EQT Corp (EQT) 2008 Q3 法說會逐字稿

Good morning.

My name is Jessica, and I will be your conference operator today.

At this time I would like to welcome everyone to the Equitable Resources third-quarter 2008 earnings conference call.

(Operator Instructions).

Thank you.

It is now my pleasure to turn the floor over to your host, Pat Kane.

Sir, you may begin your conference.

Thanks, Jessica.

Good morning, everyone, and thank you for participating in Equitable's third-quarter 2008 earnings conference 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, Murry will provide an update on our drilling program and midstream projects, and Phil will briefly review a few topics related to the third-quarter financial results which were released this morning.

And then following Phil's remarks, we will open the phoneline up for questions.

But first I would like to remind you that today's call may contain forward-looking statements related to such matters as our well drilling and infrastructure development initiatives; reserves; reserve replacement ratio; financing plans; capital budget; capital expenditures; growth rate and other financial operational matters, including daily sales volumes and operating cash flow.

Finally, 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, along with other cautionary matters regarding certain non-GAAP financial and operational measures to be discussed this morning, are listed in today's earnings release, the MD&A section of the Company's 2007 Form 10-K, the 2008 third-quarter 10-Q that will be released tomorrow morning, as well as on our website.

And now I would like to turn the call over to Murry.

Thanks, Pat, and good morning, everybody.

I wanted to update you this morning on a number of things, but first I just wanted to reiterate that the major premises that underlie the growth prospects for Equitable have clearly been borne out by this quarter and by the results that we just released.

In particular, as I mentioned in the release, horizontal air drilling is certainly working.

It is cheap to implement, quick to implement in this Appalachian mountain terrain, and it seems to be broadly applicable to a number of geologic formations in a number of areas in the Basin.

Secondly, our midstream [quarter] strategy, while time-consuming to implement, is obviously working to a level, frankly, that has surprised me even.

And the reason it surprised me, or the reason it is really up, is that we've drilled a lot more wells.

We are getting better at completing those wells.

The compression and processing performance for the midstream assets is turning out better than the designs specs.

So we're kind of hitting on all cylinders there.

And very importantly, our team is strong, it is talented, it is driven.

We have a culture here of do first and talk later, and I think Equitable has an unfair share of that rare breed of individual who can really accomplish astonishing things.

And so those have really been the reasons why we have outperformed.

Third, our cost structure is low, industry-leading, and therefore, the Company is resilient to even further market stress.

And just a couple of supporting facts to that, drilling capital required to keep our volumes flat is about $150 million a year, and that is a very small percentage of our operating cash flow.

Phil will talk to you about that in just a minute.

And breakeven prices consistent with our lower midstream spend presuming this environment hangs on for awhile in sort of a feel what we have built strategy, at the breakeven price at 0% IRR is about 250 Nymex and to make our cost of capital is about $5.00 Nymex.

So obviously the cost structure is helpful to us in that regard.

Furthermore, our assessment of reserve potential at the Company continues to grow, and while few in the market seem to care much about reserves or long-term value right now, I do care.

When this time of market stress passes, I believe the winners will be those who have not abandoned innovation, and we certainly have not done that.

We continue to discover more ways in which value can be extracted from this wonderful Appalachian Basin asset.

Lastly, in the release we said that implementation of our strategy is applied to the total asset base.

It gives us the potential to grow in excess of 20%.

Just so you know what we're really thinking about, Dave and I believe that without any capital constraints, the Company can grow organically at an average rate of about 25% for at least five years and then continue to grow at a substantial rate beyond that given what we have had and what we're able to do and our ability to execute.

So I want to go on to a few operational statistics here.

I will just try to update you from the quarter-end.

Total year-to-date we have spud about 554 gross wells.

Horizontal wells so far 315 have been spud.

And, as we mentioned, we are on pace to drill 375 horizontal wells this year, which is up 25 from our last estimate.

Just to remind you that total horizontal wells we drilled so far since the program inception at the latter part of 2006 is 408 wells.

And so far we've drilled 13 Marcellus wells.

On reserve implications you might be interested to note that 71% of the drills that we spud through the third quarter were on locations that were classified as unproved when we drilled those wells.

And so I know there's a tendency at this point to focus valuations on proved reserves, but to be honest with you, we don't even look at the reserve classification of the well when we drill it.

As you can tell, many of the wells we drill are not on proved locations.

And although this is not sort of an audited number, we think that our reserve replacement ratio through the third quarter due entirely to our drill bit activity is about 600%.

We currently have about 21 rigs running, one in the coalbed methane, two in the Marcellus, 16 in the horizontal play and a couple of others doing other conventional drilling.

An update on the different plays on the Lower Huron play, the low-pressure Devonian play, our bread and butter so to speak.

We have spud 295 wells this year.

Drilling results continue to confirm both the economics of the play and the decline curves we've previously published.

On the emerging plays, and again these are plays that we have no 3P reserves booked, I will go through a couple of them.

But anyhow the Berea we now have 15 horizontal Berea wells, and seven of them or online; 30-day IPs range from 1.1 million a day to 2.0 million a day.

The completed well costs to remind you for the Berea are projected to be about 1.4 million to 1.5 million barrels.

We anticipate spudding a total of 25 to 30 Berea wells this year with the majority being in Kentucky.

The results from the Berea have stimulated us to begin testing other collateral unconventional targets, siltier targets, sandier targets, limier targets.

We've got a well that we're going to spud in the Raven Cliff, one in the Big Lime and one in the Weir.

As you recall, we estimate that we could have as many as 3800 new Berea locations on our acreage to be drilled, meaning locations where no previous wells have been drilled to test the (inaudible).

On the shale reentry, to remind you again, we have about 4700 existing, 80 acre spacing units that have been previously drilled into the low pressure shales with a vertical well.

We've drilled 113 reentry wells, 52 in Kentucky and 61 in West Virginia, and we have 30-day IP, 30-day production results on 47 of those wells.

On average in both Kentucky and West Virginia, these horizontal redrills or reentries are producing about 400,000 per day, and the decline of the existing vertical well has remained unchanged.

