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Executives

Pat Kane – Chief Investor Relations Officer

Dave Porges – President and CEO

Phil Conti – SVP and CFO

Analysts

Scott Hanold – RBC Capital Markets

Craig Shere – Tuohy Brothers Investments

Ray Deacon – Pritchard Capital

Rebecca Followill – Tudor Pickering

Zack Trevor (ph) – Ducane Capital

EQT Corporation (EQT) Q1 2010 Earnings Call April 28, 2010 10:30 AM ET

Operator

Good morning and welcome to the EQT Corporation First Quarter 2010 Earnings Conference call. All participants will be in a listen-only mode. (Operator Instructions). Please note this event is being recorded. I would now like to turn the conference over to Pat Kane, Chief Investor Relations Officer. Sir, the floor is yours.

Pat Kane

Good morning everyone and thank you for participating in EQT Corporation’s first 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. In just a moment Phil will briefly review a few topics related to our financial results that we reported this morning then Dave will provide an update on our drilling and infrastructure development programs and our other operational matter.

Following Dave’s remarks we’ll open the phone lines 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 drilling and infrastructure development including experience, expansion, sales volumes, rates of returns, well cost, acreage acquisitions, financing plans, operating cash flow, rates 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 the anticipated results or other expectations expressed in these forward-looking statements. These factors are listed in the company’s Form 10K for the year ended December 31, 2009 under risk factors as updated by any subsequent Form 10Qs which were on file at the Securities and Exchange Commission and available on our website.

Finally this morning’s call may contain certain non-GAAP financial measures. Please use this morning’s press release, a copy which is available on our website for the reconciliations and other disclosures which impact such non-GAAP financial measures. Before introducing Phil Conti, I do have one house keeping item. Later today we will pose to our website EQT’s 2009 quarterly sales volumes by play and our realized price reconciliation table in the new format that was presented this morning. With that I’ll turn it over to Phil Conti.

Philip Conti

Thank Pat and good morning everyone. As you saw in the press release this morning EQT announced first quarter 2010 earnings of $0.65 per diluted share which was an 18% increase over share in the first quarter of 2009. That increase in EPS as well as the increase in cash flow that we mentioned 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 load drilling and per unit operating costs at production. Another record in gathering transmission and processing volumes in our Midstream business and solid operating income at gas. The result this quarter I think are pretty straight forward, so my comments about the financial performance will be relatively brief before turning the call over to Dave Porges.

Starting out with EQT production, operating results, it is in the case for well over a year now, the big story in the quarter of EQT production was the growth in sales of produced natural gas. The growth rate as you saw hit almost 31% in the recently completed quarter over the first quarter of 2009. That growth rates was organic and was driven by sales from our Marcellus and Huron/Berea horizontal shale plays which together contributed over 40% of the volumes in the quarter, far exceeding the 25% contribution in the same quarter a year ago. Contribution from the Marcellus shale is growing rapidly and represented over 10% of the volume this quarter when it was really about 1%, it contributed about 1% in the first quarter of 2009 and only 3% for the full year of 2009.

Gas prices were also up a little bit in the quarter. The realized prices at EQT production was slightly higher at $4.23 compared to $4.16 last year and at the corporate level EQT realized $6.62 per Mcfe or about 9% higher than last year. You may have noticed that we have slightly ordered our price reconciliation table included in the press release this morning. We did underline to reflect the full value of our produced liquids in the realized price and by the way those liquids come primarily from our Huron/Berea play.

Our previous presentation did include the Btu premium at the price of natural gas. However any profit made when on Midstream group strips the liquids and realizes higher prices than the natural gas price was included in the processing that revenues at Midstream but it was not included in the average gathered price to EQT Corporation. While this additional detail does not change to reported financial results at all, we do think it only illustrates the full revenue generated from our producing wells.

As you can see on the table EQT Corporation realized a $1.22 per Mcf on average above the price of dry gas. The $0.58 recognized the Btu premium at production and $0.64 recognize that Midstream. A brief moment on expenses at production, total operating expenses were higher quarter-over-quarter as a result of higher DD&A, SG&A and ROE, all consistent with the significant production growth. Production taxes were down a fair amount in the quarter especially on a unit basis, $0.26 per Mcfe in the recent quarter versus $0.36 per Mcfe a year ago.

