EQT Corporation (EQT) Q1 2012 Earnings Report, Transcript and Summary

Good morning and welcome to the EQT Corporation First Quarter 2012 Earnings Conference Call. All participants will be in a listen-only mode. (Operator Instructions) Please note this event is being recorded. Now, I'd like to turn the conference over to Mr. Patrick Kane. Please go ahead. Patrick Kane – Chief Investor Relations Officer: Thanks, (Emily). Good morning, everyone and thank you for participating in EQT Corporation's first quarter 2012 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, Distribution and Commercial; and Steve Schlotterbeck, Senior Vice President and President of Exploration and Production. In just a moment, Phil will summarize our operational and financial results for the first quarter 2012, which were released this morning. Then Dave will provide an update on our strategic operational matters. Following Dave's remarks, Dave, Phil, Randy, and Steve will be available to answer your questions. I'd like to point out that today on our website we provided additional details on our cost per well and EUR per well at different well lengths. Historically, we have provided these estimates assuming a 5300-foot lateral, which was our projected average. As you will see, the EUR per foot of lateral is unchanged and the cost per well is lower. This call will be replayed for a 7-day period beginning at approximately 1.30 pm Eastern Time today. The phone number for the replay is 412-317-0088. The confirmation code is 10006583. The call will also be available for seven days on our website. But first, 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 results to differ materially…

We will now begin the question-and-answer session. (Operator Instructions) And our first question will come from Neal Dingmann of SunTrust. Please go ahead. Neal Dingmann – SunTrust: Good morning guys. First, guys can you address maybe just a different source that you are seeing going forward? And then secondly as you sign – you talked about the MarkWest deal that likely signed up, how do you perceive sort of the infrastructure costs going forward if that deal was successfully completed?

So, we talk about ones, changes going forward, you are talking about on the infrastructure side?

Correct.

Randy, you want to comment on where you see infrastructure heading?

Well, with respect to the pricing, we haven’t seen a great deal of softening in the market from that standpoint, but in terms of the projects, EQT is working towards, we continue to be on time, on budget with our Sunrise expansion and in building up the infrastructure that connect to the plant. And as Dave alluded to we are looking in the interim to other options as well to move, to get our gas process.

We are obviously going to see average gathering rates decline even in the constant cost environment just as the mix continues to move towards the Marcellus, but we've mentioned in the past that the unit rates for Marcellus are roughly half that for Huron. So, as the mix keeps moving we will continue to see average declines even without a – because of mix change along. Neal Dingmann – SunTrust: Okay. And then just kind of going forward one last question just on the improved sort of techniques you are continuing to see, as far as what are you seeing that as far as opportunities why, just on a percentage, does that continue to expand and maybe cost that you see on that going forward. Are you able to as you continue to do more of these new processes, bring down the cost a bit on that completion?

Yeah, I think you’re talking about production. So, I will turn that over to Steve.

I assume you are speaking about completion techniques in particular? Neal Dingmann – SunTrust: Yeah, exactly, Steve.

Yeah. Well, we continue to really feel good about the results we are seeing with the new frac techniques specifically in the more brittle areas like we talked about. I think roughly 44% of our program this year we expect to use the new technique. And I think that benefits pretty well from the reduced service costs we are seeing. So, that’s been a big benefit as well that the cost for that new technique could come down along with the overall costs. Neal Dingmann – SunTrust: And then when your peers talked about just the tighter denser space, I mean, is that something Steve that also that you are looking into and do you assume, it look like that they talked about increase rates based on that, is that something that you’re looking at doing as well?

Well, I guess I would say we pioneered that.

Yeah, that’s what we are talking about. Yeah, that's what we are talking about, year and a half. Neal Dingmann – SunTrust: I guess, what I'm asked to Steve is as you continue to sort of on these specs do that, is that going to be basically majority, I mean right now it's still I don’t know what percent of your total program that is. I am just wondering if that will become sort of more mainstream here in the next letter part of this year for you?

Well, I think we still believe that it’s going to be location specific based on the brittleness of the rock. And our current estimate is that for 2012, 44% of our 132 wells will use that technique. Neal Dingmann – SunTrust: Well, okay.

