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Executives

Patrick J. Kane - Chief Investor Relations Officers

Philip P. Conti - Senior Vice President and Chief Executive Officer

Murry S. Gerber - Chairman and Chief Executive Officer

David L. Porges - President and Chief Operating Officer

Analysts

Scott Hanold - RBC Capital Markets Corp.

Xin Liu - J.P. Morgan

Michael A. Hall - Stifel Nicolaus

Faisel Khan - Citigroup

Raymond Deacon - Pritchard Capital Partners

Rebecca Followill - Tudor, Pickering, Holt & Co.

Jim Harmon - Barclays Capital

Richard Gross - Barclays Capital

Carl Brown - Royce

EQT Corporation (EQT) Q2 2009 Earnings Call July 29, 2009 10:30 AM ET

Operator

Now I would like to turn the conference over to Mr. Patrick Kane, Chief Investor Relations Officers. Sir, the floor is yours.

Patrick J. Kane

Thanks PJ. Good morning everyone and thank you for participating in the EQT Corporation Second 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 second quarter financial results that were released this morning. Then Murry will provide an update on our drilling program in other operational matters. Following Murry's remarks, we'll open the phone lines up for questions.

But first, I would 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, total and daily sales volumes, reserves, financing plans, operating cash flow, capital budget, growth rate and other financial and operational matters.

Finally, it should be noted that a variety of factors could cause the company's actual results to differ materially from the anticipated results or other expectations expressed in those forward-looking statements. These factors are listed in the company's form 10-K for the year ending December 31st, 2008 under Risk Factors as updated by any subsequent Form 10-Qs which are on file at the Securities and Exchange Commission and also available on our website.

I would now like to turn the call over to Phil Conti. Phil?

Philip P. Conti

Thanks Pat. Good morning everyone. You read in the press release this morning, in our second quarter 2009 earnings per share of $0.20 which compared with EPS of $0.44 in the second quarter last year. Just like last quarter, this was another very strong operational quarter for the company in terms of volume growth, drilling progress and cost structure. Murry will talk a lot about that in a minute.

However, the financial results were once again, negatively impacted by the continued lower commodity price environment. That environment impacted EQT results in a couple of different areas as lower NYMEX went to lower realized gas prices and significantly reduced EQT Production revenues And also lower NGL prices, suppressed revenues and EQT Midstream processing business.

As we have shown in the table in this morning's release, the EQT realized natural gas price was $5.25 per Mcf in the quarter or 31% lower than $7.60 per Mcf price we saw last year. Just to remind you for segment reporting purposes, that 5.25 per Mcf of revenue realized by EQT Corporation has allocated us $3.59 per Mcf to EQT Production and $1.66 per Mcf to EQT Midstream.

In total, lower commodity prices resulted in about 62 million less net revenue in the current quarter versus the second quarter last year. We're going into a little more detail in all of that as I briefly discuss result by business unit starting with EQT Production's operating results.

The big story in the second quarter at EQT Production was the 22% increase in average daily sales volumes versus the second quarter last year. The second quarter volumes were also 6% higher than just last quarter. That sales growth progress for EQT represents a pretty staggering level of progress in a short period of time and in a somewhat constrained environment. And again, Murry will elaborate more on all that in a few minutes.

So, we continue to realize the benefits of all the work we did in 2008 and the first half of 2009 and we continue to be very encouraged by the sales growth results. But again, like last quarter, the bad news was that the volume increase was more than offset by an average NYMEX price that was down 68% and an average wellhead price to EQT Production that was 42% lower. That price decline resulted in $55 million less revenue in the production business in the current quarter versus the same quarter last year.

While dwarfed by the absolute decline in NYMEX, we also did see a drop in basis to about $0.09 per Mcf on average in the quarter versus $0.31 per Mcf the last year and $0.18 per Mcf in the last quarter or the first quarter of 2009. That drop in basis is largely as a result of the nearly 70% drop in absolute NYMEX from an average of almost $11 in the second quarter '08 to about $3.50 per MMBtu in the recently completed quarter.

Another item I should also point out that we did realize a $1.71 per Mcf benefit in the current quarter as a result of hedge position. Total operating expense at our EQT Production were higher than second quarter 2008. However, on a unit basis, the total cost to produce, gather, process and transport EQT's produced natural gas was actually down almost 10%. And that is even excluding the impact of significantly lower production taxes which you can see in the unit cost table we provided in the release this morning.

So we are starting to see some of the benefits of scale. DD&A expense was higher, reflecting our significant drilling investment and growing production levels of late. The Company also invested $4.4 million in the quarter for the purchase and interpretation of seismic data which shows up as exploration expense in the second quarter financial result. Exploration expense year-to-date is $7.7 million and we project it will be around $16 million for the full year. And finally, production taxes were 5.8 million lower, again as I mentioned, reflecting the lower NYMEX prices.

Moving on to the Midstream business, operating income here was up 39%, consistent with the overall growth of gathered, processed and transported volumes as well as the selling of the Big Sandy pipeline capacity which came on line in the middle of the second quarter of 2008. Gathered volumes increased 18% mainly from gathering EQT Production's growing sales volumes and that resulted in a 22.5% increase in gathering net operating revenues.

Transmission net operating revenues were also up 66% mainly again, from the fact that in 2009, we had a full quarter of Big Sandy operations versus only one and a half months in the second quarter of 2008.

Processing volumes increased by 89% as a result of a full quarter of operation of the Langley plant which did not go into operation until the third quarter of 2008. The average liquid price was $0.63 per gallon in the second quarter '09 or less than half of the $1.57 average liquid price that we saw in 2008 and the impact on 2009 second quarter net operating revenues was a negative $7 million.

However, the higher processed volume more then offset that NGL price decline as you saw in the release this morning.

And finally, storage, marketing and other new operating revenue were 68% higher. Mainly from revenue generated by selling Big Sandy capacity not currently needed by EQT Production.

Operating expenses at Midstream were about $11 million higher than last year and that increase was expected based on 2008 infrastructure investments as we prepared to continue to remove record production volumes to market.

DD&A expense at Midstream accounted for $5 million of the $11 million increase in expenses while increased electricity and labor to run our expanded compressive fleet accounted for most of the risk.

Moving on very briefly the distribution, operating income, the distribution was $9.4 million in the second quarter or $7.4 million higher than in 2008. Approximately $3 million of the increase was due to the higher rates effective at the end of February, when we received final approval of our previously announced settlement of the overseas Pennsylvania base rate case.

Lower bad debt expense mainly associated with an increase in customer participation and state and federal low income assistance programs explains the majority of the rest of the increase in operating income at Distribution.

And then finally, a brief liquidity update. During the second quarter, as you well know, we completed a $700 million offering of 10-year 8% senior notes which significantly improved our liquidity outlook. As you will see in the Form 10-Q that we'd release later today, the company had about $335 million of cash and cash equivalents on the balance sheet at the end of the second quarter and no short-term borrowings outstanding at 6.30, 2009.

Based on commodity prices that have trended lower, we are now estimating our 2009 operating cash flow to be above 550 to $600 million inclusive of the $99 million tax refund which we did receive in April. So adjusting for the change in cash flow estimate and the recently completed debt issuance, we are still forecasting a very manageable less than $200 million of outstanding under our revolver at year end, excluding working capital swing.

And with that I turn the call over to Murry.

