EQT Corp (EQT) 2010 Q2 法說會逐字稿

Good morning and welcome to the EQT Corporation second quarter 2010 earnings conference call.

(Operators Instructions).

After today's presentation there will be an opportunity to ask questions.

Please note this event is being recorded.

I would now like to turn the conference over to Mr.

Pat Kane, Chief Investor Relations Officer.

Sir, the floor is yours.

Thanks, B.J.

Good morning, everyone, and thank you for participating in the EQT Corporation second quarter 2010 earnings conference call.

With me today are Dave Porges, President and Chief Executive Officer, Phil Conti, Senior Vice President and Chief Financial Officer, Randy Crawford, Senior Vice President and President of Midstream Distribution and Commercial, and Steve Schlotterbeck, Senior Vice President and President of Exploration and Production.

In just a moment, Phil will briefly review a few topics related to our financial results for the second quarter 2010 which we released earlier this morning, then Dave will provide an update on our drilling and infrastructure development programs and other operational matters.

Following Dave's remarks, Dave, Phil, Steve, and Randy will all be available to answer your questions.

First, I 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, including Equitrans and the potential natural gas liquids joint venture.

Production sales volumes, rates of return, well and operating costs, operating cash flow, growth rates and other financial and operational matters.

It should be noted that a variety of factors could cause the Company's actual results to differ materially from the anticipated results or other expectations expressed in these forward-looking statements.

These factors are listed in the Company's Form 10-K for the year ended December 31, 2009, under risk factors as updated by any subsequent Form 10-Qs, which are on file with the Securities and Exchange Commission and available on our website.

Finally, this mornings call may contain certain non-GAAP financial measures which are in this mornings press release -- the reconciliations are in this mornings press release, I'm sorry.

And before introducing Phil, I would like to inform you that we posted our Marcellus decline curve to our website this morning.

Now, I will turn the call over to Phil Conti.

Thanks, Pat, and good morning, everyone.

As you read in the press release this morning EQT announced second quarter 2010 earnings of $0.20 per diluted share which was unchanged from the second quarter of 2009.

Operating cash flow, however, increased by 17% over the prior year quarter as a result of another outstanding operational quarter at EQT Production and Midstream.

Sales of produced natural gas at production increased by 31% for the second quarter in a row while gathered volumes at EQT Midstream increased by 20%.

On the downside, realized gas prices were lower than last year primarily as a result of having fewer hedges in place at a lower average hedge price.

As we show in the table in this morning's release the EQT average wellhead sales price which is our realized natural gas price was $5.49 per Mcf in the quarter or only slightly lower than the $5.57 per Mcf we realized last year as some of the negative impact of the hedge position was offset by higher liquids prices.

Just to remind you, for segment reporting purposes that $5.49 of revenue realized by EQT Corp.

is allocated as $3.10 per Mcf to EQT production and $2.39 per Mcf to midstream.

Overall, absolute costs increased as expected to support our outstanding growth rate but on a per Mcfe basis costs related to EQT's produced natural gas and NGLs were down about 8% versus the same quarter last year after adjusting for the water treatment capacity charge mentioned in the release.

I will go into a bit more detail on all of that as I briefly discuss results by business unit starting with EQT production.

And there as has been the case for two years now the big story in the quarter was the growth in sales of produced natural gas.

As I mentioned the growth rate was north of 30% for the second straight quarter.

That growth rate was all organic and was driven by sales from our Marcellus and Huron/Berea horizontal shale wells which together contributed 45% of the volumes in the quarter far exceeding the 28% contribution in the quarter a year ago.

Contribution from the Marcellus shale play alone is growing rapidly and represented over 16% of our volume this quarter and that was up from less than 2% in the second quarter of 2009 and 13% in the first quarter of this year.

A moment on expenses and production, total operating expenses were higher quarter over quarter again consistent with the significant production growth.

SG&A costs were $7 million higher than last year with the biggest cause of the increase being a $4.5 million charge to write off approximately three years of contracted capacity for treatment and disposal of recovered frac water that we no longer need.

