Good day and welcome to the Antero Resources Year End 2014 Earnings Conference Call and Webcast. All participants will be in listen-only mode. [Operator Instructions] Please note this event is being recorded. I would now like to turn the conference over to Michael Kennedy. Please go ahead.

Thank you for joining us for Antero’s fourth quarter 2014 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 in today’s call. These materials along with the updated company presentation can be located on the homepage of our website. 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.

Thank you, Mike and thank you to everyone for listening to the call today. In my comments, I am going to highlight the recently released 2015 capital budget and guidance, provide a review of fourth quarter price realizations and expectations going forward, including our substantial hedge portfolio and cover our fourth quarter financial results. Paul will then review our 2014 development program by highlighting our low F&D cost and significant resource base, briefly discuss service cost in the current commodity price environment, and summarize operational goals for the quarter. Lastly, during our comments, both Paul and I will periodically refer you to a handful of slides that are located in a separate conference call presentation on the homepage of our website entitled Fourth Quarter 2014 Earnings Call Presentation. This is separate from our monthly investor presentation also located on our website. So, please make sure you are reviewing the correct slide deck during the call. Before we get in today’s topics, I just wanted to briefly revisit Antero Midstream IPO that happened in November 2014 just a few months ago. This was a very strategic transaction for us as it generated $1.1 billion in total net proceeds, with $843 million of those proceeds pushed up to AR to Antero Resources and $250 million remaining as cash on the balance sheet for AM, obviously, a significant de-leveraging event for us. The IPO was also instrumental in unlocking incremental value previously held at AR. As of yesterday’s close, AM’s equity value of $3.9 billion implies a $10 per share value associated with AR’s 70% ownership in AM. Additionally, the AM IPO will enable us to take on even more midstream projects in the Marcellus and Utica since AM will be self funding going forward. Now, on to our prepared comments, as you…

Thanks Glen. In my comments today, I am going to review our 2014 development program highlighting our significant resource base and its low development cost nature. I will provide a brief update on service costs and discuss operational results for the quarter. We executed our 2014 development program ahead of the plan, as production and reserve adds were both excellent. Our production for 2014 averaged 1.007 Bcfe per day, which was in excess of our original guidance of 950 million cubic feet equivalent per day and slightly above the increased guidance of 1.0 Bcfe per day. Our proved reserves also were ahead of expectations. As SSL completions improved our recoveries. The most important development of 2014 was the validation of SSL completions in highly rich gas areas of the Marcellus where we had limited development prior to this last year. This is especially important in low gas price environment as the liquids drive well economics even with low oil and NGL prices. As shown on Slide #4 titled Marcellus development program target the liquids, the success of our 2014 liquids development program has carried forward into the 2015 development plan, and we are forecasting the completion of 80 liquids-rich locations that have an average heating content of 1,250 BTU. The 2015 drilling program is shown in red on the slide. The impact of the 2014 development program can also be seen in our outstanding reserve growth for the year. Our proved reserves grew 66% during the year to 12.7 Tcf equivalent and only 29% of our total 543,000 net acres had proved reserves associated with it at year end 2014. So, we have a lot of growth ahead of us in proved reserves. All sources, finding and development costs, including acreage costs, were $0.61 per Mcfe and we have bottoms-up…

Thank you. [Operator Instructions] The first question comes from Neal Dingmann with SunTrust.

Good morning guys. Just a couple of two questions. One, just looking at that slide where you guys really lay out your – I think you call it the realized price roadmap, your thoughts on, I guess beyond ‘17, I mean, you certainly have a large amount that’s obviously covered there. Two questions, one, if you were to go and add some of this type of takeaway today, either obviously you have the expanding amount in the Chicago market and especially in the Gulf Coast market. I guess my first question is what would that kind of FT cost you today? And my second question to go with that is, I forget how much do you have excess FT today that you are able to continue to market?

Yes. Neal, it’s Paul here. Well, I would say it depends on which FTE there is we have lots of different segments as you know these segments add up to a little over 4 Bcf a day, as they all come on if you few measure it in 2018. So have a lot of pipes going to different areas. You know from our story that we were able to get in early on so many of these pipes and so the early FTE some of it was very inexpensive. It was exchange agreements, it was compression adds, it was reversals and then now we are more on to new builds. As you know more than half of our FTE goes to the Gulf through various conduit, so out of that 4 Bcf a day about 2 Bcf goes to the Gulf. I guess I would just say that there are new expansions coming on with higher prices on various pipes, Rex would be one going West towards Chicago, Colombia would be another going South towards the Gulf. So there is various ones, will we participate, yes in some, less so in others. The new Rover pipeline we think is a good project and pretty reasonable. So I know that doesn’t give you firm numbers, but it’s definitely most of the new projects are much higher than where we are.