Murry S. Gerber

Thanks Phil. Welcome everybody. Just to reiterate the message that Phil gave, it was a very strong operational quarter and the headlines statistics on the operations was the production sales volume growth of 22%. Just want to remind shareholders that's this growth that we are seeing at EQT, at this point in time is driven entirely by our Huron Ba Ria play horizontal drilling in those place of course. It's all organic growth. And at this moment in time anyhow, there is really not a very material contribution from our other main play, the Marcellus in the production sales volume growth.

So, as we're looking forward and we'll talk more about Marcellus in a minute. Just be aware that result to date do not include a material contribution from the Marcellus.

I Phil said we believe this is the highest period production sales growth we've ever had. Now, the company's been around for over 100 years. So, we didn't have all the statistics readily available for going back all the way but at least in recent time, this certainly is the highest period-on-period sales growth that we've ever had. And we are raising our production sales volume guidance as you saw in the release 98 to 100 Bcfe or about a 16 to 19% increase expected for 2009 versus 2008.

On drilling for the first six months, we had about 167 wells in the quarter, 91 horizontal in the quarter. Year-to-date total gross spread wells of 304, total horizontal wells are 148 so far.

Turning first on the Huron Ba Ria play. In that play so far, for both zones, we drilled a little over 600 total horizontal wells and just to remind you the scope of this play, we have more than 2.2 million acres in the, Huron Ba Ria play with more than two zones available for us to drill per drill site on average. We so far reported 6 trillion cubic of 3P reserves that is at the end of the year 2008.

We reported that with an estimated 13 Tcf of resource potential in that Huton Ba Ria play. As we continue up the learning curve, applying the technology like stack and frac, we continue to see evidence that per well reserves will go up and are going up and drilling F&D costs are going down.

On drilling cost efficiencies just to frame it, our single-leg fractured Huron well used to cost us about 1.2 million. This year in 2009, the same type of the well apples-to-apples comparison on a well cost about 1.0 million and the savings are basically attributed about half the learning curve and the other half to reduce steel and the other half to reduce the O&M... completion cost.

On the stack and frac, these are the stacked multilateral wells where're we're now fracturing them. We have drilled 19 multilateral so far. Nine are fracs and online. So, nine of those multilaterals are frac online 7... and that's additional three are fracs but not online and seven are just multilaterals that we took as natural completions. We plan to drill 15 to 20 of those frac multilaterals in 2009.

The advantages of this stack and frac as we mentioned before increase the productivity and maximized the volumes for well pads, to reduce the midstream infrastructure cost, particularly in southern Appalachian, 30 days IPs for the multilateral wells or approximately 750 million a day. We're thinking that we can get the cost of the this multilateral down to about 1.2 million for the which is a significant reduction from what I think previous talked about and although it's little early on it, we are definitely thinking that will have drilling costs, drilling F&D cost below a dollar and I said that last time, I think the only new one this time is we're feeling even more confident about that today than we were last quarter.

On a Marcellus, just to update you, we have 400,000 acres in the play. To date, we spent 21 horizontal Marcellus wells. We have a bunch a verticals as I mentioned last quarter but we are focusing all of our activity at this point on horizontal Marcellus wells. 18 of those 21 have been drilled and completed to the point of having reliable cost data and I will get to that in just in a moment.

12 wells have at least an initial test rate. But only 8 of our oil wells have been turned in line and have been on production for greater than 30 days. We are still on track to drill 41 horizontal Marcellus wells in 2009.

On well cost we've seen a pretty dramatic improvement in well cost this year and particularly during the past quarter and parenthetically I know a lot of you have been in the business a long time but this has been the most dramatic learning curve that I have ever seen in my career. Doesn't mean it doesn't happen to other people in other places but at least we seem here to be able to do something that is extraordinary.

During the first quarter of 2009, our average completed Marcellus well cost a little over 5.5 because there were some that were higher than that, some that were lower. And on the last call, based on our knowledge of the time, we reported that we could lower... our vision was that we could lower our completed Marcellus wells costs at 3.5 to $ 4 million. We have already exceeded that goal. Our most recent fore wells have average completing cost of about 3.3 million. We now think that we can get the cost even lower to 3 on average.

And the reason for those drop... the drop in the cost has been several factors; not all of these are equal but drilling days are down by half. That's helped. Water handling driven by mostly onsite recycling has been a significant contributor completion costs, excluding issues related to water have been pretty significant costs and location costs, building locations and we have seen a little bit of benefit of headroom so far has also had a fairly significant impact and that really explains the variants from 5.5 to 3.3 that I just mentioned.

In drilling days is about a quarter of that water is about 30% completion, 30% and the location cost about 14% of that variant. EURs from Marcellus, we're expecting to be in a 3.5 Bcfe range, a little higher than the 3.2 we reported last time and the reason for our optimism is that we've seen some considerable variability in initial test results and that is likely to be pointing us to hotspot that up till now, we haven't had. As you know, EQT hasn't had really headline 30 day IPs but some of the data that we're getting tends to make us think at this point that we will see some of those hotspots and those will tend to drive our overall EURs up, maybe even beyond the 3.5 that I just mentioned.

In any event, Marcellus is turning out to be nice add-on to our Huron play. Both plays are moving in a direction where drilling F&D costs will be below $1 per Mcfe at reserves. So the drilling F&D below $1 for both Marcellus and for the Huron Ba Ria play, we are at this point quite confident of that.

Turning to the Midstream and in particularly the AquaTrans (ph) we've spoken a little bit about that over the last couple of quarters. We have a little bit more to talk about now. As many of know, the trans pipeline system runs through much of our West Virginia and Pennsylvania acreage and really runs through the heart of the South Western portion of the Marcellus play. It currently has an annual throughput of about 600,000 decaterms (ph) a day.

Our vision based on industry interest that we have seen to date. We've spoken to a lot of producers, we are getting a lot of indications of interest. Based on that interest, we intend to leverage the existing AquaTrans (ph) asset to add incremental capacity of approximately 1.2 million decaterms a day. Currently, we expect that 70% of that capacity would be spoken for by third party producers. Obviously, EQT will take some of that too, may be more. But that's sort of current first pass estimate of what we think we can do there.

Now, why EQT and why AquaTrans and why is there such interest in this particular asset? Well, there are a number of factors that are important. First of all speed. The pipeline's there and as we turn this thing around from being basically a pipeline that delivered gas to the industrial market in Pittsburg and turn it around to be a high pressure gathering system for the Marcellus highly needed bit of asset, this high pressure gathering. It's already there and it already provides a considerable amount of capacity to be able to be let. And so speed for the producers is very important. And I think that's way they are starting to favor us.

We have existing right write aways, very important and not only the existing write aways, but existing write aways that already have high pressure pipelines on them.

So, they have the legacy of carrying that high pressure pipe. And course nimby issues etc. etc. this is a very, very important issue. Another key factor for the AquaTrans system is that it's currently connect with 5 inner state pipelines. Texas Eastern, Tennessee, Dominian, Columbia and National Fuel Gas. And as I mentioned again later, the... and really to emphasize a bit what Phil talked about on bases earlier it's going to be important for Appalachian producers to have the ability to deliver their gas to the highest value markets and this asset is already set up to deliver gas from the Marcellus into multiple markets through these very, very important interconnects very difficult to recreate. And because the pipeline is already there and we believe that at the end of day that our customers on this pipeline will find it to be a cost effective solution.