We also incurred about $900,000 of LOE expense this quarter from those contract obligations.

While we would obviously rather avoid contracting for unnecessary capacity the good news is that as a result of our progress in recycling the recovered frac water, rather than disposing of all of it, the economics of our Marcellus wells have improved.

The financial benefits of recycling have been incorporated into our improved well economics shown in the table in this morning's release.

Final point on expenses and production, exploration expense was $3.3 million lower quarter over quarter as we did reduce the size of our seismic program compared to last year.

A quick moment on well count reporting.

With the implementation of our extended lateral initiative, the lateral length of our wells are getting longer on average and will vary greatly depending on the geometry of our acreage blocks.

Operationally we increasingly think about feet of pay to measure progress in our drilling program, and to help you better track our progress we will provide average completed lateral lengths in addition to well counts going forward.

So with that thought in mind, year to date we have spud 62 horizontal Marcellus wells with a projected average feet of completed lateral of 3,550 feet, and 143 Huron/Berea wells with a projected average feet of completed lateral of 3,920 feet.

Based on those averages we plan to drill 96 Marcellus wells and 271 horizontal Huron/Berea wells in 2010.

Neither the development pace, nor the capital budget has been materially impacted by the focus on the longer laterals.

However, expected well productivity and returns have improved considerably as demonstrated by the table in the press release.

And then one last point on our Marcellus status.

EQT has spud a total of 115 horizontal wells in the play of which only 34 are currently in line.

So of the 81 wells not yet in line, 27 are either currently drilling or have been top holed.

38 are drilled and awaiting a frac job, and 16 have been fracked and are awaiting pipeline hookups.

The rather large number of wells that are still in progress is driven by the large number of pad wells we have drilled recently.

While pad well drilling is a key to improving our well drilling and midstream costs it does necessarily result in delays in getting wells on-line.

At the current time we are not sufficiently comfortable from a safety perspective with conducting simultaneous operations on the Marcellus pads so basically we cannot hook up the wells until we finish the activity on the pad.

The good news is that we are still exceeding our production targets and have a lot of visibility, vis-a-vis our Marcellus growth forecast.

On to Midstream results.

Operating income there was up 80% consistent with the overall growth of gathered and processed volumes as well as significantly higher liquid frac spreads which were driven by a 70% increase in average NGL prices versus the same quarter last year.

In addition to improved prices, processing volumes were also up by about 12%, mainly as a result of higher production volumes from our white gas Huron/Berea play in Kentucky.

Gathered volumes increased 20% again mainly from gathering EQT's, increasing production and combined with higher rates resulted in 25% increase in gathering net operating revenues.

Storage, marketing, and other net operating revenues were also higher in the quarter, as the relative lack of seasonal volatility and spreads in the forward curve this year resulted in more contract settlements in the second quarter compared to the same quarter the last several years.

The timing of these settlements mask the fact that based on the current forward curve we expect overall net revenues from that activity to be lower in 2010 than last year.

Also, third-party marketing margins continue to be lower than last year as contracts expire in an environment where capacity constraints have eased somewhat in the TCO/Big Sandy corridor, resulting in a smaller premium for marketing services related to our current unused capacity.

So in summary net revenues from storage, marketing and other was up for the quarter due to timing issues but as you saw flat year to date and we expect it to be down for the full year by approximately $10 million.

Net operating expenses at Midstream were $4 million or about 8% higher quarter over quarter.

Higher DD&A expense associated with our increasing midstream infrastructure accounted for about $2.8 million of that $4 million increase.

While increased electricity, materials, and severance taxes accounted for the majority of the remainder.

Moving briefly on to distribution, operating income at distribution was $4.3 million in the quarter or about $5 million lower than the same quarter 2009.

Approximately $2 million of the decrease was due to higher bad debt expense, mainly associated with a decrease in customer participation in state and federal low-income assistance programs.