In some of the cases, in certain pricing environment, it doesn't make sense and other pricing environment it does make more sense. So, depending on where natural gas prices go, there is kind of a gray area either somewhere it just seems that it basically always make sense. Others were basically seems that it never make sense so, on some place where it's little bit more sensitive to current economics. So, you can see that percentage moving up of that. Though, I would say and I think I look at the things that folks are doing. They keep working on ways to come up with the optical completion technique for each of those – for each of the areas on which we are working, whether it's the tighter spacing, which again we've been talking about for a – that's what we are talking about now, we talk about (specs) that's what we've been talking about for the last year and a half or thereabout or other techniques. Neal Dingmann – SunTrust: No, it still sounds like that combined with your long laterals you are really seeing some of the best results out there. Thank you.

But we'll keep working on, ever working on trying to get better and better. Neal Dingmann – SunTrust: Perfect, thank you.

Our next question comes from Scott Hanold of RBC Capital Markets. Please go ahead. Scott Hanold – RBC Capital Markets: Yeah, thanks. Good morning. A question for you, on your drilling program in the Marcellus obviously the gas price where they are, I guess you made the case that your economics are still good. And so, I guess that implies at this point in time, you are not going to make a change to your overall development program. But can you talk to the extent where you're shifting or you have the capability of shifting activity more to liquids from the drier gas parts of the plane. How much of that is actually going on at this point in time?

What we are shifting to the extent that we can obviously we only get the uplift and this is true for everybody goes not just does. We only get the uplift when you're actually able to extract enough of the liquids. We get a certain amount of the uplift just from the so called JT skids for you. But the mainly design just give you a pipeline quality gas of its, I guess the tastes where that can put you over into that making it more economic that I'm more prolific dry gas well. But what we're really focusing on more is the ability to link the development program with the processing capability. So, we're moving in that direction as much as we – as much as we can, but we are marrying the production activities with the Midstream activities. Scott Hanold – RBC Capital Markets: Sort of the delay in the MarkWest plant kind of I guess to a certain extent limit your ability to really focus a little bit more efforts in those areas.

Not right now because realistically a well that we spend right now, it does affect cash flows in 2012, right I don't want, we mentioned that in the prepared remarks and that's true. But those are on wells that hit over to the spot. For the decisions that we are making now to spot wells, the presumption is that we have a reason to believe those – that plan will be upon running and preferably some of the increased capacity that we made reference to would be ready as well because there is a lag between the decision to spot now comes online. So, now I wouldn't say that it's – that client doesn't impact the decisions that we're making on where the drill right now that delay there impacts really third quarter cash flows. Scott Hanold – RBC Capital Markets: Okay. And then maybe kind of referring to, may be the early part of the question I had so, if you're looking to the back half of '12 and the early '13, I'm not sure what you are assuming for gas prices. But are you making focused effort with MarkWest expect to be online in 2013 that you are going to drill in the higher liquids areas and can you be pretty fluid with that program if need be?

Yeah, but we work with any number of process, we just want to get our – the liquid extract from the gas and we get the revenue uplift from the propane and butane. Scott Hanold – RBC Capital Markets: Okay, how much of it?

Just one company, I mean, we talked about one company, that's one plant in North and West Virginia, but more broadly yes, we are as we look ahead, we are looking at making sure that we can as we said that we can continue to focus on both the areas that are more liquid rich amongst our acreage as well as the once that are more prolific, which really needs the dry gas so that are – that have the best economic. Scott Hanold – RBC Capital Markets: Yeah, if memory serves me that plant specifically with MarkWest that we are referring to is a $100 million a day.

Our capacity on that would have been is actually is $120 million a day. Scott Hanold – RBC Capital Markets: Is a $120 million a day? Okay. And then how much of an impact will that shift have or let me ask you the question this way when that plant comes online, how much of an annualized basis improvement would you get in pricing?

We have to be able to do the answer for that, probably the best opportunity.

Part of the Mcf basis, the liquids uplift gives us about $2.50 increase. Scott Hanold – RBC Capital Markets: At today's price?

At today's prices. Scott Hanold – RBC Capital Markets: Okay, alright. And that's $2.50 per...

Per Mcf. Scott Hanold – RBC Capital Markets: Per Mcf – on an Mcf basis, okay. One last quick question if I could you, Phil, I think you mentioned what your cash balance at the end of the year, I apologize I missed that, could you give us?

At the end of the first quarter by the way, I'm sorry, $7.45 was at the end of the first quarter. Scott Hanold – RBC Capital Markets: Yeah, okay, $7.45, thanks guys.