Just a quick scope on it, this particular project, the AquaTrans project we think has the potential to double or more the total EQT Midstream EBITDA over the next 5 years just from the expansion related to the Marcellus alone and I know the Midstream has a number of other projects on line to serve EQT particularly in the South and other things that we're doing but this particular expansion to serve the Marcellus has the potential to double this EBITDA over the next years hopefully do even better than that.

Drilling down just a little bit more there are more than 10 non-jurisdictional and frac regulated projects that we're currently working on and association with AquaTrans. On the non-jurisdictional side we should go a little bit quicker the first project we expect to be completed by early fourth quarter 2010, this is a rather small project its only a 105,000 decaterms I mean not too small but it's not a huge project. It's less than a $100 million in capital.

We're still doing the engineering on this but it seems like it's going to fall in that kind of range and precedent agreements, the firm agreements that we need to go forward with this project are currently being negotiated with producers. On the frac regulated side you'll recall that I previously said that we had an open season or that we conducted an open season last fall and we got at that time over 300,000 decaterms a day at interest from producers.

Since that time there has been a significant increase in interest that is going to cause us to run another open season. We're expecting to do that in the September, early October timeframe and again it will be... it's based on the fact that we the new open season is based of the fact... the conducting of the new open season is based on the fact that we're seeing considerably more interest.

If the thing gets to level that we're talking about, if the interest that we've seen so far is confirmed then over the next few year we have got the potential to spend obviously supported by contracts with producers 650 to $700 million although any of that spending as I said will be contingent on the firm contracts and it won't be expected to begin until 2011 with current in-service dates for various projects starting in 2011 and then going through 2013. And as we get more specific in details on this vary exciting project we'll update you and you should expect to get another update from us on the third quarter.

As Phil mentioned and I previously did too, basis did move around a bit this quarter for number of reasons. I think again this adds emphasis to the importance of the AquaTrans redevelopment for particularly interconnects and to the approach that EQT has taken with projects such as the Al Paso 300 line expansion, and it's going to be critical to have these outlets to sell our gas everyday, and to sell the gas at the highest possible price.

In Distribution, we haven't said a whole lot about it. I did want to make you all aware that the Distribution segment continues to show very, very impressive results and efficiencies, effectiveness and their overall operational excellence efforts.

One thing I would point you to is remarkable statistics for me anyhow, and that is that we were able to, even in a very bad market, reduce bad debt. And we have delinquent customers down 8% since October 2008, which is remarkable. It takes a lot of effort to do something like that, and our Distribution folks have done a fantastic job not only collecting money from those who can pay but also making sure that those that can't pay are on various support programs to be able to pay their gas bills.

So, that's really the operational highlights. I would just like to make a brief comment on pacing. There are lot of things that EQT is concerned about but among the things that we are not concerned about or not issues for us and I think it should be important to emphasize we you all, is that we are not concerned about revolver redetermination, we are not concerned for any near-term financing, equity or debt, we are not concerned about holding our acreage through drilling obligations. So, there are a number of things that we are not concerned about liquidity is Phil mentioned earlier.

What we are concerned around here about is pacing and how fast this asset, this considerable asset should be developed. As I have mentioned in the past perhaps, a little bit I don't have particular bias at this point in time but we are looking at kind of two end members where one is an end member where we EQT never issue equity. That's a potential and under that scenario, we could grow production at you know 7, 8% for quite a number of years. Certainly well more than a decade. That has implication obviously, to the PV value of the company.

Another option is in end members develop as fast as we can where given our current technology, given the asset that we have in and even the progress we have made and in proving to ourselves how fast we can go, we could certainly have production growth rate exceeding 30% for multiple years any how. But the attended consequence of strategy like that it requires significant more capital and more access to capital and more Midstream infrastructure that needs to be put in place ahead of the drilling et cetera, et cetera.

So those two end members continue to be the one that we are discussing, we've had some discussion with our Board about those end points and number of other cases in between. As we develop our 2010 capital plan, we intend to put that plan in a context of our long-term pacing strategy so that it kind of, all tries to make sense. I just wanted to let you know that we're still working on that, it's very important to us. And will have more to say about in the third and the fourth quarter.

And with that, Pat, I think we'll turn it over to the group for questions. Thank you, all.

Question-and-Answer Session

Operator

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

Murry Gerber

Just for everybody's information, Dave is a little under the weather today. So we'll try to not to stress him out too much. He has small children and their little germ machines are bringing bad stuff on to him so, we are try to not stress him. Anyways, Scott, go ahead.

Scott Hanold - RBC Capital Markets Corp.

I'll try to be easy on David folks; don't you worry.

Murry Gerber

Okay.

Scott Hanold - RBC Capital Markets Corp.

When you look at your Marcellus activity, obviously, those cost coming down were just tremendous accomplishment in the quarter. Now, I guess it's working on some of the productivity. And in terms of where you've drilled and what you've seen and I think lot of your drilling is been focused on sort of Northern West Vrigina side of things. Is there any desire to move Southwest P.A. Is there something different you would seeing between sort of those areas that might contribute to sort of the IP rates that may not be core and core headline IP today?

Murry Gerber

Well. Yeah, Scott, there is considerable factors. Two really big factors. Let me set it this way. I think one factor that I definitely think is operative and I think others are talking about it is going to be natural variability on the Marcellus and I mentioned in my comments and you know how strongly I feel about this whole IP issue and I'm probably the poster child for 30 day IPs out there.

However, I will say that we have had initial production rates that have very quite substantially from place-to-place. We just don't know how important they are. I mean, we've had the tools for the 24-hour test and we've had nearly tens of the 24 hours tests and that I think emphasizes the point that there is going to be some variability.

Now, we don't know where the end for all of these wells because they haven't been on production long enough, how significant they are going to be long enough how significant they're going to be in terms of our EURs. I mean that's really why I've been kind of hesitant and not giving these initial floor test results which I think can lead to some weird things.

But to your question specifically, we're seeing good wells in West Virginia and we're seeing very good wells in Pennsylvania also. Dave, I don't know if there is any... do we know enough to have a significant progress at this point?

David Porges

My feeling of the whole thing is that just two key data points to make. You don't want to extrapolate too much from two key data points. We do know that we very much like this play but beyond I getting into the specifics, I'd say we're in the still a little bit in the experimentation phase other than to say we enough we really like to play.

Murry Gerber

That's helpful. In addition, completion is there is no question that completion has a certain amount of importance. How important completion techniques in the Northern shales will be versus natural variability of the Rockies and I think this is a point they are making is an ongoing question for us.

My personal view if you want to take this for what it's worth is that you know I am hopeful that on average when you drill a Marcellus well you'll get something that's good enough to continue to encourage you to drill. Meaning that I don't think you will need the hotspots necessarily to bail you out. I think the average well is going to be okay, particularly with costs in the range that I mentioned earlier.

So I don't think you're going to have to be dependent on a hotspot is what I'm hopeful of and that's my current working of others. I mean that could prove to be wrong with time but based on what I've seen so far I think that's how it's going to play out.

The average well will be okay. It will be a distribution and occasionally you'll run into something that's pretty darned interesting and but that's my... and again don't hold me to that forever but that's kind of how I'm thinking about it right now.

Scott Hanold - RBC Capital Markets Corp.

Is there anything change in the completion technique? What exactly can you talk about lateral length and number of factors...

Murry Gerber

Not really much I think the... I wouldn't attribute these initial well results that I mentioned necessarily to completion. But I think what people are saying and this is really on the backs of a lot of work being done by a lot of people.