Lower commodity prices resulted in lower bills and fewer customers qualifying for assistance programs and, therefore, government grants to distribution companies have decreased in 2010.

Weather, which usually does not impact results significantly in the second or the third quarter turned out to be a somewhat significant factor for the quarter in utility at least on percentage basis, lowering revenues by about $1.9 million.

According to NOAA, the second quarter 2010 in our service territory was the second warmest in over 50 years.

Then finally a quick liquidity update.

We did close the second quarter of 2010 with no short-term debt.

That's zero short-term debt, and headed into the second half of 2010 with a net cash balance of about $425 million, and a fully available credit facility.

A quick note on the credit facility.

As of recently the full $1.5 billion that came available to us again when a new bank stepped into Lehman's former position so we do have the full $1.5 million available.

Our 2010 CapEx estimate remains at $1.2 billion excluding acquisitions and we estimate that full year 2010 operating cash flow at the current strip will be approximately $650 million including the $121 million we received from the tax refund earlier in the year.

So we continue to be in a great liquidity position to fund the remainder of the 2010 growth plan.

With that, I will turn the call over to Dave Porges.

Thank you, Phil.

As the results from this quarter again demonstrate, we're delivering on our committment to increase shareholder value by accelerating the monetization of our extensive reserves.

We have recently completed our annual internal strategic review, no real surprises come out of the review but our areas of focus for the next couple of years are, if anything, even clearer.

I'll return to that topic after covering some of the operational highlights for the quarter.

At EQT production we posted our second consecutive quarter of 31% year on year growth in sales of produced natural gas.

This growth was again driven by horizontal drilling in our Marcellus and Huron/Berea plays.

We may have been a bit late to the party in terms of volume growth, but this is now our eighth consecutive quarter of double-digit natural gas sales growth.

These plays have become so extensive that we do not wish to focus too much on single well anecdotes but we do have a couple of Marcellus vignettes.

During the Q1 call, we mentioned a recently completed and fracked well with a 5300 foot lateral, 4800 feet of pay, and 16 frac stages.

It has now been on line for 90 days.

It costs $5.3 million with an EUR of 8.8 Bcf.

Also during that call we mentioned a well with a 9,000 foot lateral and 8,400 feet of pay which was recently TD'd and cased.

A 28-stage frac job is now underway and we will update you on the progress next call.

I'd now like to provide an operational update on our midstream business.

As we announced a few weeks ago we are negotiating with DCP to form a liquids oriented venture that will combine our existing liquids related midstream assets with DCPs industry leading expertise.

We continue to target a third quarter signing for this venture which would reduce our need for internal capital for future liquids projects.

I would also like to provide updates on projects we discussed last quarter.

We are on track for the second phase of the Ingram gathering system.

This will add 40,000 decks per day of capacity in Pennsylvania for EQTs production by year end bringing total capacity to 90,000 decks.

In northern West Virginia we are constructing a [Doddridge] gathering system expansion.

This will deliver EQT's production from north central West Virginia into the western leg of the Equitran system.

This will add 50,000 decks per day of capacity by year end.

Bringing total gathering capacity in WV to about 70,000 decks.

Finally, upgrades to various segments on the existing Equitrans transmission system along with modifications to compression at the Pratt station are proceeding on schedule.

The $15 million initial phase will allow for about 100,000 decks per day of incremental delivery capacity to Equitrans' interconnections with five interstate pipeline facilities.

Construction is expected to be completed by year end.

We continue to work toward completing the rest of that large Equitrans project.

On May 28, 2010, FERC accepted Equitrans' request to initiate the pre filing process for phase 2 of the project.

The provisional in-service date is in 3Q 2012.

As noted previously this project is likely to continue to progress as a series of smaller stages unless we determine that we can identify a third party interested in helping to fund a larger project.

That's probably a reasonable segue into some bigger picture topics related to that annual strategy review.

The biggest of these is that we have updated our assessment of Marcellus well economics in a way that has a significant impact on the overall returns we expect in this play.

These updates and improvements are in both the production and midstream areas.

