Good morning and welcome to the EQT Corporation First Quarter 2011 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 Patrick Kane, Chief Investment Relations Officer. Please go ahead.

Thanks, Andrew. Good morning everyone and thank you for participating in EQT’s first 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 Exploration and Production. In just a moment, Phil will summarize our operational and financial results for the quarter, which we released this morning. Then Dave will provide an update on strategic operational and regulatory matters. And 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. It should be noted that a variety of factors could cause the company’s actual results to differ materially from the anticipated results or expectations expressed in these forward-looking statements. These factors are listed under risk factors in the company’s Form 10-K for the year-ended December 31st, 2010 that was 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. And you can refer to the morning’s press release for important disclosures regarding such measures and forward-looking statements discussed on today’s call. 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 2011 earnings of $0.82 per diluted share, a $0.26 increase over EPS in the first quarter of 2010. Three items cumulatively added $40 million to our pre-tax income, or about $017 after tax earnings per share. The sale of the Kentucky processing complex resulted in a book gain of $22.8 million. There was also an adjustment for non-income tax matters that added about $13 million, and we recognized a $4 million gain on the sales some available for sale securities. Adjusting for those three items, EPS was flat with last year’s quarter, despite the fact that gas prices were considerably lower in the first quarter of 2011. Operating cash flow, which excludes the impact of gains on sales of the Langley processing complex and the available for sale securities increased by 22% to just short of $250 million for the quarter. Increase in cash flow comes as a result of another outstanding operational quarter across all three of EQT’s business units, including record produced natural gas sales, and continued low per unit development and operating costs for production, which were already among the best in the industry, another record and gathering in transmission volumes, lower per unit cost in our midstream business, and solid operating income at equitable gas. The operating results of this quarter were pretty straightforward. And I’ll just talk to them fairly briefly starting with EQT production, where the story in the quarter continues to be the growth in sales of produced natural gas. The growth rate was a little over 43% in the recently completed quarter over the first quarter of 2010, and sequentially a little over 11% versus the fourth quarter of 2010. That growth rate…

Thank you, Phil. We are off to a good start this year, but we still have a lot of work ahead of us in order to realize our potential from a shareholder value perspective. And we are determined to do so. Phil spoke about some of the operational results from the first quarter. And we are happy to answer additional questions you may have about our operations during Q&A, but we believe that this quarter’s results make it clear that we know how to execute. So I’d like to direct my comments to some more strategic issues for ourselves and the industry. 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, I committed to you that we would live within cash flow plus proceeds from asset sales. Our longer-term goal is to achieve organic volume metric and cash flow 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. We estimate that we can achieve this goal by 2014, provided we outspend cash flow by about 300 to $400 million per year for the three years between now and then. In total, this means a little more than the $1 billion in external capital from 2011 through 2013. Now, I wanted to discuss why we are very confident we can meet this target without tapping the equity market. First, of course, we funded the forecasted excess spending in 2011 by selling our Kentucky processing complex. Most of the remainder of our funding need could be achieved by the sale of our Big Sandy pipeline plus utilizing the additional debt capacity that…

Thank you, Dave. This concludes the comments portion of the call. Andrew, we’re ready for you open the lines for questions.

(Operator instructions) The first question comes from Neal Dingmann of SunTrust. Please go ahead. Neal Dingmann – Sun Trust: Good morning, guys. Good quarter. Say, could you give us a little more color on – you mentioned that you may not have seen enough results on those newer wells yet decide if you’re going to go with that design on all the wells, maybe give us an idea of is it the length, is it the way you’re fracking those maybe a little bit more color on why the wells are doing well.

We’ll let Steve handle that.

