Please stand by. We're about to begin. Good day and welcome to the EQT Corporation Year-End Earnings Call. Today's call is being recorded. After today's presentation, there will be an opportunity to ask questions. At this time, I would like to turn the conference over to Patrick Kane. Please go ahead.

Thanks, Kyle. Good morning, everyone, and thank you for participating in EQT Corporation's conference call. With me today are Dave Porges, CEO; Steve Schlotterbeck, President of EQT and E&P; Phil Conti, Senior Vice President and CFO; and Randy Crawford, Senior Vice President of EQT and President of Midstream and Commercial. This call will be replayed for a seven-day period beginning at approximately 1:30p.m. today. The telephone number for the replay is 719-457-0820 with a confirmation code of 4832196. The call will also be replayed for seven days on our website. To remind you, the results of EQT Midstream Partners, ticker EQM, and EQT GP Holdings, ticker EQGP, are consolidated in EQT's results. Earlier this morning, there was a separate joint press release issued by EQM and EQGP. The partnership will have a joint earnings conference call at 11:30a.m. today which requires that we take the last question on this call at 11:20a.m. The dial-in number for that call if you're interested is 913-312-9034. In just a moment, Phil will summarize EQT's year-end 2015 results. Next, Steve will give a Utica update and summarize today's reserve report. And, finally, Dave will provide a summary of the 2016 budget and the balance sheet implications. Following the prepared remarks, Dave, Phil, Randy and Steve will be available to answer your questions. I'd like to remind you that today's call may contain forward-looking statements. You can find factors that could cause the company's actual results to differ materially from these forward-looking statements listed in today's press release, and under risk factors in EQT's Form 10-K for the year ended December 31, 2014, as updated by any subsequent Form 10-Qs which were on file at the SEC and also available on our website; and under Risk Factors, an EQT's Form 10-K for year ended December…

Thank you, David. This concludes the comments portion of the call. Will you please open the call for questions?

Thank you. [Operator Instruction] We'll take our first question from Scott Hanold with Royal Bank of Canada Capital Markets.

Yeah. Thanks. Good morning, guys. How are you doing? David L. Porges - Chairman & Chief Executive Officer: Good Scott. Steven T. Schlotterbeck - President, President-Exploration & Production: Doing well.

Good. So, Steve, if I could ask you on the Deep Utica, obviously, the first well is a little better than you expected, and if you run the math, I think you guys are projecting somewhere around 18 Bcf EUR. And just so I understand this right. And then the total bookings for the two would be 24 Bcf. So does that imply the second well, the expectation's around 6 Bcf. Is that the correct math? Steven T. Schlotterbeck - President, President-Exploration & Production: Well, I think there's two adjustments you need to keep in mind, trying to use the SEC reserves number to back into EUR estimates. One, those are reserves, not EURs. So anything produced prior to December 31 is not in there. That's fairly minor for the Pettit well. But it's also, using the SEC definition, so reasonable certainty, we have two producing wells. The Pettit well had almost no production data, so our reserve projections in that case tend to be pretty much on the conservative side. So I'm not sure the SEC numbers for the Utica wells really reflect very accurately our view. And we think it's too early to really comment on our view of the EUR for the second well, but I would say that it's consistent with our expectations of the Utica. It's very, very early, but probably not quite as good as the Scotts Run. I think the Scotts Run well will likely stand out for quite a while as an exceptional well and one that is definitely above the mean for the Utica.

So, can I ask you this question? What was, from what you've seen in the Scotts Run versus the Pettit, what made the Scotts Run that much better? Steven T. Schlotterbeck - President, President-Exploration & Production: I don't think we know at the current time. We're doing a lot of reservoir testing and studying it pretty closely and I don't think we have any firm conclusions. Again, we have some limited data points. We have two data points now and the second data point has such limited history that I think it's premature to speculate too much about the reservoir just yet, other than to say, I think, one thing we've proven is with the Scotts Run that clearly there's going to be some areas of the Utica that are exceptionally good and with the cost that we've already achieved, the economics of those types of locations will be superior to probably any of the Marcellus opportunities that we have. But we need to define where the areas are, how big they are, how repeatable they are. And then, you're going to have lots of areas that it's going to depend a lot on completion techniques and the final cost of these wells to see how it compares to the Marcellus. I think that's going to take us some time and quite a few more wells to really define. But there's certainly going to be some areas that are exceptional.

