EQT Corp (EQT) 2012 Q3 法說會逐字稿

Good morning, and welcome to the EQT Corporation third-quarter 2012 earnings conference call.

All participants will be in listen-only mode.

(Operator Instructions)

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

(Operator Instructions)

Please note this event is being recorded.

I would now like to turn the conference over to Mr. Patrick Kane, Chief Investor Relations Officer.

Please go ahead.

Thanks, Laura.

Good morning, everyone, and thank you for participating in EQT Corporation's third-quarter 2012 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.

This call will be replayed for a seven-day period beginning at approximately 1.30 PM Eastern time today.

The phone number for the replay is 412-317-0088 and the confirmation code is 1000-6606.

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

As you already know, this is the first quarter for EQT Midstream Partners, ticker EQM, and its results are consolidated in EQT's results.

There will be a -- there was a separate press release issued by EQM this morning, and there is a separate conference call at 11.30 today, which creates a hard stop for this call at 11.25.

If you are interested in listening in on the EQM call, the dial-in number is 412-317-6789.

In just a moment, Phil will summarize EQT's operational and financial results for the third-quarter 2012, which were released this morning.

Then Dave will provide an update on our strategic operational matters.

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

But first, as usual, I'd like to remind you that today's call may contain forward-looking statements related to future events and expectations.

You can find factors that could cause the Company's actual results to differ materially from these forward-looking statements listed in today's press release under Risk Factors in the EQT Form 10-K for the year ended December 31, 2011, which was filed with the SEC, as updated by any subsequent form 10-Qs, which are on file at the SEC and available on our website.

Today's call may also contain certain non-GAAP financial measures.

Please refer to this morning's press release for important disclosures regarding such majors, including reconciliations to the most comparable GAAP financial measure.

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

Thanks, Pat, and good morning, everyone.

This morning, EQT announced third-quarter 2012 earnings of $0.21 per diluted share.

That compares to EPS of $0.45 in the third quarter of 2011 after adjusting for the sale of Big Sandy.

Operating cash flow was $176 million in the third quarter of 2012, compared to $191 million for the third quarter of 2011.

And adjusted cash flow per share was $1.18 in the current quarter, compared to $1.28 in the third quarter last year.

Our operational performance was outstanding again this quarter, with 33% higher production volumes, 30% higher gathering volumes, and continued low per-unit operating costs.

However, as I'm sure you are aware, commodity prices in the recently completed quarter were significantly lower than they were last year, resulting in both lower operating income and cash flow.

This quarter, as Pat mentioned, was our first with an MLP.

As you know, EQT Midstream Partners completed its initial public offering in early July.

The EQT Midstream Partners results are consolidated in EQT results, and we recorded a $4.8 million, or $0.03 per diluted share, deduction in the quarter for the portion that went to non-controlling interest unit holders to arrive at the net income to EQT shareholders.

While there is no gain on the accounting books as a result of the IPO, on the tax books, we recognized a gain of approximately $110 million, net gain results and additional cash taxes for 2012 of approximately $13 million, as we were able to offset most of the tax obligation with our tax shields from intangible drilling cost deductions and tax depreciation.

Another non-operational variance from the norm this quarter was our effective tax rate of 24%.

The lower effective tax rate was due to less income on our companies that pay state taxes, a tax benefit recorded in the third quarter to reflect the 2011 tax return that we recently filed, and the impact of EQT Midstream Partners.

As we have mentioned, from a financial reporting standpoint, we consolidate 100% of EQM pretax income at EQT.

However, we only report taxes on our 60% share.

That has the effect of lowering the average effective tax rate.

Despite the quarterly rate, we do expect our full-year effective tax rate to be around 38.5% after making adjustments at year-end to reflect our increasing income contribution from Pennsylvania, which taxes at a higher rate than other states where we operate.

Moving on to the segment results, starting with EQT production, sales volumes there continue to grow rapidly.

The growth rate in the recently completed quarter, as we mentioned, was 33% over the third quarter of '11.

That growth rate was driven by sales from our Marcellus play, which contributed approximately 60% of the volumes in the quarter.

Marcellus volumes were 85% higher than the same quarter a year ago.

However, as I mentioned, gas prices were lower in the quarter, consistent with lower NYMEX prices.

At the corporate level, EQT received an average wellhead sales price of $4.04 per Mcf equivalent, compared to $5.25 received in the same quarter last year.

The realized price at EQT production was $2.85 per Mcf equivalent this quarter, compared to $4.02 last year.