I think since that larger of a unit decrease may not be intuitive in the recent price environment, do remember that production taxes are the total of two price related taxes, one being severance taxes and the other being property taxes. Severance tax is a fairly straight forward calculation as it is just a percentage of our unhedged production revenue at current prices. Property tax is also price related but with the lag, so the property tax incurred in 2010 is primarily based on 2009 gas prices while the comparable 2009 property tax was primarily based on 2008 gas prices. So the significant decline in prices from ’08 to ’09 therefore resulted in lower property tax in 2010.

Exploration expense was also $2 million, lower quarter-over-quarter as we reduce the size of our seismic program compared in the last year and we expect our exploration expense to be above $6 million for 2010. moving on to the Midstream business, operating income here was up37% consistent with the overall growth of gathered and processed volumes as well as the significantly higher liquid scratch spreads which were driven by a 72% increase in average NGL prices quarter-over-quarter. Gathered volumes increased 16% mainly from gathering EQT productions growing sales volumes and combined with higher rates resulted in a 26% increase in gathering that operating revenue.

In addition to improve prices, processing volumes were also up by about 21% as a result of higher production volumes from our wet gas Huron/Berea play in Kentucky. Transmission net operating revenues were also up a little bit primarily because of slightly higher rates and finally storage, marketing and other net operating revenues were lower mainly from lower third party marketing margins. In 2010, capacity constraints has eased somewhat in the (inaudible) Big Sandy quarter resulting in a somewhat smaller premium for marketing services.

In addition first quarter 2009 margins on gas market utilizing in Big Sandy capacity included contracts that were negotiated in the 2008 price environment, by the first quarter of 2010, those have been replaced by lower margin contracts. Net operating expenses at Midstream were also about $6 million, 15% quarter-over-quarter. Higher DD&A expense associated with our increasing Midstream infrastructure accounted for about $2.7 million of that increase in expenses while increased electricity and labor to run our expanded compressor fleet accounted for the majority of the rest.

Moving onto distribution, operating income at distribution was up about 8% mainly as a result of a full quarter of higher rates in Pennsylvania which went into effect last February. Weather was basically the same as last year, the only real variance of note this quarter was $1.8 million increase in bad debt expense which is reported in DD&A and that reflects a decrease in federal funding for customer assistance plans this winter compared to last winter. The collections history distribution actually improved somewhat quarter-over-quarter.

And then finally our regular liquidity update, as a result of $538 million in net proceeds from the recent equity offering and by the way about $9 million of that came after 331, so it won't show up in the queue later today. But we’ve got $9 million when the small portion of the green shoe was exercised after the end of the month. And then coupled with that the receipt of a $120 million cash tax refund resulting from the five year NOL carry back allowed by legislation that was enacted during the first quarter of 2009.

Those two together we closed the quarter with no short term debt and a net cash balance of about $553 million. As previously announced our 2010 capital expenditure estimate is about $1.2 billion and we estimate that 2010 operating cash flow at the current strip will be approximately $650 to $700 million including the $121 million we received from the tax refund. So we’re really in a great liquidity position to fund the remainder of the 2010 growth plan.

And with that I’ll turn the call over to Dave Porges.

David Porges

Thanks Phil and good morning everyone. As I assume my new role EQT, I look forward to building upon the firm foundation laid by Murry during his 12 year tenure as CEO. Because of his leadership and passion EQT has transformed itself from a regional utility into one of the leading natural gas production companies in the nation. EQT and its predecessors have been around for over 100 years. In my opinion Murry Gerber, will be remembered as the finest CEO this company has ever had.

One of his greatest legacies has been developing a management team that can continue his fine work. As many of you know, I joined the company in 1998 along with Murry as Chief Financial Officer. Over the past 12 years, I’ve held various management positions, the most recent being President and COO. At the offset EQT strategy was set largely by the two of us and we view this effort as a partnership.

Increasingly the management team that has built up and grown up around us has become much more involved in setting strategy and running the company. This is a team that is committed to the ultimate goal of increasing shareholder value. Aspects of achieving that goal is just in all of our businesses from accelerating our innovating shale drilling program to expanding and strengthening our Midstream capabilities to continuing our initiatives to be the most efficient and customer oriented gas distribution company we can possibly be.

