EQT Corp (EQT) 2009 Q3 法說會逐字稿

Good morning and welcome, everyone, to the third quarter 2009 EQT Corporation earnings conference call.

All participants will be in a listen-only mode.

(Operator Instructions) After today's presentation, there will be an opportunity to ask questions.

Please note this event is being recorded.

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

Patrick Kane.

Sir, you may go ahead.

Thanks.

Good morning, everyone, and thank you for participating in EQT corporation's third quarter 2009 earnings call.

With me today are Murry Gerber, Chairman and Chief Executive Officer; Dave Porges, President and Chief Operating Officer; and Phil Conti, Senior Vice President and Chief Financial Officer.

In just a moment Phil will briefly review a few topics related to the third quarter financial results released this morning.

Then Murry will provide an update on our drilling program, Equitrans and other operational matters.

Following Murry's remarks, we will open the phone lines up for questions.

But first I would like to remind that you today's call may contain forward-looking statements related to such matters as our well drilling and infrastructure development initiatives, production and sales volumes, reserves, the estimated ultimate recoveries for our wells, operating cash flows, capital budget, growth rate, and other financial and operational matters.

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

These factors are listed in the Company's Form 10K for the year ending December 31, 2008, under Risk Factors as updated by any subsequent Form 10Qs, which are on file at the Securities and Exchange Commission and available on our website.

Please see the press release, a copy of which is available on our website, for non-GAAP financial measure reconciliations and other disclosures, with respect to such non-GAAP financial measures.

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

Thanks, Pat.

Good morning, everyone.

As you read in the press release this morning, EQT announced third quarter earnings per share of $0.02 which compared with earnings per share of $0.73 in the third quarter last year.

Adjusting for stock based incentive compensation expense and building relocation expenses, both of which I will discuss later, EQT's normalized earnings per share as shown in the table in this morning's release is more like $0.22 in the current quarter vs.

$0.32 in last year's third quarter.

Also to get a better sense of our normalized operating cash flow, that--and that comparison to last year, you would want to make those same adjustments by adding $32 million to this quarter's operating cash flow, and subtracting $85 million from last year.

Said another way, about $117 million of the $143 million reduction in operating cash flow, quarter-over-quarter, is attributed to those non-operating adjustments.

Behind the cash flow and the $0.22 of earnings per share this was another very strong operational quarter for the Company, both in terms of growth and produced natural gas sales from the Huron, Berea, and Marcellus drilling programs; as well as growth and gathering transmission and processing revenues in our midstream business.

We have also continued our progress of reducing drilling costs and per unit operating costs, which were already among the best in the industry.

Not withstanding all of the operational progress, the financial results were once again negatively impacted by the continuation of lower year-on-year commodity prices.

Lower prices impacted EQT results in two primary areas.

First, as you would expect lower NYMEX led to lower realized averaged well head natural gas prices for EQT production, significantly reducing productions revenues; and to a lesser degree lowered NGL prices suppressed unit revenues in the midstream processing business.

As we show in the table in this morning's release EQT's realized average wellhead natural gas price was $5.23 per mcf in the quarter or 28% lower than the $7.26 per mcf that we experienced last year.

So in total, lower commodity prices resulted in about $54 million less net revenue in the current quarter vs.

the third quarter last year.

I will now go into a little more detail on all of that as I briefly walk through the results by business unit, starting with EQT production.

And there, once again, the big story in the quarter at production was the increase in sales of produced natural gas as you saw in the release, up 18.5% vs.

the third quarter last year.

On a rolling four quarters basis we have grown sales volumes by 19.5% despite being in a period of constrained capital expenditures.

I will also point out the majority of the very positive well results mentioned in this morning's release and that Murry will elaborate upon in a minute, are not included in the third quarter results; but will instead show up in the fourth quarter.

But just like the last several quarters, the significant volume increase was more than offset by an average NYMEX price that was 67% lower than last year resulting in an average well head price to EQT production that was 37% lower.

That price decline resulted in $52 million less revenue in the production business in the quarter vs.

last year.

On a much smaller absolute level we also saw a drop in basis to $0.06 per mcf on average in the quarter vs.

$0.15 per mcf in the third quarter last year and $0.08 in the second quarter of 2009.

Historically, basis is lowest in the summer months; but the majority of the drop in basis from the third quarter '08 to now was a result of the nearly 70% drop in absolute NYMEX .

One other item I should point out and will show on the table is that we did realize income of $45 million, or about $1.81 per mcf in the current quarter as a result of our hedge position.

Just a brief moment on expenses.

Total operating expenses at EQT production were higher than third quarter '08; however, on a unit basis the LOE was actually down 11% as a result of the substantial volume increase.

That, by the way, is excluding the impact of production taxes that were $7.5 million lower.

We're continuing to see the benefits of scale in our protection business.