Neal, regarding the specifics of the technique we’re still not ready to talk about the specifics, a couple of things I’ll say though, typically 5300 foot length of well with the new design is quite a bit more expensive, probably about a million dollars more expensive. ` So while we are clearly seeing higher production rates initially, it’s very important that we get a little longer production history so we can accurately calculate the return we are getting for that extra million dollars. I can say we have about five wells so far that have more than 100 days of production with the new technique and they’re averaging a little more than 60% higher production over that time period than their offsets would be standard technique. So results are very encouraging, but it’s going to be closer to the end of the year before we talk in more detail about it. Neal Dingmann – Sun Trust: Okay. And a follow-up maybe on that a little bit. Are you convinced I know one of your peers has talked about maybe going to a shorter lateral, they think maybe you’re just trying to cut cost but you seem to imply that you think the lateral – the longer laterals are more well – you know, well worth that, maybe give us an idea of just your thought as far as the length versus the cost of these wells and what you’re seeing from these wells incrementally?

Sure. I think we are absolutely convinced that longer laterals are better, at least up to 9,000 feet, which is as far as we’ve drilled to-date. We do plan a few laterals this year, even longer than that, but at least up to 9,000 feet, we are absolutely convinced, based on what we’ve done, that longer is better from an economic standpoint. We think what you may be hearing from others when they’re looking at their all-in economics, is they’re factor in these lease obligations, so the drilling obligations related to leases. But if you factor in an assumption that you would lose leases because of failing to meet the drilling obligations, and then you might say that you would assume that you would have to pay market rate to get those leases back and you factored those into the economics. It is probably true that shorter laterals make more sense because what you want to do in that circumstance is touch as many of those leases as possible. Remembering that these initial lease terms, that the norm has been a five-year lease term, and some folks did, especially ones who moved to the Marcellus earlier than us, would be nearing the end of some of those initial terms. So from an all-in economics perspective for those companies, it probably does in fact make the most sense, until they’re – you know, until they’ve got the volumes flowing and they’ve honored the obligations, and then they’ll move into whatever seems to be most economic at that point. And it may also be the different parts of the state have different – there are slightly different geologies in different parts of the state. Neal Dingmann – Sun Trust: Sure. With your positive cash position, are you out there adding any leases, are you out there top leasing to your area, some bolt-ons, etcetera?

We have had a relatively modest leasing effort in the recent past. I’ll probably leave it at that. Frankly, we’ve been waiting for economic circumstances to have caused the lease bonuses to have dropped, though I have to acknowledge that doesn’t really seem to have happened very much. Neal Dingmann – Sun Trust: Got it. And last question, if I could. Just as production ramps up, will you continue to add the hedges on the out years, or what are your thoughts with the hedging?

Yes, we will. Neal Dingmann – Sun Trust: Okay. Thank you very much.

The next question comes from Scott Hanold of RBC Capital Markets. Please go ahead. Scott Hanold – RBC Capital Markets: Thanks, good morning, guys. I think you all mentioned that it looks like Marcellus well costs have moved up to around $6 million, and I think your prior estimated current data model is around 5.3 million. When you look at your 2011 CapEx, is there going to be – are you going to be spending more than you had planned previously, or is there sort of a mix shift activity that will offset some of that?

All of the – all of the numbers we’ve given you on volume guidance, Scott, are consistent with staying at that CapEx level. Now, look, we’ve talked about asset sales before, because part – realistically part of the grand plan is to monetize some other assets and ramp up, and eventually, as a result, ramp up the development pace and in that circumstance, absolutely you would see over some period of time capital going up, but we’re very conscious of the concern, frankly, that a number of investors have that we are not spending money before we have it. Scott Hanold – RBC Capital Markets: Okay. So just so I understand, you’re not – even though your well customer higher, you’ve not made a change to your 2011...

Oh, it’s the total number of wells actually has declined a bit as a result, but there is also longer laterals. Scott Hanold – RBC Capital Markets: Okay. And that when you amount of wells that declined you specifically talk about Marcellus wells?

Yes. Scott Hanold – RBC Capital Markets: Okay. And then...

One of the reasons we’ve tended to focus more on feet of pay and frac stages and things like that, as opposed to the well count itself. Scott Hanold – RBC Capital Markets: Okay. No, that makes sense. And then as you look, and it sounds like you’re doing a little bit more stepping out in some of your Marcellus areas and you’re seeing – it seems to be pretty good results, and you recently said you are drilling a well in Tyoga, how much just in general terms of your activity is going to be in the areas of like Tyoga where it’s a little bit of a stretch from where you’ve operated previously.