In production we continue to improve drilling costs and completion effectiveness due in part to use of extended laterals.

In Midstream, design and engineering work lead us to sharply reduce our cost estimates for gathering, processing when needed, and transporting produced gas to market.

We had perhaps conservatively estimated $1.98 per Mcf of midstream costs in support of the Marcellus development.

The new estimate is $1.29.

This reduction is due to fine internal work within our Midstream group and to the evolving nature of Marcellus production.

Specifically, pad drilling combined with increased production per well allows a more compact efficient midstream system.

Also, as Pat mentioned, we have published to our website a Marcellus decline curve based on the midpoint of our EUR range.

This improved curve further aids making midstream investment sufficient.

That is, we can support large higher pressure pipes that move a lot of volume.

So applying the lower cost of development and lower midstream costs, the Marcellus economic return estimates have been revised upward.

We now expect to earn a 63% all-in after-tax return on average, assuming a flat $6 per Mmbtu NYMEX.

This is double our previous projections.

Importantly, at $4 NYMEX, we can earn a 23% after-tax return.

Interpolation will give you a reasonable feel for the economics at prices between those two levels.

Strategically, this is making our current situation even clearer than it was.

We have an immense resource base.

We have demonstrated that we can economically develop this resource base.

However, we do not have nearly enough capital to pursue all of these opportunities, and we have no interest in issuing equity at anything like current prices.

So we focus ever more intently on capital allocation issues.

More specifically, the most economic steps for us involve developing our Marcellus position and also developing our Huron/Berea position in a manner that keeps midstream intensity low.

So what doesn't fit?

Two investment opportunities that we believe have attractive return potential will struggle to make the cut in the near term.

Most obvious are those midstream opportunities whose prime focus is moving third-party volumes.

We are quite open to obtaining other people's money to pursue those attractive opportunities but are not likely to pursue many of them without other people's money.

Also, large midstream buildouts in the Huron/Berea and CBM plays are not likely to get funded in the near term.

In the Huron/Berea this still allows us to grow by focusing on projects with lower midstream intensity but you should not expect to see initiatives that involve large expenditure of EQT capital on midstream projects as a means to achieve that growth.

On a somewhat related topic we wish to tweak our volume growth guidance.

We previously estimated 26% year on year sales growth.

Obviously the first half of 2010 was ahead of that pace and we believe that we will now have sufficient midstream capacity to increase our estimate for sales of produced natural gas in 2010 to between 129 Bcfe and 131 Bcfe.

Though we manage a variety of risks in our business, the primary risk to volumes throughout the remainder of the year continues to be the timing of midstream capacity increases.

So far, we have done a better job managing through operational issues and curtailments this summer than we expected, or at least that I expected, but this will represent an ongoing timing risk given the growth rates we are experiencing.

Finally, I wish to touch on some environmental and regulatory issues with which the industry is dealing.

There has been much discussion recently about the ingredients used in the hydrofracking of shale wells.

EQT is committed to operating safely, protecting our workers, neighbors, and the environment.

EQT is also committed to transparency in our operations.

To that end, we will be disclosing the ingredients of our frac fluids.

As most of you know this information is already available to the relevant regulators.

We have determined that the best way to make the information more broadly available absent an industrywide approach is to disclose those ingredients on our website.

Further, again to the extent appropriate, we intend to post on our website significant communications with legislative or regulatory bodies regarding these issues.

This will be a work in progress but again our intention is transparency.

Incidentally, something else we'll be posting on the same area in the website is our corporate sustainability report and you will be seeing a first draft of that soon.

In summary, EQT is committed to increasing the value of our vast resource by accelerating the monetization of our reserves by various means.

In the second quarter alone we have continued to accelerate the pace of organic development, lowered the expected cost of development, and announced an expected partnership for handling our liquids which will allow us to leverage nontraditional sources of capital.

We look forward to continuing to execute on our commitment to our shareholders and appreciate your continued support.

And with that I will turn the call back over to Pat.

