Good morning, and welcome to the EQT Corporation Second Quarter 2011 Earnings Conference Call. All participants will be in a listen-only mode. (Operator Instructions) After today’s presentation, there will be an opportunity to ask questions. Please note that this event is being recorded. And now I would like to turn the conference over to Patrick Kane. Mr. Kane, please go ahead.

Thanks, Keith, and good morning, everyone. Thank you for participating in EQT Corporation’s second quarter 2011 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 E&P. In just a moment, Phil will summarize our operational and financial results for the second quarter, which we released this morning. Then Dave will provide an update on our development programs and strategic operational matters. Following Dave’s remarks, Dave, Phil, Randy and Steve will all be available to answer your questions. But first, I’d like to remind you that today’s call may contain forward-looking statements related to the 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, 2010 that was filed with the SEC, as updated by any subsequent Form 10-Qs which are also filed with the SEC and available on our website. Today’s call may also contain certain non-GAAP financial measures. Please refer to the morning’s press release for important disclosures regarding such measures, including reconciliations to the most comparable GAAP financial measures. 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 second quarter 2011 earnings of $0.58 per diluted share, 190% increase over EPS in the second quarter of 2010. Three items cumulatively added $17.7 million to our pre-tax income, or about $0.07 per share to EPS. The purchase of the outstanding interest in ANPI, an off balance sheet structure set up to fund the acquisition from Statoil in 2000, resulted in a book gain. As we consider potentially more complex financing alternatives to fund our significant growth opportunities we have looked for ways to clean up and simplify our already relatively simple structure, and the buyback of ANPI is an example of that. There was also an adjustment for non-income tax matters and a gain on the sale of some available for sale securities. Even after adjusting for those three items, the EPS in the second quarter of 2011 increased 2.5 times over the second quarter of 2010. Operating cash flow, which for the most part excludes the impact of the three items I just discussed, increased by 66% to $189 million for the quarter. The increase in cash flow comes as a result of another outstanding operational quarter across all three of EQT’s business units, including record production and midstream volumes, and continued low operating – unit operating costs, which were already among the best in the industry, as well as solid operating income at Equitable Gas. The operating results in this quarter are fairly straightforward, and I will start with EQT production where sales volumes continue to grow at a record pace. The organic growth rate in the recently completed quarter you saw was 43% over the first quarter of 2010, even excluding 1.4 Bcfe of volumes from the ANPI transaction.…

Thanks, Phil. This was yet another strong operating quarter as we continue our efforts to maximize shareholder value creation from our core strategic assets. The two topics to which I’d like to devote most of my time this morning are the positioning of our Midstream business within the strategic framework of the company, and separately, some comments on legislative and regulatory issues in the Commonwealth of Pennsylvania where we’ve just completed work on the Governor’s Marcellus Shale Advisory Commission. First, to set the stage for my Midstream thoughts. During the past year or so, we have talked quite a bit about addressing our greatest strategic challenge, applying capital to our best investment opportunities. Last year, we committed that we would live within cash flow plus proceeds from asset sales. Last quarter, we communicated a longer-term goal to achieve organic volumetric and cash for growth north of 30% per annum in production, and associated cash flow growth in the Midstream while living within operating cash flow, that is without proceeds from asset sales. The estimates that we can achieve this goal by 2014 was predicated on the assumption that we can outspend cash flow by about $300 million to $400 million per year for the three years between now and then, or a little more than $1 billion in external capital from 2011 through 2013, without tapping the equity market. We have made significant progress towards making that assumption a reality. First, of course we sold the Kentucky processing complex in a transaction that was announced and closed in the first quarter this year. Next, we sold the Big Sandy pipeline in a transaction that was announced in the second quarter and closed at the very beginning of the third quarter. Those two transactions raised about $600 million. For the remainder,…