So it's not just EQT, but the notion that you have a lot of frac busters in these fracs I think is catching on as a major important element. And I think more than I thought earlier hitting yourselves, getting a well planted in the Marcellus in the most highly fractured zones is going to be important.

And the very interesting think about the Marcellus and this is something I didn't anticipate was that the more organic rich part of the Marcellus is also the zone that has the most, what we're seeing is organic silica, silica that was deposited along with those rocks.

Importance of that is that it provides... it's brittle. So the most organic part is also the most brittle part. That is normally the case in organic shales. The advantage of that is then if you do a lot frac buster you can be pretty effective in rubblizing if you will or creating a big zone of permeability around the borehole and that's something that I think we've learned over time in the Marcellus and may be others have learned it.

So that is unique as far as I can tell among the shales.

Scott Hanold - RBC Capital Markets Corp.

Okay and just specific on the completion the last four wells you said that it had came in at around to 2.2 million. But what was the lateral length in frac?

Murry Gerber

3500 feet plus or minus. Yeah 3500.

Scott Hanold - RBC Capital Markets Corp.

Right is a 10 page frac.

Murry Gerber

Yeah that and the frac cost I think of five or six frac busters per stage or something like that.

Scott Hanold - RBC Capital Markets Corp.

How many stages you done with almost?

Murry Gerber

Six stages I think.

Scott Hanold - RBC Capital Markets Corp.

Okay.

Patrick Kane

I can get that for you offline.

Scott Hanold - RBC Capital Markets Corp.

Okay.

Murry Gerber

I mean there are is experimenting Scott, that's what I am getting at six to eight and then five, six frac busters per stage, that sort of thing.

Scott Hanold - RBC Capital Markets Corp.

Okay.

Murry Gerber

And then they're experimenting with sand a little bit. But again I wouldn't focus too much on that, I think the issue of placing the well in the right part of the Marcellus I think is more important than I originally thought and that there is just there is going to variability from place to place.

Scott Hanold - RBC Capital Markets Corp.

And remind me how many rigs are going to be running in the Marcellus three to four?

Murry Gerber

We are going to do 41 well in total. We are going to start 41 wells in total. I think we are going to have three rigs running.

Scott Hanold - RBC Capital Markets Corp.

Okay 3 rigs. And so, when you look out were those rigs be? Are they going to be in West Virginia or...

Murry Gerber

Both Southwest of Pennsylvania and West Virginia.

Scott Hanold - RBC Capital Markets Corp.

Okay. So it's a mixture.

Murry Gerber

It's going to be a mixture of all those areas.

Scott Hanold - RBC Capital Markets Corp.

Okay.

Murry Gerber

These 41 wells, Scott, by the way, we're still trying to scope out limits to the play, the variability to play. So, we want to really spread as much as we can. On the other hand, we are on the fine line, we're sort of, fairly fine line that we want to able to have this close enough the infrastructure. So that we can blow them, so that we can see what the 30 IPs and ultimately, hopefully, get some kind of an EUR on these wells. So we're sort dancing around both try to get close to infrastructure that we have.

Or that we will have in the near-term around the AquaTrans system and also being able to scope the play a little bit more around the 400,000 acres that we have. So, we are kind of trying to deal with two goals at the same time.

Scott Hanold - RBC Capital Markets Corp.

Okay, now appreciate that. Okay, I mean that's a lot good color. I appreciate that all. And one quick question on AquaTrans. When you look at that time that states 2011 to 2013. Is there any reason you couldn't accelerate that given the level of activity and interest in the Marcellus by their operators? And secondly, when you look at line, is that something that would only service Southwest P.A. or West Virginia, or is that something they could do and so the greater Marcellus playing including the part of the play?

Murry Gerber

To the first question I think the timing, on how fast we are going to be highly dependent on what happens in this next round of open season and then importantly, what kind of specific agreement we get signed with producers. I mean if they are attracted to go quickly, we can accelerate. But we'll have to see. So I think that's an unknown at this point in time.

To your second question, yeah, I think we can expand up to the north and the reason I say that is because we are more inclined to take on Greenfield extensions to AquaTrans system and other may wishes to do that because of these interconnects that we have. And so it's the AquaTrans is going to be an easier thing to connect into, to provide maximum flexibility for producers to deliver their gas to best possible markets.

So, depending on how the play evolves and depending on the interest, I think Randy and his team are definitely open to the idea of expanding to the North. And we also have some distribution assets up there too, by the way, which could potentially be used as high pressure gathering for the northern extension of the Marcellus there. Dave, did you have anything to add?

David Porges

And just on that, that jurisdictional piece of AquaTrans. Even though we can certainly try to get in a lot quicker than 2011 to 2013 but your jurisdictional piece which is always we are referring to it for that timeframe, that is subject to the normal bulk timeline and does mean that it's harder to get it done quickly.

So, we mention we have got more than 10 individual projects that we are talking about and the one for the non jurisdictional, we certainly see us being able to get in much sooner than that.

Scott Hanold - RBC Capital Markets Corp.

Okay, I appreciate it. Thanks.

Murry Gerber

Okay, thanks, Scott.

Operator

Our next question comes from Xin Liu from J.P. Morgan.

Xin Liu - J.P. Morgan

Good morning guys.

Murry Gerber

Hello.

Xin Liu - J.P. Morgan

For your Huron play, what's the update on your recent wells that are not lateral and not fractured? IP rates constantly high.

Unidentified Analyst

as I mentioned in the call, the 30 IP for the frac multilaterals are about 750 a day. And we are not quiet here on cost yet but the... we think we can get those frac multilaterals to $1.2 million. There is a little bit of color to that and the reason it's coming down so much is reason we think it's going to down because originally we drilled these multilaterals with the theory that drilling a lot of lateral borehole in the Huron zones was a substitute for fracing a single-leg lateral. And so, the theory was really more feet of horizontal well as a substitute for fracturing.

But our initial flat multilateral were drilled with kind of the same geometry that we've started with. So, very long lateral of the main borehole and I think our team is feeling that we are may not be getting the most effective fracs all the way down those main lateral. So we are in the tighten those laterals up a little bit more. And so that's kind of why those costs are going to start coming down abut about 750 and 1.2 million and hopefully there is some upside on both of cost and volumes.

Xin Liu - J.P. Morgan

And then for your non-fractured as well in that?

Murry Gerber

I didn't give a number for those. It's a little bit, it's less. It's in the 4, 500 range. It's pretty significant, it's about a doubling for these fractured multilaterals.

Xin Liu - J.P. Morgan

Okay. You are seeing to expect the F&D to be under data, so you're estimate are on the high end of your estimate on that.

Murry Gerber

Yes, ma'am.

Xin Liu - J.P. Morgan

Are you purely multi-well pad drilling?

Murry Gerber

Yes.

Xin Liu - J.P. Morgan

Okay.

Murry Gerber

We have one well that we are doing now which I guess call this spaceship well or something has it, I'm not sure we are going to do all ten. But has ten wells, initially five wells that five wells five multilaterals at a couple levels. We may not do all ten, we may not be more efficient to do all ten. But that's the kind of thing what we're hoping to... what we hope will become more of a standard operating procedure down the road. But we're in the process of doing that ten well pad right now. And plus or minus wells.

Xin Liu - J.P. Morgan

Okay. Thank you. This is very helpful.

Murry Gerber

Okay. Thank you.