Our next question comes from Anne Cameron of BNP Paribas. Please go ahead. Anne Cameron – BNP Paribas: Hi, good morning. Not to be the dead horse on the West Virginia wet gas issue, but what is your current West Virginia wet gas production from the Marcellus on an Mcfe basis?

Yeah, we don't provide the breakout on Marcellus by state. Anne Cameron – BNP Paribas: Okay. So, I guess my – what I am driving at is when the MarkWest plant does come online is a 100 net enough to handle all of our wet gas production and how much more processing do you need?

Well, as we keep growing, we'll need more and more and that's we and we are currently working on and you are well into development what those alternatives are to keep processing more than the 120. Anne Cameron – BNP Paribas: Okay. And do you have capacity in the second mobile plant?

Maybe you talk about it…

Yeah, I mean, maybe we are – we have a firm right to a $120 million a day of that plant and MarkWest is putting in a larger plant and we are in discussions with them and others about additional. I would reference on capacity on the plate as well though that as we said before we've been proactive with adding a $100 million a day of capacity. We'll have a total of $100 million out of our Dodgeridge County and at the year end at our other wet area and that's another $100 million a day and with our Sunrise project, we've adequate residue gas to move that gas to market. So, we had been proactive in doing that and when the plant comes on, we're going to be prepared to move the product going forward. So, as they believe we're working toward getting additional processing capacity at this time.

We are not concerned about that overtime. The issue is when plants coming, it can move things by a quarter here and there, that's the issue, it's the near-term cash flow forecast, not the longer term strategy that gets impacted. Anne Cameron – BNP Paribas: Okay, thanks. And that $2.50 uplift, does that correspond to 1.8 gallons per Mcf excluding in the ethane?

Yes. Anne Cameron – BNP Paribas: Is that about right?

Yeah. Anne Cameron – BNP Paribas: And the $2.50 net of processing fees or is it growth of processing fees?

It was net. Anne Cameron – BNP Paribas: Okay, got it, thanks. And then in terms of the ethane, can you mix ethane indefinitely from what you can see right now into the gas stream.

Well, Anne, this is Randy. From what we can see right now, we have the adequate mix to mixed the dry to meet our pipeline specs and so as we said previously we'll make the decision whether it take the ethane based on economic conditions not on pipeline quality issue. Anne Cameron – BNP Paribas: What kind of infrastructure would be involved in moving that ethane either to the enterprise line or to the Mariner East project, if you did the side to extract it?

Well, our commercial arrangement at MarkWest provides the option that they would extract the ethane and move it.

Yeah so really the fact what it means it would take from that plant and would really just I think shift the whole thing up to their one of the fractionation facilities. So really that infrastructure already exists. It just a question on making the determination that it's economical to extract the ethane. Anne Cameron – BNP Paribas: Okay, got it. And then just a totally separate question, which you may or may not be able to answer given that your docs are still sitting with the SEC. The strategy for the MLP like really is the gain plant to gross third-party volumes with that business or is it really mostly just to process Equity Gas and like how….

What our General Counsel is looking at is shaking our hands. Anne Cameron – BNP Paribas: Oh, (indiscernible) okay.

We don't want to say anything that would make you more likely to buy the unit. So… Anne Cameron – BNP Paribas: Okay, okay, I'll backup. Sorry guys. Alright, thank you. That's it from me.

The next question comes from Michael Hall of Robert W. Baird. Please go ahead. Michael Hall – Robert W. Baird: Most of my questions have been answered. I guess couple of remaining one from me. May I talk about Northeast strategy that changing despite current environment, which make sense. But are there any other tactics that you are kind of reviewing currently that we haven't really talked about outside of just drilling additional liquid rich wells. Any other sorts of cost saving initiatives or things along those lines that are currently under consideration?

Yeah. We certainly continue to look at ways to improve cost structure and of course before I alluded to production, but the same thing is to a midstream continuing to improve cost structure. I am not sure I feel comfortable getting into the things that are simply in the development stage because we often look at different alternatives and yet test them out, you see what works and doesn’t. Michael Hall – Robert W. Baird: Got it. And I guess the other one is, have you reviewed or do you continue to review your legacy assets for any sort of Utica exposure I know in the past expense likely to just be in a dry windows. Is there any indication as we can better understand the windows potentially some wet gas and that as well or is there no real change there? Thanks.

