EQT Corp (EQT) 2009 Q2 法說會逐字稿

Good morning, and welcome to the EQT second quarter 2009 earnings conference call.

(Operator Instructions).

Now I would like to turn it conference over to Patrick Kane, Chief Investment Relations Officer.

Sir, the floor is yours.

Thanks, PJ.

Good morning, everyone, and thank you for participating in EQT Corporation's 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 and other operational matters.

Following Murry's remarks, we will open the phone lines up for questions.

But first, I'd like to remind you that today's call may contain forward-looking statements related to such matters as our well drilling and infrastructure development initiatives, total and daily sales volumes, reserves, financing plans, operating cash flow, capital budget, growth rate and other finance and operational matters.

Finally, it should be noted that a variety 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 the Company's Form 10- K for year ending December 31, 2008, under Risk Factors, as updated by any subsequent Form 10-Qs which are on file at the Securities and Exchange Commission and also available on our website.

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

Phil?

Thanks, Pat, and good morning, everyone.

As you read in the press release this morning, EQT announced 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 -- and 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 led to lower realized gas prices and significantly reduced EQT production revenues, and also lower NGL prices suppressed revenues in EQT Midstream processing business.

As we show on 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 the $7.60 per Mcf price we saw last year.

Just to remind you, for segment reporting purposes, that 5.25 for Mcf of revenue realized by EQT Corporation is allocated as $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.

I'll go into a little more detail on all of that as I briefly discuss results 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 of that in a few minutes.

So we continued to realize the benefits of all the work we did in 2008 in 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 well head 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, too, of about $0.09 per Mcf on average in the quarter, versus $0.31 per Mcf 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.

One other item that I should also point out is that we did realize $1.71 per Mcf benefit in the current quarter as a result of our hedge position.

Total operating expenses at EQT Production were higher than second quarter 2008; however, on an unit base, 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 were 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 results.

Exploration expense year to date is $7.7 million, and we protect that we 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 selling the selling of 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 1.5 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 get into operation until the third quarter of 2008.

The average liquid price was $0.63 per gallon in the second quarter of '09, or less than half of the $1.57 average liquid price that we saw in 2008, and impact on 2009's second quarter net operating revenues was negative $7 million.

However, the higher process volumes more than offset that NGL price decline, as you saw in the release this morning.

And finally, storage marking and other net operating revenues were 68% higher, mainly from revenues 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 the 2008 infrastructure investments, as we prepared to continue to move 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 compressor fleet accounted for most of the rest.

Moving on very briefly to distribution, operating income at division 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 LDC's Pennsylvania base rate case.

Lower bad debt expense mainly associated with an increase in customer participation in 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 years 8 1/8% senior notes, which significantly improved our liquidity outlook.

As you will see in the Form 10-Q that we 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 borrowing outstanding at 6/30/2009.

Based on commodity prices that have trended lower, we are now estimating our 2009 operating cash flow to be about 550 to $600 million, inclusive of the $99 million tax refund which we did receive in April.

So adjusting for the 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'll turn the call over to Murry.

Thanks, Phil.

Welcome, everybody.

To just reiterate the message that Phil gave, it was a very strong operational quarter, and the headline statistic on operations was the production sales volume growth of 22%.

Just want to remind shareholders that this growth that we are seeing at EQT at this point is in time is driven entirely by our Huron Berea play -- horizontal drilling in those plays, of course.

It's all organic growth; and at this moment in time, anyhow, there's 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 results to date do not include a material contribution from the Marcellus.

As Phil said, we believe this is the highest period on 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 times, 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, to 98 to 100 Bcfe, or about a 16 to 19% increase expected for 2009 versus 2008.

On drilling for the first six months, we spud 167 wells in the quarter, 91 horizontal in the quarter.

Year to date, total gross spud wells of 304.

Total horizontal wells 148 so far.

Turning first to the Huron Berea play, in that play so far, for both zones, we've 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 Berea play, with more than two zones available for us to drill per drill site on average.

We've so far reported 6 trillion cubic feet of 3-P reserves; that is, at the end of the year 2008 we reported that, with an estimated 13 Tcf of resource potential in that Huron Berea play.

As we continue up the learning curve, applying the technologies 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 well apples to apples comparison on a well costs about 1.0 million, and the savings are basically attributed half to learning curve and the other half to reduced steel and reduced completion costs.

On the stack and frac, these are the stacked multi-lateral wells where we're now fracturing them.

We have drilled 19 multi-laterals so far.

Nine are fracked and online, so nine of those multi-laterals are fracked and online.

Seven -- an additional three are fracked but not online, and seven are just multi-laterals that we took as natural completions.

We plan to drill 15 to 20 of those fracked multi-laterals in 2009.

The advantage of the stack and frac, as we have mentioned before, is to increase the productivity and maximize the volume per well pads to reduce the Midstream infrastructure cost, particularly in the Southern Appalachian.

30 day IPs for the multi-lateral wells are approximately 750 million a day.

We're thinking that we can get the cost of these multi-laterals down to about 1.2 million for the -- which is a significant reduction from what I think I previously talked about.

And although it's early on EUR, we are definitely thinking that we will have drilling costs -- drilling F&D costs -- below a dollar.

And I said that last time.

