EQT Corporation (EQT) Q2 2008 Earnings Report, Transcript and Summary

Good morning, ladies and gentlemen, my name is Sharon and I will be your conference operator today. At this time I would like to welcome everyone to the Equitable Resources second quarter 2008 earnings conference call. At this time all lines have been placed on mute to prevent 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, Sharon. Good morning, everyone. And thank you for participating in Equitable's second-quarter 2008 earnings conference call today. With me is Murry Gerber, Chairman and Chief Executive Officer, Dave Porges, President and Chief Operating Officer, and Phil Conti, Senior Vice President and Chief Financial Officer. In just a moment, Phil will briefly review a few topics related to the second quarter financial results which were released this morning. Then Murray will provide an update on our drilling program and midstream projects. Following Murray's remarks, we'll open the phone lines 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, financial plans, capital budget, growth rate, and other financial and operational matters, including daily sales volumes. 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 are listed in today's earnings release, the MD&A section of the company's 2007 form 10-K, the 2008 second-quarter 10-Q that will be released today, as well as on our web site. With that I'd like to turn it over to Phil Conti. Phil?

Thanks, Pat, and good morning, everyone. Thanks for joining us. Earlier today, Equitable announced earnings per diluted share of $0.44 in the second quarter of 2008. That compared with earnings per share of $0.87 in the same quarter last year. You will recall that the second quarter of 2007 results included a $119.4 million gain from the sale of our Nora properties to range resources which distorts the year-over-year comparison. However, operating cash flow which does not include any cash from the 2007 divestiture was up significantly in the quarter versus 2007 due to higher operating income at production and mid-stream as well as due to lower cash taxes and lower executive compensating expenses. I will briefly elaborate on each of those topics before turning the call over to Murray who will provide an operational update. Starting with production as you saw in the release, production operating income was up significantly versus last year. The primary drivers of the improved results were higher natural gas prices and higher sales volumes. The average well-head sales price which includes the effect of hedges was 28% higher than last year at $6.14 per MMBtu. The increase in the average well-head price was driven by NYMEX, which was up approximately 45% in the quarter versus 207. Sales volumes were also higher in the quarter. We reported sales of just under 20 Bcf, which on a reported basis was approximately 3% higher than last year. However, when you normalize for the fact that we still own the Nora properties for about half of the 2007 second quarter, sales volumes were up almost 6.5%. Expected gas flow disruptions as we continue to bring midstream projects on line are suppressing sales in the short run. So overall the sales volume growth in the second quarter was right on track with our expectations as we progress to our double digit sales growth rates. Higher operating expense has offset a portion of the benefit from higher prices and volumes. Approximately half of the increase in operating expenses was for DD&A which reflects our increased drilling expenditures, and planned SG&A expenses as we continue to ramp up in preparation to drill even more wells and sell more gas. The remainder of the increase was gas price driven as production taxes and allowance for bad debt were both higher in the quarter, directly reflecting a significant increase in the NYMEX. Moving on to the midstream business briefly, operating income here was also a little higher at $23.6 million versus $20.7 million in the quarter last year. The increase was due to three main factors, first higher gathering rates, second, higher natural gas liquid prices, and finally the revenues from the big sandy pipeline which was brought on line during the quarter. Offsetting these factors in the quarter-over-quarter comparison would lower gathered volumes as a result of the Nora joint-venture transaction in the second quarter '07 and again higher operating expenses as a result of our ramp-up. We've discussed the higher gathering rates in the past and the higher liquids prices, I believe, are self-explanatory. After the Big Sandy pipeline the project did come on line in the second quarter and started generating operating revenues and operating income. We have been reporting Allowance for Fund Used During Construction or AFUDC associated with that project as other income in the midstream unit while the project was being constructed, and prior to it being commissioned. In the current quarter, because the project came on line partly through the quarter, we actually had some AFUDC and some operating income from Big Sandy. But going forward you will see other income from the project go away and more than be replaced by operating income as we continue to ramp the project up with the completion of Langley. Moving on to the distribution company, distribution had slightly lower operating income versus last year. Although due to seasonality, the second and third quarters are not material from an operating income standpoint of distribution. Weather was slightly warmer in the quarter and expenses were slightly higher resulting in the approximately $1.4 million reduction in operating income. One thing you may have noted in the release is the increase in bad debt expense in the quarter of distribution. We have seen more customers participate in our payment assistance program. However, I should point out that the increased cost of that program is being funded by a higher surcharge we began receiving earlier this year. So net-net the increase in bad debt expense has not impacted the bottom line. And as mentioned in the release, we did file a base rate case at the end of the second quarter to increase rates charged to customers by $51.9 million. And that was Equitable Gas's first base rate case in more than 10 years. I want to touch on a couple of other quick matters. First I did mention that the executive compensation expense was down in the current quarter versus last year. In the second quarter '07, we took a $21 million charge, a significant portion of which was due to an increase in the price and multiple assumptions around our executive performance incentive program or each of those we refer to it. This program with the recent significant drop in stock prices, we did not take any additional charges associated with that program in the second quarter, reflecting the fact that at the current stock price and multiplier, we are more than fully accrued for that program. We had provided some sensitivities for various stock prices and potential remaining EBIT charges for the second half of '08 in the queue that will be released later today. Footnote on operating cash flow. I mentioned it was significantly higher quarter-over-quarter, as expected, due to higher operating income. However, the increase was also driven by the fact that the deductions we received for accelerated tax depreciation and the tangible drilling cost from our midstream and drilling investments are dramatically reducing our cash tax payments versus prior periods. I should point out that in this particular quarter, if we took net income and added back DD&A and the non-cash portion of taxes on income generated just in this quarter, you would have... you would get a smaller operating cash flow result, more like about $117 million versus the $162 million we reported in the release. Although still significantly higher than the $66 million run rate on operating cash flow for the company from a year ago in the second quarter. The remaining $45 million is a net operating loss generated by our investment in the recent quarter that can be carried back for a cash refund against taxable income realized in 2006 and 2007. Finally, I want to give a quick CapEx and balance sheet update. As you saw in the release in July, Equitable's Board authorized an increase in capital commitments for 2008. That increased authority will result in an increase in capital expenditures for 2008 from $1.2 billion to about $1.6 billion as we estimate. Murray will talk about the specifics of where that will be spent. But with that backdrop we thought it would be useful to you to give a quick balance sheet and liquidity update. Including the debt and equity transactions that's we completed so far be we have raised under $1.1 billion of capital since March of '08. And because of that capital raising, you will see in the queue later today that we did not have any short-term debt outstanding as of June 30, 2008 and in fact had approximately $168 million in cash on hand and another $239 million in margin accounts related to our hedging program. On top of that cash we also have the full $1.5 billion available under our corporate revolver. So we were really in great shape from our balance sheet and liquidity standpoint heading into our growth initiatives for the second half of the year. But having said that, the best time to raise capital isn't always at the exact time you need it. So do not be surprised if you see us raising more debt capital during the second half of 2008. And with that I'll turn the call over to Murry.