And obviously that's a very encouraging result, and the proximity of these wells to existing infrastructure makes the economics of these reentries even more interesting.

During the quarter we did spud two multilateral wells.

We actually did both wells at the same pad, so they are stacked multilateral.

One in the Lower Huron where we drilled about 12,200 feet of lateral hole in the shale and one in the Cleveland where we did 9800 feet of lateral penetration of the shale from that well.

So we have done our first stacked multilateral well, and we are expecting to turn that well in line this week.

On the Marcellus, as you know, we have 400,000 acres in the high-pressure Marcellus play.

So far we have spud 13 wells in this play, four horizontal and nine vertical.

We've turned in line seven of those wells.

The two horizontal wells -- one is in Greene County, one in Doddridge County, West Virginia, the 30-day IPs are 1.3 million to 2 million cubic feet per day, and the costs are expected in the Marcellus for horizontals to be $3 million to $4 million.

Five vertical wells have been drilled, one in Wetzel and Doddridge County, West Virginia; Lewis County, West Virginia; Ritchie County, West Virginia; and Gilmer County, West Virginia.

Three wells have 30-day IPs, and those are averaging about 0.5 million cubic feet per day.

The first well cost $2 million.

First vertical cost $2 million.

The next two cost about $1.3 million.

So we're getting a pretty good learning curve there.

So, as we mentioned last time, we continue to be encouraged by this play, and by the end of '09, we plan to have drilled at least 75 Marcellus wells.

As we mentioned in the release, we are experimenting with air drilling in the Marcellus.

We have done it twice.

We still have some bugs to work out, but we believe total drilling costs could come down by 25% or more with broad application of air drilling, horizontal air drilling for the Marcellus play.

One new thing we're doing that you might be interested in, we are interested already in determining whether refracing the horizontal wells will be interesting.

To test that concept, we during the quarter performed a refrac of a vertical well, vertical shale well.

The well was drilled in 2002.

We refraced it with nitrogen over a fairly broad interval, and we nearly tripled the production from that well.

So we're going to do some more refracs, and this will be new news down the road, but we are hopeful that after all these horizontal wells have been drilled that there will be a whole other round of refracing to occur after that.

So that is sort of the drilling update, the production update.

On midstream obviously we are pleased with the progress of the buildout as detailed in the press release.

Strategically since it became clear a couple of years ago that horizontal air drilling was going to work, we emphasized to you that construction of a robust midstream infrastructure was the most important next step to assure growth.

We even said that the Company's strategy was pipe-driven, at least until sufficient capacity had been built.

Fortunately the Company undertook the development of such an infrastructure, and while we recognize that these projects could take awhile to complete and it might be frustrating to wait on the completion of those, there are multiple projects that are basically done.

This quarter's results show the fruits of that long effort.

They are coming to market.

We think that the volumetric results that we have seen in the third quarter and that we're projecting for the fourth quarter and the future attest to the benefits of that midstream effort.

However, at this point given the uncertainty of the Capital Markets, we're making plans to slow down midstream development somewhat and focus our capital spending as much as possible into drilling wells where pipeline capacity already exists.

This is being done to achieve the highest possible near-term growth rates without having to access the Capital Markets.

Essentially we're currently in the mode of filling what we have built.

As you know, we have always prided ourselves around here being a low-cost producer.

Having the three large projects completed that we talked about in the release means that the unit cash costs to EQT of drilling near this midstream capacity is very low as much of the gathering and compression charge report in production is a transfer to the midstream unit.

However, there is no question that the cost of contractors and steel have driven up the cost of putting in new pipe, and from that perspective, a silver lining to the slowing of the growth of the midstream development is that we will benefit as those pipeline construction costs decline as they have now started to do.

Fortunately, as I said, we have built enough pipelines and process and capacity to achieve growth rates in excess of 12% for the next couple of years without the necessity of accessing the capital markets, and Phil will go into those details in just a minute.

But we're continuing to position ourselves for a rapid ramp-up of both drilling and midstream if capital becomes more easily available either in the capital markets or through partnerships.

And with that summary, I will turn the call over to Phil for the financial details of the quarter.

Thanks, Murry, and good morning, everyone.

As you know no doubt saw earlier this morning, Equitable announced earnings per share of $0.73 for the third quarter of '08, which compared to earnings per share of $0.27 in the same quarter last year.

As Murry just discussed, from an operations perspective, we had our best quarter ever.

I will briefly review the reported results and then spend some time on our capital plans and the related funding of those plans.

Starting out with production, as you saw in the release, production operating income was up 40% versus last year.

Primary drivers of the improved results were higher sales volumes and higher average well price.

Sales volumes of 21.2 Bcf were 12.3% higher than the third quarter of '07 when normalized for the sale of (inaudible) property '07.

Those incremental unhedged volumes, as well as a significantly higher Nymex price, resulted in an average wellhead sales price of $5.62 per MMbtu, which was 29% higher than last year.

Higher operating expenses offset a portion of the benefit from higher volumes and prices.

Approximately half of the increase in operating expenses was DD&A, LOE and planned SG&A expenses, all of which reflect our increased drilling activity and sales volumes.

About one-third of the increase was gas price driven as production taxes and allowance for bad debt were both higher in the quarter, directly reflecting the significant increase in Nymex during the early part of the third quarter.

Finally, for the first time in many years, the Company invested in the purchase and interpretation of seismic data targeting deep zones.

That investment was expensed in the third quarter and accounts for the remaining $3.3 million of the operating expense increase.

Moving on to the midstream business, operating income here was also higher at $29.8 million versus $23.5 million last year.

The increase was due to four main factors -- higher gathering volumes, higher gathering rates, higher natural gas liquids prices and then the revenues from infrastructure projects brought online this year that Murry just talked about.

We've discussed the higher gathering rates in the past, and higher liquids prices I believe are self-explanatory.

Midstream did complete the construction of the Langley processing plant during the quarter, and that coupled with the recently completed Big Sandy pipeline in the Mayking quarter added to the new volumes and resulted in increased operating revenues and operating income at midstream.

