Good morning. My name is Samara and I will be your conference operator today. At this time I'd like to welcome everyone to EQT First Quarter 2009 Fiscal Earnings Conference Call. All lines have placed on mute to prevent any background noise. After the speakers' remarks there will be a question-and-answer session. (Operator Instructions). Thank you. Mr. Kane you may begin your conference.

Thanks, Samara. Good morning, everyone and thank you for participating in EQT Corporation's first quarter 2009 earnings conference call. With me today are Murry Gerber, Chairman and Chief Executive Officer; Dave Porges, President and Chief Operating Officer; and Phil Conti, Senior Vice President and Chief Financial Officer. In just a moment, Phil will briefly review a few topics related to first quarter financial results which were released this morning and provide a liquidity update. Then Murry will provide an update on our drilling program and other operational matters. Following Murry's remarks, we will open the phone lines up for questions. But first, I'd like to remind you that today's call may contain forward-looking statements related to such matters as our well drilling program, infrastructure development initiatives, growth rate, storage and marketing prospects and other financial and operational matters. Finally, it should be noted that a variety of factors could cause the company's actual results to differ materially from the anticipated results or other expectations expressed in these forward-looking statements. These factors are listed in today's earnings release, the MD&A section of the company's 2008 Form 10-K, the 2009 first quarter 10-Q that will released later today as well as on our website. Any required reconciliations are included in today's press release and are posted on our website. With that I'll 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 2009 earnings per diluted share of $0.55 which compare with earnings per share of $0.57 in the first quarter of 2008. The first quarter was a strong operational quarter for the company and I'll get into the details of that in a couple of minutes. However, quarterly results were obviously negatively impacted by the current commodity price environment. That environment impacted EQT results in three different areas, first, lower NYMEX unrealized gas prices reduced EQT production revenues. Second, lower NGL prices reduced revenues in EQT Midstream's processing business. And third, seasonal -- lower seasonal spreads reduced revenue in Midstream storage business. In total, lower commodity prices resulted in about $48 million less revenue in the current quarter versus the first quarter of last year. And again I'll go into greater detail of all of that in a minute when I briefly discuss results by business unit. The other main variance to keep in mind when comparing our results to Q1 last year is the $40 million reduction in incentive compensation expenses. So starting with EQT production operating results, the big news in the first quarter at EQT production was the 18% increase in average daily sales volumes versus the first quarter of last year. We continue to reap the benefits of all the work we did in 2008 and into 2009 and we continue to be very encouraged by the sales growth result that Murry will talk about that in a minute. But the bad news of course was the volume increase was more than offset by NYMEX price that was 39% lower and an average wellhead price that was a $1.5 per Mcf lower or 20% lower than in the…

Thanks Phil. And good morning, everybody. I just want to give a couple of comments on the overall operations of the company. First of all, importantly as Phil mentioned growth -- sales growth is up 18% quarter-on-quarter. Virtually all of that is driven by our Huron and Ba Ria play, where of course we pioneered horizontal layer drilling and this play as you all should know is just at the front-end of it's dramatic growth track. We're still sticking to a $1 billion in CapEx this year focused on drilling. We are still planning 675 wells, horizontal wells about 375. To reiterate our breakeven price is $2.50 at NYMEX and we make 8% after tax IRR at $4.50 NYMEX. First I'll talk about the Huron play, as you all recall the Huron play has multiple zones. So far this year we've spud 57 gross horizontal wells. So far since the inception of this play, we've got 540 horizontal air drilled wells under our belt so we're really getting the benefit of that knowledge in our activities. Our drilling efficiency for example, we continue to make progress here. In 2008, a single leg completed Huron well cost roughly $1.2 million. In 2009 we're expecting that same well to cost roughly $1 million. These cost savings are mainly attributed to learning curve which is about half of that savings. We do steel cost about a quarter and reduced drilling services and completion cost about another quarter. I would like to talk about a new thing that we've been experimenting with and that's our fractured multilateral wells and actually stacked and fractured multilateral wells, we're calling stack and frac around here. We have spud a total of 16 multilateral wells so far and plan to drill at least 25 in 2009 and possibly…

That concludes the comments portion of the call. Samara, can we please now open the call for questions. Thanks.