I’ll let – I think Steve is the best one of us to answer that one.

I think probably 15% of our wells this year would probably fit that category, although while Tyoga is probably the – obviously the furthest we’ve gone afield from most of our activity has been – it’s getting close to where lots of our competitors have drilled a lot of wells, so we have a high level of confidence in Tyoga, and now that we’re drilling up there, I think we have a pretty good spread across our acreage position with test wells of some sort. So our knowledge and confidence level in our acreage just continues to improve. Scott Hanold – RBC Capital Markets: Okay. Okay. Thanks. And one last question. You mentioned opportunity to monetize a lot of different assets, and you made a comment relative to below the pine PDPs are you considering something like a VPP, or would you not try something like its lack of better term, that exotic?

I don’t know that we would go with a VTP proper, but I love – Phil and his group have been looking at what’s out there and I’m happy to let him share any observations he’s got about what we’ve seen in the marketplace.

We’ve seen there are various factors out there with overriding royalty interests and VTP there is another structure that’s out there. I think my simple answer is we’re looking at all of that and comparing the cost of capital to some of our other alternatives to see which of those structures make the most sense for EQT. Scott Hanold – RBC Capital Markets: Okay. And when do you think we could get some, significant news flow on some things you’re actually going to going forward into doing?

Honestly I would expect that every couple of quarters you’ll be hearing something. Scott Hanold – RBC Capital Markets: Great. Thanks guys.

And I recognize when I say that that the first quarter you already heard something, which we announced and also closed on the Langly thing, and we would certainly expect that you’ll be hearing more very specific stuff in 2011, and then you’ll hear specific stuff in 2012. I mean that’s absolutely the goal. Scott Hanold – RBC Capital Markets: All right. I appreciate it, thanks.

The question comes from Michael Hall with Wells Fargo. Please go ahead. Michael Hall –Wells Fargo: Thanks. Congrats on solid results. Just curious, as I look at your current production guidance, what sort of 2011 Marcellus exit rate is embedded within that?

I believe we actually provided some of that. So Pat, why don’t you –

We’re 280 million projected at year-end, Michael. Michael Hall –Wells Fargo: Okay, thanks. And then, as you look at the cost structure, solid cost structure improvement quarter-on-quarter at the production level. How sustainable, particularly like on the LOE front, is that? Is there anything in that that would be more one-time in nature, or should we think about that as a fair run rate?

I think it is a fair run rate. The efficiencies that we gain in the Marcellus from the high production rates, the multiple wells per pad, as we do more and more Marcellus, that should only support those low LOE unit costs that we see. Now, obviously, the one exception is on production taxes. And I think Phil spoke to that. But you’d probably have to look at 2010 or 2009 as a better normalized rate, if you assume that there is some form of compact fee that eventually comes to Pennsylvania. And Randy is the best one to talk about it, if you want to hit cost structure on the Midstream side. Michael Hall –Wells Fargo: Sure.

Yeah. Well, Michael, with respect to that, again, when you work with the more pads per well and the longer lateral, the efficiency gains associated with the Midstream are also significant, and you can see that in the results. And essentially, less miles of pipe or more volume per mile of pipe capacity is what we achieve in Marcellus. I mean it’s actually with the longer laterals and more pads. And also, a factor in the environmental footprint that Dave had mentioned earlier. So those efficiency gains do translate in the Midstream cost reductions, as well. Michael Hall –Wells Fargo: Okay, great. And then as it relates to the future monetizations or potential monetizations, how does the storage and marketing business fit into that thinking? You’ve seen some pretty juicy multiples on storage assets recently. Is it fair to say that that’s also being considered?

You know, Randy, I’ll let you answer that one, too.

