EQT Corporation (EQT) Q3 2008 Earnings Report, Transcript and Summary

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. All lines have been placed on mute to prevent any background noise. After the speakers' remarks, there will be a question-and-answer period. [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 Murray 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, Murray 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'll open the phone lines up for questions. But first, I'd like to remind you that today's call may contain forward-looking statements related to such matters as our well drilling program, infrastructure development initiatives, reserves, reserve replacement ratio, financing plans, capital budget, capital expenditures, growth rate, and other financial and 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. I'd now like to turn the call over to Murry.

Thanks Pat. 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 had 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's cheap to implement, quick to implement in this Appalachia and 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 corridor strategy while time consuming to implement it is obviously working to a level frankly that has surprised me even. And the reason it surprised me, for the reason, it's really up, is that we drill 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 design spec. So, we're kind of hitting on all cylinders there. And very importantly, our team is strong, it's talented, it's driven. We have a culture here, 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 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's a very small percentage of our operating capital. Phil will talk to you about that in just a minute. And breakeven price is consistent with our lower midstream spend presuming this environment hangs on for a while and sort of a fill what we build strategy. At the breakeven price at 0%, IRR is about 250 NYMEX and make our cost of capital is about $5 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 and long-term value right now, I do care. And when this time of market stress passes, I believe the winners will be those who haven't abandoned innovation and we certainly haven't 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 as applied to the total asset base 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 of about 25% for at least five years and then continue to grow at a substantial rate beyond that given what we've had and what we're able to do in our ability to execute. I want to go onto a few operational statistics here, just try to update you from the quarter end. Total year-to-date, we've spud about 554 gross wells, horizontal wells so far 315 have been spud, and as we mentioned we're on pace to drill 375 horizontal wells this year which is up 25 from our last estimate. Just to remind you that the total horizontal wells we've 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 know that 71% of the wells 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 is 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. And as you can tell many of the wells we drilled aren't on proved locations. And although this isn't sort of an audited number, we think that 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 coal-bed 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 are bread and butter so to speak. We've spud 295 wells this year. Drilling results continue to confirm both the economics of the play and the decline curves we previously published. On the emerging plays, and again these are plays that we have no 3P reserves booked. I'll go through a couple of them. But anyhow the Berea, we now have 15 horizontal Berea wells and seven of them are 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 Berea are projected to be about $1.4 million to $1.5 million. 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, filthier targets, sandier targets, limier targets. We've got a well that we're going to spud in the Ravencliff, 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 Berea. 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 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 re-drills 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 at 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've done our first stacked multilateral well, and we're 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've spud 13 wells in this play, 4 horizontal and 9 vertical. We've turned inline seven of those wells. Two horizontal wells, one is in Greene County, one in Doddridge County West Virginia, the 30-day IPs are 1.3 to 2 million cubic feet per day and the costs are expected in the Marcellus, the horizontal 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, and Ritchie County, West Virginia; and Gilmer County, West Virginia. Three wells have 30 day IPs and those are averaging about a 0.5 million cubic feet per day. The first well costs $2 million. First vertical costs $2 million, the next two costs about $1.3 million, so we're getting a pretty good learning curve there. So as we mentioned last time, we're continuing to be encouraged by this play and by the end of '09, we plan to drill at least 75 Marcellus wells. As we mentioned in the release we are experimenting with air drilling in the Marcellus, we've 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 to 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 refract of a vertical well, vertical shale well. The well was drilled in 2002. We refraced with nitrogen over a fairly broad interval, and we've 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're hopeful that after all these horizontal wells have been drilled that there will be a whole number round of refracing to occur after that. So, that's sort of a drilling update, production update. On midstream obviously we are pleased with the progress of the build-out, as it is detailed in the pres release. Strategically since it came 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 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 recognized that these projects would take a while 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 and we think that the volumetric results that we have seen in the third quarter and that we are projecting for the fourth quarter in the future attested benefits of that midstream effort. However at this point, given the uncertainty in the capital markets we are making plans to slow down midstream development somewhat and focus our capital spending as much as possible in the 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 build. As you know, we've 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 cost to EQT, of drilling near this midstream capacity is very low, as much as the gathering and compression, charge report in production as the transfer to the midstream unit. However, there is no question that the costs of contractors in 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'll benefit as those pipeline construction costs decline as they have now started to do. Fortunately, as I said we built enough pipelines and processing 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'll turn the call over to Phil for the financial details of the quarter.

