EQT Corp (EQT) 2011 Q3 法說會逐字稿

Good morning and welcome to the EQT third quarter 2011 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.

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, sir.

Thank you, Denise.

Good morning, everyone, and thank you for participating in EQT Corp's third quarter 2011 conference call.

With me today are -- Dave Porges, President and CEO; Phil Conti, Senior Vice President and CFO; Randy Crawford, Senior Vice President and President of Midstream Distribution and Commercial; and Steve Schlotterbeck, Senior Vice President and President of Exploration Production.

In just a moment, Phil will summarize our operational and financial results for the third quarter, which we released this morning.

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

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

The call will be available for replay for a 7 day period beginning at 1.30 PM Eastern time today.

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

You will need a confirmation code, which is 447032.

The call will also be replayed for 7 days on our website.

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

You can find these factors that could cause the Company's results to differ materially from these forward-looking statements listed in today's press release under risk factors in the Company's Form 10-K for the year ending December 31, 2010, which was filed with the SEC, and updated in our subsequent Form 10-Qs, which are also filed with the SEC.

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

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

So with that, I'll turn the call over to Phil Conti.

Thanks, Pat, and good morning, everyone.

As you read in the press release this morning, EQT announced third quarter 2011 earnings of $1.19 per diluted share.

Adjusting for the gain on the sale of the Big Sandy pipeline, which closed as expected on July 1, EPS was $0.45, or an 88% increase over EPS in the third quarter of 2010.

The Big Sandy transaction resulted in a $111 million after-tax gain.

Operating cash flow excluding the impact of the Big Sandy pipeline sale increased to $190 million for the 2011 quarter, or by 44% compared to the same quarter last year.

The increase in cash flow comes as the result of another outstanding operational quarter, including record production, and Midstream volumes, and continued low per unit operating costs.

As a result of the Big Sandy gain, the gain on the sale of our Langley natural gas processing complex earlier in the year and our growth in volumes and organic operating income, we have become subject to the alternative minimum tax or AMT in 2011 and because of that, we have started to pay some cash taxes again in 2011, about $36 million through the first three quarters.

Next year, assuming no additional transactions, we would expect to be back to the deferring the vast majority of our book income taxes.

Other than that, operating results this quarter are pretty straightforward and therefore my comments will be relatively brief.

EQT Production operating results.

At EQT Production, sales volumes continue to grow at a record pace.

The growth rate in the recently completed quarter was 51% over the third quarter of 2010.

That growth rate was driven by sales from our Marcellus play, which contributed approximately 44% of the volumes in the quarter, up from only 19% in the quarter a year ago.

Gas prices were lower in the quarter, consistent with lower NYMEX prices.

At the corporate level, EQT received $5.25 per Mcfe compared to $5.52 per Mcfe received last year.

However, the realized price at EQT Production was $4.02 per Mcfe compared to $3.81 per Mcfe last year.

EQT Production's realized price was higher in an overall lower price environment, due to the increase in the production mix from the Marcellus.

As we have discussed on recent calls, the gathering rate Midstream charges from Marcellus production is approximately 0.5 of the gathering rate for Huron.

That lower rate reflects the significantly lower costs to gather Marcellus gas.

Produced liquid mainly from our liquids-rich Huron accounted for 6% of the volumes and about 21% of the un-hedged revenues in the quarter.

As a reminder, we do not include ethane in this calculation, as it is currently mostly sold as methane.

Total operating expenses at production were higher quarter-over-quarter as a result of higher DD&A, LOE, and production taxes.

However, unit LOE was flat with last year and unit production taxes were slightly higher as a result of recent property tax increases in the state of Virginia.

We've also seen an increase in service costs, as we finalize our contracts for next year.

As a result, we are increasing our cost per Marcellus well estimate from $6 million per well to $6.7 million per well.

This cost per well assumes 5,300-foot of lateral pay and a standard frac design.

Moving on to the Midstream results in the third quarter, operating income at Midstream was up 16%, even with the loss of income from the Big Sandy sale.

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

Gathering net revenues increased by $9.3 million, as gathering volumes increased by 35%, while the average gathering rate declined by 13%, again, due to the increase in Marcellus gathered volumes.

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

Specifically, the increase in Marcellus volumes, where we experienced significant Midstream economies of scale drove a 26% decrease in Midstream's unit gathering and transmissions costs this quarter.

Transmission net revenues totaled $18.3 million, as Equitrans Marcellus expansion revenues were $7.3 million higher, nearly offsetting the $8.5 million in (inaudible) Big Sandy pipeline revenues.

Storage, marketing, and other net revenues were down $6.6 million in the third quarter.

