EQT Corp (EQT) 2010 Q3 法說會逐字稿

Good morning.

Welcome to the EQT Corporation third quarter 2010 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 Pat Kane, Chief Investor Relations Officer.

Sir, the floor is yours.

Thanks, Maureen.

Good morning everyone and thank you for participating in EQT Corp's third quarter 2010 earnings conference call.

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

In just a moment Phil will summarize our financial results for the third quarter 2010, which were released this morning.

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

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

But first I'd like to remind you that today's call may contain forward-looking statements.

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

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

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

Please refer to this morning's press release for important disclosures regarding such measures and the forward-looking statements discussed on today's call.

I'd now like to 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 2010 earnings of $0.24 per diluted share compared to $0.02 per diluted share in the third quarter of 2009.

Operating cash flow also increased by $75 million to $137 million in the third quarter 2010.

These results were driven by another outstanding operational quarter at EQT Production and EQT Midstream.

You should note that both EPS and cash flow in 2009 were impacted by $24.7 million in higher long-term incentive compensation expense.

To get a better sense for our normalized EPS and operating cash flow, adjusting for the reduction in long-term comp by adding $24.7 million to last year's totals, EPS was 71% higher, and operating cash flow was 76% higher than the third quarter 2009.

Leading the way on the operating performance was a 35% increase in sales of produced natural gas at EQT Production, our highest organic growth rate ever compared to the prior year period.

Because of that outstanding performance we have increased our sales guidance for full year 2010 to 134 Bcf, which represents growth of 44% over 2009 sales volume.

Gather volumes and processed liquid volumes at Midstream also increased by 22% and 25% respectively, following the higher volumes of production.

On the down side, as we saw on the table in this morning's release, the EQT average realized natural gas sales price was $5.63 per Mcf in the quarter or about $0.10 lower than we realized in the quarter a year ago.

The drop came as a result of having fewer hedges in place and a slightly lower average hedge price, much of which was offset by higher NYMEX price and higher natural gas liquids prices, and that is important because approximately 10% of our total production is in the form of liquids.

Just to remind you, for segment reporting purposes, of the $5.63 per MCF of revenue realized by EQT Corp, $3.32 per Mcf has been allocated to EQT Production, with the remaining $2.31 per Mcf allocated to EQT Midstream.

Overall absolute cost increase as expected, giving our outstanding continued growth, but on a unit basis, the total cost to produce, gather, process and transport EQT's produced natural gas and NGLs was down about 13%.

I'll go into a bit more detail on all of that as I briefly discuss the results by business unit started with EQT Production.

And there as has been the case for about two years, now the big story continues to be the growth in sales of produced natural gas.

As I mentioned up front, the rate was 35% and was north of 30% for the third straight quarter.

That growth rate was all organic and was driven by sales by Marcellus and Huron Berea horizontal shale wells, which together, contributed 48% of the volumes in the quarter.

Contribution from the Marcellus Shale play alone was growing rapidly and represented nearly 20% of our volumes in this quarter, up from only 2% in the third quarter of 2009.

The average daily sales of produced natural gas was just under 370 million cubic feet per day for the third quarter, and post quarter end in the month of October, we did reach an important milestone of 400 million cubic feet per day for the first time in the Company's history.

Moving on to expenses, total operating expenses at EQT Production were $15 million higher quarter-over-quarter.

Absolute DD&A, SG&A and production taxes were all higher, consistent with the significant production growth.

Exploration expense was $3.6 million lower quarter-over-quarter as we reduced the size of our seismic program compared to last year.

Absolute LOE excluding production taxes was actually $800,000 lower than last year as the timing of the production operational activity tends to be a little bit lumpy throughout the year.

That said, the volume increases have been outpacing the general trend of higher absolute LOE expenses and as you would expect, per unit LOE was lower year-to-date by about 14% compared to the first nine months of 2009.

For your modeling purposes, we are currently estimating fourth quarter LOE to be about $0.22 per Mcf.

Finally, a note on production taxes.

There's been a lot of discussion by the legislators about enacting a severance tax.

Due to a lack of cooperation between the Pennsylvania House and Senate, we do not know exactly how that all will turn out.

However, you should know that our economic analysis for capital budgeting purposes continues to assume a 5% plus $0.054 per Mcf severance tax.

Just a Marcellus well status update quickly.