Equitable announced earnings per share of $0.73 for the third quarter of '08 as compared to earnings per share of $0.27 in the same quarter last year. As Murray just discussed from an operations perspective we had our best quarter ever. I will briefly review the reported results and then spend sometime on our capital plans and the related funding of those plans. Starting out with productions, as you saw in our 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 more appropriate [ph] '07. Those incremental unhedged volumes as well as a significantly higher Nymex price resulted in an average well sales price of $5.52 per Mbtu 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 allowances for bad debt were both higher in the quarter, directly reflecting the significant increase in Nymex during the early 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 account for the remaining $3.3 million of the operating expense increase. Moving on to the midstream business; operating income here was also a 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 on line this year as Murry just talked about. We have 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 and Mayking corridor added to the new volumes and resulted in increased operating revenues and operating income at midstream. These investments in infrastructure 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 has 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. Couple of other items, I want to talk about before we turn 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 of '08 of previously recorded compensation expense. Executive incentive compensation expense, including the reversal, resulted in approximately $70 million of credit in the current quarter which represents an $80 million swing from the $10.3 million expense recorded in the third quarter '07. The reversal was based on a stock price assumption of $37 and a multiplier of 1.7 times which were the existing conditions at quarter end. As we discussed in the past, the final plan expense will be determined by the year end stock pricing and multiplier. Now some of you may recall the two main reasons for choosing this current plan structure were one, it clearly tied 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 expense 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 perform shares and options. However, the amounts are much lower as we have returned to the practice of annual awards versus the multi-year plans we have been using for most of this decade. The philosophy around long-term incentive program for management continues to evolve although at Equitable, incentives 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'd like to do in conclusion is briefly walk through 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 at the EPIP expense reversal shows up as operating cash flow even though it mainly implies to previous periods. And there isn't cash until the end of the year anyway. So striping out the effects of compensation expense reversal as well as tax refund that won't be received until 2009, would leave to a normalized operating cash flow in 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've 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 added up 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 a $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 that I told, if the current $7... as a $7.50 Nymex strip prevails, we anticipate generating available cash flow including the tax rate fund of $700 million to $750 million in 2009. Returning to the effective sales price 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 of the result of our drilling program which is current 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 loss 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 2009 Nymex strip is 750 or approximately $50 lower than Nymex is currently projected to run in 2008. Moving on to CapEx; we spent about $960 million through the third quarter and anticipates spending another approximately $450 million in the fourth quarter for a total of $1.4 billion for full year 2008. But we have said we are currently developing a plan to spend $900 million to $1 billion of CapEx in 2009 and we'll 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, that balance is expected to rise to above $700 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 that with our $1.5 billion revolving credit facility that expires in the fourth quarter of 2011. I should point out that only about $1.4 billion of that facility, that's currently available. And Lehman Brothers held $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, that's why we are confident, we can fund capital plans for the next couple of years, that will generate 12 plus percent sales growth without having to go to capital market. 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 bolster our liquidity and move towards the 20 plus percent growth potential 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 portions of the call. Jessica can we please now open the phones for the questions. Question And Answer

Thank you. [Operator Instructions]. Your first question comes from Scott Hanold with RBC Capital Markets.

Good morning.

Hey Scott.

Murry can you talk about production little bit obviously looking at a you know 250-260 exit rate and based on your activity levels, its looks like production could be a good 15% to 20% next year and you have obviously talked about bringing in capital and having various growth outlooks and can you kind of lend some color on what you expect at those spending levels here in year '09?