I think the only nuance this time is we're feeling even more confident about that today than we were last quarter.

On the Marcellus, just to update you, we have 400,000 acres in the play.

To date, we've spud 21 horizontal Marcellus wells.

We have a bunch of verticals, as I mentioned last quarter; but we're 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 our having reliable cost data, and I'll get to that in just a moment.

12 wells have at least an initial test rate, but only 8 of our 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 costs, we've seen a pretty dramatic improvement in well costs 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've ever seen in my career -- it doesn't mean it hasn't happened to other people in other places -- but at least we've seemed 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; and of course, there were some that were higher than that, some that were lower.

And on the last call, based on our knowledge at the time, we reported that we could lower the-- our vision was that we could lower our completed Marcellus well costs to 3.5 to $4 million.

We've already exceeded that goal.

Our most recent four wells have averaged completed costs 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 drops -- the drop in the costs have been several factors.

Not all of these are equal; but drilling days are down by half -- that's helped.

Water handling driven by mostly on site recycling has been a significant contributor.

Completion costs, excluding issues related to water, have been a pretty significant cost; and location costs, building locations, and we've seen a little bit of benefit of pad drilling so far has also had a fairly significant impact, and that really explains the variance from 5.5 to 3.3 that I just mentioned.

I mean, the drilling days, there's about a quarter of it; the water is about 30% completion, 30%; and the location cost about 14% of that variance.

EURs for Marcellus we are expecting to be in the 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 hot spots 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 hot spots, and those will tend to drive our overall EURs up, maybe even beyond the 3.5 that I just mentioned.

In any event, the Marcellus is turning to be a nice add-on to our Huron play.

Both drills are heading in a direction where drilling F&D costs will be below $1 per Mcfe of reserves.

So the drilling F&D below $1 for both Marcellus and for the Huron Berea play, we are at this point quite confident of that.

Turning to the Midstream, and particularly at Equitrans, we have 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 you know, the Equitrans pipeline system runs through much of our West Virginia and Pennsylvania acreage, and really runs through the heart of the southwestern portion of the Marcellus play.

It currently has an annual throughput of about 600,000 dekatherms a day.

Our vision, based on industry interest that we've seen to date -- we have 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 Equitrans assets to add incremental capacity of approximately 1.2 million dekatherms 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, maybe more.

But that is sort of the current first-pass estimate of what we think we can do there.

Now, why EQT and why Equitrans, and why is there so much interest in this particular asset?

Well, there are a number of factors that are important.

First of all, speed -- the pipeline is there; and as we turn this thing around from being basically a pipeline that delivered gas to the industrial market in Pittsburgh, and turn it around to be a high pressure gathering system for the Marcellus, highly needed a 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 producers is very important, and I think that's why they are starting to favor us.

We have existing right of ways -- very important.

And not only existing right of ways, but existing right of ways that already have high pressure pipelines on them, so they have the legacy of carrying that high pressure pipe.

And of course, with [Nimby] issues, et cetera, et cetera, this is a very, very important issue.

Another key factor for the Equitrans system is that it currently connects with five interstate pipelines -- Texas Eastern,Tennessee, Dominion, Columbia and National Fuel Gas -- and as I will mention again later, the -- and really, to emphasize a bit what Phil talked about on basis 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 of pipeline's already there, and -- we believe at the end of the day that our customers on this pipeline will find it to be a cost-effective solution.

Just to put some scope on it, this particular project -- the Equitrans project -- we think has the potential to double or more the total EQT Midstream EBITDA over the next five years, just from the expansion related to the Marcellus alone.

And I know the Midstream has a number of other projects online 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 five years, and hopefully do better than that.

Drilling down just a little bit more, there are more than ten non-jurisdictional and FERC related projects that we're currently working on in association with Equitrans.

On the non-jurisdictional side, which will go a little bit quicker, the first project we expect to be completed by early fourth quarter 2010.

This is a rather small project, it's only 105,000 dekatherms a day.

I mean, not too small -- but it's not a huge project.

It's less than $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 FERC 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 dekatherms a day of interest from producers.

Since that time, there's 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 time frame.

And again, it will be a -- it's based on the fact that we -- the newest open season is based on the fact -- the conducting of the new open season is based on the fact that we have seen considerably more interest.

If the thing gets to the level that we're talking about -- if the interest that we've seen so far is confirmed -- then over the next few years, we've got the potential to spend --obviously supported by contracts with producers -- 650 to $750 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 specifics and details on this very 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 a number of reasons.

I think, again, this adds emphasis to the importance of the Equitrans redevelopment story, particularly interconnects, and to the approach that EQT has taken with projects such as the El Paso 300 line expansion; and it's going to be critical to have these outlets to sell our gas, A., every day, and to sell the gas at the highest possible price.

Our 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 on efficiencies, effectiveness and their overall operational excellence efforts.

One thing I would point you to is -- a remarkable statistic 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 the distribution folks have done a fantastic job, not only collecting money from those that can pay, but also making sure that those that can 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 a lot of things that EQT is concerned about, but among the things that we are not concerned about are not issues for us, and I think should be important to emphasize with you all is that we are not concerned about (inaudible) determination; we're not concerned for any near-term financing equity or debt; we're not concerned about holding our acreage through drilling obligations.

So there are a number of things that we're not concerned about -- liquidity, as Phil mentioned earlier.