Those results include a $4.4 million reduction in processing fees, as we did not own the Langley natural gas complex during the third quarter of 2011, while we owned it for the full third quarter last year.

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 continue to estimate that full year 2011 net revenues in storage, marketing, and other will total approximately $50 million.

Operating expenses at Midstream were $4.3 million lower quarter-over-quarter, at $52.3 million.

Excluding the impacts of the sales of the Langley processing complex and the Big Sandy pipeline, operating expenses were up by $5.2 million, consistent with our growth in the Midstream business.

Just a quick note on the Big Sandy pipeline sale, as previously discussed, in July, we closed the $390 million sale of (inaudible) Big Sandy pipeline.

We did record a pretax gain of approximately $180 million in the third quarter.

The Big Sandy pipeline sale did also impact our unit revenue realization.

Transportation and processing revenue to EQT Midstream went down by $0.14 per Mcfe, while third party gathering, processing, and transportation expense increased by $0.14 per Mcfe in the third quarter.

And then finally, just a bit of guidance, today we reiterated our production sales volume forecast for full year 2011 to between 190 Bcfe and 195 Bcfe, and we are likely to be in the high end of that range.

We still expect that 2012 volumes will exceed 250 Bcfe and we'll have more clarity on the 2012 volume guidance after we establish our capital budget in December.

As a result of the higher volume forecast, we are increasing our operating cash flow estimate for 2011 to approximately $875 million.

As you know, we also have raised approximately $620 million in pretax proceeds from the sale of Langley and Big Sandy, or approximately $572 million after 2011 estimated cash tax payments.

So as a result, we have funded nearly all of our year-to-date CapEx with the proceeds from those sales and operating cash flow.

We closed the quarter with no outstanding balance on our $1.5 billion credit facility.

So along with the 2011 cash flow forecast, which by the way is more than 75% higher than in 2009, the last time we issued debt, we remain in a great position from both a balance sheet and a liquidity standpoint.

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

Thank you, Phil.

Our team put up another great quarter.

50% growth in sales of produced natural gas versus last year is quite a feat.

My congratulations to our production team, our Midstream team, and our commercial team for producing these volumes, getting them to market, and selling them.

These growth rates we've experienced lately also place strains on various of our functional groups, everything from procurement to human resources and IT on the front end to accounting, land administration and yes, legal as we move through the process of getting this gas to market and selling it.

They are performing admirably and I am proud to be associated with this Company as we execute against this growth strategy.

Since Phil reviewed the quarter, I will dive right into an update on our Midstream structure review.

The only topic of my prepared remarks.

Last quarter, I laid out a framework for our Midstream strategy in which we discussed three main options.

The first was to sell our Midstream assets and outsource our Midstream needs.

The second was to stay with the current model of building needed Midstream systems and occasionally selling seasoned assets most likely to MLPs.

We call this build-fill-sell, and it did work this year.

A third option was to create our own MLP with or without a partner.

Since the last call, we have been more clearly defining the Midstream growth opportunity built around our extensive gathering and transmission assets in the Marcellus region.

As a result of this and further study of our alternatives, we are currently focusing most of our efforts on two alternatives.

We have concluded that the operational benefits of controlling the timing, location, and size of incremental gathering and Equitrans expansions provide value to EQT Corporation beyond the direct returns made from these investments.

Therefore, we do not currently plan to exit the Midstream business.

There is a price for anything.

Still, as must be clear from listening to the commentary from all of us who are large Marcellus producers, these growth rates put a lot of stress on infrastructure.

While it is not possible to eliminate these bottlenecks given such growth, we are convinced that the best way for us to mitigate the risks includes maintaining capabilities and at least a certain amount of control in building our infrastructure.

Of course even with these capabilities, one needs commercial skills involved in dealing with long line pipes and in marketing, and this is the reason that we have been securing firm transport, as one example for future pipeline projects.

However, we believe we also benefit from maintaining our ability to design, construct, and operate pipelines in compressor stations.

Our Midstream and upstream teams work closely together to assure that the take-away capacity matches the pace of development and we would like to maintain that strength.

As our development activities bring us into areas of these plays in which acreage is more fragmented, we will clearly be contracting with other Midstream firms to gather and compress some of our produced volumes, so we are not saying that we must control all of our own Midstream.

Rather, we are saying that we want the ability to build out our own infrastructure to be one of the alternatives available to us.

This reality tends to push an outright sale down our list, at least during the near to medium term.

Now, the primary reason for not pursuing one of the Midstream strategies that involves more control and coordination would be the availability of capital.

