EQT Corp (EQT) 2010 Q1 法說會逐字稿

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

All participants will be in a listen-only mode.

(Operator Instructions) 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 Pat Kane, Chief Investor Relations Officer.

Sir, the floor is yours.

Thanks, BJ.

Good morning, everyone and thank you for participating in EQT Corporation's first quarter 2010 earnings conference call.

With me today are Dave Porges, President and Chief Executive Officer and Phil Conti, Senior Vice President and Chief Financial Officer.

In just a moment, Phil will briefly review a few topics related to our financial results that we reported this morning, then Dave will provide an update on our drilling and infrastructure development programs and other operational matters.

Following Dave's remarks, we'll open the phone lines for questions.

But first, I'd like to remind you that today's call may contain forward-looking statements related to such matters as our drilling and infrastructure development, including Equitrans expansion, sales volumes, rates of returns, well costs, acreage acquisitions, financing plans, 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 at the Securities and Exchange Commission and available on our website.

Finally, this morning's call may contain certain non-GAAP financial measures.

Please see this morning's press release, a copy of which is available on our website, for the reconciliations and other disclosures which impact such non-GAAP financial measures.

Before introducing Phil Conti, I do have one housekeeping item.

Later today, we will post to our web site, EQT's 2009 early sales volumes by play and our realized price reconciliation table in the new format that was presented this morning.

With that, I'll turn it over to Phil Conti.

Thanks, Pat and good morning, everyone.

As you saw in the press release this morning, EQT announced first quarter 2010 earnings of $0.65 per diluted share, which was an 18% increase over the first quarter of 2009.

That increase in EPS, as well as the increase in cash flow that we mentioned, comes as a result of another outstanding operational quarter across all three of EQT's business units, including record-produced natural gas sales and continued low drilling and per-unit operating costs at production.

Another record in gathering transmission and processing volumes in our Midstream business and solid operating income at Equitable Gas.

The results this quarter I think are straightforward, so my comments about the financial performance will be relatively brief before turning the call over to Dave Porges.

Starting out with EQT production operating results, as has been the case for well over a year now, the big story in the quarter at EQT Production was the growth in sales of produced natural gas.

The growth rate, as you saw, hit almost 31% in the recently completed quarter over the first quarter of 2009.

That growth rate was all organic and was driven by sales from our Marcellus and Huron/Berea and driven by horizontal shale plays, which together contributed over 40% of the volumes in the quarter, far exceeding the 25% contribution in the same quarter a year ago.

Contribution from the Marcellus Shale is growing rapidly and represented over 10% of the volume this quarter, when it was really about -- it contributed about 1% in the first quarter 2009 and only 3% for the full year of 2009.

Gas prices were also up a little bit in the quarter.

The realized price at EQT Production was slightly higher at $4.23 compared to $4.16 last year.

And at the corporate level, EQT realized $6.62 per Mcfe or about 9% higher than last year.

You may have noticed that we have slightly altered our price reconciliation table included in the press release this morning.

We did add a line to reflect the full value of our produced liquids in the realized price.

And by the way, those liquids come primarily from our Huron/Berea play.

Our previous presentation did include the BTU premium at the price of natural gas, however, any profit made when our Midstream group strips the liquids and realizes higher prices than the natural gas price, was included in the processing net revenues at Midstream, but was not included in the average wellhead price to EQT Corporation.

While this additional detail does not change the reported financial results at all, we do think it better illustrates the full revenue generated from our producing wells.

As you can see in the table, EQT Corporation realized $1.22 per Mcf on average above the price of dry gas.

$0.58 recognized as the Btu premium at production and $0.64 recognized as net liquids at Midstream.

A brief moment on expenses at production.

Total operating expenses were higher quarter-over-quarter as a result of higher DD&A, SG&A and LOE, all consistent with the significant production growth.

Production taxes were down a fair amount in the quarter, especially on a unit basis.

$0.26 per Mcfe in the recent quarter versus $0.36 per Mcfe a year ago.

I think since that large of a unit decrease may not be intuitive in the recent price environment, do remember that production taxes are the total of two price-related taxes, one being severance taxes and the other being property taxes.

Severance tax is a fairly straightforward calculation as it is just a percentage of our unhedged production revenue at current prices.

Property tax is also price-related, but with a lag.

So the property tax incurred in 2010 is primarily based on 2009 gas prices, while the comparable 2009 property tax was primarily based on 2008 gas prices.