Thank you Dave.

This concludes the comments portion of the call, B.J.

you can now open the call for questions.

Yes, sir.

We will now begin the question-and-answer session.

(Operators Instructions).

Our first question comes from Scott Hanold from RBC.

Please go ahead.

Yes, thanks, good morning, guys.

Hi, Scott.

You talked about the 9,000-foot lateral well, I guess there was 8,400 feet of pay.

Can you give us a sense on what that will would cost?

Yes, Scott this is Steve.

We're estimating that well, when we're finally done with it it, to be between $8 million and 9 million.

And you guys haven't completed that, or are completing that at this time?

We started fracking yesterday, and we have successfully pumped the first two stages, which, frankly, were the biggest concern the first several stages.

So it's proceeding as we speak.

Okay, good.

And sticking with the Marcellus it seems like you guys are ahead of speed -- in terms of first half drilling with 62 wells but plan on doing a total of 96 wells by end of the year.

Does that infer that your rig count is going to drop from where it was on average?

Can you kind of help me square the circle on that one?

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

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

The top hole rigs are easier to bring in and let go.

The bigger Marcellus rigs, we have under longer term contracts.

We have experienced crews.

We like to maintain more stability on the bigger rigs.

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

Okay.

So it's a capital allocation decision.

Exactly.

That makes a lot of sense.

And you do have a pretty good size backlog, so is part of the process running six rigs in some top holes and you're just getting ahead of yourself too fast, or is it infrastructure going to be available to get what you guys want on line here over the next 12 months?

Well the infrastructure, there's going to be a continuing timing issue.

We talk about that internal, plan it internal fair amount, but we think with the schedule that we have for drilling that the delays aren't going to be too great.

Okay.

What about --

We're not slowing down drilling for Midstream.

The pace of drilling is really beg set more by the decision about how much capital we wish to spend.

And when you look at your inventory of Marcellus wells to get on line, how are services in the area?

Is it hard to get frac crews out there?

Do you guys have dedicated frac crews?

What's happening there in terms of giving them and the cost associated with in the.

Scott, we're actually in pretty good shape on frac crews.

We do have dedicated crews sufficient to do all the fracking we need through the remainder of this year.

Part of the issue with the backlog is we're drilling a lot of pad wells.

For instance, the extended lateral well is on a pad with six other wells.

And we have a number of those types of pads that are just finishing up drilling now.

A lot of is it just the timing and the nature of how a lot of wells get fracked in a short amount of time.

Inventory will be run down, but then it will build back up again as we start on more multiwell pads.

So, we should expect growth could be a little bit lumpy where you all of a sudden get six wells tied in and a big production boost in any specific quarter?

Is that kind of how we should think about going forward?

Yes, I think that's going to continue with the Marcellus for as long as we are executing pad drilling the way that we are.

Okay.

And one last question on Marcellus.

Just because I think I may have misunderstood the numbers.

Did you say you drilled 151 Marcellus -- horizontal Marcellus wells and only 34 wells are on line?

115 wells.

81 wells are still in progress.

Got it.

On the regulatory front, what is your thought on the talk of permit moratoriums and severance taxes and other issues outside of just the fracking issue?

What we don't hear that much in PA or West Virginia about permit moratoria in the areas of the state with which we're operating, obviously we wouldn't like that if it happened, but we actually don't hear much about it.

We hear much more about disclosure issues and other forms of regulations, but frankly in the other forms of regulation, our attitude is that from what we can tell we are already operating in a manner that is consistent with the preliminarily proposed regulation.

So in a way it's actually positive for us if the bar gets raised a little bit closer to the level that we're already at, and as far as severance taxes, as a lot of folks in this area know, we're actually proponents of the notion of Pennsylvania instituting a severance tax in the context of broader clarification of rules regarding natural gas development.

Okay.

We're not experts on knowing whether that's likely to happen.

That's Harrisburg issue, and as a lot of you folks may or may not be aware, we're already in the run-up to a gubernatorial election here in Pennsylvania.