DD&A expense was higher reflecting our recent drilling investments and growing production levels.

The Company also invested $4.5 million in the quarter for the purchase and interpretation of seismic data, which shows up as exploration expense in the third quarter financial results.

Exploration expense year-to-date is a little over $12 million, and we project it will be around $14 million for the full year.

Moving on to midstream business.

Operating income here was up 27%, consistent with the overall growth of gathered and processed volumes, as well as increased revenues from Big Sandy pipeline.

Gathered volumes increased 8%, mainly from gathering EQT production's increasing sales volumes and combined with higher rates resulted in a 16% increase in gathering net operating revenues.

Midstream's transmission revenues are largely based on demand charges with only modest revenues gained from the actual shipping of gas for firm transportation customers.

So even though transmission volumes were slightly lower, transmission operating revenues were up 39% vs.

last year; primarily because we were able to sell capacity on Big Sandy that is not currently being used by EQT production.

Processing volumes were are also up again year-over-year.

This time by 50%, even despite a three week outage of the Langley processing plant.

However, the average liquids price was $0.78 a gallon in the third quarter; or just slightly more than half of the $1.51 price that we saw in 2008; and partially offsetting the impact of the volume increase.

And then finally, storage, marketing, and other net operating revenues at midstream were higher mainly from higher gas sales to an industrial customer.

Operating expenses at midstream were about $8 million higher than last year and that increase was expected based on the 2008 infrastructure projects including Langley, Big Sandy and Mayking that have been in service all year.

DD&A expense accounted for a little under $5 million of the increase in expenses while increased electricity and labor to run our expanded compressor fleet accounted for much of the rest.

Reported SG&A was down $2 million as higher SG&A related to the growth in the midstream business was more than offset by not having a recurrence of the $5 million charge in the third quarter of '08 that we had for the Lehman related bad debt.

Quickly moving on to distribution.

Operating income at distribution was about $3 million higher in the third quarter or $5 million higher than in 2008.

I'm sorry, was $3 million in the third quarter, or $5 million higher than in '08.

Approximately $3 million of the increase was due to higher rates that became effective at the end of February when we received final approval of our previously announced settlement of the LBT's Pennsylvania-based rate case.

Expenses were also a bit lower, as a result of lower bad debt, as well as the shift in timing of some maintenance projects.

Moving on to a couple of other items before I turn the call over to Murry.

First, incentive compensation, the recent increase in the stock price, it was actually up 22% during the third quarter coupled with EQT's performance relative to a previously discussed peer group, was primarily responsible for stock-based incentive compensation expense of a little over $28 million, or approximately $23 million after tax for the recent quarter.

As you know, our current compensation programs were designed to provide investors with tremendous transparency around the cost of executive compensation.

Not just at the time of of the grant, but throughout the life of the plans.

With that transparency and the Stock Market volatility over the last few years we have also experienced, as you know, a fair amount of compensation expense volatility in our reported results as the recent quarter comparison vs.

last year clearly demonstrates.

If there was any doubt about the link between incentive compensation and shareholder return, all we have to do is look at last year's third quarter when EQT stock price declined by 47% and we realized an $85 million reversal of previously recorded incentive compensation expenses vs.

the $28 million charge this quarter when the stock price was up 22%.

And said a different way that is $113 million swing between quarters.

Couple other things on--you saw that we mentioned a $4 million office relocation charge in the press release.

In the third quarter, EQT moved our headquarters from the north shore of Pittsburgh to a downtown location.

Since moving to the north shore four years ago, we've added approximately 500 employees to facilitate the dramatic increase and the growth our production and midstream businesses and we outgrew the previous space.

The north shore location was designed to allow the addition of space to that facility; however given soft commercial real estate market conditions the current price for type A office space in downtown Pittsburgh is approximately $22 per square foot, or about 25% less per square foot than the estimated cost of adding space to our north shore building.

So, we decided to secure downtown office space with a long term lease, and the ongoing annual savings associated with the new space explains our willingness to incur a small amount of relocation and lease impairment expense in the recent quarter.

Finally, a brief liquidity update.

As you'll see in the Form 10Q that we release later today, the Company had $193 million of net cash on the balance sheet at 9/30/09.

We are continuing to estimate that 2009 operating cash flow will be about $600 million, inclusive of the previously discussed tax refunds.

Although gas prices have trended lower during the year, sales volumes are up and our cost per well is down; and so, we are reducing our forecast of outstanding under our $1.4 billion revolver at year end to under $100 million excluding working capital swings.

That low level of outstandings under the revolver, which doesn't expire for two more years, puts us in a great liquidity position as we head into the 2010 budget decisions.

Murry will elaborate on that in his comments.

And with that, I will turn it over

Okay, Phil thank you very much.

Again, welcome everybody this morning.