These investments in infrastructured projects also provide the backbone to quickly move gas from our horizontal drilling program to market.

Operating and maintenance expenses, DD&A and SG&A were also higher in midstream, consistent with the growth of the midstream business.

Midstream did record a $5.2 million reserve against Lehman Brothers receivables, which was included in midstream SG&A in the quarter.

Lehman Brothers defaulted on a park and loan transaction at the transmission and storage end of the midstream business.

We do not have any further income statement exposure to Lehman Brothers.

A couple of other items I wanted to talk about before we turn it over to Q&A.

First, the EPIP.

The recent reduction in stock price, coupled with Equitable's lower ranking in a peer group, resulted in a reversal in the third quarter '08 of previously recorded compensation expense.

Executive incentive compensation expense, including the reversal, resulted in approximately a $70 million credit in the current quarter, which represents an $80 million swing from the $10.3 million expense recorded in the third quarter '07.

Reversal was based on the stock price assumption of $37 and a multiplier of 1.7 times, which were the existing conditions at quarter-end.

As we have discussed in the past, the final plan expense will be determined by the year-end stock price and multiplier.

Now some of you may recall the two main reasons for choosing this current plan structure were one, it clearly ties executive compensation to shareholder return, and second, we thought that it would provide transparency to shareholders around the cost of executive compensation.

In retrospect, the transparency caused some confusion to investors as we were often explaining fairly big swings in the quarterly expenses each time the assumptions of year-end 2008 stock price changed.

And even as we sit here two months away from the end of the year, we obviously cannot predict what the final year-end stock price will be.

In the third quarter, the compensation committee implemented a new long-term incentive program, which comprised performance shares and options.

However, the amounts are much lower as we have returned to the practice of annual awards versus the multiyear plans we have been using for most of this decade.

The philosophy around long-term incentive programs for management continues to evolve, although at Equitable incentive programs will continue to link management incentive compensation to shareholder returns.

This has been a core to every program that we have had since Murry arrived in 1998.

However, in contrast to the '05 program, the use of annual programs and options will result in less volatility on reported income and cash flow.

As an example, when the new program was implemented, we projected a quarterly expense of about $1 million.

What I would like to do in conclusion is briefly our cash flow, CapEx and funding plans over the near-term starting with operating cash flow.

As the table in the press release demonstrated, operating cash flow of $203 million in the third quarter and $512 million year-to-date were both up significantly versus last year.

Those numbers do have some noise in them, not the least of which is that the EPIP expense reversal shows up as operating cash flow even though it mainly applies to previous periods and is not really even cashed until the end of the year anyway.

So stripping out the effects of compensation, expense reversal, as well as a tax refund that will not be received until 2009, would lead to a "normalized" operating cash flow, more like $412 million year-to-date versus $280 million year-to-date in 2007.

So still a sizable increase at 47% over last year as a result of what we have already talked about, volume growth higher prices and lower cash taxes.

For the year 2008, we expect normalized operating cash flow to be about $550 million.

Looking forward to 2009, there are several factors that will affect available cash, as well as earnings.

First, our anticipated sales growth will be additive to cash flow and earnings.

Second, our gas hedge position, which I will elaborate on in a minute, will likely increase our effective sales price in 2009.

As I mentioned, we also expect to receive about $100 million refund from the IRS in 2009 for taxes that were paid in 2006 and 2007.

There are some other ins and outs from the other businesses, but all told it is the current -- as a $7.50 Nymex strip prevails, we anticipate generating available cash flow, including the tax refund of $700 million to $750 million in 2009.

Returning to the effective sales tax issue for just a minute, there are three factors that are exerting upward pressure on our unit sales prices in 2009 versus this year.

First is the increase in sales volumes are the result of our drilling program, which, as you know, occur at basically market prices.

Second, our gas price swap position will drop from 50 Bcf in 2008 to 37 Bcf in 2009, again increasing the sales volumes exposed to market prices.

Finally, the average strike price on the remaining fixed price swaps increases from $4.62 in 2008 to $5.91 in 2009.

The net impact of all that is we expect our effective sales price will be about $0.50 to $0.60 higher in 2009, even if the 2009 Nymex strip is $7.50 or approximately $1.50 lower than Nymex is currently projected to run in 2008.

Moving onto CapEx, we have spent about $960 million through the third quarter and anticipate spending another approximately $450 million in the fourth quarter for a total of $1.4 billion for full-year 2008.

As we've said, we're currently developing a plan to spend $900 million to $1 billion of CapEx in 2009, and we will come back with details in December once we finalize the plan and receive board approval.

Trying to tie all that together, at the end of the third quarter, we had net short-term debt of $83 million with expected CapEx of about $1.3 billion to $1.4 billion between quarter-end third quarter 2008 and the end of 2009, as well as dividends and other cash outlays.

That short-term debt balance is expected to arrive to about $700 million to $800 million by the end of 2009, net of any seasonal working capital swings, which leaves us ample room under our credit facility to fund an additional shortfall in 2010.

As you know, we currently fund short-term debt with our $1.5 billion revolving credit facility that expires in the fourth quarter of 2011, although I should point out that only about $1.4 billion of that facility is currently available, and Lehman Brothers held a $95 million commitment in the facility.

So the combination of our drilling success and sales volume growth, coupled with our strong balance sheet and liquidity position, is why we are confident we can fund capital plans for the next couple of years that will generate 12% plus sales growth without having to go to the capital markets.

Having said that, should the capital markets return to some level of normalcy over that period, it is clearly in the best interest of the shareholders that we raise additional capital to bolster our liquidity and move towards the 20% plus growth potential inherent in the asset base that Murry talked about.

And with that, I will turn the call back over to Pat.

Thank you, Phil.

That concludes the comments portion of the call.

Jessica, can we please now open the phones for questions?

(Operator Instructions).

Scott Hanold, RBC Capital Markets.

Murry, could you talk about production a little bit?

You are obviously looking at 250 to 260 exit rate, and based on your activity levels, it looks like production could be a good 15% to 20% next year.