(Operator Instructions). Your first question comes from the line of Scott Hanold with RBC Capital Markets.

Good morning.

Hi, Scott.

Hi, lots take any -- lots going on, Marcellus, first of all I know you guys don't like to sort of cite IP rates, but can you kind of give a little bit of color on some of the recent wells what you've been seeing, I think the industry has been above that -- at or above that 5 million in day rate. Have you seen stuff somewhere to that, and also on the Marcellus, with respect to where you've done from your drilling, now some of your competitors have talked about in part the Greene County that it's actually pretty good guess, where you don't have the processing to do in there? Are you seeing the same thing and how widespread do you think this could be?

On the second point first, as I mentioned earlier, we haven't seen a lot of need for processing yet, we know others have. And I think there is going to have to be more drilling done to really outline the wet dry boundary if you will. Actually we are starting to think that it's not just a line that might be a little more complicated than that. But in any event, we are cautiously optimistic that not as much processing is going to need to be required as perhaps others had thought previously. On IPs I think Scott, we're sticking to a 30-day IP, we haven't had headline 30-day IPs, others have had higher 30-day IPs than we have, you can make your own conclusions from that. But interestingly, our EURs are pretty much in the range with what other people have set at 3.2 Bcfe and that's reflective of what we are observing to be and this is the importance of doing 30-day rather than initial IPs. We are seeing a little flatter decline curve and I know it's early but that is somewhat encouraging. So we don't have the headline IPs, but on the other hand our EURs are very much in line with what we are seeing and certainly within what would normally be considered natural variability in a system that's controlled by non-linear differential equation. This is not linear stuff. This is non-linear, and so we're quite encouraged by the EURs.

And then are you drilling and fracking in the extra Marcellus now relatively--

Yeah, we are but I'll tell you what it hasn't made much difference to be honest with you, one way or the other, it's made a little difference. And I think on the margin fracturing techniques can help, but I think you are going to see, a reasonable amount of variability but I think the wells we've got particularly, if we can get these costs down to 3.5 to 4, which our guys are sure they can do, we'll make for a very good play.

We are on the steep side of the learning curve for Marcellus horizontal right now. That's -- we don't like to yield a handful of -- folks have drilled more than that. And we are seeing improvements in result and techniques, we're still refining things. We analyze to what we see in the lower Huron and we're still making improvements in the lower Huron but that's part of what's going on with us too. So there is geographic variability and we're seeing a lot of improvements kind of on a real-time basis, they just don't show up in some of the results that we report.

Right.

So it's really both things. And I think Dave is right, I think the improvements and just learning curve improvements are going to have some impact on the cost, no question about it. But we should be prepared to see variability from plays-to-plays and I'm not surprised that in our wells that we have a little lower 30-day IPs, I'm very encouraged though that EUR is even with a few wells are as high as they are and so within the range of what other people are talking about.

Okay, okay. Good. And the prior point, we're talking on the quality of gas that--

Yeah.

It sounds like butane and propane hasn't been an issue for you yet and can you just give us an idea, yesterday on of your competitor indicated that they drilled in a tight spot in Greene County, what counties have you also seen similar things then?

Tight spot meaning?

They're drilling those pretty localized, they've really just stepped out of the whole lot in Green County?

Yeah, I mean what we're, Scott what we're going to do of course, we expect this natural variability I mean that's just the way it is. But and that is why we're committing to a much broader program of horizontals the 45 to see how much this geographic variability, see what it is. We're not scared of it, we just want to understand it in total and that's why our wells are going to be spread over a fairly large area. And now we're balancing that a bit with putting some wells where we've got suction systems being developed and where we have existing high pressure gathering because we want to get this gas to market so we can watch it flow for a while. So we're sort of balancing drilling close to infrastructure and that goal. We're balancing that goal with the goal of testing geographic variability and given our vertical program we saw a lot of wells that had tight spots if you will and that's the reason why we think that horizontals are the right way to go, where I think the horizontal well generally averages a vertical well, because that's just taking a little sample in a fairly a vertical uptick -- a fairly small sample in a small area. So I don't know if that answers your question or not.

Yeah, it does to a certain extent. And I am just trying to figure out how this sort of geographical anomaly, how expanded it is? Where you get sort of the good quality gas and then given the data point so far?