Even with more than 50% of our volumes hedged in 2012, EQT productions average realized price per Mcfe was 41% lower than the third-quarter 2011.

Produced liquids accounted for 5% of the volumes in the quarter.

And as we always remind you, we do not include ethane in this calculation, given that it is currently primarily sold as methane.

Total operating expenses at EQT production were higher quarter over quarter, mainly as a result of higher DD&A expense, which was driven by the 33% higher volumes and a higher DD&A rate in 2012.

Our average DD&A rate was $1.54 per unit for the quarter -- for the recent quarter, and we estimate that it will be up $0.01 to approximately $1.55 in the fourth quarter.

As a result of the impressive volume growth in the quarter, and looking at the well schedule to come online, as you saw, we are raising our 2012 sales volume estimate to 257 Bcf equivalent.

Furthermore, even though we are still completing our development plan for 2013, we are comfortable that our growth rate off of that revised 2012 estimate will be at least 335 Bcf, or up 30% or more on an annual basis versus 2011.

We will provide an update in December when we announce our 2013 capital budget.

Moving on to midstream results in the third quarter, operating income here was up 22%, again, adjusted for the Big Sandy gain in 2011.

The increase is consistent with the growth of gathered volumes and increased capacity-based transmission charges.

Net gathering revenues increased 22% to $77 million in the third quarter of '12, primarily due to a 30% increase in gathered volumes.

The average gathering rate paid by EQT production will continue to decline, as Marcellus production continues to grow as a percentage of our total production mix.

Specifically, the average revenue deduction paid by EQT production to EQT Midstream for gathering was $0.09 lower this quarter versus the same quarter last year at $1 per MCF equivalent.

Transmission revenues for the third-quarter 2012 increased by a little over $8 million, or 45% versus 2011, and that resulted in capacity charges associated with Equitrans expansion projections, including Sunrise, which was completed in July 2012.

Storage, marketing, and other net revenue was down $7 million in the third-quarter 2012, or $0.04 in earnings per share, primarily from unrealized losses on derivatives and inventory in this quarter.

As has been mentioned before, the storage and marketing part of the Midstream business relies on natural gas price volatility and seasonal spreads in the forward curve and those have continued to deteriorate year over year.

Given current market conditions, we now estimate that full-year 2012 net revenues in storage marketing and other will total approximately $45 million.

Operating expenses at Midstream were $5.6 million higher than the same quarter last year, consistent with the growth in the business.

To conclude, just a quick liquidity update.

As a result of the slightly higher volume forecast, we also expect our operating cash flow for 2012 to slightly exceed $800 million.

We closed the quarter with no outstanding balance on our $1.5 billion credit facility and had $639 million of cash on our balance sheet as of September 30.

So we remain in a great position from both a liquidity and a balance sheet standpoint.

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

Thank you, Phil.

We continue to focus on achieving our objective, maximizing shareholder value to be an overarching strategy of economically accelerating the monetization of our asset base and prudent pursuit of investment opportunities, while living within our means.

The tactics continue to evolve somewhat based upon market conditions and the fact that we are completing some of the tactical steps outlined previously.

We took three major steps, all related to our Midstream business, so far in the past two years, with the sale of our only processing plant and our Big Sandy pipeline in 2011, and our successful IPO of EQT Midstream Partners midyear 2012.

We still have more work to do as we look forward to accelerating the development of our vast opportunities.

We have two plays that we are not currently developing.

Our CBM acreage, representing about 250 Bcf of proved developed reserves, but not much additional 3P value at current market prices, and our huge Huron play, 1 Tcfe of proved developed reserves and 7.72 Tcfe of 3P reserves.

We will look to realize value from these two plays, but probably in different ways.

It is most likely that we will eventually sell the CBM play outright, since there is not much value in the undeveloped locations at anything close to current prices.

To that end, we did do some work to determine what potential buyers might be willing to pay for those assets.

For the time being, the transaction market value is not high enough to warrant further pursuit of a cash transaction.

We will revisit this issue as natural gas prices recover, thereby increasing the value of the PDPs.

The Huron, on the other hand, has significant value in the undeveloped locations at the current strip.

So we re more likely to try to find a way to capture some of that value but accessing another source of capital, though not EQT equity, to reactivate that play.

Obviously this will require some imagination and may take a while.

Though we are in the early stages of examining the alternatives, they generally involve EQT continuing as operator but using third-party capital for development, as EQT has developed some competencies in developing this somewhat distinctive play.

Unfortunately, even though Huron development is economical at the current strip, it does not compete well with our alternative uses of capital, which is which is why we believe it makes sense to examine possible transactions.