Well. We haven't finalized the plan yet Scott. Obviously its going to be somewhat fluid, but suffice it to say that we're still holding control plus will come back in December and talk about what that number is or obviously choices that have to be made between, absolutely adjust filling up precisely what we've already built versus providing some capital commitments for the future either our own or someone else's so I'd like to stick to that 12 plus at this point of time. You correctly point out that as the current ramp up of sales that we've seen at least for the first couple of quarters next year, you're going to see some pretty healthy quarter-on-quarter growth, but you know it drilling doesn't ramp up to it's full potential that quarter-on-quarter rate will diminished, because we'll be drilling into these kind of big quarters that were having right now and in the fourth quarter, so let's stick to the 12 plus percent and will come back in December with more data.

Okay and then maybe I can try... you 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 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 in the to put our drill rigs right where that capacity is. And that's really why we need to a little bit more time to come with a number.

Okay fair enough. Turning to the Marcellus, it sounds like you've got a couple of the horizontal wells, can you give a little bit more color on that second well and where the first well is at? And I think that, I recall the first well we drilled up in Hamilton and kind of talk about what kind of... when you went horizontal into that second well?

Yes. We continue to think that Hamilton is a good place to drill the horizontal well. We tried a horizontal first, horizontal air drill well, we did in the Hamilton and the second one we started in the Hamilton and drifted down into the Marcellus. And it's a little more difficult in the Marcellus to drill horizontal. So, nothing has really changed, we think that from the standpoint of operations, the Hamilton is more competent and 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 drill exclusively at the Marcellus. The problem is right now for the wells that we've drilled, it's been a little more difficult to drill horizontally in the Marcellus. I think the jury is out, we are satisfied with the results of drilling in Hamilton. We just don't know if they can get better that those results will be improved by drilling strictly in the Marcellus.

Okay and so then I guess the subsequent horizontal wells will be drilling, what zone are you targeting? Are you just going to 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 keep getting... if its gets thwarted we will continue... we will drill in some more competent zone.

Okay and one last question, any update on that on that Utica well.

No, we're still in that 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 are going to do that sooner or later and when we drill later, if we drill, we liked it, frac both at the same time. So we're sort of on a little bit of hold on the Utica at this point.

Okay, on that first well there. Anything you saw, I know you, even at frac yet when [indiscernible] slowdown.

We did attempt to frac, we just didn't get it up to kind of level. We didn't bring in as the larger frac equipment as we probably need.

Okay, okay well can you say anything about the reservoir slowing down there.

No. it's not. We don't... we have not sufficiently tested the Utica yet. Because we haven't fraced it to the level that it needs to be frac.

Okay, understood.

Your next question comes from Michael Hall with Stifel Nicolaus.

Thanks. Real quick drill down a little bit more on the CapEx spending and the growth plans, you talked about for the 700 to 750 of operating cash flow in that $900 million to $1 billion CapEx number, so you calling at a 130% cash flow with the mid point, that drives around 12% growth. And then you talked about the 25% plus kind of growth rates, how much more capital you think you would need to of those levels as a percentage of unexpected cash flow or is that a 150% or 175% or can you help to think about that? How much more capital?

In general, I think our plan... keep in mind that is a lot of moving parts here. In the 2008 capital, it was 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 didn't anticipate that we'd have a continuing need for as much midstream capital as a percentage of the total. On the other hand, we felt because we 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 in if their capital markets were down as much as we spent in 2008 and possibly more and we would have been encouraging people to that because we'd wanted to ramp the drilling up. Dave, did you want to say anything?

