Good day, and welcome to the Antero Resources Fourth Quarter 2016 Earnings Call Presentation. 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 Mr. Michael Kennedy, Vice President of Finance and Head of Investor Relations. Please go ahead.

Thank you for joining us for Antero's fourth quarter and full-year 2016 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 provided a separate earnings call presentation that will be reviewed during today’s call. 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 will now turn the call over to Paul.

Thanks Mike, and thank you to everyone for listening to the call today. In my comments, I am going to first provide a recap of our consolidation efforts within the basin in 2016. Secondly, review our overall development program throughout the year including some of the key encouraging pad results. And then thirdly, discuss cost efficiencies that we achieved in 2016. Glen will then highlight our fourth quarter and full-year financial results including first of all, price realizations, secondly capital efficiency gains and thirdly EBITDAX margins. He will then provide a brief discussion on a couple of the recent NLG infrastructure announcements and the impact those announcements will have on our business. Lastly, he will touch on our long-term targets and outlook moving forward. First, let's discuss Antero's 2016 acquisition activity and our efforts to consolidate the Appalachian Basin. We are the most active operator in the basin. We have a strong balance sheet and the largest contiguous acreage position in the core of the Marcellus and the Utica. We are therefore extremely well positioned to be a leading consolidator in these two place. On Slide number two entitled, a leading consolidator in Appalachia, you can see the acreage we acquired in the Marcellus throughout 2016 highlighted in green which is shown in and amongst our existing acreage in yellow. In total we acquired approximately 74,000 net acreage in the core of the Marcellus and Utica shale place in 2016, including 64,000 net acreage in the Marcellus which is highlighted on the map. In addition to our consolidation efforts I would also like to take the opportunity to point out a number of notable pads where we implemented advanced completion techniques in 2016, and which are now delivering some strong EUR results. One of our recently completed pads that I…

Thanks Paul. Let me begin with some of the key highlights from the quarter end here production average of record 1.99 Bcfe per day or essentially 2 Bcfe a day for the quarter, a 6% quarter-over-quarter increase including nearly 87,000 barrels of liquids. Liquids production included 5,000 barrels a day of well, and just over 81,000 barrels per day of NLGs representing a 7% increase from the prior quarter as Antero remains the largest NLG producer in Appalachia. This production outperformance continues to be driven by operational improvements, particularly associated with the advanced completion that were implemented in 2106, which Paul touched on his remarks. Moving on realized pricing during the fourth quarter, we achieved outstanding results for both realized gas and liquids pricing. We realized a $0.07 premium to NYMEX Henry Hub or $3.05 dollars per Mcf of four hedges on our gas production during the quarter, which was $0.52 higher than our next closest peer and $0.78 per Mcf higher than the peer average. This further validates the strategic advantage of our extensive firm transportation portfolio enabling us to move firstly all of our gas away from unfavorable local Appalachian industries. In fact, for full-year 2016, we were able to achieve a $0.04 for Mcf premium to NYMEX Henry Hub, which was at the higher end of our guidance of neutral to $0.05 premium. We realized a natural gas hedge gain of $187 million during the fourth quarter $1.38 per Mcf of gas produce and $957 million for the full-year or $1.89 per Mcf of gas produced during the year. Moving forward we believe our firm transport and hedge will continue to be competitive advantages for Antero as uncertainty around both northeast basis differentials and overall gas pricing is likely to be continue. As a reminder, for 2017…

We will now begin the question-and-answer session. [Operator Instructions] And the first question is from Neal Dingmann with SunTrust. Please go ahead.

Good morning guys. Say particular up to and dig in on that 10 well pad, Marcellus pad, you all mentioned to have that exceptional 1.7 either cash-on-cash, you mentioned on the longer laterals in the San. I guess I’m just wondering on that or in that area location wise, is there still - I mean if you kind of give me some color, is there a lot of acreage that kind of fits that parameters on those 9,000 to 11,000 foot laterals and then kind of in that same vicinity?

Hi, Neal. Yes absolutely, there is a lot of lateral locations to there, we are pretty solid yellow for many miles and it fits in terms of BTU yield and pressure. So it should have many, many more locations like that there.

And then on those, you mentioned kind of with that cash-on-cash, does that assume some inflation on there and is that the well that you have locked in about 70% of your cost, in order to achieve that that’s the nominal cash-on-cash payout?