Thanks, Phil and good morning, everybody. I did want to give you guys an update on operations for the quarter and for the first part this year, so we'll go through a few things. First on drilling, and these are numbers that are year-to-date numbers, so they're a little higher than the quarter. So far we've drilled 367 wells, we've spud 367 wells. Of those about 192 are horizontal wells. And to remind you, Equitable has drilled about 285 horizontal wells since the inception of our horizontal drilling program in 2006. We've drilled four Marcellus wells to-date, one horizontal, three vertical. We've drilled one Utica well. The rest of the wells are cold bed methane or some non-operated wells, and a few vertical conventional wells. We are on pace to drill at least at this point 350 horizontal wells this year. That number is up substantially from what we had previously reported. And that's the second time this year that we've increased the horizontal drilling number. On reserve implications, we'll get more into this later a little bit latter, but you might be interested in the fact that of the wells we've drilled to-date, 67% were classified in our most recent reserve report as unproved. And this continues to trend that we had previously talked about and has implications for how much of our P3 reserves that you might consider to be reasonably certain to be produced. Another reserve implication of the drilling so far is that through the second quarter, we estimate that our reserve replacement ratio, and this is just through the second quarter, due entirely to drill bit activity, drilling wells, and proving up offset locations is greater than 600%. So we hope that that will continue through the rest of the year. We currently have 22 rigs running, four in coal bed methane, two in the Marcellus, one vertical and one horizontal, 15 in the horizontal play, and one vertical rig drilling conventional wells. We expect the rig count to increase to 27 by year end. We're going to add four more horizontal rigs and one more for the Marcellus and Utica program. We normally don't go into this, but I thought you might be interested. For the low-pressure at Devonian horizontal we're primarily using Highlands Drilling and Crossrock drilling. These are generally hydraulic, top drive rigs with about 200,000 hook load plus or minus. For the high-pressure vertical Marcellus we're also using Highlands Drilling, and using SpeedStar 200,000 hook load hydraulic drive rigs. As for the high pressure Marcellus we're using Union and Patterson drilling and these are a bit larger rigs, mechanical drive rigs with upwards of about almost 400,000 pound hook loads. So I thought you might be interested in these and all the rigs are top drive. On coal bed methane in Virginia this year we have spud a total of 113 wells in the coal bed play, 48 in the second quarter. We have participated also in 29 wells that were drilled by Range, of which five were horizontal and 24 were conventional. We're also continuing our coal bed infill program. To-date we've drilled 69 infilled wells and we continue to be encouraged by the results and we are continuing to expand that infill program. On to the horizontal drilling, I want to talk about this in a couple of different ways. First, we'll talk about so called bread and butter development. I want to define a little better what we mean by that. The bread and butter has been the low-pressure do Devonian shale play. The target of this low pressure Devonian shale package includes the lower Huron, Cleveland rank [ph] street, and the low-pressure Marcellus. Colloquially this play seems to have been designated by everybody. The lower Huron play and rather than fight that trend we just want to continue to emphasize to you that when we talk about the lower Huron play, we're really talking about multiple zones. The low pressure shale package itself ranges in thickness on our acreage from 200 to 2,200 feet thick. It is quite extensive an aerial extent on our acreage covering approximately 2.50 million acres. All of the low-pressure shale zones seem to have generally similar geology. Wells drilled in this lower Huron play will be drilled with air, either with one horizontal leg or with multiple lateral horizontal legs, and generally we intend to frac these wells one way or another either with firm sand or with "vapor" that is high speed, high pressure, nitrogen fracs with entrained sand. Where more than one shale zone is present depending on local geology, we intend to drill multiple horizontal or multiple or multilateral wells to access all profitable zones. We've drilled 181 low pressure Devonian shale wells this year, horizontal 95 in the second quarter, including a number of re-entry wells which I'll discuss later. Drilling results to date in the lower Huron play continues to confirm both the volumes, costs, and economics of the play, and supports the decline curves that's we have previously published. So that's looking really good so far. Now let's move on to the emerging plays and to remind you... to remind everyone before we go into this. Equitable has not booked any reserves into its 3P reserve inventory for any of the plays I'm now going to discuss, other than minor amounts that have come from the few completed wells drilled in the play last year. First one I want to talk about is the Berea, which is really an extension of the horizontal play. We continue to have encouraging results from our horizontal wells in the Berea sandstone play. We've now drilled eight wells and five of them are online. We've reported a couple of good flow rates from the wells last quarter, the second and third wells they had little... second and third wells had 30-day average daily flow rates of 1,900 Mcfe 1.56 - 13 and 2,100 Mcfe respectively and are still performing quite well. The fourth and fifth wells were turned in line last week with anticipated first month average daily flow rate to be approximately 1,500 Mcfe. So those are looking pretty. The completed well costs for these Berea wells are slightly higher than the lower than Huron, 1.4 to $1.5 million. This is due to the fact that the Berea sandstone drills are little lower than the shale. We're still in the early phases of this play and have some technical uncertainty about drainage areas, both laterally and vertically, but what I can say is that if the results from these wells continue to look strong, then the Berea well EURs will be higher than what we've seen for the lower Huron. We anticipate spudding a total of 25 to 30 Berea wells this year with the majority of those wells being in Kentucky. And so we're gearing up that play. Now under the reserve implications for the Berea, we estimate that we have at least 3,800 Berea locations on our acreage. And these are locations where no previous wells have been drilled to test the Berea specifically. In addition, the Berea may hold potential for re-entry in areas where our existing vertical wells have been completed in the Berea. And the number of potential re-entry locations will depend on what we learn about drainage patterns and the horizontal Berea wells. So there is significant scope with significantly more... sorry I am using that word twice. I went to public school. But anyway, there could be many more Berea locations. We're currently saying 3,800 potential locations at this point. Obviously it's a big leap from eight wells drilled and five in line to the implications suggested by thousands of locations, but suffices to say that if the drilling results continue to be satisfactory, we should start to see P3 additions related to the Berea this year. And we are also beginning to put in additional midstream right now to support this play. Lastly, on this particular topic, the results from the Berea have stimulated us to begin testing other collateral, unconventional, non-organic rich [ph] sales. This is kind of a weird way to say it. The unconventional has been thought to be shaled. We're saying that this is unconventional... unconventional shale, which is going back into the... the sandstones and silt stones that are collateral to the organically shale's. We're going to spud three raven cliff wells, three big lime wells, and five weird [ph] horizontal wells this year, all horizontal, to see if these collateral non-organic, rich shale targets have some potential. All right, so that's the Berea, story and the collateral potential implications from the Berea. Going to the re-entry targets, to reiterate, the re-entry play encompasses about 4,700 existing locations that have previously been penetrated by a vertical shale well. The new activity that we could carry out on one of these locations could be re-entry of an old vertical well