Regarding the main such alternative use of our capital, we continue to manage our Marcellus acreage position to allow for as much of multi-well pad development as possible, as this is both the most economical and most environmentally sensitive approach.

In circumstances in which this approach is not practical, we are either looking at joint development or tactical sales of properties.

To that end, we are looking at the possibility of selling or swapping our 8,600 acres in Tioga County, since it is neither large enough nor close enough to our core development areas to rank very high on our investment priority list.

Another source of relatively low-cost capital is EQT Midstream Partners, our MLP.

Sale of Midstream assets to EQM, that is drop downs, offers a repeatable source of low-cost capital.

This funding source helps EQT accelerate development of our Marcellus position, which in turn will create new Midstream opportunities that add to the inventory of dropable Midstream assets.

As you recall, conceptually over time we intend to fund EQT's Midstream CapEx with these sales to EQM.

As for specific timing, it is unlikely that we will execute a large drop that would require the issuance of new units prior to July 2, 2013, when EQM would be considered a seasoned issuer, which simplifies EQM's process for raising equity capital.

Though it is possible that we would execute a small drop before then to give us a little expense with the process of valuing and accounting for a drop down.

We are currently working through the mechanics of drop-downs involving various Midstream assets.

Moving on to other operational matters, as we told you on the last call, MarkWest is building a processing plant to serve our West Virginia wells.

Construction of this plant is still moving along according to the revised schedule, and we still anticipate completion by year end.

As you recall, this revised schedule calls for later completion than originally anticipated, but there have been no further revisions to the schedule since our last quarterly update.

As mentioned on the last call, EQT and MarkWest have also developed an interim solution using some existing and some new assets to provide EQT with some cryogenic processing until we originally contracted facilities are turned in line.

This capacity, roughly equivalent to 35 million cubic feet per day, or one-third of contractual capacity on the new plant was online for most of the third quarter.

However, since this was all interruptible, we currently only have about 25 to 30 MMcfd of capacity.

We have also committed to take 100 million cubic feed equivalent of incremental processing capacity on a planned expansion of this facility, so this represents incremental processing above and beyond the 120 MMcfe that we have in the first plant.

We are still working with MarkWest on the timing of this incremental volume.

As you saw in this morning's press release, we increased our production sales volume guidance.

I mentioned in the last call growth rates versus same quarter prior year can vary, due to the inherent lumpiness of how we add volumes.

This lumpiness is largely the result of a combination of pad drilling and the timing of infrastructure adds.

Last quarter, we discussed the 10 well pad in Green County that was being turned in line in July.

As we expected, we saw initial flow rates of 100 million per day from this pad.

Additionally, we have two pads with a combined total of 13 wells, that are being turned in line currently, and three more pads, with a combined total of 15 wells that will begin being turned in line next line.

This is what gives us confidence to increase volume guidance for 2012 and to set that preliminary 2013 volume growth target of 30% versus that upwardly revised 2012 target.

In summary, EQT is committed to increasing the value of our vast resource by accelerating the monetization of our reserves and other opportunities.

We continue to be focused on earning the highest possible returns from our investments and are doing what we should to increase the value of your shares.

We will stay disciplined and live within our means, investing our available cash from operations and from future monetizations.

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

And with that, I'll turn the call back over to Pat Kane.

Thank you, Dave.

This concludes the comments portion of the call.

Laura, can we please now open the call for questions?

Yes, certainly.

(Operator Instructions)

Our first question is from Neal Dingmann of SunTrust.

Quick question on the -- if we just look at your Marcellus horizontal well status -- looked like, as far as the wells spud were down just slightly third quarter versus second.

I'm just wondering -- the rate there that you see going forward, what kind of growth rate just on total wells spud?

But it looks like frac stages might be expanding just slightly.

If you could talk a little bit on how you are spacing that?

Neal, just so you know, we have both Steve Schlotterbeck and Randy Crawford sitting in with us and to also help answer questions, and this sounds like a great one for Steve.

Yes, Neal, I think that is just a normal fluctuation of timing.

You'll see little bit lower well count due to drilling longer laterals, but I don't think there is really much to read in there.

We still expect to end the year around 130 to 132 wells spud, so really no new news there.

I think on the frac stages -- you didn't specifically ask about it, but the fourth quarter is going to be a very busy quarter for us in terms of bringing online new wells and new frac stages.

And for reference, over the past four quarters, the biggest quarter for us in terms of new frac stages online was three quarters ago, with 578 stages.