Well, I think there’s still – we look at everything in terms of the value proposition and what’s best to create shareholder value. Obviously storage, going forward, the spreads have been narrowing, but our judgment is that that’s a – it’s a key part of the growth in Marcellus and in this basin, creating demand and a need for storage. So we certainly would look at that, but we see that as an integral asset, as well, as we continue to grow our volumes going forward.

So if you know people who’ll call in on that one, what we’re telling folks who call on that, because I think we’ve now made it clear enough that we are open to just about anything that we actually do to get a fair number of inquiries. And it’s this changing dynamic in the Marcellus which gives us some pause on storage. We’re going to be moving away from long line pipes to bring gas into this region. It’s going to be more local production. And what’s going to be the role of storage is going to be a question. And when I say that, I recognize that it is always possible, though, to contract for storage, even if one doesn’t own it. It’s just that that’s an asset where the value is a little bit – it’s a little bit less clear whether the changes in dynamics in the market are going to – what effect they’re going to have on the value of the assets, compared to what’s going on in some of the other areas of the midstream further south of the Marcellus. Michael Hall –Wells Fargo: Okay. That’s helpful color. Appreciate it. Thanks, guys.

But everything we’ve got here, in case you are talking to friends and stuff, there’s a price for everything, so don’t be shy.

The next question comes from Becca Followill of US Capital Advisors. Please go ahead. Becca Followill – : Hey, guys. Two quick ones. I think the Greene County well that you talked about last quarter was completed using the new frac geometry, and that had a 30 day flow rate of 23 million a day. Can you tell us what that well is doing now after – what is it, how many days?

I’ll be honest, Becca, I don’t have that data with me. I can’t tell you. Call Pat later maybe. Becca Followill – US Capital Advisors: Okay. I’ll do that. And then just to clarify, you guys had talked before about a 20% growth rate longer term, living within your means, now upping CapEx by 3 to 400 million over the next few year and picking up by 30%. If we see some assets over the next three months, would you go ahead and start upping CapEx spending for 2011, given that you’re already above that 30% level?

Yes, but the practical reality, given that most of the money for the Marcellus, at least, is spent on fracing, would be even if we were making a commitment, most of that would – or a big chunk of any increased commitment that we would have would, under the scenario you described, would probably still show up in 2012, and with the volume showing up in 2012 and then out years. So the short answer is yes, but I wanted to make sure you had a better feel. But with the pad drilling, we do have longer lags on when the money actually gets spent versus committed. Becca Followill – US Capital Advisors: Yeah, I’ve got that, Phil. I just wanted to make sure that you guys would put that money to work pretty quickly. You wouldn’t say, I am going to save that for the next year, I am going to go ahead and start...

And honestly, the reason for that – at one point I was thinking we would, that it would be a rainy day fund or something like that, and frankly now, based on more of the work that we’ve done in the asset market, our view would be, no, that would come from the next, you know, if we wanted that, that would be the next asset sale. Becca Followill – US Capital Advisors: Great. Thank you.

Next question comes from Rhett Bruno of Bank of America/Merrill Lynch. Please go ahead. Rhett Bruno – : Hey, guys.

Hello. Good morning. Rhett Bruno – Bank of America/Merrill Lynch: Can you give us an update in the waiting on completion backlog in Doddridge County and where you are now production-wise relative to the remaining capacity, and if there was any surprises from the wells that you would have brought on late in Q4 or Q1?

Yes, great question. Some of them were asked. We have had an email match – we have had a fairly significant backlog in Doddridge Country primarily because we’ve been drilling some pretty large multi-well pads, and as Dave said previously, we take a fairly conservative approach to not having simultaneous operations on the pad. So we’ve had a backlog build up here recently, now we’ve begun to work that down. And just this week, we started turning in line a 7-well pad in Doddridge County, six of those wells are – have been in line for 24 hours or more, as I speak. I can tell you the average 24-hour rate from those six wells is 9.2 million cubic feet a day. These were relatively short lateral wells due to the nature of the lease, the average lateral length was 2,970 feet and we had average of just under 11 stages per well. So the total up all is IP, it’s a little over 55 million a day total. You want to talk to the capacity.

