Good morning, everyone, and welcome to the EQT Corporation First Quarter 2014 Earnings Conference Call. [Operator Instructions] Please also note that today's event is being recorded. This time, I would like to turn the conference call over to Mr. Patrick Kane, Chief Investor Relations officer. Mr. Kane, please go ahead.

Thanks, Jamie. Good morning, everyone, and thank you for participating in EQT Corp.'s first quarter 2014 earnings conference call. With me today are Dave Porges, President and Chief Executive Officer; Phil Conti, Senior Vice President and Chief Financial Officer; Randy Crawford, Senior Vice President and President of Midstream and Commercial; and Steve Schlotterbeck, Executive Vice President and President of Exploration and Production. This call will be replayed for a 7-day period beginning at approximately 1:30 p.m. Eastern Time today. The telephone number for the replay is (412) 317-0088. The confirmation code is 10037662. The call will be replayed for 7 days on our website as well. To remind you, the results of EQT Midstream Partners, ticker EQM, are consolidated in EQT's results. There was a separate press release issued today by EQM, and there's a separate conference call today at 11:30 a.m., which creates a hard stop for this call at 11:25 a.m. If you're interested in the EQM call, the dial-in number is (412) 317-6789. In just a moment, Phil will summarize EQT's operational and financial results for the first quarter of 2014, which were released this morning. Then Dave will provide an update on strategic and operational matters. Following Dave's 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 related to future events and expectations. 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 under Risk Factors in EQT's Form 10-K for the year ended December 31, 2013, which was filed with the SEC, as updated by any subsequent Form 10-Qs, which are on file at the SEC, and available on our website. Today's call may also contain certain non-GAAP financial measures. Please refer to this morning's press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measure. I'd now like to turn the call over to Phil Conti.

Thanks, Pat, and good morning, everyone. As you read in the press release this morning, EQT announced first quarter 2014 adjusted earnings per diluted share of $1.35, which represents a 214% increase over adjusted EPS in the first quarter of 2013. Adjusted operating cash flow also increased by 57% to $483 million in the quarter. As a reminder, EQT Midstream Partner results are consolidated in EQT Corp.'s results, and EQT recorded about $18.7 million of net income attributable to noncontrolling interests, or about $0.12 per diluted share in the first quarter. We had a very solid operational quarter, including record produced natural gas sales and record gathering volumes at Midstream, the high-level story for the quarter was strong volume growth and higher realized prices, coupled with lower unit cost in both the Production and the Midstream businesses. While our volume growth in the quarter was a little ahead of the guidance we provided at year-end, the realized price was probably quite a bit above expectations, so I will start by walking you through some details around realized price this quarter. First, NYMEX was 48% higher than last year at $4.94 per MMBtu. As you're aware, there are a variety of factors that will cause our realized price to vary from NYMEX, many of which were listed in the press release this morning. One of the most obvious factors is basis, which average a negative $0.22 per Mcf equivalent in the first quarter compared to approximately flat with NYMEX during the first quarter of 2013. From a reporting perspective, EQT accounts for its basis relative to NYMEX at the first liquid delivery point. And even though we delivered to many points, the average basis has tended to be close to the TETCO M2 price, where approximately half of our gas is…

Thank you, Phil. This was another strong quarter. But since the results were pretty straightforward, I'll focus my comments on the related issues of realized price and basis. In our discussions with investors over the past several months, there have been many questions around these topics at the basis in our region with some premium to or parity with Henry Hub to discount. Over time, basis should reflect the transportation cost in the producing regions of the market. This notion has been tested recently because of the historic construct of the producing regions being near the Gulf Coast and the market being in the northeast has clearly been turned on its head due to the tremendous growth of Marcellus production. Thus, while EQT has only sold and will continue to sell to the local market, most of our efforts recently have been to ensure that we have sufficient capacity on long-haul pipes to ship our gas to other considering markets, an imperative that couldn't really exist but with the growth in Marcellus production. More specifically, in total, we currently have 980,000 dekatherms per day of firm pipeline capacity out of the basin and expect to have 1.2 million deks per day by the end of 2014. We also have about 300,000 deks per day of firm sales. In total, our firm pipeline capacity plus firm sales will total 1.53 million dekatherms per day at the end of 2014. So we feel very comfortable with our position in 2014 and heading into 2015. This represents a mix of local sales, sales through the traditional Northeast markets and backhaul sales to the Gulf Coast. We continue to look at and make commitments on long-haul pipeline taking gas to a variety of markets. But our goal has been to stay ahead of our…