You have obviously talked about bringing in capital and having various growth outlooks.

Can you kind of lend some color on what you expect at those spending levels here in '09?

Well, we have not finalized the plan yet, and obviously it is going to be somewhat fluid.

Suffice to say, we're still holding to 12% plus.

We will come back in December and talk about what that number is.

There are obviously choices that have to be made between absolutely just filling up precisely what we have already built versus providing some capital to midstream for the future either our own or someone else's.

So I would rather stick to the 12% plus at this point in time.

You correctly point out, though, that at the current ramp-up of sales that we have seen at least for the first couple of quarters next year, you're going to see -- you were likely to see some pretty healthy quarter-on-quarter growth.

But if drilling does not ramp up to its full potential, that quarter on quarter growth rate will diminish because we will be drilling into these kinds of big quarters that we're having right now and in the fourth quarter.

let's stick to the 12% plus, and we will come back in December with more data.

Okay.

And maybe I can try and ask the question this way.

Is there anything from an infrastructure perspective that would limit growth based on what you currently have at this point?

Well, we have built a lot.

If you take Mayking, Langley and Big Sandy, we have a lot of capacity there to fill.

And so the question is going to be, how surgical can we be in the drilling, which includes the permitting, getting the sites ready, etc., etc.

How surgical can we be to put our drill rigs right where that capacity is?

And that is really why we need a little bit more time to come up with a number.

Fair enough.

Turning to the Marcellus, it sounds like you have got a couple other horizontal wells.

Could you give a little bit more color on that second well and where that first well is at?

I think if I recall that first well we drilled up into the Hamilton and kind of talked about what kind of occurred when you went horizontally into that second well?

Yes.

We continue to think that the Hamilton is a good place to drill the horizontal well.

We tried a horizontal -- the first horizontal air drilled well we did in the Hamilton.

And the second one we started in the Hamilton and drifted down into the Marcellus.

It's a little more difficult in the Marcellus to drill horizontal.

So we're really -- nothing has really changed.

We think that from the standpoint of operations, the Hamilton is more competent.

It is easier to drill.

We're getting good results from fracing down into the Marcellus from the Hamilton, but we continue to wonder whether we could get better results if we drilled exclusively in the Marcellus.

The problem is right now for the wells that we have drilled, it has been a little more difficult to drill horizontally in the Marcellus.

So I think the jury is out.

We're satisfied with the results of drilling in the Hamilton.

We just don't know if they can get better by -- those results will be improved by drilling strictly in the Marcellus.

Okay.

And then so I guess the subsequent horizontal wells you will be drilling, what zone are you targeting?

Are you going to kind of try to continue to look to the Marcellus to drill in?

We're going to try to do that if we can, but again, if we get thwarted, we will continue -- we will drill in some more competent zone.

Okay.

And one last question, any update on that Utica well?

No, we're still in the process of engineering a bigger frac job there.

We're thinking about drilling another well, but we don't know whether in the context of the market conditions whether we're going to do that sooner or later.

And when we drill that or if we drill it, we would like to frac both at the same time.

So we're sort of on a little bit of hold on the Utica at this point.

Okay.

So on that first well there, anything you saw?

I know you have not fraced it yet, but when you -- (multiple speakers)

Well, we did attempt to frac it; we just did not get it up to a high enough level.

We did not bring in as large a frac equipment as we probably need.

Okay.

Can you say anything about the reservoir you saw when you were down there?

No, it is not -- we have not sufficiently tested the Utica yet because we have not fraced it to the level that it needs to be fraced.

Okay, understood.

Thanks a lot.

Michael Hall, Stifel Nicolaus.

Real quick, drill down a little bit more on the CapEx spending and growth plans.

You talk about, call it 700 to 750 of operating cash flow in that 900 to $1 billion CapEx number.

So call it 130% of cash flow at the midpoint.

That drives around 12% growth.

And then you talk about the 25% plus kind of growth rates.

How much more capital do you think you would need to get to those levels as a percentage of that expected cash flow?

Is that 150% or 175%?

Can you help me think about that?

How much more capital?

In general, I think our plan -- keep in mind, there's a lot of moving parts here.

In the 2008 capital, there was a significant flood of CapEx that was directed towards completing the big projects that we did complete this year.

So in our thinking at least, over the long-term, we did not anticipate that we would have a continuing need for as much midstream capital as a percentage of the total.

On the other hand, we felt because we've built the capacity to do so that we would be drilling a lot more wells in 2009 than we would have in 2008.

And so plus or minus, we would have thought that we could spend as much as we spent, if the capital markets were available, as much as we spent in 2008 and possibly more, and we would have been encouraging people to do that because we would have wanted to ramp the drilling up.

Dave, did you want to say anything?

Yes, our internal models would have shown that we would have maybe spent 15% or so, 50% or 60% more capital in 2009.

But then those internal models, as you know, also equate to a more than 30% volume growth in 2010 over 2009, keeping in mind, of course, that in this business for us, as well as other companies, for the most part, there's a lag of, let's call it six to nine months between the capital spending and what shows up in the volumes.

The '09 capital really leads more to 2010 volumes than it does to 2009 volumes.

I understand if you spend it in the first quarter, then you get the benefit in -- certainly you get the benefit in the second calendar year.

But the other thing is, as we have mentioned when we built Big Sandy, etc., we had talked a lot about how we had looked for third-party midstream companies to work with us on those.

And we built those things on our own in part because we could not find any of those.

And that is a change.

We actually find that's still changed.

So definitely the other moving piece for us as far as figuring out what our capital expenditure would be is that there has persisted in being more interest on the part of third-party midstream companies in getting more of a foothold in the Appalachian Basin, and those are discussions that we are -- that we continue to encourage.

They have obviously slowed down a little bit in this environment, but the fundamental interest remains there.

Obviously the more you lean in that direction, all the CapEx we have been talking about has been as if we're going to do the whole thing ourselves.

But I guess what I'm indicating is, when the capital markets ease up and there's a decent chance that a fair amount of that midstream capital comes from third parties, not from Equitable, which Murry alluded to in his comments, the reference to partnerships.