Sure. I mean in (inaudible) Steve with the excellent results, we’ve positioned ourselves to stay out in front, and we positioned to have 70 million a day out of the West Virginia, and we are – one of the positive aspects of that is at a higher BTU gas, and we have JT skids there to extract and to meet the pipeline quality. Going forward and the previously announced agreement with MarkWest on the processing facility, is in the next year is when we’ll be able to expand additional capacity over and above the 70 million a day. Rhett Bruno – Bank of America/Merrill Lynch: Okay. Great, thanks.

The next question comes from Josh Silverstein of Enerecap Partners. Please go ahead. Enerecap Partners – excuse me. Josh Silverstein – : Hey, good morning, guys. Just following up on the midstream and takeaway issues. Could you just kind of walk through the planning stages of how you guys are looking at developing the Marcellus capacity over the next few years with significant growth there, how you’re trying to kind of stay ahead of that, since it seems like most of the bigger producers are starting to bump against their current capacities, and are having to expand faster than they probably thought they would have to?

First, Randy is going to answer that. But we have become one of the bigger producers. I think that the – missed some, but we have actually become one of the bigger producers on the Marcellus, but that said –

No, absolutely. And you’re right, we work, of course, Steve and I and the two teams that work hand in glove to ensure that the development plan and the midstream plans are working together, and they’ve done an excellent job, and we’ve been focused in, in a couple of primary areas, right our Greene County and our Doddridge area and we’ve been able to build out the additional capacity in those areas. One of the benefits of the Marcellus, just so you are aware, is the higher pressure wells, and so we do take advantage of some of those higher pressures, so as we stage in the larger diameter pipe, the longer lead items such as compression that we can stage in as the wells are brought in line, and so that’s how we look at it, is that we put the Bates infrastructure in and then we bring in the compression as the wells come on. With respect to our Equitrans asset, as we previously announced in line, we turned on line in excess of a hundred million a day of capacity this year, we have an additional 400 million a day that we are through the certificate process that will be coming on in 2012. And again we’ve at EQT in terms of the commercial we’ve always been proactive on the downstream capacity commitments on the interstate pipelines. We have a large position on Columbian transmission to move our HERON gas. We’ve been – we have a contract as you’re aware of with the Tennessee gas pipeline for 350 million a day that moves our product even further downstream into a northeastern market. And also with segmentation provides the flexibility to move an additional 300 into the south market. So again, that’s how we look at it, we work closely together. We built out the infrastructure and we have – I think an excellent track record of being out in front and doing just that. Josh Silverstein – Enerecap Partners: Got you. And then, you know, just looking at the frac inflation cost, or I guess the well inflation costs, I was curious if this new frac geometry is a way to reduce some of that inflation, or even lower some of well costs?

No, in fact just the opposite. The revise design would raise our per well cost and per stage cost. However, what we’re waiting to see is if that incremental investment is justified by the higher production and reserve. So, we’re going to wait until later in the year before we start drawing conclusions on that, but – so the goal is per unit costs going down, but per well or per stage costs would certainly go up. Josh Silverstein – Enerecap Partners: Gotcha. And then lastly for me, just want to see if there’s any update on drilling into the other formation for the Utica, Upper Devonian or other stacks?

Well, we are certainly looking at those and watching what our competitors are doing in those areas. I think the Upper Devonian, we have drilled one well in the Upper Devonian several months ago in West Virginia. And we will drill at least one more this year in Southwestern Pennsylvania. Our plans for the Utica right now are to sit tight and watch what our competitors are doing, and if that ends up being the next big thing, we’ll be right there with them. Josh Silverstein – Enerecap Partners: As you know, we pride ourselves on being innovate in a lot of areas, but we have thought that it is more prudent for us for the time being to focus on getting the most of our Marcellus position. And actually for that matter Huron as well. But we do pay close attention to what the other companies in the area are doing in the Upper Devonian and the Utica. And eventually we’ll hopefully figure out what works and we’ll jump right in.