Thank you, Dave. Jamie, we're ready for questions.

[Operator Instructions] And our first question comes from Christine Cho from Barclays.

You have some impressive gains for your third-party gathering and transportation lines. I know you discussed it, but can you talk more about the dynamics of that? Were you marketing someone else's gas or your own? In fact, there was some capacity released this Q, it was a little unclear to me what's going on. Also, if you can just talk about delivery into which markets drove this dynamic?

Sure. Christine, this is Randy. The majority of the activities are selling our own gas into the -- primarily into the TETCO M3 markets and to this -- but we also have had some capacity releases on our Tennessee's 300 Line as well. But primarily, we enter into those capacity contracts to ensure flow and sharing some diversity at market and pricing. And so that is primarily there that we see the higher prices that we did this winter.

On the TGP 300 line, is that mostly for your Huron gas?

It certainly does access the Huron gas, but we also have the ability to deliver our Marcellus through other interconnections that we have with other capacity. So we can utilize it in both aspects as well as some of our Tioga gas.

Okay. And then, can we talk a little bit more about the second leg of this Ohio Valley Connector? When you say you want to go more west, are you essentially trying to go parallel to a part of REX because it sounds like REX is going to be full going the other way? And what pipelines are you trying to interconnect to or markets that you're trying to deliver into?

Yes. Sure, Christine. We're looking at -- your point on REX is a good one. But look, producers are looking for diversity of markets, right, including the Midwest. And we'll connect to a variety of pipes along the way, but certainly there's the ANR pipeline, the Panhandle, such -- Tennessee along the route are pipelines that I think producers are looking forward to access both the Midwest markets as well as the Gulf Coast.

I think the producers are really focused more on that than the fact that it might or might not parallel.

Right.

They're interested in getting to other markets. You pick up more interconnects as you move further west into Ohio.

And when you talk about more interconnects as you go West, are you guys also looking to go north like Michigan, and maybe Dawn, and I think ANR is offering that on their pipe.

Sure. I think what we're looking for, as David had said, to go further west, really to hit those liquidity points that will give the producers access to go in either direction, quite frankly. When you connect with some of other additional pipelines, you can go north as well as you can -- those pipes are working our projects to turn around and to go into the Gulf Coast as well.

I meant the E&P.

It's actually through the alternatives. We wouldn't be going to Michigan in this size. This is a size that [indiscernible].

No, no, no. I meant you as a producer, would you look to maybe take capacity to go north?

We'll certainly look at that. Our overarching driver is to diversify our market and to realize -- to get to the best markets. And certainly, as part of a diverse portfolio, we consider that certainly.

Okay. And then last one for me. Can you discuss what drove your decision to postpone your 2014 Utica program without even getting any of your own well results? Is some of this based on maybe competitor results, or just kind of the thinking around there?

Christine, this is Steve. I think the decision was driven by the fact that the first wells that we drilled were not where they needed to be to have a viable economic play there. We have some very specific completion design changes we're going to implement. And we just thought it prudent to execute those changes, get the data, evaluate the data. And do expect that, since we're doing it in 2 phases, we'll make some changes based on the first phase and then collect the data from the second before we commit a lot of capital dollars into another drilling program. So we think 5 wells, we'll learn a lot from those 5 wells, and we just want to be prudent with the capital investments we're making.

Our next question comes from Neal Dingmann from SunTrust.

