EQT Corporation (EQT) Q2 2012 Earnings Report, Transcript and Summary

Good morning, and welcome to the EQT Second Quarter 2012 Earnings Conference Call. All participants will be in listen-only mode. (Operator Instructions) After today’s presentation, there will be an opportunity to ask questions. Please note this event is being recorded. I would now like to turn the conference over to Mr. Patrick Kane. Mr. Kane, Please go ahead.

Thanks, Amy. Good morning, everyone, and thank you for participating in EQT Corporation’s second 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. This call will be replayed for a seven-day period beginning at approximately 1:30 p.m. Eastern Time today. The phone number for the replay is 412-317-0088. The confirmation code is 10006595. The call will also be replayed for seven days on our website. As you already know, we successfully completed an IPO of EQT Midstream Partners earlier this month. Before we review this quarter’s results, I want to remind you that there was no impact to our second quarter results as the IPO did not close until July 2. next quarter, our EQT results will include the results of EQT Midstream Partners on a consolidated basis. Below in that income line in the statement of consolidated income, EQT will present the amount of net income attributable to the public unitholders under the caption “net income attributable to non-controlling interest”. Cash distributions from the partnership to the non-controlling interest will be reflected in the financing section of EQT’s statement of cash flows as a use of cash. The cash distributions to the non-controlling interest will not impact the consolidated cash flows provided by the operating activities or cash flows from investing activities. There will also be a separate press release, 10-Q and conference call to detail EQT Midstream Partners third quarter results. In just a moment, Phil will summarize our operational and financial results for the second 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 all be available to answer your questions. But first, as usual, 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 and under Risk Factors in the company’s Form 10-K for the year ended December 31, 2011 filed with the SEC, as updated by any subsequent Form 10-Qs, which are on file with the SEC and are 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. Phil?

Thanks, Pat, and good morning, everyone. As you read in the press release this morning, EQT announced second quarter 2012 earnings of $0.21 per diluted share, a $0.30 decrease from adjusted EPS in the second quarter 2011. Two price related items together reduced EQT production revenues by $15.3 million or $0.07 per share this quarter, one item was related to gas price put that should have been recognized in 2010 and 2011 resulting in a non-cash revenue reduction of $8.2 million in the second quarter of 2012. The other was a $7.1 million increase in third-party gathering, processing and transmission revenue deductions, from the sale of unused firm capacity at rates below what we are paying, and I will give you some more on that in a minute. Operating cash flow in the quarter of approximately $160 million decreased by 14% versus cash flow in the second quarter of 2011. Other than that, the operating results this quarter are fairly straightforward. In short, we had another strong operating quarter at EQT. Production and sales volumes were 28% higher than last year and a 11% higher than in the first quarter this year. NGL volumes were 10% higher than the last year and 8% higher than in the first quarter, and midstream gathering volumes were 24% higher than last year and 9% higher than in the first quarter. However, commodity prices were significantly lower than last year and that more than overwhelmed our operational progress. I would discuss that in a bit more detail in the segment results starting with EQT Production, where sales volumes continued to grow as planned. As I mentioned, production volumes were 28% higher and that growth was driven by a 74% increase in sales from our Marcellus Shale play. We do, we did hit two significant…

Thank you, Phil. As I’ve previously communicated our objective of maximizing shareholder value is unchanged by changes in the environment in which we operate. The strategy accomplishing the amortization of our asset base and prudent pursuit of investment opportunities while living within our means is also unchanged. Of course, the specifics of these monetizations the assets, the timing, the form are very much affected by market conditions. We took another major step forward this month with the successful IPO of EQT Midstream Partners LP. Including the impact of the underwriters over allotment option, which was fully exercised EQT Midstream sold about 40% of the limited partnership units to the public, with the units pricing on-schedule and at the top of the indicated price range. These units trade on the New York Stock Exchange using the ticker EQM. We believe EQM will provide us with ongoing access to capital at relatively low cost consistent with the steady cash flows generated by those midstream assets. As we were on our multi-city MLP IPO roadshow, we met with many of our existing EQT shareholders and many of our new EQM unit holders. Both groups of equity owners including those now owning both securities recognized the symbiotic relationship between EQT and EQM. The capital raised in this offering will be redeployed to accelerate the development of our vast Marcellus acreage position. This acceleration will lead to increased sales of produced volumes, and also increased gathering and transmission volumes and cash flow for EQT Midstream and EQM. This increase in Midstream cash flow drives MLP unitholder returns and will help increase the amount of capital available through additional midstream sales of assets from EQT to EQM so-called dropdown. For the time being we anticipate that most large Midstream investments will be made and EQT level.…