Last quarter we did provide a breakdown of our spud Marcellus wells in various stages of completion and based on feedback you gave to Pat, that information was informative.

So I will go ahead and update our current status.

EQT has spud a total of 132 horizontal wells in the Marcellus play, 79 wells not yet online, 18 are either currently drilling or have been [potholed] 42 have drilled and awaiting a frac job.

19 have been fracked and are awaiting pipeline hookups.

Another way to look at our progress internally is by frac stages online or in the system for our Marcellus wells.

As of the end of the quarter, 595 frac stages are online, 246 are completed, but not yet online and 789 are planned for well spud but not yet fracked.

Moving on to the Midstream business quickly, operating income here was up 36%, consistent with the overall growth of gathered and processed volumes as well as significantly higher liquid frac spreads, which I mentioned up front were driven by 28% increase in average NGL prices quarter-over-quarter.

In addition to improved prices, processing volumes were also up by about 25%, mainly as a result of higher production volumes from our wet gas Huron Berea play in Kentucky.

Gather volumes increased 22%, again mainly from gathering EQT Production's growing sales volume and combined with higher rates, resulted in a 26% increase in gathering net operating revenues.

On the other hand, the line item storage marketing and other net operating income was flat in the quarter and year-to-date.

This part of the midstream business relies on seasonal volatility and spreads in the forward curve and those have trended down this year versus last year.

Also, third party marketing margins and volumes for reselling unused pipeline capacity have been under pressure, resulting in a smaller premium for marketing services.

Although net revenue from storage, marketing and other were flat year-to-date we expect it to be down for the full year by about $15 million.

Net operating expenses at Midstream were about $7.7 million higher quarter-over-quarter.

O&M expense represented the lion's share of that increase running $5.2 million higher quarter-over-quarter, about half of which was related to impairments for the decommissioning of some old compressors will increased electricity, materials and property taxes accounted for the majority of the remainder of the increase in O&M expense.

About $2.2 million of the remainder in the increase in total net operating expenses was due to higher DD&A expense associated with our recent Midstream investments.

Finally, our standard liquidity update.

We closed the quarter with no short-term debt.

We finished with a net cash balance of about $200 million a fully available $1.5 billion credit facility which expires in October 2011.

We have recently begun the process of renewing our credit facility and expect to have a new multi-year facility in place by year end.

Our 2010 CapEx estimate remains at about $1.2 billion excluding acquisitions and we estimate that full year 2010 operating cash flow at the current strip will be approximately $650 million to $700 million including the $123 million we received from the tax refund earlier in the year.

We continue to be in a great liquidity position and expect minimal draws under the revolver at year end.

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

Thank you, Phil.

At EQT Production we posted our third consecutive quarter of over 30% year on year growth in sales of produced natural gas.

The Marcellus has quickly become our fastest growing and most important play as well as our most profitable one.

After having accounted for only 2% of off sales in the third quarter of 2009, the Marcellus accounted for nearly 20% of our sales of produced natural gas in the third quarter of 2010 and we expect Marcellus to account for about 30% of fourth quarter sales.

I will return to the topic of profitability shortly.

On September 29th, we announced the results of two prolific Marcellus wells in Pennsylvania.

The Greene County well, which had a 30 day production rate of 22 million cubic feet per day Is currently constrained to allow for the fracking of seven wells on the same path.

And the last full day of production October 12th, the 37th day, this well hit a 24 hour rate of 20.2 million cubic feet equivalent per day.

The Armstrong County well, which had a 24 hour production rate of 15 million cubic feet per day is also in line.

Due to capacity constraints in that area, this well is producing under 2 million cubic feet per day right now, which happens to be the total take-away capacity in that area.

Given the takeaway constraints, we will not have meaningful initial 30-day production data from this well.

As we alluded to in our press release regarding this well, the primary purpose is to help us establish whether the new well geometry would result in sufficiently prolific wells to help us justify building out midstream assets in this area.

We are now in the process of designing and sizing the gathering system needed to develop our 34,000 Armstrong County acres.

Our Midstream group expect to have a gathering system in place to support development of the area commencing in 2012.

This impressive well result is additional evidence of the quality of our overall Marcellus acreage position.

We have now fracked two wells using the new geometry and several more are planned.

As is typically the case with these innovations, the frac costs are higher on a per well basis but lower on a per unit volume basis.

It is too early to declare the new geometry a standard operating procedure, but we are pleased with the results.