I was trying to look at -- just on your -- the basis differential, obviously, continues to be very positive for you all. So you got the recent slide where you all talked about the price uplift, either for Steve or one of you, I'm just wondering about if you still have the same type of uplift for -- is it still about 35% of the acreage in the West? Is it still considered wet, Steve? And then secondly, I think on the slide, it shows the uplift going from, when it's not processed, around $5.57 to $6.76. Is that uplift, sort of that percentage, still in line, or is it even going a bit higher than that?

I think both of those numbers are still our best estimate.

Okay, okay. And then what about -- and then if I could just ask a follow-up on that. I think part of that says -- what are you seeing, Steve, on the propane side? Is that -- are those numbers holding in as far as -- I think, on the prior question, kind of talking about different markets where you would go, wondering about either on the propane, iso-butane or some of these others -- how some of those markets right now look for marketing some of those products?

Neal, this is Randy. I'll answer that. Obviously, you've seen the price in propane has remained reasonably strong and it will be exports, at the same time till the export project is announced. And so, we are looking into -- at numerous ways to take advantage of that and to get that propane to the best market.

Okay, very good. Then very last question. Steve, are you still comfortable -- I think it's got -- you got this slide that shows the type curves of the 3 different areas still -- are those still holding up? And is there any thoughts about -- as these wells continue to look solid, to say the least, about maybe even bringing this up anytime soon?

Neal, I think, as you know, our practice is to gather data, analyze it before we update our type curves. I think for now, those are our best estimates. I guess the only color I can provide is we've, more recently, been doing more drilling in the Southern Allegheny portion of our acreage. And those wells, they're still pretty early in their lives. So it's too early for us to incorporate them into a new type curve. But I will tell you that they are -- the results have been a little bit better than we expected. So I think there's reason to be optimistic in that area. But it's very early, the wells are just coming online, so we need to see how they hold up before we decide to make any changes either way.

Our next question comes from Scott Hanold from RBC Capital Markets.

To clarify, you all provided updated guidance on what you think basis can be, $0.40 to $0.60. Can you just clarify, is that just your best view, or is there -- do you have some of that locked in at this point? Specifically, could we see that bleed up or down through the year? And if you could give any color on if -- going through 2Q, 3Q, 4Q, how that sort of marches along, they widen out and then tightening -- back up for the end of the year?

Yes. Scott, this is Randy. Certainly, that's our forecast. We have -- we, certainly, throughout the year, take different positions on hedging our basis. But obviously, there's a lot of volatility in the basis going forward. And as you get forward into the year, into the winter, the prices do improve. And so, again, I think that the key driver for us is that with our diverse portfolio, be ready to access all of these different markets and continue to provide EQT with very good pricing. And we'll still -- and we're going to continue to utilize our commercial and midstream capabilities to make the best of whatever situation exists, whether -- you saw the effect of what happened in the cold winter. But that's quite possible, as you get into the shoulder months, in the summer, that the focus will be on mitigating any negative effects that we get from basis. So it's not just the basis numbers, it's utilizing the commercial and the midstream capabilities, they get the best realized price for their corporation.

Okay, understood. And I guess, regard to my question, is if you had a bias -- I mean I know that's your best guess right now, but like what does that look like in the summer? Specifically, if we were to look at 3Q, what kind of basis do you think, on average, that you all would have of the $0.40, $0.60? What does it look like in kind of that worst quarter of the year?

Worse than that. I don't know that we have a -- I don't think we have -- if I knew what the weather and such was going to be like I could predict. I would say that the commercial team is doing an excellent job. They do a great job maximizing the value for EQT. And I think we'll continue to do that.

But we have no special insight into what M2 is going to be, what M3 is going to be or NYMEX is going to be. We just based on what we see in the market. It's a kind of joke internally, if you know where those things are going, you should quit and go into business as a proprietary trader. But we don't. We have to deal with the markets as we see them, and try to build as much optionality, both financially and operationally, into our business as we can.

