Good morning and welcome to the EQT Corporation second quarter 2010 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 this event is being recorded. I would now like to turn the conference over to Mr. Pat Kane, Chief Investor Relations Officer. Sir, the floor is yours.

Thanks PJ. Good morning everyone and thank you for participating in EQT Corporation's second quarter 2010 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 briefly review a few topics related to our financial results for the second quarter 2010 which we released earlier this morning then Dave will provide an update on our drilling and infrastructure development programs and other operational matters. Following Dave's remarks, Dave, Phil, Steve and Randy will all be available to answer your questions. First I'd like to remind you that today's call may contain forward-looking statements related to such matters as our well drilling and infrastructure development initiatives including Equitrans and the potential natural gas liquids joint venture, production, sales volumes, rates of return, operating cost, operating cash flow, growth rates and other financial and operational matters. It should be noted that 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 the company's Form 10-K for the year ended December 31, 2009 under risk factors, as updated by any subsequent Form 10-Qs, which are on file with the Securities and Exchange Commission and available on our website. Finally this morning's call may contain certain non-GAAP financial measures which are in this morning's press release. The reconciliations are in this morning's press release. And before introducing Phil, I would like to inform you that we posted our Marcellus decline curve to our website this morning. So now I'll turn the call over to Philip Conti.

Thanks Pat and good morning everyone. As you read in the press release this morning EQT announced second quarter 2010 earnings of $0.20 per diluted share, which was unchanged from the second quarter of 2009. Operating cash flow however increased by 17% over the prior year quarter as a result of another outstanding operation of quarter at the EQT Production and Midstream. Sales of produced of natural gas production increased by 31% for the second quarter in a row while gathered volumes at EQT Midstream increased by 20%. On the downside, realized gas price were lower than last year, primarily as a result of having fewer hedges in place at a lower average heads price. As we show on the table on this morning release, the EQT average wellhead sales price, which is our realized natural gas price was $5.49 per Mcf in the quarter. We were only slightly lower than the $5.57 per Mcf we realized last year, as some of the negative impact of the hedge position was offset by higher liquids prices. Just to remind you, for segment reporting purposes that $5.49 of revenue realized by EQT Corp. is allocated as $3.10 per Mcfe to EQT production and $2.39 per Mcfe to Midstream. Overall, absolute costs increased as expected to support our outstanding growth rate put on our per Mcfe basis cost related to EQT's produced natural gas and NGLs were down about 8% versus the same quarter last year after adjusting for the water treatment capacity charge mentioned in the release. I will go into a bit more detail on all of that as I briefly discuss results by business units starting from EQT production. And there as has been the case for two years now, the big story in the quarter was the growth in…

Thank you Phil. As the results from this quarter again demonstrate, we are delivering on our commitment to increase shareholder value by accelerating some optimization of our extensive reserves. We have recently completed our annual internal strategic review. No real surprises come out of the review but our areas of focus for the next couple of years are as anything even clearer. I will return to that topic after covering some of the operational highlights for the quarter. At EQT production, we posted our second consecutive quarter at 31% year-on-year growth in sales of produced natural gas. This growth was again driven by horizontal drilling in our Marcellus and Huron/Berea place. We may have been bit late to the party in terms of volume growth but this is now our eight consecutive quarter of double digit natural gas sales growth. These plays have become so extensive that we do not wish to focus too much on single well anecdotes but we do have a couple of Marcellus wins yet. During the Q1 call, we mentioned a recently completed in frac well with a 5,300 foot lateral, 4,800 feet of pay and 16 frac stages. It is now been online for 90 days. It costs $5.3 million with an EUR of 8.8 Bcf. Also during that call, we mentioned the well with a 9,000 foot lateral and 8,400 feet of pay, which was recently TD'd and cased. Our 28 stage frac job is now underway and we will update you on the progress, next call. I would now like to provide an operational update on our Midstream business. As we announced a few weeks ago, we are negotiating with DCP to form a liquids oriented venture that will combine our existing liquids-related Midstream assets with DCP's industry leading expertise. We continue…

Thank you Dave. This concludes the comments portion of the call. PJ, please now open the call for questions.