Okay. So, would I be correct in saying that – and I realize, I totally respect the fact that we've got limited data, especially on that second well. But, certainly, you guys are still trying to evaluate whether or not this Deep Utica opportunity can compete with some of your better Marcellus areas. I mean, obviously, Scotts Run gave you indications that there's a good chance for it, but, I guess, the second well, did it sort of put you a little bit on the sidelines yet? Steven T. Schlotterbeck - President, President-Exploration & Production: Well, I think, you can't oversimplify the process that we need to go through. It's a brand new play, very limited data, potentially over a fairly broad area. And I would say our expectations always have been that there will be some areas that are really, really good, and I think the Scotts Run clearly demonstrates that. There's going to be some areas that are – take more time to figure out exactly how good they are and exactly how they stack up to the Marcellus. And there's clearly going to be areas that you could drill Utica well – very productive Utica wells, but they don't compete economically. I mean, the Utica is huge, covers a very large area. So, there's going to be areas of exceptional performance in economics, areas of competitive with the core Marcellus. And remember, that's our hurdle is comparing it to the best of our Marcellus opportunities and there's going to be areas where it falls short. It's going to take some time to define that.

Okay. I understand and appreciate that. Thanks. Steven T. Schlotterbeck - President, President-Exploration & Production: Yes.

We will take our next question from Drew Venker with Morgan Stanley. Drew E. Venker - Morgan Stanley & Co. LLC: Good morning, everyone. I was hoping you can provide a little bit more color on the well cost targets. It sounds like it's not really changed at this point but you've made some really great progress so far on getting down to 12.5 Bcf to 14 Bcf. Can you tell us where your latest thinking is? Steven T. Schlotterbeck - President, President-Exploration & Production: Yeah. I think, we haven't changed the targets, but I'm feeling pretty confident that our next well will be within that range. We still have a long way to go on it so anything can happen, but it's looking pretty good. I'm becoming much more optimistic that we will be ultimately at the bottom part of that range rather than the top part. It's just a little early for us to revise that range. We wanted to get in it for a well or two before we start updating it. But I think our confidence in the lower part of the range goes up every day. There's still quite a few areas for improvement and, I guess, that's why I'm so optimistic. We're going to be within that range and can identify numerous opportunities for future improvements. So, we'll keep you up-to-date on how we're doing. Drew E. Venker - Morgan Stanley & Co. LLC: And as far as – obviously it's still early, but as far as the different parts of the play, do you expect well costs to be materially different between West Virginia and Pennsylvania once you get in to – let's say once you get closer to those well targets? Steven T. Schlotterbeck - President, President-Exploration & Production: I think –…

And we'll take our next question from Arun Jayaram with JPMorgan.

Yes. Good morning. Steve, just to clarify your comments, you're saying based on your initial results in the Deep Utica, it's kind of matching your expectations based on the limited data that you have, if you can get well cost into that range that it could compete with your Marcellus program? Obviously, a lot more drilling and completing to do, but just I want to get your initial read on how the program initially competes with the Marcellus. Steven T. Schlotterbeck - President, President-Exploration & Production: Yeah. I think our thinking all along is if we can get within that range and get the results that we we're hoping to get, there will be areas of the Utica that are competitive with our very best Marcellus. And I think, clearly, the Scotts Run, which I would repeat, we don't expect the Scotts Run result to be the norm. So, that's not when we factor in what we think the Utica is going to do, we're assuming something a little less productive than the Scotts Run. But, yeah, I think, our view is that if we can get within that cost range and have the productivity that we think we can get, that there will be areas that are competitive and probably some areas that will outcompete some of our best Marcellus.