From what I see, it looks like there's going to be a bit of give and take.

What kind of things as an operator would you like to see in exchange for the severance tax and other types of things out there.

We'd like clarification on -- I'll name two things.

We would like pooling rules that are more in line with what we see in the rest of the country, and we'd like to see clarification on what kind of deductions are allowed for midstream costs when dealing with -- calculate what gets paid to either royalty owners or in the case we have severance taxes, to the government.

We also believe it is in our best interest, though, that any severance tax would divert a fair amount of the money to the localities that incur the inconveniences that do in fact come along with drilling as opposed to going to the state capitol.

Yes, okay, got it.

Alright, appreciate it thanks.

Our next question comes from Amir Arif from Stifel Nicolaus.

Please go ahead.

Thanks, good morning guys.

Just a couple of quick questions.

One, as you talk about capital allocation and focus on the highest return project any desire to shift more towards the Marcellus away from the Huron even in terms of (inaudible) drilling?

Yes, I think will you be seeing some of that over the course of time.

You are seeing some of it already but of course these are long lead time decisions.

And we haven't actually set our budget for 2011.

But directionally, certainly that's the way we'll react to any changes that we see returns.

We'll direct our efforts more toward the higher return projects.

I think on Huron/Berea you mentioned you won't see too much more aggressive expansion where would you need additional midstream.

Is that --

I was trying to make a more subtle point.

We've put in a lot of midstream already.

We're going to try to focus ourselves more on developing in ways that keep the midstream intensity lower as opposed to areas that will require a big new, let's say, corridor.

Look, obviously, that's one of those situations where it is possible that third-party capital becomes available, because the issue for us isn't so much the economics of that, though there's some of that that goes on, obviously, it's the total availability of capital.

So if we can -- to the extent we can source other midstream capital that alters that dynamic.

The focus that we've got is that we don't want to put a lot of our capital into some of those developments.

Not that we don't want the capital to go into the development.

Okay, is there certain absolute production number in terms of at which point, just for the Huron/Berea -- which point you would need or -- internal capital?

No, there really isn't a number.

For us practically speaking, it's got more to do with where we're developing within the play.

We've got quite a lot of acres that in play, as you know.

Then just a question in terms of the CBM.

When you look at that time economics of the Marcellus and the Huron and the inventory you guys have there and you desire to keep focusing allocating capital properly.

Any thought process of divesting some of your other assets?

We're an economic enterprise.

Everything is for sale every day.

It just doesn't seem as if right now is a great time to get very good prices for assets that are primarily proved producing.

Okay.

And I guess there's no -- , you hold those assets, or the acreage so there's no need to have

And we're already drilling, for the most part.

Really, the question with the CBM is whether at some point -- what is the circumstance under which we would ramp up in such a way that we would need that next big midstream project.

And it's a little bit simpler in that regard that there would be -- if we wanted to step up lot, there would need to be a new pipeline that would be put in, and either would be our capital or we'd have to be committing to firm transport on that pipe.

Or anybody else would, frankly.

There's nothing magical about our methane.

It's near capacity down there.

Sounds great.

Thank you very much.

Our next question comes from Ray Deacon from provide Pritchard Capital Partners.

Please go ahead.

Yes, hello Dave.

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

I'll flip that question over to Steve.

Yes, Ray, what I would say is, our current estimate across our Marcellus acreage position is what's reflected in that 3,800 foot of pay, clearly we're drilling wells longer than that.

The reason we're showing 3,800 is that's our estimate of how it will all average out between long and short.

I think over time, if we can consolidate acreage and work with our neighbors, we may see that go up, but right now that's our best estimate.

Okay.

Got it.

I guess just to ask you to elaborate on a comment earlier, you said biggest risk to the volume growth this year is a function of the buildout of the infrastructure.

And I guess how much of that is third party infrastructure and how much of it is you just being able to get permits for the expansion of Equitrans, I guess?

It's a risks but there's actually another risk that we were very concerned about in the summer.