Thanks, Dave. That concludes the prepared portion of the call. Amy, could you please open the line for questions.

Thank you. (Operator Instructions) Our first question is from Neal Dingmann with SunTrust Robinson Humphrey. Go ahead please. Neal Dingmann – SunTrust Robinson Humphrey: Good morning, guys. Just a couple questions, first just is you alluded to on the dropdowns, I guess I was just wondering timing, how soon could we begin to see some of those dropdowns and just again remind me, the rationale of initially why to buy to the EQT and then dropdown versus I thought maybe there would a lower cost structure the other way?

Well, I’m not that comfortable giving timing guidance on dropdowns at this point, because we just kicked this off. Obviously, routinely we would want to have dropdowns, but I just assume to stay away from… Neal Dingmann – SunTrust Robinson Humphrey: Fair enough, maybe…

Too much guidance on that. Neal, was your other question about why the construct we’re using for the time being at least is to build facilities at EQT and then drop as opposed to building at EQM? Neal Dingmann – SunTrust Robinson Humphrey: Correct. I’m certain you looked at sort of cost basis, I just wanted the benefits, how much you anticipate saving that?

Sure. Certainly, over time we would expect there will be more facilities constructed at EQM. The issue that we have though is that as we understand because we are neophyte in this MLP world. But as we understand it what we’re really trying to do to drive value at that level is, as you try to drive unit distribution growth and it is more difficult to do that when a high percentage of the capital employed is tied up in non-cash generating assets, such as assets under construction. So, from that perspective – actually you think even with large MLPs, you see that there’s only a certain percentage of their capital that they have invested in non-cash generating assets, is just the size of EQM, that’s not a very big number right now. Over time you would expect to see that number to grow. Neal Dingmann – SunTrust Robinson Humphrey: Okay. And then just two more if I could, Dave for you or Steve; one, as well as looking at the, I think the last presentation, you all had out. I think you’ve identified maybe 30% – 35% of the Marcellus as being wet. Number one is that still accurate. And then number two, around that clearly with these pads, what kind of well cost savings should we continue to assume as this 10 well pad just is amazing. So, I’m just wondering, how much savings we could see because of these?

At this time, I’m sure you’re bored of hearing my voice. So, I’ll let Steve answer that.

Neal, I think regarding the breakout of wet versus non-wet that still holds. I will be clear on our definition of wet versus non-wet, because into those numbers is an 1100 Btu cutoff. So, I think that’s not always consistent amongst companies. But that’s what we’re using to come up with that number, but nothing has changed in that area. Regarding well cost savings, the average cost numbers that we’re using for our type curves incorporate the fact that some of our wells will be on 10 well pads. So, I think you will be safe to continue to use those type curve numbers. Neal Dingmann – SunTrust Robinson Humphrey: Okay. And then lastly, maybe Steve just following up as far as uniquely we’re able to cut CapEx a little bit even on the upstream side. Just wondering, when you look at lease expirations, again you generally haven’t had any issues there, will that continue to be the case?

Yeah, nearly, all of our acres is HBP. We have a small handful of drilling commitments that we’re easily able to keep up with. So really no issues whatsoever with lease expirations. Neal Dingmann – SunTrust Robinson Humphrey: Perfect. Thanks with the color.

You bet.

Our next question is from Michael Hall with Robert W. Baird. Go ahead please.

Hello, as a feeling we might have answer his questions already, or he is rushing out to buy more stock. Amy, are you still there?

Amy?