What we are concerned around here about, though, is pacing, and how fast this asset -- this considerable asset -- should be developed.

As I have mentioned in the past perhaps a little bit -- and I don't have a 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 7, 8% for quite a number of years -- certainly well more than a decade.

That has implications, obviously, to the PV value of the Company.

Another option as an end member is develop as fast as we can, where given our current technology, given the asset that we have and given the progress that we've made, and proving to ourselves how fast we can go, we could certainly have production growth rates exceeding 30% for multiple years anyhow.

But the attendant consequence of a strategy like that is 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 ones that we're discussing.

We've had some discussion with our Board about those end points and a number of other cases in between.

As we develop our 2010 capital plan, we intend to put that plan in the context of a 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 we'll have more to say about it 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.

(Operator Instructions).

Our first question comes from Scott Hanold from RBC Capital Markets.

Hey, Scott.

Just for everybody's information, Dave is a little under the weather today, so we'll try to not stress him out too much.

He's -- small children, and they're -- little germ machines are bringing bad stuff home to him, so we'll try not to stress him.

Anyway, Scott, go ahead.

All right, I'll try to be easy on David and focus on you, Murry.

Okay.

When you look at your Marcellus activity, obviously those costs coming down were just tremendous accomplishments 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, I think a lot of your drilling has been focused on sort of the Northern West Virginia side of things.

Is there any desire to move to Southwest Pierre's?

Is there something different you're seeing between sort of those areas that might contribute to sort of the IP rate that may not be quote/unquote, headline IP rates to date?

Well, yes.

Scott, there is considerable variability.

I mean, I have 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 there's 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 varied quite substantially from place to place.

We just don't know how important they are.

I mean, we've had the 2s for the 24 hour test, and we've had the nearly 10s for the 24 hour tests; and that, I think, emphasizes the point that there's going to be some variability.

Now we don't know whether -- for all of these wells, because they haven't been on production long enough -- how significant they're going to be in terms of EURs.

I mean, that's really why I've been kind of hesitant in not giving these initial flair 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, David.

I don't know if there's any -- do we know enough to have a significant preference at this point?

My feeling about the whole thing is there are just too few data points to make.

You don't want to extrapolate too much from too few data points.

We do know that we very much like this play.

But beyond that, getting into the specifics, I'd say we're in the -- still a little bit in the experimentation phase, other than to say we -- again, we've seen enough to know we really like the play.

Yes.

I don't know if that's helpful to you.

In addition, I mean, completion is -- there's no question that completion has a certain amount of importance.

How important completion techniques in and of themselves will be versus natural variability of the rock is, I think -- and I think this is the point Dave's making -- is an ongoing question for us.

My personal view -- if you want to take it for what it's worth -- is that I'm 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'll need the hot spots 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 hot spot is what I'm hopeful of, and that's my current (inaudible).

I could be -- and 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, is that the average well will be okay.

It will be a distribution, and occassionally you'll run into something that's pretty darn interesting.

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.

Has anything changed in the completion technique?

What exactly -- can you talk about lateral length and number of fracs --

Not really much there.

I think the thing that's -- and 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 clusters in these fracs, I think, is catching on as a major important element; and I think more than I though earlier, hitting yourselves -- getting the well planted in the Marcellus, in the most highly fractured zone, is going to be important.

And the very interesting thing 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 now is organic silica -- silica that was deposited along with those rocks.

The importance of that is that it provides -- it's brittle.

So the most organic part is also the most brittle part.

That is not normally the case in organic-rich shales.

The advantage of that is that if you do a lot of frac clusters you can be pretty effective in (inaudible), if you will, or creating a big zone of permeability around the bore hole.

And that's something that I think we've learned over time in the Marcellus.

And maybe others have learned it, too, but those -- that is unique as far as I can tell among the shales.

Okay.

And just specifically on the completion on those last four wells, you've said that that came in at around 3.2 million -- what was the lateral length in frac stages?

3,500 feet, plus or minus.

Yes, 3,500.

So like 8 to 10 stage fracs --

Yes, yes, yes.

And the frac clusters, I think, are 5 or 6 frac clusters per stage, or something like that.

Okay.

How many did you run on those?

Six stages, I think.

Okay.

I can get that for you offline.

Okay.

Yes, I mean, there's 6 to 8 -- they're experimenting, Scott.

That's what I'm getting at.

6 to 9, and 5,6 frac clusters per stage, that sort of thing.

And then they're experimenting with sand a little bit, too.

But again, I wouldn't focus to 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's just -- there is going to be variability from place to place.

And remind me, how many rigs are going to be running in the Marcellus for the rest of the year?

Is it three to four?

The -- well, we're going to do 41 wells in total.

We're going to spud 41 wells in total.

I think we're going to have three rigs running.

Okay, three rigs.

And so when you look at where those rigs are going to be, are they going to be in West Virginia, or --

Both Southwestern Pennsylvania and West Virginia.

Okay, okay, so a mixture.

All right --

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

Okay.

We're still trying -- with these 41 wells, by the way, we are still trying to scope out the limits of the play, the variability of the play -- so we want to really spread these wells out as much as we can.