with additional drilling of a new horizontal or multiple horizontal wells, or we could be drilling an entirely new horizontal well or wells in the same location in this lower Huron package so to speak. To date we have drilled five wells that were true reentries, where we reentered an existing well bore. We drilled an additional 48 wells that were drilled on the same location as an existing vertical well. So in total, we have spud 53 horizontals that we would classify it as reentry or redrill; 25 in Kentucky and 28 in West Virginia. We have 30-day production results on 14 of the 53 wells. On average, the first-month results from these "reentry wells" are consistent with what we've seen for virgin shale locations. And importantly, where we have drilled a new horizontal well in a location where there is an existing vertical shale well, we have not seen production interference between the two wells. We would view the results of the reentry program to-date as quite encouraging so far, and again, we would anticipate P3 additions to reserves this year from that... from that play. Moving on to the next category, emerging play, multilateral, we did not drill any this quarter. We are continuing to on auto... to have some little permit issues on getting these things done. But we are going to drill a number of multilaterals in Kentucky this year. We expect to also spud our first stack multilateral in Kentucky in the third quarter. So we're a little behind on that, but we're catching up pretty quick. In summary, on the extension and reentry category of our emerging plays, we're working this very hard and hope what I've described gives you a sense of where we're headed. Next let's move on to the high-pressure Marcellus. As you'll recall, Equitable has a little more than 400,000 acres in the high-pressure Marcellus played footprint. We're continuing to add modestly to that position. Again, we have no reserves currently in any of our P3 categories for the high-pressure Marcellus play. So far we have turned in line, meaning these wells are flowing, at least some other gaps to the sales meter for all four of those Marcellus wells. So they're flowing to sales meter. One horizontal well is in Green County, the three vertical wells are in counties are in Wetzel county, Dodridge county, and Lewis county, West Virginia. The horizontal Marcellus well averaged 1.9 million cubic feet per day in its first 30 days. And keep in mind just to remind everybody; at Equitable when we talk about IPs, we're talking about first month average daily flow rates. We think that's a better way to describe the potential of these wells. All of these wells produced IPs, if you will, that is initial productions in the short run at the beginning of their production life of multiples of this number. But what we try to stick to here at Equitable is the first month average daily flow rate. And that's the 1.9 I just mentioned. This particular horizontal well cost a lot. It's cost $6 million to drill and complete. We did a lot of science on this well including micro-seismic and a whole bunch of other stuff. We expect future horizontal Marcellus wells to cost in the range of $3 million to $4 million. And we're... what could get us, we think, to the lower end of that range is some experiments that we're currently conducting in drilling horizontal, high-pressure Marcellus wells with air. And that could have a pretty significant impact on the costs per well of these high-pressure Marcellus wells. We don't know if it's going to work, how well it's going to work. We've got some initial success; we don't know how extensive we can apply that technology. But anyway, we're pushing the envelope on air drilling in this high-pressure Marcellus. The three vertical Marcellus wells have not been on line for full 30 days, but we estimate based on what we see right now that they'll have first-month average daily flow rates of about 600 Mcfd. One of those verticals is being shot back significantly with 850 Psi casing pressure. Obviously that's a midstream issue. But anyhow, the actual flow rates are 600 Mcfd averaging for those we think they'll average for the first month. The first well, the first vertical Marcellus well cost about $2.7 million. The next two cost about $1.3 million each. So that's been pretty good cost improvement there. Among the many goals of our first Marcellus wells was to test the area of spend and the opportunity on our acreage with the current results we feel we've made profitable economic wells in a geographic area that's 50 miles long by 30 miles wide. Our plan for 2008 is to drill eight additional horizontal and six additional vertical high-pressure Marcellus wells for a total of 18 split evenly between horizontal and vertical wells. More importantly, we are sufficiently encouraged so far by this play. Our drilling, others drilling. By the end of '09 we plan to have drilled at least 75 Marcellus wells. In addition, as we mentioned in this mornings press release we are making our first commitments to mid-stream projects to support our high-pressure Marcellus development equitable mid-stream will build two 20 million a day distributing plants that's 40 million a day in total. And 30 miles of supporting gathering pipe in a couple of mini-corridors, one of these corridors is in Northern West Virginia, the other is in Southwestern Pennsylvania. And this investment will both jumpstart our EQTs Marcellus development and give us flexibility to lead a larger collaborative mid-stream solution to support Marcellus development down the road presuming the results from these wells continue to be good. So that's the Marcellus story so far for us. On the deep Utica, we're in the process of fraccing that first well, and we don't have anything to report there. Although we do intend to drill at least one more vertical well this year regardless of the results of this first well. As the pace of drilling activity increases and with the enthusiasm we currently have on the emerging plays, Equitable is... is turning into a reserve addition machine. I... that's just what's happening. We... it seems as though every time we turn a corner and try something, at least for the most part what we're trying is turning out to be pretty good. Not only that, but the well results demonstrate that the reserves are getting to the surface. So we're also, you know, becoming a production rate machine. Obviously, the challenge for the company at this point is to get sufficient midstream infrastructure in place so that we can turn what is currently a reserve and production growth machine into a gas sales growth machine. And that's really what we're all focused on here at Equitable right now. And with that... I'll transition into a brief midstream update. As we mentioned previously, Big Sandy is in line and flowing gas. Making Phase I is constructed and currently being commissioned. It's approximately three months ahead of schedule. So that's... that's good news. And the Langley processing plant is still on track for third-quarter turn in line. On to capital expenditures as you read in the press release, we're raising our CapEx estimate for the second half of the year. For this year, by about 400 million years... $400 million. $400million the Marcellus, more wells midstream and some acreage acquisition accounts for approximately 55% of this increase. Other midstream activity accounts for about 39% of the increase and I might mention that of that 39% increase, about a quarter of that is inflation and most of the inflation is in steel prices. Other drilling, primarily horizontal drilling, accounts for about 6% of that CapEx increase. So far this year, Equitable has had considerable success in executing our operating plans. Drilling is ahead of schedule, Big Sandy is on line. We're completing other midstream projects including the completion of making Phase I on time or ahead of schedule. We expect completion of the Langley processing plant on time. This is a testimony to the strengthening team that we have here at the company from end to end. All this makes me feel confident that we will exceed the daily sales target milestone of 235,000 Mcfd that we previously discussed with you. We're not there just yet. But I will inform you when we do get there. To remind you, one year ago, our average daily sales rate was about 206,000 Mcfd and we started at 210,000 Mcfd. We are in the process of integrating all of this new information related to our emerging plays and our ability to drill faster into our 2009 business plan. And we'll update you on our long-term growth rate expectations later this year. And with that I'll turn the call back over to Pat, and then to you all for questions. Thank you.