Still the core strategy that animates our upstream and midstream efforts is accelerating the monetization of our extensive reserves. We intend to accomplish this via the drill bit and other means as appropriate. Those other means could include anything from partnerships with strategic or financial parties to asset sales. However we feel that our ability to execute against an organic growth strategy will create more opportunities for other monetization alternatives. Therefore we plan to stay the course in terms of developing our shale assets and getting the produced hydrocarbons to market. Returning to the management team for a moment I would like to gradually introduce you to more of them.

Today I’ll stop by mentioning the three individuals whose titles include being a Senior Vice President of EQT Corporation. You all know Phil Conti, who just spoke. Phil will continue as Senior Vice President and Chief Financial Officer of EQT. Steve Schlotterbeck, who runs our upstream business as Senior Vice President EQT Corporation and President, Exploration and Production. Steve and his team have demonstrated extraordinary innovation in developing both our Huron and Marcellus opportunities.

You are all aware of our innovations and air drilling in the lower pressure Huron and an adapting horizontal drilling to our assets. These are not isolated innovations. They are part of the culture Steve and his team has build and I’ll mention more of their innovations in a few moments. Randy Crawford runs our Midstream and downstream businesses as Senior Vice President EQT Corporation and President Midstream, Distribution and Commercial. Randy personally along with his team developed the very notion of utilizing our Equitrans assets be the existing (inaudible) etcetera to assist in the critical role of getting our produced natural gas to market. Randy and his team are also leading our efforts to forge Midstream partnerships.

Now onto the first quarter results, as Phil mentioned we had another strong quarter across our business lines, but the headlines statistic is the 31% growth in sales of produced natural gas quarter-over-quarter and 11% growth in average daily sales sequentially. This is our seventh consecutive quarter of double digit natural gas sales growth. This growth is driven by horizontal drilling in our Marcellus and Huron/Berea plays.

Including the anticipated close within the next few days on the previously announced Marcellus shale acquisition, EQT will have approximately a half million acres in the our Marcellus play. Improvements in both drilling cost and completion effectiveness have cost us to become quite bullish on this way even on the current price environment which is a great credit to the EQT team and here is a reason. As we’ve discussed over the past several quarters, we’ve seen a market improvement in well costs and EURs. On our yearend earnings call we reported having achieved completed our Marcellus well costs of about $3 million per well. This cost per well was based on a standard lateral well, 3,000 foot laterals and I’m referring to pay here with eight stage fracs.

We are now drilling that link wells with ten fracs. Prospectively this is our new standard. This change cost about $300,000 per well. We are also witnessing increased steel and services cost which prospectively are likely to add in our $200,000 per well. These two effects both of which are consistent with the economics discussed as part of our recent equity offering mean that we now expect our Marcellus wells to cost between 3.3 and $3.5 million per well based on that 10 stage frac standard. Earlier this quarter our average (inaudible) of Marcellus wells would increased to between 4 and 4.5 Bcfe across all of our Marcellus acreage.

We will not be surprised if given the current data additional frac stages per well and with our drilling results, our Marcellus EUR per well continues to edge up.

Current economics include unit development cost for Marcellus wells of around $0.80 per ounce. Our all in after-tax IRRs are about 30% at the current NYMEX strip which is about $6 and about 10% and $4 for the life of the well.

We include nearly $2 for transportation and gathering in our calculations to reflect the needs from new infrastructure. This assumes that new infrastructure is required to move essentially all volumes. Obviously, once the infrastructure is in place, the actual marginal cost to keep the pipes full indefinitely is much lower, thereby improving the IRRs on subsequent drilling materially.

We believe treating all volumes as if they require a new infrastructure is a conservative approach to our capital investment decisions. We also believe it is the correct approach for us to take at this stage of the plays development. By the way, we estimate the payback period for Marcellus wells at the current strip price to be between three and 3.5 years.

Regarding well reserves for the Marcellus, we have spud 74 horizontal wells to date including 21 in the recently completed quarter. Of those 74 wells, 28 has been turned in line. We are expecting to drill 100 Marcellus wells in 2010.

So far in 2010, we have 11 wells with at least 30 days of production data which are not artificially curtailed to takeaway constraints. The average 30-day IP of these wells is 6.6 million cubic feet per day. You can pretty safety assume that these were standard length laterals. However, we are expanding – we are experimenting with longer laterals.