Operator

Our next question comes from Michael Hall from Stifel Nicolaus.

Michael Hall - Stifel Nicolaus

Thanks. Good afternoon.

Murry Gerber

Hi Michael.

Michael Hall - Stifel Nicolaus

Hi. See sticking out back of the Marcellus and the scene of variability... have you seen any additional variability in liquid contents or BTU contents in...

Murry Gerber

Dave, you might answer that. It's been pretty dry.

David Porges

Yeah, that's very less than dry. At this point it does even seem like it requires the stuff we're finding does even for processing. It's extremely... the BTU content on some of the stuff is about 10.30 which is almost spot on pure methane and there is small amounts of heavier stuff and various also small amount of inert.

So again, one thing we wish to caution on we still don't have enough data points to make broad conclusions. There are other folks in the play who have more data points then us and we suggest that from your prospective you just view the data points we've is part of the overall portfolio of data.

Murry Gerber

I think there is some emerging though that there's not just going to be a line on a map. I think it's going to more variable than that. And there are a lot of reasons for that. There are some geological reasons that are starting to emerge. I'm sure some of us have talked about we're starting to consider internally here about the early deposition of history of the Marcellus and whether that has some implication for the kind of carriage those deposited there and those carriages then been more prone for liquids versus gaseous hydrocarbon and stuff like that.

So there is some hypothesis that is emerging but, as Dave said, we don't have enough data point yet to confirm our theory. We're just developing some theories but we don't know if we have any enough data to confirm the theories yet. But I wouldn't be surprise if it turns out to bit more variable than I think all of is originally thought.

Michael Hall - Stifel Nicolaus

Okay. Fair enough. And in terms of the data point you do have at this point, what's the kind of... can you help me think about maybe, North, South, East, West area extent of what you looking at it this point?

Murry Gerber

In terms of the...

Michael Hall - Stifel Nicolaus

The whole line of Marcellus results and in terms of the 20 versus 21 drilled to date. How many...

Murry Gerber

Yeah, may be you will take Upshur County, may be then the southern edge. I guess, Dave, maybe perhaps on West Virginia, Upshur is pretty far south.

Michael Hall - Stifel Nicolaus

Okay.

Murry Gerber

There may be another well further south than that. And then in North, certainly Green and Washington Counties for sure up to the north. So, that gives you kind of a spread. And then, east or west, I mean right in the fair way with everybody else.

Michael Hall - Stifel Nicolaus

Okay.

Murry Gerber

And we are right, we are right in that.

Michael Hall - Stifel Nicolaus

You have been pretty widespread than you have really were.

Murry Gerber

Yeah.

Michael Hall - Stifel Nicolaus

And then, thinking about the, I mean, you talking comfortable with 3.5 Bs per well. At any point, have you think you want to disclose that tight curve or is it really just a tight curve based on that?

Murry Gerber

No, no, absolutely. I think when we get to the point where we have, I think this is helpful for investors when we get deploy where we have a tight curved that we like.

Michael Hall - Stifel Nicolaus

Yeah.

Murry Gerber

And that we think is starting to get representative. I... we will definitely put it out.

Michael Hall - Stifel Nicolaus

And what's the longest data points you have at this point?

Murry Gerber

It is I think we have got well for may be five months five, six months. I mean we don't have enough really to make a tight curve even on that. Yes, we are again we want to make sure that we've got enough data points with enough confirmation of the decline to put something out that seems like it's reasonable.

It's possible that it could be more than one. Given a vast area of extent of this play so we are going to try to be careful not over generalize but on the other hand we will gain and our history as give out curves when we think we're comfortable. The reasonably we gave you our curves very quickly and the reason we did that is because we have 13,000 wells... when we had 30,000 well in the play in the basin but we also had almost 5000 Huron vertical wells.

And when horizontal results started to match the overall decline of the verticals, we felt pretty confident that we had a substantial data set on which to put out some generalized curves. Marcellus, as Dave mentioned, were all a few hundred wells into this play. Basically, the industry and so we are cautiously forecasting EURs but you shouldn't be surprised if they are going to wall up and down a little bit as data starts to come in.

Michael Hall - Stifel Nicolaus

When you think about cost, obviously, substantial cost improvements, you guys think about walking in with multi-year contracts and completions and things along those lines in the next couple of quarters?

Murry Gerber

Yeah, I don't want to.talk about that.

Michael Hall - Stifel Nicolaus

Can you talk about that?

Murry Gerber

I don't think my Drilling Vice President will let me... allow me to announce that on the phone call right now. So wise to say that I think I am going to use the judgment and when we should lock in both drilling cost and completion cost but clearly I think it would be fair to say that there is more of an appetite on any number of commodities including the services right now for providers to be locking in.

And so I think we just have to pick the spot that we think is the best spot for us given what's happening in the market. So the answer to your question is, yes, we will be happy to do it when I think our teams think it's the right time to do it.

Michael Hall - Stifel Nicolaus

Okay, that helpful, I appreciate that. Then on liquid trends, is there any... I mean to what extent can you just kind of phase in some of those volumes? How should we think about it as an ability to ramp up if we have to be a step change in two years or can it be?

Murry Gerber

No. Dave and I don't want to point out. But I think what we try to do by emphasizing the fact that there were ten projects out there is to emphasize that there is a lot of flexibility on AquaTrans (ph) to expanded in a bunch of different directions and, B, because there are multiple projects we are anticipating clearly a phase in volume growth before that.

Michael Hall - Stifel Nicolaus

Okay.

Murry Gerber

Now there may be some large one there will be little step changes but I mean overall we're expecting it to ramp up overtime data unless than any particular...

David Porges

And the bunch was a 100.

Michael Hall - Stifel Nicolaus

Yeah. That's a pretty big one.

David Porges

And that's by... we expect that would kick in by late next year. And again as Murry mentioned in his prepared remarks we would expect that in the third quarter call we'd have more to say particularly on that one.

Michael Hall - Stifel Nicolaus

Okay. Alright, thanks. I think that's pretty well done. Just on housekeeping, the other expense came in the little higher than you think. I mean is there anyway to breakdown what's involving, what's incorporated in that?

Philip Conti

That's not the case. That is mainly the set of compensation points that are mark-to-market with the EQT stock price.

Michael Hall - Stifel Nicolaus

Okay.

Murry Gerber

So. It's a lot of details to indicate but then you want to give me a call to walk you through that pretty quickly.

Michael Hall - Stifel Nicolaus

Probably better. Thank you very much.

Murry Gerber

Alright, thanks.

Operator

Our next question comes from Faisel Khan from Citigroup.

Murry Gerber

Hi, Faisel.

Faisel Khan - Citigroup

Hi, how you doing?

Murry Gerber

Very well, thank you.

Faisel Khan - Citigroup

Okay. Just going back on pace, in the near term in the production ramp, you guys have had, you continue on the sort of ramp when would see a little more infrastructure and what much time did you brought your kind of infrastructure you have in place?

Murry Gerber

It's a good question. It's actually very central to the whole pacing plan. We'd like to get as much gas to market as we can with little infrastructure and so we are as we are developing these pacing plans certain of our options particularly on the... we are we intend anticipating going full to develop as quickly as possible we have to constrain Midstream investment and put it in the right place.

It kind of depends I mean we still have a considerable amount of capacity downsize because of all that work that we've done over the last few years and certainly a couple years at least of capacity down there. And then the Marcellus depending no how the well results go. The AquaTrans option for transfer in gas accelerating projects if we can and building little project might be a very attractive accelerant. And a cost effective is accelerant too to that growth.