Yes. Our next question is from Anne Cameron with BNP Paribas. Anne Cameron – BNP Paribas: Thank you. Yes, I’m here. So just a question on the dropdown schedule, I know you don't want to talk about it too much, which you made a comment before I was just curious about. If you're going to fund CapEx at EQT with proceeds from dropdowns at EQM, I mean, just given the run rate of your spending this year, that implies a somewhat slower dropdown schedule than I was expecting if we slap in an assumption of like 10 or 11 whatever you want multiple on it. Can you just comment on whether or not the dropdown schedule could get ahead of your CapEx?

Well, certainly, it could, yeah because all of this is over time. I’m trying to talk – rarely will you find a quarter and maybe even a calendar year in which they just line up perfectly. So, yes, absolutely it is possible for us to run ahead. And I do realize that over a longer period of time, of course, there will be more dropdowns than there will be CapEx, more and more of the business will shift to EQM. The issue that we get into, the struggle that we have is trying to forecast what dropdowns are, frankly especially given the various disclosure constraints with the new entity. So, yeah, absolutely there can be periods of time even in the near-term when dropdowns run ahead of CapEx. Anne Cameron – BNP Paribas: And is there a target of how much of the EQM units that EQT wants to remain the owner of?

No, we do not have a – we do not have such a target. Anne Cameron – BNP Paribas: Okay. And how important are the IDCs from your drilling business in terms of shielding gains on sale from those dropdown?

That is definitely something that will be taken into account when there are timing dropdowns. Anne Cameron – BNP Paribas: Okay, I guess what I’m asking is, is there a scenario where you could maybe spin-off the LP and the GP and dropdown without those if those IDCs able there to shield it?

Sure. As you know, we’ve said that we are open to anything that create shareholder value. That is the tax attributes or something that or one of the issues that one ways when looking at those kinds of decisions. So, I don't feel that comfortable saying anything more than yes we would certainly take that into account, but it's not the – that's not the sole determining factor in anything that we do from a structural perspective. Anne Cameron – BNP Paribas: Okay, got it. Thank you, very helpful.

Our next question is from Becca Followill with U.S. Capital Advisors. Go ahead please. Becca Followill – U.S. Capital Advisors: Good morning guys. Four questions for you on Tennessee capacity, can you give us some more information on how much capacity you released of the total that you have and then how you expect that trajectory to change over time, at what point do you think you will be fully utilizing that capacity and not having to sell at a discount?

We will turn that one over to Randy.

Obviously, we have growing production option that we have with our Huron to move into that capacity, as well as some of our Tioga production. So, we do expect to utilize that capacity over time. While the market has been increasing, primarily the demand market around the power generation. It is seasonal it’s not a robust marketing summer. However, it is a constrained pipeline and as demand increases in the Northeast and supply, I think the value of this capacity will increase, but it is seasonal. But our intent is over the next couple of years to utilize that capacity primarily to move our product to market. Becca Followill – U.S. Capital Advisors: So, probably on a 2Q and 3Q level, we’ll usually see some maybe some discounting that not in Q1 and Q4 and then over the next couple of years and that completely goes away. Is that fair?

That's right, Becca. It is seasonal and I think that’s correct.

There is probably just to say, it does – the difficulty with looking at second and third, even though they’re likely not to be as good as first and fourth with the perspective in the market is. It’s really driven by extreme weather. So, it is certainly possible that extremely hot weather can drive demand just as much as extremely cold weather can drive demand. As we like to say around here, we’re more comfortable when you are not comfortable. The comfortable weather is not for the business. Becca Followill – U.S. Capital Advisors: Okay, thanks. And then on the MarkWest, the incremental $40 million a day, can you quantify about, how much liquids uplift you think you’ll get from that?

Well, we have a slide in our board presentation. I’m sorry with the Investor Relations website that calculates that Becca, it’s in the… Becca Followill – U.S. Capital Advisors: Okay, I’ll look at that.

Okay.

And so just to summarize Becca, we’re currently getting a half down per Mcf on average and that will go up to 1.8 is what we estimate. Becca Followill – U.S. Capital Advisors: On that incremental volume?