Thank you, Murry. That concludes the comments portion of the call. Sharon, can we please now open the phones for questions. QUESTION AND ANSWER

Thank you. [Operator Instructions]. We'll pause for just a moment to compile the Q&A roster. Our first question is coming from Shneur Gershuni. Please go ahead.

Good morning, guys.

Good morning.

I just wanted to focus I guess on these re-entry wells. And I just kind of wanted to get of color on how to be thinking about them with respect to proved reserves. You know, assuming that you can have this success rate over time. Would you be in a position where you would rebook all of those wells or all of those locations into proved reserves kind of like by the end of the year? Lets see if you would rolled enough for by the end of next year, or is it still going to be that you still have to drill those locations and ultimately count it into the group reserve category? And so it would take a longer time.

I think it's more likely the latter than the former. But you know, with the rules that are... well, first let me comment that the rules obviously are changing on how we have to treat these reserves. The SEC is out with some comments on this and while we were asking for comments on what they've... what they've said, I think based on what we see so far, it's likely that you'll be able to book from this particular play a bit more on the proved with the new rules than you might have with the old rules. But more importantly, I think as I mentioned earlier in my call, the notion of what the P2 and P3... the notion of the risk of P2 and P3's reserves particularly for the shale plays and very specifically Appalachia, is kind of a... isn't as troubling. The risk isn't as troubling as it might be for other plays elsewhere. And I made the comment that 67% of well we drilled this year were even on locations that were, booked as proved when we drilled them. So, that's not a good answer. I just think what we have to do what will be helpful to you is for me to continue to describe the success that we've had on the re-entry, and the scope of that play. And I think as time passes and we have hopefully more and more success, less and not very many failures, we'll be able to work into your model an assumption of how many of those 4,700 wells will ultimately, be produced. So I realize that's a long-winded answer. But I don't know any other way to talk about it. There's no hard line yet on this.

Murray can you talk about drilling costs for the well a little bit just with respect to re-entries and with respect to the Marcellus play as well?

Yeah. The re-entry specifically, I've said this before and it hasn't really changed. Because most of the time it looks like we're going to be drilling a new well where had previous a new horizontal well, we previously drilled a vertical well, I don't anticipate that those costs are going to be substantially different. We do have a pad so that saves a little bit of the cost. And there's some at least rudimentary road to the old vertical well that we can use. So there's a little bit of a cost decrease versus a brand-new location. However, that's really not the value driver for or that's not what drives value for the re-entry play. It's the new reserves and the new production. On the Marcellus, I'm encouraged by the learning curve on the vertical, high-pressure Marcellus wells that I mentioned to you. I think there is still... we're still on the steep part of the learning curve for the high-pressure horizontal Marcellus wells, and I'd like to see some technology improvements to improve that. And as I said, we're experimenting with air drilling right now. And we'll just have to see how that... how that works out. But we'd really like to try to get those horizontal Marcellus wells down to about 3 million bucks or so.

Great. And just one final question. I missed, Phil, what you said how much room [ph] you had on the revolver if I could.

We have the full $1.5 billion available, plus, about $168 million of cash as of 6/30/08.

Okay. Perfect. Thank you very much, guys. Appreciate the commentary.

Thank you. Our next question is coming from Scott Hanold. Please go ahead.

Good morning.

Hi, Scott.

On that Marcellus horizontal well that you had the production rate, was that the one that was, drilled in Hamilton and fraced from Hamilton?

Yes.

Okay. And what is sort of the thoughts on that sort of well being in the Hamilton? Is that something that could be... something we see going forward, or are you going to try and stay within zone [ph] and do you think the production rate could have been better that actually was in the Marcellus?

That is a very good question. And first of all, I think that production rate is quite good. And it started out a lot higher. As I mentioned, we at Equitable do talk about the first month average daily flow rate when we talk about these numbers, so you're going to see our numbers lower than IT [ph] and obviously it started out at considerably higher rates than that. But your point is a good point. I think that this is going to be a tradeoff... the issue of drilling in the Hamilton or drilling directly in the Marcellus is going to be a continuing tradeoff that we're going to make. And it's going to be a cost tradeoff. Can we drill directly in the Marcellus, and complete a well at a reasonable cost, or would we rather drill in the Hamilton where a more confident formation effectively, drill quicker and cheaper and get maybe a little bit less flow rate? And I think those are choices that Dave and I are going to have to make, blow-by-blow. We don't have enough data yet to come to any generalization. We've only got this one well. I will mention, though, that the Hamilton one is very organic rich. So it's possible that we're getting contributions not only from the Marcellus... we're certainly getting contributions from the Marcellus, but we could also be getting contributions from the Hamilton in this well anyway. So... if that helps you or not. But that's where we're early.