Extended laterals of course are already standard operating procedure.

55 of our Huron/Berea wells have completed pay at more than 4,000 feet and the same is true of 10 of our Marcellus wells.

Recoveries from extended lateral wells has been proportional to the length increase while cost increases have been much less than proportional to length increases.

Implementation of extended laterals will be limited by land issues, which should become less of a limiter, if we can pool our acreage with our neighbors, entirely voluntarily, or with the assistance of legislation.

You should expect our average lateral length to continue to increase.

These results emanate from our culture of encouraging innovation.

I believe this culture is more important than the well specifics.

The Greene County well was the result of longer laterals.

The Armstrong county well was the result of trying new frac geometries.

These are just two of the many advancements made by our production group over the past few years, resulting in remarkable progress in lowering unit capital and operating costs.

Not all innovations are applicable everywhere but our production group is committed to finding the most profitable approach to developing each of our 500,000 Marcellus acres.

An important attribute of our acreage position is that nearly all of the held by production or MC.

In the current capital constrained environment, if we had to drill to hold acreage, we would be using fewer multi-well pads and drilling only standard laterals to allow us to touch more leaseholds.

Instead, we developed our acreage in the most economic manner meaning that we were drilling individual wells and pads that are more expensive but that help us achieve that most important of strategic objectives, reducing our long-term cost structure.

A related issue is takeaway capacity.

Our midstream group completed the interim gathering system and added compression in Greene County PA in the third quarter, adding 70 million cubic feet per day of take-away capacity.

They are on schedule to add 50 million cubic feet of daily take-away capacity in Doddridge, West Virginia, in the fourth quarter.

We are already drilling in Doddridge, so it will not be long before you hear about West Virginia Marcellus wells fueling our growth.

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

The $15 million initial phase has been completed and provides about 100,000 Mcf per day of incremental delivering capacity to Equitrans' interconnections with five pipeline facilities.

Midstream has done a great job of coordinating the capacity addition in support of production development plans.

Once again, we achieved the best cost structure we can develop in a way that concentrates volumes at a handful of pads in order to allow us to build fewer larger mid-stream systems.

An additional success in our third quarter was from our commercial group.

They found take-away capacity while the interim progress is being constructed, enabling EQT to avoid expected take-away constraints, and therefore exceed our internal sales projections, which assume more take-away constraints.

For EQT to excel, the production midstream and commercial groups all must succeed.

I'm confident that all three groups will continue to perform.

Moving on to some bigger picture topics related to our capital budget.

Since April, the five-year strip for natural gas has fallen from nearly $6 per MMBTU to approximately $5 per MMBTU.

I'm sure a number of you noted that.

The silver lining of this cloud is that we have many investment opportunities that earn respectable, even good returns at these prices.

In fact, we have many more opportunities than we have available capital in the current environment.

At EQT, we are willing and able to live within operating cash flow and can achieve a five year production sales growth CAGR in the mid teens at that level so we can afford to defer some of our projects with limited loss of shareholder value.

This is our base.

We think we can do better.

As we all know, this economic and price environment leads to the need to make some tough choices.

To free up capital, pursue the best opportunities, we are looking to monetize some of our assets.

Our focus is on assets that earn lower returns or are perhaps worth more to others, such as acreage that would not be drilled in a timely manner or midstream assets in lower growth areas, or that are fully contracted, like our Big Sandy pipeline.

We are in the process of determining if there is an attractive market for some of these assets and opportunities.

We are pursuing this in a more determined manner right now so that by the time we finalize our 2011 budget in January, we will have a better idea of whether we are spending in line with only our operating cash flow projections, Or if we will also have cash from asset monetizations to redeploy.

Though we are not ready to discuss our capital budget for 2011, we can tell you that it will be set by either operating cash flow or operating cash flow plus a reallocation of some of the proceeds from such monetizations.

We do not anticipate any new capital from capital market transactions.

Either way, we will invest in the highest return projects.

While our wet Huron/Berea development still makes a credible return to current prices, especially for wells drilled near existing pipes, building significant additional take-away capacity for Huron/Berea drilling does not seem prudent in the current pricing environment.

These are amongst the projects that look attractive economically, attractive enough to keep and develop, but not so attractive that the shareholders lose money from deferring some of them until the economic conditions are more favorable.

These deferrals will result in a slower growth rate for our Huron/Berea shale production.