Okay. Understood. Appreciate the color. And just kind of a follow-up on -- maybe it was Neal's type curve question and more, again, specifically to this quarter. It seemed like you had a -- the Marcellus sales performance was pretty strong. Was that a lot to do with those Southern Allegheny wells? It seem like the wells that you tied it was a little less than I thought, but production still is a little bit stronger. Is that what's really driving the performance there?

That certainly was a portion of it since some of the new wells were in that -- in the last quarter, in the previous quarter, in that Southern Allegheny area. But I think overall, it's just continued good performance in the wells. They seem -- they're holding up very well. So Southern Allegheny was a contributor to that.

Okay. And then when you look at like your, I guess, completion backlog real loaded this quarter. How is that going to progress through the year? Is that somewhat dictated by infrastructure? Is it going to be a little bit lumpy or linear as we go through the year?

It will continue to be lumpy, just as it has in the past. It is driven primarily by drilling and frac-ing timing, not so much by infrastructure timing, although that occasionally had some small impacts. It's more with the larger, multi-well pads, large number of wells tend to come on in chunks. So we didn't have a lot of new wells come online in the first quarter. That means in the next couple of quarters, we're likely to be a little bit above the run rate. So it has been chunky, and I think it's going to continue to be chunky just from the nature of our drilling completion practices.

Okay. So we should anticipate the production in the next couple of quarters as well is lifted a little bit more by a higher mono-pad drilling being completed. Is that a fair context?

Well, I think you just have to keep in mind that turning wells online in a quarter is very dependent -- the volume impact of that is dependent on when in the quarter that happens. So you can have a lot of wells come on late in the second quarter and not have much impact in the second quarter. So just -- you do have to be mindful of that. But I think our backlog does indicate that over the next couple of quarters, we will have quite a few wells coming online.

But we -- look, we are particularly focused as a company on multi-well pads, often several wells on a pad, and a lot of stages per well. So that's probably a reason that we could show a little bit lumpier results than some of the peer group. There can be hundreds of stages at one pad.

Our next question comes from Faisel Khan from Citigroup.

If I could ask you another question on the change in sort of the midstream deductions going from positive $0.64 this year to negative sort of $0.26 last year. Can you give us a little bit of color on what your expectations are for the rest of this year for that number?

Yes. We put the -- those specific numbers in the release, Faisel.

But the -- for the -- that's different from your basis assumptions, right?

Well, we get basis and the guidance on that line item as well.

Okay, fair enough. And then just as I'm looking at your Marcellus capacity sort of assumptions that you guys just slide -- you guys laid out on your slide deck, Page 35. This market mix, is it fair to say that the 11% to 12% that you're assuming for NYMEX, that's all the capacity getting to the Gulf? Is that how I should look at it?

Right. That's from our backhaul, yes.

Okay. So everything else usually will end up in M3, TCO and M2. And those are the next step pricing which you guys don't know what it could be. There are assumptions for it, but it could be anything over the course of the year.

Right.

Okay. And then in terms of the injection rate and the storage for you guys, is there any sort of -- given what kind of winter we had this last few months, is there any sort of restrictions on the injection rate into storage in terms of just getting back up to full capacity before the season -- the next winter season starts?

This is Randy. As you probably know, I mean a lot of northeast storage is reservoir storage. And so, there are certain -- from a utilities perspective, a certain amount of injection daily that's required. But certainly, the filling of that storage, it will be challenged throughout the year at the low level. So physically and contractually, there are some limitations.

Okay, got it. And then just looking at sequential depreciation and amortization -- DD&A from fourth quarter to the first quarter. It looked like it ticked down. Just trying to figure out exactly what caused that to happen.

It was based on the reserve report that we released on the year-end.

Okay. So there's an increase in proved reserves?

It's mostly what drove it down. I think it was $1.50 last year, it's about $1.21 in the first quarter.

Our next question comes from Michael Hall from Heikkinen Energy Advisors.