That is another moving part that makes it difficult to assess.

You've got to get more leverage per capital.

Of course, your cash costs out-of-pocket wind up being higher, alright, because those gathering and compression costs that you pay, the transmission costs are all cash costs; whereas right now it is basically DD&A in the Corporation.

Does that help you get a sense of what we're talking about?

It is certainly helpful.

It sounds like then the real kind of anchorman or the discretionary, more discretionary piece and the rest is maintenance, but just the swing piece I guess is more midstream?

Yes, it is definitely midstream, and I think what -- Dave is right.

Had there been a perfect world, we probably would have had presuming they would have wanted to react to our needs, having a midstream partner is not a bad thing to do.

The problem is no one wanted to meet our needs, and so we ended up doing a lot of it ourselves.

And we're not dissatisfied with that.

I think the pace at which we have been able to grow is a result of our having been very responsive on midstream to the needs of the production business unit.

But at this moment in time, when you're having to make choices, right, the swing in capital spending is a midstream dollar.

So that is why the incremental returns on the midstream are lower than, frankly?

Well, right.

And the payouts are a little bit longer.

I meant they make EVA certainly, but again we're talking about where is the best place to put the next dollar.

And if you had your choice, you would put it in drilling and not in midstream.

Just keep in mind, as far is midstream, it is true midstream returns are lower.

But you also keep getting the money for a longer period of time.

Over time it is less gas price sensitive.

It is definitely a little different.

(multiple speakers)

And the different cost of capital, and so the way we look at things around here, we have always looked to EVA.

You will get a good spread, but the point right now is that if you have to make a choice, it is hard to put the next dollar in midstream like today.

Because you get to pay back so much quicker in drilling.

So I think this is obviously where this crisis meets Main Street, right.

We're having to make the least worst choice.

We like both businesses clearly, but if you have to make a choice, you put your dollar in drilling right now.

And this is for everyone, though.

The comments that Murry made about some of the silver lining is slowing down and stuff that we were talking about even before this capital situation involved in the marketplace, steel prices have just gotten out of hand.

We really only started to see -- we have seen the downturn in those industries, but we're still -- you know, the October prices for the stuff we look at maybe are equivalent now to the August prices.

They are below the September prices, right?

But they are still way above what they were even at the beginning of the year.

Give this thing a little time and those prices are going to come down, and the economics on all this stuff starts looking a lot better.

That is very helpful.

I appreciate the color.

One more line of questioning.

Can you just talk a little bit more about air drilling in the Marcellus?

Kind of help me out in thinking about air drilling in an overpressured environment as opposed to the more normal pressured environment that you are drilling in with the Huron.

It is a great question.

I think the conventional wisdom would say that the overpressures would prohibit you from doing it.

And we -- just start with the Marcellus is not that overpressured, okay, so start with that.

Because I think if it was a 0.7, 0.8 grading, I think you probably could not do it.

You just had (multiple speakers)

Was it is .6 grading?

It is less than that actually.

It is 0.5 to 0.6 is why I understand over most of the play.

So it is really just more than hydro pressure.

So I think it is because of the fact that we don't have as much stalling and pushback.

Now keep in mind, in the Marcellus itself, we have not been able to drill horizontally with air very well.

We are getting a bit of hole problems, but in the competent units above, which are also slightly more than hydro pressured, we're able to drill that well, those wells.

And so the implications of being able to do the air drilling are quite substantial.

I mean, number one, the per well cost will go down, meaning the drilling cost will go down.

You still have the $1 million or so per well of fracturing cost.

But more importantly than that is we can drill the wells quicker, which means that we can drill more wells per rig.

And the rigs are smaller.

So we can drag them more easily around the Appalachian Mountains.

So what I'm most excited about on air drilling, if it turns out that we can continue to do it, is that the pace of drilling in the play could be accelerated substantially.

And that is what needs to happen for this thing to be a real big winner.

And so stay tuned.

I mean I would say we're cautiously optimistic about what is going on so far on that.

If you had to put -- understanding it is very early -- but if you had to put a likelihood on full-scale development ending up being air drilling as opposed to more traditional longer pressure drilling, what would you put it at?

I'm cautiously optimistic.

Fair enough.

Great.

I appreciate it.

Congratulations on a good quarter.

Shneur Gershuni, UBS.

Most of my questions have actually been answered, but I did want to go over one thing here.

When you talk about no need to access the capital markets for 2010, I know you are clearly not going to give 2010 CapEx guidance, but how can we think about '09 CapEx guidance in terms of how we would think about 2010?

And do we need to think of $900 million as kind of what you would be able to generate at the --?

No, I don't think so.

The comments that we made about midstream suggested that a number of the projects underway we're going to lead to an additional midstream capital expenditure in 2009.

Obviously with more leadtime, we would not need to do that in 2010.

no, it would be consistent with a lower capital expenditure in 2010.

Okay.

And how much flexibility do you have in this CapEx?

I mean are you concerned about loss of labor if you decide to reduce it even further?

I mean has the board talked about the fact that where are the stock prices right now relative to you guys are not even trading at proved reserves right now?

Has there been any thought about that, or is it more likely this is temporary --?

I certainly do not think it's lost on (inaudible) stock price is lower (multiple speakers).

At least the two board members in this room I will say (multiple speakers).

I think it has generally been recognized that there is a bit of an issue.

But I think your point is a very good point.

And that is hopefully a question that will become easier to answer in December as we lay out the business plan.

But if you just put some broad strokes on it, broad pieces on it, we need to commit to drilling rigs to drill the program.

And whereas that is an expense and there are commitments that we have made to drilling rigs, there is more flexibility in ramping up and ramping down there than there is in midstream.

Because think about it, once you are decide you are committing to big pieces of midstream, and the challenge is at least to date the midstream corridor projects have been very large projects.

You know, $100 million plus projects.

Once you kind of go down that road, it is hard to kind of stop.

You cannot stop -- either you're one foot short of completing the pipe, the pipe is not complete.