Our internal models would have shown that we would have may be spent 15% or so 50-60% more capital in 2009, but then those internal models just to you now were also equate to a more than 30% volume growth in 2010 over 2009 keeping in mind of course that in this business for us well other companies for the most part there is a lag of lets call it six to nine months between the capital spending and what shows up in the volumes. Nine capitals really lead more to 2010 volumes than it does to 29 volumes. I understand if you spend it in first quarter, then you get the benefit in... start getting the benefit in the same calendar year. But the other thing is that as we've mentioned, we built fixed Sandy etcetera, we had talked a lot about how we were... we have looked for a third party mid-stream companies to work with us on those and we built those things on our own in part because we couldn't find any of those, and that's a change. We actually find that still change. So its definitely the other moving piece for us as far as figured out what our capital expenditure would be is that there has persistent in being more interest on the part of third party mid-stream companies in getting more of a foot hold in the Appalachian basin and those are discussions that we are... that we continue to encourage, that obviously slowed down a little bit in this environment, but the fundamental interest still remains there. And obviously, the more you lead in that direct... in all the CapEx we've been talking about is been we going to do whole thing ourselves. But I guess why I am indicating is when the CapEx... the capitals market ease up, then there is a decent chance that a fair amount of that mid -stream capital comes from third parties not from equity which Murry eluded to in his comments so as... a reference to partnerships. That's another moving part that makes it difficult to assess and you're going to get more leverage for capital, of course cash cost on a pocket line up being higher, right because they are gathering a compression cost that you pay, the transmitted costs are all cash cost whereas right now its basically DD&A at the corporation. Does that help you kind of get a sense of what we are talking about?

I think yes it's certainly helpful. And it sounds like then the real pending income around the discretionary, more discretionary piece of it, the rest is maintenance. But just the sewing piece I guess, it's more midstream

Yes, it's definitely midstream. And I think what Dave is right. I mean had there been a perfect world, we probably would have had... presuming that they would have wanted to react to our needs, having a midstream partners 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 that ourselves. And we're not just satisfied with that. I think the pace at which we've been able to grow is a result of our having been very responsive on midstream so the needs of the production and should have some business units. But at this moment in time, when you're having to make choices right, the swing is capital spending is a mid-stream dollar.

And so that's sort of the incremental returns on the midstream are lower than frankly?

Wellyes. And with the payouts are a little bit longer, I mean they make EBA 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 in drilling and not in mid-stream.

Yes, just keep in mind, as far is midstream, it is true midstream returns are lower. You often keep getting the money for a longer period to time. Overtime it is less gas price sensitive.

Right.

It is definitely a little different. It's a different cost of capital and so the way we look at things around, we've always looked at EDA. I mean to get a good spread, but the point right now is that if you have to make a choice, it's hard to put the next dollar in midstream like today.

Because you get the payback so much quicker.

So I think all this is obviously where this crisis meets mainstream, right? I mean we're having to make the least worse choice. We'd 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. The comment that Murray made about some of the silver line of slowing down and the stuff that we are talking about even before this capital situation about in the market place and steel prices you just gotten out of hand. We really only started to see the jump. We have seen the downturn in those indices, but we're still the October prices, but the stuff we look at maybe are equivalent now to the August prices. They're below the September prices right, but they're 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 economic and all the stuff starts looking a lot better.

Great that's very helpful. I appreciate the color. One more line of questioning. Just talk a little bit more about the air drilling in the Marcellus and then kind of help me out in thinking about air drilling in the overpressured environment as opposed to the more normal pressured that you are drilling in. I would appreciate a lot?

It's a great question. I think the conventional wisdom would say that the overpressures would prohibit you from doing it and keep it, just with the Marcellus isn't that over pressured. Okay, so start with that, because I think it was up 0.7 to 0.8 grading, I think we've... you probably couldn't do it.

You said it was 0.6?