I guess the overall message for the quarter is that, as Phil said, it was a very strong operational quarter leading with the headline of the 8.5% increase in produced natural gas sales volumes.

All this volume increase or at least the vast majority of it is driven by the Huron and Berea play.

It is all organic.

For your information, this is our fifth consecutive quarter of double digit produced natural gas sales volume growth.

Based on the progress that we have had so far as we saw in the release, we're raising our 2009 sales volume guidance to 100 bcfe, which is 19% higher than 2008.

Total gross well spud in the third quarter was 214.

Year-to-date, 518.

Total horizontal well spud third quarter, 123.

Year-to-date, 271.

We currently have 23 rigs running.

Three Marcellus rigs, we'll have five by year-end.

Two in the coal bed methane, and the rest are deployed drilling horizontal wells in the Huron and Berea play.

Just a drilling update on the main plays.

On the Huron and Berea play, just to remind you, we have drilled a total number of air-drilled horizontal wells since our program inception in late 2006 of 712 wells.

So we're getting a considerable amount of experience in drilling these wells.

More than 25% of our third quarter natural gas sales volumes now come from air-drilled horizontal Huron and Berea wells.

To remind you of the scope of the play, we have 2.2 million acres in the Huron and Berea play.

Generally each spacing unit, which now we think is about 80 acres, could be a little less but say 80 acres.

Each spacing unit averages a little more than two perspective zones to allow for stacked wells.

We reported 6.6 tcfe of 3p reserves at year-end 2008; and we estimated at that time 13tcfe of resource potential.

On the drilling side, approximately 10% of our horizontal Huron and Berea wells are designated for alternative geometries, or drilling techniques.

This year, we have spud a total of 15 multi-lateral wells, and two extended laterals, 14 are frac'd and on line.

On the multi-laterals we continue to be encouraged by the volumes that we're getting.

We're tuning this geometry a bit, moving towards what we call paddle geometry that equalizes the lateral lengths of the legs of each of the multi-lateral wells.

This should improve frac effectiveness and reduce cost.

So we're still working hard on that.

Obviously stacking these up too.

Our latest application of new technology is the extended lateral design.

As background for the Huron Berea , the greatest driver of both well productivity and EUR per well seems to be feet of shale or Berea sand penetrated and effectively stimulated.

Until now, we have had to limit the length of horizontal legs of our wells in the Huron Berea based on the number of frac stages we could deploy using packer plus or other similar tools developed by Baker, Bj, Peek and Haliburton.

Normally this meant nine frac stages over a length of about 3,000 horizontal feet of shale or Berea sand penetrated.

Improvement in this technology is now allowing for 18 or more stages.

So we have lengthened our laterals.

To date, we have successfully drilled and completed two extended lateral wells with links in shale of 5,600 feet.

We have done that successfully.

Our current design includes 7,000 feet of lateral length in our targeted formations.

We also think we can go considerably further than 7,000, but that's our current design.

And with this improvement, we believe we can double our reserves per well for less than 40% more cost.

So, 1.6 bcfe in the lower Huron for about $1.4 million, this drives drilling F&D costs to be a little less than $0.90.

Currently at $7.00 NYMEX or the strip basically, IRRs for extended laterals are estimated to be in the mid-30s.

And importantly, payback period is about 2.7 years on that investment.

So that's a pretty important improvement this extended lateral, as it applies not only to single laterals; but, hopefully, later to multi-laterals as well.

So we're still innovating on this important play.

On the Marcellus play, just to remind you, we have 400,000 acres in the play.

On drilling, we have spud 34 horizontal Marcellus wells so far.

We have three rigs running now.

Are rigging up a fourth and as I said we expect to have five running at the end of the year.

16 wells have been drilled and completed to the point of our having reliable cost date.

11 of these wells have been turned in line and have been on production for greater than 30 days.

As we reported in the third quarter, we turned in line our best Marcellus well yet with a 30 day average IP of about 9 million cubic feet a day.

This well seems to stack up nicely with the highest 30 day IPs from any Marcellus well drilled to date.

We're on track to drill 41 horizontal Marcellus wells in 2009, and should have about 20 turned in line by the year-end.

On well costs, we have seen a dramatic improvement in well costs this year.

During the first quarter, our average completed Marcellus well was costing us a little over $5.5 million.

On our last earnings call, we reported having achieved completed well cost for the Marcellus of $3.3 million per well; and we, at that time, said we had a target of $3 million per well.

We are now at the $3 million level, and confident that we can continue that.

The main reasons for the drop in well costs are completion costs are down considerably.

That's down about a $1.1 million, from the 5.5.

That's a little--to a little less than 40% down.

Drilling days are down.

We're now drilling Marcellus wells in about 17 days.

Location costs and pad drilling is probably--accounts for about another $700,000 of that cost decrease.