So, I'm really, Dave and I, are still working hard in the team, are working hard on pacing is actually why we have this call, we're talking about pacing again today. But I'm sorry I can only give you color, I can't give you specific here on this.

Faisel Khan - Citigroup

Okay, got you. And then in your high end case, say now a 30% will that all be sourced from your Huron play or is that considering Marcellus?

Murry Gerber

No, we consider both.

Faisel Khan - Citigroup

Okay, got you. And then just on the focusing on the cost structure for little bit, the sequential uptick in LOE in the second quarter versus first quarter but would cost that go up a little bit?

Philip Conti

Somebody even asked that question on the first quarter call. We thought the first quarter was a little bit seasonal and bit of a trend to what it looked like for last year it was closer to $0.28, that you are looking at. I think first quarter was just a little low and we did say that on the first quarter.

Faisel Khan - Citigroup

Okay, guys. And exploration expense higher?

Murry Gerber

Well we're doing size I mean we're shooting a 3D seismic program and so we're just seeing the expenses coming for that. I mean I we're focused primarily on deeper things and it's something we've had in play for quite a long time and we decided to carry forward with that project not only because the deep well but also because of what we might learn on the more sellers and other more shallow zones. So we decided, Dave and I, to continue with that project rather then delay it.

Faisel Khan - Citigroup

Okay, got you. Thanks for your time guys.

Philip Conti

Okay.

Operator

Our next question comes from Ray Deacon from Pritchard Capital.

Raymond Deacon - Pritchard Capital Partners

Yeah, hey, good morning.

Murry Gerber

Good morning, Ray.

Raymond Deacon - Pritchard Capital Partners

Hey, I was just wondering, Murry, what is governing the location of the Marcellus wells that you are drilling? Is it partly infrastructure, partly a desire that kind of test out what you see is a fair way?

Murry Gerber

Both, it's really both, I think initially at the beginning of the year, I think we had sort of a mix of horizontal and vertical wells and they were much more concentrated around the existing infrastructure. We start plan had that to be the case, as we got into the year; we developed a strong preference for horizontal wells. So we made that change and based on the results that others were having we decided we needed to spread out a little bit to find out a lot more about our acreage more broadly rather than concentrate in particular spot. So really the answer to your question is we're doing both of those things.

Raymond Deacon - Pritchard Capital Partners

Okay, got it.

David Porges

I haven't heard the production people seem to think that it's a quite strongly influenced by infrastructure and the infrastructure people think that it's not really that strongly influenced by infrastructure.

Raymond Deacon - Pritchard Capital Partners

Got it. So you might be as part of 41 horizontals test that sort a North Eastern part of your acreage position?

Murry Gerber

I do not know if we have a permitted well up there to be honest with you at some point we will yeah but I just don't know that this year.

Raymond Deacon - Pritchard Capital Partners

Okay. Got it.

Murry Gerber

I just don't know I'm sorry I just don't know at this moment in time.

Raymond Deacon - Pritchard Capital Partners

That's fine. I guess just a bigger picture question; you've shown sort of historical cost in your presentations it sounds so you feel very comfortable it could be marching down towards the dollar and Mcf this year about some of the cost. But, is there, with the reduced service costs, is there any other way to sort of talk about the efficiency gains and how that's going to impact your returns this year?

I mean it seems to me you're going to be over the grow production at sort of a much lower cost than in the past year, you sort of adding resource that have a much shorter reserve life and your returns ought to be going up I guess. So I was wondering if there is any way you can kind of put that in context.

Murry Gerber

As far as gas prices, yeah. The third question because it's going to be somewhat depend on gas prices there. But as far as what we can do this certainly we're having some benefits from lower steel costs, lower service costs and better contracting terms, I guess, you might say. But Dave and I keep focusing, I think, on what is fundamentally going to be different and we just have it in our head that dollar F&D is something that we just don't ever want to exceed.

Now having said that, if something occurs that will allow us to spend a bit more money and accelerate production, we are certainly happy to do that even if the unit F&D cost creeps up. So, we don't want to get trapped in a low cost mentality that will restrict our ability to the make the most money.

But as a general principle, we try to do that and in the Marcellus in particular, I mean most of the things I mentioned to you that explain the variance between our average well cost of a couple of quarters ago and now relate to operational issues getting the days drilling down and that's just getting the right property, getting the right bids, operating at efficiency; that's a very big thing and that is EQT driven; water handling clearly EQT driven.

David Porges

And then that we have metrics I mean the water handling is how much of it gets recycled. How far does the water have to be moved et cetera, right.

Murry Gerber

Exactly and obviously location completion costs. Some of it is tuning our completions to exactly what we need. I don't think we are there yet. I think we are experimenting there. But we've the wind at our backs with respect to the overall market for completion services.

So, I think when I look at overall reductions and then... by the way that's on Marcellus. On the Huron play that's clearly a mostly well geometry stuff that EQT is doing to try to improve productivity based on just new techniques and more innovative ways to drill the wells. So I if I have to put a number out there I say at least two-thirds of what we are seeing is EQT innovation and the rest of that probably comes from market cost reduction.

David Porges

Steel costs, tubulars are really not that low, if you look back any more than six months or so, or eight months. And if you look, I don't even think steel costs back to where we were in the beginning of '08.

Raymond Deacon - Pritchard Capital Partners

Got you, great.

David Porges

If you look at it from that prospective, it kind of took a blip up and maybe it just come back a little bit more to where it was.

Murry Gerber

So our view is as a general matter less than a buck on F&D drilling. Now that's not going to show up as... I'm sorry drilling F&D. In frac I'm sure because I believe for most of the wells we're growing these days anyway we do add reserves for the wells that we drill. So the overall F&D will be a little less than that. But when you're looking at drilling F&D, we kind of target a buck. We don't want it to be much more than that.

Raymond Deacon - Pritchard Capital Partners

Got you, thanks. And I guess has the cost reduction you talked about in the Marcellus, does that factor in what you've been able to achieve with the new special purpose rig or is that something that could be incremental?

Murry Gerber

I think it could be incremental, I mean I think the rigs... one of the things that the new rigs are able to do is get a little bit quicker from location to location on the pads and stuff like that. So and the new ones as our Drilling VP is scoping about and having them either built or retrofit for us. We've done a little tweaks that are really improving the process so, yeah.

Raymond Deacon - Pritchard Capital Partners

Got it, okay.

Murry Gerber

Right.

Raymond Deacon - Pritchard Capital Partners

Hey, just one last quick one, I mean would you attribute the increase in the guidance for 15% or 16 to 19 to one play or one area?

Murry Gerber

Huron. Absolutely right. Yeah, I mean, I think that's... it keeps I think I don't want to whine about this but it keeps being underappreciated part of the EQT story.

Raymond Deacon - Pritchard Capital Partners

Got it, okay, great. Thanks very much.

Operator

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

Rebecca Followill - Tudor, Pickering, Holt & Co.

Good morning. Following up on what you said, Murry, on pacing. I guess it's not just a question of pacing, it's also a question of allocation of capital.

Murry Gerber

Yeah.

Rebecca Followill - Tudor, Pickering, Holt & Co.

Especially, in light of this larger AquaTrans project. So when do we get a feel again releasing we're still discussing this with your Board for how much capital you're going to allocate and when to get a feel for financing needs and the bigger picture?