It's less than that actually. It's 0.5 that 0.6 is why I understand over most of the play. So it's really just more than hydro pressured. So I think it's, because of that fact that we don't have as much stalling and push back. Now keep in mind in the Marcellus itself we haven't 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 air drilling are quite substantial. I mean number one, the per well costs will go down, leaving the drilling costs to go down. You still have the million dollars or so of per well of fracturing costs 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 that more easily around the Appalachian mountains. And so, what I'm most excited about, their 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's what needs to happen for this thing to be a real big winner. And so, we stay tuned. I mean we are cautiously optimistic about what's going on so far on that.

If we had it further, we're understanding it's very early. But if you got to put a likelihood of full scale development and that being air drilling as opposed to traditional overpressured drilling what --

Matt,I'm cautiously optimistic.

Fair enough. Well, I appreciate it. Congrats on a good quarter.

Thanks.

Your next question comes from Shneur Gershuni with UBS.

Hi, good morning guys.

Good morning.

Most of my questions actually have been answered but I did want to go over one thing here, you talked about no need the access to capital markets through 2010. I know you are fairly not going to give 2010 CapEx guidance but, how can we think about the '08 and '09 CapEx guidance in terms of how you think about in terms of 2010? Do we need to take $500 million is kind of what you need to able to generate anything?

No, I don't think so, the comments we have made about midstream suggest that number of projects we're underway will going to lead to an additional midstream capital expenditures in 2009 obviously with more lead time we would need to do that in 2010. So no, we would we 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 cost of labors as you decide to reduce even further? I mean has the Board talked about this asset, where the stock price is right now relative to... I mean you are not trying to get proved reserves of it right now, has there been any thought about that or it's more like just temporary --

I certainly don't think it's lost [ph] the stock prices low, at least the two Board members in this room I will say. So we could speak as we I think its generally which generally been recognized as a bit of an issue. But I think your point is a very good point and that's 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 where is that isn't 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 a midstream because you think about it. Once you decide you are committing to big pieces of midstream and the challenges at least today, the midstream corridor projects have been very large projects, $100 million plus projects. Once you kind of go down that road, it's hard to kind of stop. You can't stop either you are one foot short of completing the pipe, the pipe's not complete. So now what we're doing though is we're trying to see if there are legitimate ways to shrink the size of corridor projects to try to really more finely tune and match the drilling to the midstream which is something we ought to do at any how. And to see if we can make that individual midstream expenditure a little less painful in terms of its total magnitude. Now having said that, one of the things that happened over the last couple of year as a result of horizontal drilling is every time we drill in some formation, we find some new play that we like, like the Berea and the re-entry and all kinds of stuff. So it has been difficult to be very surgical about putting in midstream assets. So they're lumpier. Midstream is lumpier and it's a little more difficult to flip flop on it. And those are some of the issues we have to deal with.

And maybe philosophically you're trying to get it, what happens on the people trying et cetera. Like probably all oil and gas companies, we are certainly, we are 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 probably got a fair amount of room on working capital, but it will take a little a while to squeeze that out of the system. That's another place to generate more cash beyond what we're talking about in'09. So we're confident in that, but we are 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 would 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 are continuing to want to keep boats on the landside for instance. We're continuing aggressive effort there so that we can more quickly get going on mid-stream projects and on drilling wells, you know once we have got the desire to do so, same thing on the engineering front, you want to make sure that we are 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, we are able to do so. So while we are looking to fine tune and cut expenses working capital etcetera across the board we are definitely trying to protect the core of what we consider to be our growth opportunity so that's a kind of thing that you are getting you know how do we kind of running the risk we are very cognizant of the fact that its one thing to trim and as a different thing when you 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 if the reserves are really there. I mean we can't have IP [ph] 50 of 60, otherwise the reserves just won't be there. So we're very aggressive and it 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. I don't know when, but ramping it up in the next year or two significant. So we're very conscious of that and I think from our people standpoint too I think it's important to know that even if we don't get capital for a while, 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't indefinitely living within our straight operating cash flow. So it's not if... we just don't that's the optimal way to exploit this resource.

Okay. I am sorry but I guess explanations are required in times of uncertainty.