As a further aside the extended lateral concept will likely also apply to the Marcellus, although we haven't tried one yet.

And as I think others have discussed in their conference calls, we're not sure exactly what the spacing is going to be on the Marcellus yet.

We all think--I think, less than 100 is the right number, but I'm not exactly sure what the right number is yet.

We are currently still using a 3.5 bcfe number for our EUR.

Could be a little higher, could be a little lower; but we're sticking with that at the moment.

Anyhow, drilling F&D costs are estimated, again, to be a little less than $0.90 based on our current cost structure.

IRRs for our Marcellus wells at the strip are about 30%, a little bit more than that; and again, pay back period is about 2.8 years.

The final point on production is one that we think is quite significant.

And I know there have been some who have been concerned about the efficacy of shale EURs and the attendant risks about those EURs.

Clearly for EQT at least, a key mitigant of that concern is the much shorter payback period that we're now forecasting for both Huron, Berea and Marcellus plays.

And that's the real--that's the power of lower well costs at work.

Turning to midstream and Equitrans.

EQT midstream successfully completed an open season earlier this month for proposed expansion of our Equitrans pipeline system within the Marcellus shale fairway.

We received request for capacity of more than 1.1 million decatherms per day from interested parties.

We're currently negotiating binding precedent agreements with those interested parties and finalizing the design of each of the pipeline expansion projects.

Total investment for the expansion is estimated to be between $650 million and $700 million.

And the project is currently thought to go forward in three phases.

Phase one, involving about 100,000 decs; we believe will now cost much less than $100 million.

Regulatory approvals are expected by the end of the first quarter of 2010.

Construction, if we get approval will occur in the second quarter of 2010 with completion by year end.

Phases two and three will build the project up to the full $1.1 million decatherms per day of capacity.

Regulatory process could take up to 18 months; and presuming precedent agreements are signed and FERC regulatory approval is granted, phase 2 construction would occur in the second half of 2011.

Phase three construction would occur in the second half of 2012.

As a more general midstream comment, I would like to talk briefly about one important development that bears on the cost and riskiness of investments in the midstream business as EQT currently sees it.

As you know, a pipe and infrastructure project, individually costs much more than an individual well costs.

And that presents a marked difference in magnitude of investment risk.

Also, once built, the pipe must be filled necessitating further investment by producers who use the pipe.

That presents a payback and in some cases a credit risk.

We call this the build-to-fill risk.

EQT is doing two things mitigate these risks.

First, through a better design and engineering process, we're figuring out how to shorten the build to fill timeframe.

Basically, we're going to build more, smaller and phased projects in order to shorten that build-to-fill risk.

Secondly, as we previously mentioned, EQT is open to considering partnerships on various aspects of our midstream business, providing such partnerships are constructed to off an attractive cost of capital and we're in the midst of several discussions on this particular matter.

In short, we'd like generally to have less EQT equity expensed on midstream.

On pacing, not unrelated; as we discussed we're working on defining the correct pace for developing our extensive acreage position.

Our work so far has shown that we can grow sales of produced natural gas organically with the drillbit by more than 30% for a long period of time.

The improvements in cost structure throughout the Company, particularly per well cost and per well performance that I discussed earlier lead us to believe that we can achieve growth at significantly less cost; and with significantly less external capital requirements than we previously thought necessary.

For 2010, we project we can achieve a sales growth rate similar to the rate that we have experienced this year with 15% to 20% less CapEx than we will spend this year.

In December, we will finalize our 2010 budget with our board.

We expect the budget to be set at a level that can be funded using internal sources; including operating cash flow, plus a small draw on our revolving credit agreement.

In short, this has been a pretty good quarter, pretty good year for EQT and I think continues to position us as a compelling investment.

We're becoming certainly a much more prominent U.S.

exploration and production company.

Our growth rate is competitively superior as best we can tell driven by horizontal shale drilling.

Our cost structures lead the industry, we're financially strong.

And we continue to have the flexibility to capitalize on improved market conditions, flex ourselves up in growth, if conditions present that opportunity for us.

And with that I will turn the call over to Pat, and then we will open it

Thank you, Murry.

That concludes the comments portion of the call.

BJ, you can now open the call up for questions.

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

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

Good morning,.

Murry, you were talking about pacing.

Can you give us a sense of when you're looking at your capital budget and what you all would like to do?

Within the current infrastructure that you have in the lower Huron, is there any limitations when you look at '10 or '11 or when do you have to really start thinking about building out that a little bit more?

I think--there is not much right now.

Of course it depends on the pace of drilling, but there is not a whole lot right now.

The big expenditure that will come or will need to come, as a result of accelerated drilling, will eventually be the the building of another processing plant to handle the liquids.

And, at this point in time we think that that decision needs to occur--the decision to build that plant probably needs to occur somewhere in 2011, I would guess.

