Good morning and welcome everyone to the third quarter 2009 EQT Corporation 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. Patrick Kane. Sir, you may go ahead.

Thanks BJ. Good morning, everyone and thank you for participating in EQT Corporation's third 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 the third quarter financial results released this morning. Then Murry will provide an update on our drilling program, Equitrans and other operational matters. Following Murry's remarks, we’ll 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 and infrastructure development initiatives, production and sales volumes, reserves, the estimated ultimate recoveries for our wells, financing plans, operating cash flows, capital budget, growth rate and other financial and operational matters. It should be noted that a variety of factors could cause the company’s actual results to differ materially from these 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 ending December 31, 2008, under Risk Factors, as updated by any subsequent Form 10-Qs which are on file at the Securities and Exchange Commission and available on our website. Please see the press release a copy of which is available on our website, for non-GAAP financial measure reconciliations and other disclosures, with respect to such non-GAAP financial measures. I’d now like to turn the call over to, Phil Conti.

Thanks Pat and good morning, everyone. As you read in the press release this morning EQT announced third quarter earnings per share of $0.02 which compared with earnings per share of $0.73 in the third quarter last year. Adjusting for stock-based incentive compensation expense and building relocation expenses both of which I will discuss later, EQT's normalized earnings per share as shown in the table in this morning's release is more like $0.22 in the current, quarter versus $0.32 in last year's third quarter. Also to get a better sense of our normalized operating cash flow, and that comparison to last year, you would want to make those same adjustments by adding $32 million to this quarter's operating cash flow, and subtracting $85 million from last year. Say it another way, about $117 million of the $143 million reduction in operating cash flow, quarter-over-quarter, is attributed to those non-operating adjustments. Behind the cash free flow and the $0.22 of earnings per share this was another very strong operational quarter for the Company, both in terms of growth and produced national gas sales from the Huron, Berea and Marcellus drilling programs, as well as growth in gathering transmission and processing revenues in our Midstream business. We have also continued our progress of reducing drilling costs and per unit operating costs which were already among the best in the industry. Notwithstanding all of the operational progress, the financial results were once again negatively impacted by the continuation of lower year-on-year commodity prices. Lower prices impacted EQT results in two primary areas. First as you would expect lower NYMEX lead to lower realized average wellhead natural gas prices for EQT Production, significantly reducing productions revenues, and to a lesser degree lowered NGL prices suppressed unit revenues in the Midstream processing business. As we…

Okay, Phil. Thank you very much. Again, welcome everybody this morning. I guess the overall message, for the quarter is that as Phil said, it was a very strong operational quarter leading with the headline of the 8.5% increase in produced natural gas sales volumes. All of this volume increase or at least the vast majority of it is driven by the Huron and Berea play, it’s all organic. For your information this is our fifth consecutive quarter of double-digit produced natural gas sales volume growth. Based on the progress that we’ve had so far as we saw in the release we're raising our 2009 sales volume guidance to 100 Bcfe, which is 19% higher than 2008. Total gross well spud in the third quarter was 214, year-to-date 518. Total horizontal well spud third quarter 123, year-to-date 271. We currently have 23 rigs running. Three Marcellus rigs, we’ll have five by year-end. Two in the coalbed methane and the rest are deployed drilling horizontal wells in the Huron and Berea play. Just to drilling update on the main plays. On the Huron and Berea play just to remind you, we have drilled a total number of air drilled horizontal wells since our program inception in late 2006 of 712 wells. So we're getting a considerable amount of experience in drilling these wells. More than 25% of our third quarter natural gas sales volumes now come from air-drilled horizontal Huron and Berea wells. To remind you the scope of the play, we have 2.2 million acres in the Huron and Berea play. Generally each spacing unit which now we think is about 80 acres could be a little less, but say 80 acres. Each spacing unit average is a little more than two perspective zones, to allow per stacked wells. We…

Thank you, Murry. That concludes the comments portion of the call. BJ, you can now open the call up for questions.

(Operator Instructions). Our first question comes from Scott Hanold from RBC Capital Markets.

Murry you were talking about pacing and can you give us a sense of when you're looking at your capital budget and what you all would like to do within the current infrastructure that you have in the lower Huron, is there any limitations when you look at '010 or '011 or when do you have to really start thinking about building out that a little bit more?