Yes absolutely. I just... I kind of assumed that your flexibility would be on the E&P side, but at the same time I mean on other E&P company as well as other lobby exits [ph] your access to labor has been a problem, nobody wants to give us...

Yes, I agree and we're not going to do that. And that's exactly right and fortunately for this company either because we were pressured which I choose to favor that explanation or lucky which is another alternative. We've built a lot of mid-stream over the last couple of years. And so we've 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, try to get every dollar that we can possibly get in cash available to able to drill wells. And that's where -- we are really working on that.

If I can, just one last follow up question, and maybe it's completely irrelevant, but it's about food reserves and clearly the market doesn't even care about that. But you talked about your success with reentry well, you've got to think over 4000 locations, and granted if you go horizontal on least of locations and so forth that net, net, you are 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 of the reserves [ph]?

Yes I don't want to speculate because there is a lot of things changed on this reserve and when you change drilling technique as we would be in this reentry from the expectation of continued vertical drillings, 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'll try to make sure that you understand exactly what we've included in these various categories and 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 reserve category we end up putting these reserves in. So and I think a lot of pretty shale price frankly you have to do that anyhow. You have to really interrogate management's decisions on how they have decided to count reserves.

We are not sorting our drilling program for what is going to do to year end booked reserves. And we're sorting based on how much volume we can get per dollar of CapEx, we're sorting based on payback period. I don't think there has been a lot of talk in the E&P business about payback period lately but it is something that we are looking at closely and we better allow other companies in the industry are looking at as well and then the reserves, the book reserves are going to fall out how they fall out.

Okay great, I thank you very much guys.

Your next question comes from Jim Harman with Barclays Capital.

Morning it's actually Rick and Jim. How are you?

Hey we need a new business card.

We are working on that as we speak.

Sorry about that.

What?

What's on your mind?

Okay, we have a couple of questions to start with, then you keep talking about you have got a lot of capacity to sell, how much is available and how much in terms of sales volume can you support under the current infrastructure?

Yes 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 is an additional 110 to 115,000 a day of capacity plus or minus that we have got there, you know that would go to sales volume and of course we're selling 240 or 245 or so right now, so it provides the capacity for significant increase. Now the question that Dave and I are struggling with it 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's not just the preview, you can't just divert all of the resources to fill that up in a year or in a day. So, we're but that's kind of a level of capacity plus or minus that's been created by this most recent capital program in the midstream. Is that helpful?

That includes [indiscernible]and takeway?

It does although yes. It does and would require us among other things to fire up the old processing plant at the Langley facility which we intended to do at well. We've been... 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. You planned a 100, I will plan about 70.

Thank you there, is there some, under the new program. Is there some minimum level of drilling you might pursue?

I don't know. I'm in well for the year. We haven't sorted it that way. We started with the premise, that we can't go to the capital markets. And then we sort of bake into or we're baking into yearly capital numbers and then now we're further baking into the split between midstream and drilling and we don't just have those numbers, all we've got just --

We've got thousands cases, as everybody else in the sector has too.

And Jim, we're going to have another communication in December after the Board blesses the capital program, so 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 --

I'm particularly interested in the Berea, because.

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 mid-stream tweaks or upgrades a little bit. So 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 put a little bit more mid-stream in to make sure that we get... we can drill a lot more Berea well.

Yes, we are looking at some one-year payouts from 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 re-drilling inventory? You end up with some prices and cannibalized in this --

I guess, you mentioned you have refracs inventory, I didn't know whether that was new wells drilled after certain period of time you can only refract them and you kind of reshut the tight curve, the decline curve, and whether this, since you are thinking about refracing a lot of older wells in which you have some interplay with the whole re-drill program?

We could refract verticals wells, no question about it, but the reason we went to the refrac programs, at the 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 refract the 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 to predict what we might get when we refract eventually horizontal, but nothing we'll refract verticals routinely, but my thinking is on the re-entry and the re-drill play where we originally drill vertical wells we will go in, drill then with horizontal, which is very profitable and then come back later on and refrac them.