(Operator Instructions) Our first question comes from Scott Hanold from RBC. Please go ahead.

Hey. You talked about the 9,000 foot I guess lateral well, I guess there's a 400 ft of pay. Can you give us a sense on what that well would cost?

Yes Scott, this is Steve. We're estimating that well when we're finally done with it to be between $8 to $9 million.

And you guys haven't completed or are completing at this time. Is that right?

We starting tracking yesterday and we have successfully pumped the first two stages which frankly were the biggest concern, the first several stages. So it's proceeding as we speak.

Okay. Good. And you speak of the Marcellus, it seems like you guys are ahead of speed in terms of first half drum with 62 wells but plan on doing a total of 96 by the end of the year. I mean does that infer that your rig column is going to drop from where it was an average. Can you kind of help me square the circle on that one?

Yeah. What we're going to do is in the first half of the year, we used a lot of top hole rigs to start the wells. In the second half of the year, we'll be using the bigger Marcellus wells to drill the entire well. So we'll maintain our fleet of the larger Marcellus rigs which currently is six rigs and we won't have as many of the smaller top hole rigs running.

Well why was the decision made to get rid of top hole rigs?

Well the top hole rigs are easier to bring in and let go, the bigger Marcellus rigs are, we have under longer term contracts, we have experienced crews, we like to maintain more stability on the bigger rigs.

And the broader issue Scott on the number of wells really, and this is what drives that, decisions on what we think the appropriate amount of capital spend is.

Okay, its an capital allocation decision?

Exactly

That makes a lot of sense and you do get a pretty good sized backlog so I guess we're in six, is part of the process I mean when your running six rigs and some top-holes and your just getting ahead of your self too fast or is the infrastructure going to be available to get what you guys want on line here over the next 12 month?

While the infrastructure is going to be, there is going to be a continuing timing issue. We talked about that internally, plan it internally a fair amount but we think with the schedule that we have for drilling that the delays aren't going to be too great.

Ok, what about…

We are not slowing down drilling for mid-stream. The pace of drilling is really being set more by the decision about how much capital we wish to spend.

Ok and when you look at your inventory of Marcellus wells to get online and you know how services in the area, is it hard to get frac crews out there? I mean do you guys have dedicated frac crews and you know what's happening in there in terms of giving then and the cost associated with it?

Scott, we're actually in pretty good shape on frac crews. We do have dedicated crews efficient to do all the fracing we need through the remainder of this year. Part of issue with the back log is we were drilling a lot of pad wells. For instance, the extended lateral well is on a pad with six other wells and we have a number of those type of pads that are just finishing up drilling now. So a lot of it is just the timing and the nature of having, we have a lot of wells now get fraced in short amount of time and that inventory will be run down but then it will be build back up again as we start on more multi well pads.

So we should expect growth could be a little bit lumpy where you all of a sudden get say, six wells tied and a big production boost in any specific quarter is that's kind of and how we should think about it going forward?

Yeah I think that's going to continue with the Marcellus for as long as we're executing pad drilling the ways that we are.

Okay and one last question on Marcellus, just because I think I may have misunderstood the numbers, did you say you drilled about 151 Marcellus, horizontal Marcellus wells and only 34 are online at this time?

115.

Well I'm sorry, a 115. Okay, thank you.

81 are still in progress.

Got it and on the regulatory front, I mean what is your thought on the talk of permit more moratoriums and severance taxes and other issues outside the fracing issue?

We don't hear that much in P.A. or West Virginia about permit moratoria. In the areas of the states, at least in which we are operating, obviously we wouldn't like that if it happened but we actually don't hear much about it. We hear much more about disclosure issues and other forms of regulations but frankly, on the other forms of regulation, our attitude is that for what we can tell, we are already operating in a manner that is consistent with the preliminary proposed regulations. So in a way it's actually positive for us, if the bar gets raised a little bit closer to the level that we're already at. And as far as severance taxes, as a lot of folks in this area know, we're actually proponents of the notion of Pennsylvania instituting a severance tax in the context of broader clarification of rules regarding natural gas development. We are not experts on knowing whether that's likely to happen. That's a Harrisburg issue and there's a lot of you folks may or may not be aware we're already in the run up to a good inventory election here in Pennsylvania.