We cannot have a Midstream -- a medium term plan that diverts material amounts of capital from reserve development to infrastructure.

In short, we still need other people's money for this strategy to work.

So we examine the other alternatives to see how well they meet those needs.

As we work through the implications of our build-fill-sell approach, which does provide for control and coordination during the critical build out phase, and does utilize other people's money once individual projects are built, we have also concluded that this approach is not likely to be ideal for development in the Marcellus region.

It may work for certain systems, but there appear to be too many circumstances in which somewhat discreet gathering systems interact with each other to a sufficient extent that it would be problematical to have separate owners.

This is clearly a judgment call, but as we see things now, it seems less than ideal to, in the words of one of our advisors, Swiss cheese our Midstream business in these plays.

Realistically, we wish to keep our future structural alternatives open and this also does less well on that score.

So build-fill-sell may well be employed again on occasion, but it is not currently our preferred approach for Marcellus Midstream.

At this point, you must be wondering how we have two options, since we started with three and have downgraded the likelihood of two of them.

It's the new math.

More seriously, since the last call, we have devoted more time to the third alternative, which we described as an MLP and/or a partner.

We've realized that this was really a tactical alternative and the strategic issue is that we are sufficiently persuaded as to the benefit of some control and as to the economic proposition of Midstream investment in this region that we should see how we can pursue it, even though that must mean using some form of other people's money.

MLPs and JVs are both forms of OPM and of course JVs themselves can take many forms.

So our current efforts are focused on working through the various separate entity alternatives to see which best meets our needs.

We still wish to reach a conclusion around year end, but the real timing driver is to implement something in 2012 so that we can pursue some of these Midstream opportunities without diverting capital from upstream development.

It may be helpful for you to understand our thought process a bit as we continue this analysis.

One issue that has led us in this direction is a desire for flexibility and timing monetizations of assets.

This flexibility is beneficial from both a cash flow perspective and in tax management, and it seems easier to accomplish if we use a related, but separate entity, rather than being solely dependent upon the asset sale market as with build-fill-sell.

A second issue relates to the interconnectivity of these Marcellus area systems.

Monetizing multiple assets using a single related entity helps alleviate concerns about this.

Eventually related assets would end up in the same entity, though there may be a transition period when some part of an asset has been monetized, but other parts have not.

This is also difficult to achieve in build-fill-sell without sacrificing value or operational efficiency.

A third issue is that one of the concerns with committing to a separate entity is their need for visible growth opportunities.

However, as we look at our existing assets and the assets necessary to support the rate of development that we expect, there seem to be visible growth opportunities for quite sometime.

Now, increasingly, these opportunities will involve new systems that are not solely or perhaps even largely dependent upon EQTs produced volumes, given the fragmented nature of the acreage positions.

However, that will merely be one of the realities that we will need to factor into our decision on which tactic to employ.

We do not wish to overstate how much we know about the tactics we wish to employ.

We have certainly started the process of getting smarter about MLPs, and we have had some discussions with potentially credible JV partners.

Still, there is more for us to learn about the various alternatives, and we are doing what we can to better define the benefits and the risks of those alternatives.

Obviously, some of the most significant trade-offs involve cost of capital versus certainty of capital, and control over the issues that matter most to us versus the ability to augment our skill set to best pursue the available opportunities.

Accordingly, we are doing our best to work through the pros and cons of the various tactics.

Earlier this year, we communicated a longer-term goal to achieve organic volumetric and cash flow growth north of 30% per annum in production over the 5-year period from 2011 through 2015 and associated cash flow growth in the Midstream, by investing a little more than $1 billion in external capital from 2011 through 2013, without tapping the equity market.

Our asset sales to date and use of our available debt capacity should allow us to meet that goal rather comfortably.

Still, these growth rates and funding needs are based on the assumption of building the needed Midstream using EQT capital.

When we calibrate the proceeds of alternative financing for Midstream, we expect to be in a position to increase these growth forecasts to reflect the acceleration of our Marcellus development.

Thank you in advance for your patience and continued support.

With that, I'll turn the call back over to Pat.

This concludes the comments portion of the call.

Denise, could we please open the call for questions.

(Operator Instructions) Neal Dingmann, SunTrust.

Say, just a bit of color on maybe if we could drill down a little bit on, you mentioned that your increase in some of the Marcellus costs just a bit to basically extend the laterals, et cetera.

Could you give us an idea of kind of those costs, breakdown, and then on the Marcellus plans for next year, will most all those be with the longer laterals, the additional frac stages, et cetera?

Neil, this is Steve.