Yes, I means that cash-on-cash payout is the - that’s specific to that pads to so those cost already are standard costs, but we do not have any acceleration built into our service cost in the budget for this year. We can hit on that in greater detail if you like. But we have 90% of our drilling rigs and completion crews under contract this year, and about two-thirds in 2018. You can see that on Slide 20 and our website presentation for March. And within those completion contracts we were concerned about sand cost and all. We have escalators built in there, but they are tied with things like PPI and CPI and labor indices and some of the sand contracts have in oil index escalator if oil prices go up. But other than that, we are not going to be subject to spots sand prices with those completion crews. It's pretty well time now to various indices. So for that reason, we haven't built and escalation and service cost into our budget for this year; plus we seeing a lots of efficiencies continue in both the Marcellus and the Utica as you could see, we don’t think that’s going to stop and sort of thirdly the EURs are continuing to improve as well. So we are pretty comfortable with that. We didn’t chase the service cost down last year by lowering our budget, we use sort of our contracted numbers in our AFEs.

And then the last one if I could, just on the NGLs, you guys are doing obviously phenomenal job with the realization there, what is the hedge market a year or two, three out, has that market become much more fluid than it once was? Are you able to continue locking these great realization, I guess what I am asking?

Yes, the hedge market is there or at least two maybe three years out. One can hedge ethane, propane and butanes and if one wants to butane is a little less liquid. I will emphasis in term of our presentation, we blend in the gas and the liquids hedges together and then it comes out to 60% or so. But in reality the detail is that we are 100% hedge down gas and quite un-hedged on all of our liquids. We are about 75% hedge this year on propane and then un-hedged for Cal 18 and beyond and the same would be other products. So yes, there are markets out there where we can hedge and we will be adding hedges, but right now we see upside in liquids, we see it because of increasing demand as well as improving infrastructure. So we will be hedging as we go through time, but we are quite well exposed to the upside that we are seeing in liquids.

Very good, Paul, Glen, thanks. Great quarter.

Thank you, Neal.

Our next question comes from David Deckelbaum with KeyBanc. Please go ahead.

Good morning, everyone. Thanks, Paul and Glen for taking my questions.

Hi, David.

I was just curious to ask just to ask and I guess can you guys give us some color on how you are thinking about ramping your volumes for Rover and I kind of you split out that you guys have allocated right now in the Utica for sort of dry locations versus rich gas which seems to be more rich gas oriented now, which imagine more IRR driven. Is there any thought around little bit more aggressive activity in the [dry] (Ph) gas window, the Utica and preparation for sort of Rover startup?

Yes, we are definitely of course looking forward to the Rover startup, the announced date is July and so we are prepared to begin filling as soon as it opens, we might risk that a little bit or at least we are prepared and opens later, but expected to be there in July. We do have a pretty good split between Utica dry gas and Marcellus rich. At the current times, the Marcellus rich gas does have better economics than the Utica that we are making great progress on that Utica drive really getting the well cost down there. We will be juggling back and forth our CapEx budget between each of the place, but as we are rapidly building out our processing complex it sure would, but do have to tie in capital spending on the Marcellus side, tie that all into liquids infrastructure too. So there will be some adjusting back and forth for Rover, but it needs to match all of our other FT and processing.

Appreciate that. And I guess my other question is, you guys highlight sort of the excess cash that anticipate generating your fairly highly hedged obviously quite a number of years now, so it’s fair to say looks like the program is well cover. Should we be thinking about the uses of excess cash in you are sort of long-term program that continue consolidating the Appalachian area or are you starting to look outside the basin just given that you kind of highlight that you have I guess 40%, 50% sort of the undrilled locations in the liquids rich core there?

Yes, consolidation is certainly filling our minds and we will continue to consolidate and so that’s one you just have the cash this anything significant there we think beyond just certainly cash flow, but the other notice we are talking about consolidated cash flow from operations relative to DMC and we are pretty well covered there, but we do have other spending along the lines with midstream spending, because we have given you a consolidated number there. So not completely at the point of showing free cash flow yet over the next few years. We will be continuing to invest in the midstream business.

All right. Thanks guys.

Thank you.

Thank you.

Our next question comes from Holly Stewart with Scotia Howard Weil. Please go ahead.

Good morning gentlemen. Maybe taking through Slide 10 a little bit, with just the C3+ uplift maybe taking a step further. What your thoughts right now on I think extraction versus rejection? And then what are your constrains there, if any I see the ethane guidance for 2017?