Yeah. No, that is a great color. And are you aware of like some of the - on your car parts in Appalachia what have they' done its pretty much that they think in the Marcellus zone or... some of them also done in Hamilton?

Scott, this is Dave for you. There been some mix right now from what we are gathering. Everybody's on a learning curve. The one thing that seems to be certainly true is that everybody has tried directly going into the Marcellus has had at least some of their wells have considerable problems that have added considerably to the costs. So that's really the... that's the tradeoff is that you get some of them completed at the cost that you budgeted and some of them completed at costs that are well above the multiples of what folks had budgeted. That's all of the chatter out there, whereas going into the Hamilton. And I think we're able to frac all the way the entire extent of the Marcellus by going into the Hamilton. So, we don't think we're missing anything in the Marcellus. But it's much more... its early days it seems to offer that's much more predictable. It's still a tradeoff.

Okay. No, that's great. And could you talk a little bit more about air drill? Just kind of give us sort of the advantages of going to the air drill and what really that... what that means?

Well, it's cheaper. I mean, if it works, at least on paper,... and by the way, again, I'm going to give you numbers, I don't want you to hold me directly to them. But we think with a conventional drilling, that is a wet drilling of a high-pressure horizontal Marcellus well, we think we can get that cost to around $4 million. Plus or... now the dry whole cost is significantly less than that, but that would be the total completed cost. We think we could take about $1 million out of the drilling cost. $750,000 to $1 million out of the drilling cost by drilling the well with air, and of course we... and we still have to frac it with slick water just like the other well. So it's got some significant potential leverage on cost, if we can pull it off. However that cost is because we're drilling it quicker as [inaudible].

Okay. And then the...

Or you could look at another way and say if you have x number of rigs dedicated to it you can drill more wells per given time period with the same number of rigs.

Right.

So it's worth pursuing, and as I said, we are doing that as we speak.

Okay and final question if I could, I'd like to Murray. Just like to hear your comments on your current thoughts of the regulatory issues... folks talking about in the Marcellus?

Well, yeah. I think I mentioned on the last call we were a little disappointed on kind of how that evolved with... you're talking about the water issues now?

Yeah its correct yes.

Yeah. We were a little disappointed on how that evolved. I will say that partly this is because we're a hometown player here. We have been using our extensive relationships here in Pennsylvania, not so much to get around anything but just to make sure that we are present and active in the dialogues surrounding what's going to happen on the water issues. And beyond that I will say that, Pennsylvania does not have a severance tax at this point in time. Under certain conditions we are not... against there being some more revenues generated from the wells, if it facilitates the bureaucracy that needs to be in place to approve the wells and get through all the permitting processes, et cetera et cetera. So we are active in the dialogue, I think it's fair to say. And we think it's going to be a constructive dialogue. It just got off to kind of a rocky start, unfortunately.

We do view this as being just growing pains. I'm sure for the two companies they got hammered by particularly hard if you were to ask them, it may have been felt worse at the time but we think for everybody in the Marcellus, these are just growing pains.

Okay. And you don't see any issue with giving permits going forward, for water and executing at least over the next, say, 12 months, or I guess [inaudible]?

We don't. But keep in mind most of the wells we're drilling are outside of the Delaware basin and the Susquehanna basin water authorities. We are mostly in the Ohio River basin. And to this point in time, there is no Ohio river basin water authority that being required to issue a permit for water. So we have a little bit of a special situation in South Western Pennsylvania.

None of the things you have heard about pertain directly to the areas in which we have acreage. And keep in mind, a lot of our drilling is in Northern West Virginia, too.

Good to know. Thanks, appreciate the time.

Thank you. Our next question is coming from Stewart Wyman [ph]. Please go ahead.

Yeah, hi, this is Jay actually.

Oh, oh, okay.

Hey, Murry, how are you?

Well, thank you.

Just a quick question on the comment that you just made about severance taxes. Can you... is that something that's being discussed now? Because that's the first I've heard of it in Appalachia?

It's very, very loosy goosy right now. I just wanted to point out that that's... Pennsylvania is unique in the fact that it doesn't have one.

We do need cooperation. Everyone in the industry does need cooperation from governmental agencies to make this play work as well as we all want it to work. So Murry's comment was only if at some point they start throwing back that it's increasing their costs we're obviously going to have to come to some form of accommodation.

Got you. And then the other question was regarding mid-stream in the industry. Range Resources announced a deal here with MarkWest and is that the kind of stuff that you would also be... I guess competing with MarkWest on, and... if that's the case and how does one pick one versus the other just how's the industry playing out for the gathering in mid-stream build out given the reserves in for production in the area?

I'll make my comments. Dave may have a different view on this. We do not share the view of some of our competitors that all this is just going to get worked out. We do think it's going to take some active management by everybody. Ideally, if it was me and you had a choice, there would be some consortia out there that would put together some projects that were the bigger, perhaps more efficient. Right now, it seems as though the way the development is progressing, it's going to be in smaller projects. And maybe that's appropriate. Hopefully they'll be put together in a way they can be linked in some way down the road. But as I think we've mentioned before in this Marcellus play, no individual operator has more than 20% of any area that would logically be put into a gathering corridor, if you will. And so they're going to have to be... there's going to have to be a lot of work done collaboratively to get this done. What Dave and his team have decided to do for our initial work in the Marcellus is put two skids out there, $20million a day. Obviously those things can be expanded. And we're putting in strategically in places that they could be expanded if others wish to... our own drilling is better and we see more opportunity or others may want to come in. So we're trying to build some backbone. But it is not possible, I don't think, for Equitable to sort of go out... it's too big a project for one company at this point at its sole risk to take this on as a major corridor. I'd say its a couple of $3 billion type investment. So right now I think it's my view to develop a little patches for a while.

So for your own mid-stream would contracting with companies like MarkWest? I mean, if its... it's a big enough industry, big enough players, enough players. Is that something to consider, or are you...

Yeah, absolutely. But just as you read about one small announcement. And what they're talking about a 30 million a day deal...