Specifically on the cost increases, I think what we're seeing mostly is lot of our contracts that we've put in place 1 year or 2 years ago, I think we were able to get at below market prices.

Some of those are rolling off and we're currently in the process now of putting in place new contracts with our suppliers.

And we're seeing some cost increases.

The biggest one we're seeing is in our pumping services, which we're looking at about a 14% increase over what we've been seeing.

Most of the other services are a little bit less than that, but still look like they are going to be an increase.

That's what's driving the cost increase for us.

One thing I do want to stress about the costs that we quote for our wells, the costs that we quote include the cost to build the locations, to drill and complete the wells obviously, as well as to install the production facilities and well lines.

So that cost is inclusive of all the onsite activity that we do.

So that's pretty much what's driving it.

Okay, and Steve are these the type of wells, you mentioned, I think on a prior call about doing a bit more of -- I guess the new technique for lack of better word, that you were going to start doing on a number of these wells, is that the case for most of these more expensive wells?

Well, no, the $6.7 million for 5,300-foot lateral is for our standard frac designs.

Not with the new frac design.

I think as we put our capital budget together in December, we'll be -- at that point, we'll disclose how many of the new frac design versus the standard we're likely to do next year.

Okay, and then just last question, maybe one for David, just you gave good commentary on sort of the Midstream strategic alternatives around that.

Again, it does sound like I guess in your opinion, David, has timing, has or has not changed I guess around that and it's still just as probable that something could get done?

Oh, the timing has not changed.

The only thing I added on timing was the urgency for us in making a decision is to make sure that we're able to implement by the time we get into next year.

And with these things, with all of them, you have to make a decision and then there's a certain amount of time involved with implementing them and actually getting, from our perspective, of course implementing them means getting the cash in the door.

Scott Hanold, RBC Capital Markets.

You gave a lot of good color on the Midstream options there.

Just so I understand this, right now you've got two leading options.

One, you're obviously -- potentially looking for a partner to help you develop that, but you can still control and own a certain percent.

And was -- the other options still -- do you still leave the door open for potentially looking at an EQT owned MLP to utilize this --

Absolutely.

Those are the two that we're focused on.

Okay, and if you were to go sort of the EQT/MLP route, how much control do you really need over that?

Would you be a 50% owner?

Or how much do you think you would need to maintain that control?

Well, you folks can probably look at existing circumstances where companies have MLPs and JVs and reach a reasonable conclusion about how those things work.

And I wouldn't say that anything we would do in that type of area would be any different from what you'd normally observe.

Okay, okay.

Fair enough.

And then moving on to the Marcellus wells that you're drilling, when you talked last period about the cluster fracs, I think you indicated that you need a little bit more time to the end of the year to really get a full evaluation of this.

I think your first ones now are probably just about 1 year old.

Can you give us sort of an update on how those are performing relative to sort of your standard frac type wells?

Yes, Scott.

I can't give you much additional data, because we're still gathering data and studying it, and as I've said all along, it's going to take quite sometime to be definitive on this.

I think as we mentioned before, we generally are seeing higher initial rates.

The decline curves we've seen so far for the most part are encouraging and along the lines of what we expected to see.

Maybe the one bit of color I can provide at this point is, and it's still even preliminary for this, but our current thinking is, it's likely that we're going to find areas where the new technique is clearly beneficial from an economic standpoint.

I think we're going to find some areas where it just doesn't meet our economic thresholds.

Certainly at current prices, and obviously that threshold moves as gas prices move.

And then I think there's going to be some areas where it's going to take quite a bit more time for us to really define where it falls on the economic spectrum.

That's sort of our current thinking on that.

But I really can't give you any more data right now.

Yes, because I think last time you said they were performing 60% better initially or something to that effect.

Still seeing that kind of rate?

Yes, that's correct.

Okay, and then lastly, when I look at the number of wells that you've drilled and have not yet completed, the backlog is built a little bit from the prior quarters.

Is that just due to higher levels of activity?

Are there some constraints on frac crews in the basin?

And if you could remind me, how many frac crews do you have right now and is that capable of keeping up your sort of 6-rig program?

Yes, actually, I think our backlog in terms of frac stages has been pretty level from prior quarter to this quarter.

So we're not seeing much move.

And I think that's sort of, that's what we expect to see.

It's pretty lumpy with the multiple well pads we're drilling.

We currently have two frac crews working currently, and that is sufficient for us to be able to keep up with our needs for now.

We do have plans to bring a third crew in probably mid next year at some point when we need them.

But we are not building a backlog for lack of pumping services.

Amir Arif, Stifel Nicolaus.

Just a question on the 2012.