Well, if you look at our 3P reserves we have got well over 1 billion barrels of ethane and so we have a lot. We will be supporting local markets, we have talked about that crackers and such, but right now we are recovering in the low to mid 20,000 barrel a day range of ethane and then the rest we are rejecting leading in the stream, just because of the ethane economics. All-in so not some cost, but if for new cost new tariffs and so on, we need to be in the mid 30s and ethane $0.35 plus a gallon in order to pay extract the ethane and ship it to Belvieu. And right now the future's curve does begin to go out there, in the near-term, it's $0.28, $0.29 a gallon and kicks out into the $0.34 range. So we are seeing some uplift there and getting close what we have been doing is as I say leaving it in the stream as we supply to crackers and the export those have a mix of gas plus and upside of Belvieu upside. So get pretty good prices that are a little bit different than just a straight extraction tariff and sell at Belvieu. So we will be extracting more. Our [indiscernible] right now at Sherwood is for 40,000 barrels a day. MarkWest will build another one for us another 20,000 barrel a day at least as we go forward, as we prepare for some of the markets, local markets as well as the good at Mariner East 2 is that we will be exporting ethane to Borealis as soon as that opens for another 11,000 barrels a day and we will be open for business there on ethane for more international exports and again that pricing structure is such that it does pay to recover and we did a good flow or plus and upside as liquids rise.

Perfect, and then Paul maybe a follow up to that, it's sound like ME 2 is at least - or ME 2X is at least going to move forward at this point, any thoughts on that commitment to that project at this time?

Well, we are of course leased that ME 2 is going forward and we believe that it will be in service by the fall, we are glad ME 2X can go forward as well and that just opens up opportunities for us. We haven't thought yet about committing more to ME 2X, but we certainly would with the right pricing and the right international markets developing.

Okay. And then maybe just a quick modeling one if I could, any lumpiness to think about in terms of the quarterly production volume cadence?

No, I think it should be fairly steady throughout the year Holly, we expect to see continuing ramp up, I wouldn’t say would be particularly lumpy I think it’s fairly steady completion schedule throughout the year. We are watching Rover closely and I think once see the space in the ground, we may want to accelerate some of the DUCs that we are going to carry in the Utica into next year. We are planning to finish this year with about 30 DUCs expecting Rover to potentially be into 2018. So I think if that does come to fruition and they are actually plain pipe and then you may see some acceleration there of DUCs bringing more completions into the third and fourth quarter in the Utica. But that’s the only thing I could think of right now, it’s pretty steady.

Okay. That’s helpful. Thank you, guys.

Thank you.

And our next question is from James Sullivan with Alembic Global. Please go ahead.

Hey, good morning, guys. Thanks for taking the questions. If I could just ask you a little bit again prime marketing on your marketing guidance, once you guys see the ET is space in the ground for Rover, do you guys had a plan for certainly up that in our segment that you guys target to pick back up from them and is that any anticipated increase marketing expense in the guidance there?

Yes, so as Rover and something expansions go into the Michigan, Chicago area. So that would be Rover and others that goes to defiance, if there is a the ANR capacity is by directional and so if prices are better in the Gulf then we will be able to move our gas as well as excess gas any build up in the Michigan and Chicago markets to the Gulf, so that will be the early stage and then as we fill up Rover ourselves and expect to probably move that down ANR and capture any premium in the Gulf and also just supply the LNG projects that we are producers for such as [indiscernible].

Okay. So the idea would be that taking that FT from the Rover team there, you would be able to pick up I mean excess cash just pick it up from mid last rather from Appalachia?

Yes, that’s right. That ANR goes from or from REX Zone 3 from Shelby, Indiana and also the defiance it goes south to the Gulf. So that would be third-party plus Antero gas. And yes we will contractually energy transfer turns that back over to us as it becomes in service to the Seneca complex in Ohio.

And then lastly, could you guys just going back to the liquids for a second, could you comment on kind of any particular market strength in the Northeast for a propane and to what extent that impacted your obviously impressive C3+ realization that you had in the quarter. And any sense do you guys have durable that [indiscernible].

I think the demand in the North East is fairly steady that the local demand and rail rates have come down quite a bit which has helped us differential for railing products in the interim between now and the startup of ME 2. But once ME 2 comes online, you have quite a take away option there, they are going to have 275,000 barrels a day of capacity on that pie go into market so that can enabling export there. So we feel pretty good about that whole scenario that’s why we are bullish on raising the guidance for this year for our NGL pricing relative to WTI.