One consequence of this decision is that we will not need additional processing capacity in Kentucky as early as previously projected.

This impacts the economics of the proposed liquids JV with DCP.

We continue to work with DCP to find a structure that works for both of us.

However, while our processing needs are reduced in the near-term in Kentucky, they have increased in Northern West Virginia, where we have wet Marcellus gas.

Approximately 40% of our 500,000 Marcellus acres contain wet gas.

Structurally, one positive for EQT is that it appears unnecessary to invest our own capital even as part of a joint venture to process, fractionate, and transport our wet gas and liquids in the Marcellus.

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

The practical impact of that for the next year or so means an increased emphasis on sales of assets that are worth more to others than to us, and a reduced, though still healthy, drill bit development pace versus our previous notion of aggressive development.

As has been true since Murray and I came to EQT in 1998, we continue to be obsessed with earning the highest possible returns from our investments and doing what we should to increase the value of your shares.

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

Thank you, Dave.

That concludes the comments portion of the call.

Maureen, will you please open the call for questions?

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

(Operator Instructions).

Our first question is from Scott Hanold, RBC.

Please go ahead, sir.

Thank you.

Good morning, guys.

You talked quite a bit about the potential for asset sales.

Can you address what you all think about the joint venture process.

I know you guys have been doing a lot of work trying to evaluate them and what your current thoughts are there.

Well, when it comes to any assets that we might monetize, opportunities we might monetize, what we're really trying to do is we're trying to figure out what the values are to see what's attractive.

And I don't have an answer right now on any of those.

But that's because we don't know what values are out there and what's attractive.

But our mindset is that any number of the kind of opportunities that I've discussed could be available if the price looks attractive.

Fundamentally what we're talking about is just taking money that we receive and redeploy it to other opportunities.

Or get paid early for some of those opportunities and we just need to get more specifics from the market if you will before we can make an assessment of which of these we wish to pursue.

And it did sound like you guys want to move somewhat quickly.

You generally provide guidance in the next couple months or so.

When you look at your options, of outright asset sales, joint venture some of that takes a little longer than others.

How do you kind of fit that all into the equation?

I agree with you.

If there are attractive prices on state asset transactions, those are likely to happen sooner and that is likely therefore to influence budgeting decisions quicker than something that is more structured.

Okay.

So if I'm reading into your comments, CapEx budget as is and then if let's say a joint venture comes into play, then your CapEx would go to this.

Yes, it's not just joint venture.

I'd use that same logic for asset sales.

Perfectly understood.

And in the commentary around, when you're looking to spend your 2011 CapEx budget, you made the comment you're spending within cash flow and obviously any kind of monetization proceeds could be in addition to that, and there's no new capital.

Would you also -- would you use your revolver so cash flow was X, and could CapEx be X plus what you do on your revolver, or when you say no equity --

The reason I made that -- no, we didn't want to use -- I'm not talking about going beyond the operating flow plus some portion of asset sales.

If we find there's enough attractive things on the divestiture front we will not spend all of it.

So honestly, we're looking ahead over the next two or three years, and we're going to have a lot of attractive opportunities organically over the next two to three years, and I would just as soon not be in the same situation, I'm not sure everybody in the industry would have the same thing to say, a year from now, two years from now if the economy continues to be in this kind of situation.

We do not want to start drawing on revolvers and things like that in a way that's going to make us uncomfortable.

I appreciate that.

I worded my question poorly.

Let me start again.

Excluding asset sales, would you set a CapEx budget above your discretionary cash flow number, meaning would you actually use --

We're talking about setting it based to operating cash flow.

We can use up other stuff, revolver and stuff like that.

It's operating cash flow is what is going to set up.

And then some portion of proceeds from any possible divestitures.

I appreciate that.

One last question.

On the sort of NGL/ethane market in the Marcellus, what do you think about some of these projects that are being announced to bring some of that stuff down to the Gulf Coast?

Do you have any sense on what kind of cost that would be?

Are there any other better options you see over the next several years?

Mainly, I'm encouraged that there are projects being announced.

We do not plan as if we will get premium pricing for ethane.

For ethane we would like to simply get -- we're getting natural gas pricing now.

We understand that's not the same as if Marcellus and the Huron/Berea were located in the Houston ship channel, but they're not.

So we're planning for just getting natural gas prices for that, anything above that would be gravy.

And most of the projects we're talking about really are focused on concerns about ethane.