In the fourth quarter this year, we expect to bring online over 1,100 new stages.

So we have a lot of new production coming on this quarter.

Wow, that is a big number.

And then Steve, just to follow that, it doesn't look like -- you didn't appear to be any takeaway issues.

I was just noticing on the wells complete but not online.

Is that related to the takeaway, or not necessarily?

There is always a handful of wells that are waiting on a pipeline to be completed.

But for the most part, it is timing of these multi-well pads.

So we happened to hit a spot here early in the fourth quarter where a number of large pads are ready to go, so we would be bringing a lot on.

So the backlog will fall really a trivial amount of pipeline or capacity issues involved in those numbers.

Okay, and then just lastly in that same area -- it sounds like you obviously are doing now primarily pads.

Does that mean, Steve, you just want to look on a unit basis, you'll be able to get more wells in some of these key areas because of that?

I'm just wondering -- the question would be, how many wells max per pad?

And then, how many, if you hit some of these key areas, how many wells could you get in some of these units?

Well, we have been focusing our efforts in two key areas.

One, the Greene County area, which is a dry gas area, but is our most productive area.

We focused a lot of our attention there this year.

The second area is Doddridge County, which is higher BTU gas and still -- equivalent from an economic basis to Greene County.

So we have already been focusing there.

You are going to see pads range from four wells to as many as ten wells.

A lot of it is depending on the specific anchor position in those areas.

But that is a clear goal of ours -- is to maximize the number of wells per pad.

We think that is a big economic advantage.

And continuing to drill as long of laterals as we can.

Perfect.

Great color.

And our next question is from Amir Arif of Stifel Nicholas.

Just a quick question on the unused transmission capacity, the $5 million charge.

Can you just tell us, give us some color where that was?

Is this something is the Cuyahoga area?

And what the total liability might be over the next few quarters or so?

Yes, the capacity is related to the Tennessee 300 line, and as we have said, we have got long-term and short-term leases for that, and we continue to see the value in that capacity over the long-term.

It is a constrained area, and it's centered in and around the Cuyahoga, northern Pennsylvania area.

How much is that total commitment that you might not end up using in terms of costs or capital?

Well it is really a contractual asset.

We have contracted with 350 million a day capacity, and we continue to utilize that as we ramp into our production.

And we're actually executing on a short-term some additional releases, and in the long-term.

But the value associated with that capacity, as I said, in a constrained area is seasonal in nature.

So it is difficult to predict how that will go quarter over quarter.

There is a lot of seasonality with it.

And as you are aware, when we first enter into those agreements, since these are new pipes because there is growth, or a new expansion, you have to enter into an agreement to take out all of the capacity that you are going to get for that particular project, all up front.

It is just that, as Randy said, with our own production, we are ramping into the need for it.

So some of it gets reserved for our own use, for our own produced assets.

In some cases we have contracted out for a two-, three-year period, et cetera, on a pretty much a firm basis.

But then, we always keep some that is a little bit on the short-term cushion versus what our current needs are, which would allow us to make sure we can move our own production if it increases more rapidly than expected or that we would sell into the market.

And what we are talking about then is what happens with that additional portion only.

And that is the piece that has tended to be a bit, as you would imagine, a bit seasonal, where you make most of the -- so for the most part, you're making money in the first and fourth quarters, and you're losing a bit of money in the second and third quarter.

But we did not enter into that capacity, just so you know, for trading purposes.

That is designed over time to be moving our own produced gas.

Okay, that's fair.

And then can you just give us some timing in terms of the 80,000 acres in Tioga, the swap or the sale, as well as timing on when you decide what to do the Huron Berea?

I'm sorry, I'm not sure if we heard that.

Is it possible for you to speak up a little?

Sure -- just the timing in terms of the selling or swapping the 80,000 acres that you are talking about in Tioga?

Whether it's 2Q --

It is actually 8,600 acres, so I must not have been clear on my comments.

I apologize for that.

It's 8,600 acres in Tioga.

And I just say that we are in the midst of finding out what might be out there for that property.

I don't know that I have got any specific timing to offer up.

And incidentally, our attitude is that all the assets at some point are for sale.

So sometimes, we run formal processes and sometimes we just do market checks.

So it really depends on market conditions, what would happen there.

And I would say on the Huron, that we are in the early stages of looking at what the alternatives are, because we do suspect that it is likely to be something a little bit more structured with the Huron, since the issue there is the development opportunity, we think has so much value in it.

But we are going to have to figure out how we can best extract that value.