What I think is, I think my view is and you can take it or leave it my view is the play is going to be fine, its going to be a good play, a very good play but we should expect to see some variability that's just the fact.

Overtime all of us are going to figure out more of where those sweet spots are and obviously overtime, you are going to see us drilling a heck of a lot more wells, you see sweet spot. So I think you are going to see a bunch of us who wind up finding the various sweet spots and then we can see -- you see a lot of concentration of drilling around there. That's just not where we think it's best for us to go right now, we are trying to look on our acreage for where more of those, where those sweet spots are.

Okay.

But we'll find the things sweet spots are obviously more than going to balance that with drilling a lot of wells--

Right now in same area.

But the bottom-line is if we get 3.2, 3.5 Bcfe per well on average, I am confident that our team is going to get the cost down to make that a very, very profitable play.

Okay.

And we don't underestimate the extend to which being close to an existing pipeline system which is more I mentioned, we are quite confident, we can re-imagine or reinvent as a Marcellus header system is going mean that the economics are further improved.

Okay, guys I appreciate your time. Thank you.

Your next question comes from the line of Raymond Deacon with Pritchard Capital.

Hey, Murry. I was wondering if you could just walk me through the economics again of a piece of frac and stack wells and what could this do to the 450 sort of breakeven economic price?

Well. I am not really ready to change that much. I mean we have had F&D cost cut in the $15 to $20 range so to speak, I really think, this is going to take it below a dollar clearly. As we tune this process up and hopefully employ this as a standard operating procedure down the road. I mean, we are pretty excited about this, particularly in light of the fact that we have so much capacity down south to be able to feed this gas into and the fact that we are going to get a lot more gas per pad and have a lot fewer -- a lot lower need for gathering lines. We are going to have bigger -- fewer bigger gathering lines and that is a tremendous benefit to the Southern Appalachian region which is quite hilly and difficult to operate it. So when you add the straight line lower F&D costs for drilling and the efficiencies that you get by having more gas per pad with the lower gathering cost, I think it's going to have a pretty substantial impact on overall operating cost and F&D profitability. But so I am not ready to say it's $4 instead of $4.50 but for breakeven but it's going to be lower than in the future, if this pans out, the breakeven is going to be lower than it is currently.

Right, okay, got it. And so your in terms of the rigs that you'll need, is there much of a change that needs to happen there, at all?

No, no, no change whatsoever.

Got it. And I would think your recovery of gas in plays would be higher because of where you are?

Yeah, that's going to take some time exactly I hope so too, Ray, I really do, I would be okay if we're just getting higher initial rates and the same reserves, that would be good. But I think it's going to take some time in watching these wells for a while to determine how much extra EUR or as you said how much extra recovery efficiency will be gained by this new technique. So that's going to take some time to figure out.

Just one -- one more quick one with the reduction in the cost to pipelines do you look at all that -- the overall CapEx budget and think about maybe reallocating some dollars into the back into the midstream that you had cut in, I think it was December. Do you think the current allocation stays where it is?

I think we need to right now, Ray, I mean I no, the short answer. We've got this the reinvention of Equitrans might require -- is going to require some capital. No question about that, we're not, Dave and I aren't quite ready to make the big commitment there. Obviously, we want to see what others -- what other producers are going to want to do, because we'd like to have them join in with us on that project. But that going to -- that's not going to occur in here right, Dave?

It won't be and at this point we're really concentrating more on -- our working hypothesis right now is reallocation within the midstream segment. Let me guess we're kind of focusing on now is -- we're going to go to a point where the two big priorities for us are the slower Huron play and the Marcellus. And I think you are going to see more and more of the midstream dollars supporting exactly those two priorities.

Got it. Great, thanks.

Thanks, Ray.

Your next question comes from line of Jim Harness (ph) with Barclays Capital.

Jim? Jim, you are very quiet. Okay we take the next one please.

Just a moment please.

We've rendered Jim speechless.

Your next question comes from the line of Becca Followill with PQT.

PQT, good morning.

Becca hi, send your resume, we're happy to consider.

Several questions for you one on the Equitrans, it's likely you talked about, what's the cost to do this -- what's the timing to do it? How do you handle your existing firm transportation customers, is this conceptual or is this, how far long are you?