That’s very good. Thanks. And then just one second one if I could, looking to the slides that describing really talk about that massive Utica dry gas position you have in addition to your others I guess now and you mentioned I think in one of the slides, now all the operators would have seen some significant wells there and I know you guys are drilling just your thoughts on sort of how fluid your drilling plan is based on the well results, I mean obviously there is again I am looking at that slide that shows the returns between kind of the highly rich gas and the rich gas versus the dry gas and I am just wondering if you all could comment how you think those three will differ kind of going forward or based on the well results you are seeing so far you feel pretty comfortable with the economics of all three of those and how different that plan could be?

Well our focus is on the liquids rich drilling as we have emphasized in this call and elsewhere. So that’s liquids rich in the Utica, liquids rich in the Marcellus. We have quite a good handle on the dry gas in the Marcellus. We have drilled a lot of wells there, more than 150 wells over on the dry side and they are very good EURs per lateral foot, but they are just not as strong compared to the ones that give us the liquids rich premium. So feel quite knowledgeable about those, also feel good about the deep dry Utica we have in some of our slides, that we not only have down dry Utica in Ohio, which we have a good position. But underlying our Marcellus acreage, we have at least 160,000 acres of deep rights over in the Northwest corner that look highly prospective for the deep dry Utica. As you know there has been a number of tests that are quite impressive along the Ohio River on both states in West Virginia and Ohio probably the closest certainly the closest to our acreage is the Magnum Hunter well that had very impressive rates, very strong bottom hole pressure, big flow rates and it didn’t require that much drawdown of the reservoir to pull that much gas out. So like our 160,000 acres of deep rights throughout that Northwest Marcellus. But when would we shift gears to develop that, you have to consider again the gathering infrastructure and the gathering infrastructure that we have built throughout that area, and that we plan on continuing to build this all designed for rich gas. We collect the rich gas. We bring it to the plants and extract the liquids. And so you wouldn’t want to put the deep dry gas into that. So it will require some infrastructure. Right now the takeaway on deep dry gas is not as favorable, but by the end of ‘16 to mid-2017, the Rover project comes on of which we have 800 million a day of firm. And so that goes right through our deep Utica dry gas fairway. So, I think probably between now and then, our focus is going to stay on the rich gas where we do some deeper dry gas once the Rover line comes on, so we can go directly into that line and into favorable markets. It’s quite possible. I don’t think we will be shifting over our entire program, but we may work some of that in. So, that’s how we are thinking about it, focus on the liquids in both the Marcellus and the Utica, but like long-term potential of the deeper dry Utica play.

That’s very helpful. Thank you.

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

Hi, guys. Thanks for the comprehensive update. Just curious where your 500 to 750 foot drilling pilot is located, I guess, how many are expected in 2015? And what do you believe the optimum spacing will be across your various acreage windows.

Well – so we have done we are talking about the Utica. And so, everything we have – when we talk about our resource, we talk about 1,000 foot interlateral distance. When we talk about our proved undeveloped, that’s all on 1000 foot interlateral distance. We have conducted pilots on 500 and 750s. The results I would say are encouraging, but too soon to tell. And so naturally the PDPs on 500s and 750s are booked on that interlateral distance, but everything else is on 1000s. And so where within the Utica, it’s within the rich, the highly rich and the liquids trends. So, we are spread across the different BTU regimes. And so we get a feel in all of them as to how that can work, but I think the very solid that we naturally feel are the lowest risk are just the 1000 foot interlateral and then we will just see through the course of this year how the others perform.

How about over in West Virginia?

In West Virginia, we have moved towards 660s on everything that we do. There is still some areas where we haven’t demonstrated the 660s yet over on the far west side kind of the Southwest side of our acreage block. But it’s less than 10% of our total that is still on 1000s. So, everything else is on 660s and certainly supported by the well performance.

Okay, great. The $150 million land budget, I guess, how much of this is lease extension and how much of this will be targeting new acreage?

It’s almost all new acreage. There is very – the lease extensions are within the core of our block and those values are very reasonable, so much of it is new leasing.

So, any acreage expirations in the coming year or two kind of outside on the fringe area, outside of the core?

No, there is really not. We are in such a good position. I think more than 60% of our Marcellus is HBP and so much of the rest is either 5 plus or 5 plus 5, 10 year. So, we have yet in all of our drilling in either play had to drill any wells to hold acreage and don’t foresee that happening.