I think there is not much right now because it depends on the pace of drilling, but there is not a whole lot right now. The big expenditure that will come or will need to come, as a result of accelerated drilling will eventually be the building of another processing plant to handle the liquids. At this point in time, we think the decision to build that plant probably needs to occur somewhere in 2011 I would guess. With hopefully, that plant being online in 12 or early 13. But that depends on a lot on the pacing that we're expecting. But that’s the major barrier right now in the long-term for the Huron/Berea play.

Then when you kind of commented that to get similar growth rates in 2010 to what you saw this year with 15% to 20% less capital, that's specifically talking about drilling capital, or is that just kind of totaling?

Yes I think we’ve we're going to spend about a $1 billion this year. So, to be more specific, we could achieve what we're saying is, we could achieve this year's growth rate for 15 to 20% less than the $1 billion that we're spend this year.

That's the reason we don't think we’d need to tap any external capital markets to be able to achieve that.

Did you catch that, Scott?

One last question on the Marcellus. Obviously, you had a tremendous with that $9 million a day well in Green County. There is still a fair amount of variability that you’re seeing is. Can you point to something specific to that? Is it just the variability by nature of the acreage within the play? And, on that 9 million day well, I know you typically don't like to talk about 24 hours IP rates like others in the industry. But can you kind of give us a sense where that may have fallen out?

Well, first of all, the reason we're not raising our overall EURs, yet, is because of the variability that you described. I think to be to be frank the variability doesn't concern me nearly as much when we're drilling $3 million wells as it did when we were drilling five, six, or $7 million wells. So, to put not too finer point on it, even if we averaged 3.5 Bcf and I realize our number is a little lower than others. I'm quite satisfied with the result given our current ability to drill these wells to drill them and complete them at the level numbers that I just reported. There was a bit of a rumor about this big well that we had, and my feeling about 24 hour IPs and I don't want to be critical obviously, of the use of this data. But, just to the give you a flavor for how variable this could be and how many factors are involved in determining an IP and in particular, then, how you interpret the factors, I'm going to give them to you for this well, all right. And this may be the only time I do it but I'm going to do it this time. And the only reason I'm doing it is to let you know that all these factors need to be understood in order to figure out what the well can flow. This particular well, flowed $20.4 million a day for 24 hours. Now the flowing casing pressure was 2,226 psi, that's important. The choke was 3,964 inches, that's important. There was about an hour downtime during the 24-hour flow period, that's important. So, with all these factors and several others too, I'm not sure what this well would have flowed nor how the flow of this well would compare with other companies results. But those are things that you need to know in order to try to even start making an attempt to understand what these wells can do. That's why I traditionally have not seen the wisdom in reporting these results. But there it is. And the only reason I'm telling you this because there was some rumor about this well circulating right after it was completed or turned inline.

Our next question is from [Serra Nanzda] from Millennium Partners.

Well, it’s actually Mark Caruso. I just wanted to make sure. It sounded like you guys answered it under Scott's question. But that I hear earlier that you guys are saying that you would expect to have less of a draw, on the revolver from originally for 2009?

We had originally in the year forecasted under $200 million. Now we're saying under $100 million, even with gas prices down.

I think Murry you just said earlier on lower CapEx you guys think that the combination of the revolver and with the was dollar going further you should be fine, the revolver is enough and you don't need to think about, asset sales, NLPs, or any other stuff that were originally contemplated?

Well, not to put too finer point on it. But I think Mark the differences are A, the efficiencies have caused us to think that we can put a budget together and grow at the same rate next year for less money and use internal sources to fund it, that's what I said. And in addition, we are open to Midstream partnerships if the cost of capital is right to further reduce EQT's equity investment in Midstream projects, again if the cost of capital works out. I’m not sure…

If you were asking those does that combination of a continuation of this year's growth rates, and 15 to 20% less CapEx, is that consistent with not going to the capital markets that is correct.

That is true, yes.

Just one last question you just kind of hinted out, I know earlier in the year we had talked about looking and open to the opportunity of JVs at Midstream. It sounded like you’re still open to that, are you contemplating that on the upstream just given there is so much interest by others?

No. I mean its right now, you can see even from quarter-to-quarter, the massive amount of technology change and economic change that occurs in these plays I am allowed to consider options on the upstream partnerships unless they were just staggeringly good. I mean, you never say, no. But boy, its going to have to be pretty darn good at this moment in time. Some day I think when the plays are delineated a bit more the technology improvements slows down then absolutely we will consider partnerships to accelerate the production growth. But, right now things are changing so quickly there would have to be a very, very good deal in order to catch my attention. Not so on the Midstream I think on the Midstream with the right cost of capital we would entertain partnerships there.