It was actually 150 I thought...

Well, I'm just talking about what the processing is with MarkWest.

Oh yes I got it.

There's a bunch of other midstream companies who are now up here talking to a lot us. They talked to Equitable and I'm sure they talked to Range and Chesapeake et cetera. They're companies that never used to be interested in this basin and who are now interested in this basin who are much more pure, mid-stream players. So if you're asking can we anticipate... could we anticipate doing something with one of them, absolutely we could anticipate that. Right now, some of the questions that we don't have answers to is... how much processing does this gas need? How wet is it really? Does it change as geography changes? Am not talking about the geology, but it seems that some of it changes a bit as geography changes, as well. So we all want a little bit better answers to those questions before we make big commitments. But those conversations are underway, absolutely. And there's a bunch of companies, that probably anybody would think of being a sizable mid-stream company is in discussions with multiple producers up here.

Okay. One last question. And kind of a theoretical one. Where do you think for Equitable the reserve life peaks out at... obviously you've identified so much in reserve...

Yeah. It's a good question.

Where do you think it peaks out for the company?

That's a great... since Dave and I have been here, we've continued to struggle, we're trying to get ROP [ph] down. And it seems the more we do the more it goes up.

Well I think I calculate it 35 years, given your major updates.

Clearly that's the wrong answer. Right ROPs [ph] these are way too high. That means of necessity production has to go up one way or the other. Otherwise this question about whether the reserves are really there or not, and obviously that's a... not that they're not there, but that they... they come out in a reasonable amount of time. So we're struggling with that. And right now, if I had to guess, I would say that at least for the next few years, ROP [ph] is not going down given the number of things that we're doing and the number of opportunities that we're getting. I hope a few years from now we can start saying that it's coming down, although that will be a good news bad news story, right?

Sure. Again, good quarter and thank you for the update.

Alright Good.

Thank you. Our next question is coming from Rick Gross [ph]. Please go ahead.

Good morning.

Hello.

[inaudible]

Hello?

Yeah, we can hear you. Sort of.

Sort of?

Yes.

Hello?

Yes. Go ahead with your question.

Go ahead.

Okay, In regards to kind of Mpv [ph], you've got all these experiments going on, and let's assume that they're all good. How do we think about prioritizing all of this either from an infrastructure Mpv [ph], you don't have lease expiration problems like a lot of these guys do in these new shale plays. Is there a possibility that we accelerate the processing of this by bringing in somebody else on a promoted basis, maybe not right away?

Yeah.

But as we think about how do we get... under a 30 year reserve life. Is that...

Yeah, Rick, obviously the shareholder value going to drive all of these decisions. I think the question is what kind of trade do you make when knowledge is insufficient to be able to figure out what to do. I will say this, though and we've been very consistent in this overall development model. And I don't know if this will help you or not. But the way we've approached first the Huron, now the Berea, and also the Marcellus is first to drill enough wells in a particular area that we get confidence of our reserves there and that there is a sufficient incentive to build mid-stream infrastructure. And you can argue whether it's us build it or others build it, but to have mid-stream infrastructures. So phase one is get a little bit of a... get enough wells around there that you can define a reserve base. Second, commit to and build mid-stream and then drill the heck out it to build the mid-stream infrastructure. That is our overall business model. Now the question you're asking is how... and we call those things corridors. The question is how many corridors are we going to drill, do ourselves, how many corridors might we have someone else do on a promoted basis? I can't answer that right now. And the reason I can't answer is because I'm not sure I know which are the best and which ones I want to give up and what the trade is. I don't think you're wrong in presuming that at some point we could have partners to do some of these, but not today. I think we're a couple of years off from that.

But you've got...

The development model is very clear. We know exactly how we're going to do this. We're already executing on that development model. All the way from the Nora days, when we started these corridors with the coal bed methane. So we're just... we're just stamping out corridors first by exploring them, then by building then, then by filling them out. And, you know, whether a corridor ends up going to somebody else, I think if it makes the best shareholder value sense, we'll do that somewhere down the road.

Okay. This is almost out of curiosity. As you begin to sample, it's not as though your patented drilling and drilling 20 holes [ph] off a given path. You've got a [inaudible], rigs [ph], flat trucks, all this kind of stuff. Is there anything in the way of as you build kind of scale that there's a logistical scale cost curve that going to help you mitigate costs for the gorge, spending all of your time moving the equipment around from sample to sample as opposed to drilling a venture configuration of things?

Well, I think...

I don't want to...

I think... let me put this way. We are the curve, right. We're the most expensive horizontal driller in Appalachia. And I think part of what we've seen in the results, which have been significant, are the... the cost curve improvement that we've seen part of the reason for that is absolutely because of the scale that we have here and the fact that we got a lot of other wells that we can go back to. A lot of these re-entry wells are patented and have already been there. So... I think the biggest scope for improvement right now in my view is on the horizontal is not so... in the low pressure horizontal, it's not so much the drilling of the wells of the logistics which I think we're doing is an outstanding job on. I think what we're hoping for is that we get a little bit more recovery per well. So the improvements in fracturing, hopefully multilateral will work. And that we'll get more wells drilled per location and be able it reuse that location multiple times for all these zones within the shale. That's where I'm really looking for the leverage. And on the Marcellus, I think we had a pretty good discussion about that. We're just really on the steep part of learning curve on the high-pressure Marcellus so there is clearly a scope for technology improvements, its there. I don't know if that helps or not but I think logistically, I mean, Equitable is more... we're a logistics machine here. I mean, to get all this stuff moving from place to place.

Okay. And then one last issue. You mentioned, you know, kind of in Berea that you well you kind of gone back into Kentucky. You may have some areas where you've historically had and called vertical walls. And maybe you haven't exploited other areas [inaudible] for whatever reason that you may open up commercially. But we are in the big line and all of these that work are areas are the people who have drilled vertically for varying degrees of success. Is the model here from a reserve booking standpoint that we're going back into we'll call it familiar areas and that is we test the model that we made going to areas that to some degree are worth contemplating or aren't anywhere near, you know, we'll call it the reserve...