Good. Thanks, guys.

The next question comes from John Abbott of Pritchard Capital. Please go ahead. Raymond Deacon – : Yeah, hey, this is Ray Deacon. I was wondering, Steve, if you were to correlate the 9.2 million a day IP rate, 24 hours to your experience in Green, what would that kind of correlate to like a 5 or 6, 7 BCF well or–?

Well, I think, I mean, I just do the simple math for you, if you double the lateral length from those, from our experience we would double the initial rate. So you’d be looking at a 5300-foot lateral well with 18 million a day IP, if you just double those averages. And I think – I’m not going to quoting the UR, but you can probably go back to numbers we’ve published before, and see what an 18 million a day IP would – might look like. Raymond Deacon – Pritchard Capital: Got it. Great. And why did you have to drill the shorter laterals in West Virginia. I thought you had a pretty key blocky acreage position in...

Well, we do generally, but we have a lot of leases and a lot of acreage in certain areas, the short laterals just fit better than longer ones. And that was the case on this lease. So, we can drill economic wells with extremely short laterals, down well below 2,000 feet per well, and we’re still generating excellent returns. So when we have to drill short, we will. Obviously when we can drill longer, that is our strong preference. Raymond Deacon – Pritchard Capital: Got it. And did the 9.2 million a day that would have had a pretty big liquids component, I think?

Well, its – the BTU content is about twelve fifty in that area. Raymond Deacon – Pritchard Capital: Okay. Got it.

But you are aware that our processing – the processing plant that we’ve -where we’ve contracted for capacity, that MarkWest facility is not going to be ready until next year. Raymond Deacon – Pritchard Capital: Got it.

Right now the only way to get any liquids out, actually get liquidities out, is to use these little J.T. skids. And what kind of extraction do you actually get when you’re using those?

Per Mcf if you’re getting in the range of between 0. 5 and a gallon of 1 – 0.5 and 1 gallons. Raymond Deacon – Pritchard Capital: So this is what you would expect from a plant...

A Cryo about 2.5 gallons, and so that’s – and then we – we’re essentially meeting the specs and we blend the gas and we’re able to move that way. So overly not getting much in the way of – we’re getting the benefits from liquids and that you’re getting more BTU per unit volume, but we’re not getting the pick-up in the premium – really much of a pick-up for a premium in per BTU value, those liquids, until that plant is... Raymond Deacon – Pritchard Capital: When that plant does come on line, where do you think the 7% liquids contribution could go to, I guess?

Yeah, so I’m not sure that it goes – in that area, of course, it’d be higher than 7%, because that was an average number across all of our properties, but the issue, if you’re getting it, about the ethane, it’s more of a question of when do the ethane markets start delivering better value per BTU than methane. And when we follow the reports of folks, who are coming up over other ways to move the ethane, it doesn’t strike us that they’re getting any better than ethane prices. So the real issue is making sure that you – you’re moving ethane, so that you can get the gas to pipeline quality, not really to get a pick-up in per BTU pricing. Does that – hope I said that in a way that my – that it’s clear. Raymond Deacon – Pritchard Capital: Great. No, that makes sense.

I mean, obviously, it would be great if we had robust ethane markets here, and a bunch of us in the industry are looking for those types of longer term opportunities to see if we can get those, but right now we’re really just talking about folks making sure they can move the ethane, so that they can, so the gas can lock. Raymond Deacon – Pritchard Capital: Got it. And I guess, Steve just one quick follow-up. I’ve had a couple of people tell me, the completion costs were up sort of like 10% sequentially in the Marcellus, and I was just wondering how shielded are you from furthering increases with the contracts you have in place?

Well, generally speaking, the contracts we have are for frac services are basically fixed plus variable, so a lot of the consumables we use are variable, and we have seen – I think on average about a 7% increase in those over the – sequentially from the prior quarter. Much of the rest is fixed, but they can still vary based on a few indices. So as inflation picks up, we may – we are subject to some continued costs increase, but I think we’re pretty well mitigated from the supply/demand pressures that we’ve seen in the past. So when there’s no a lot of activity and operators are willing to pay whatever it takes to get a frac crew, and prices shoot up, we’re insulated from that, at least through the end of the year. Raymond Deacon – Pritchard Capital: Got it. Okay. Thank you.