So now what we are doing, though, is we're trying to see if there are legitimate ways to shrink the size of the corridor projects to try to really more finally tune and match the drilling to the midstream, which is something we ought to do anyhow and to see if we can make that individual midstream expenditure a little little less painful in terms of its total magnitude.

Now having said that, one of the things that has happened over the last couple of years as a result of horizontal drilling is every time we drill a new well in some formation we find some new play that we like, like the Berea end the re-entry and all kinds of stuff.

So it has been difficult to be very surgical about putting in midstream assets.

So they are lumpier.

The midstream is lumpier.

And so it's a little more difficult to flip-flop on it.

And that is -- those are some of the issues we have to deal with in our plans.

And (multiple speakers) maybe philosophically you're trying to get at what happens on the people side, etc.

Like probably all oil and gas companies, we are -- certainly we're more familiar with the straight gas producers, of course.

But probably like all of them, we're re-examining all of our operating expenses.

We think we've probably got a fair amount of room on working capital, but it will take a little while to squeeze that out of the system.

That is another place to generate more cash beyond what we're talking about in '09.

So we're confident in that, but we're really just undertaking it.

But we are looking to protect those parts of the business that we think will fuel the more rapid growth when the capital markets clear up.

I mean we are operating under the belief that eventually it will be a little bit easier to get capital either from third parties or from the capital markets without predicting when that is going to be.

And what that means is that we're continuing to want to keep boats on the landside, for instance.

We're continuing aggressive efforts there so that we can more quickly get going on midstream projects and on drilling wells once we have got the desire to do so.

Same thing on the engineering front.

We want to make sure that we're engineering some of these projects so that as soon as we want to push the button on spending the money on a project whenever that happens to be, whether its three months from now or three years from now, if we are able to do so.

So while we're looking to fine-tune and cut expenses, working capital, etc.

across the board, we're definitely trying to protect the core of what we consider to be our growth opportunity.

So if that is the kind of thing that you are getting at, how do we kind of run into risk, we're very cognizant of the fact that it's one thing to trim, and it's a different thing when you start cutting off limbs.

And we're trying not to do the latter.

And the asset itself is so rich and bountiful that we have to have more and more, ultimately more and more engineering talent, more and more drilling talent, more and more scientific talent, land talent, operating people to get this thing to produce at the levels that the assets require it to produce if the reserves are really there.

We cannot have R over Ps of 50 or 60.

The reserves just will not be there.

So we're very aggressive and will be very aggressive in maintaining all of those people that are critical to ramp this business up.

Because it is our view that we will be ramping it up -- don't know when -- but ramping it up in the next year or two significantly.

So we're very conscious of that.

And I think from our people standpoint, too, I think it is important to know that even if we do not get capital for awhile, we can continue to grow, and we need them to continue to fuel the growth for the next couple of years.

And look, we can grow indefinitely living within our straight operating cash flow.

So it is not as if we can't.

We just don't think that is the optimal way to exploit this resource.

Okay.

Well (multiple speakers) I'm sorry, but I guess explanations are required in times of uncertainty.

No, no, absolutely.

I just kind of assumed that your flexibility would be on the E&P side.

But at the same time, on other E&P companies, as well as other (inaudible), you know access to labor has been a problem, and nobody wants to give up on anybody.

I agreed and we're not going to do that.

That is exactly right.

And fortunately for this Company either because we were prescient, which I would choose to favor that explanation, or lucky, which is another alternative, we have built a lot of midstream over the past couple of years.

And so we have got a lot to grow into, so to speak.

And we need the staff to do that.

As Dave said, we're going to trim everywhere we can trim.

Working capital, other things, to try to get every dollar that we can possibly get in cash available to be able to drill wells, and that is we're really working on that.

If I can, just one last follow-up question here.

And maybe it is completely irrelevant, but it's about proved reserves.

Clearly the market does not even care about that today.

But you have talked about your success with re-entry wells.

You've got I think over 4000 locations.

Granted if you go horizontally, you'll probably lose some locations and so forth, but net net you're going to bring on more gas.

Is there an opportunity for your year-end proved reserves to actually be rebooked as a result or at least some of the price to be re-booked?

Yes, I don't want to speculate on it because a lot of things are changing on this reserve.

When you change drilling technique as we would be in this re-entry from the expectation of continued vertical drilling to the expectation of horizontal drilling, there are some nuances that we need to address.

So I don't really want to project what will happen on the proved side.

Suffice to say that when we do our reserve report this year, we will try to make sure that you understand exactly what we have included in these various categories.

I think then you can make your judgments on the efficacy of those reserves and how soon you think they can be brought to market, regardless of what reserve category we end up putting these reserves in.

And I think a lot of -- for these shale plays, frankly, you have to do that anyhow.

You have to really interrogate management's decisions on how they have decided to count reserves.

We're not sorting our drilling program for what it is going to do to year-end booked reserves.

We're sorting based on how much volume we can get per dollar of CapEx.

We're sorting based on payback periods.

I don't think there has been a lot of talk in the E&P business about payback period lately, but it's something that we're looking at closely and we bet a lot of other companies in the industry are looking at as well.

And then the reserves, the booked reserves are going to fall out how they fall out.

Jim Harmon, Barclays Capital.

It is actually [Rick] and Jim.

We need a new business card.

We're working on that as we speak.

(multiple speakers).

What is on your mind?

Okay.

We have got a couple of questions to start with.

You keep talking about you have got a lot of capacity to sell.

How much is available and how much in terms of sales lawyers can you support under the current infrastructure?

We have done some calculations just looking at the Mayking, Big Sandy and Langley plant, and please don't get rationally exuberant with these numbers.

But plus or minus, there's an additional 110 to 115,000 a day of capacity plus or minus that we have got there that could go to sales volume, and of course, we're selling 245 or so right now.

So it provides the capacity for a significant increase.

Now the question that Dave and I are struggling with, or the problem that we are struggling with and the team is struggling with, is how surgical can you be in filling every one of those cubic foot of capacity up and how quickly can you do that?

And it is not -- just to preview it, you cannot just divert all of the resources to build that up in a year or in a day?