So the significant decline in prices from '08 to '09 therefore resulted in lower property tax in 2010.

Exploration expense was also $2 million lower quarter-over-quarter as we reduced the size of our seismic program compared to last year and we expect exploration expense to be about $6 million for 2010.

Moving on to the Midstream business, operating income here was up 37% consistent with the overall growth of gathered and processed volumes, as well as the significantly higher liquids frac spreads, which were driven by a 72% increase in average NGL prices quarter-over-quarter.

Gathered volumes increased 16% ,mainly from gathering EQT Production's growing sales volumes, and combined with higher rates, resulted in a 26% increase in gathering net operating revenues.

In addition to improved prices, processing volumes were also up by about 21% as a result of higher production volumes from our wet gas Huron/Berea play in Kentucky.

Transmission net operating revenues were also up a little bit, primarily because of slightly higher rates.

And finally, storage, marketing and other net operating revenues were lower, mainly from lower third-party marketing margins.

In 2010, capacity constraints had eased somewhat in the (inaudible) Big Sandy corridor, resulting in a somewhat smaller premium for marketing services.

In addition, first quarter 2009 margins on gas marketed utilizing Big Sandy capacity, including contracts that were negotiated in the 2008 price environment.

By the first quarter 2010, those had been replaced by lower margin contracts.

Net operating expenses at Midstream were also about $6 million or [14%] higher quarter-over-quarter.

Higher DD&A expense associated with our increasing Midstream infrastructure accounted for $2.7 million of that increase in expenses, while increased electricity and labor to run our expanded compressor fleet accounted for the majority of the rest.

Moving on to Distribution, operating income at Distribution was up about 8%, mainly as a result of a full quarter of higher rates in Pennsylvania, which went into effect last February.

Weather was basically the same as last year.

The only real variance of note this quarter, was a $1.8 million increase in bad debt expense, which is reported in DD&A, and that reflects a decrease in federal funding for customer assistance plans this winter compared to last winter.

The collections history at Distribution actually improved somewhat quarter-over-quarter.

And then finally, our regular liquidity update, as a result of $538 million in net proceeds from the recent equity offering, and by the way, about $9 million of that came after 3/31, so it won't show up in the Q later today.

But that $9 million was a small portion of the (inaudible) after the end of the month.

And then, coupled with that, the receipt of $120 million cash tax refund resulting from the five-year NOL carryback allowed by legislation that was enacted during the first quarter of 2009.

Those two together, we closed the quarter with no short-term debt and a net cash balance of about $553 million.

As previously announced, our 2010 capital expenditure estimate is about $1.2 billion, and we estimate that 2010 operating cash flow, at the current strip, will be approximately $650 million to $700 million, including the $121 million we received from the tax refund.

So we're really in a great liquidity position to fund the remainder of the 2010 growth plan.

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

Thanks, Phil and good morning, everyone.

As I assume my new role at EQT, I look forward to building upon the firm foundation laid by Murry during his 12-year tenure as CEO.

Because of his leadership and passion, EQT has transformed itself from a regional utility into one of the leading natural gas production companies in the nation.

EQT and its predecessors have been around for over 100 years.

In my opinion, Murry Gerber will be remembered as the finest CEO this Company has ever had.

One of his greatest legacies has been developing a management team that can continue his fine work.

As many of you know, I joined the Company in 1998, along with Murry, as Chief Financial Officer.

Over the past 12 years, I've held various management positions, the most recent being President and COO.

At the outset, EQT's strategy was set largely by the two of us and we viewed this effort as a partnership.

Increasingly, the management team that has built up and grown up around us, has become much more involved in setting strategy and running the Company.

This is a team that is committed to the ultimate goal of increasing shareholder value.

Aspects of achieving that goal exist in all of our businesses, from accelerating our innovative shale drilling program to expanding and strengthening our Midstream capabilities to continuing our initiatives to be the most efficient in customer-oriented gas distribution company we can possibly be.

Still, the core strategy that animates our upstream and Midstream efforts is accelerating the monetization of our extensive reserves.

We intend to accomplish this via the drill bit, and other means as appropriate.

Those other means could include anything from partnerships with strategic or financial parties to asset sales.

However, we feel that our ability to execute against an organic growth strategy will create more opportunities for other monetization alternatives.

Therefore, we plan to stay the course in terms of developing our shale assets and getting the produced hydrocarbons to market.

Returning to the management team for a moment, I would like to gradually introduce to you more of them.