I don't think any of us are concerned about the markets for propane and butane.

This region should take propane in from other regions, net-net.

Okay.

They're not looking for premium pricing.

When you talk about wet and stuff like that we're talking about C3 and above.

We understand ethane is an NGL, technically, and certainly economically an NGL some parts of the country.

The reality is, it doesn't function that way economically in the A basin.

Next question is from Amir Arif from Stifel.

Please go ahead.

Good morning, guys.

Good morning.

Couple quick questions.

Just on the two well results that you've been talking about, could you elaborate on that a bit, the new geometry that you're talking about?

Amir, this is Steve Schlotterbeck.

We're not ready to talk about that geometry.

We only have a couple of data points.

That's not enough for us to feel comfortable with the correlation between the new geometry and the improved results.

We want to get a big enough sample set where we're comfortable that there's some meaning to it, and then we may talk about it.

For now we would like to keep that under wraps.

Okay.

If I may, though, can you help me is it in terms of geometry, is it in terms of one well relative to placement of other wells, or is it the direction of the wells, or the placement of the wells or you don't want to go there at all.

I would rather not talk about it.

Information gets around this industry fast enough without us making announcements on conference calls.

Okay.

And then just another quick one on the same well.

You've done the 9,000-foot lateral, you said you've got a lot at 4,000 feet.

Do you feel you're sort of figuring out the optimal lateral length in terms of if there wasn't any issues on lead lines.

I think from our perspective longer is better at least up to 9,000 feet.

That's as far as we've gone so far.

I think economically our belief is based on the results we've seen both in the Marcellus and in Huron, the results are proportional to length.

The results we've seen have fit exactly with our model.

So we thing it's really limited by land, and at some point technology, how far we would be able to go.

And I actually think fracturing pressures will ultimately be the limit to length from an operational side but more common would be land limitation.

Longer lateral, higher rate, more upfront pipeline and Midstream take-away capacity.

So doesn't that also become a limitation in terms of optimizing the capital in Midstream.

The way we think about it is for a given amount of capacity, what's the most efficient way to fill that capacity and if we can do it with less wells, that are more productive, and more economic, we think that creates the most value.

If you had a dream scenario you would have one pad and all the gas in the Marcellus would come into one pad and all the gas in Huron would come into one pad.

I'm not imagining we'll get to that in our lifetime, but we had tended to think that the fewer locations, the more gas that's moving under the earth surface and the less -- the fewer spots it's hitting at the surface, the better for economics.

Just economies of scale.

Okay, and your comfort level on the HM BCFE number that you put out.

I know from the numbers you mentioned, it's not really deeplining yet, but that's because it's being held back by surface constraint, but how do you guys come up with the HMBCF?

The HMBCF -- clearly, it's not based on a lot of production history, 30 to 40 days.

It's basically taking the initial rates and fitting it to our tight curve.

Any reserve projections done that early on the life of the well is certainly subject to high levels of uncertainty.

Given the way that well started its production life, compared to other Marcellus wells in the area, that have longer production histories, that's our current best estimate.

Can you tell us how much that build costs?

We put out a $7.1 million cost.

7.1 is still our --

Okay.

One final question, I'll turn it over to someone else.

Just on the production is growing 30%, I think in your Marcellus numbers, you guys were talking about 140 by the end of the year.

I thought your takeaway capacity was only going to be 120 at the end of the year.

Or is that just Pennsylvania?

Those are just the additions.

This is Randy Crawford.

That's for just Pennsylvania.

That is just Pennsylvania.

Okay.

So next year, if you guys are growing mid-teens on the cash flow, there's definitely no take-away issues, and but even if you're growing 30%, shouldn't be any issues if you're finding it there?

No, we said it was the incremental capacity that we constructed here in Pennsylvania.

We don't think that at these rates that -- the issue on growth in the Marcellus for us is the availability of capital.

We think that -- I think we said right along, we are going to have lumpy periods because of putting in Midstream.

That continues to be the case.

But we don't -- when we look at our plans, we don't see anything typically that would stop us from keeping up the kind of growth rates that we have for a Company because of midstream.

Capital issues, not midstream.

Thanks.

The next question is from Philip Chung with BMO Capital Markets.

Please go ahead, sir.

Good morning, guys.

Good morning.

Earlier this year you thought 2011 production would be at least 26%.