Sure, Dave. As you know, last fall we began testing a new frac design, which we’d hoped would result in both accelerated production and increased reserve recovery from our horizontal Marcellus wells. We call this design our 30-foot cluster spacing test, and the design basically involves using 150 foot frac stages with 30 feet between perforation clusters, versus our standard design of 300 foot per stage – 300 feet per stage with 60 feet between perf clusters. With this design we pump the same amount of water and sand per foot as we do in the standard design, but we achieved double the injection rate per foot versus the standard. The theory behind this design is to focus the hydraulic energy into a smaller volume of rock thereby creating a more dense induced fracture network, and increasing the recovery factor for that volume of rock. Additionally, we did expect to see accelerated production in addition to the increased recovery. As we noted on the last earnings call, and Dave just mentioned, we are seeing around 60% higher early time production rates from wells that used the 30-foot cluster spacing design. But it will take a significant amount of time to accurately quantify the level of increased reserve recovery we are seeing. That is still true and we don’t expect to be discussing levels of recovery or projected economics until the end of this year at the earliest. Today we’re posting two slide on our website which provide a little more detail. The first is a schematic showing the stage and cluster spacing for our standard and 30 foot cluster test wells. The second is a micro seismic survey we conducted on two parallel wells, one with the standard frac design and one with the 30 foot cluster spacing. This survey was designed so that we had a third listening well located directly between the two test wells, which provided excellent data quality in the survey. As you will see on the slide, the well with the 30 foot clusters achieved similar frac half lengths and total stimulated volume but had more than three times more micro seismic events than the standard design. While this is only circumstantial evidence, we are encouraged that this supports the theory of creating a more dense fracture network. Much additional analysis is required before drawing economic conclusions about this design, but we continue to be encouraged by the results we have seen, and will continue to provide additional details as we continue the test.

Okay, thank you Steve. Keith, we’re ready to open the call for questions from our investors.

(Operator Instructions) And the first question comes from Michael Hall with Wells Fargo. Michael Hall – Wells Fargo Advisors LLC: Thanks, good morning, everybody. Congrats on a solid quarter. Just curious, I guess a little more clarity on the commentary around strategic decisions, make sure I’m understanding it correctly. I guess first, am I hearing you right that option 2 then is kind of off the table? And then as a follow-up, am I understanding also then that the MLP option, option 3, in your mind only make sense if you decide to kind of further expand your activities in terms of sourcing – or serving rather third parties?

Not exactly. Actually none of those alternatives are off the table. The only thing that is off the table is routinely using our own capital to build out our Midstream business. At some point, the issue was only where does the external capital come from. If at this point even though we haven’t reached final conclusions, the bias is – that we’ve got now is, if we decide that we want to have a more aggressive growth plan in Midstream we’re best off using – having the external capital come from an MLP, either on our own or with a partner. Whereas if we decide that we’re going to limit the Midstream to going more after Equity, just supporting Equity production that external capital will come from more one-off transactions, either selling assets the way we’ve been selling with Langley and Big Sandy, or possibly taking on a partner. But that we probably wouldn’t want to go down the road, if that’s what we do, of having the administrative issues associated with an MLP? One way or another, the big picture is that, we don’t really want to be devoting a lot of our – let’s call it, C-Corp capital to – net, to expanding the Midstream business. One way or another it’s going to have to come from external capital. Michael Hall – Wells Fargo Advisors LLC: Okay.

And I don’t mean equity of course, I mean the MLP market or asset sales are in whole or in partnership? Michael Hall – Wells Fargo Advisors LLC: Okay. And in terms of creating – if you did go out of creating your own MLP and kind of raising capital in that way, is it still possible or is it at all possible that at some point then you consider kind of spinning off those, that part of the entity and at some point having a standalone upstream C-Corp?

Yes. That’s actually another conclusion that we’ve reached, I guess I just figured I’d get a question, and now I have, is that we have also concluded that having an MLP is not inconsistent with any of the structural alternatives that one might reasonably assume that we would look at. And look, we recognized that the issue for our company and for other of our peer companies is that the extent of our investment opportunity is greater than the – exceeds in dollars the amount of capital that we have available. I mean, we laid out a viable plan for a certain level of development, but that doesn’t necessarily mean that that’s the optimal plan. So we certainly recognize an issue we’re going to be dealing with is, if we wanted to ramp up development more we need to move further down that road. So basically, though, we have gotten ourselves comfort that whether we had an independent Midstream business or a Midstream business that’s associated with, we stay as a certain C-Corp, an MLP is really a better way to raise the money for the Midstream business. So we don’t – and incidentally, we further decided that, I think we have gotten ourselves comfortable that if we ever did split the business that it would probably have been best to do the MLP first. Michael Hall – Wells Fargo Advisors LLC: Okay.