On the other hand, we're on the fine line -- we're sort of on a fairly fine line that we want to be able to have these wells close enough to infrastructure so 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 of dancing around both trying to get close to infrastructure that we have --

Or that we will have --

Or that we will have in the near term around the Equitrans system, and also being able to scope the play a little bit more around the 400,000 acres that we have.

So we're kind of trying to deal with two goals at the same time.

Okay, all right.

Appreciate that.

Okay, I mean, that's a lot of good color.

I appreciate that all.

And one quick question on Equitrans.

When you look at that time line you put out there of say 2011 to 2013, is there any reason you couldn't accelerate that, given the level of activity and interest in the Marcellus, better operators?

And secondarily, when you look at that line, is that something that would only service Southwest PA, West Virginia, or is that something that could serve into the greater Marcellus play, including the Northeast part of the play?

To the first question, I'd say the timing on how fast we go is going to be highly dependant on what happens in this next round of open season.

And then importantly, what kind of specific precedent agreements we get signed with producers.

I mean, if they are hot to trot to go quickly, we can accelerate; but we'll have to see, so I think that's an unknown at this point.

To your second question, yes, I think we can expand up to the north; and the reason I say that is because we're more inclined to take on Greenfield extensions to the Equitrans system -- and others may wish us to do that because of these interconnects that we have.

And so it's -- the Equitrans is going to be an easier thing to connect into to provide maximum flexibility for producers to deliver their gas to the 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 play.

Dave, did you have anything to add on that?

Yes, it's just that on that jurisdictional piece of Equitrans, even though we can -- we'll certainly try to get it in a lot quicker than that 2011 to 2013.

The jurisdictional piece, which was all that we were referring to for that timeframe, that is subject to the normal FERC time lines, and that does mean that it's harder to get it done quickly.

As we mentioned, we've got more than ten individual projects that we're talking about, and the ones that are non-jurisdictional we certainly see us being able to get in much sooner than that.

Okay, appreciate it.

Thanks for your time.

Okay, thanks, Scott.

Your next question comes from Xin Lu from JPMorgan.

Good morning, guys.

Hello.

For the Huron play, what's the update on your recent wells that's multi-lateral and non-fractured?

IP rates, cost and EUR?

As I mentioned in the call, the 30 [DIP] for the fracked multi-laterals are about 750 a day, and we're not quite here on costs yet, but the -- we think we can get those fracked multi-laterals to $1.2 million.

There's a little bit of color to that, and the reason it's coming down so much is -- or at least we think it's going to come down -- is because originally, we drilled these multi-laterals with the theory that drilling a lot of lateral bore holes in the Huron zones was a substitute for fracking a single-leg lateral.

And so the theory was drill more feet of horizontal well as a substitute for fracturing, and our initial --- but our initial frack multi-laterals were drilled with kind of the same geometry that we'd started with, so very long laterals off the main bore hole.

And I think our team is feeling that we may not be getting the most effective fracks all the way down those main laterals, so we're going to tighten those laterals up a little bit more.

And so that's kind of why those costs are going to start coming down.

But about 750 and 1.2 million, and hopefully there's some upside on both cost and volumes.

And for the non-fractured wells?

The naturals?

I didn't give a number for those.

It's a little bit -- it's less.

It's in the 400, 500 range, so it's a pretty -- it's about a doubling for these fractured multi-laterals.

Okay.

And you were saying you expect the F&D to be under a dollar, so your estimate is on the high end of your estimate on the single lateral?

Yes, ma'am.

Okay.

Are you drilling multi-well pads (inaudible)?

Yes, yes.

One well that we're doing now, which I guess we called it a spaceship well or something, has -- I'm not sure we're going to do all ten, but has ten wells.

Notionally five at -- five wells -- five multi-laterals at a couple of levels.

We may not do all ten.

It may not be efficient to do all ten, but that's the kind of thing we're hoping to -- well, 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 -- ten plus or minus wells.

Okay.

Thank you, that's very helpful.

Okay, thank you.

Our next question comes from Michael Hall from Stifel Nicolaus.

Thanks, good afternoon.

Hi, Michael.

Hi.

Let's see, kind of sticking back on the Marcellus and on the theme of variability, have you seen any additional variability in liquid contents or BTU contents?

Dave, you might want to answer that.

Actually, it's been pretty dry mostly.

Yes, that's very --

Go ahead.

It has been dry.

At this point, it doesn't even seem like -- the stuff we're finding doesn't even require processing at this point.

Okay.

It's extremely -- the BTU content on some of this stuff is about 1030, which is almost spot-on pure methane, and there are small amounts of heavier stuff, and various -- also then on the other side, very small amounts of inerts.

So again, one thing we wish to caution on, we still don't have enough data points to make broad conclusions.

Sure.

There's other folks in the play who have more data points than us, and we'd suggest that from your perspective, you just view the data points we have as part of the overall portfolio of data.

Yes, I think there's some emerging thought, though, that there's not just going to be a line on a map.

I think it's going to be more variable than that.

And there are a lot of reasons for that.

There's some geological reasons that are starting to emerge.

I'm sure some others have talked about -- we're starting to consider internally here about the early depositional history of the Marcellus, and whether that has some implication for the kind of carriage that is deposited there, and those carriages then being more prone for liquids versus gaseous hydrocarbon and stuff like that.