Is that a target that you still think can be achieved assuming you guys spend the cash flow in 2011 and --

We could probably achieve that if we slow down.

Okay.

And then also when you get to the end of the year --

Just to make sure, I probably came across as a bit flip -- the reason the CAGR gets lower as you go out over a longer period of time is the way this thing is always going to work.

I've had this conversation with investors individually, but I'm happy to have it broader.

There is a lag of nine months or a year or something from changes in capital to volume changes.

A lot of our investors felt that rather painfully two, three years ago when we were putting capital in.

It took a while for the volumes to pick up.

We're now in the other position where regardless of what we do with capital, volumes should start off in 2011 very strong.

Cutting of that capital eventually starts affecting you as you get further out.

So that's the -- I wouldn't focus so much on any concerns about 2011, the capital sensitivity is as you look further than 2011.

Okay.

It dips, and then the profile, no matter when we do it, is the second year is often the weakest and then starts picking up as the cash flows from the wells, since they're high return wells, even at these type of prices, begin fueling more growth.

So that's kind of the lower approach is to see a pop up in the first year after slowing down, and then it drops, and then it begins slowly climbing back up, and I'm talking about the year-on-year production growth rates.

Right, because of the 79 Marcellus horizontals that still aren't producing, I assume there's going to be a substantial number of those that aren't online by the time we come to year-end, so kind of this launching pad into next year in terms of --

Yes, and it will always be the case, it's just that when you're spending at a lower rate, you would typically have -- you'd exit the next year with fewer such wells to help you with the second year's volumes.

Right.

Okay.

And then, I think earlier this year, I think you said on the midstream, it was a matter of when, not if that became a bottleneck to production growth, and we're especially concerned about the summer periods.

Has the success that you've seen so far this year, that you've experienced in the Marcellus, has this made you any less concerned about the midstream being a bottleneck in the future, or at least, excluding the capital side of things?

Well, the capital side is going to be a big thing in this industry for a while.

The thing that's heartening is the continued interest of other midstream companies in investing in the Marcellus, but generally speaking, I think our view on the bottlenecks on midstream is about the same, which is, over long periods of time, it doesn't create constraints, it's just that you will frequently -- and we will continue to frequently go through periods where we plateau, and where the volume plateaus is where drilling, and we're waiting for midstream to come in, because it's just not economic to put all the midstream in ahead of time so as soon as the wells are ready to flow they can all flow.

So we're going to continue to see these situations where the volumes will spurt up which we've gone through just kind of recently and then they will -- they'll plateau for a while as we're putting the midstream in and then they'll spurt up again.

You could have a quarter -- if you looked at sequential quarters, I still think we've got the potential that there will be sequential quarters even in a very healthy growth rate environment that are close to flat.

Right.

Okay.

And then on the completion, new completion design on the well in Armstrong County, is that technology that you think can be used a little further north in Clarion County where I see that you have quite a bit of acreage?

This is Steve.

We certainly hope so.

Again, we only had two data points so it's very, very early to jump to too many conclusions about those techniques but we certainly would hope that it would apply in many of our Marcellus areas.

More broadly, I want to come back to our view, certainly it's Steve's and my view, that our folks have demonstrated again that they will figure it out.

So if it's some different techniques that are required in Clarion County, I'm confident and I know Steve's confident that our folks are going to figure out what works best there.

That's it from me.

Thanks, guys.

Next question is from Ray Deacon, Pritchard Capital.

Please go ahead.

Hey, good morning.

Steve, I was wondering, what do you think the trend in Marcellus horizontals as a percentage of the total drilling well count will look like over the next couple quarters.

Looks like about 13% of the wells you completed in the quarter were Marcellus horizontals and I'm sure it was a much bigger percentage of capital.

But what do you think the trend looks like over the next couple quarters?

Ray, really all I can tell you there is we haven't announced our 2011 budget yet so I can't provide well count numbers.

But following Dave's comments, we are looking hard at where we put our capital to work and clearly Marcellus drilling is at the top of our list in terms of returns.

So I think it's safe to assume that you will see a lot of our capital going into the Marcellus in relation to our other opportunities.

So, that's really all I can tell you at this point.

Okay.

Got it.

And can you say where the six Marcellus rigs are drilling currently, and where do you maybe see that rig count?

Does it stay flat there for the rest of this year?

We will stay flat at six rigs for the rest of the year.

I believe two are currently in Greene County.

One is in I believe Indiana County.