The order of magnitude after 12-18 months after the big declines?

That's why we're getting the data now Rick. I don't know what the timing will be on the refrac. That's 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 you know what we should do, obviously the wells there, the pipes there you don't have capacity problems refracing is a very efficient use of capital, even it turns out to be, you know turns out to work well.

Okay, it just basically goes to accelerating or recovering, not so much improving to recover.

I think that's right but we need some data. We need to follow these refrac wells to see if we are getting just accelerated production or if we are getting accelerated production and reserves. And keep in mind with this long wide wells that you can keep the production up, you might actually add reserves just because you are pushing the production you know up sooner and then that's the time to the time that you get to the economic status for the well. By the time you get there you will have produced more which means the reserves will be higher. So it could be increased, certainly will be increased production, it could be increased reserves too.

Okay thanks.

Your next question comes from Annie Tsao with Alliance Bernstein.

Good morning everyone. I know you went through the liquidity. Do you mind go through that over again a little bit and get all of detail...

Okay, let me tell you this way, September 30 of '08 and then this Q come up tomorrow morning, and we will have net short term position of $83 million. We are anticipating, as I mentioned, in my comments fourth quarter CapEx of about $450 million and then $902 billion of CapEx in 2009. So all those would add to short term that will take away from liquidity. In addition, we have dividends through 2009, use about a $140 million, and then I mentioned in my comments that our short-term debt balance would 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 on another ins and outs. So we sort of work it through that's how you get to the seven to $800 million of short term debt at the end of 2009. Is that helpful?

Yes thank you. And also when you talked about you are going leave examining all the operating expenses, do you see a timing that we should back or when you would expose that more detail for?

I think it's just a non-billing work. I think the biggest piece of the expense piece that David talked about was really working capital. I mean we have a fairly large... we have been keeping a fairly large working capital of providing for a fairly large working capital number and we're just looking at all the way that we can kind of keep that... reduce that better inventory management etcetera. So that's the biggest piece of it. But I just review that as an ongoing effort.

Thank you.

[Operator Instructions]. Your next question comes from Carl Brown with Rebus Partners [ph].

Hi guys. Can you hear me?

Yes.

On the reentry program, the fact we've got 60 wells that have been drilled but there are either having been completed or there on in less than 30 days, is that indicative of the pace at which you accelerated or is there some kind of a bottom that we're wells are getting drilled but they're waiting to get completed or they're waiting to get tied into a gathering well?

The former. We've actually drilled a heck of a lot more in this reentry program than we originally planned.

But it's the former that... and its the decline curve is exactly the same on Virgin acreage, can you determine that what the benefits are and that when the drilling path itself has long gone but it's just a fact that there is already a road to the location, the location has been leveled and the fact that they are gathering?

Yes,I wouldn't for too much stock in the cost benefits of the reentry/re-drill because most of the vast majorities of the wells are being re-drilled not reentered. But yes, there is a path there, there is road there, but the key to making that place successful is the enhanced recovery that we get from horizontal versus the vertical well. But it's just like these are just locations that we're increasingly coming for the conclusion. Our every bit is good as a non-drilled shale location, but they never showed up that way in our reserve reports.

So everybody is good, but not better and therefore is just added to the drilling.

And it just adds to the drilling inventory. But currently it's not included at any of the reserves that we 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're talking about vertical or horizontal program or vertical.

Dave may want to comment. I feel like there are ways that we are considering developing the Marcellus. One is horizontal wells, second is vertical wells and the third is sort of the S shaped wells, pad drilling I guess is what you would call it. and I wouldn't say that we have a particular conclusion or even bias at this point. No I do think that the some occasions, Murry alluded to this. You just can't drill horizontals into the Marcellus proper everywhere because of the size of the rigs, access roads, et cetera. 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 the frac into and through the Marcellus as opposed to horizontal into the Marcellus proper. And if you're going to the Marcellus proper, you probably got bigger rigs probably, which means, there is going to be more locations where you are going to say aah, maybe we try with the vertical. I think it's early days, we're kind of hoping that this quicker, cheaper approach of going to the Hamilton and frac into and again, all the way through the Marcellus will wind up being the winner but again a little proofing.