With, hopefully, that plant being on line, in '12 or early '13.

But that depends on a lot--depends on a lot on the pacing that we're expecting.

But that is the major barrier right now in the long term for the Huron Berea play.

Okay.

And then when you kind of commented that to get similar growth rates in 2010 to what you saw this year with 15% to 20% less capital, is that specifically talking about drilling capital, or just kind of cancelling?

Total, total.

Yes.

I think we have said we're going to spend about a $1 billion this year.

So to be more specific, we could achieve--what we're saying is, we could achieve this year's growth rate for 15% to 20% less than the $1 billion that we're spending this year.

Okay.

Got it.

And then--

The reason we don't think we'd need to tap any external capital markets to be able to achieve that.

Did you catch that, Scott?

Yes, got it.

Thanks.

One last question on the Marcellus.

Obviously you had a tremendous result with that 9 million a day well in Green County.

There is still a fair amount of variability that you all are seeing.

Can you point to something specific to that?

Is it just the variability by nature of the acreage within the play.

And on that 9 million a day, I know you typically don't like to talk about 24 hour IP rates like others in the industry; but can you kind of give us a sense where that may have fallen out?

Okay.

Well, first of all, the reason that we're not raising our overall EURs yet, is because of the variability that you describe.

I think, to be frank, the variability doesn't concern me nearly as much when we're drilling $3 million wells as it did when we were drilling $5 million, $6 million, or $7 million wells.

To put not too fine a point on it, even if we averaged 3.5 bcf; and I realize our number is a little lower than others, I'm quite satisfied with the result given our current ability to drill these wells and drill them and complete them at the low numbers that I just reported.

There was a bit a rumor about this big well that we had, and you know my feeling about 24 hour IPs.

And just--I mean it just--and I don't want to be critical, obviously, of the use of this data; but just to the give you a flavor for how variable this can be, and how many factors are involved in determining an IP; and in particular, then, how you interpret the factors, I'm going to give them to you for this well, all right?

And this may be the only time I do it but I'm going to do it this time.

The only reason I'm doing is to let you know that all these factors need to be understood in order to figure out what the well can flow.

This particular well, flowed 20.4 million day for 24 hours.

Now the flowing casing pressure was 2,226 psi.

That's important.

The choke was 3964 inches.

That's important.

There was about an hour down time during the 24 hour flow period.

That's important.

So, with all these factors, and several others, too; I'm not sure what this well would have flowed nor how the flow of this well would compare to other company's results.

But those are things that you need to know, in order to try to even start making an attempt to understand what these wells can do.

That's why I traditionally have not seen it--seen the wisdom in reporting these results.

But that--there it is.

And the only reason I'm telling you this is because there was some rumor about this well circulating right after it was completed or turned in line.

Okay.

I appreciate that color.

Thanks a lot.

All right.

Our next question is from Sharon Nanzada from Millenium Partners

Sarah?

Murry, it is actually Mark Caruso.

How are you?

Oh.

Hey, Mark.

Sorry to disappoint you.

Well, say hi to Sarah for us.

Will do.

I just wanted to make sure.

It sounded like you guys, under Scott's question but, did I hear earlier that you guys were saying that you'd expect to have less of a draw on the revolver from originally for 2009?

We had originally in the year forecasted under 200 million.

Now we're saying under $100 million even with gas prices down.

Got you.

And, Murry, I think you just said earlier in lower CapEx, you guys think that the combination of the revolver and lower--or the dollar going further, you should be fine.

You don't--the revolver is enough and you don't need to think about asset sales, MLPs, or any of the other stuff that was originally contemplated?

Not to put too fine a point on it but I think, Mark, the differences are, A, the efficiencies have caused us to think that it is--we can put a budget together and grow at the same rate next year for less money and use internal sources to fund it.

That's what I said.

And in addition, we are open to midstream partnerships if the cost of capital is right to further reduce EQT's equity investment in midstream projects; again, if the cost of capital works out.

Yes.

If you were asking though, does that combination of a continuation of this year's growth rates, and 15% to 20% less CapEx, does that--is that consistent with not going to the external--to the capital markets?

That is correct.

That is true, yes.

Okay perfect.

One last question.

You just kind of hinted at it.

I know earlier in the year we had talked about looking at--open to the opportunity of JVs at midstream; and it sounded like you are still open to that.

Are you contemplating that on the upstream just given there is so much interest by others.

Oh, no.

I mean it--right now, we just--there is--you can see even from quarter-to-quarter, the massive amount of technology change and economic change that occurs in these plays.

I am loathe to consider options on the upstream partnerships unless they were just staggeringly good.

You never say no; but, boy, it's going to have to be pretty darn good at this moment in time.

Some day, I think, when the plays are delineated a bit more, the technology improvement slows down, then absolutely we will consider partnerships to accelerate the production growth.