And the other three are in West Virginia, I believe in Doddridge County.

Got it.

Thanks very much.

You bet.

The next question is from Michael Hall, Wells Fargo.

Please go ahead.

Thanks.

Kind of getting back on the 2011 outlook, just to be sure I'm thinking about the growth correctly.

So you said the CAGR would -- obviously is front end loaded then, that mid-teen CAGR.

What might that have looked like let's say prior to the decision to ratchet back spending to within cash flow?

That five year CAGR.

Well, what's easier to say is that it's -- we're certainly capable of numbers that are north of 30% CAGRs.

I think we've said that before.

And that's over at least five years.

Probably you could look out more than several -- let's call it several years.

It's not all capital of course.

There is a judgment on which of these things look attractive if the prices stay low and I think that's something probably a lot of us in this industry are struggling with.

We do need to get some of our cost structures down to make more of our Huron/Berea play as attractive as we know it can be.

And a lot of that is on the -- is more getting the gas from the wellhead to the market.

So I don't know, if the prices were low, even if you just decided you wanted to give us $1 billion or something, I'm not sure that we would actually want to go spend all of that, right now.

I think we would just as soon work in some of these areas on improving the cost structure before we go spending too much of the additional money.

Okay.

So if you view that as the standard and you would say well, then, to what extent is capital drawing it down, certainly would be north of 20% CAGRs but I'm not sure if in this price environment, even if we had the capital, if we would think it's economically the right thing to do to be growing at those kind of 30% CAGR rates.

Okay, good.

Refreshing to hear that.

As we think about the potential for asset sales, what sort of dollar magnitudes are we talking about?

Any numbers you can wrap around that, what you identified as potentially for sales, internally expected numbers.

Certainly enough to bring the -- as we sit here now, I doubt that we would think it would make economic sense for us to spend as much money in 2011 even excluding the acquisition as we did in 2010.

So even if the capital were all there, it doesn't feel like it's the right environment in which to do that.

So you're talking about a number less than that, certainly.

And then it's all about the values.

If we can just fill a gap of, I don't know, $200 million, $300 million to get up to a slightly better rate, that would be great.

But we would like to sell things that give us good value.

Which incidentally, it's true across the board.

I mean, as they say, all the shares in the Company are for sale virtually every day also.

So everything is always for sale at a price because we're an economic enterprise, as should be the case I guess for every Company.

I guess if you were to --

We don't know what the values.

What we're trying to focus on is stuff whereby the people who have money and are willing to spend the money are interested in buying.

I mean, that's the practical reality.

Right?

There's only some parts of the market that have money and are willing to spend it, and what you would like to do is to get a better feel for which assets of ours and opportunities of ours line up with that.

Because they don't all.

As is also the case with all production companies.

I mean, who likes mature producing properties right now?

Not the people who have got a lot of money.

Yes.

Is this the right time to be selling those, though?

I mean -- ?

Well, to who?

I guess that's the point.

I mean, if there's not a big market of buyers, presumably you're not going to get a very good price.

But we've got assets that we think are interesting.

Okay.

To people who have got a lot of money, so why force the ones that aren't interesting down the market's throat?

We don't need to do that.

I guess I can imagine companies that might be in that situation.

That's not the situation we're in.

Okay.

We've got assets and opportunities that we think are attractive to people who have got money and that's going to be the priority.

Stay within cash flow, if you can sell some assets at attractive prices you're willing to but you're not going to fire sale anything in the market.

That's exactly right.

I guess stepping over onto the pad drilling, when you're thinking about the sizing of the gathering and compression assets on those, on the facilities you need, I mean, how are you thinking about that relative to obviously what the pads could produce on a peak basis, how do you size it relative to that?

I'd just as just as soon have Randy -- Randy can answer the sizing of Midstream.

We work closely with Steve.

It does vary a good bit on the amount of pad drilling and the contiguous acreage position that we're looking at but certainly we continue to refine our design based on these increased results.

But fundamentally what we do is we look at putting our backbone, the pipeline system in and then with the longer lead items we phase in the compression over time as the pads and as David mentioned, sizing it all immediately, but putting the compression in over time.

Great.

Thanks.

Great.

Thank you.

The next question is from Josh Silverstein, EnereCap Partners, please go ahead.

Good morning, guys.

Good morning, Josh.