Right. Becca Followill – U.S. Capital Advisors: Okay, thanks. And then you talked last quarter about moving more to the wet gas area with the pullback in liquids prices, is that still the plan, has anything changed?

Yeah, it affects economics, but it’s still – you get more, look it’s just one factor. We still get more value per unit volume in the wet areas than in the dry areas. But it can certainly affect individual decisions. Becca Followill – U.S. Capital Advisors: Okay, thanks. And then the last question on the $65 million CapEx cut. I think the wording was that you refined your estimates. Can you give us any more information on what went into that $65 million reduction?

Becca, that’s really just having a better idea of exactly, which wells are going to drill, where we’re going to drill them, and when we’re going to drill, and then we did back in November when we put our original plans together. So, there is really nothing more to it than that and just more knowledge about specifically what’s going to happen in the second half of this year. Becca Followill – U.S. Capital Advisors: So, it’s not fewer wells or lower well cost, it’s more of the individuality of the wells?

Exactly. Becca Followill – U.S. Capital Advisors: Perfect. Thank you, guys.

You bet.

Your next question is from Michael Hall with Robert W. Baird. Go ahead please. Michael Hall – Robert W. Baird & Co.: Thanks. Sorry for missing the earlier call. Just quickly, I guess, couple of things on my end. Number one, and apologies if you covered this at all, but the backlog uptick quarter-on-quarter, I understand you are drilling more on pads. I’m thinking that probably is driving part of that. Do you expect that then to kind of maintain at that sort of level or how should we think about that?

Michael, this is Steve. I think we expect it to bounce around a good bit, because it is driven almost solely by the timing of these large multi-well pads we’re drilling. I would remind you that, we’re also doing a lot more fracs per well or per foot of well drilled than we used to, which also means there is more frac stages out there per well that can add to the backlog. But just to follow-up on the pad that Dave talked about, the pad in Greene County, where we have 10 wells. There is 203 total frac stages on that pad, which will be coming on line here over the next couple of weeks. So that backlog of 412, I believe it is a backlog of frac stages, half of those will be going away just in the next couple of weeks from one pad in Greene County. Michael Hall – Robert W. Baird & Co.: Okay.

So, it just happens to be very lumpy because of the timing of these things. Michael Hall – Robert W. Baird & Co.: Okay, that makes sense. I guess the other one on my end is a little more structural. In thinking, obviously now we’ve made our way through the MLP process, kind of begs the question, I suppose regarding the distribution business. How you guys are thinking about that in the grander scheme of things within the EQT corporate structure currently and to what extent is there our inability to I guess put away the production and unit from the others or desire I guess along those lines?

Well, first of all, I do not intend to make news on that front on this conference call. So, if you interpret any of my remarks is making news then please reconsider, but… Michael Hall – Robert W. Baird & Co.: Okay.

Yes, we did say that we are going to – once we get passed what we did with the Midstream, which is round up being EQM that we would again kind of resume looking at some of the other structural issues. And all I’d say on that front is, we just got finished with the MLP, and we’re really just kind of catching our breadth, and we’ll start looking at all the various possibilities to increase shareholder value. But I’d say it’s a little too – we’re just not that bigger company that we could report a lot of our resources management and otherwise into getting that in EQT midstream partners up and running. And so even though we have the opportunities start looking at other stuff. We’re really only at the very, very beginning of looking at other things. And I would limit that necessarily to just distribution. We’re looking at all aspects of our business to see how we can create more value. Michael Hall – Robert W. Baird & Co.: Okay. Is it fair to say that maybe by the end of the year, you will call your breadth enough that maybe you have some more, let’s say concrete thoughts around next steps?

I promised that by the end of the year, I will be able to answer that question whether we have it. Honestly, my view is we all learn things in new jobs and one other things I learned is not sharing too much about thought process. so I don’t know where we’ll – we try to make progress on creating shareholder value on virtually continuous basis, and I just think it’s – we’re in the same month as we closed an EQM going public. Michael Hall – Robert W. Baird & Co.: Yeah.

so I’d rather not put any timing commitments other than just to promise you that everything is always on the table, but that’s not news. That’s the way it’s been, I’d say, since I have been at EQT, our mindset has been everything is always on the table. Michael Hall – Robert W. Baird & Co.: Okay, that’s helpful. I appreciate it, and certainly understand like you said, just got out of the MLP. Thanks.