But right now things are changing so quickly there would have to be a very, very good deal in order to catch my attention.

Not so much on the midstream.

I think on the midstream with the right cost of capital we would entertain partnerships.

To be clear on our strategic thinking.

It's not just that we want to get money for that.

It is the further upstream you move, the less we view that as our core business.

So Murry mentioned the processing.

We have a little bit in liquids lines and things like that; but generally speaking, the further away from the well, especially on the liquid side that it moves, the less core it is for us.

And other than making sure that it happens, so that our gas will continue to flow, the closer it gets to the well the more core it is; and therefore, the less interesting getting involved in joint ventures is.

Again, not to belabor it but clearly wells are our business.

Now upstream of that we don't have drill rigs, right?

So, we don't have frac'ing companies.

But drilling, we own leases, we drill wells, we gather the gas, we even build the high pressure gathering, which we've talked about a lot of on these calls.

Very key in our mind to have a significant amount of control of that high pressure gathering.

Processing, not so much.

We'd like somebody to process our gas.

We'd like someone to fractionate our gas.

We are not in the fractionation business.

We'dl like someone to sell the liquids that come out of the gas.

We're not going to have EQT tanks at the local grocery store.

We're not going to have that.

As Dave says, there is a point at which we are outside of our core capability, which at this point, is the acreage we have, the drilling technology we have to exploit this shale; and the pipeline capability to gather, measure, monitor the gas.

Those are core things of EQT.

Anything other than that is open for suggestion--open for potential partnership.

That's long winded but I just want to make sure we get it clear.

Perfect.

Okay, thanks.

Our next question comes from Ray Deacon from Pritchard.

Please go ahead.

Yes, Murry, I was wondering those five rigs at year-end.

Will you say which--will the bulk of them been in Dodridge or Green or a combination.

Combination of both.

By the way, I didn't say this but we're very pleased with West Virginia.

Very pleased with West Virginia.

But they're going to be a combination of Pennsylvania and West Virginia.

Okay.

And do you see a need to drill 3D so that you can drill longer laterals or do you feel like the returns are adequate without it?

I currently think the returns are adequate without it.

I think the question is would a 3D given the resolution of the 3D, would there be a compelling reason not to drill a well based on 3D data.

Steve Schlotterbeck and I talk about that quite a bit.

Boy, that would be a hard one at this moment, unless there was something that came out that was just so compelling.

Would you not drill a well because of something you saw on 3D seismic?

I don't know.

Not given the results that we have seen so far.

We are completing, though, I think the largest 3D survey in the Appalachian Basin.

It's about 75 square miles, it's in the--it has been acquired and it is in the processing phase right now.

And, we will interrogate that data as much as we can to see if there are indications from that data that can help at least grossly target Marcellus wells.

But the reason that thing was shot was for deeper objectives, and to get a better picture of deeper geology.

We committed to this a couple years ago and we wanted to follow-through because we are interested in staying ahead of the curve on the deep, even though today might not be the ideal time to drill.

All right.

Anyhow.

I guess just--two more quick ones.

Did you put a dollar number on the full three phases of Equitrans?

I was thinking you said 6 to 7.

Yes.

650 to 700 is what we said.

Got it.

And any comments on the liquid side and the decline year-over-year?

Any visibility on that improving going forward or--?

Decline on the liquids, Phil, you want to talk about that?

Liquids pricing?

No.

Liquid volumes is what he's asking about.

They were up over last year.

They were up 50% over the third quarter last year.

They were down a little bit from the second quarter but our Langley plant, as I mentioned in the comments, was out for three weeks.

Okay got it.

Up in total, but down quarter to quarter.

I thought that's what you were mentioning is the quarter to quarter decline.

And that is back up just so you know.

Okay.

Got it.

And how about pricing.

I guess, is there any visibility on increased demand.

You'd talked at one point about trying to develop local sources of demands for liquids.

Anything new there?

I'd--we continue to work--Davis particularly active on NGVs in this community and we're doing some things with equitable gas and the local communities to try to get the buses converted.

We're very active, EQT people are leading the states NGV task forces, and stuff like that.

So we're working hard on that.

If that's what you meant.

And on the liquid side look, we share a view that I think a number of folks in the industry would now say they share; which is eventually we have to figure out what to do with the ethane.

If you were asking about the liquids.

Obviously, we're really not worried about market--this region is a net importer of propane.

So we have a long way to go, before we worry about having too much propane.

You just wind eventually curtailing the imports.

But eventually, we think we need to have solutions for ethane.

Now, right now our Marcellus gas is pretty dry.

But obviously, we haven't drilled that many wells.

We have to look at others as well to get a better picture of the overall industry.

And it seems reasonable to believe that ethane's going to become an issue eventually in the Marcellus and eventually it becomes an issue in the Huron as well.