Okay, and then just one final question -- in terms of the 30% production growth you've laid out for '13, how may wells does that require in terms of drilling in '13?

Gee, I don't know that it requires many wells in '13.

You are aware of the -- we have got this extensive lag -- especially with the multi-well pads, I guess, maybe we've even got a little bit longer lag.

But, gee, Steve I don't know.

We probably don't need all that many wells.

It doesn't require a lot of drilling next year.

2012's drilling is what comprises the majority of our growth in 2013.

Now by the same token, that means, of course, that most of the wells that we drill in 2013 are not really going to be contributing much to 2013 volumes.

So lest you think that we could race way, way higher than that, once again past -- what, Steve, about the first quarter of 2013?

It is really not going to contribute much to 2013 volumes.

Okay, and then the '13 guidance is coming out in December in terms of the capital side?

The formal guidance, yes, because that get blessed by our Board.

And we typically think of it as our December Board meeting.

It is typically in the very end of November, the very beginning of December, and that is when the Board approves the capital budget.

And the next question is from Ray Deacon of Brean Capital.

Randy, I had a question as far as when you talk about doing a small drop down, what is the range of value you could do there without having to issue units at EPM?

Well, we have got obviously a variety of options with the inventory that we have at EQT.

And so, again, we have access to a $350 million a day, so $350 million of a revolver that we could access with that drop.

Certainly we wouldn't be looking to do all of that, but we have that opportunity.

So I don't know --

It was actually Dave that mentioned that.

We would be thinking about something pretty small, just as Dave mentioned -- try out the process.

We have to go through a conflicts committee with EQM, and there's accounting implications that we need to try out.

So if we can, we'd like to try to do a small one before we do larger one.

If you are trying to get a sense for modeling purposes for EQT, I don't think you really need to pay much attention to that.

I think you'd be looking more at what it would look like -- what a larger drop might look like as you get more deeply into 2013.

Okay, got it.

I guess just big-picture thoughts on the Marcellus -- if you look at, I believe the Marcellus is producing about 6.4 BUs a day.

Where do you guys feel think that is in a year?

I feel like I'm hearing a lot of people talking about cutting back?

Do you guys have a view?

I guess there some areas in the Marcellus -- we've talk about tiering.

And I might have a comment, and Steve, I think, will have a comment.

But when we talk about the economic tiering, let's say, within the Marcellus, we have observed that there has been a fair amount of cutting back in the lesser, the lowest tier, which is, seems like it is generally speaking, geographically more like in the middle of the play.

Not really so much in the northeastern part of the play or the southwestern part of the play.

Steve, do you want to?

I think that is very true.

The only thing I would add is we are not really up in the northeast part of the play, but we do continue to hear about the Midstream constraints up there.

So that might moderate what happens there over the next year or two.

But I think in this -- down where we are at, we have a lot of capacity.

We have great economics.

So I think it is going to be continued significant activity down there.

We hear a lot about the number of wells that are prevented from being turned in line due to Midstream.

But we really don't have very much direct experience with that.

From our experience, most of it, as Steve alluded to in answer to an earlier question, is much more just the timing, some little timing issues.

But we don't actually see those things that get reported on as being big -- large backlogs of wells that evidently are -- get represented as being completed and ready to turn in line, but not able to turn in line.

And we understand if that is happening, that people in that part of the play might decide they don't want to drill more wells for a while.

That would make sense, but we don't actually have any direct experience with that in the southwestern part of the play.

Got it.

And I feel like I heard for a couple of years that differentials were going to go away in the Marcellus, and I'm seeing $0.20 to $0.30 premiums on Tennessee, it seems like.

Any sense that, that is going to change going forward?

Are you benefiting as a result right now of having that locked-in capacity on Tennessee?

Ray, this is Randy.

As I said, it is a constrained area.

There are wells that are -- as we hear, are continuing to be turned in line.

And so, we think that capacity, certainly near-term and maybe into of the future as other development goes, has value.

So over the calendar year, with the long-term and short-term releases, we have been able to recover our costs plus after this year.

I'll tell you, we have the sense that most companies that we think of as our peers -- similar size and stuff like that -- have taken a similar approach with making sure that they are lining up this capacity.

I guess we're presuming that there must be other folks who did not take that approach.

But the ones that we follow most closely, from what we can tell, took approaches that more or less were similar to what ours were, where you take big positions on these pipes when they do get built, and we are certainly happy that we have done so.

So that said, if you are planning to build a big industrial facility, we prefer that you build it in southwestern PA or northern West Virginia.

Got it.