Got you. Got you. And just the overall objective of this year's appraisal program, which could be five to 10 wells? Steven T. Schlotterbeck - President, President-Exploration & Production: Well, yeah. As I said in my comments, we have two objectives. The first one, and going into the year, was our primary focus was to get the get cost down. Since we started at around $30 million a well, we we're certain that the costs in that range were never going to yield an economic project. We've gotten this cost down quite a bit faster than I had expected. So, that was our primary objective. But, I think, we're almost there. I can't quite declare victory yet, but we're getting very, very close. The second objective was to understand the productivity and the extent within the core of that productivity of the Utica and that's why we have to drill a 5- to 10-well program this year and get various data points, and as we all know, early in new plays, there's always a lot of improvement even on the completion side. You have to get up the learning curve. So, we'll make some mistakes. We'll have some – obviously, we'll have some fantastic wells. We'll probably have some underperforming wells as we experiment with different techniques, and we have to gather that data and analyze it, and it's a lengthy process. So, we're going to spend the year gathering data and studying it, and as we become comfortable with the implications, we'll communicate that to you.

Okay. And my final question is, just looking at the core Marcellus program, in 2015, you drilled about 160 Marcellus wells with an average lateral length of 5,400 feet. This year obviously, you're doing much longer laterals, plan to do 72 wells. Can you comment on what you're seeing in terms of well productivity for the longer laterals? Are you seeing similar EURs per 1,000 feet of lateral? And just maybe comment on the potential for well productivity gains in 2016 versus 2015. Steven T. Schlotterbeck - President, President-Exploration & Production: Yeah. Our experience has been that the productivity versus lateral length is perfectly linear, at least out to 10,000 feet. We've seen no drop-off in productivity per foot as we've drilled longer, which is why we been saying for a long time, the longer the better. So, we work really hard on our land department to put together drilling locations with the longest possible laterals. So, you've seen our laterals get longer especially this year. A lot of that is driven by all the land work that goes on behind the scenes to make that happen. It hasn't been a change in our thinking about the economics of longer laterals. We've always believed longer is better.

Okay. Thank you very much.

We'll take our next question from Michael Hall with Heikkinen Energy Advisors.

Thanks. Good morning. David L. Porges - Chairman & Chief Executive Officer: Good morning.

I guess I just wanted to talk a little bit about the big picture outlook around production. David, you've walked through your views around the market and the big lags that you can see around laying down rigs and slowing down activity relative to production and highlighted the 9- to 12-month lag that you guys typically see. In that context with the reduced well count in 2016 versus 2015, how are you thinking about growth potential in 2017, fully understanding it's premature to quantify, but just kind of high level? What are the key factors within the 2016 program driving our expectations around a year out from here? David L. Porges - Chairman & Chief Executive Officer: We certainly think we'll be looking at a lower growth rate in 2017 versus 2016. But also, I think that we will be seeing some growth. And probably that – I guess you could always say that the productivity of the specific wells that we drill is going to influence what happens in the next year. In this case, you'd probably particularly say it hinges on some of the Utica, even though there's not that many Utica wells. But generally speaking and I think it has to be for any of the companies that you're looking at that when you see lower capital expenditure and these kind of lags that when you look out another 9 to 12 months, you're going to be seeing a reduction in the growth rate. I think there's going to be folks like us where it's a – you'll see that real reduction in the growth rate, and I think probably the great untalked about 'elephant in the room' as it were is the companies where they've had a sharp reduction in capital expenditures, and their growth rates going to have parenthesis on it in 2017. And frankly, I think that will probably have a psychologically beneficial effect on the natural gas price market, but that's still within the context of a clearing price that's a lot lower than what we would have thought maybe a couple of years back. But that won't be the case for EQT, but you will see a – you'll see a reduction in growth rate; you will for anybody who's cutting their capital expenditure. I'll be happy to have anyone else here add their thoughts to that. Steven T. Schlotterbeck - President, President-Exploration & Production: Yeah. Maybe the one piece of information I can provide that's related, might be helpful, is if we look at what our maintenance CapEx needs are to maintain a 2 Bcf a day production rate and this is all-in capital including sufficient capital to replace the acreage that we develop with the program. So, certainly, in theory, this would be a sustainable level of drilling. We need about $700 million per year to sustain 2 Bcf a day ad infinitum. So don't know if that gives you any more information?