That is as the system starts filling up, the storage, et cetera, starts filling up the pressures start changing in the system, and that creates bottlenecks where there didn't used to be bottlenecks.

We're putting in projects to resolve those bottlenecks, but in a number of cases the projects were he never scheduled to come in until, say, late third quarter.

What we found throughout the middle of this year is we've been able to essentially come up with work-arounds to minimize the impact of some of those bottlenecks.

That's what I really meant about some of the middle of the year.

Incidentally, that's always going to be the issue, that you are going to ramp up, then once you get into the summer, when we're into injection season, then the dynamics start changing on the storage front.

And also that is, as you would imagine, the summer is the normal time for pipeline companies to take down their -- take their lines out of service temporarily for maintenance purposes.

And there's actually been a little bit less of that this summer than we were afraid of, and to the extent there has been, we've been able to come up with a little bit better work-around than we were anticipating.

But that's going to be, as we keep ramping up, this will be something we talk about every summer.

Mr.

Deacon, do you have any further questions?

Yes, sorry, one more quick one.

I was wondering how much of your frac fluid are you currently recycling, and I guess where do you see this going over time?

Yes, Ray, I'd say we are recycling nearly 100%.

Occasional there maybe few barrels here or there that he we dispose of, but effectively it's 100%, and we would expect that to continue.

Alright,thanks very much.

Our next question comes from Tim Snyder from Citigroup.

Please go ahead.

Hello, guys quick question.

You said you're drilling 34 more wells in 2010 in Marcellus.

Just wondering what kind of -- or how many wells do you expect will come on line out of that inventory you have in that 115 wells how much of that is baked into the guidance?

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

Got it.

What is the current take-away capacity in the Marcellus for you guys on the midstream side?

I don't know that we have one -- I don't know that we have one number for take-away capacity, because West Virginia versus Pennsylvania, it's different in different kind of sub geographies.

That's why we mention he'd some of those -- the projects that we had, specific projects in Pennsylvania and West Virginia.

But we'd probably be operating at reasonably close to our end year capacity with the end year exit rate that we provided.

Okay, got it.

We continue to work to put in additional capacity.

Got it.

Going forward, how should we think about the NGLs volume growth?

Is that just kind of a linear function with your production growth, or is that more centered towards the Huron/Berea?

It's more towards, it's Huron/Berea, and also parts of the Marcellus play that are kind of sort of more to the west.

The further west, or I guess you would say the further northwest you get, the wetter it gets in the Marcellus.

And the dividing line roughly, I don't want to make it seem so clean as a line, but the division is pretty much in southwestern P.A., from what we can see.

So a lot of it has to do with, as we've got opportunities that are a little bit more to the west than in the Marcellus that will be wetter.

And as you get far enough west, it's actually wetter than the Huron/Berea.

As you get to the east it gets pretty dry.

Got it, do you have an average gallon per M liquid content?

Randy, do we have an average gallon?

We do in the Huron, about two and a half, in the Kentucky.

And as far as the processing capacity goes, you guys see any sort of restraints there?

In Kentucky, our current facility is 170 million a day, and is adequate for the growth that we have.

But as we expand into Marcellus with our partnership with DCP we're working to evaluate what the needs are in the areas of the Marcellus going forward.

Okay,thanks, guys.

Is our next question comes from Michael Hall from Wells Fargo.

Please go ahead.

Thanks.

Good morning.

Apologies if I hit anything that's already been covered.

I had to hop off.

Just wondering there's any developments on your views around joint ventures in the Marcellus, any changes in your stance there, just maybe an update on your current thinking.

Well --

Joint venture in the upstream side that.

Our view are there appear to be some interesting deals that are getting done.

You're not actively looking at any on your end?

Look, we're open minded to ways to source capital.

As I said, the big picture issues for us, we've got a bigger opportunity than realistically we're going to be able to prosecute entirely on our own.

But that said, our focus right now is getting the midstream, especially the liquids ventures done.