Today a I'll start by mentioning the three individuals whose titles include being a Senior Vice President of EQT Corporation.

You all know Phil Conti who just spoke.

Phil will continue as Senior Vice President and Chief Financial Officer of EQT.

Steve Schlotterbeck runs our Upstream business as Senior Vice President, EQT Corporation and President, Exploration and Production.

Steve and his team have demonstrated extraordinary innovation in developing both our Huron and Marcellus opportunities.

You are all aware of our innovations in air drilling in the lower pressure Huron and in adapting horizontal drilling to our assets.

These are not isolated innovations.

They are part of the culture Steve and his team have built.

And I'll mention more of their innovations in a few moments.

Randy Crawford runs our Midstream and Downstream businesses as Senior Vice President, EQT Corporation and President, Midstream Distribution and Commercial.

Randy personally, along with his team, developed the very notion of utilizing our Equitrans assets, be they existing pipes, right of ways, et cetera, to assist in the critical role of getting our produced natural gas to market.

Randy and his team are also leading our efforts to forge Midstream partnerships.

Now on to the first quarter results, as Phil mentioned, we had another strong quarter across our business lines.

The headline statistic is the 31% growth in sales of produced natural gas quarter-over-quarter and 11% growth in average daily sales sequentially.

This is our seventh consecutive quarter of double-digit natural gas sales growth.

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

Including the anticipated close within the next few days on the previously announced Marcellus Shale acquisition, EQT will have approximately 0.5 million acres in the Marcellus play.

Improvements in both drilling costs and completion effectiveness have caused to us become quite bulllish on this play, even in the current price environment, which is a great credit to the EQT team.

And here's the reasons.

As we've discussed over the past several quarters, we've seen a marked improvement in well costs and EURs.

On our year-end earnings call, we reported having achieved completed Marcellus well costs of about $3 million per well.

This cost per well was based on a standard lateral well, 3,000 foot laterals, and I'm referring to pay here with eight stage fracs.

We are now drilling that length wells with 10 fracs.

Perspectively, this is our new standard.

This change cost about $300,000 per well.

We're also witnessing increased steel and services costs, which perspectively are likely to add another $200,000 per well.

These two effects, both of which are consistent with the economics discussed as part of our recent equity offering, mean that we now expect Marcellus wells to cost between $3.3 million and $3.5 million per well, based on that 10 stage frac standard.

Earlier this quarter, our average EUR of Marcellus wells was increased to between 4 and 4.5 Bcfe across all of our Marcellus acreage.

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

Current economics include unit development cost for Marcellus wells of around $0.80 per M.

Our all in after-tax IRRs are about 30% at the current five-year NYMEX strip, which is about $6, and about 10% at $4 for the life of the well.

We include nearly $2 for transportation and gathering in our calculations to reflect the need for new infrastructure.

This assumes that new infrastructure is required to move essentially all volumes.

Obviously, once the infrastructure is in place, the actual marginal cost to keep the pipes full indefinitely is much lower thereby improving the IRRs on subsequent drilling materially.

We believe treating all volumes as if they require a new infrastructure is a conservative approach to our capital investment decisions.

We also believe it is the correct approach for us to take at this stage of the plays development.

By the way, we estimate the payback period from Marcellus wells at the current strip price to be between three and 3.5 years.

Regarding well results for the Marcellus, we've spread 74 horizontal wells to date, including 21 in the recently completed quarter.

Of those 74 wells, 28 have been turned in line.

We're expecting to drill 100 Marcellus wells in 2010.

So far in 2010, we have 11 wells with at least 30 days of production data which are not artificially curtailed due to takeaway constraints.

The average 30 day IP of these wells is 6.6 million cubic feet per day.

You can pretty safely assume that these were standard length laterals.

However, we're experimenting with longer laterals.

We've successfully drilled, completed and fracked a Marcellus well with a 4,800 foot lateral and 16 stages.

We're currently drilling out the frac plugs and will begin flow testing after that.

We have also just TD'd and cased a Marcellus well with 8,500 feet of lateral and we're planning a 28-stage completion.

The casing is being set as we speak.

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

Moving to our Huron play, as previously reported, we're drilling extended laterals into the Huron/Berea play.

To date, we've drilled and completed nine extended lateral wells.

Right now, that means they have about 5,500 feet of lateral each.

In 2010, we plan to drill 99 extended laterals in this play, and fully expect that extended laterals will be our standard operating procedure in the Huron/Berea play by year-end.