That's helpful. Do you know roughly of that $700 million – sorry to get greedy here, but how much of that is that acreage replacement relative to just raw drilling and completion dollars? Steven T. Schlotterbeck - President, President-Exploration & Production: Well, the raw drilling and completion is about $575 million, and then you have acreage, some capitalized overhead, G&G costs, compliance, CapEx, a bunch of other items to make up that difference, so. David L. Porges - Chairman & Chief Executive Officer: I do want to add one other comment. Observing it, some peers, for their own reasons – we assume they obviously – we all try to do what's best for our shareholders, but are talking about no rigs operating in 2016. And I think it's phenomenal what the industry has done with improved rig efficiencies. I'm still a little dubious that you can get down to no rigs and still have your production keep going up.

Yeah. At some point, that seems like it'll give. Steven T. Schlotterbeck - President, President-Exploration & Production: And yet, frankly, the market seems to behave as if, of course, we can get to no rigs, and volumes will keep going up.

I also wanted to think a little more near term. You've got a pretty substantial quarter-on-quarter growth rate implied by the first quarter guidance. Is that more a function of fourth quarter timing of well completions, or i.e., late completions in the fourth quarter or early completions in the first quarter or some other kind of variable? Steven T. Schlotterbeck - President, President-Exploration & Production: Well, it's both of those reasons and really nothing more. It's really timing of when the rigs get done, and the fracs get done, and wells get turned on line versus specific quarter-end dates. So, yeah, we are expecting a pretty substantial growth rate in the first quarter. We will be, this year, in 2016, the growth will be more concentrated in the first half of the year than in the second half. And you'll see, if you look at our backlog numbers, they came down a little bit in the fourth quarter. We expect you'll see a pretty substantial drop when we report the results for the first quarter in terms of stages complete not online.

Okay. So, the completions pace in 2016 is also then front-loaded, I would assume by that comment? Is that fair? Steven T. Schlotterbeck - President, President-Exploration & Production: Yeah, in terms of stages that come on per quarter. Yeah.

Yeah. Steven T. Schlotterbeck - President, President-Exploration & Production: It's more front-end loaded. And it's just the nature of the timing of the rigs and the reduction in our capital program. So, you'll see that reflected more in the second half of the year in terms of number of stages that come online.

Sure. And then last on my end is just the composition of that backlog, do you know the average lateral length on that or maybe the average stage length (41:48)? Steven T. Schlotterbeck - President, President-Exploration & Production: I do not...

Maybe... David L. Porges - Chairman & Chief Executive Officer: No. I don't have that.

What's your typical stage length? Steven T. Schlotterbeck - President, President-Exploration & Production: In-between 5,000 and 5,500 feet, Michael. Because the last three years, our average length has been in that range.

I know. Okay. Steven T. Schlotterbeck - President, President-Exploration & Production: 150 foot frac jobs, five stages.

Perfect. Thanks, guys. Appreciate it. Steven T. Schlotterbeck - President, President-Exploration & Production: Thank you.

We will take our next question from Bob Bakanauskas with GMP Securities.

Hi. Good morning, guys. Thanks for taking my question. Back to the Scotts Run well, I wanted to ask in terms of the increase in EUR per lateral foot, is that simply a function of the pressures not declining as fast as you originally modeled? Steven T. Schlotterbeck - President, President-Exploration & Production: Well, that's the primary driver, but it's also – so, we model that. So, it's not just the extra time it's going to take to get to pipeline pressure. It's the history matching of our reservoir models. The pressure decline that we match now indicates a higher potential EUR than the matches we were getting with West data, (43:09) but it manifests itself through a slower pressure decline than we originally had modeled.

Okay. Got it. Thanks. And then, just the progress on the cost side on the Shipman well, specifically, it looks like you'll be pretty close to hitting your original target. Is there a different completion design there or are you still using ceramics or have you switched to sand? Steven T. Schlotterbeck - President, President-Exploration & Production: We switched to sand on the Pettit well, so at the current time, our plans are only the Scotts Run will have ceramic. Our reservoir engineering analysis suggests that we're not seeing any impacts from switching to sand. We're going to monitor that. And, if clearly, if it would indicate that ceramic would drive a meaningful change in well performance, we would switch back and at least experiment more with it. But, for now, we're going with sand for this and all future wells.