And, I guess from what I see, it looks a good, you mean bit of give and take, what kind of things as an operator would you like to see in exchange for say the severance tax and other types of things out there?

We would like to clarification on, I'll name two things. We were like pooling rules that are more in line with what we see in the rest of the country and we would like to see clarification on what kind of deductions are allowed for Midstream costs when dealing with, calculating what its paid to either royalty owners or in the case we have severance taxes to the government. We also believe it is in our best interest though that any severance tax would divert a fair amount of the money to the localities that incurred the inconveniences to do in fact come along with drilling as apposed to going to the state capital.

Our next question comes from Amir Arif from Stifel Nicolaus. Please go ahead.

Just a couple of quick questions. One just, as you guys talk about capital allocation and focusing on the highest return projects and any desire to shift more towards the Marcellus, away from Huron even in terms of 10 drilling.

Yes. I think you will be seeing some of that over the course of time. You are seeing some of it already but of course these are long lead time decisions and we haven't actually set our budget for 2011 but directionally, certainly that's the way we will react to any changes that we see in returns. We will direct their efforts more towards the higher return projects.

And I think on Huron/Berea you mentioned that, you wont see too much more aggressive extension there, where you would need additional Midstream, is that flattening?

I was tying to make a more subtle point. We put in a lot of Midstream already and we are going to try to focus ourselves more on developing in ways that keep the Midstream intensity lower as opposed to areas that will require a big new lets say corridor. Look, obviously that's one of those situations where it is possible that third-party capital becomes available because the issue for us isn't so much the economics of that. There is some of that that goes on obviously. It's the total availability of capital. So if we can, to the extent we can source other Midstream capital that alters that dynamic. The focus that we've got is that we don't want to put a lot of our capital into some of those developments, not that we don't want the capital to go into development.

Is there certain absolute production number in terms of at which point, just further Huron/Berea which point you would need?

No, there isn't really a number. For us practically speaking its got more to do with where we are developing within the play. And we've got quite a lot acres in that place as you know.

And just a question in terms of the CBM. When you look at the economics on the Marcellus and the Huron and the inventory you guys have there and you desire to keep allocating capital properly, any thought process of divesting some of your other assets then?

We are an economic enterprise. Everything is for sale everyday. It just doesn't seem as if right now is a great time to get very good prices for assets that are primarily producing.

And then I guess there is no, I mean you hold those assets anyways or the equities so there is no need [hasten].

No, and we're already drilling out. I mean for the most part really the question with the CBM is whether what is circumstance under which we would ramp up in such a way that we would need that next big Midstream project and it's a little bit simpler in that regard that there would be; if we want to step up a lot there need to be a new pipeline that would be put in, and either would it be our capital or we'd have to be committing to say from transport on that pipe.

Okay

Or anybody else would frankly. I mean there's nothing magical about our methods, its newer capacity down there.

Our next question comes from Ray Deacon from Pritchard Capital Partners. Please go ahead.

I was wondering how much of your Marcellus acreage do you think is perspective and blocked up enough that you can drill these longer laterals and gain the efficiencies there?

I'll flip that question over to Steve.

Yes, Ray what I would say is our current estimated cost, our Marcellus acreage position is what's reflected in that 38,000 foot a pay. Clearly we are drilling wells longer than that. The reason we're showing 38,000 is, that's our estimate of how it will all average out between long and short. I think over time, if we can consolidate acreage and work with our neighbors, we may see that go up but right now, that's our best estimates.