Murry Gerber

Yes, good question. I think the... I don't think we are going to have a good solid thing to talk about with you all until late this year, is what I would say. And the allocation question you raised is a good question; maybe just give a little new answer on it.

First of all, as far as we're concerned right now on the drilling side, on the production side, we're not seeing a lot of preference between Huron, Ba Ria and Marcellus at this moment in time in terms of allocating capital; maybe that will change with time.

Certainly, existing capacity will favor certain areas versus others and that could have a bearing on where capital is allocated. As far as Midstream though is concerned, the advantage of the AquaTrans reinvention is that a lot of that is paid for by third parties. It's certainly our capital upfront but it's financible, if you will; some commitments that are made by producers. And both Dave and I and Phil are very open to the idea of alternative ways in which that Midstream can be financed.

At this point in time, it appears to us, and may be it's just a temporary problem, but at this point in time it appears that what we... and this is how we're acting, that we will have to build it at least, will fill it and then hopefully people may wish to be partners with us at that point in time. In other words it seems to be interest in buying assets that have existing cash flow histories and something that can be depended on.

At this moment in time, we haven't seen a lot of interest by others in doing the Greenfield development or the initial development and putting the capital out. So, but that could change and if does change, I think we're open to the possibility of having partners on the Midstream even at an earlier stage of development if the cost of capital that's presented to us is something that we think is reasonable for us and is not too onerous for us.

I realize it's a long way when you questioned I just want to give you so little bit a long line answer just want to give you a little bit color about how we're thinking about it. But in direct answer to your question not till late this year.

David Porges

And that jurisdictional portion of the AquaTrans piece for the Marcellus does not require a financial commitment from us this year and will not require a financial commitment from us next year. So from our perspective that's par and half that we don't need have to worry about how they finance. But first of all, we have to make sure that there is not interest and go from there.

Rebecca Followill - Tudor, Pickering, Holt & Co.

Alright. Thank you guys and thanks for the well data.

Murry Gerber

Okay.

Operator

Our next question comes from Robert Mellon from Ducane (ph).

David Porges

Hey, Rob.

Unidentified Analyst

Hi, how you guys doing?

Murry Gerber

We are okay.

Unidentified Analyst

My questions were asked and answered. Thank you very much.

Murry Gerber

Okay.

Operator

Okay. Our next question comes from Jim Harmon from Barclays Capital.

Jim Harmon - Barclays Capital

Hey, it's Rick and Jim, how are you guys doing?

Murry Gerber

Hey, Rick and Jim.

Jim Harmon - Barclays Capital

Thanks for the change in the conference call operator so we could ask our questions this quarter.

Murry Gerber

Oh, I am sorry if you could not.

David Porges

But that was just a specific Barclays execution on our side.

Unidentified Analyst

I might just look through.

Jim Harmon - Barclays Capital

Check that up. You said in an email now to make sure you guys don't get through this.

Unidentified Analyst

I think it's the number.

Patrick Kane

Alright, alright. What's your question, James?

Jim Harmon - Barclays Capital

Well, the question was and the answer that I think in general today it's going to the 400,000 acreage in Marcellus was between your drilling this year and others drilling around it kind of the special sampling, how much of it do you in core I guess will be tested that you will have pretty good idea of what percentage might be, might be good?

Murry Gerber

Well, that's a tough one because I think the thing that the cause... I don't want to avoid the question but I just want to give you the facts around that. We are seeing some well to well variability within relatively short distances and either that well to well variability is because of very specific issues with respect to completion or it well to well variability because of changes in geology from place to place. I don't think we have enough information yet to determine whether it's one or the others.

So my... what I said earlier, I still hold to I think in general, the average well in the Marcellus is going to be okay throughout our acreage. What we would prefer to do now is buying the hotspots first.

Jim Harmon - Barclays Capital

Right.

Murry Gerber

And I am not sure how that would be done or if we can do that with techniques other than drilling and I think that's sort of a challenge for our geological team and by the way for others' geological teams as well. They doesn't seem to be yet a silver bullet either on seismic or other things that we think is economically useful at this moment of time.

There are varies, there are things that people are thinking about but I know Steve Schlotterbeck in particular is wondering whether it just ends up adding cost and we didn't have drilled wells anyhow and we would really get a lot of incremental benefit from doing that.

But, again we're staying open-minded. There is certainly other opinion in the company about the value of a more remote sensing. So I don't think, I think we're going to be just seeing... trying to make sure that the area that we've acreage on is productive and then I think we will work or start drilling away from wells we think are the better ones I think is how we will currently evaluate.

Once the infrastructure that we're talking about, and that others talk about too, is in there is going to be a mighty incentive.

Jim Harmon - Barclays Capital

Yeah.

Murry Gerber

To use that as opposed to even if wells aren't the, quote-unquote, best wells, right.

If you have a great well that is 10 miles away from the nearest other wells and from the nearest infrastructure it's never be great beyond what anyone's reporting.

Richard Gross - Barclays Capital

Yeah.

Murry Gerber

Justified building infrastructure just for that well.

So, it would be great if you could figure all that out in advance and then put in the pipes next to the bigger wells and all that stuff. But at this moment in time I think it's going to be a bit more hunting pack and then there will be commitments made by producers based on what they have seen two pipes as Dave said once those pipes are in, they'll be drilling well on those pipes to try and fill them up.

Richard Gross - Barclays Capital

Okay. Then this is the variation on that but you indicated that you are still trying to sort out type curves that the IP rates have been variable and it is obviously is a homogeneous and yet you also kind of reconcile that with most tight curves I see in most analyses have done by flat but an IP rates, its going to give you the tight curve in the EUR. And then the EURs is our highly correlated in a lot of this kind of analysis with the IP rates. how do we come up with?

Murry Gerber

You talked about 30 day IPs, right Rick?

Richard Gross - Barclays Capital

Yeah.

Murry Gerber

I think it's more likely that the 30 days are going to show some correlation to EURs and maybe if it's not a very good correlation, it at least gives you a relatively high probability that you'll have a profitable well.

I think we're hoping that is going to be the case, it seems like that is the case in the other shelves place, it certainly is the case in the Huron play and as you know with all of these shelves because they are not linear right by definition. The production mechanisms are not linear that we can't make a deterministic solution for figuring out what the reserves are going to be in the production rates or we're going to be like we did in the Gulf of Mexico and all these other places that we've developed over the years.

We end up having to bet that there is a distribution code, that there is histogram.

Richard Gross - Barclays Capital

Yeah.

Murry Gerber

And that we're going to drill into that histogram and on average we're going to win in total with the play even though individual wells may not be profitable. I think that's just a nature of this beast.

David Porges

What we can... for instance, when you get the large of the high IPs are they just anomalies and you get a lot of gas out early and once you have 1000 wells to drill they just don't matter because frankly in the Huron we were drilling vertical, that's what happened. We'd run into nature fractures you get a lot of volume early.

Richard Gross - Barclays Capital

Yeah.

David Porges

But in the overall scheme things you figure out it really effect the curve.

Richard Gross - Barclays Capital

Okay.

David Porges

Or is that more meaningful, I don't think we feel that we have enough information to now.

Richard Gross - Barclays Capital

Okay. One last question on the price, on the AquaTrans expansion?

Murry Gerber

Yeah.

Jim Harmon - Barclays Capital

Get to the large expansion, I guess I am curious it's an awful lot of gas.

Murry Gerber

Yeah.