Just one more quick one -- is the 30% growth in 2013 -- you are not assuming that you are able to make something happen in the Huron to achieve that, it sounded like it?

No that doesn't include anything in the Huron.

As a matter of fact, the reality is that would mean it has to overcome a little bit of natural decline in the Huron.

I don't have numbers in front of me, but it's just, we have not been drilling there for several months, and that's -- unfortunately we cannot make the volumes go up without drilling.

And our next question is from Becca Followill of US Capital Advisors

Two questions for you -- one on the Huron.

If you look at another source of capital for that, I assume that is for the EMP side, and that is an area that requires incremental infrastructure.

So how do you handle the capital for incremental infrastructure?

Well, we would be -- to start with, if it were an incremental development plan, we would be targeting the parts of the play where less infrastructure was necessary.

So I guess that would be the -- that's certainly something that we are aware of.

To some extent, depending on the pacing, one can simply drill into the decline, as it were.

That -- to really take broader advantage of the development opportunity, though, as you suggest Becca, we would have to have paired with it a Midstream program.

But when we're looking at the solutions, we are taking that into account.

We never really just look at the capital that would be associated with the development.

We would look at the capital that would be required for the Midstream build out.

So that structure -- and I know it's still an early phase -- but that structuring, it could come from two different sources of capital, one for material and one for EMP, or one source.

There is options there.

That is correct, yes.

And incidentally, it could be for the whole Huron, or we could break it up into pieces, either around Midstream the way I just described, or something that followed more natural geographic boundaries.

So we are open-minded.

And seriously -- and I know I've said this before on calls; maybe people think I've been sarcastic -- but if there are good ideas that folks have, we are happy to hear them.

We know it is going to take a creative solution, and we know that we don't have a monopoly on those.

Thanks.

And then my second question is, we saw that you guys had permitted a couple of wells in Guernsey County in Ohio, and I'm assuming those -- they look like they're Utica permits.

Can you talk about acreage position there and plans for pursuing drilling where those permits are?

Yes, Becca, this is Steve.

You are right; we did permit a couple of wells.

I think one is permitted; one is permit-applied.

We hope to drill one or two test wells in the Utica this year.

We have, at the current time, an immaterial amount of acreage in Utica.

Our strategy is to drill one or two test wells, see whether we like the play or not; and if we do, at that point, we would consider whether we want to build an acreage position in it.

So right now, it's fairly immaterial.

And our next question is from Christine Cho of Barclays.

Can you remind us how quickly you expect to ramp up to the 120 million a day at MarkWest's plant when it is up and running?

Gee, Randy, I don't know.

You could almost measure in minutes probably.

Okay -- so immediately?

Once the plant is -- it's not just a matter of the plant being turned in line, they then have to -- just normally, as you would with any plant, they're going to have to run through a variety of tests.

So it's not as if the volume would immediately go to capacity on day one.

But if you put aside plant issues, I think we would probably be ready to flow.

I think realistically, it is probably over a couple months to get those wells in line going to the play.

But it is, in the scheme of things, very quickly.

Okay.

And then you talked about possible expansions with MarkWest.

Do you have a size?

I know you said timing is still being worked out.

Well as David said in his comments, were looking at 100 million of incremental capacity above our 120 million.

Okay, and then when I look at the map and the table detailing how many acres you have within each type curve in your analyst presentation, you guys are drilling most of your wells by the border of southwest PA and West Virginia, where it is a mix of wet and dry.

And I realize that only 35% of your acreage overall is in the wet part, but how should we think about the pace that you drill up the wet acreage there that might be lower EURs, but may or may not be better economics, depending on where liquids prices are?

Do you just primarily focus on the nine [eet] wells that are probably dryer and have higher initial rates and better production declines?

Or what dislocation does there have to be between NGLs and natural gas that make you think that net present value is better in some of the wetter wells?

Right now for us, the economics between the Doddridge County wet area we are focused on and the Greene County dry area are pretty equivalent.

So we really are drilling for economics, but we obviously have to factor in capacity.

So if we can't flow the gas, the economics generally don't look too good.

But right now, they're fairly equivalent at current gas price, liquids price spreads.

So if that changes, then we may want to focus on one area more than the other.

Although there are also operational constraints -- how many wells we can put in one small area.

But right now, it is pretty equivalent.

Okay.

So if everything stays the same, you would say it is going to be dictated by infrastructure pretty much, it sounds like?

Well infrastructure and land issues.

Sometimes if you think you have a chance to fill in some land positions that would allow you to either have put more wells on a pad or have longer laterals, that can obviously influence some of your timing too, or influence your prioritization.