Because we’ve looked at that sequencing issue too. Michael Hall – Wells Fargo Advisors LLC: Okay. And then I guess timing on your final decisions around this, any?

Well, the final decisions of course on all kinds of strategic issues get made by the board, but the normal timeframe for us to really dig in to the strategy issues is about this time of year. So it’s going to be during the course of the third quarter and – well I guess I’ll say through the remainder of the year we’re really going to be working through this particular issue in a big way. Michael Hall – Wells Fargo Advisors LLC: Okay. And then just on that new frac geometry, just curious, if it indeed is successful, does it imply then that ultimately tighter spacing per well would also then be required to maximize recoveries, or is that, am I making the wrong assumption or conclusion on that?

I don’t think we’re ready to draw conclusions on that yet Michael. It could imply that, but we are not – we don’t have enough data yet to really draw conclusions. Michael Hall – Wells Fargo Advisors LLC: Okay. And then I guess final one from me, housekeeping, on the ANPI, what did you pay for that? Sorry, if I missed it.

We took on a debt liability. Actually the best way to handle this, it is sort of complicated and we’ll get into a lot of accounting journal entries. Why don’t you call Pat, and he can walk you through it. But basically high level, that was an off balance sheet financing we did when we bought Statoil. It only had a few more years to run on it. There was a lot of administrative burdens associated with it, so we decided to bring it back on the balance sheet and simplify. So the reserves and production came back on the balance sheet as well as some debt liabilities and a couple of other liabilities. And the net effects are we told you production’s up about 8 BCF initially annually, and that declines. EPS is up only very, very slightly, less than $0.01 a quarter, and cash flow is basically – operating cash flow is up a little, but total cash flow’s sort of neutral because there is a debt service component that includes interest and debt repayment, and like I say that’s probably more information than you want, but that’s the high level story. It’s really just a simplifying transaction. Michael Hall – Wells Fargo Advisors LLC: Okay. That is helpful. Thanks. I will follow up offline.

Thank you. And the next question comes from Neal Dingmann from SunTrust. Neal Dingmann – SunTrust Robinson Humphrey: Good morning, guys. Good quarter. Say, either for Dave or Steve, just wondering on the production guidance now that you have laid out sort of for the remainder of the year, and a little bit obviously into next year. Could you break that down a little bit as far as maybe more detail as far as number of Huron and Marcellus wells anticipated, and then within those how many you anticipate I guess will use the new technology or technique?

Yes Neal. We’re anticipating right around 100 Marcellus wells for the year, and 120 Huron wells for the year. And right now with the new design somewhere between 20 wells and 24 wells. Neal Dingmann – SunTrust Robinson Humphrey: Okay. And then either for Dave or Randy on the Midstream, just kind of wondering – it looks like obviously Equitrans continues to add, or the phases continue to go along I think as you had planned. Maybe just remind me as far as kind of the next couple of phases, or what benchmarks we should be looking at for the remainder of the year and then into next year on it.

You know, I’ll let Randy handle that.

Yes. I mean Neal, as you know, we put the first phase in at the beginning of this year for the 100 million a day, and we are focused on adding 130 million a day in 2011, with a project in to the third quarter of 2012, an additional 430 million a day in the Equitrans phase. Neal Dingmann – SunTrust Robinson Humphrey: Okay. And then last question if I could. Just wondering on sort of -- I guess two things I guess actually. One on differentials. Looked like you continue to be very positive there going into this quarter. Wondering going forward if you think that those will remain about the same? And then just hedging, are you comfortable now where you’re at, or will you add a little bit more along the way.