I know you haven't firmed up your budget, but you're talking about, what is it, 250 Bcf.

Just curious, does that assume similar number of wells, about 100 Marcellus wells next year?

It would be -- the issue that we've got in providing updated guidance, if you will on third quarter, is that our normal approach, which we're sticking with this year is to go to our Board for a capital budget in early December.

So at this point when we're really just talking about the stuff we've looked at, the reason we haven't really given an update is we don't really have a budget yet.

So I think it's a little pre -- I mean Steve, you can give I guess a rough idea of what that would involve as far as how many wells we drill, but do bear in mind that in the Marcellus, there's quite a lag involved.

The 2012 budget, capital budget has a rather muted effect on 2012 volumes.

But I'm happy for you to comment more specifically.

Well, I think that's exactly right is the thing to keep in mind with the, especially with the timing related to the multi-well pads we drill, 2012 volumes will be driven probably more so by 2011 drilling than it will be by 2012 drilling.

So you have to be careful about connecting the two, too closely.

Okay.

Sounds good.

And then the -- just on the new frac -- that you are doing, I know just you mentioned that IP rates are higher.

You're not at a position to sort of quantify it yet.

Will you be at position year end to update the EURs on the new approach?

I'm not sure I can -- yes -- but again, our target was to make sure that by the time we're actually making decisions on the budget that we would have a -- we've reached a firmer position on that.

And not trying to put you off, but that's, again, that's something that we spend most of November pulling that stuff together.

So that's -- from our perspective, we're still on that same schedule.

Okay, and then so are the -- so the initial rates are 50% to 60% higher.

Can you tell us 6 to 12 months out how much higher the rates are on the new wells versus the old type curve?

I think we're going, we're going to pass on that for now, mostly because we don't have sufficient number of wells with 12 months worth of production yet.

So most of the data we're working with is still pretty early in the well's life.

So I think we're going to not comment on that right now.

Okay, and then could you just maybe let us know, are all of these wells in Greene County, like in the southernmost, southeast portion?

Or is this spread across your acreage in terms of the percentage improvements you're seeing?

Well, they are not all in Greene County.

Quite a few have been in Greene County.

Another area we've done quite a few is in our Doddridge County area, and we have several other wells spread around beyond those two areas, so --

Hsulin Peng, Robert Baird.

Dave, I just want to make sure that I understand the option that's on the table.

One, you are saying it's a JV structure where you work with the partner and most likely a financial partner, and the second one is your own MLP, correct?

Well, I didn't say a financial partner, and actually, I also want to make clear that those are not necessarily distinct approaches.

All right.

You could conceivably combine a joint venture on MLP.

The real thing that we focused on is that we do want to pursue this opportunity.

We want to reach a specific decision on it quickly so that we can implement, meaning not just close, but get cash in the door by mid-2012 or thereabouts, which means that we do need to be reaching closure on it pretty quick.

And frankly in laying out some of the stuff that we're interested in, that hopefully gives the market a better idea of the kinds of characteristics that we're looking for as we, as we look through this, which is a certain amount of control.

But we also need low cost of capital.

That's a big -- it's not just availability of capital that we like through a separate entity.

It's lower cost of capital.

Right.

I mean, I understand the objective, so I'm sorry, can you just repeat what are the options on the table then?

Well, separate entity, and at this point, all we know about the possibilities of separate entities as we look around are -- and I'm talking about specifically Midstream, are joint ventures and MLPs.

So those, when we focus on just studying these, those are the things that we're focused on.

But we were aware that there's other -- there's clever folks out there in the marketplace and if one of them hears about the objectives that we have and says we've got a way to give you a lot of inexpensive money and meet your objectives in some other way, then that's fine for us, too.

Okay.

But the overall objective of the, of the evaluation, you are still hoping to make a decision by year end and with some implementation planned sometime in 2012, is in that correct?

Yes, the only emphasis that I was putting kind of new emphasis on timing is that we have to make a decision around year end so that we can actually start getting money in the door to pursue some of this and to make sure that we're not diverting money as we have been frankly, from development into Midstream.

So it isn't just a magic number on making a decision.

I mean, around here, the real goal is get the cash in the door.

We need to get the cash in the door.

And the only way that's going to happen is to make a decision quickly.

Right.

Okay.

So this is not different from what you have previously outlined, really, it's the same?

It's -- I mean, it's basically the same.

It's just that we're recognizing that it's possible that as you look at MLP or joint ventures, they could either be distinct or they could be together.

What we really talked about before, the two changes we made is, we intended to lump MLP and JV together before and now we're saying they could be together or could be separable.