Okay got it. I guess just to ask you to elaborate on a comment earlier, you said the biggest risks to the volume growth this year is a function is to build out of the infrastructure and I guess how much of that is third party infrastructure and how much of it you just been able to get permits for the expansion of Equitrans I guess.

It's a mix but there is actually another risk that we were very concerned about in the summer and that is as the system starts filling up, I mean the storage etcetera starts filling up, the pressure starts changing in the system and that creates bottlenecks where didn't used to be bottlenecks. So, though we are putting in projects to resolve those problems, I explained in a number of cases, the projects were never scheduled to come in until say late third quarter and what we found throughout the middle of this year is we have been able to essentially come up with work-arounds to minimize the impact of some of those bottlenecks. So that's what I really meant about some of the middle of the year and its not that, that's always going to be the issue that we have that you are going to ramp up here and then once you get into the summer when we are into injection season, then the dynamics start changing on the storage front and also that is as you would imagine, the summer is the normal time for pipeline companies to take down their lines out of service temporarily for maintenance purposes. And there is actually been a little bit of less of that this summer than we are afraid and to the extent there has, we have been able to come up with a little bit walk arounds than we were anticipating. That's going to be, as we keep ramping up, this is something we talk about ever summer.

Mr. Deacon, do you have any further questions?

Yes, sorry, just one more quick one. I was wondering how much of that your frac fluids are you currently recycling and I guess, where do you see that going overtime?

I would say we are recycling nearly 100 percent. Occasionally, there maybe a few barrels here or there that we dispose off but effectively it's a 100% and we would expect that to continue.

Alright, thanks very much.

Our next question comes from Tim Schneider from Citigroup.

Yes, hey guys, a quick question. So you said you are drilling 34 rows in 2010 in a Marcellus. Just wondering what kind of well or how many wells do you expect to come online out of that inventory you have in that 115 wells, how much of that are baked into the guidance?

I think, I don't have a specific number for you but I think the bulk of those we would expect to be online of the current inventory.

Got it and what is the current takeaway capacity in the Marcellus for you guys on the Midstream side?

I don't know that we have in one number for a takeaway capacity because it is the West Virginia versus Pennsylvania, its different and different kind of sub-geographies. That's why we mentioned some of those, the projects that we had, specific projects in Pennsylvania and West Virginia but we probably the operating at reasonably close to our end year capacity with the end year exit rate that we provided.

Okay got it.

We continue to work to put in additional capacity.

Got it and then going forward, how should we think about the NGL's volume growth? Is that just a kind of a linear function with your production growth or is that more centered towards the TCO and Berea?

Well it's mortgaged. Here on Berea and it's also the part of Marcellus play that are kind of sort of moving to the West. If you go further West, I guess you'd say the further in North West, you get a weather, it gets in Marcellus and the dividing line roughly, I don't want to make it seem so clean as a line, but the vision is pretty much in South Western PA from what we can say. So a lot of it has to do with it as we've got opportunities that are a little bit more to the West than in Marcellus, that would be wetter and as you get far enough west, it actually wetter than the Huron/Berea and as you get to East, it gets pretty dry.

Got it. Do you have an average gallon per m kind of liquid's content?

Randy, do we have an average gallon.

We do it in the Huron, it's about 2.5 gallon in Kentucky.

Okay and as far as the processing capacity goes, do you guys see any sort of restrains there?

In Kentucky, our current facilities is a 170 million a day and its adequate to the growth that we have but as we expand in the Marcellus with our partnership with DCP, we are working to evaluate what the needs are in the area to the Marcellus going forward.

Okay thanks guys.

Our next question comes from Michael Hall of Wells Fargo. Please go ahead.

Thanks, good morning. Apologize if I hit anything that's already been covered, I just had this cut off. Just wondering if there's any development on your views around joint ventures in Marcellus, any changes in your stance there or just may be an update on your current thinking. It does interest me in the upstreams side that is.

Our view on this; there appear to be some interesting deals are getting done.