And to be clear on our strategic thinking it’s not just that we want to get money for that. It’s the further upstream you move, the less we view that as our core business. As Murry mentioned the processing, we have a little bit in liquids lines and things like that. But generally speaking the further away from the well, especially on the liquid side that it moves the less core it is for us and other than making sure that it happens, so that our gas will continue to flow. The closer it gets to the well the more core it is. And therefore, the less interesting getting involved in joint ventures is.

Again, not to [belabor] it, but clearly wells are our business. Now upstream of that we don't have drill rigs right. So, we don't have fracking companies. But drilling at we on leases we drill wells, we gather the gas, we even build the high-pressure gathering which we’ve talked about a lot on these calls, very key in our mind to have a significant amount of control of that high pressure gathering. Processing, not so much. We like somebody to process our gas. We like somebody to fractionate our gas. We are not in the fractionation business.

We would like somebody to sell the liquids.

We're not going to have EQT tanks at the local grocery store. We're not going to have that. But so as Dave says there is a point at which we are outside of our core capability which at this point, is the acreage we have, the drilling technology we have to exploit this shale and the pipeline capability to gather, measure, monitor the gas, those are core things of EQT. Anything other than that is open for potential partnership. That's long winded, but I just want to make sure we get it clear.

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

Murry I was wondering those five rigs at year-end, will you say which will the bulk of them been in Doddridge or green or a combination?

Combination of both. Well by the way, I didn't say this. But we're very pleased with West Virginia. We're very pleased with West Virginia. But they're going to be a combination of Pennsylvania and West Virginia.

Do you see a need to drill 3Ds, so that you can drill longer laterals or do you feel like the returns are adequate without it?

I currently think the returns are adequate without it. I think the question is would a 3D given the revolution of the 3D, would there be a compelling reason not to drill a well based on 3D data. Steve Schlotterbeck and I talk about that quite a bit. But that would be a hard one at this moment, unless there was something that came out that was just so compelling. Would you not drill a well because of something you saw 3D seismic? I don't know, not given the results that we have seen so far. We are completing though, I think the largest 3D survey in the Appalachian Basin. It’s about 75 square miles. It has been acquired and it is in the processing phase right now. And, we’ll interrogate that data as much as we can to see if there are indications from that data that can help, at least grossly target Marcellus wells. But the reason that thing was shot was for deeper objectives and to get a better picture of deeper geology. We committed to this a couple of years ago and we wanted to follow-through because we are interested in staying ahead of the curve on the deep, even though today it might not be the ideal time to drill.

I guess just two more quick ones. Did you put dollar number on the full three phases of Equitrans? So I was thinking you’d said 6 to 700?

Yeah, 650 to $700, is what we said yes.

Any comments on the liquid side and the decline year-over-year, any visibility on that improving going forward or?

Decline on the liquids. Phil you want to talk about that?

Liquids prices?

I never know liquid volumes is what he’s asking about.

They were up 50% over last year. They were down a little bit from the second quarter, but our Langley plan as I mentioned in the comments was out for three weeks.

Right. Okay. Got it. And I guess…

It was up in total but down quarter-to-quarter. I thought that’s what you’re mentioning is the quarter-to-quarter.

And that is back up just so you know.

How about pricing. I guess, is there any visibility on increased demand, you talked at one point about trying to develop maybe some local sources the demand for liquids or if anything new there?

We continue our data’s particularly active on NGVs in this community and we’re doing some things with equitable gas and the local communities to try to get the buses converted. We're very active. EQT people are leading the states NGV taskforces, and stuff like that. So we're working hard on that. If that's what you meant.

On the liquid side look, we share a view that I think a number of folks in the industry would now say they share, which is eventually we have to figure out what to do with the ethane.

So that if you are asking about the liquid, obviously we're really not worried about market, so this region is a net importer of propane. So, we’ve got a long way to go, before we’d worry about a having too much propane. You just wind up eventually curtailing the imports. But, eventually we think we need to have solutions for ethane. Now right now our Marcellus gas is pretty dry. But obviously, we even drilled that many wells. We have to look at others as well to get a better picture of the overall industry. It seems reasonable to believe that ethane is going to become an issue eventually in the Marcellus and then, eventually it becomes an issue in the Huron as well.

Just to let you Ray, I mean their discussions occurring about taking ethane both south which would be obvious to the ship channel down there or north. There are discussions about taking it north, too. So, we are actively involved in, as we normal do here at EQT, thinking about how these molecules are going to get sold, working them all the way down to the market. That's why we did the 300 line expansion, that's why we’ve developed a fairly robust downstream strategy for delivering this gas. But as Dave said, ethane is on our radar screen and we're looking at various alternatives. Don't have anything in mind right now.