Just to let you know, Ray, there are discussions occuring about taking ethane both south, which would be obvious to the ship channel down there or north.

There's some discussions about taking it north, too.

So, we are actively involved in--as we normally do here at EQT, thinking about how these molecules are going to get sold.

Working them all the way down to the market.

That's why we did the 300 line expansion.

That's why we have developed fairly robust downstream strategy for delivering this gas.

But as Dave said, ethane is on our radar screen and we're looking at various alternatives.

Don't have anything in line right.

Look, it is not a near term issue.

No.

It is just--as hopefully, we have communicated it.

We really believe that we have got several years of very high growth rate potential in this company, and we think everybody else in the Marcellus probably; not a lot of other people are in the Huron, but they probably share the same view.

That means we need to be looking several years out.

But we have the same concerns about water, and I think as we have talked about and others have talked about, through a variety of means, we have now basically solved the water issues, as far as disposal, right?

With the 100% recycling.

We're confident that we will also solve the ethane issue, but it is a longer term issue.

Great thanks.

Can you remind me the--I know had you purchased that skitttable processing.

What is your capacity to handle we gas in the Marcellus?

Maybe if you could talk about takeaway, too.

Well, we're going to be up to 35 million day by the end of the year and we haven't given a 2010 number but--just suffice it to the say there was no issue at this point, with handling liquids capacity.

We have plenty of these flexible arrangements to be able to do that.

Where we're drilling.

We haven't run into lot of wet gas yet, but we know from looking at our--at our friends who are drilling elsewhere in Southwestern PA, that there are some areas of very high, very high liquids content.

So for what we're experiencing right now we have far more capacity than we would need.

Yes.

That is not an issue.

Eventually, we would imagine we're also going to run into some wetter gas and we think we have got that planned for for awhile out.

Eventually, I think you're going to see industry solutions to as opposed to single company solutions to those issues.

Right, got it, great.

Thanks very much.

Okay.

Thanks, Ray.

Our next question is from Jin Luo from JPMorgan.

Please go ahead.

Good morning,.

Just a couple quick questions.

Your extending lateral program, and do you plan to apply to all your future, horizontal wells or it's just still you guys still experimenting?

Well, it--let me put it this way.

I think the extended lateral technology for the Huron--since we have so much experience, if we can convince ourselves with relatively few number of wells, that these are performing as we expect they will, then I think we will fairly rapidly turn to drilling a lot of more wells with extended laterals in the near future.

We haven't made that decision yet, but I think the timeframe on making that decision is fairly short.

On the multi-laterals, we're not giving up.

That is still a very viable technology.

We get a lot of feet of shale penetrated with those Marcellus--with those multi-laterals.

What we need to be able to do is effectively fracture all of them, to--and we're getting good results, but we want a really even more effectively fracture those laterals.

We're changing the geometries a little bit.

So, you will see us have a combination of long extended laterals, multi-laterals, obviously stacking them, wherever there are multiple formations available, and you will see a mixture of these as we go forward.

The extended laterals have moved beyond experimentation, from our perspective.

They are becoming much more part of the base case, we just have to determine the extent of the application.

That's at least for the Huron.

In the Marcellus, you might say that is more of in an experimental phase.

But some of these experiments work and we start rolling them out.

There's horizontal drilling, air drilling and, frankly, extended laterals in the lower Huron have moved toward--kind of out of that experimentation phase and into a selective rollout phase.

It's really driven by the number of frac stages.

We always could drill the wells longer, but the tools--the frac tools, packer plus and all the rest of them that are following on to packers plus didn't have enough stages to be able to have effective frac 'ing on very long laterals.

That's why we went to multi-laterals because we didn't think that each individual lateral could be drilled and frac'd effectively.

Now that we can drill longer laterals, and frac longer laterals that changes the game a little bit.

It looks very, very encouraging as I mentioned in my comments.

Okay.

And it looks like you guys have improved the efficiency of the drilling, the cost is down and the returns are very attractive.

And your balance sheet look pretty good, so why not out spending your cash flow.

I didn't tell what you our budget for 2010 is going to be, I just said that at this point in time we can easily grow as fast as we did this year for less money than we spent this year.

I mean, if conditions in the markets improve, it is possible.

As I said, we certainly have the flexibility to go more than that.

If we feel that it's appropriate to do so we will.

But prices are pretty soft right now.

There is a lot of uncertainty in the economy.

We're just not certain that it is--it is a good time to rush into something.

To rush out there.

So that's why we're taking a bit more modest view towards 2010, in terms of spending and in terms of accessing the capital markets, which as Dave said we don't need to do.

So I just want to--

If you're positing, if facts change will we change our views, well, Phil, it was--John Maynard Canes said when the facts change, I change, don't you?

And I think that is exactly the attitude.

You saw that with us and the whole industry when we all scaled back on capital in the light of the new circumstances for this year.