We're not a huge company.

We can only focus on so many things.

But we're certainly open minded as far as how we would go about pursuing capital.

Okay, fair enough.

Then when you think about the potential to move towards a more -- a pooling regime, if you will more similar to the rest of the country, what would that maybe mean for EQT as it relates to horizontal locations relative to current vertical locations that are limited by acreage?

We don't really drill vertically in the Marcellus, so as far as the horizontal, Steve mentioned that the 3800-foot design that we're showing now is our average is affected by the fragmented land position.

That would obviously be one of the things.

Pooling rules would help with that.

You would just extend to a more -- an average 4,300 feet or something to that extent?

We'd extend and it's possible that would come out in the form of prioritizing different locations.

There's locations that get pushed back a little bit because of land reasons, and that could get he reshuffled a little.

Okay.

And then kind of along those lines, I think you had talked about, kind of super extended long lateral that you were testing in Greene County around this time.

Any color around that yet?

Again, apologies if you already mentioned it.

Is I mentioned that briefly earlier, just a real quick update.

We began fracking yesterday.

We successfully fracked the first two of 28 stages so we'll be work on that well for probably at least a week completing the rest of the stages, but at least the initially operationally, it's going very well.

Okay, I think that does it for me.

Thank you very much.

Our next question comes from Josh Silverstein from Fig Partners.

Please go ahead.

Hello, good morning, guys.

Previously when you guys had done the equity issuance you mentioned a preliminary production guidance for 2011 would be at least the same as it was for 2010 which was at the time 26%.

I was just kind of curious with you guys increasing the rate for this year if we were to kind of assume that 2011 could be the same rate, maybe 30% for next year, or at least that much, and if you guys were assuming the previous kind of 4 Bcfe to 4.5 Bcfe per well in that analysis versus the 5 Bcfe to 6 Bcfe.

We, -- the assumptions we were using at the time of that offering were based on the old well design but as we mentioned it was based on a particular hypothetical as far as how much capital we'd be willing to spend.

Certainly we are capable of growing this asset at that kind of rate.

But it is dependent on what capital we decide to spend is and we don't make those decisions until later in the year, and in this environment, in this financial environment, which is still a bits unsettled, it still doesn't seem that prudent to make commitments to what the capital spending will be in 2011.

What we said before is we were capable of higher growth rates.

Absolutely we continue to be capable of those rates, and adjusted for the well design issues, but it supposes certain capital commitments that we are not prepared to make yet.

That's something you guys will probably do in December?

Yes.

And, okay, also the 5 Bcfe to 6 Bcfe average that you guys have, can you break that out by area?

Previously you had talked about some locations in Greene County versus counties down in West Virginia that were a little different.

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

Got it, great, thank you.

You bet.

Our next question comes from Phillip Jungwirth from BMO Capital Markets.

Please go ahead.

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

No, we're currently finalizing the negotiations so we don't -- haven't reported that number yet.

Okay.

And then just on the -- what's the best way to gauge the level of spending in 2011 that you're comfortable with?

Is it to look at liquidity?

Because you'll probably be around $1.5 billion by the end of the year.

Is that the primary metric that you'd look at?

Then how low are you comfortable taking that liquidity to, to continue to outspend cash flow?

We do not want to run too close to the edge.

If that's what you are asking.

We'd like to know -- we'd like to know where the capital is coming from before we commit to spend it.

Okay.

That's all I had.

Thanks, guys.

Thank you.

This concludes our question-and-answer session for today.

I would like to turn the conference back over to Mr.

Pat Kane for any closing remarks.

Thanks, B.J.

This concludes today's call.

The call will be available for replay for a seven-day period beginning approximately 1:30 p.m.

today.

The phone number for the replay is 412-317-0088.

You will need a confirmation code which is 436920.

The call will also be replayed on our website for seven days.

Thank you everyone for participating.

Thank you.

That concludes the EQT corporation second quarter 2010 earnings conference call.

Thank you for attending today's presentation.

You may now disconnect.