I guess just want to come back a little bit on the outlook around basis and marketing. Number one, I guess through the summer, that $0.64 gain that you had in the first quarter and given the guidance for the rest of the year, I think implies probably around $0.20 or so negative on the gathering and transport. I'm just trying to understand kind of to what extent there's a possibility that as we work through the summer and into the fall as regional prices look likely to be pretty volatile. To what extent do you have an ability to repeat what we saw in the first quarter and kind of surprise to the upside by accessing other markets? Was that purely a weather-driven phenomenon in the first quarter, or is there really a flexibility that's provided by that line item that can really offset any basis headwinds that make their way through the summer?

Yes. Michael, Randy again. Yes, they're both. Certainly, the weather had an impact but these capacity constraints and the optionality that EQT holds and just continue to hold upstream firm capacity contracts, certainly provide us the optionality to improve pricing.

Look it's easier to make a lot of money on it, frankly, when there's a lot of demand. I mean I just would be straightforward as possible. And this only isn't -- kind of getting, again some of the operational issues. A thing that I'm maybe not sure we related as an anecdote. There was a circumstance where some of our commercial folks saw an opportunity move gas in a different direction, but it wound up that we have to utilize our compressor station that actually hadn't been run for a while. So the operations folks in midstream went out and restarted the compressor station and flowed gas to take advantage of that opportunity. And we will continue to try and leverage our various capabilities to be able to do that. And it's just a lot easier to do it when we do have high demand.

Okay, I guess -- I'm also just trying to understand this, if it's in part a function of -- when we have these big interregional spreads across these different price points, does that create an opportunity? So even if you do see a lot of negative basis throughout the region, if there's a lot of variability across those different points, that there's an opportunity in it for you guys to then...

As long as we do have the assets in place. I think what you'll see going forward is that we're going to continue to focus on an asset strategy that allows us to have more optionality going forward.

Okay. that's helpful. And then, looking out to 2015, you provided the mix in the slide deck today for 2014 as it relates to the different price points you're selling to, which is helpful. How should we think about that evolving in 2015? Was it materially different where we stand today versus what 2014 looks like? And then, I guess as a follow-up on that, at what point -- as we think about reversals and changing flow dynamics in the Northeast, at what point do you see an environment -- and I know, it's hard to predict, but we're -- maybe we get back to the more normalized typesetting for basis in the Northeast.

I'll take your first part. David mentioned in his comments, we have a 2014 capacity that comes on in November of this year. That capacity allows us to move gas both to the Northeast syndicate market as well as to the Gulf coast. So that, again, will have an impact in 2015 on our realized prices and the optionality. And your other question was really I guess about the growth in production and that of -- exceeding local markets. Certainly, again, that's why we go forward with our continuing in our capacity and access a variety of markets. And over time, it will. We'll get to a point where there will be more -- enough infrastructure to take the gas to the market.

But that will be a new steady-state, so we're not particularly worried, over time, about the basis going out in a negative way here. But it is going to wind up reflecting the cost of those reversals, et cetera.

So yes, we look forward and we see that our region of the country is going to be a net exporter to other regions of the country. And that's going to get reflected in basis. But that basis within -- over the next, I don't know, 3, 4 years, that starts collecting. So that [indiscernible] that matches what the cost is of moving the gas.

And what is that cost really currently, as you start looking at...

It depends on where you're going. You can see examples of the tariffs on the new pipeline projects as they come on. That's fair [ph].

And I guess last one on my end, just in the Utica, what are the completion design changes that you're bringing forward on these next 5 wells? Just kind of what's different in terms of -- versus the prior one?

This is Steve. That's a topic that we're not ready to talk about. If it works, we want the techniques to remain proprietary for a while.

And if it doesn't work, you don't really care.

Our next question comes from Andrew Venker from Morgan Stanley.

In West Virginia, there's some talk about a pretty nice Utica play. Do you see that as prospective on your acreage?

Andrew, this is Steve. We're certainly monitoring the results from our competitors in the dry gas Utica. And certainly, as it seems to be moving further east toward where we have larger holdings. That said, we're currently updating our geologic review of the play, which we did a couple of years ago. And right now, all I can say is we're updating our assessment of the play and hope to be able to report a little more detail later in the year. But for now, we're monitoring what's going on and taking a closer look at the geology and how our assets sit on top of that.