Extended lateral wells are providing increased productivity, which is expected to result in a per-unit development cost of a little less than $0.90 per Mcfe.

Our Huron/Berea wells are producing liquids rich gas, which also has a positive impact on the economics.

Over the past few years, EQT has developed an innovative culture that has led to several industry firsts and helped drive EQT's F&D costs to amongst the lowest in the industry.

These innovations include air drilling in the low pressure Huron, the first use of horizontal hammer drilling techniques, which have drastically lowered the costs to drill the hard rock formation such as the Berea, Big Line and Ravencliff, and the first use of a rotary steerable system on dry air which allows to us drill significantly longer laterals in the Huron play.

All of these technologies have proven themselves to add value for EQT.

Our latest focus has been on transferring our extensive knowledge and experience in air drilling to our operations in the Marcellus.

We have recently successfully completed the drilling of two Marcellus wells using air drilling techniques down to the beginning of the lateral.

While this technique is still in the experimental stage, if successful, we've seen many potential benefits from this, including the ability to use our smaller, cheaper and more mobile Huron rigs to drill a larger portion of our Marcellus wells.

This could provide a significant cost savings over our current practice, as well as minimize the amount of mobilization of the larger, more complex Marcellus rigs.

We will continue searching for new and better ways to drill, complete and produce our wells.

We will adopt and roll out the innovations that work, and will endeavor to learn from the experiments that do not work.

Switching to our Midstream activities, we're clearly moving towards a modular approach to building infrastructure.

I've mentioned in many forums that managing the Midstream issues for such a rapidly growing play is likely to provide challenges on an ongoing basis, as we seek to keep up with production growth without getting too far ahead.

Oddly, a more modular approach seems best suited to this evolving situation and that is the approach we're adopting.

To give you a flavor for what this means, I'd like to speak for a few moments about specific projects.

In the first quarter, EQT Midstream completed construction of the [Ingram] gathering system, which allowed for the delivery of 50,000 dekatherms per day of EQT production in Green County, Pennsylvania to two Equitrans pipelines.

Midstream is now on track for the second phase of that project which will extend the system east to nearby EQT production acreage.

Once completed, this will provide a further 40,000 deks per day of capacity for EQT's production by year end.

The necessary right-of-ways have been acquired and the pipe has been purchased.

In Northern West Virginia, EQT Midstream is in the process of constructing a [Doddridge] gathering system expansion which will deliver EQT's production from North Central West Virginia into the western leg of the Equitrans system.

Capacity additions of 50,000 deks per day will be made available by year end, bringing total gathering capacity in West Virginia to approximately 70,000 deks per day.

Turning to the regulated pipeline and storage business, we continue to make progress on our multiple expansion initiatives.

As you recall, the Equitrans Marcellus expansion project is underway and given its significant scope, is progressing in stages.

Equitrans has secured the market commitments needed to support the first phase of this project.

FERC prior notice application authority for this phase was received April 2.

As a result, this phase, which consists of upgrades to various segments on the Equitrans transmission system, along with modifications to compression at the frac station is proceeding according to schedule.

This $15 million phase allows for 100,000 deks per day of incremental delivery capacity to Equitrans' interconnections with five interstate pipeline facilities.

Construction is expected to be completed in the fourth quarter of this year.

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

In fact, Equitrans is preparing a second quarter 2010 certificate pre-filing for the balance of the project.

A provisional in-service date of mid-2012 is anticipated.

Consistent with my broader comments, this may well continue to progress as a series of small stages thereby giving us more flexibility to meet market needs, including the growing needs of EQT Production.

This would also buy us some time in terms of funding for the project.

Along those lines, we continue to have discussions with potential Midstream partners.

Initially, we are most focused on identifying a strategic partner for the liquids buildout.

This means that they must have experience dealing with wet systems, processing and downstream aspects of liquids, as well as being willing and able to fund a sufficient amount of the capital required for this buildout.

We are also open to partnering on the dry gas aspects of our Midstream business.

In this instance, operating expertise is less important as our Midstream unit already has that know-how.

Rather the focus is on a partner that brings funding capacity and willingness.

As a result of the slight differences in desired attributes for the wet versus the dry, we may end up with more than one partner.

In either event, we remain committed to getting at least the first stage, the liquids aspect, executed in 2010.

I'd like to conclude my remarks by reiterating our production guidance.