The scenario Murry pointed out did suggest a little more than cash flow because he suggested a summary draw under the revolver 2010, at the same growth rate as we achieved this year.

Got you.

Okay.

Thank you very much.

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

Please go ahead.

Two questions for you.

One on your 15% to 20% reduction that you can do the same growth rate with 15% to 20% less.

Is that 15% to 20%, is that all coming from midstream?

Does that reflect a partnership or is it--?

No.

At this moment what that number reflects is EQT, 100% just as we have done this year and just dramatic reductions in well costs that we talked about.

And the pacing of midstream.

The smaller projects, paced out a little bit differently.

Shortening that build-to-fill period, which increases the time where we start getting our cash back--or decreases the time on which we continue to get our cash back.

We're really focusing on this payback period.

And when you roll all that together, our view of the total capital that is required to prosecute this play, both Huron, Berea and Marcellus, I should say, plays is much less than we thought six months or nine months ago.

With the biggest factor being that unit F&D, and it is in both of the big areas going forward: Huron and Marcellus.

It has been a dramatic--actually, Phil is probably in a better position to look at what the overall cash flow effect is, but it's been a dramatic impact on our thinking just, really, in the last six months.

In higher flow rates out of the Marcellus wells also.

Yes, I think that is right, Becca.

I think the--versus our original decline curve; which again, these are all based on not very much data.

But versus our original assumption about Marcellus decline curves, we think we're getting a little more gas out quicker, which is reducing the payback period, again.

And is accelerating the cash flow.

So it is cost reduction, a little faster gas flows.

By the way, for the Huron, Berea on these are extended laterals that is true, too.

So getting cash back faster.

Not putting it out as quickly for the midstream.

Pacing that.

Smaller projects, shorter build-to-fill periods.

All of this is combining to generate less cash requirements in total and less external market access in total, too.

So I know you all have been very patient with us about this.

We have been talking about pacing for quite a long period of time, but I think the work that we've done here has been--I'm very proud of it because I think we have solved a lot of the issues of risk that I was quite concerned about a year ago.

And I feel like we're getting to place that is a lot better than we would have been had we prosecuted this play in the way that we would have a year ago.

Great.

Thank you.

And then the second question is, on the discussions about midstream partnerships.

Will your '10 guidance in December reflect some of that; and at what point is this--are these just preliminary discussions?

Is this something that is fairly furlonged?

Obviously, we're not going to talk about all that in public; but I would guess at this point that the 2010 guidance we give on our capital budget in December will not include the prospects of a partnership.

Not that we won't be looking at them, but I doubt whether anything will be that--will be that close at that point.

I could be wrong.

But at this point, if you asked me today--you're asking me today, I'm going to tell you today that in a month-and-a-half from now we're unlikely to have something closed up.

Okay.

I'm sorry, I have one more question.

On the Equitrans open season, did the LDC take some of that capacity?

No, but EQT production did.

Okay.

We will just hold off to hear about that amount until later?

Yes.

I think so.

I think--I mean the filings are going to come out here in November?

For--to start move this along.

In deference to any of the production companies, not just the affiliated one, but others.

It just doesn't seem to be the practice in the industry to disclose that information.

Until it has to be disclosed.

It really kind of in deference to all of the productions companies.

Remind everybody--as you know, everybody has to go through the process of precedent agreement.

It takes a little while to get all that done.

So we don't want to front run that process.

Great.

Thank you, guys.

Good results.

Okay.

Thanks, Becca.

Our next question comes from Stewart Weinman from Catapult.

Please go ahead.

Hi.

Thanks for taking my call.

Just one quick question kind of to go with what Becca was just asking.

This year ENP vs.

non-ENP was about 60%/40% of the capital budget.

Could you give us a little bit of color on just the percentage of budget associated with the ENP?

It's going to move more towards the production.

If you're asking trend-wise--if you're asking the trend, I think--my anticipation is that a higher percentage of the budget will be in the drilling.

As we go forward.

Certainly for 2010, and--but also beyond.

Are we thinking more 80% or--?

You're asking me to give you the budget, and I already said we're not going to reveal the budget until December.

We really have to wait until it is approved.

But it is moving more towards production.

There are two reasons.

In the Huron where we're really the dominant player.

We have had to put a lot of investments in upfront, in--not just the big pipelines like Big Sandy and the processing but even in the corridors, etc.

And a lot of that stuff now has been done and helps for a while.

And in the Marcellus, a lot more of it are going to be industry solutions because you don't have the dominance of one producer throughout Southwestern PA and Northern West Virginia.

Speaking that probably means industry solutions on the pipelines as well.

Thanks.

That's all I had.

Okay thank you.

Thank you.

This concludes our question-and-answer session for this conference.

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

Patrick Kane for any final remarks.

Thank you BJ.

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