Well on hedging we are going to continue to re-look at where we want to be. I mean honestly given where our economics are we kind of like where the prices have been. Since our development pace is dictated by cash flows, what we’ve really tended to focus on is to see if we can get more stability around our future cash flows, because that facilitates making the type of longer term drilling rig, frac crew, etc. commitments that help us reduce those costs over time. So no I wouldn’t necessarily say that we are done with our hedging. Maybe – for 2011 it almost becomes just a commercial matter, it’s not really hedging, it’s what do you want to sell at. But I wouldn’t say that we’re necessarily done at 2012. I understand that we’ve added a fair amount since the last time we put out financial results, and certainly with 2013 we’ve really only just begun to lie in some hedging. We’re focused on cash flow stability, so as prices move up that helps us with that cash flow stability, that feeds in to our ability to accelerate the development of the reserves. Neal Dingmann – SunTrust Robinson Humphrey: Yes, great point. And then last question Dave, just one around M&A. You obviously have most of your production held so that’s not a big issue, if there is more Marcellus and acreage in the region for sale, given you are outspending cash flow will you continue to look for M&A deals, or do have enough acreage sorted at the time?

We are certainly interested in tactical acreage acquisitions. I guess what I’d really – and the way I’d think of that, is as we’ve mentioned before there is a fair amount of the acreage we have, and it’s not unlike the situation of other companies, but a fair amount of acreage that we have that doesn’t really permit the extended laterals that we would like to have. Certainly doesn’t permit the multi-well pads with everything having extended laterals. So to the extent that we can get other acreage around us, lease other acreage that would allow us to go from either short laterals or fewer wells per pad up to more wells per pad, extended laterals that’s attractive to us. Now this Marcellus Shale Advisory Commission did recommend with both industry and environmentalists supporting it, that we come up with a better pooling statute in the Commonwealth of Pennsylvania, and that would of course help. And actually a similar issue exists in West Virginia. So some of the view that we have on leasing acreage also is going to be impacted by where the legislation heads in Pennsylvania and West Virginia on pooling. Neal Dingmann – SunTrust Robinson Humphrey: So you anticipate you will in addition to M&A would do more pooling as well Dave?

Yeah, pooling is – well, clearly that’s a more – that can be a simpler way to save some of the money upfront. But we are looking at the tactical – at tactical leasing. And we recognize incidentally that that means that we need to be more open to asset sales, whether via MLP or straight sales, than is necessary – than what we laid out in that kind of $1 billon over three-year timeframe. I mean, it would have to come from that, we’re not going to be going to the equity markets for that. Neal Dingmann – SunTrust Robinson Humphrey: Okay. Thank you.

Okay, and the next question comes from Josh Silverstein from Enerecap Partners. Josh Silverstein – Enerecap Partners: Hey, good morning, guys.

Good morning. Josh Silverstein – Enerecap Partners: It looks like you guys have been getting pretty efficient on turning the wells that were spud to the wells that are completed. It looked like by the numbers you gave it was about 30% a year ago to 60% now. Is that basically just a move to pad drilling, or is there anything else that you guys have done to gain that efficiencies, and where do you think that 60% could get to over the course of the next 12 months?

I don’t know that we really look at it that way, but really what I think is happening is that we’re able to co-ordinate our Midstream and Production business a little bit more closely than other companies are, because we control the Midstream. And incidentally, that said, we do recognize that a variety of folks in the midstream business who chat with us about alternative approaches tell us that we could achieve that through partnerships or contractual arrangements, but a close coordination between midstream and upstream is what helps us on that front, I would say. But I don’t know that we’d say we had a target. We’re always going to have some wells that are -- I think we laid it out in the table in the press release. There is always going to be gaps between the wells that have been permitted but not spud, spud but not TDed, TDed but not frac’d, frac’d but not tilled. There is always going to be stuff. Josh Silverstein – Enerecap Partners: Right. I was just curious if there was more sort of delays on frac crews there, if you guys are looking to add dedicated frac crews, because it seems like as soon as your rigs are moving off the pads, one or two days later the wells are starting to get completed.

Actually that then is within production. They have just done a good job, and I think they’ll – I’m confident they will continue to do a good job coordinating between the rigs and the crews. I mean we do tend to have longer-term commitments to both drilling rigs and frac crews, so that they are more under our control. We’re not going pad by pad. Josh Silverstein – Enerecap Partners: Got you. Then the average lateral length you said was about 5,300 feet. I was curious how long you guys had tested, and if you think you are still moving towards even further, if you’re going out towards 6,000 feet or 7000 feet as kind of an average?