We're to the point Becca where it is. We know what we can do physically, that is to say; we know how we would be able to change the capacity and reroute it in a way to be able accept to both serve the market here, and accept Marcellus gas. We have a lot of work to do on the regulatory side, let's put it that way. To figure out how we are going to present this new capital program to the regulators and just figure out all the pieces of it. And frankly, we need to make sure that we've canvassed the producers appropriately to make sure that we are getting support. As I mentioned, we have a tremendous amount of interest in this high pressure gathering, that is the launch pad for the Marcellus, is this high pressure gathering. And so we expect to have a lot of partners on this, won't you say, Dave?

Right now, as far the conceptual issue, we haven't really begun construction of most of the things we need, but we have identified about a dozen and a half specific projects. Some of them not very expensive, some of them more expensive. And which ones you -- which ones we undertake first and what kind of combinations we undertake, are going to depend as Murry said, and what those discussions with the producer come in at a yield. Because as you know unlike the other areas where we operate on Kentucky et cetera, we are not the dominant producer, this stuff will move a large percentage of the volumes, would be third party volumes. So we need to make sure that we are working closely with the producer community to figure out which of these projects make the most sense, which combination of the project make the most sense.

And the other thing, Becca is, in our 45 well expanded horizontal program, because we weren't going to drill this many horizontals in Marcellus, we are intending to use that program also as Dave mentioned to scope out where we think the hot spots are in the play. And that will direct us to which Equitrans pipeline projects we want to undertake too. So it'll be both to serve our needs and others, so it's going to take a little while to suck that out.

And just one other things we've identified is, that there are some interstate transmission companies that also have some, what we would think would be economical expansion opportunities, depending on -- they just don't need to undertake them right now. But depending on what we choose to undertake with Equitrans that we presume that they would undertake those other projects, but we have to have discussions with them to get ourselves comfortable with what they're timing is versus our timing.

So just kind of back to the original question is, the cost to do this?

These are going to be attractive for Equitrans, but we don't really want to preempt the -- since a lot of this is jurisdictional, we'd rather not preempt that discussion.

Okay. About the timing?

Timing, I think by the end of this year I think, we'll be in a position to have a firm plan on exactly what's going to happen on Equitrans.

And then you would make a filing and--

Yeah.

So realistically it's probably two and a half years?

No, no. we're not -- I should have probably mentioned that earlier, some of these projects could be very expensive, but the good news is the write-aways are there, and projects are relatively small. A lot of times Becca, we're upgrading pipe sizes where in the past they've been downgraded because of lack of activity here in Pittsburg. Pipelines have -- 8-inch pipelines have four inch replacement pieces, right? As you know, you put a four inch replacement piece in a six inch pipe or an eight inch pipe, it's now a four inch pipe, the whole thing. So there are replacements like that, small interconnects, looping and there are some big projects don't get me wrong, some very expensive big projects that are needed as well but, it's not like a Big Sandy type Greenfield project. This is a Brownfield project and therefore, cheaper to do probably, less time laps.

We'd expect, some of these projects to be underway this year. And some of these projects are just not, some of them are larger as might you say, and some of them just aren't very large at all.

So we'll start doing construction this year but the time lag even on a big ones are not going to be more than a year or so.

So it would be a reallocation of capital; some other midstream projects typically--

Yeah.

Not incremental capital?

Yes.

Okay.

Yes.

Yes, that's correct. And you know you probably have the second Equitrans, it's a system of pipes. It is not one pipe. That is one when Murry mentioned Big Sandy. That's the difference. It's a system of pipes. So some projects really only makes sense, if you're also going undertake other projects. That's where the discussions with the transmission companies on one side and the producer community on the other need to be undertaken. We don't want to even undertake inexpensive projects if no one is really going to need it.

Yeah.

Okay. And then back to the big picture question which you've kind of addressed but I wanted to hit on it again is only four horizontal Marcellus wells completed so far which means you are very early on a learning curve and everyone of course is still going to make comparisons against rates that we're seeing from capital range which are considerably higher than those rates.

Right.

Is the higher rates a function of just want to make sure that's where you are in the learning curve or is it your completion technology is where you think that maybe you don't get as much in the IP front but you get it in the ultimate reserves or where is the delta?