Okay, great. And then I guess one last one from me, you guys touched on how your well completion designs have changed over the past year, but I am wondering if you could discuss any expected changes or anything you are currently testing to further optimize well performance in both the Marcellus and Utica?

Well, I think we have said it before that I don’t know if you ever reach perfection on frac techniques. So, we are always judging and conducting pilots, but we have gone of course we and the rest of industry towards shorter stage length and the stage length that we model and that we believe feel good about is 200-foot stage length in the Marcellus and 175 in the Utica. We have gone tighter in the Marcellus. So, we have a number of pilots on 150-foot interlateral distance, but it’s too soon to tell as to whether you come out ahead. What you would expect is you will get higher recoveries, but it’s higher cost and so time will tell. So, still have that working for a little shorter yet, but feel very good with the 200s and that’s what we go with as the standard formula or recipe across all of the Marcellus with just these pilots as I mentioned. Feel good about the 175-foot stage length in the Utica and that’s probably where we will stay for a while.

Okay, thanks for all the detail guys. Appreciate it.

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

Good morning. Thanks for taking my questions. Given the continued volatility in commodity prices here, seeing distress from increase across industry, how do you think about the opportunity to consolidate acreage above and beyond the typical leasing program in either play?

Those opportunities are certainly out there. We have got an active land machine and so we look at things all the time. There are bite-sized things that we are always doing that are probably not that significant to mention, but plenty of takeouts of smaller players, just the smaller independents, where we will lease their deep rights or take them out entirely. So, plenty of distressed companies out there in the industry these days and so our basins, the Appalachian basin is no stranger to that, we are somewhat distressed, but we really don’t have anything on the planning horizon that we are going to jump back yet. I think we all know that we are only 12 weeks into the big commodity down cycle. So, there is time and we will be patient.

Okay. And then on cost savings, are you able to quantify how much is baked into the budget at this point and do you have any targets for savings incremental to 10% that you mentioned earlier?

Well, I think we mentioned we feel good in that 6% range is what we have baked into the budget and feel that 10% reduction is very reasonable. We have a lot of respect for our contractors. They have been with us for a long time. And so discussions have been under way. They understand the issues. And so there is definitely room for more and have good response from our contractors. They want to continue with the working of their equipment. The most straightforward thing to have a reduction on is labor and so that comes fairly readily and then raw materials whether it’s gravel for a location or sand for fracking, those are the next to come in a little bit. It’s the ones that where we have contracted with rig companies or frac companies. We obviously respect our contracts. And so we are working with our contractors. Sometimes there is a restructuring of them, but that those folks are making payments to the bank and so the reductions are a little harder in coming. So, we are respectful of that, but working with the contractors can we manage the reduction up to, I don’t know maybe high side is 20%, it’s possible and it will be higher in some aspects as I mentioned like labor or materials and lower in other parts. So, still a program underway and I think many would realize if you have a contract, the reduction on a rig is one thing. If you were to go out and pickup a new rig, the reduction would be quite a bit more that the day rates on contracted rigs are quite a bit lower. So, there will be a managing down of cost through time for the industry and for us.

Great, thanks for the detail.

The next question comes from Ben Wyatt with Stephens.

Hi, good morning guys. Quick follow-up maybe I believe to Neal’s question about the dry Utica. Just curious if you guys had any definitive plans on a Tyler test? And then maybe as a follow-up to that, if the infrastructure was in place, just curious from what you guys have seen so far, how the deep dry Utica would compare economic wise to your other drilling prospects?

So, we had talked about a deep dry Utica in Tyler County. But as we have looked at it and looked at the markets now, the takeaway is just not optimum yet to get to good markets. It’s not easy to get to a good market. And we most likely end up at TETCO M2 for deep dry Utica out of Tyler County until the Rover pipe comes through, which as I said year and a half to two years away. We have the Magnum Hunter Stewart Winland dry test I think that’s the name of it, yes it is Stewart Winland only a few miles away and down dip of us. We are up dip of that where we drill our test. So it’s already been answered a little bit as to what the section looks like, what the pressure is, what the deliverability is and so we feel good about that. So, no plans for the near-term to start trying to develop that again with that forward takeaway. I think if you had reasonable gas prices and we have the conduit to it then that deep dry Utica can be competitive. Will it be as good as liquids rich Marcellus or Utica, questionable, I would say if we had to weigh the probability right now, we still think that the liquids rich is probably going to be better, but time will tell. We really don’t have much production history on any of the deep dry Utica yet.

Very good, I appreciate that. That’s all for me. Thanks guys.

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