We recently upped sales growth guidance to 26%.

In the first quarter we beat that number, but it was compared to relatively low volumes for 1Q '09.

As I've discussed earlier today and previously, our attitude on guidance in these rapidly growing plays is influenced by the belief that Midstream constraints are a matter of when not if.

This will not halt the trend towards sharp increases in volumes over the coming quarters and years, but does make it more difficult to make it forecast specific timing on a quarter-by-quarter basis.

We'd rather see how some of our efforts to ameliorate these Midstream constraints during the summer play out before reassessing our relatively fresh production guidance.

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

We believe EQT is a very compelling investment.

Growth rates and cost structure are industry leading.

We receive a premium basis to NYMEX.

We have an extensive acreage position to develop, and we believe we have the most innovative group of employees in the Basin, people who are committing to getting it done.

Thank you.

I will now turn it back over to Pat and we'll take your questions.

Thank you, Dave.

That concludes the comments portion of the call.

BJ can now open the phones for questions.

Thanks.

Yes, sir.

We will now begin the question and answer session.

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

Please go ahead.

Thanks.

Good morning.

Hey, Scott.

So, it looks like on the well, you indicated that you're drilling at 8,500 foot lengths and 28 stage fracs.

So, when you look at pushing the envelope in terms of trying to optimize production, what is your capacity, do you believe, in terms of your acreage position and what do you think is the optimal length at this point in time?

We don't know.

We're experimenting so that we can come back with you.

Based on what we're seeing now with current technologies, that 8,500 foot may be about as far out as we can economically get.

We've got -- we're committed to experimentation and we'll have to get back to you on what we wind up concluding eventually is the best approach.

We do think it probably makes sense to go further than 3,000, which is the current standard, but in the Marcellus, as you are aware, the acreage positions are so fragmented that land is going to be a limiter that we're going to have to wind up figuring out.

Yes.

Absolutely.

And when you think about that, are you actively looking to bolt onto your acreage position to enable you to optimize your drilling at this point?

We're certainly open to those types of tactical acquisitions.

I also think something that we haven't done a lot of here, which is normal in other plays with fragmented acreage, and therefore we're going to get into, are doing deals with other production companies.

Whether it's little swaps or people participate in wells with each other, et cetera.

I think we're seeing a little bit of that in Marcellus.

Historically, we haven't done very much of it.

But I think that's going to be something we're going to wind up pursuing on the business development side of production.

Okay.

Got it.

And when you look at those, I think you said 11 wells had been online for 30 days.

It had an average 30-day rate of 6.6 --

6.6

Yes, 6.6.

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

Those are basically consistent.

We keep looking at the right EURs, but some of those 11 only have 30 days, which isn't that much data to be using to reassess EURs.

Okay.

Okay.

And one final question.

What did your active rate count in the Marcellus right now and where do you expect it to be at the end of the year?

And can you also, as part of that talk about the acreage acquisition that you made, how much activity is going to be up in that area?

Let me answer the last one first.

As we put in the equity presentation, we're still looking at probably about three wells in that area in 2010.

The closing hasn't actually happened yet.

So it should happen any day now.

But the working hypothesis is three and we'll revisit that in future calls once we actually own it.

As far as the rigs, it depends on the definition.

We typically run with the notion that we've got about six, but those are more of the big rigs.

And you might assume, to go along with that, that there's three piggyback rigs, which would get you, if you count total rigs on the Marcellus to nine.

And we would expect that we would continue that through the year.

That that would be consistent with getting to that 100 wells for the year.

All right.

Appreciate it.

Thanks.

Thanks, Scott.

Our next question comes from Craig Shere from Tuohy Brothers Investments.

Please go ahead.

Hi.

Congratulations on the quarter.

Thank you.

What is the time frame you're, perhaps, thinking about for feedback on this new technology application that may allow the use of smaller, less costly rigs in the Marcellus?

How would you see that kind of interweaving with the possible continued upward migration of the frac station and EURs going in to 2011?

I really think this is more of an ongoing issue.

Its probably in the area of months, when it comes to making a reassessment of the rigs, but I was really trying to get across on the call is our team doesn't just have an innovation or two.

It really is a culture that they've got.

The possibility of changing how we drill those wells is something that they've been working on for a while.

They've been making changes.

We've had some experiments that succeed, some that don't succeed.

I just think this is going to be an ongoing process.

We'll have more to report on that I'd say, probably every quarter.