Just look it's not a near-term issue.

No.

As hopefully its communicated, we really believe that we’ve got several years of very high growth rate potential in this company, and we think everybody else in the Marcellus probably not a lot of other people are in the Huron, but they probably share the same view and that means we need to be looking several years out. But we have the same concerns about water, and I think as we have talked about and others have talked about, through a variety of means, we have now basically solved the water issues, as far as disposal, right with the 100% recycling. So, we're confident that we will also solve the ethane issue. But it’s a longer term issue.

Can you remind me I know you had purchased that skiable processing, what's your capacity to handle what gas in the Marcellus? And maybe if you could talk about takeaway too?

We will be going to be up to, $35 million day by the end of the year and we haven't given a 2010 number. But, just suffice to the say there was nothing issue at this point, with handling liquids capacity. We’ve got plenty of these flexible arrangements to be able to do that.

Where we're drilling, we haven't run into lot of wet gas yet, but we know from looking at our friends who are drilling elsewhere in Southwestern, PA, that there are some areas of very high, very high liquids content. So, for what we're experiencing right now, we just got far more capacity than we would.

That’s not an issue, just not…

Eventually we would imagine we're also going to run into some wetter gas and we think we have got that planned for awhile out. Eventually I think you're going to see industry solutions to as oppose to single company solutions to those issues.

Our next question is from Xin Liu from JPMorgan.

Just a couple quick questions. That you're extending lateral program, and do you plan to apply to all your future horizontal wells or are you guys still experimenting?

Well, let me put it this way. I think the extended-lateral technology for the Huron, since we had so much experience, if we can convince ourselves with relatively few number of wells, that these are performing as we expect they will, then I think we'll fairly rapidly turn to drilling a lot of more wells with extended-lateral in the near future. But, we haven't made that decision yet. But I think the timeframe on making that decision is fairly short. On the multilaterals we’re not given up, that is still a very viable technology. We get a lot of feet of shale penetrated with those multilaterals. What we need to be able to do is effectively fracture all of them and we're getting good results. But we want to really even more effectively fracture those laterals. We're changing the geometries a little bit. So, you will see us have a combination of long extended-laterals, multilaterals, obviously stacking them, wherever there are multiple formations available. And you will see a mixture of these as we go forward.

The extended-laterals have moved beyond experimentation from our perspective, they are becoming much more part of the base case. We just have to determine the extent of the application, that's at least for the Huron. In the Marcellus you might say that’s more of an experimental phase. But some of these experiments work and just we start rolling them out. There is a horizontal drilling, air drilling and frankly extended-laterals on the lower Huron have moved toward kind of out of that experimentation phase, and into a selective rollout phase.

It’s really driven by number of frac stages. I mean we always could drill the wells longer. But the tools, the frac tools, packer flux and all the rest of them that are following on to packers plus didn't have enough stages to be able to have effective fracking on very longer laterals that’s why we went to multilaterals, because we didn't think that each individual lateral could be drilled and fracked effectively. Now that we can drill longer laterals and frac longer laterals that changes the game a little bit. And it looks very, very encouraging, as I mentioned in my comments.

It looks like you guys have improved the efficiency of the drilling the costs down and the returns are very attractive and your balance sheet looks pretty good. So, why not outspending your cash flow?

Well, I didn't tell what you our budget for 2010 is going to be, I just said that at this point in time we can easily grow as fast as we did this year for less money than we spent this year. I mean, if conditions in the markets improve, it’s possible, as I said we certainly have the flexibility to go more than that, and if we feel that it’s appropriate to do so, we will. But prices are pretty soft right now. And there is a lot of uncertainty in the economy. And we're just not certain that it is a good time to rush into something, to rush out there. So that's why we're taking a bit more modest view towards 2010, in terms of spending and in terms of accessing the capital markets, which as Dave said, we don't need to do. So, I just want to.

If you're positing your frac change, will we change our views, well, (inaudible).

When the frac’s change, I change, don't you, you know. So, and I think that’s exactly the attitude.

You saw that with us in the whole industry when we off scaled back on capital in the light of the new circumstances for this year.

But the scenario that Murry pointed out did suggest a little more than cash flow because he suggested a summary draw under the revolver in 2010.

Right.

At the same growth rate as we achieved this year.