Not really, I mean maybe there is, but really hadn’t been much change, but we haven't quietly spent too much on focusing on that. The large part of those, which is also deeper in Pennsylvania than it is in Ohio. So, our approach on the Utica is still pretty much what it was for our Pennsylvania acreage, which is – there is going to come a time where it make sense to drill down basically from the same pads that were using for the Marcellus. Because that will obviously involve an improved cost structure to be able to use all the same pads and well roads and compressor stations, etcetera. So, that will be settled – when we get to that point time that will show cost structure improvements too. Michael Hall – Robert W. Baird: Okay. That’s all I have. Thank you very much.

Our next question comes from Ray Deacon of Brean Murray. Please go ahead.

Ray, you there?

Mr. Deacon, your line is live. We'll move on to our next question. (Operator Instructions) At the time, we'll take a question from Craig Shere, Tuohy Brothers. Please go ahead. Craig Shere – Tuohy Brothers: Hi guys. Couple of follow ups on the frac geometry from Neal's question. First if I remember correctly when you'll first announce that it was said that I might add maybe a million dollar per well and cost, but you are obviously noting that services cost are lower currently so, that's really helping a lot. First part, do you have an updated figure for how much more cost per well to imply the new geometry and to the extent, Dave, we commented some of the new geometry was economic in some cases of less optimal brittleness based entirely on commodity prices. So, when you think about issues of hedging and when you think about commodity prices at their extremes. How does that kind of play into any expansion of this program?

On the first part, cost for the new frac – the additional cost per well is about $1.2 million for the 5,300 feet and that's down from $1.4 million previously.

On the price side I just generally speaking say that it the areas where it's kind of a gray area whether it makes sense or not. They tend to look better when prices go up. So, yeah, I mean, if you look at this is – if you want to look at any company as say one thing that would have been if there is a more than you say it's almost if there is the call options embedded price – long call options on gas price. We cannot to really factor that into much in the hedging because that's, I mean such a long – there is a longer term play. But you're right it does – it does suggest if prices are higher that you had more exposure. So, you may that is true, but I don’t know I said we formally corporate that where when we are looking at our hedging strategy. For the most part, the hedging strategy is designed not to pick prices, but to make sure in the cash flow state a reasonable level. So, that we can optimally size our business, right, so, we are at the cash flows don’t get jerked around so much that you're constantly trying to get fewer rigs or more rigs, fewer crews or more crews. Craig Shere – Tuohy Brothers: Right. So, cash flow certainty not necessarily rate of return certainty particularly at low gas prices. When you make this decision, are you basing it more on like the current strip of 12 months? Are you basing it on the next 10 years of strips?

Well, generally, just ballpark we are typically within more of a five-year strip, but if the price – I think you'd say in theory and we do try to apply some of this. But you try to hedge not to guess prices, but when certainty about price would alter the behavior or when uncertainty about price would alter the behavior. So, I wouldn’t say that we don’t take returns into our account back. I’d say if there is projects were buy, it’s an attractive investment if prices are at the current level, but prices decline it's not attractive anymore, but that's the time we say yes, best decision is to go ahead and make the investment, but also hedge. Craig Shere – Tuohy Brothers: I got it. Okay, it doesn’t sound simple, but it sounds like you have a lot on your plate to manage the portfolio there.

No, but I think a lot of hedging is that, right it's more or like, I guess it's expected utility as suppose to expected value is what we’re looking at. It’s kind of the same as what you’re looking at the life insurance, right? So nobody buys life insurance hoping that it pays off. Craig Shere – Tuohy Brothers: Sure.

Well, at least start soon. Craig Shere – Tuohy Brothers: Well, hopefully, well we get out of this throughout with gas prices and you can enjoy the benefits of the entire portfolio.

Yeah again, we do think that we need to be structuring our business and what we pursue is for investment opportunities with a relatively conservative gas price in mind, not to say this one is influenced by the current storage situation. But that – it’s getting more economical to drill for natural gas at least in our base in the Marcellus, but I guess, we can see the other bases and we need to bear that in mind what we’re forecasting our dividends. Craig Shere – Tuohy Brothers: Understood. I appreciate all the color.

Thank you.

This concludes our question-and-answer session. I would like to turn the conference back over to management for any closing remarks. David Porges – President and Chief Executive Officer: Thank you for everybody for participating and we’ll look forward to doing this again in three months. Thank you.

The conference is now concluded. Thank you for attending today’s presentation. You may now disconnect.