As far as -- the longest laterals we’ve drilled so far are right around 9,000 feet. We are trying to permit a well as long as 12,000 feet. I don’t think that would likely be drilled until early next year at this point. We do, our philosophy is to drill the longest lateral we can. As Dave mentioned earlier, we are frequently limited by the lease geometry we’re faced with. So -- and especially until there’s some better pooling regulations, that’s kind of what limits our averages right now. So we do expect the average to continue to go up. I don’t think we’d expect a quick jump up to the 6,000 foot range in the short-term, but they will continue to increase.

That reminds me. One comment I should have made to an earlier question about acreage is, we are much more actively involved in discussions about acreage swaps with other producers than historically we have been. So that of course is another way that we could head towards optimal. I don’t know that we have a view on what optimal length is right now, other than a view that generally speaking the land situation prevents us from getting to the optimal length on as many of the well locations as we’d like. But that’s another tool in the tool kit. It doesn’t just have to be pooling or lease acquisitions. It can be acreage swaps as well. Josh Silverstein – Enerecap Partners: Got you. Then lastly for me, on the new frac design, I know you guys will be talking more about it later on this year. But I was curious if the kind of the implied thought that you would be looking to keep a similar well count kind of year-over-year but your production rate could grow 30% to 40% just based on putting that new design in, or would you still grow the total well count next year and then going forward?

Well, optimal – our assessment of optimal is above the type of growth rates that we’ve talked about before. But the capital will come from internally generated cash flow or from sales of assets or opportunity. So really it’s going to start with how much capital that we have available and go from there. And again, we do recognize, it’s been pointed out by a variety of investors, so that EQT along with our peers eventually may wind up being capital limited in pursing what is optimal on our own, and that is obviously strategically something that we are going to continue to wrestle with. Josh Silverstein – Enerecap Partners: Got you. Thank you.

Okay, thank you, and the next question comes from Becca Followill from U.S. Capital Advisors. Becca Followill – U.S. Capital Advisors LLC: Good morning. Two questions for you. One, on you evaluating strategic options on your Midstream business, does this mean that your goal of being free cash flow positive in 2014 is moved forward?

Certainly we could get free cash flow positive, and if you mean cash flow minus CapEx, but the odds are that we would wind up turning around and investing that business in accelerated development. I think transactions that we have seen out in the marketplace have pointed out that entities, that have what for practical purposes looked to us to be unlimited amounts of capital, have an ability to accelerate the development beyond the capability of companies such – that are our sized. And therefore getting – increasing the value of our company is probably going to continue to be tied to trying to pull forward that development of the resource, as much as we can. But again, subject to the constraint that we actually agree with the investors that we should not be tapping the equity markets for that. Becca Followill – U.S. Capital Advisors LLC: Great. And then on the new frac geometry, why today show us the geometry and what you are doing, but not to put out results? And I understand that it takes a year of data, but why are you guys giving us that information today? And I think before when you talked about the incremental cost it was $1 million, and now it’s $1.6 million. What’s changed there?

Well, I think the reason we are not giving conclusions yet is because we don’t have conclusions yet, so. But we did reach the point where I think for competitive reasons, enough information was leaking out, and most of our competitors were fairly aware with what our design was, there was really no advantage to trying to keep that a secret any more. So that’s why we decided to talk more about the specifics. I think we’ve said all along we won’t be drawing conclusions for quite some time yet. Regarding the cost, that’s a mixture of things. Some is we’ve been experimenting with – the design hasn’t been completely static the whole time, so we have been tweaking it some. And the latest version is a little bit more expensive than where we started. That combined with oil field inflation that we have seen since we started doing this has contributed. And some of it’s just around because it involves a lot more activity on site in terms of setting plugs, and there is a lot of down time. Honestly, early on it was hard to estimate what the costs would be, since a lot of service providers didn’t really know how to price it. So now I think we have done enough. They know how they are going to price it, and we know what it’s going to cost. So I think our cost estimates are just more sound now.