The next question is a follow-up from Scott Hanold with RBC Capital Markets. Please go ahead. Scott Hanold – : Yeah, thanks, guys. Hey, real quickly, could you remind me what – I guess in the last quarter, what was the EBITDA from the Big Sandy system was?

Can’t remember exactly what we said, but it’s in the $25 million range.

(Inaudible).

25 to 28 I think.

Yeah.

I was...

Annually.

Yeah. Scott Hanold – : Annual. So in theory, we’re talking about something like 10 or so multiple on that, so you’re probably looking at something close to nearing $300 million, monetize that? Does that sound reason?

Or so. Well, I wouldn’t call us with an offer for 300. Scott Hanold – : Understood. Appreciate it. Thanks.

The next question is a follow up from Michael Hall with Wells Fargo. Please go ahead. Michael Hall –Wells Fargo: Thanks for the follow-up. Just quickly, curious on the kind of longer range growth, you talked about trying to get to 30%-plus annual growth, and in the next couple of years, like you said, that requires some outspend. Does that suggest, then, that’s the kind of level of growth you would expect in the next couple of years, or is that – may be gear up to get to that level? Obviously, this year you’re going to be above 30%, but just kind of get a feel for 2012.

I’m sorry, could you – I’m not sure if I followed all – your... Michael Hall –Wells Fargo: So you said, you’re trying to get a long-range CAGR of 38% per year or better.

Yes. Michael Hall –Wells Fargo: In terms of production growth, and that’s going to require some outspending. I’m just trying to understand, does the initial couple of year period, the 2012 to 2013 period, is that lower than 30%?

No, no, no. no, I’m sorry. No, I wouldn’t. We wouldn’t see that being lowered. As a matter of fact, the way we kind of seen that two is that we’d be talking about a more of a several year CAGR, even though we’re only talking about outspending for three years, so it kind of gets the machine going. And in fact, by the end of that period is when you probably start dropping down a little bit. When you’re – obviously, it is difficult to grow any business at 30% – any capital instance of business at 30% while living within cash flow indefinitely, so we actually rely on the jump start kind of front end load a little bit of that. Michael Hall –Wells Fargo: Okay. I didn’t know if you needed some sort of jump start and spend to get the growth later, but...

I actually think about this a lot. That is happening now. And we’re already benefiting from some of that lag, because we have put money in – obviously, we have outspent our cash flow for the last couple of years. Michael Hall –Wells Fargo: Right, right.

So we’re actually getting – we actually are benefiting from the fact that that occurred over the last year or two currently. And that would – we would anticipate that continuing, but it does mean that that’s – that’s why we do feel some urgency to make sure we keep that going. Michael Hall –Wells Fargo: Okay. That’s super helpful. Thanks.

The next question comes from Rhett Bruno of Bank of America, Merrill Lynch. Please go ahead. Rhett Bruno – Bank of America/Merrill Lynch: Hey, guys. Just one quick follow-up on this resized sort of capital outlook you guys are talking about. Is the midstream spend, does that change? Could you give us some idea on the run rate maybe the next two or three years?

No, I think the – probably the ratio that we spend on midstream to total remains pretty similar to what it is in 2011. Obviously, that’s a lot lower than what it had been. Rhett Bruno – Bank of America/Merrill Lynch: Okay. All right. Great. Thanks.

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

Thank you, Andrew. That does conclude today’s call. The call will be replayed for a seven-day period beginning approximately 1:30 PM Eastern Time today. The phone number for the replay is 412-317-0088. The confirmation code for the replay is 447030, and it’s also available on our website for seven days. Thank you, everyone, for participating.

This concludes the EQT Corporation first quarter 2011 earnings conference call. Thank you for attending today’s presentation. You may now disconnect.