Right and then you add... because you add the air drilling component on there that adds another dimension. So I think the well we've concluded so far, Carl is that we've been very pleased with the horizontal Marcellus results conventionally drilled. We are pleased with the horizontal results from air drill Marcellus where we've been to able to do it so far at cautiously optimistic there. And we've pleased with the vertical results. And so I think we are not into sort of thumbs up thumb down on one approach or another, I think we're going to just be optimizing I think.

And immediately it seems to us, there is not as much homogeneity geographically across the Marcellus play as you might expect. Yeah you could well be that different tactics were better in different areas even within such that you can find area as South Western Pennsylvania. We are noticing that there are differences and we think if you talk to some of the other companies and there are couple of others that are active in this area as well. The Ranges, the Atlases et cetera, I am sure they find the same thing that there are differences from kind sub geography to sub geography and that might affect what you try to use.

And Murry and the well costs you referenced in your comments as three to four million on vertical wells, and I am sorry on the horizontal wells and then on the vertical wells, $2 million but more recently down to $1.3 million range, air drilling benefit on the cost side, is that affecting other those numbers or is it?

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

And but not the vertical numbers?

Not substantially, we're drilling most of that area anyhow. And 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 rig rates and current casing costs. Right over is obviously over time I think it will be fair to say that both of those are under pressure. A downward pressure.

At given steel price at a given steel price further, the air drilling will impact the horizontal Marcellus wells, positively impact the cost. And I said 25% but I think it's actually going to be more than that, if it works consistent.

And then last question on, I had a question about your PDP reserves, I am was curious if you could think of that of what you thought, hypothetically if you stop all drilling activity under the terms, I am saying but, just as a hypothetical, if you stopped all drilling activity what do you think the decline rate would be, would look like for your PDP or your today's production for the next couple of years? And what's the terminal decline rate for... the average terminal decline rates for the well you drilled you think?

Well I may not be inquisitive. It's highly that calculation, and I think you can do that calculation actually because you know that the existing base of wells eventually declines at 3% or 4% rate and the new wells given those declines curves out so really depends at any moment of time on the mix of wells that are new versus wells that are old. I don't think I've done that calculation.

You are talking about, where's the blow down case look like, probably exactly what --

I don't know how many years out, we've run it, and I mean realistically the lag issues we've talked about before meaning that the first year after you stop you might actually see increases. Okay so the effects of volume hitting the market and capital we've already spent. And then the declining curve obviously gets shallower and shallower to the point where you get to that 3% to 4% number.

I don't have the knowledge of a blow down case number. Frankly, our view has been, 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, you know what type of replacement CapEx would you need for that really, when we get to that case that will be IRR on that first $150 million to $200 million bucks. Since we own so much of our own mid-stream it's going to be so high that it's hard to imagine a circumstance where you have do that.

Okay, I agree. I was just... I wanted to be able to tell my wife they were on the same PDP reserves. And you are even paying for all those.

No. Listen if that's what you want to know, you're definitely not paying for all the PDP there. And of course and the thing that we keep struggling with, but I am sure you all do too is when we come out every quarter and say that we've drilled 70% of our wells on non-proved locations, what does that really mean in terms of the reserve base that is on proved, it's a very, very difficult thing to... it's a difficult calculation to make. But you should feel comfortable telling your wife that there is a blue light special going on... it's still available.

All right, thanks that's all I had.

All right, thank you.

There appears 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 296-143-40. The call will also be available on the website. Thank you everybody for participating.

This concludes today's Equitable Resources conference call. You may now disconnect. .