We have successfully drilled, completed and fraced the Marcellus well with a 4,800 foot lateral in 16 stages. We are currently drilling up the frac plugs and we will begin flow testing after that. We have also just TD'd and cased a Marcellus well with 8,500 feet of lateral and we are planning a 28-stage completion. The casing is being set as we speak.

Eventually our definition of a standard well will likely change, but we see a most comfortable sticking with the 3,000 foot 10-stage frac as the 2010 standard.

Moving to our Huron play. As previously reported, we are drilling the extended laterals in the Huron/Berea play. To date, we have drilled and completed nine extended lateral wells. Right now that means they have about 5,500 feet of laterals each. In 2010, we plan to drill 99 extended lateral in this play and fully expect that extended laterals will be our standard operating procedure in the Huron/Berea play by yearend.

Extended lateral wells are providing increased productivity which is expected to result in a per unit development cost of a little less than $0.90 per Mcfe. Our Huron/Berea wells are producing liquids rich gas which also has a positive impact on the economics.

Over the past few years, EQT has developed an innovative culture that has lead to several industry firsts and helped drive EQT’s F&D cost to amongst the lowest in the industry. These innovations include air drilling in the low pressure Huron.

The first use of horizontal hammer drilling techniques, which has drastically lowered the cost of drill the hard rock formation such as the Berea, Big Line and Ravencliff. And the first use of a rotary steerable system on dry air, which allows us to drill significantly longer laterals in the Huron play. All of these technologies have proven themselves to add value for EQT.

Our latest focus has been on transferring our extensive knowledge and experience an air drilling our operations in the Marcellus. We have recently successfully completed the drilling of two Marcellus wells using air drilling techniques down to the beginning of the lateral. While this technique is still in the experimental stage, if successful, we see many potential benefits from this including the ability to use our smaller, cheaper and more mobile Huron rigs to drill a larger portion of our Marcellus wells.

This could provide a significant cost savings over our current practice as well as minimize the amount of mobilization of the larger and more complex Marcellus rigs. We will continue searching for new and better ways to drill complete and produce our wells. We will adopt and roll out the innovations that work and we will endeavor to learn from the experiments that do not work.

Switching to our midstream activities, we are clearly moving towards a modular approach to building infrastructure. I had mentioned in many forums that managing the midstream issues were such a rapidly growing play is likely to provide challenges on the ongoing basis as we seek to keep up with production growth without getting too far ahead. Broadly and our modular approach seems best suited to this involving situation and that is the approach we are adopting.

To give you a flavor for what this means, I would like to speak for a few moments about specific projects. In the first quarter, EQT midstream completed construction of the Ingram (ph) gathering system, which allows the delivery of 50,000 dekatherms per day of EQT production in Green County, Pennsylvania to two Equitrans pipelines.

Midstream is now on track for the second phase of that project which will extend the system to East to nearby EQT production acreage. Once completed, this will provide a further 40,000 deks per day of capacity for EQT’s production by yearend. The necessary right-of-ways have been acquired and the pipe has been purchased.

In Northern West Virginia, EQT midstream is in the process of constructing a Doddridge (ph) gathering system expansion which will deliver EQT’s production from North Central West Virginia into the Western leg of the Equitrans system. Capacity additions of 50,000 deks per day will be made available by yearend bringing total gathering capacity in West Virginia to approximately 70,000 deks per day.

Turning to the regulated pipeline of storage business, we continue to make progress on our multiple expansion initiatives. As you recall, the Equitrans Marcellus expansion project is underway and given its significant scope is progressing in stages. Equitrans has secured the market commitments need to support the first phase of this project. FERC prior notice application authority for this space was received April 2nd.

As a result, this space which consists of upgrades to the various segments on the existing Equitrans transmission system along with modifications to compression at the frac station is proceeding according to schedule. This $15 million phase allow us for about a 100,000 deks per day of incremental delivery capacity to Equitrans’ interconnections with five interstate pipeline facilities. Construction is expected to be completed in the fourth quarter of this year.

We continue to work towards completing the rest of that large Equitrans project. And the fact that Equitrans is preparing a second quarter 2010 certificate pre-filing with the FERC for the balance of the project. A provisional in-service date of mid-2012 is anticipated.