So to kind of reiterate that first point, though, Becca. The reason we weren’t providing details about this previously is for competitive reasons. We really didn’t have a great interest in sharing that with our competitors. We’ve become aware – and we know that that information eventually leaks out, but we thought why help the cause. And we’ve become aware over the last couple of months or so that through service providers et cetera that the information has gotten out to the point where frankly it’s probably only the investor community and analyst community that wasn’t aware of what we were doing. So we figured that we should levelize the knowledge playing field. Becca Followill – U.S. Capital Advisors LLC: Thanks. And then would it be fair to say that even if you’d planned originally to drill a certain number of wells using this new frac geometry, that as you drilled your first one late last year, that you wouldn’t be continuing this if you didn’t think that there – the economics in it was higher EURs per well to justify the higher cost?

I think in an experiment like this there are sort of several outcomes. One could be that from the initial results were below expectations and it was clear that it was a failure and we would discontinue. Obviously we haven’t done that. The other outcome for this kind of thing is results are at expectation or above, but because of the nature of what we’re trying to do you need a substantial amount of history before you can draw firm conclusions about the economics, and I’d say that’s where we are at. So you can conclude that the initial results were not bad enough for us to pull the plug. And I think we have given some indication of what we’re seeing in the 60% higher IPs versus offset wells. So, and that is in the range of what we were expecting to see. Becca Followill – U.S. Capital Advisors LLC: Great. Thank you guys.

But it’s still true that it’s not clear to us that we would want to do this if in the fullness of time, as it were, it seems as it the only thing we are doing is accelerating the production from given EURs. So that’s what takes time. Is to see, compared to the offsets, what does that decline curve look like. And is this in fact just accelerate – to what extent is it acceleration, and clearly there is a lot of acceleration going on, and to what extent is it higher recovery factors, so higher EURs.

And I guess one thing I would add is for the cost that we’re quoting, the $1.6 million for our type well, for this to be an attractive economic opportunity for us, we need to see about 10% higher EUR per well. So 10% or better this would be a success below that we probably wouldn’t adopt it.

So you could also then conclude that we certainly have not gotten to – I guess in the scientific sense, we had not rejected the hypothesis that this was attractive. Becca Followill – U.S. Capital Advisors LLC: Thank you guys.

Thank you. And the next question comes from Phillip Jungwirth from BMO. Phillip Jungwirth – BMO Capital Markets: Good morning, guys. What is the goal for the Huron in terms of production growth? Kind of the multi-year goal. Is it to keep production flat there, grow it single-digits or double-digits, or could you talk about that?

I don’t think we’d say that strategically the goal there is necessarily tied to a particular volume growth level. As with everything of course, the goal is to extract as much value as we can from that asset, and it’s a long-lived asset. We’d certainly like to figure out a way to accelerate the monetization of that asset. I think it remains to be seen whether that’s entirely through the drill bit, or whether in some form or fashion that is a candidate for some other form of monetization, at least partially. Phillip Jungwirth – BMO Capital Markets: Okay. Have you looked at the royalty trust option for that asset or your CBMS?

I’ll let Phil speak to that.

We are looking at it. We haven’t made a conclusion yet on that, but it’s -- we’re certainly aware of that structure, and we’re looking at it to see how it compares to other, the cost of capital of our other alternatives. Phillip Jungwirth – BMO Capital Markets: Okay. And then...

Can’t rule out the joint-venture structure for Huron either. I mean there is a variety of things that still look like they could be attractive with regard to getting that, pulling that value forward in the Huron. Phillip Jungwirth – BMO Capital Markets: Okay. And then can you update us on your latest thinking around the utility given that you should be building up quite a bit of IDCs, which would help shield any tax gain from the sale of that asset?

Yes, at this point it’s small enough that compared to the rest of the company in my view, and Pat you can’t quite reach me to kick me if you don’t like what I’m saying, but I think that decision should be subsidiary to the broader decision about the structure of the corporation. Phillip Jungwirth – BMO Capital Markets: Okay.