And the other thing is that we've said the other two alternatives that we've looked at, for instance, particularly build-fill-sell, which --

Right, those two are out.

That doesn't look to be as suitable for what we're trying to accomplish as a separate entity would be.

Okay, and just to clarify--

So as we dive down into one alternative, you wind up seeing the different aspects of that alternative, if you will.

Right, and really to maintain -- given that control is what you are looking for, I mean, as far as your own -- as long as you have the general partner in a MLP structure, that is control.

Yes, I agree.

Correct?

Yes.

Okay, got it.

And the second question on this additional well cost --

Well, it's a sufficient amount of control.

I don't want to presume -- there's LP unit holders have rights, of course, but it's enough control for us.

Actually that's the only reason I kind of stopped you as far as just the financial partner.

I could easily imagine working with a strategic partner where we had a sufficient amount of control over the stuff that matters to us, which is the timing, location, and size of the facilities.

So, yes, it's certainly conceivable that we would operate, we would be with a strategic who would say we'll bend towards your control concerns sufficiently to meet EQTs needs.

Okay.

But in the end, of course, then it's what the best value.

It's very hard to speculate what's the best value.

At the time we announce a decision, you can be confident that, that's what we think is the best value for us all-in.

Okay, okay and that time is still year end, like you said.

Soon.

Yes, I'd say soon.

Okay, and then my second set of questions regarding the service costs, I know you mentioned that it was because some of your current cost is well market but can you just be more specific in terms of which component in service cost is driving the -- is it cash or comp or other key component is driving the cost?

Yes, the big mover is the pumping services, which is the biggest costs we have in drilling and completing a well, it is also the area that's seeing the biggest percentage cost increase.

So it's really driven by the fracing costs.

Okay, and can you talk about what this does to your economics?

Well, obviously it has a negative impact on our economics.

We'll be updating our slides and our presentation after the call.

Okay.

I know you'll -- I'm just trying to get a magnitude in terms of the IR, what that was, but I can wait for the slides.

Joe Allman, JPMorgan.

Dave, just to clarify again on the restructuring here, so in terms of the cash in the door that you speak of, you don't necessarily need cash in the door today.

I think if I understand correctly, you need cash in the door on an ongoing basis.

Yes.

Yes, we would rather have cash in the door on an ongoing basis, but if somebody at JPMorgan just wants to write us a really big check and then we have to warehouse it, I'm sure we can make that work, too.

It won't be me, I guarantee that.

[laughter] So I guess in terms of -- so the monetization that you -- the cash in the door that you would get upfront most likely would be based on the existing Midstream assets, is that correct?

Or were you thinking that okay --

Yes, that's true.

That's true, it would most likely be in the existing Midstream assets.

It's just that from what we observe, these are just observations now, when you have MLPs, you have periodic drop downs and you get cash from that.

In some of the joint venture approaches, it seems like you could do the same thing, or there are circumstances where somebody comes in low and winds up buying their way up.

So you don't actually get cash in the door subsequently, but you no longer invest your own cash in the Midstream.

Right.

So effectively it's freeing up cash.

Right.

But it's because perhaps the construction's going on inside the entity.

Got you.

So it seems to me, are you leaning more towards a JV at this point than a MLP?

Because it seems to me that based on what you're describing, that's really what you need.

If I'm leading you to believe that I'm leaning either towards a JV or towards a MLP, I did not mean to.

I am open minded about those.

To me, it's a big deal that we've said it's got to be a separate entity, need to make a decision quick, because we want to be able to close this thing no matter how complex it is and get cash in the door within a matter of months.

Got you, okay.

And you want it to have its own credit facility, et cetera?

I'm sorry?

And you want that entity to have its own credit facility?

I haven't really focused.

I mean, I guess the odds are that, that would be the case, because if it's a separate entity, it probably would.

Okay.

Do you expect to make an announcement by year end?

I expect to make an announcement once we get, once it's the appropriate time to make an announcement.

Mark Caruso, Millennium Partners.

Dave, I don't want to drag it out like it's been dragged out many times here.

But I guess, two clarifications for me, the first is why -- I guess is it crazy to assume that you would probably want to have an idea of what you're doing by the time you get -- formal decisions on the budget for next year?

No, not necessarily, because we're not going to spend money that we don't have.

You're aware, we're not going to spend money we don't have.

So if we have to have contingent stuff in the budget, that is fine.

Would I like to have a decision made sooner rather than later, by the time of the budget?

Sure.

But we've -- we need to go through the process in a kind of combined thoroughness and speed.

Got you.

Then as far as once you've made a decision, MLP or JV by the end of the year, and you want to implement it early in the year, does that cover your thought process around splitting?