Consistent with my broader comments, this may well continue to progress in a – there is a series of small stages, thereby giving us more flexibility to meet market needs including the growing needs of EQT production. This will also buy us sometime in terms of funding for the project. Along those lines, we continue to have discussions with potential midstream partners.

Initially, we are most focused on identifying a strategic partner for the liquids build out. This means that they must have experience in dealing with wet systems processing and downstream aspects of liquids, as well as being willing and able to fund a sufficient amount of the capital required for this build out. We are also opened of partnering on the dry gas aspects of our midstream business.

In this instance, operating expertise is less important as our midstream unit has that know-how. Rather the focus is on a partner that brings funding capacity and willingness. As a result of the slight differences and desired attributes for the wet versus the dry, we may end up with more than one partner. And in either event, we remain committed to getting at least to the first stage by liquids aspect executed in 2010.

I would like to conclude my remarks by reiterating our production guidance. We recently upped the sales growth guidance to 26%. In the first quarter, we beat that number. But it was compared to a relatively – to relatively low volumes from 1Q09.

As I have discussed earlier today and previously, our attitude on guidance in these rapidly growing plays is influenced by the belief that midstream constraints are a matter of when not if. This will not halt the trend toward sharp increases and volumes over the coming quarters and years, but does make it more difficult to forecast specific timing on a quarter-by-quarter basis. We would rather see how some of our efforts to ameliorate these midstream constraints during the summer play out before reassessing our relatively fresh production guidance.

While it is true that our midstream and commercial folks often figure something out to mitigate these concerns and I am confident in their ability to do so again. To growth track, we and the rest of the A-basin producers are on will make the issue of looming midstream constraints a recurring theme.

We believe EQT is a very compelling investment. Growth rates and cost structure are industry leading, we receive a premium basis to NYMEX, we have an extensive acreage position to develop and we believe we have the most innovative group of employees in the basin, people who are committing to getting it done.

Thank you. I will now turn it back over to Pat and we will take your questions.

Pat Kane

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

Question-and-Answer Session

Operator

Yes, sir. We will now begin the question-and-answer session. (Operator Instructions). Our first question comes from Scott Hanold from RBC Capital Markets. Please go ahead.

Scott Hanold – RBC Capital Markets

Thanks, good morning.

Dave Porges

Hi Scott.

Scott Hanold – RBC Capital Markets

So, it looks like on the well you indicated that you are drilling at 8,500 foot lengths and 28 stage fracs. So when you look at pushing the envelope in terms of trying to optimize production, what is your capacity do you believe in terms of just kind of your acreage position or what you think is sort of the optimal length at this point in time?

Dave Porges

We don’t know. We are experimenting so that we can come back with you. And based on what we are seeing now with current technologies, that 8,500 foot maybe about as far out as we can economically get. I mean, but, we have got a – we are committed to experimentation and we will have to get back to on what we wanted to conclude eventually is the best approach.

We do think it probably makes sense to go further than 3,000 which is the current standard. But in the Marcellus as you are aware that the acreage positions are so fragmented that land is going to be a limit that we are going to windup figuring it out.

Scott Hanold – RBC Capital Markets

Yes, absolutely. And when you think about that, are you actively looking to I guess bolt o on to your acreage position to enable you to optimize your drilling at this point?

Dave Porges

We are certainly opened to those types of tactical acquisitions. I also think something though that we haven’t done a lot of here which is normal in other plays were fragmented acreage and therefore we are going to get into are doing deals with other production companies, whether it’s little swaps or people participate in the wells with each other, et cetera. I think we have seen a little bit of that in the Marcellus. Historically we haven’t really done very much of it, but I think that is going to be a – that’s going to be something we are going to wind up pursuing on the business development side of production.

Scott Hanold – RBC Capital Markets

Okay, got it. And when you look at those, I think you said 11 wells had been online for 30 days. It had an average 30-day rate of 6.6 –

Dave Porges

6.6.

Scott Hanold – RBC Capital Markets

Yes, 6.6. How did that compare at 6.6 in that first 30 days compared to your 4 to 4.5 Bcf model?

Dave Porges

Those are basically consistent. That’s – we keep looking at the right EURs. But, of course, event that – some of those 11 have 30 days, which isn’t that much data to be using the reassess EURs.