Let me ask it a different way, perhaps.

Having looked at the R&D options and the potential and actual realized in the last couple of years impacts of them, would you say that what you have on your plate now in terms of things that you're evaluating to tweak the drilling process would maintain, accelerate?

Where would it be in terms of the potentiality of the reduced trend of capex per mcf over time?

If we look at last couple of years and what you have on your plate now, can we see an acceleration of the cost per mcf improvement or it's totally up in the air?

I don't think that we're going to see the kind of step changes that we've seen over the course of the last year.

Not that level of step change.

Those were huge changes that we experienced.

I do expect that the trend over time is going to be continued improvement.

There'll be a lot of small innovations is what I anticipate and then the occasional larger innovation.

Now, in the near term, with oil field inflation going on, we're probably looking for some short-term or mid-term period of time having productivity improvements that keep us more even as opposed to swimming against that tide right now.

But we don't expect that that's going to go on indefinitely.

And is the cost there more on the fracking, the steel?

Where's the main cost?

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

Sure.

Thank you very much.

Thank you.

Our next question comes from Ray Deacon from Pritchard Capital.

Please go ahead.

Hey, Steve.

I had a question for Steve.

I was wondering do you see any range -- range is talked about the Utica and the Upper Devonian potential and I was wondering if you have any plans to test that in southwestern PA?

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

Okay.

We respect those guys greatly and we obviously follow whatever they are doing.

We take a look at what they're doing to see if there's any lessons for us.

So we're as interested in what they're doing as you are, but it's not one of our top priorities right now.

Got it.

But you wouldn't rule out that it could be productive?

Oh, not at all.

Okay.

Got it.

Okay.

And --

We're optimistic about it eventually as well.

It's just that we have other things on the plate that rate ahead of it right now.

Okay.

Long-term, we're probably as optimistic about that as they are.

Okay.

Got it.

And I guess not quite understanding your math when you talk about the 3 to 3 1/2 year payout at the current strip for Marcellus well.

I'm showing somewhere around Bcf and to 1.3 b's in year one.

It seems like at $5 gas, you'd get payout on a well in one year, I guess, trying to make sure I understand that.

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

We haven't put out an actual decline curve yet, but we'll be in the next several months.

Okay.

All right?

Great.

Do bear in mind, Ray, we take into account the infrastructure up front as well.

Okay.

Yeah.

That would make sense.

So that's an up-front cost that definitely affects the economics.

Not just a well cost.

Got it.

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

Got it.

Got it.

Makes sense.

I guess, Steve, it doesn't sound like you yet want to put out an IP rate for one of these longer lateral Huron wells, I guess.

No.

Any thoughts there?

No.

We just as soon get one or two on -- get more of them online and then we'll do that.

Okay.

Got it.

Hey, thank you.

Great, thanks.

Our next question comes from Becca Followill from Tudor, Pickering.

Please go ahead.

Good morning.

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

Yes.

There are guys that are much earlier in the learning curve than Marcellus who are getting $14,000 an acre.

What do you think you could do in the organic strategy that would give you more than that or that would make something different versus what we're seeing already in transactions?

Well certainly, those are some nice numbers that we're seeing out there.

We'd agree with that.

But I guess from my perspective, six months ago or nine months ago, folks were wondering why we wouldn't sell at $5,000 an acre.

So, it's hard to tell where it's going.

We do think that we are in the upper tier, let's say, of Marcellus producers.

We're not trying to claim that we're number one, but if there's an upper grouping that we're in that upper grouping.

We'd like to get enough results so that that becomes the general view.

And I guess I'm trying to figure out when is enough enough?

How much do you need to know?

I know you've only drilled a handful of wells in the scheme of things, but what gives you that comfort that you're there?

Is it a couple years from now?

Is it ten years from now?

How far along in that process?

I don't know that we measure in time, but I will tell you, our ears are open.

When people come to talk to us, we listen.

We don't tell folks that we've got no interest in -- if they've got a way for to us increase shareholder value, we listen.

I do think that we find more people are talking to us as a result of the well results that we started putting out, really only late last year.

I think we've already seen folks taking us a little bit more seriously.

And, at this point, I think we expect that trend to continue.

But I wouldn't put a time frame on it.

Talk to the other companies who are interested in putting money in and ask what they think of EQT?

That's probably a better metric than us commenting on it?

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

I was hoping you'd do that work for us.

So they're knocking on your door and you are not turning them away at this point?