So there's some hypotheses that are emerging; but as Dave said, we don't have enough data points yet to confirm a theory.

We are just developing some theories, but we don't know if we have enough data to confirm the theories yet.

But I wouldn't be surprised if it turns out to be a bit more variable than I think all of us originally thought.

Okay, fair enough.

And in terms of the data points you do have at this point, what's the kind of -- can you help me think about what the maybe north, south, east, west, aerial extent of what you're looking at at this point is?

In terms of the --

The horizontal Marcellus results in terms of the 20 -- what's it -- 21 drilled to date, how many -- what the north, south, east was?

Maybe if you take Upshur County, maybe, then the southern edge -- I guess, Dave, maybe, perhaps on West Virginia?

Upshur's pretty far south.

Okay.

There may be another well further south than that.

Okay.

And then in north, certainly Green and Washington County, for sure up to the north.

So that gives you kind of a spread.

And then east to west, I mean, right in the fairway with everybody else.

Okay, okay.

And we're right in the fairway.

So you've been pretty widespread then?

You haven't really clustered it up?

Yes, yes.

And then in thinking about the -- I mean, you're talking comfortable with the 3.5 B's per well.

At any point do you think you'll

be willing to disclose that type curve?

Or is it really just a type curve based -- No, no, absolutely.

I think when we get to the point where we have -- I think this is helpful for investors -- when we get to the point where we have a type curve we like --

Yes.

-- and that we think is starting to get representative, I'd -- we will definitely put it out.

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

I think we've got a well for maybe 5 months -- 5, 6 months.

I mean, we don't have enough really to make a type curve even on that yet.

But we're -- again, we want to make sure we have got enough data points with enough confirmation of the decline to put something out that seems like it's reasonable.

And it's possible there that could be more than one, given the vast aerial extent of this play.

You bet.

So we're going to try to be careful not to overgeneralize; but on the other hand, we will get -- and our history has been to give out curves when we think we're comfortable.

The reason we gave out -- we gave Huron curves out very quickly, and the reason we did that is because we had 13,000 wells -- well, no, we had 13,000 wells in the play -- in the basin -- but we also had almost 5,000 Huron vertical wells, and when horizontal results started to match the overall decline of the verticals, we felt pretty darn confident that we had a substantial data set on which to put out some generalized curves.

You know, Marcellus, as Dave mentioned, we are all a few hundred wells into this play basically as an industry.

And so we -- we're cautiously forecasting EURs, but you shouldn't be surprised that they can -- they are going to wile up and down a little bit as data starts to come in.

and down at data starts to come in.

Fair enough.

And in thinking about costs, obviously substantial cost improvements.

Do you guys think about locking in multi-year contracts on completion and things along those lines in the next couple of quarters?

I don't --

Is it too early to talk about that, or --

I don't think my drilling vice president would let me -- would want me to announce that on the phone call right now.

Suffice to say that I think I'm going to use his judgment on when he should lock in both drilling costs and completion costs.

Okay.

But clearly, I think it would be fair to say that there's 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'll 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 team thinks it's the right time to do it.

Okay, that's helpful.

Appreciate that.

And then on Equitrans, 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?

Is it ability to ramp up -- does it have to be a step change in two years, or can it be --

No.

Maybe Dave might want to make a point on it, but I think what we tried to do by emphasizing the fact there were ten projects there, is to emphasize that, A, there's a lot of flexibility on Equitrans to expand it in a bunch of different directions; and B, because there are multiple projects, we're anticipating clearly a phased-in volume growth for that.

Okay.

Now, there may be some large ones that will be little step changes; but I mean, overall, we're expecting it to ramp up over time -- unless there's any particular one --

And the first one is 100.

Yes.

That's a pretty big one.

And that's by -- we expect that 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 in particular on that one.

Okay.

All right, thanks.

I think that pretty well does it.

Just on a housekeeping, the unallocated expense came in a little higher than I had been thinking.

I mean, is there any way to break down what's involved and what's incorporated in that?

(Inaudible), mainly the incentive compensation plans that are mark-to-market with the EQT stock price.

Okay.

So --

All right.

It's a -- there's a lot of details in the K, but if you want to give me a call I can walk you through that pretty quickly.

Probably better.

All right, thank you very much.

All right, thanks.

Our next question comes from Faisel Khan from Citigroup.

Hi, Faisel.

Hey, how are you doing?

Doing well, thank you.

Okay.

Just focusing back on pace, in the near-term, given the production ramp you guys have had, if you continue on this sort of ramp, when would we see a need for a new infrastructure.

What's the -- how much time have you bought with your current infrastructure you have in place?

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 as little infrastructure as possible, and so we're -- as we're developing these pacing plans, certain of our options, particularly where we aren't anticipating going full out 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 down south 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 on how the well results go, the Equitrans option for transporting that gas and accelerating projects if we can and building little projects, might be a very attractive accelerant, so -- and a cost effective accelerant to that growth.

So I'm really -- Dave and I and Phil are still working hard on -- and the team -- are working hard on pacing.

As a matter of fact, as soon as we get off this call, we're talking about pacing again today.

So -- but I'm sorry, I can only give you color, I can't give you specifics yet on this.

Okay.

Got you.

And then in your high-end case update of 30%, would that -- is that all -- would that all be sourced from your Huron play, or is that considering Marcellus?