I think just to cut that you know, where those other zones had previously produced, rig, the reservoirs were more conventional, high-permeability reservoirs. I think what's happening with this new technology in those reservoirs, the Berea, Big Line, Weir, etcetera, hopefully is that you aren't going into the zones where those sands have become less permeable, less porous, and the recovery factors were insufficient to make economic wells... economic vertical wells. So in a way, there's... they're not Shales, but they're near Shales from a production characteristic standpoint. And those are the wells that... those are the areas that we think have the most potentials to be re-entered, redrilled, or exploited for the first time with horizontal drilling.

Okay. And then lastly, in stripping plants, these things I assume the results going to be full-scale trials [inaudible]

Yeah you assumed correctly. And again we just like the others here what comes to Marcellus, we will find out whether we need something bigger as we get down the road. Something the earlier caller had made a comment about the range what they had... we think they misunderstood what range was announced. They were talking about 150, they were talking about was pipeline capacity. So 30, the stripping.

Okay. And who's the big pipe outlet for this?

There is... every big pipe in the country is having discussions, as well.

Obviously the Ohio valley is a major conduit in that it head through the Appalachian basin from....

Okay. But you haven't decided through this mid gathering systems is....

You know, you mean the gathering. No the gathering is going to be bits and pieces. I think its going to, we think its going to depend on where in the Marcellus. The big part is I think get it to market. Actually it's going to be multiple solution...

Yeah. There is going to be Tennessee, it is to be dominion, you know, mostly up here.

But you've seen a variety of announcements. And I think it's fair to say that if there's a pipeline company whereby they haven't said anything about wanting to do something in Marcellus, they've just haven't made an announcement.

Right. Okay. Thank you.

Thank you. Our next question is coming from Faisel Khan. Please go ahead.

Good morning, its Faisel from Citi.

Hi Faisel.

How you doing?

Good, well thank you.

If I can kind of ask a question more pertaining to current production and maybe look at the reserve life question in a different way. Based on... based on what you guys have done so far this year, based on the infrastructure coming on line, how much in the production do you think you guys have in... in the backlog? Is there a way to answer that now that you have kind of had a little more experience in drilling those horizontal wells?

Not really. And the reason I think we can't answer that is we don't have any pure experiments on that except maybe making. And we don't have nearly enough history on making yet to determine that. You see what I mean?

Yeah.

And so until you run the perfect experiment where you have pipes that are clearly unfilled. And you can compare the production from the wells to the time when you had pipes that were filled. You can't run that experiment. I mean making as the potential perhaps to give us some insight on that. But I can't give you a number right now.

We'll try to come up with something that makes sense in that context.

But that's the road mark that we're looking for, right?

Okay. Yeah.

What's the timing on that? When do you have more information?

If we did it, I'm sure it would be in the context of our annual plan and budget. The process just getting underway.

On the CapEx budget, that's going to... that's going from 1.2 to 1.6 billion. Is that correct?

That's correct.

Okay. And in terms of... in terms of... of that CapEx budget kind of carrying forward, giving your drilling plan and your infrastructure plan, is it... is it fair to say that that should continue going forward? For the next 18 months?

We'd be misleading you if we told you to carry that number forward. I mean, I think what you should take away from the call and Dave and Phil and my comment is that we are accelerating, we have the ability to accelerate our drilling well beyond what we thought we could at the beginning of the year. We're also have a couple of new plays that are emerging, the Marcellus and the Berea in particular. And that's not even including the re-entry plays. So I... what we're doing right now is taking the information from all of these new opportunities and our increased capability to drill faster, and build pipe faster too, I might add. Though the team's really doing a great job. We're taking all that and putting it into the 2009 plan. And I really don't want to forecast the number at this point in time.

Okay. With your cash flow which are certainly being held by the deferred tax line. I mean, how does that look going forward? Is there... is there a way to... did that come back to you any time soon? Or is that going to be kind of a... a temporary post of cash over the next 12 to 18 months?

Obviously our operating cash flow has gone up since the time when we were a full taxpayer. The $45 million that I referred to, we will go back in software refund which we will receive in 2009. You know, for the rest of 2008 and actually for the foreseeable future at the rate we're spending, we're going to probably continue to be generating net operating losses that will be able to be carried back to the extent that we have operating income in '06 and '07 to carry it back again. And then from there forward, it will be carried forward. So I... I don't know if that answers your question...

Yes, but certainly for...

Certainly for the rest of this year we are going to continue to be in that situation while we're generating net operating losses.

Okay. Again, on the... on the executive plant, the employee... the employee... the employee cost that you guys had... that had there historically went to your numbers, you didn't have it this last quarter. But the stock price came off kind of after the quarter ended. I was trying to figure out how that exactly looks and gets booked?

Well, we... we've currently booked... actually a little more expense for the entire plan through the end this year than we would need given the stock price and multiplier today. Now, as of June 30 when the stock price was closer to $70, we would have still continued to have expenses for the rest of this year. There will be some sensitivity in the queue that comes out later today. Let me give you one. That $65, we have about $25 million of expenses. That would run through the income statement during the second half of 2008.

Okay.

And at the current price and multiplier, there's actually going to be probably a little bit of a gain if that doesn't change.

And that's helpful. Is there any update on the... on the pipeline project with you in El Paso?

No.

Okay. Thanks, guys.

Thank you. Our next question is coming from Becca Followill. Go ahead.

Good morning.

Hey Becca.

Going back to the Berea sandstone, do you guys have any feel for when you're going to give us the metrics on URS-type [ph] curve and where do you think their cost could go on these wells?

Yeah. Its going to be year end, I think, Becca. We're still wondering how much we're draining with these things. And I don't know what the... I don't know... so we've got to kind of... we're doing some more technical work, some other engineering work on that. And I really got to watch these wells very carefully for a while. I mean, not to make... put some finer point on it, but when we started drilling horizontal shale wells, we had had the benefit of declined curves for a whole bunch of vertical shale wells. And so as we saw those things match, we got kind of more confident in our ability to project URS and decline curves because the models matched... the verticals matched the horizontals, and so it all sort of fit tightly together. This is a bit of a new world for us. And I'm going to be a little more cautious on projecting URS for a while. So I don't know. End of the year, I'll... well I'll give you updates every quarter on how I feel about that but my own guess its probably going to be end of the year or so.

Just the reason I asked is 3,800 locations, these kind of IPs, this cost, it's significant potential that clearly is not your stock, and so...

Where here.