If we wind up going down the road of splitting it, I think you don’t worry about the LDC first, you do the split first, and then you let that subsequent company worry about the LDC. If you decide, you’re going to not do that, then I think it makes more sense to revisit, okay, now what do we do with the LDC? But I think the first thing you decide is what to do with the broader structure. Incidentally, we went through that logic on the MLP also, and we reached the conclusion that you want to do the MLP first regardless of which way you go on structure. I mean we looked at that, we studied it, we got advisers to help us with it, and we concluded that it won’t – that won’t preempt either direction we might want to go on structure. And in fact if you want to do an MLP your probably best of doing it before you make that – you execute against that. With the LDC I think it’s the flip side. I think you wait until after you’ve made the structure decision. Phillip Jungwirth – BMO Capital Markets: Okay, makes sense. And then Marcellus average lateral lengths continue to increase, they averaged about 5,000 feet in the quarter up from 4,800. Should we expect you to be averaging the 5,300 and the type curve by kind of late this year, or when should we expect you to average 5,300 for well spud.

I think when we look at lateral lengths by quarter, you’re likely to see a fair amount of variability quarter-to-quarter, because it’s very much driven by the specific, completely driven by the specific wells we drill in a quarter. I would say, generally speaking, I would expect it will be around that 5,300 foot average next year. But any given quarter could be plus or minus several hundred feet, so. Phillip Jungwirth – BMO Capital Markets: Okay. And then last, do you have any well results to talk about from Tioga County or West Virginia?

Well, first in Tioga County, we are currently drilling up there, Randy’s group is constructing a pipeline to get the gas to market. We don’t expect any production results until the very end of the year. So our first opportunity to talk about it would be the first quarter call.

Full-year call.

Full-year call. So nothing really to report there other than the drilling is going ahead fine and then the pipeline constriction is moving ahead on schedule. In West Virginia I have a couple of things I can tell you. On the last call we talked about a six well pad with nice results in Doddridge County. Just to complete the set, I can tell you that the seventh well on that pad was the best one. It’s 24-hour average IP was 11.6 million a day, which would pull that average up a little bit. In total, since the last call, we’ve turned in line 15 wells. 13 wells of those 15 wells were curtailed in some way during their production since that time. So the IP rates probably aren’t particularly representative of the capability of the wells, but those 15 wells averaged 6.8 million a day in their first 24 hours, all in West Virginia. Phillip Jungwirth – BMO Capital Markets: Okay. Great. Thanks guys.

You bet.

Thank you and the next question comes from [Mike Mattis] from Citibank.

Hi, congratulations on a good quarter. I just had a quick question. I was unsure as to what equity production actually means when you were talking about the different scenarios you could go through?

What we’re referring to there, of course that’s in the context of Midstream, is EQT’s production versus other producers production. So even – I mean if there were other, and the rare occasion that we might have other working interest owners in a well of ours, we tend to really include that as traveling along with equity production. But we’re really talking about a decision to spend extra money on Midstream with the objective of being able to gather gas that is produced by other operators.

Okay, and just another one, if I may. And I understand if you don’t want to answer directly, but one of your peers went the route of actually doing a two step kind of IPO of the E&P business. I was just wondering why or why not that might be considered, or not, an alternative?

Well we’re looking at a variety of alternatives. I mean I think we all – my impression from talking to our – most of the peers is we all – of our size, is that we all realize that we’ve got this huge investment opportunity and that the size of our company makes it problematical to attack that opportunity in a optimal way, and we are all finding our own ways to deal with that. So nothing is off the table.

Okay. Understood.

And incidentally, seriously, if others of you have ideas, we do think – I get one or two people around here chuckle, but seriously, we are not – we have no pride about it being our idea. We are happy to execute against somebody else’s good idea. So, if you have stuff to consider I’m happy for you to throw it into the hopper. We just want the best answer for – we’re not painting a picture or something here, where it’s got be, it’s pride of authorship. We’re just trying to create value.

Understood. Thank you.

Okay. There are not any more questions at present time. I would like to turn the call back over to management for any closing remarks.

Thank you, Keith. That concludes today’s call. The call will be replayed for a seven-day period beginning at approximately 1:30 PM Eastern time today. The phone number for the replay is 412-317-0088. You will need a confirmation code for the replay, that code is 447030. And the call will also be replayed for seven days on our website. So thank you, everyone, for participating.

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