I think it's all of the above plus geographic variability which you left out of those -- of that equation. I mean any of those hypothesis at this point are valid and I don't know which one is going to rise to be the most important of those three. I will say though that as is the case with any of these play which is surely is true in the Huron that we expect to see some improvement in costs because of learning curve. That is no question and obviously that has an impact on profitability. We are also expecting to see some marginal improvement on frac techniques but nothing that would double the reserves or double the IPs and then you cut the geographic variability to consider as well. Again we are not afraid of that, its just something that you should expect to see in a play of this magnitude and in this breadth.

Now frankly, we are confident of moving up the leaning curve more quickly than we probably even did with the horizontal program in the lower Huron because we are kind of on an island there, we were basically learning from ourselves, we tried to learn from service providers et cetera. We do -- the advantage of not being the leader in the Marcellus horizontal is that we can go to school on other folks in addition to work on our internal issues.

But all three of those hypothesis are equally valid Becca.

Okay. And then last two clarification questions. Competing in TA, the 290 permits that were led through April 7, are those Marcellus permits?

Yes.

Okay.

We had the stats.

Okay. And then the cost for an eight inch pipe, you said it's going down to $400,000 a mile from what was the original?

Seven.

700,000.

700,000 yes. Very significant decrease.

Okay, thank you.

One final point at the permitting just to you all. We are -- we really are pleased with where the government is, the state government is on permitting base, they have been, it is a long road, they haven't had to do this before but they are trying to be supportive of the industry. They're trying to understand the industry's needs and issues and they're to be supportive.

Okay, thank you.

All right.

Your next question comes from the line of Jin Luo (ph) with JPMorgan Chase.

Hello.

Hi, my questions has been answered. Thank you.

Okay.

You have a follow-up question from Scott Hanold with RBC Capital Markets.

Hi, again. On the stack and fracs the 25 you are targeting in 2009, well I guess this will be multilateral wells, how many of those are going to be stack and frac?

I am not sure what the mix is yet Scott. We're just kind of getting these things going and as I mentioned, we have got this 110 well and so 10 are going to be one Scott basically. And then we'll do as many other ones as the results, as we are led to do with the results that come from those wells.

Okay, okay. And--

A good percentage of them will be stacked and fracked, yeah.

Okay. And just to clarify you've drilled how many stack and frac so far?

We've got -- we've drilled two sets, two on one pad that I mentioned to you, two on another pad that had been drilled and we're just now getting some of the results from those. So two sets of two, so far. And then -- pardon me.

Okay, no, go ahead.

And then we're going to expand one of those pads to include more wells and then we've got this 10 well pad basically that I mentioned in my comment.

Okay. In the -- what kind of theory you're going on and then what you want to try to do. Would you like to frac both the pads for horizontal?

That's a good question. We're experimenting with that right now. We -- in that first second frac, the frac should the lower Huron. We took the Cleveland naturally and we believe that this remains to be seen with more production date, but we believe that the frac at Huron actually had an impact on the Cleveland, positive impact on the Cleveland. And we are not sure we understand that exactly we know it did have an impact, we just don't understand why it had an impact because we had produced the Cleveland multilateral before the Huron frac and then we produced that after and it went up. So we've got some work to do there and trying to understand how far these fractures are going, we are doing some more technical work to try to understand that a bit better. But the current theory, the current working hypothesis is that we probably fracture both zones unless one of them is producing a natural of above 0.5 million a day and I mean 0.5 million initial like first few days production. It is not producing at about 0.5 million in the first few days, we'll go back and then fracture it.

Okay.

But that's just a rule of thumb now and it has a little deterministic, scientific background to back it up, that's just our current rule of thumb.

Okay. And still a thought on when your frac it -- what you do at the horizontal well with the lining and what not with the prices you're going to go right now?

What we are doing is we are drilling the multilateral well we are not actually putting the fractures into the laterals. We are just isolating each leg of the fractured multilateral and fracking all the way down on it. So from the motherboard all the way onto the lateral. At some point in time, the guys think maybe it will get cheap enough and it really is a cost issue and maybe it will get cheap enough to be able to actually to put the packers plus tool in each one of the lateral legs and frac those frac have a multi stage within the leg we are not doing that right now. We're fracking the leg from the motherboard.