Well, it's to the extent we do.

But haven't we all been a little surprised by the extent of the international interest?

I mean, geez, Reliance Industries, that's interesting.

I know.

They're big numbers.

They're impressive numbers.

That's a big company.

The guy who runs this is a very wealthy man.

He can certainly afford it.

We just wouldn't have thought that an Indian company would have done it.

So who knows.

Now we've got a Norwegian company, Indian company, a Japanese who got in.

I remember when I was in banking, the Japanese were getting big into the upstream in the U.S.

that was in the '80s.

Then you really didn't hear a lot from them in the '90s.

In the box or whatever we call that.

So, wow, if the Japanese are interested again, then who knows where we're heading.

Okay.

Thank so you much.

Great.

Thank you.

Our next question comes from Zack Schreiber from Duquesne Capital.

Please go ahead.

Hi, guys, it's Zack Schreiber, can you hear me?

Yes, Zack, how are you doing?

Good.

How are you?

Congratulations on the results.

Just following up on Becca's line of questioning, did you guys have any conversations with Reliance?

It sounds like did you did and obviously --

No, actually we didn't.

I don't mean to mislead you.

No, we did not.

We had been hearing about it before the deal was announced, but no, we did not have any discussions.

Honestly, the only connection is it winds up that the CEO of Reliance was a business school classmate of mine so I follow them with a little more interest.

But no, we did not have conversations.

Is it the former Shell guy?

No, no, no.

I'm talking about Mukesh Ambani.

Oh, really?

Oh.

Got it.

So the folks sniffing around have not called you or they have called or they're just starting to call you?

People are sniffing around, but I don't think you'd want to say we know what they're interested in.

So far, our impression is the people who've done deals are ones that are the producers who went after them aggressively.

Yes.

But I don't think that's the only conversations that are going on.

So when you rip apart the Atlas/Reliance deal, is that a deal that you think could you have done or is there something distinguishing about Atlas' acreage via the geology or the location that you think makes that valuation not accessible to you?

Or were you to explore and aggressively pursue these joint venture opportunities that kind of valuation is accessible to you?

I'm not sure what you're trying to say, Dave.

I don't know if it's accessible.

I think the best deal for any company is probably specific to that company's circumstances.

So I don't feel comfortable speaking for what Reliance or Atlas saw.

I feel pretty confident they must have each thought that it was the best deal for them.

But beyond that, all we're taking away from it is that it appears, as if generally speaking, the values that are available out there are still going up.

Yes.

Despite the very weak price environment.

And so what you're saying, though,is that when Reliance was looking for that deal, you were not actively in the market looking for --

I don't think it was -- look, you'd have to talk with Reliance and Atlas.

Our impression was it was Atlas that was looking for a deal.

Agreed.

So that's our impression that Reliance wasn't comparing it to -- we don't know money we weren't -- we certainly were not involved in a process.

Got it.

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

Got it.

Just in terms of, you know, the value from accelerating the monetization of your extensive reserves, and following up again, on Becca's question, so I'm sort of plagiarizing her, but how exactly do you view your success with the drill bit feeding into any possible asset sales or partnership type deals?

If it's not an issue with the amount of time, is it an issue with some degree of success or EURs that you think?

If it's not time what exactly is it that you think allows you to reach full value?

Because I agree with you, values do keep going up, despite the low gas price.

That's obviously the economics of the asset that you're sitting on.

But if you sit on that forever waiting for it to go up, you are effectively competing against the time value of money discount rates.

So at what point is it better to bring forward that value?

I'm not sure I'm making sense but you know --

I understand what you mean.

I guess what's the rate of inflation of that value relative to your cost of capital and discount rate?

I don't have a specific answer for you.

I will tell that you it does seem to us that we're still in the process of demonstrating increased value from these assets.

Yes.

And that, we think,a positive no matter what way we go.

Yes.

It seems to us as if there's been no diminution in interest in the shales, and in the Marcellus shales specifically, on the part of either domestic or international companies.

So while we agree with you you don't want to wait forever, it doesn't appear to us as if you need to be panicked into doing something, either.

Yes.

And we continue to show improvements.

At this point, it doesn't appear to us as if our performance is plateauing.

Got it.

All righty.

I'll let you escape.

Thanks so much.

Thanks, Zack.

Thank you.

This concludes the question and answer session for today's conference.

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

Pat Kane for any closing remarks.

Thanks, BJ.

That concludes today's call.

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