Can you provide some color on just the geology? Is it higher pressure in the Marcellus that sits right on top?

It's certainly higher pressure. It's clearly very widespread from a geologic standpoint. I think the producibility of the reservoir in certain areas is still an unknown. I think one of the biggest challenges for us that we're looking hard at is the depth. So from a cost standpoint, the wells are going to be expensive. Where most of our acreage is, the minimum depth we'd be looking at is 10,000 feet, all the way up to north of 13,000, perhaps even closer to 14,000 feet in some areas. So that's a cost challenge as well as a completions challenge. So we have questions that we need to dig into concerning what will it take to stimulate this reservoir, particularly at the 12,000-foot depth, at the pressures we'd be looking at. Can we effectively pump the rates we think we would want? What kind of equipment would it take? What kind of wellbore design would it take? And therefore, what would be the cost and the economics? So we're looking into all of those aspects. But clearly, the challenges get a little more difficult as you move further to the east and deeper into the basin.

Is there any significant chance that the gas there is overcooked, or are you fairly confident that it's dry gas?

It's a huge play, so I don't think you can make blanket statements. I think, clearly, there are areas where it's not overcooked. But as you approach the deeper areas of the basin, it's certainly possible that it is. So that's why I say the producibility is an unknown, especially as you get further to the east.

Our next question comes from Joe Allman from JP Morgan. Joseph D. Allman - JP Morgan Chase & Co, Research Division: On the Marcellus, are you set with your completion techniques? Are you still modifying some of the completion techniques?

Joe, I'll tell you, we'll never be set on our completion techniques. That will be a constantly evolving practice for us and for, probably, our competitors. I don't know that -- we're trying to know an unknowable when it comes to stimulating these reservoirs. We'll never know all we would like to know to have the perfect design. So you should expect we will always be [indiscernible]. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Could you talk about some of the recent modifications you made and the impact on production?

I'd rather not talk about specifics. More recently, the changes from the Marcellus in our core areas where most of our drilling has been, had been focused on small changes around sanitizing, pump rates, stage sizing, those types of things, the normal things that completions engineers will be looking at. In Central PA, where we have -- there's a test program going on. That's -- we're a little early in our understanding of that rock, particularly around how we design our completions around faulting and there's more faulting there. So those are the sort of aspects of the design that we're focused on up there, more than in a quieter, in core parts of the play for us. But that's about as specific as I'd like to be. Joseph D. Allman - JP Morgan Chase & Co, Research Division: Okay. That's helpful. And then I know that Utica is not nearly as important for you as some other plays, but can you just repeat what you're going to do there? I think you drilled 7 wells. Have you completed 2 already and just not terribly satisfied with those results? I think you said you're going to complete 3 using a different technique. And then -- are you going to complete the next 2 using yet another technique? Could you just describe what you're going to do?

Yes, it's great. Actually, I think we drilled 8 wells and 3 are online. The results are certainly not where we'd like them to be and not competitive with our other investments. So if we can't make improvements, it's not a play we put any more capital into. However, based on those results and the data we collected during those completions, we saw some very specific things that we want to address in the next stage, which will be 3 wells, and we're currently implementing right now. So we're going to finish frac-ing those wells, get them online midyear, get some results back, gather some more data. Based on that, we have 2 more wells that have been drilled that we will likely modify the completion design again. Frac those, get the results. That will be late in the year. And then based on all that of data, we'll start to make some decisions about do we move forward in this play, or do we not move forward? and we'll update you at that time on what we think. That's a year from now, probably.

And everyone, at this time, I'm showing no additional questions. I'd like to turn the conference call back over to management for any closing remarks.

Thank you, Jamie, and thank you, all, for participating.

Ladies and gentlemen, that does conclude today's conference call. We do thank you for attending, you may now disconnect your telephone lines.