Okay great. And then if I could squeeze one in here, do you guys have any color or any updates on year-over-year assessment of the demand for the end markets perhaps for LPG [indiscernible] for the conversations like in those guidance in terms of looking for more of a score volumes?

Jim, I heard your question right, that was the outlook on the LPG markets is strong, it's booming, and so we will be able to - we have capacity that we can use on Mariner, it's penciled then as propane but it is both propane and butane technically and it can be a mix and it can be made to at the right combinations to serve the different LPG markets in the Atlantic basin. So that is really emerging as another demand source out of markets look. And so we think that has a bright outlook.

Great thank you guys. Appreciate it.

Thank you.

Our next question is from Brian Singer with Goldman Sachs. Please go ahead.

Thank you good morning.

Hi, Brian.

Hi, Brian.

My first is follow-up on with regards to one of the earlier questions here, when we think about the productivity gains, the potentials to cost inflation and pipeline and associate tariff coming on, how do you think about your operating costs per Mcfe over the next couple of years, less so in 2017, but just more what is that trajectory is, given the visibility of production in some of these tariffs?

Yes, we have already got in service quite a bit of our FT portfolio, so we don’t expect a large increase in the flow through from FT to operating cost. But I mean it goes up by a few penny over the next few years. So not significant.

Got it, okay thanks and then on the completion front, you continue to highlight the increases in profit loading, can you talk more about your expectations for EURs for the 2,500 pounds per foot, lateral that the relationship that you see between profit loading EUR and where is that all of you see constraints profit loading wise?

That’s a good question Brian and that is why we are running the pilots, we are not sure where the break over point of diminishing returns will be. We are very early in the 2,500 pound, the expectation of course would be that it's better than the 2,000 pound, but we don’t know yet. So expect to have good results that we should see and even we will have to see initial rates and then watch the curves overtime. We are pretty conservative and we will be watching to see if it's were the extra effort. We think it will work, we think it will be good, and that’s why we want to do it early while we still have 3000 or 4000 more locations to drill just to figure it out on the early end, but it is early.

Thanks and you may have said this already, but what is the incremental costs for the 2,500 versus the 2,000.

Not much, less than 10% per say.

Got it. Thank you.

Yes, thanks, Brian.

And our next question is a follow-up from David Deckelbaum with KeyBanc. Please go ahead.

Hi, David.

Thanks, guys. Sorry to hop back in here with one more. But just wanted to just ask about, at least in the press release you guys discussed that a portion of your wells in the Utica are going to be on existing pads this year. I wanted to ask sort of the pointing that out in the press release is that more of an indication your cycle times in the Utica should be relatively compressed this year this of is this sort of a new strategy to test kind of reentering existing pads across Appalachia and leverage some of the costs that you have kind of already sunk in there?

Well, I think maybe it signals through, but it especially just reflects the fact that these are big pads and typically when we get out of pad we will have four or five wells going in one direction in kind of a pitchfork pattern. And we will move off just because of that cycle time I think 180 days are more to drill and to complete and so the sales delay is a little bit of an affecting there. So we come and we build the pad, we drill them all in one direction, frac them out, put them online and then come back at a later date maybe a year later and get on the same pad and drill on the other direction. And so it’s just away to reduce the cycle time and so I think you think it will reflect it will have shorter cycle times in the future when we go back to existing pads that it’s much more quick in and out and the infrastructure is there. We do have plenty of pads where we have just drilled pitchfork in one direction and can come back and drill on the other direction. So we have been saving these and these definitely fit into our drilling schedule.

But and to follow-on to that David, I mean when you are drilling $10 million to $15 million kind of MPV wells then that doesn’t really move the needle a whole lot, it’s really more about where you have infrastructure and what are the best locations to drill.

Got it. So this is more kind of a coincident of the Utica program, which I guess will start to showing up I guess in the Marcellus program overtime.

It’s true and one more add on that to what Glen just said our typical compressor stations might be 120 million, 160 million a day and you can see when you bring on pads you max out the compression just with the pitchfork in one direction. So part of the coming in and then moving of a pad half way through it is to fit the infrastructure.

Thanks for taking the follow-up guys.

Thank you.

This concludes our question-and-answer session. I would like to turn the conference back over to Michael Kennedy for any closing remarks.

Thank you for participating in today’s conference call. 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.