. It's in the negative, $0.05 roughly, to negative $0.35 range, whereas the others, whether its Tesco or simply the Northeast, by the hub. So is it widen by quite a bit more. So guess I would say, because of where we are, we're located in a spot that has advantages, but we work hard to stay ahead of a basis blowout. So we hedge a lot of basis, we have a lot of financial hedges that, of course, have basis rolled in, so they are TCO hedges. And then we have a lot of discussions, conversations underway with a lot of the long haul pipe builders to support new projects, to move away even more. I think we're in pretty good shape with the amount of FTE that we have to get away and move to places like the Gulf. So we have FTE that goes to Henry Louisiana, where we can hedge NYMEX. We have firm to Chicago where we can hedge a healthier basis, a Chicago basis. But that's where our effort is going to be. And so we've been out ahead of it. We intend to stay ahead of it to just mitigate basis risk by selling locally.

Then I just had one quick follow-up. Do you guys anticipate losing any ethane in 2014? And I guess would that be additive to your 2014 growth target, if so?

We don't anticipate. We -- of course, we as others, look at future's curve, as well as lots of research reports on demand for ethane. We have our list of crackers and so on, as well as others. Don't necessarily see the ethane prices changing, through 2014. And it's too more economic, of course, to leave the ethane in the stream. We don't believe we're going to have a gas quality issue that puts us into the category of must recover. But that's how we see it going forward, probably won't be recovering ethane.

[indiscernible] Mark, that we do see a whole lot of optionality on that. And if you take a few years further out, we did see some potential to extract ethane and sell it for a nice uptick over gas value.

This concludes our question-and-answer session. I would like to turn the conference back over to Mr. Kennedy for any closing remarks. Please go ahead, sir.

This concludes our Q3 conference call. If you have any further questions, please feel free to contact us. Thanks, again.

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