I was just wondering along the same lines as far as the pads go and the gathering compression systems, if you're going to likely see more step functions in the production going forward, are you planning on turning one well online that can flow at 20 million per day or maybe three wells at a time that you can get to 40 to 60 million per day?

This is Randy again.

We certainly -- we don't size for peak.

And so we take into account all of those factors.

But again, a big decision is the size and the diameter of the pipe.

As I said, once we put that in, then we can use the compression.

A lot of the advantages we gained this year was that the higher pressure wells and some of the excellent results we've seen at EQT Production we've been able to go directly into the interstates and around that compression and then as some of the declines come in, we can stage that compression in and keep the flows moving.

So conceptually, that's how we work with the team and factor in the design.

But it does -- you're right that it does wind up shaving the peaks.

I mean, we're not getting -- we're not going to wind up getting peak 30 day rates on all of our wells.

Because we'll wind up either turning just some in line at a time from pads or let them all be choked back some.

And then --

Don't waste the money on sizing for peak.

Got you.

And then also, I was wondering if you guys were designing pads in specific locations to try to be efficient with the capital to get longer lateral wells but also hold acreage at the same time?

Well, certainly to get longer laterals, that is a strong desire of ours.

Greater than 90% of our acreage is firmly held.

So we make really almost no development decisions based on the desire to hold acreage.

Our acreage is already held.

As Steve said, positioning it so we can get longer laterals, et cetera, more wells on one pad, absolutely that goes into it.

I was curious on the Greene County well, if that was in the wet gas zone, if you had a breakdown how much was dry gas versus the liquids side in.

That Greene County well was in the dry gas area, it was pipeline quality and it's not being processed.

Okay.

Just lastly from me, you talked about the asset sales and ranking and who would want what.

I was curious if the distribution assets were considered up for sale as well?

Generally speaking, I do not think that makes sense in this environment.

Again, you would never want to say never, but the ones that have the best cash flows right now and are steady cash flows, I mean, I'm not sure if those are going to -- especially on the distribution side if those are going do be most attractive.

We have tax basis issues with the distribution.

There's a whole bunch of reasons that the aftertax proceeds we get from that type of asset is very unlikely to prove to be attractive.

Okay.

That's it from me.

Thank you.

We have a follow-up question from Ray Deacon, Pritchard Capital.

Please go ahead, sir.

Yes, hey, I guess, Steve, I was wondering, I'm assuming all your acreage in Nora and in the Huron is held by production pretty much so if you were to slow down you wouldn't lose any.

Is that basically right?

Yes, that's correct, Ray.

And also, what do you expect the capital to be on the part of DCP Midstream in 2011 and has the first facility been decided on already?

Ray, this is Randy.

As Dave mentioned, with the changes that we've looked at in the Huron, that we're looking for working with DCP on other structures that may work.

And so what needs to be spent is really more in line with West Virginia and the wet gas and the needs for processing there at this point.

Got it.

And since we don't plan on putting our own capital in, we only care what the capital commitment is as far as it affects our rates.

Right.

And I guess just one more.

Do you have a -- of the wells that are waiting online, is there a large percentage in Doddridge?

Is that -- ?

That is where the highest percent of those wells, is in Doddridge County.

And we are actively fracking out there now and capacity's coming online.

So we would expect to see volume increases in that area here shortly.

Great.

Thank you.

The next question is from Holly Stewart, Howard Weil, please go ahead.

Good morning, gentlemen.

Good morning, Holly.

Good morning.

Just, Dave, just kind of a bigger picture question as you're looking at ways to gain capital.

What do you think about the dividend?

I mean, it's a fairly nice -- you're at a 2.5% or so yield today.

I'd call it $130 million this year of capital.

How are you guys thinking about that kind of going into the out-years now?

Well, it is a healthy dividend, I agree with you.

We do periodically look at dividend strategy, but I don't think it would be fair to say that has been one of the first things we've been looking at right now.

We have periodically reviewed it, and we would expect to continue to periodically review it.

I know that --

Perfect.

You're not going to think that's a substantive answer, but that's my answer.

Well, good enough for now.

Thanks, guys.

Thank you.

Having no further questions, this concludes our question-and-answer session.

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

Thank you.

That concludes today's call.

This call will be available by replay, beginning around 1.30 PM Eastern time today.

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Thank you very much.

This concludes the EQT Corporation third quarter 2010 earnings conference call.

Thank you for attending today's presentation.

You may now disconnect.