Got it. That's it for me. Thanks.

We will take our next questions from Dan Guffey with Stifel. Daniel Guffey - Stifel, Nicolaus & Co., Inc.: Hi, guys. Just piggy backing on that last question. You switched to sand in the Pettit well. I guess, I'm curious on the next two or I guess the five that'll be completed this year. Are same concentration water volumes and/or stage or cluster spacing changing in any of those next five wells? Steven T. Schlotterbeck - President, President-Exploration & Production: Well, that's hard to answer because we will decide as we gather data and have to commit to certain completion designs. I think for now, generally speaking, it's a very general comment, we're going to try to not change too many variables at once. So, I think the completion designs most likely remain very similar unless the data that comes back is indicating that there's something that we do want to change and gather data on. So, again, I'm expecting not a lot of changes but that said, I would expect that we will be tweaking a few things over the course of the next several wells. Daniel Guffey - Stifel, Nicolaus & Co., Inc.: Okay. It's helpful. And then I'm curious – switching gears to the Marcellus. Can you, guys, give any detail regarding what you think to be optimal spacing throughout your core Marcellus and does this change as you move from Southwest PA dry into the wet West Virginia window? Steven T. Schlotterbeck - President, President-Exploration & Production: Well, actually, we don't see a lot of change driven by dry versus wet. We do see some differences in optimum spacing driven more by clay content in the rock. And our spacing varies from as close as 500 feet in certain areas to as wide as 1,000 feet. I think our average right now is running around 700 feet. So, it varies by geographic location and by geology, but 500 feet or 750 feet are probably the two most common spacings with few areas at 1,000 feet. Daniel Guffey - Stifel, Nicolaus & Co., Inc.: Okay. That's helpful. And then just one last one. Can you guys give me the annual decline on your PDP at year-end 2015? Philip P. Conti - Chief Financial Officer & Senior Vice President: It's around 30%. Daniel Guffey - Stifel, Nicolaus & Co., Inc.: Okay. Thanks for all the color, guys.

We will take our next question from Brian Singer with Goldman Sachs. Brian Singer - Goldman Sachs & Co.: Thank you. Good morning. David L. Porges - Chairman & Chief Executive Officer: Good morning. Philip P. Conti - Chief Financial Officer & Senior Vice President: Good morning. Brian Singer - Goldman Sachs & Co.: With regards to the impact of the CapEx trajectory on production as you see the pace of production start to slow, as a result of lower CapEx, is there any correlating impact on Midstream and the Midstream EBITDA growth? And if not, should we at all see unit cost to the E&P side of the equation move higher, all else equal? Philip P. Conti - Chief Financial Officer & Senior Vice President: You mean in terms of a load factor. I guess, Brian... Brian Singer - Goldman Sachs & Co.: Exactly, does your Midstream – how aligned is the Midstream growth to what you're doing on the volume side to the E&P business, first and foremost? Philip P. Conti - Chief Financial Officer & Senior Vice President: Yeah. I tend to be right around the 100% load factor. So, we're really spot on with the demand and capacity equipment (47:49). In fact, we're slightly over that in this quarter. So, pretty well aligned with the commitments to capacity. Brian Singer - Goldman Sachs & Co.: Got it. Okay. And then separately, can you just talk about any consolidation opportunities and your strategy there and what you see out there at these valuations and the level of interest? Philip P. Conti - Chief Financial Officer & Senior Vice President: We just keep looking. And I think this is what happens in a down market is the sellers – the sellers have a more difficult time adapting for…

I would now like to turn the conference back over to Patrick Kane for any additional or closing remarks.

Thanks, Kyle. Just one last closing statement. We are updating our analyst presentation to reflect the new information put out today. That will be available sometime this evening. And again, thank you all for participating.

This does conclude today's conference call. Thank you, all, for your participation. You may now disconnect.