Scott Hanold – RBC Capital Markets

Okay. And one final question. What did your active horizontal rig count in the Marcellus right now and where do you expect it to be at the end of the year? And can you also, as part of that talk about the acreage acquisition that you made, how much activity is going to be up in that area?

Dave Porges

Let me answer the last one first. As we put in the equity presentation, we are still looking at probably about three wells in that area of 2010. The closing hasn’t actually even happened yet. So it should happen today. But the working hypothesis is three and we will revisit that in future calls once we actually own it.

As far as the rigs, it depends on the definition. We typically run with the notion of we have got about six and it’s – and those are more than big rigs. And you might assume to go along with that that there is three piggy back rigs, but if you count total rigs in the Marcellus to nine. And we would expect that we would continue that through the year, so that would be consistent with getting at that 100 wells for the year.

Scott Hanold – RBC Capital Markets

I appreciate it, thanks.

Dave Porges

Thanks Scott.

Operator

Our next question comes from Craig Shere with Tuohy Brothers Investments. Please go ahead.

Craig Shere – Tuohy Brothers Investments

Hi, congratulations on the quarter.

Dave Porges

Thank you.

Craig Shere – Tuohy Brothers Investments

What is the time frame you are perhaps thinking about for feedback on this new technology application that may allow the use of smaller, less costly rigs in the Marcellus? And how would you see that kind of interweaving with the possible continued upward migration of the frac stages and EURs going into 2011?

Dave Porges

I really think this is more of an ongoing issue. It’s probably in the area of months when it comes to making a real assessment on the rigs. But what I was really trying to get across on the call is that our team doesn’t just have an innovation or two, it really is a culture that they have got. So they are going to – the possibility of changing how we drill those wells is something that they have been working on for a while. They've been making changes. We've had some experiments that succeed, some that don't succeed and I just think this is going to be an ongoing process. We'll have more to report on that I'd say probably every quarter.

Craig Shere – Tuohy Brothers Investments

Well, let me ask you in a different way perhaps. Having looked at the R&D options and the potential and actual realized in the last couple of years in tax of them, would you say that what you have on your plate now in terms of things that you're kind of evaluating to tweak the drilling process would maintain, accelerate. Where would it be in terms of the potentiality of the reduced trend of CapEx per Mcf over time? And if you look at the last couple of years and what you have on your plate now, can we see an acceleration of the cost per Mcf improvement or it's totally up in the air?

Dave Porges

I don't think it's totally up in – I don't think that we're going to see the kind of step changes that we've seen over the course of the last year, not that level of step change, those were huge changes that we experienced. I do expect that the trend over time is going to be continued improvement. There'll be a lot of small innovations is what I anticipate and then the occasional larger innovation. Now in the near term with oil field inflation going on, we're probably looking for some short term or mid term period of time having productivity improvements that keep us more even as opposed to the kind of we're swimming against that tide right now but we don't expect that that's going to go on indefinitely.

Craig Shere – Tuohy Brothers Investments

And is the cost there more on the fracing, the steel, where is the main cost?

Dave Porges

Anything that seems to be particularly used in the high pressure shales around the country is under cost pressure would be my assessment.

Operator

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

Ray Deacon – Pritchard Capital

Yes, hey Steve. I had a question for Steve. I was wondering, do you see any range – Ran just talked a little bit about the Utica and the upper Devonian potential and I was wondering if you have any plans to test that and (inaudible).

Steve Schlotterbeck

We've taken a little bit of a look at that, Ray but that's not one of our top priorities right now.

Ray Deacon – Pritchard Capital

Okay.

Steve Schlotterbeck

I mean we respect those guys greatly and we obviously follow whatever they are doing, we take a look at what they're doing to see if there's any lessons for us. So, we're as interested in what they're doing as you are but it’s not one of our top priorities right now.

Ray Deacon – Pritchard Capital

Got it, but you wouldn't rule out that it could be productive and –

Steve Schlotterbeck

Oh, not at all.

Ray Deacon – Pritchard Capital

Okay, and just –

Steve Schlotterbeck

We're optimistic about it eventually as well, it's just that we have other things on the plate that rate ahead of it right now.

Ray Deacon – Pritchard Capital

Okay.