So you're not actively looking at any on your…

Look we are open minded to ways to source capital. As I said, the big picture issues for us are we have got a bigger opportunity than we realistically we are going to be able to prosecute entirely our own. But that said, our focus right now is getting the Midstream, especially the liquids ventures done. I mean we are not a huge company; we can only focus on so many things. But we are certainly open-minded as far as how we would go about pursuing capital.

Okay, fair enough and then, when you think about the potential or the move towards a more pooling regime if you will, more similar to the rest of the country? What would that maybe mean for EQT as it relates to horizontal locations relative to current, you know, vertical locations that's are limited by acreage?

Well we don't really drill vertically in the Marcellus. So as far as the horizontal, that you had Steve mention that the 3,800 foot design that we're showing now as our average is affected by the fragmented land position. That would obviously be one of the things pooling rules would help with that.

Okay, you just extent to a more on an average 4,300 ft or some to that extent?

We'd extend and I don't possible if that would come in the form though of prioritizing different locations. There's locations that can push back a little bit because of land reasons and that could get reshuffled a little.

Okay and then its kind of along those lines here. I think you had talked about kind of super extended long lateral that you were testing in Greene County or around this time, any color on that yet, and again apologies if you already mentioned it.

I mentioned that briefly earlier, just a real quick update. We began fracing yesterday. We successfully fraced the first two of 28 stages. So we'll be working on that well for probably at least a week, completing the rest of the stages. Initially, operationally, its going very well.

Our next question comes from Josh Silverstein from FIG Partners.

Previously when you guys had done the equity issuance a little while ago, you had mentioned that I guess the preliminary production kind of for 2011 would be at least the same as it was for 2010, which was at the time 26%. I was just kind of curious whether you guys increasing the rate for this year if we are to kind of assume that 2011 could be the same rate maybe 30% for next year or at least that much, and if you guys were assuming the previous kind of 4 to 4.5 Bcfe per well in that analysis versus the 5 to 6 Bcfe?

The assumptions we were using at the time of that offering, we were based on the old well design, but as we mentioned it was based on a particular hypothetical as far as how much capital we be willing to spend. Certainly we are capable of growing this asset at that kind of rate but it is dependent on what capital we decide to spend and we don't make those decisions until later in the year. In this financial environment which is still a bit unsettled, it still doesn't seem that prudent to make commitments to what the capital spending will be in 2011 yet. So what we said before is we are capable of higher growth rates absolutely, we continue to be capable of those rates and adjusted for the well design issues. But, its suppose a certain capital commitment that we are not prepared to make yet.

That some of your guys are probably do in December?

Yes.

Okay, and then also the 5 to 6 Bcfe average that you guys have, can you break that out by area? I know previously you talked about some locations in Greene County versus some counties down in West Virginia that were a little different.

Yeah I think generally speaking it's fairly safe to assume that the lower end of both cost and EUR range apply more generally to West Virginia and the upper end of the range applies more generally to Pennsylvania.

Our next question comes from Phillip Jungwirth from BMO Capital Markets. Please go ahead.

Just on the DCP Midstream JV, the processing plant and the NGL pipeline that you are contributing for the 50% interest, is there an EBITDA number associated with those assets that are going into the JV that you could give us?

No, currently, Jungwirth, we are finalizing the negotiations so we haven't reported that number yet.

And then, what's the best way to gauge the level of spending in 2011 that you said you're comfortable with, is it to look at liquidity because you will probably be at around $1.5 billion by the end of the year, is that the primary metric that you look at and then how low are you comfortable taking that liquidity to continue the out spring cash flow?

We do not want to run too close to the edge, that's what you're asking. We'd like to know, maybe put another, we'd like to know where the capital is coming from before we commit to spend it.

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

Thanks PJ. This concludes today's call. The call will be available for replay for a seven-day period beginning approximately 1.30 PM today. The phone number for the replay is 412-317-0088. You will need a confirmation code, which is 436920. The call will also be replayed on our website for seven days. Thank you everyone for participating.

Thank you. That concludes the EQT Corporation second quarter 2010 earnings conference call. Thank you for attending today's presentation. You may now disconnect.