Does that sort of effectively do that for you as you're moving that business around?

Or is that --

No, I don't believe so.

What I meant to communicate with that is that, that type of structure would not be inconsistent with that, that we would not want to enter into a transaction that took that off the table.

Got you.

But for the Swiss cheesing thing, the concern was that if you just sell little pieces here and there, a stake of this system and a stake in that system, then you're kind of taking that off the table.

Not only though, have we -- as I mentioned before, we have not made any of those kinds of decisions, but we don't want to implicitly make the decision because of how we go about dealing with Midstream this time around.

We just want to make sure that we are not unwittingly taking such structural alternatives off the table.

And we will be mindful of that.

But you guys -- I think I heard you say earlier you're already in discussions or have had inbound interest from JV partners?

Yes.

Yes, we have.

Okay.

And I wouldn't be shocked if after this call we get more.

John Abbott, Pritchard Capital Partners.

Just really quickly, looking at your guidance for 2011, I was somewhat surprised that you actually didn't raise guidance for the year.

Is there some sort of bottleneck that we should be looking at for tube for the fourth quarter of 2011?

I wouldn't say that there's a specific bottleneck, no.

It just didn't seem like the -- obviously, there's -- these growth rates always do put some stress on Midstream as we mentioned before.

It was more that it just didn't feel like it was an appropriate -- well, it didn't seem like it was that big a deal to take a look at the guidance.

I mean we're getting pretty close to the end of the year.

We gave a range, we basically just kind of tightened it.

Phil Jungwirth, BMO.

Some of the large service companies indicated in their calls that they were seeing pressure on pumping rates in some of the gas basins.

Is that something you're seeing throughout the Marcellus play and the reason you're increasing your well costs is just because you were contracted below market rates, or could you help clarify that?

Well, I mean, all I can really say is I do believe that for the past couple years we have been contracted below market rates and now that those contracts are opening back up, the service companies are trying to move us closer to market, which I think makes perfect sense from their standpoint and we obviously don't like it, but I think that's life in this business.

But I think that -- I don't think there's any more to it than that simple fact.

Okay, and then of the 6 Marcellus rigs that you're currently running, how many are drilling in kind of the 9 Bcf-type curve area verse the Tier 2 and the Tier 3 areas that you've laid out?

I honestly don't know exactly on any given day, but I think pretty close would be 2 or 3 in the Tier 1 and the balance in Tier 3.

I don't think we have any in Tier 2 as I speak today.

Okay.

Are you -- then does it vary by timing of wells actually being brought on production, such as the rigs in the Tier 3 area?

Those wells take a lot longer to be brought on production and there's not as much and most of the production's from Greene County currently?

Could you repeat that question?

I'm not sure I understood it.

I'm just asking if that varies by wells being brought on production?

I'm still not sure I quite understand.

But there's a lot of factors that go into where we drill at any given time.

A lot of it is driven by really two factors, one land.

So we want to drill as many wells from a location as we can to get the economies of the multi-well pad drilling.

So we wait until a pad has got the bulk of its wells ready to go before we move a rig.

So that dictates it a little bit.

And we also strongly prefer to drill where we're going to move the gas immediately.

So targeting our rigs to go to the areas where the capacity is ready to go is a -- is probably the primary dictator of where we put our rigs.

And that changes over time.

So, if you take a snapshot at any given time, we might have a lot of rigs in Tier 1 or we might have most of our rigs in Tiers 2 or 3.

It's what's going to get us the most, the best return for our investment at any given time.

Gil Yang, Bank of America Merrill Lynch.

Just to beat that dead horse a little bit more, the options for the Midstream restructuring, is it out of principle that the build-sell is not viable in other sort of related options, or is it just a matter of the value in the price discussions you're having with potential buyers were not sufficient?

No, I would say it is the main reason that it is difficult, is in the Marcellus region, there is so much in a relationship between these systems typically.

Certainly as we talk about southwestern Pennsylvania and northern West Virginia, that to get the best out of build-fill-sell, you have to be prepared to hold auctions on individual systems one at a time, even if they wind up being related to each other.

And then you wind up with a circumstance where either you're going to sacrifice on price on a, say, a second asset so that you can have the same entity owning a couple of related assets, or you've got the risk of operational inefficiencies because you're dealing with so many different owners.

It would be a lot easier, we've concluded, and frankly the values seemed to be there to just have a separate, a single separate entity.

Okay, and just selling everything, just a one entity was not viable for what reason?

Well, if it's related to us, that's fine.