So we are -- but that is kind of the level of capacity plus or minus that has been created by this most recent capital program in the midstream.

Is that helpful?

That includes (inaudible) and takeaway?

It does although -- yes, it does.

And it would require us among other things to fire up the old processing plant at the Langley facility, which we intended to do -- well, we did not originally intend to do it, but we now are intending to do that, which basically puts Langley at 170 million a day of processing capacity.

New plant 100, old plant about 70.

Is there some -- under the new program, is there some minimum level of drilling you would like to pursue?

How many wells per year?

No, we're not sorting it that way.

We started -- Phil, did you want to say -- I say we started with the premise -- as we said earlier, we started with the premise that we cannot go to the capital markets, and then we sort of backed into or we are backing into yearly capital numbers, and then now we are further backing into the split between midstream and drilling.

And we just do not have those numbers all worked out just yet.

We have got 1000 cases if we assume everybody else in the sector has, too.

And we're going to have another communication in December after the board blesses the capital program.

So we will provide that kind of information then.

Okay.

You alluded to this earlier, but will the energy for the emerging play sampling suffer to a large degree if you have surgically fills?

I'm particularly interested in the Berea because --

No, Berea at this point is a core drilling area.

Okay?

Producing gas that gets to the sales leader from there.

Right.

So we may have to do some midstream tweaks or upgrades a little bit, but we feel that -- at least we currently feel that the Berea is such an important resource, and the well payouts particularly are so short that we may be willing to put a little bit of midstream in to make sure that we can drill a lot more Berea wells.

Yes, we were looking at some one-year payouts on some of these Berea wells.

So --

Okay.

One last quick one.

You mentioned refrac inventory.

Is there any way that relates or maybe not at all to the redrilling inventory?

You end up (multiple speakers) some prices (multiple speakers) and you cannibalize.

Pardon me, I missed that last part.

I guess you mentioned you may have a refrac inventory.

I did not know whether that was new wells drilled, and after a certain period of time, you would come in and refrac them, and you would kind of reset the type curve or the decline curve on whether this is, since you are thinking about refracing a lot of older wells, and this would have some interplay with the whole redrill program?

Yes, we could refrac vertical wells.

There is no question about it.

But the reason we went to the refrac program and the reason we went to vertical wells first in the refrac program, because they are already there.

We're just going to go down in there.

We do not want -- we don't have any reason at this point to refrac a horizontal well.

Not a lot of them have been on production for a long period of time.

We just wanted to experiment with verticals and then use the data from that experimentation (multiple speakers) to predict what we might get when we refrac eventually horizontals.

I'm not saying we will not refrac verticals routinely, but my thinking is on the re-entry and the redrill play where we've originally drilled vertical wells, we will go in, drill them with horizontals, which is very profitable, and then come back later on and refrac them.

(multiple speakers) Pardon me?

Order of magnitude after 12 or 18 months after the big declines?

That is why we're getting the data now.

I do not know what the timing will be on the refrac.

That is why we're starting that process now so that we can get some decline curves post refrac on the wells, and then we can make some economic judgments on what we should do.

Obviously the well is there; the pipe is there.

You do not have capacity problems.

Refracing is a very efficient use of capital if it turns out to be -- it turns out to work well.

So it basically goes to accelerating recovery not so much improving the recovery?

(multiple speakers)

I think that is right, but we need some data.

We need to follow these refraced wells to see if we're getting just accelerated production or if we're getting accelerated production and reserves.

Keep in mind, with these long-lived wells, if you can keep the production up, you might actually add reserves just because you are pushing the production up sooner, and then that the time that you get to uneconomic status for the wells, by the time you get there, you will have produced more, which means that reserves will be higher.

So it could be increased -- certainly will be increased production.

It could be increased reserves, too.

Annie Tsao, Alliance Bernstein.

I know you went through the liquidity.

Do you mind to go through that over again (inaudible) a little bit and get all the details?

Let me try to do it this way.

At September 30, '08, and this Q will come up tomorrow morning, it will have this -- we will have a net short-term debt position of $83 million.

We're anticipating as I mentioned in my comments fourth-quarter CapEx of about $450 million and then $900 million to $1 billion of CapEx in 2009.

So all those would add to short-term debt or takeaway from liquidity.

In addition, we have dividends through 2009.

These are about $140 million, and then I mentioned in my comments that our short-term debt balance will be $700 million to $800 million at the end of 2009.

The plug there is 2009 cash flow of $750 million plus remaining 2008 cash flow and other ins and outs.

So if you sort of work it through, that is how you get to the $700 million to $800 million of short-term debt at the end of 2009.

Is that helpful?

Yes.

Thank you.

And also when you talk about you are going to be re-examining all the operating expenses, is there timing that we should expect?

When would you disclose that in more detail?

It is just an ongoing look.

I think the biggest piece of the expense piece that Dave had talked about was really working capital, and then we have a fairly large -- we have been keeping a fairly large working capital -- providing for a fairly large working capital number.

We're just looking at all the ways that we can kind of reduce that, better inventory management, etc., etc.

So that is the biggest piece of that.

But I just review that as an ongoing effort.

(Operator Instructions).

[Carl Brown], Rebus Partners.

On the re-entry program, the fact that we have got 60 wells that have been drilled but they either haven't been completed or they are on for less than 30 days, is that just indicative of the pace at which this has accelerated, or is there some kind of a bottleneck where wells are getting drilled, but they are waiting to get completed, or they are waiting to get tied into a gathering line?

The former.

We have actually drilled a heck of a lot more in this re-entry program than we originally planned.

But it is the former.

Okay.

And if the decline curve is exactly the same on, say, virgin acreage, can you just remind us what the benefits are?

I imagine the drilling side itself is long gone, but is it just the fact that is already a road to the location, the location has been leveled, and the fact that there's gathering system?

Yes, I would not put too much stock in the cost benefits of the re-entry/redrill.

Because the vast majority of the wells are being redrilled, not reentered.

But yes, there is a pad there; there is a road there.

But the key to making that place successful is the enhanced recovery that we get from horizontal versus vertical well.