Okay.

And then, you guys have talked about how some EQT shareholders have voiced concerns that Equitrans was placed too cheaply into the MLP.

And recognizing that there is a need for balance between doing what is right for EQM and EQT shareholders, how are you thinking about the potential expansion opportunity at Sunrise that can potentially double your initial capacity at really low cost?

Should we think Sunrise gets dropped in at more of a typical multiple, and maybe we will use Big Sandy as a benchmark and EQM getting the benefit from that organic opportunity?

Or will EQM have to pay up front with a higher multiples?

Well, I don't believe any of us -- certainly I have not -- but I don't believe any of us have commented that we have gotten complaints about the pricing of EQM.

To the extent we have commented on it, I think I would characterize it more as recognizing that there is a trade-off between what is in EQT's best near-term interest and what is in EQM's best near-term interest.

Though our view has been that a fair price is in the long-term best interest of both entities, and that is really what we take into account.

That does mean, to your specific question about the Sunrise expansion -- and incidentally, this wouldn't just be Sunrise.

This will apply to any number of candidates for sales from EQT to EQM.

To what extent, if there is further investments to be made, do we make the investments of EQT and sell into EQM at probably a lower multiple on a higher cash flow, versus selling in before making the investment at a higher multiple off a lower cash flow?

And I think it is fair to say that, that is going to be done on a case-by-case basis.

But we certainly have -- there is no interest at the EQT level in selling assets to EQM on the cheap.

And we also don't think that it is in the long-term best interest of EQT, given our position at EQM, to somehow try to get an overly inflated price, either.

So it will be a balance, and it will be a trade-off.

And it is going to be particularly difficult, as you point out, to find that when there is expansion opportunities.

Right.

And then lastly, just an accounting question -- how much of the $7 million decrease in storage and marketing at Midstream was attributable to unrealized losses on derivatives and inventory?

Do you guys have that on hand?

Is a little more than half of it, I believe.

A little more than half?

And that is a non-cash thing that unwinds over time.

It is an oddity in the accounting.

A little more than half of it was that.

Our next question is from Michael Hall of Baird.

I guess a couple just real quick ones on my end; a lot have been answered.

First on the Huron capital -- would you characterize what you are considering as more temporary in terms of the source of capital, or something more permanent, like another MLP?

I would say what would prefer to do is to find something that would be a more persistent source of capital.

But that is only because we have that 7, almost 8 Tcf of 3P reserves.

It's that logic.

And the nature of the development there is, it is just going to work a lot better if once we get reenergized there and remobilized, if we are able to stick with it for some period of time.

So if temporary meant a year, it is probably not all that interesting.

It would be more interesting if we thought that it had the potential to go on and on.

But as far as that goes, I'm not sure that I would comment on any specific vehicle that we might use, other than it would be better if we thought that it gave us access to capital over a longer period of time, as opposed to the capital of it only supports the development for the short period of time.

Okay, that's helpful.

It makes sense.

And then, I guess, in some other related thinking, as it relates to any potential Midstream needs down the road around that program -- is that something then that EQM could feed off of or feed into as well?

Absolutely.

That's -- relating back to the prior question about some of the trade-offs, at this point, it is probably fair to say that for the most part, the EQT Huron Midstream position is a little less interesting from the perspective of a sale to EQM than it would be if we were to re-energize the development there; and you had at least stable, and maybe even somewhat growing volumes.

So yes, actually both things are true.

It is not just that EQM could be an interesting source of capital for that.

It is that it is actually a more interesting source of capital if it is paired with growth.

Okay that makes sense.

And I guess the only other one -- really two more.

One is the outlook you provided -- does that include capital from drop downs (inaudible) and transactions (inaudible)?

I'm sorry, which outlook, which part of the outlook are you referring to?

The 30%-plus both for EQT into '13?

No, we would say that, that doesn't really require any form of external capital.

But that is really because the lag is such that most of the growth that we anticipate in 2013 is going to result from wells that will have been already -- for which most of the capital will have been spent by the end of 2012.

Got it.

So (inaudible) in 13 (inaudible) was moving between --

Yes, most of the capital that -- the reason for continuing to push for external capital like from EQM in 2013 is primarily to facilitate growth in 2014 and 2015.

Obviously, we're not talking about growth rates, but to continue to facilitate growth in the out years.

Okay.

And then, I guess -- do you have any updates on average initial production rates that you have seen during the last quarter on your Marcellus program?