No, that would consider both.

Okay, got you.

And then just on the books and cost structure for a little bit, the sequential uptick in LOE in the second quarter versus the first quarter, what caused that number to go up a little bit?

I think someone even asked that question on the first quarter call.

We thought the first quarter was a little bit seasonal and that it would trend more to what it looked like for last year, which was closer to the $0.28 that you're looking at.

So I think first quarter was just a little low, and we did say that on the first quarter.

Okay, got you.

And exploration expense was just a little bit higher --

Well, we're doing some seismic -- yes, I mean, we are shooting a 3D seismic program, and so we're just seeing the expenses come in for that.

I mean, we're -- and 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 of the deep, but also because of what we might learn on the Marcellus and other -- the more shallow zones.

So we decided, Dave and I, to continue with that project rather than delay it.

Okay, got you.

Thanks for the time, guys.

Okay.

Our next question comes from Ray Deacon from Pritchard Capital.

Yes, hey, good morning.

Hey, Ray.

Hey, I was just wondering, Murry, what is governing the location of the Marcellus wells that you're drilling?

Is it partly infrastructure, or partly a desire to kind of test out what you see as the fairway, or --

Both.

It's really both.

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 existing infrastructure -- at least our 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 and find out a lot more about our acreage more broadly rather than concentrate in particular spots.

So really, the answer to your question is we're doing both of those things.

Okay, got it.

Well, I have observed that the production people seem to think that it's quite strongly influenced by infrastructure, and the infrastructure people think that it's not really that strongly influenced by infrastructure so --

Got it.

So you might, as part of the 41 horizontals, test that sort of north eastern part of your acreage position then?

I do not know if we have a permitted well up there, to be honest with you.

At some point we will.

We will, yes, but I just don't know if it's this year.

Okay, got it.

I just don't know.

I'm sorry.

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

No, that's fine.

I guess just a bigger picture question.

You've shown sort of historical F&D costs in your presentations, and it sounds as though you feel very comfortable it could be marching down towards a dollar in Mcf this year of F&D costs.

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 you're returns this year?

I mean, it seems to me you're going to be able to grow production at sort of a much lower cost than in the past -- you're sort of adding reserves that have a much shorter reserve life, and your returns ought to be going up, I guess.

So I was wondering if there was any way you could kind of put that in context.

Yes, well as long as the gas prices -- yes.

The return question is going to be somewhat dependent on gas prices.

Right.

But as far as what we can do, this certainly -- we're having some benefits from lower steel costs, lower service costs and better contractings, 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 a dollar F&D is something that we just don't ever wants to exceed.

Now, having said that, if something occurs that will allows us to spend a bit more money and accelerate production, we're 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 make the most money.

But as a general principal, we've tried to do that.

And the Marcellus in particular, I mean, most of the things I mentioned to you that explain the variance between our average well costs of a couple quarters ago and now relate to operational issues, getting the days drilling down, and that's just getting the right mud properties, getting the right bits, operating at efficiency -- that's a very big thing, and that's EQT-driven.

Water handling, clearly EQT driven.

And on that we have metrics.

I mean, the water handling, it's how much of it gets recycled, how far does the water have to be moved, et cetera?

Right.

Exactly.

And you know, obviously the location -- completion costs, some of it is just tuning our completions to exactly what we need.

I don't think we're there yet.

I think we are experimenting there.

But we've also had the wind at our backs with respect to the overall market for completion services.

So I think, when I look at the overall reductions -- and by the way, that's on Marcellus.

On the Huron stack and frack, that's clearly all well -- mostly well geometry and stuff that EQT is doing to try to improve productivity based on just new techniques and more innovative ways to drill the wells.

So if I had to put a number out there, I'd say at least 2/3rds of what we're seeing is EQT innovation, and the rest of it probably comes from market cost reduction.

Steel costs -- tubulars -- are really not that low, if you look back any more than six months or so, or eight months.

I mean, if you look back -- I don't even think with steel costs we're back to where we were at the beginning of '08.

So --

Got you, great.

So if you look at it from that perspective, it kind of took a blip off, and maybe it's just come back to a little bit more where it was.

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.

It's not going to show up as F&D, because for most of the wells that we're drilling 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 are look at drilling F&D, we kind of target a buck, you know?

We don't want it to be much more than that.

Got you, got you.

Thanks.

And I guess, has -- the cost reductions 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?

Or --

I think it could be incremental.

I mean, I think the rigs that -- one of the things that the new rigs are able to do is skid 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 them out and having them either built or retrofit for us, there are little tweaks that are really improving the process.

So yes --

Got it.

Okay.

Right.

Got it.

Just one last quick one.

Is -- would you attribute the increase in the guidance from 15% to 16 to 19 to one play or one area?

Huron.

Absolutely Huron.

Okay.

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

Okay, great.

Thanks very much.

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

Good morning.

Following up on what you said, Murry, on pacing -- I guess it's not even a question of pacing, it's also a question of allocation of capital, especially in light of this larger Equitrans project.

So when do we get a feel - and realizing that you are 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?

Yes, it's a good question.

I think the -- I don't think we're 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 raise is a good question.

Maybe just to give a little nuance 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, Berea and Marcellus at this moment in time in terms of allocating capital.