Jim Harmon - Barclays Capital

And the producers that would sign up for AquaTrans my suspicion is that side from fact that the interconnection materially is that downstream of those interconnect they are going to have capacity on the other pipe. How much of this depends on kind of a coordinated effort to literally expand everything?

Murry Gerber

That's a good question I don't know how that's going to... I don't think that's going to be played out in a very organized way. I think what my feeling is that producers are smart enough to know that they need to get capacity downstream of the high pressure gathering I think they will do that probably not collectively I think they will do it individually and they will either muscle out firm capacity or pay up for firm capacity downstream of the high pressure gathering and it will be fairly idiosyncratic.

I don't... we'd like to think that you could have the deal of the grand plan. But I think the grand plan given then what David has been talking about and I've been talking about on side on variability the Marcellus and what we know so far. I think the grand plan is very difficult to do given the uncertainties right now and so people are going be contracting for downstream capacity, they are going be backing up, getting AquaTrans drilling into the what they have and then with time the solution will emerge. I mean when all is drilled out, we'll know we have should done at the beginning.

David Porges

There are two series of, let's call on the smaller projects, going to the market. I mean we are at this point quite confident that the pipeline that we are contracted for that our passers and circles of 300 line.

Jim Harmon - Barclays Capital

Right.

David Porges

That is going to happen.

Jim Harmon - Barclays Capital

Yeah.

David Porges

So that's one piece. Other people are working on other things as well. So we don't have the grand solution that had been talking about one point for a huge additional line to go to New York and Boston may be they will come back I don't know. But, there is a variety of folks that we read out there who have smaller projects and in the end I think you get to a fair amount of volume, how many of them were up and how many even more I don't know but just for our guesses some of them are happening?

Jim Harmon - Barclays Capital

Yeah. So I guess that might my question of... you carry it to somebody else.

Murry Gerber

Right.

Jim Harmon - Barclays Capital

And most of that capacity is booked and as you probably tried to analyze all of this in capacity?

Murry Gerber

Yeah, we have and it's very difficult to... there are so many unknowns; you're trying to solve the equation with multiple. You get as many unknowns as you have equations and that's what we are relying on in or what Randy's relying on and the team is relying on is that they want to produce it down and sign the President Agreement that they have worked out whatever those downstream issues are for themselves, right?

And that's what we are relying on in order to ultimately go to the forth with proposals to expand these jurisdictional lines.

David Porges

I mean they are putting up there; they are paying demand charges, a lot about...

Richard Gross - Barclays Capital

I mean you said that subject to your there endeavor they're willing to dig gas to the bottom.

Murry Gerber

I mean other then the attendant credit risk that are going to come right I mean those are the things...

David Porges

I mean I agree with Murry, they're pacing through that.

Murry Gerber

Yeah, they are through and at a one pace sign of President agreements and are willing to pay demand charges. I think Randy and the teams are ready to go and Martin Fritz are ready to go build the pipe.

David Porges

We are not detecting that they are just hoping that markets will developed.

Murry Gerber

That is not what we are detecting.

Jim Harmon - Barclays Capital

Okay. Thank you.

Murry Gerber

Okay.

Operator

Our next question comes from Carl Brown from Royce.

Carl Brown - Royce

Hi guys. Also on AquaTrans, Murry, did you say that of the 1.2 million of additional capacity that 70% would be from third party including EQT or EQT is the other 30%?

Murry Gerber

Yeah, right. And this is a very rough number, Carl, but very rough number but yeah and it is reference only to the 1.2 I mean if Steve and the team come up with Marcellus then there might be bigger share of EQT.

But right now in the context of the 1.2 million debt kind of a vision for AquaTrans we're thinking it's about 70, 30 but that could change.

Carl Brown - Royce

And what about the base 600,000 that exist today, what happens to that?

Murry Gerber

The base 600,000 is called on for use by the distribution system and other producers. I don't want to get into a long detailed discussion on this but AquaTrans delivers to several others and also has storage attach to it and so there are LVC around the east coast that use acreage trends for dealing storage that we have for them, Dominion has for them, the others have.

So that system is basically utilized. I mean there's a little extra capacity that can be used but not a whole heck of the lot. Okay, and spoken for I guess is the way you would say it.

Carl Brown - Royce

Yeah and in terms of your commitment or your ability to commit to capacity on that system, what... when is the timing for the system when you wouldn't have binding agreements sign because I'm imagining that you've got the certain level conviction today in terms of the volume that can come out of Marcellus so that conviction could be very different six months from now or a year from now?

Murry Gerber

Yeah, again at this moment in time, we've got enough interest by EQT and others to have another open season. That open season will occur in the fall and then after we get those indications of interest, we'll proceed down to getting agreements, more firm President agreements signed with producers and at that point I think we will be able to be much more clear about this call.

Carl Brown - Royce

Okay so some are going some more again later end of the year or early part on next year?

Murry Gerber

Yeah.

Carl Brown - Royce

Okay and final question just on, when you talk about the pacing and the two end games of lower growth rate without needing to access capital markets versus the higher growth rate but needing to access capital markets, things like partnering and assets sales would that be in the kind of the in-between category that you referred to?

Murry Gerber

It could be, yeah. There is this and I think it's important that everybody knows that it's going to a little difficult to move easily from one strategy to another.

Once, for example, once committed to a very high growth strategy the commitment to build the pipes is a big commitment and then at that and then when those pipes are built that the quality commitment to fill it up is already set in motion.

So, once we pick a pacing strategy I mean there is going... the generics are in place for that kind of growth; I mean plus or minus I mean that there can be some variance around that overall strategy. But, we will be setting the pace pretty clearly at that point in time. So and as I said earlier we're not going to be in a place at this moment and time where we will be able to, we will not be able to clear about that till the end of the year.

Carl Brown - Royce

And you referred to...

David Porges

Partnering could be in there other ways the finances once we decide what the right pace is, financing it through partnerships or traditional forms of capital raising are all going to be considered

Carl Brown - Royce

Okay. And finally you alluded to that as potential on the Midstream business also on the EMP side as well?

Murry Gerber

I suppose but my personal preference at this point is not on the upstream although that could happen but right now it could be a great deal which we look at but we haven't seen one and on the Midstream as I mentioned earlier at this moment in time, I think that partnering would be mostly financial partners and probably after the pipe has been built and filled, at least that's what the market is presenting to us right this moment, okay.

Carl Brown - Royce

I mean also...

Murry Gerber

But that can all change, Carl, I mean that things can change.

Carl Brown - Royce

Ultimately, are you just looking at what's more dilutive, potentially issuing equity or giving up some of the economics to your partner?

Murry Gerber

What's better for PV value and keeping and part of PV value is keeping the cost of capital as low as possible and making sure that the return on total capital is as high as we can without sacrificing growth. So those are always been the factors that we look at around here.

Carl Brown - Royce

Okay. Great, thanks very much.

Murry Gerber

Alright.

Operator

Ladies and gentlemen, that concludes the question and answer session for today.

I would now like to turn the call over to Mr. Pat Kane and others for the closing remarks.

Patrick Kane

Thank you, everyone. That concludes today's call. There is a replay of the call that's available around 1:30 PM today. The phone number for the replay 412-317-0088 and there is a confirmation code for the replay 432-367. And that will be available for seven days.

Thanks and have a good day.

Operator

That concludes the EQT Corporation's second quarter 2009 earnings conference call. You may now disconnect.

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