Steve Schlotterbeck

But long term we have -- we're probably as optimistic about that as they are.

Ray Deacon – Pritchard Capital

Okay, got it and I guess -- I'm still not quite understanding your math when you talk about the 3 to 3.5 year payout at the current strip for Marcellus well because I'm showing somewhere around a Bcf to 1.3 Bs in year one. It seems like $5 gas, you'd get payout on a well in one year I guess trying to make sure I understand that.

Steve Schlotterbeck

Well, it's probably best for Pat to walk you through some of our approaches offline.

Pat Kane

We haven't put out an actual decline curve yet but we're going to -- we'll be doing that in the next several months.

Ray Deacon – Pritchard Capital

Okay.

Pat Kane

Alright?

Ray Deacon – Pritchard Capital

Yes, great and just –

Steve Schlotterbeck

I want to tell you do bear in mind Ray that we take into account the infrastructure upfront as well.

Ray Deacon – Pritchard Capital

Well, okay, that would make sense.

Steve Schlotterbeck

Right, so that's an upfront cost that definitely affects the economics?

Ray Deacon – Pritchard Capital

Not just a well cost, got it.

Steve Schlotterbeck

Right now the subsequent well to fill existing infrastructure, then it might be the economics you're looking at right now would work.

Ray Deacon – Pritchard Capital

Got it, got it, makes sense. And I guess, Steve, it doesn't sound like you yet want to put out an IP rate for one of these longer lateral cure on wells I guess, just any thoughts there?

Steve Schlotterbeck

No, we just assume kind of get one or two on -- get more of them online and then we'll do that.

Operator

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

Rebecca Followill – Tudor Pickering

Good morning. Dave in your early remarks you said that the ability to execute against organic strategy will create more opportunities for monetization.

Dave Porges

Yes.

Rebecca Followill – Tudor Pickering

There are guys that are much earlier in the learning curve in Marcellus, a few are getting $14,000 an acre. What do you think you could do organic strategy that would give you more than that or that would make something different versus what we are seeing already in transaction?

Dave Porges

Well, certainly those are some nice numbers that we are seeing out there. We would agree with that. But I guess from my perspective, six months ago or nine months ago, folks were wondering why we wouldn't sell $5000 an acre. So it’s hard to tell where it’s going. We do think that we are in the upper tier, let’s say of Marcellus producers and that vary up, but we are not claiming that we are number one, but we are in that – if there is an upper group, then we are in the upper grouping and we would like to get enough results out there so that that becomes the general view.

Rebecca Followill – Tudor Pickering

And I guess I am trying to figure out when is enough enough? I mean how do you need to know and I know that you have got 3 million acres and you have only drilled a handful of wells in the scheme of things. But what gives you that comfort that think you are there, is it a couple of years from now, is it 10 years from now, how kind of far long in that process?

Dave Porges

I don't know that we measure in time. But I will tell you our ears are open. When people come to talk to us, we listen. We don’t tell folks that we got no interest. But if they have got a way for us to increase shareholder value, we listen. I do think that we find more people are talking to us as a result of the well results that we started putting out really only late last year. I think we are already seeing folks taking us a little bit more seriously. And at this point, I think we expect that trend to continue but I wouldn’t put a timeframe on it.

Talk to the other companies that we are interesting in putting money and then ask what they think of EQT, that's probably a better metric than what – than us commenting out.

Rebecca Followill – Tudor Pickering

Why don’t you tell me who they are and I will go talk to them.

Dave Porges

I was hoping you do that work for.

Rebecca Followill – Tudor Pickering

Okay, so they are knocking on your door and you are not turning them away at this point?

Dave Porges

Well, it’s an – they do. But haven't we all been a little surprised by the extent of the international interest? I mean Reliance Industries, interesting.

Rebecca Followill – Tudor Pickering

They have big numbers and impressive numbers.

Dave Porges

I mean that's – I know – that’s big company, the guy who runs it, a very wealthy man, he could certainly afford it. But we just wouldn’t have thought that an Indian company would have done that. So who knows? So now we got a Norwegian company, Indian company, a Japanese, who got in. I remember when I was in banking, the Japanese were getting big into the upstream in the U.S., that was in the 80s. And then you really didn’t hear a lot from them in the 90s and the odds are whatever we call that. So it allows that, if the Japanese are interested again, then who know where we are heading.