Our next question comes from Rebecca Followill from Tudor, Pickering, Holt. Please go ahead.

Two questions for you. One on your 15 to 20% reduction that you can do the same growth rate with 15 to 20% less, is that all coming from Midstream? Does that reflect a partnership or is it?

No, at this moment what that number reflects is EQT, 100% just as we’ve done this year and just dramatic reductions in well costs that we talked about and the pacing of Midstream. The smaller projects, paced out a little bit differently. Shortening that build-to-fill period, which increases the time when we start getting our cash back or decreases the time on which we’ve continued to get our cash back. We're really focusing on this payback period. When you’ve roll all that together our view of the total capital that's required to prosecute this play, both Huron/Berea and Marcellus I should say plays, is much less than we thought six months or nine months ago.

The biggest factor being that unit F&D and it’s in both of the big areas going forward, Huron and Marcellus. It has been a dramatic actually Phil is probably in a better position to look at overall cash flow effect it. But it's been a dramatic impact on our thinking just really in the last six months.

Yes. So…

In higher to [tie] a flow rates out of the Marcellus wells also?

Yes, I think that is right Rebecca. I think versus our original decline curve, which again these are all based on not very much data, but versus our original assumption about Marcellus decline curves, we think we're getting a little more gas out quicker which is reducing the payback period again and is accelerating the cash flow. So its cost reduction, a little faster gas flows. By the way for the Huron/Berea on these extended-laterals that’s true, too. So, getting cash back faster, not putting it out as quickly for the Midstream, pacing that, smaller projects, shorter build-to-fill periods, all of this is combining to generate less cash requirements in total and less external market access in total, too. So, I know you all have been very patient with us about this. We’ve been talking about pacing for quite a long period of time. But, I think the work that we’ve done here has been I'm very proud of it because I think we’ve solved a lot of the issues of risk that I was quite concerned about a year-ago. I feel like we're getting to a place that’s a lot better than we would have been had we prosecuted this play in the way that we would have a year-ago.

Then the second question is on the discussions about Midstream partnerships. Will your '010 guidance in December, reflect some of that? And at what point, is this are these just preliminary discussions, is this something that is fairly prolonged…

Well obviously we’re not going to talk about all that in public. But I would guess at this point that the 2010 guidance we give on our capital budget in December will not include the prospects of a partnership. Not that we won't be looking at them, but I doubt whether anything will be that closer at that point, I could be wrong. But at this point if you're asking me today I’m going to tell you today that in a month and a half from now, we're unlikely to have something closed out.

On the Equitrans open season, did the [ODC] take some of that capacity?

No, but EQT Production did. So we’ll just hold off to hear about that amount to later?

Yeah. I think so. I mean the filings are going to come out here in November, for the first just to start moving?

In deterrence to any of the production companies, not just the affiliated one but others. It just doesn't seem to be the practice in the industry to disclose that information, until it has to be disclosed. They’re really kind of in deterrence to all of the production companies there.

You’re right, as, you know, everybody has to go through the process of precedent agreement that's a fairly, it takes a little while to get all that done. So, we don't want to front run that process.

Our next question comes from Stuart Wyman from Catapult. Please go ahead.

Just one quick question kind of to go with what Rebecca was just asking. This year E&P versus non-E&P was about 60%, 40% of the capital budget. Could you give us a little bit of color on just the percentage of budget associated with the E&P?

If you're asking the trend, I think, my anticipation is that a high percentage of the budget will be in the drilling as we go forward.

Certainly for 2010, and but also beyond.

Are we thinking more 80% or?

I'm not going to give you, you are asking me to give you the budget and I already said we're not going to reveal the budget until December.

We really have to wait until it’s approved.

Why we need to get one approved…

But it is moving more towards production. Looks there are two reasons. In the Huron, we’re really the dominant player. We’ve had to put a lot of investments in upfront, and not just the big pipelines and Big Sandy in the processing, but even in the corridors, etcetera, and a lot of that stuff now has been done and helps us for a while. In the Marcellus a lot more of it are going to be industry solutions, because you don't have the dominance of one producer throughout Southwestern PA and Northern West Virginia. In frac, speaking that probably means industry solutions on the pipelines, as well.

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

Thank you BJ. That concludes today's call. This call will be replayed for a seven day period beginning at approximately 1:30 Eastern Time today. The phone number for the replay is 877-344-7529, a confirmation code, 434029 is needed for the relay. The call will also be replayed on our website for seven days. Thank you everyone for participating.

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