And 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 Equitrans reinvention is that a lot of that is paid for by third parties.

It's certainly our capital up front, but it's financeable, if you will, from commitments that are made by producers; and both Dave and I are still -- 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 maybe it's just a temporal 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, we'll fill it, and then hopefully people may wish to be partners with us at that point in time.

In other words, there 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 it 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 it is not too onerous for us.

But I realize that's a long-winded question, I just I wanted to give you a little bit -- a long-winded answer -- I just wanted to give you a little bit of color about how we're thinking about it.

But in direct answer to your question, not until late this year.

And that jurisdictional portion of Equitrans piece for the Marcellus does not require a financial commitment from us this year, and it will not require a financial commitment from us next year.

So from our perspective, that's far enough off that we really don't have to worry about how we will finance it.

First of all, we have to make sure that there's enough interest and we'll go from there.

All right.

Thank you guys, and thanks for the well data.

Okay.

Our next question comes from Robert [Mullan] from [Ducane].

Actually --

Hey, Rob.

Hey, how are you guys doing?

My questions were asked and answered.

Thank you very much.

Okay.

Okay.

Our next question comes from Jim Harmon from Barclays Capital.

Hey, it's Rick and Jim.

How are you guys doing?

Hey, Rick and Jim.

Thanks for changing the conference call operator so we could ask our question this quarter.

I'm sorry if you couldn't.

No, no, but that was just a specific Barclays exclusion on all of those (Laughter).

Okay.

You must have slipped through.

Check that out.

He's sending an email now out to make sure you guys don't get through next time --

How did you get the number?

All right, all right, all right.

What's your question, James, Rick?

Question was, and you answered it I think in general, I was going to ask on the 400,000 acres of Marcellus --

Yes.

As far as between your drilling this year and others drilling around kind of the spatial sampling, how much of it do you think in quote, I guess, will be tested, that you'll have a pretty good idea of what percentage might be good?

Boy, that's a tough one, because I think the thing that caught -- I don't want to avoid the question, but I'm just wanting 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's well to well variability because of changes in geology from place to place.

And I don't think we have enough information to determine whether it's one or the other.

So 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 I -- what we would prefer to do, though, is find the hot spots first.

Right.

And I'm 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 the challenge for the geological team -- and by the way, for others' geological teams as well.

There doesn't seem to be yet a silver bullet, either on seismic or other things that we think is economically useful at this moment in time.

There are theories -- there are things that people are thinking about; but I know Steve [Slaughterbeck] in particular is wondering whether -- it just ends up adding costs, and we'd end up drilling the wells anyhow, and we wouldn't really get a lot of incremental benefit from doing that.

But again, we are staying open-minded.

There's certainly other opinions in the Company about the value of 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 have acreage on is productive, and then I think we'll work -- we'll start drilling away from wells that we think are the better ones, I think, is how we will currently evaluate.

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

Yes.

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 well and from the nearest infrastructure, it gets -- it better be great beyond what anyone is reporting to justify building an 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 is going to be a bit more hunt and pack, and there will be commitments made by producers based on what they have seen -- two types; and Dave said, once those pipes are in, they will be drilling right along those pipes --

Okay.

-- to try to full them up.

Then this is a variation on that, but you indicated that you are still trying to sort out type curves, that the IP rates have been variable, and that this obviously isn't homogenous; and yet you also are trying to reconcile that with -- most type curves I see and most analysis is done by slapping an IP rate that is going to give you the typer curve and the EUR, and that the EURs are highly correlated in a lot of this kind of analysis with the IP rates.

Well -- If they're all over the map, how do we come up with --

He's got to be talking about 30 day IP --

Yes, you're talking about 30 day IPs, right, Rick?

Yes.

Yes, 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 that is going to be the case.

It seems like that is the case in the other shale plays; it certainly is the case in the Huron play.

And as you know, with all these shales -- because they're non-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 be will and the production rates are going to be like we did in the Gulf of Mexico and all these other places that were developed over the years.

We end up having to to bet that there is a distribution curve -- that there's a histogram.

Yes, okay.

And that we're going to drill into that histogram; and on average, we're going to win in total for the play, even though individual wells may not be profitable.

I think that's just the nature of this beast.

Right.

And what we can't -- for instance, when you get the large -- the high IPs, are they just anomalies, and you get a lot of gas out early, and once you have a thousand wells drilled, they just don't matter?

Because frankly, in the Huron, when we were drilling vertical, that's what happened.

We'd run into natural fractures, you get a lot of volume early, and -- but in the overall scheme of things, you figured out it didn't really affect the curve.

Okay.

Or is it more meaningful?

I don't think we feel that we have enough information to know.

Okay, then last question on the pipe, on the Equitrans expansion.

Yes.

Get to the large expansion -- I guess I'm curious, that's an awful lot of gas.

Yes.

And the producers that would sign up for Equitrans, my suspicion is, is that aside from the fact that the interconnectors to these five pipes aren't -- it would have to be expanded materially -- is that is that downstream of those interconnects, they aren't going to have capacity on the other pipes.

It's --

How much of this depends on kind of a coordinated effort to literally expand everything?

Well --

Do this at vacuum?

That's a good question.