Operator

Our next question comes from Zack Schreiber (ph) from Ducane Capital.

Zack Trevor – Ducane Capital

Hi, it’s Zack Trevor (ph), can you hear me? Just following up on the (Becker’s) line of questioning, did you guys have any conversations with Reliance and it sounds like you did and obviously --

Dave Porges

No, I don’t mean to mislead you, no we did not. We had been hearing about it before the deal was announced but we – no, we did not have any discussion. Honestly the only connection is Reliance – up at the CEO of Reliance was a business school classmate of mine. So I am following them with a little bit more interest, but no we did not have conversation.

Zack Trevor – Ducane Capital

Is this the former Shell guy?

Dave Porges

No, I am talking about Mukesh Ambani.

Zack Trevor – Ducane Capital

Oh, really, got it. So the folks (inaudible) have not called you or they have called you or they are starting to call you.

Dave Porges

People are sniffing around but I don’t know what they are interested. I don’t think you want to say we know what they are interested in. So far our impression is that people who have done deals are ones that – are the producers who went after them aggressively. But I don’t think that's the only conversations that are going on.

Zack Trevor – Ducane Capital

So when you rip apart the Atlas Reliance deal, is that a deal that you think you could have done or is there something distinguishing about Atlas’ acreage via the geology or the location that you think makes that valuation not accessible to you or do you think that it actually were you to explore and aggressively pursue these joint venture opportunities that kind of valuation is accessible to you. I am not sure what to kind of say, Dave.

Dave Porges

I don’t know if it’s accessible. I think the best deal for any company is probably specific to the company’s circumstances. So I don't feel comfortable speaking for what Reliance or Atlas saw. I feel pretty confident they must have each thought that it was the best deal for them. But beyond that, all we are taking away from it is that it appears as generally speaking the values that are available out there are still going up despite the very weak price environment.

Zack Trevor – Ducane Capital

And so what you are saying was that when Reliance was looking for that deal, you were not actively in the market looking –

Dave Porges

You don’t think – look, you would have to talk with Reliance and Atlas. Our impression was that that Atlas was looking for a deal.

Zack Trevor – Ducane Capital

Agreed.

Dave Porges

That’s our impression that Reliance was comparing it to others, but we don’t know, we weren’t – we certainly were not involved in a process.

Zack Trevor – Ducane Capital

Got it.

Dave Porges

We thought the process, if there was one, was coming from Atlas’ end.

Zack Trevor – Ducane Capital

Got it. And just in terms of the value from accelerating the monetization of you extensive reserves, following up again on (Becker’s) question, so I am sort of plagiarizing here but how exactly do you view your success with the drill bit feeding into any possible asset sales or partnership type deals. If it’s not an issue with the amount of time, is it an issue with some degree of success or EURs that you think, if it’s not time, what exactly is it that you think allows you to reach full value because I agree with you, values do keep going up despite the low gas price and that's obviously the economics of the asset that you are sitting on but if you sit on that forever, waiting to go up, you are effectively competing against the time value of money discount rate. So at what point is it better to bring forward that value, I am not sure I am making sense, but bringing forward – I guess what’s the rate of inflation of that value relative to your cost of capital and discount rate?

Dave Porges

I don’t have a specific answer for you. I will you that it does seem to us that we are still in the process of demonstrating increased value from these assets. And that we think is a positive no matter what way we go. And it seems to us as if there is no diminution in interest in the shale and in the Marcellus shale specifically on the part of either domestic or international companies. So while we agree with you, you don't want to wait forever, it doesn't appear to us as if you need to be panicked into doing something either. And we continue to show improvements. We don't think – at this point it doesn't appear to us as if our performance is plateauing.

Zack Trevor – Ducane Capital

Got it. Alrighty, I will let you escape. Thanks so much for the time.

Operator

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

Pat Kane

That concludes today's call. The call will be replayed for a seven-day period beginning at approximately 1:30 Eastern Time today. The phone number for the replay is 412-317-0088. A confirmation code, 436916 is needed for the replay. The call will be replayed for seven days on our website as well. Thank you everyone for participating.

Operator

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

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Source: EQT Corporation Q1 2010 Earnings Transcript
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