So it's just like -- these are just locations that we are increasingly coming to the conclusion are every bit as good as a non-drilled shale location.

But they've never showed up that way in our reserves report.

Every bit as good but not better and, therefore, is just added to the drilling inventory.

Yes, it just adds to the drilling inventory, exactly.

But it currently is not included in any of the reserves that we have got on our books, P1, P2 or P3.

Okay.

And then on the high-pressure Marcellus, in your mind is the jury still out as to whether or not you can get the same or better IRRs, whether or not you are talking about a vertical or a horizontal program or the vertical (multiple speakers)

Dave may want to comment.

I feel like there are three ways that we are considering developing the Marcellus.

One is horizontal wells.

The second is vertical wells and a third is sort of the S-shaped wells, pad drilling I guess is what you would call it.

And I would not say that we have a particular conclusion or even bias at this point.

Do we?

Would you say --?

No, I do think that in some cases, and Murry alluded to this, you just cannot drill horizontals into the Marcellus proper everywhere because of the size of the rigs, you know, access roads, etc.

So really maybe at some point the issue becomes more I think you kind of said at the outset, are we going to get more comfortable generally drilling what we think will be quicker, cheaper wells into the Hamilton and then frac into and through the Marcellus as opposed to horizontal into the Marcellus proper.

If you go into the Marcellus proper, you got bigger rigs properly, which means there are going to be more locations where you're going to say, maybe we will try it with a vertical.

I think it is early days.

We are kind of hoping that this quicker, cheaper approach of going to the Hamilton and fracing into, and again kind of all the way through in many cases, the Marcellus, will windup being the winner.

But we will see.

Right.

And then, of course, you add the air drilling component on there, that adds another dimension.

So I think the way I would conclude it so far is that we have been very pleased with the horizontal Marcellus results conventionally drilled.

We're pleased with the horizontal results from air drilled Marcellus where we have been able to do it so far, cautiously optimistic there, and we have been pleased with the vertical results.

And so I think we're not into sort of a thumbs up, thumbs down on one approach or another.

I think we're going to just be optimizing I think.

And incidentally it seems to us that there is not as much homogeneity geographically across the Marcellus play as you might expect.

It could well be that different tactics work better in different areas even within such a confined area as, say, Southwestern Pennsylvania.

We're noticing that there are differences, and we think if you talk to some of the other companies, there are a couple of others that are active in this area as well.

You know, the Ranges and Atlases, etc.

I'm sure they find the same thing, that there are differences from kind of sub-geography to sub-geography, and that might affect what you try to use.

And Murry, does the well costs that you reference in your comments as $3 million to $4 million on the vertical wells and on -- I'm sorry on the horizontal wells and then on the vertical wells, $2 million but more recently down to the $1.3 million range, does the air drilling benefit on the cost side?

Is that affecting either of those numbers, or is it -- (multiple speakers)

Primarily if the air drilling can be broadly applicable, it would be more likely to -- it will decrease the $3 million to $4 million number that I mentioned for the horizontal Marcellus wells.

But not the vertical number?

Not substantially.

We're drilling most of that with air anyhow.

Incidentally we should mention also that all of the prices that we give, all of the capital numbers that we give, are based on current drilling rigs rates and current casing costs.

Right?

Whereas obviously over time, I think it would be fair to say that both of those are under pressure (multiple speakers) downward pressure.

At a given steel price, though, the air drilling will impact the horizontal Marcellus wells positively.

It will positively impact the cost.

And I said 25%, but I think it's actually going to be more than that if it works consistently.

And then the last question, I had a question just about your PDP reserves.

I was curious if you could take a stab at what you thought hypothetically, if you stop all drilling activity -- I know that sounds insane, but just as a hypothetical -- if you stopped all drilling activity, what do you think the decline rate would look like for your PDP or today's production for the next couple of years, and what is the terminal decline rate for -- the average terminal decline rate for the wells that you have drilled do you think?

Well, I mean, of course, it is highly -- that calculation is -- and I think you can do that calculation actually -- because you know that the existing base of wells eventually declines at a 3% or 4% rate, and then the new wells we have given those decline curves out.

So it really depends at any moment in time on the mix of wells that are new versus wells that are old.

I don't think I have done that calculation.

You are talking about, what does a blow-down case look like?

We have probably run one of those -- I don't know exactly what -- (multiple speakers)

I don't know how many years out we have run it.

I mean realistically the lag issues we've talked about before meaning that the first year after you stopped you might actually see increases, right, because of the effects of volumes getting to market on capital you have already spent.

And then it starts declining, and then the decline curve obviously gets shallower and shallower to the point where you get to that 3% to 4% number.

We have not done -- I have not -- I'm not -- I don't have the knowledge of a blow-down case number.

Frankly, our view has been, gee whiz, only needing $150 million to maintain production; at that point you don't need really anything for midstream.

And most of our midstream assets are new.

So what type of replacement CapEx would you need for that really?

When would you ever get to that case?

The IRRs on that first $150 million or $200 million since we own so much of our own midstream is going to be so high that it is hard to imagine a circumstance where you would not do that.

No, I agree.

I wanted to get on some (inaudible) PDP reserves.

You're not even paying for all the PDP.

No, no, no.

Listen, if that is what you want to know, you're definitely not paying for all the PDP.

And, of course, the thing we keep struggling with, and I'm sure you all do, too, is when we come out every quarter and say that we have drilled 70% of our wells on nonapproved locations, what does that really mean in terms of the reserve base that is "proved?" It is a very, very difficult thing to -- it is a difficult calculation to make.

You should feel comfortable telling your wife that there is a bluelight special going on (multiple speakers) still available.

There appear to be no further questions at this time.

I will turn the floor over to Pat Kane for closing remarks.

Thank you, Jessica.

That concludes today's call.

The call will be replayed for a seven-day period beginning at approximately 1:30 Eastern time today.

The replay number is 706-645-9291.

The confirmation code 29614340.

The call will also be available on our website.

Thank you, everybody, for participating.

This concludes today's Equitable Resources third-quarter 2008 earnings conference call.

You may now disconnect.