And so we just kind of like to see that. How much infrastructure are you guys looking at putting in for the Berea? You mentioned incremental...

Right. I mean, it would be wonderful if all of this stuff was at exactly the same place. But Dave is in the position of scrambling to get a Berea kind of corridor together now. It's not that we have none, we just need to upgrade it substantially to cover the kinds of flow rates that we're expecting from the Berea. Dave, you want to talk about that at all? Yeah. So again, it's... more gathering is required, etc, etc. Bigger pipes. So we're... we're moving quickly ahead on that.

Okay. We shall easily put the next question on Berea how much overlap is that, you have that with the Huron or Marcellus...

Yes, there are places where it overlaps. That's a great question, Becca. What I have... I've tried now over the past 18 month to classify this whole opportunity in a couple of different ways and I've probably been unsuccessful and being as clear as I want to be. Right now what I'm saying is the lower Huron play is a bunch of Shales. They're not all cold Huron but they are bunch of Shales. And then there is Berea and at any one location we could have Berea and in a bunch of the lower Huron Shales and as a matter of fact on one locations that we're drilling right now we've got four wells going, two Bereas going in opposite directions and two Hurons going in opposite directions. And location by location we're going to be picking all of the zones that we think are potential. And without putting this on the map it's kind of hard to describe over the phone. But we'll try to start generating some maps so that you can at least see the areas where you could have multiple zone. I still think on average over our entire acreage suite, on average, there is a little more than two locations per our two wells per location on average. You know, if you want to get some kind of a sense of how is the big picture on that.

But for infrastructure the Berea is much... its probably fairer to say that influences the priorities, whereas the Marcellus is kind of an outlier. I mean, for the Marcellus, we're looking at projects that we wouldn't have looked at otherwise. Whereas for the Berea, it simply shifts around what exactly we would have been doing for the other plays.

Will you modify as opposed to Greenfield?

Exactly.

Okay. And then two other questions for you... sorry for taking so much time. On Marcellus, URS to take [inaudible]?

Yes.

Okay.

Yes. I mean, again, we're going to have a limited I don't think you'll be able to generalize too much from... from our stuff. From the limited number of wells that we will have. But we will try give you the URS as best we can from the wells that we have drilled. And keep in mind one of the benefits of what we've done, I want to emphasize this, all these wells are flowing. So hopefully we'll start to get some decline curve data that's... that's good.

Great. And the last one is the picture of structure, which I've asked before. But the company is evolving so quickly, and clearly it is E&P focused with a lot more opportunity. So how does the LDC fit with that? In light of that, and in light of a lot of... is that cleaning a lot of capital?

Yeah. That's a great question. I think if you had a clean sheet of paper, you probably wouldn't decide that you were going to have a production company and an LDC in the same company. But we do have it. And I... the best way to describe where we are right now on that Becca is we're in for a rate case and I want to see that rate case carry forward and beyond that we really don't have anything structurally to say about the LDC.

And is there a proper timing of the rate case? Is there a mandatory time when they have to give you decisions?

Early next year.

Yeah.

Perfect. Okay. Thank you.

Our next question is coming from Holly Stewart, please go ahead.

Good morning.

Hi Holly.

Can you guys give us any update on the Cleveland shale well shouldering the quarter?

I had some data on that. I don't think... I think you should be viewing the Cleveland in the context of all of the shales that are there. I mean, the Huron's going to be better and worse in some places, the Cleveland is going to be better or worse in some places. And we're taking the Cleveland wherever we think we can make a well out of it. But I really hesitate to give you specific decline curves for these various shales because there is such a broad range. Its not constructive plus we don't have enough Cleveland wells anyhow to make a specific decline curve. I prefer that we stick to the lower Huron shale decline curve as... as a way to generalize all of those shales at this point in time.

Got it.

And I think within the context of that decline curve there's sufficient variability to describe the results that we're seeing for the... for all of those shale zones, if that's okay. I just don't have enough data to segment that out yet.

Yeah. Got it. And then talking about the... the re-entry, you said you've drilled 53 so far, and just give us a reminder, only two of those are booked in proved reserves as of year end, is that correct?

I think that's right. Yes. Yes is the answer.

Okay. That's all I had.

Thank you.

Thank you. Our final question is coming from Jonathan Freed [ph]. Please go ahead.

Good morning, guys.

Hi.

Just wanted to touch base and ask about steel prices in oil country tubulars. We've been hearing a lot of talk about there being tightness in that market. Can you talk a little bit... could that be slowdowns? Do you guys at all or how are you handling that?

We're handling it by putting in pre orders and ordering a few months ahead of time. That's basically how we're handling it. So our view has been, you know, we think we're a big enough user, and if we're willing to make the commitment ahead of time, we're able to secure the supplies that doesn't help us with the price, of course.

Right.

The price of a lot of these things... I was just looking at one of them, the lines, an industry index that shows that in the last year, July versus July last year, it was up 117%. So certainly there have been price increases there. And we are simply ordering further out in front than we used to. And what we're trying to do also is the standard... we're in the process of doing more standardization of the type of pipes we use. So that if we think we're ordering further out in front, then we could be certain about where we're going to use it. But the... it's easier to switch those orders around from project to project. And just to remind you, I think this is approximately correct. Steel tubulars represent about 10% to 15% of the well costs.

Right.

Well... yeah right. They go up and can become a higher percentage. But generally speaking, that's how you might calculate the increase in... in well costs that are coming from the steel.

Okay. And then maybe a high level one... we just heard Aubrey talking today about Marcellus maybe being out five years before it really impacts supply. How do you guys look at that from a... from a high level?

You know what, I... I wish I... I aspire to be as far reaching and far thinking as Aubrey, who's a great friend of mine, by the way. But Dave and I are worried about our little production. But it's going to impact that faster than five years.

Sure. And I Appreciate it.

Thank you. I'd now like to turn the floor back over to your host for any further comments.

Thank you. That concludes today's call. Just a reminder, the call will be replayed for a seven-day period beginning at approximately 1:30 today. The phone number for the replay is 706-645-9291. The confirmation code for the replay is... I'm sorry, 29614337. The call will also be available for replay on our web site. Thank you, everybody, for participating.

This concludes today's Equitable Resources conference call. You may now disconnect and have a good day