I don't know how that is going to -- I don't think that is 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 -- you would like to think you could have the grand plan; but I think the grand plan, given what David has been talking about, and I've been talking about on the variability of 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 to be contracting for downstream capacity, they are going to be backing up getting Equitrans, drilling into the -- what they have; and then with time, the solution will emerge.

I mean, when it's all drilled out, we'll know what we should have done at the beginning.

You do need a series of, let's call them smaller projects, going into the markets.

I mean, we are at this point quite confident that that pipeline that we've -- that we're contracted for that El Paso that is building -- that so called 300 line --

Right.

-- that that is going to happen.

Yes.

Oh, yes.

But that's one piece.

We know other people are working on other things as well, so we don't have the grand solution that had been talked about at one point for a huge additional line to go to New York and Boston.

Maybe that will come back, I don't know.

But there's a variety of folks that we read out there who have smaller projects, and when you add them all up, I think you get to a fair amount of volume.

How many of them will happen and how many of them won't, I don't know; but at this point, our guess is some of them are happening.

Yes, well, I guess -- that does go to my question of, you carry it to somebody else --

Right.

And most of that capacity is booked.

And as you've probably tried to analyze all of this into capacity --

Yes.

We have, and it's very difficult to -- either so many unknowns -- you're trying to solve equation with multiple -- you have got as many unknowns as you have equations, and that's -- so what we're relying on and -- or what Randy is relying on and the team is relying on -- is that when a producers sits down and signs an precedent agreement, that they have worked out whatever those downstream issues are for themselves.

Right?

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

Because, I mean, they are putting up there.

They are paying demand charges, a lot of --

I mean, (inaudible) if they're willing to take gas to a bottleneck.

Yes, I mean, other than the attendant credit risks that are going to come, right?

I mean, those are issues --

I mean, I agree with Murry.

They think through that.

Yes.

Yes, they are thinking through it; and once they sign those precedent agreements and are willing to pay demand charges, I think Randy and team are ready to go -- and Martin Fritz -- are ready to go build the pipe.

We're not detecting that they are just hoping that the markets will develop.

That is not what we're detecting.

Okay.

Thank you.

Okay.

Our next question comes from [Carl Brown] from [Royce].

Hi, guys.

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

EQT is -- yes, right.

And this a very rough number, Carl, but very rough number, and it is in reference only to the 1.2.

I mean, if Steve and the team come up with more Marcellus there might be a bigger share of EQT.

But right now, in the context of a 1.2 million deck kind of a vision for Equitrans, we're thinking it's about 70/30.

But that could change --

Okay, and what about the base 600,000 that exists today?

What happens to that?

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 Equitrans delivers to Pittsburgh, it delivers to several LDCs.

It also has storage attached to it, and so there are LDCs around the East Coast that use Equitrans for filling storage that we have for them, that Dominion has for the, that others have.

So that system is basically utilized.

I mean, there's a little extra capacity in there that can be used, but not a whole heck of a lot.

Okay.

And --

It's spoken for, I guess is the way you would say it.

Yes, yes.

And in terms of your commitment or your ability to commit to capacity on that system, what is the timing for the system when you would have binding agreements signed, because I'm imagining that you have got a certain level of conviction today in terms of the volumes that could come out of Marcellus.

But conviction could be very different six months from now or a year from now.

Yes.

Again, at this moment in time, we have 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 -- or more firm precedent agreements signed with producers.

And at that point, I think we'll be able to be much more clear about this, Carl.

Okay, so firm agreements are more more like a late -- end of the year, early part of next year?

Yes, yes.

Okay.

And final question, just on -- when you talked about the pacing and the two end gains of lower growth rates without needing to access capital markets versus a higher growth rate but needing to access capital markets, are things like partnering and asset sales, would that be in the -- kind of the in between category that you are referring to?

It could be.

Could be, yes.

There are -- there's -- the issue -- and I think it's important that everybody knows that it's going to be 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 when those pipes are built, the corollary commitment to fill it up is already set in motion.

So once we pick a pacing strategy, I mean, there's going to -- the genetics are in place for that kind of growth.

I mean, plus or minus, it doesn't mean there can't be some variance, but we will be setting the pace pretty clearly at that point in time.

So, as I said earlier -- it doesn't mean there can't be some variance around that overall strategy; but we'll be setting the pace pretty clearly at that point in time.

And as I said earlier, we're not going to be in a place at this moment in time where we'll be able to --we'll not be at a place to be able to be more clear about that until the end of the year.

And you referred to --

Partnering could be in there -- other ways to finance it.

Once we decide what the pace is, financing it through partnerships or traditional forms of capital raising are all going to be considered.

Okay, and partnering -- you alluded to that has potential in the midstream business, but also on the E&P side as well?

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 would look at -- but we haven't seen one.

And on 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?

I mean, ultimately --

But that could all change, Carl.

I mean, things can change.

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

Well, we're looking at what's better for PV value, 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 all the ways that -- the factors that we look at around here.

Okay, great, thanks very much.

All right.

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.

Thank you, everyone.

That concludes today's call.

There is a replay of the call that's available around 1:30 today.

The phone number for the replay, 412-317-0088, and there's a confirmation code for the replay, 432367; and that will be available for seven days.

Thanks, and have a good day.

That concludes the EQT corporation second quarter 2009 earnings conference call.

You may now disconnect.