And maybe any additional color around how existing rates are stacking up versus your EUR type curves?

And specifically relating also to the new well -- or new completion geometry that you have talked about in the past?

Michael, this is Steve.

The only thing I really have to offer -- I don't have specifics on average IPs.

But I will say we continue to be very comfortable with the type curve we have provided.

We see no reason to adjust those.

I will say, since we've focused a lot of our drilling in the Greene County area, that is one of the best areas for the reduced cluster spacing frac technique.

So we are, on average, doing a lot more stages per well.

So, for example, in the fourth quarter, for those wells I mentioned that we will be turning in line, those will have 28.5 stages per well on average.

And the average stage length is 192 feet, so the modified completion technique has 150-foot stages.

Our base design has 300-foot stages.

So you can tell from that, that there's a high percentage of wells with the new technique.

Congrats on a solid update.

Our next question is from Holly Stewart of Howard Weil.

Just really one bigger-picture question, I guess for Dave.

And certainly not trying to front-run the December budget announcement, but --.

Those are the only kind of questions my colleagues let me answer to are the big-picture questions.

(laughter)

I know.

You've talked about in the --

You didn't have to agree so readily.

(laughter)

You've talked about in the past the cash flow CapEx deficit being filled with these asset sales.

And given that you're just kicking off the process here, how should we think about the budget in December?

Should we think about it at a lower level, given that you are very early in the process?

Or just trying to -- bigger picture, trying to get a sense for how to think about it.

Well I don't want to make any commitments.

As I've said before, I don't want to make any news on this call.

But it isn't really so much for legal reasons.

It is because the Board hasn't approved a budget yet.

But the construct is that we would like to routinely -- and this is part of the idea with EQM -- is we would like to be able to continue to routinely invest $300 million, $400 million, something like that or so, more than what our internally generated cash flow would allow.

But that is just because we think that is what is optimal over time from the perspective of monetizing our asset and opportunity sets.

So in that regard, I wouldn't say that a thought process has really changed versus the thought process that went into the 2012 numbers or the 2011 numbers.

Where it comes out specifically as far as the numbers is really where it is hard to go to.

But I don't see that there is a particular need, given the cash capital we have already raised, that you should be assuming that we would only be able to spend based on operating cash flow in 2013.

Because we have already been raising money from other sources.

So how much do we have on the balance sheet now as far as cash?

$639 million, and you'll see that in the Q later today.

So we have been trying to stay a year or so, year or two ahead with that, and I would say that is our mindset coming into the 2013 budget.

Again, without trying to preempt the Board's authority in deciding what the capital budget should be.

Is that at all helpful?

Or is that a politician's answer?

No, it is helpful.

I was just trying to get a sense if we saw a fairly large number, is that because there is plans to do something?

Or just trying to really get a sense on if you guys at all felt held up by this process?

No, I think that is just the -- I think where we are -- and actually it was one of our investors who used this terminology, but we have a variety of levers that we have to pull to be able to generate additional capital.

And we think it is the right thing to do, to move -- it is portfolio management, if you will, to move money from the opportunities that aren't as interesting to us or that fall further down our priority list.

And from my perspective -- and I certainly hope this is the way people at the Company look at it -- is that is just an ongoing process.

That is not just a 2012 or 2013 process; we are going to be doing that for some period of time.

We are going to be looking at which assets would be best.

We know we are going to make the money by selling -- by monetizing molecules, and so the extent that we are selling them one molecule at a time versus in bunches is really what we have to decide.

And I think that is the issue that we are going to be facing strategically for a period of time, for more than a couple of years probably.

Next we have a follow-question from Michael Hall of Baird.

I just wanted to quickly hit on a topic I brought up last quarter, and I don't know if there's any updated thoughts.

But if you had any updated color, it would be appreciated around thoughts on the utility distribution business, and as it relates to that as a source of capital down the road?

Any updated thoughts around that?

Mike, I have been informed that we have run out of time because of the upcoming EQM.

No -- our thought process -- actually we probably have run out of time, but our thought process is the same.

It's -- strategically, there is nothing that has changed.

We do have a list of things that we're working through, as you have heard on a number of the calls.

But that is one where I definitely don't have any news that I wish to make on today's call.

But our strategic perspectives have not changed.

And this concludes our question-and-answer session.

I would like to turn the conference back over to Patrick Kane for any closing remarks.

Thank you, Laura.

I would like to just thank everybody for participating, and we'll look forward to next quarter.

Thank you.

The conference is now concluded.

Thank you for attending today's presentation.

You may now disconnect.