If it's not related to us, we're going to run into more of the problems that from what we hear a lot of other producers run into, which is Midstream companies operating completely independently typically do not want to build the systems out until they know exactly how much volume's going to fill them.

And they will design those systems so that they can maximize, understandably, maximize returns for themselves.

Right.

So it goes back to the control issue.

Yes, exactly.

But is there a price for that giving up of control that you would have taken?

I think there's a combination.

You would have to have a certain contractual relationship that travels along with the control.

And if you're saying is there a combination of contractual terms and price that would convince us that, that makes sense, absolutely.

Are you anywhere near that, or -- it doesn't sound like you are.

It sounds like --

It's just that, look, the most attractive pricing out there seems to be -- I have not yet seen that doing the whole thing results in a one-time sale that would have a contract actually results in as good an economics as you see in those other alternatives.

And I would hazard a guess that, that's probably the reason that you, generally speaking, seen companies in similar situations to us either enter into joint ventures or enter into, or form MLPs.

And of course once you finish much of the build out, then that stuff doesn't matter anymore.

Josh Silverstein, EnereCap.

Just a last question on the Midstream potential partnership or MLP.

I was curious if it was -- if there were any specific assets or if it was just specific areas that might be targeted for that?

Like would you rather have pipeline or a processing asset into that joint venture versus having it at the C Corp level?

No, I would think that eventually we start, we move towards the bulk of the Marcellus operation Midstream moving towards that separate entity.

Got you, okay.

I was curious also if there were any other potential upstream financing options, whether it would be selling off any of the assets you guys are not putting much capital into whether it would be the Huron or the CBM assets?

We are constantly looking at those things.

Eventually, we're going to have to do more.

I mean, our attitude here, back when we started looking at the processing plant in Big Sandy, a lot of folks talked to us about Midstream and we said, well we're focused on the processing plant in Big Sandy first, then we'll get to that.

That's kind of the attitude that I've got on some of the other stuff you're talking about now.

You're absolutely right, we are going to have to do that, too.

We're doing as much as we think we can handle at any one time to sort through the various alternatives, but absolutely we cannot let opportunities sit there and not take full advantage.

We have to figure out ways to extract more value from others of those assets.

It just happens that the Midstream is the number one priority as we talk here on what October 27.

Got you.

That's helpful.

And then the comments before that you made about being able to take this capital and put it into the upstream business to grow that 30% 5-year growth rate, how much faster do you think that could grow?

Is it potentially 40%-plus, or is that something that's less than that?

I don't know that I want to put a number on it.

I'll just say faster than that.

And look, you want us to be economic.

We're not aiming for, we're not trying to solve for the highest possible growth rate in volumes.

We're aiming for the highest possible shareholder value.

Got it, and then lastly just a bit of a proximity question, but I was curious if you guys have seen some service equipment migrate over to Ohio for the Utica shale and if that's something you think might cause additional service inflation for the Marcellus producers.

Well, I think any additional demand certainly has potential to drive our pricing up.

We haven't seen any issues with that in particular.

I think the crews we have are dedicated to us, so they are not going anywhere.

The rigs we have are under contract and aren't going to leave our service.

So in terms of access to the services, I don't see any problems.

In terms of whether that affects the market for the pricing for those services, obviously the more activity in a neighboring play could have that effect.

Timm Schneider, CitiGroup.

Gil pretty much already asked my question.

I guess just to follow up on that, did you guys, if you can disclose it, get a bid yet on the entire Midstream asset?

We're not going -- actually part of the delicacy, of course, is there's only a certain amount of detail that we would really feel comfortable providing on any of that.

That's why we're focusing on the philosophical questions.

So I would just assume leave it at that.

Okay, thanks.

I hope you can appreciate it.

I'm not trying to be difficult.

It's just -- I don't want to just bleed out one piece of information and then another piece of information.

[Sameer Easnah], Decade Capital.

It's actually Reza Hatefi.

I just wanted to kind of get a couple things clear in that so hopefully by year end, you will have a decision on whether to go the MLP route, the JV route, or a combination thereof.

That's essentially what you said, I think.

And then does that preclude you to consider a split later on afterwards, so maybe sometime later in 2012 or sometime later?

We would not want to do anything that would preclude any reasonable structural alternatives down the road.

So I guess at this point, the reason to go with MLP and/or JV initially rather than the split is for what reason?

You actually get capital.

Got it.

We don't get any capital from a split.

And showing no further questions in the queue, that will conclude our question-and-answer session today.

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

Thank you, Denise.

And thank you all for participating.

That concludes the call.

Have a good day.

The conference has now concluded.

We thank you for attending today's presentation.

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