Okay.

So and that's really the reason we are doing it is for cost considerations right now and some it's a bit of technical there's some technical issue of isolation also that we have to overcome. But that's our current hypothesis. But I'm glad you raised the question because fracking the individual lateral life could be another step up, true in terms of recovery. So we've got a lot more to do on this Huron play. And the team has just done a fabulous job in bringing us as far as they have.

Okay. And what is the exact -- rough distance between the Cleveland and the Huron if there's sort of any kind of interaction that's helping one and the other?

It's 300 feet.

Okay.

Yeah.

All right, appreciate it.

Okay. Thanks.

Your next question comes from the line of Mark Caruso (ph) with Millennium Partners.

I just had a two quick questions. One was I didn't hear earlier, I thought that if I missed it, what the debt-to-cap ended up this quarter? And the second question is just you mentioned earlier the operating cash flow and the short-term debt? And I just wanted to can you update your thoughts on how you're thinking about addressing any shortfall, if you take advantage, we seem some other guys take advantage of the capital markets recently on both the equity and the debt side, just want to get your update thoughts on that?

The updates that I gave in my comments suggests that if we did not, which we think is the worst case to function, did not access the capital markets between now and year-end, we have short-term debt of 8 to $900 million. Some people have access to capital markets, I think they did so earlier in the year rather than later. We were tied up with S&P ratings process and when we came out of that process, the market wasn't quite as good in March but we're watching that. And our preferred price to beat the end of the year is not 8 or $900 million of outstanding short-term debt. On the debt-to-capital, we are going to have a Q coming out later the day and you'll be able to get it right out there, we didn't say anything about that on the call.

Okay. Thanks guys.

Thank you.

Your next question comes from the line of Annon Nome with Deutsche Bank.

Hey, my name is Shannon. How are you?

Hi Shannon. We know who it was?

Sure. I guess just to piggyback on that then I had one other question, to take the phrase that you used was terming out that debt, what's the appetite for equity at this point?

Not this year. I mean we have been consistent with shareholders on that channel; we are not backing off of that.

Okay. And then so I apologize if you went through this I missed it, but your DD&A, it came in a little higher than I thought, LOE was a lot lower and I just wanted to get a sense of the sustainability or anything unusual about either one of those two?

I think LOE could be a little bit seasonal Shannon, and I think our inclination would be that last year number was a better number, that tends to be a little bit seasonal. On DD&A, that should just be the math of the capital we spend and the reserves. I don't think there is anything unusual going on at all there but if you struggle to make that connection when the Q comes out later today, you got a give Pat or myself a call.

Will do. Thanks.

Thanks Shannon.

Your next question comes from the line of Holly Stewart with Howard Weil.

Hey guys, good morning.

Hey, Holl.

Two quick ones, you guys mentioned your two biggest priorities being the lower Huron and the Marcellus, I think if I had to nail it down I would have said the lower Huron in the Ba Ria has anything changed in your mind, one?

No, I'm sorry to glance over that. It is lower -- and one thing the Ba Ria in with a lower Huron, it's another zone, low pressure. It will be prosecuted with the same technology, it could be part of a stack multilateral system as well. So I'm sorry if I was unclear about that.

Okay. And then do you have any update for us on the Ba Ria, I guess I would have thought that we would have maybe gone EU or is that a Ba Ria before the Marcellus, so just curious if you have an update there?

Yeah, I didn't get an update and that's probably just a myth on our part, we should do that, maybe we will do that, we'll try and do that a little bit later. We were just focusing so much on the fracs and--

You can do it right now if you like.

I just don't have the numbers exact -- all the well numbers exactly in front of me, so I don't want to do that.

Okay. Fair enough. Thanks.

At this time there are no further questions. Are there any closing remarks?

Yes, thank you. That concludes today's call. The call will be replayed for seven day period beginning at approximately 1.30 PM Eastern Time today. The phone number for the replay is 706-645-9291. You'll need a confirmation code to access the replay. That code is 94253440. And the call will be replayed for seven days on our website. Thank you everyone for participating.

This concludes today's EQT first quarter 2009 fiscal earnings conference call. You may now disconnect.