Thank you.

Our next question is from Chris McDougall with Westlake Securities. Go ahead, please. Chris McDougall – Westlake Securities: Thank you very much for taking the questions, gentlemen. I want a little bit more color on your natural gas drilling coverts, and that of running the rig off of natural gas. Two questions, so what percentage of the overall well cost is attributable to the diesel for the rig, and then what percentage for diesel overall, which I suspect is dominated by the frac stages?

Chris, this is Steve. I don’t have a specific number for you, but diesel cost as a percent of a total well cost is fairly small, certainly in single-digit percentages. So it’s not a huge driver towards the overall cost of a well, but it’s the little thing, it’s doing a lot of little things, adds up over time. So I wouldn’t say it’s trivial that we have a cost savings, but up in and of itself, it’s not a marked reduction in well cost. So what was the second part of your question? Chris McDougall – Westlake Securities: Yeah. So you had talked about this being a pilot program and I understand infrastructure and everything else has to kind of develop along with it. Do you have any thoughts on the timing for converting more wells or more drilling rigs to this and have you experimented at all with running the frac spreads off of natural gas?

Yeah. At the current time, I think as we speak, we have our second rig running on natural gas. So that’s two out of five of the Marcellus rigs. I think we’re going to see how that goes probably through most of the rest of the year. If it continues as well as it have so far, I would expect next year we’ll talk about trying to convert over the entire fleet, assuming that it continues to work well. We have had discussions about the frac fleet. That’s much more difficult problem to solve there. I think ultimately, our desire is to convert our frac fleets over to natural gas. but that is clearly going to take significantly longer than the drilling rig. So something we’re beginning to work on, expect it to take quite a while before you see us actually fracing with natural gas, with natural gas powered pumps. Chris McDougall – Westlake Securities: Okay, thanks. And just lastly on the rig cost, how much conversion cost do you have to – in a capital sense to convert one of these to run often natural gas?

I think it’s in total and for these first ones we've paid for it as a pilot program. We certainly hope in the future we can convince the drilling companies to make the conversions themselves. It varies a lot. I think it’s between $0.5 million and $1 million and the difference is for – when we want to operate with field gas, meaning taking gas off of one of our pipelines rather than LNG. We have to have a gas-conditioning skid, and the cost of that skid is about $0.5 million. But the cost of the gas is significantly less. So, from an economic standpoint, we think field gas will be the best way to go in the areas where it’s available and we can use it, in the areas where we can’t we’ll go with LNG. Chris McDougall – Westlake Securities: Okay, thanks a lot guys.

You bet.

Our next question is from Marcus Talbert with [Sevara Capital]. Go ahead please.

Hi, gentlemen, good morning. Thanks for taking my call. I had a quick question on the Midstream segment, given the way that you framed the capital budget for the company with the reduction on the upstream side. Just curious as to how the projects are coming along the gathering and expansion projects within the Midstream business, and if there’s been any change to the prior guidance in terms of how much you had planned to allocate to this project this year.

Hi, Marc, Randy Craw. No change in our forecast, and we’re on-time, on-budget. In fact our Sunrise project will be turned in line in the third quarter, August 1, and that that’s $300 million of their capacity on Equitrans, so we’re on-time and no changes.

Okay, thanks very much. And just one more quick question for me on the E&P business with this initial 10-well pad that you guys are putting in line in August. Is it that all 10 of these wells will be turned into sales during the month of August? And then just a follow-up in terms of the completion design; was there any differentiation between your standard frac design and some of the newer completions that you spoke about in the past?

Yes, all these wells should be online by the end of August. Three are currently online, those three are producing about 40 million a day as we speak, and over the next couple of weeks, we should have the rest in line. On the completion designs, there was a mix on this pad, but most of these wells used our reduced cluster spacing design.

Okay, great. Thanks very much guys for the color.

You bet.

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

Thank you, Amy, and thanks everybody for participating. We’ll see you next quarter. Thanks.

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