EQT Corp (EQT) 2008 Q2 法說會逐字稿

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 any background noise.

After the speakers' remarks, there will be a question-and-answer session.

(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, ad 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.

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 comparisons.

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 in midstream, as well as lower cash taxes, and lower executive compensation expenses.

I will briefly elaborate on each of those topics before turning the call over to Murry 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 wellhead sales price, which includes the effect of our hedges was 28% higher than last year at $6.14 per MMBTU.

The increase in the average well head price of driven by NYMEX, which was up approximately 45% in the quarter versus 2007.

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 v 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 progressed toward double-digit sales growth rates.

Higher operating expense 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, $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 were 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 online in the second quarter and started generating operating revenues and operating income.

We have been reporting allowance for funds 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 Northern 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 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.

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' first rate-based case in more than 10 years.

I wanted to touch on a couple of other quick matters, 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 of multiple assumptions around our executive performance incentive program, or EPIP, as we refer to it.

The 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 were 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 Q 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 you took net income and added back DD&A and the noncash 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 millioner have us 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 footer that can be carried back for a cash refund against taxable income realized in 2006 and 2007.

Finally, I wanted 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 commitment 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.

Murry will talk about the specifics of where that money will be spent, but with that backdrop, we thought it would be useful to give a quick balance sheet and liquidity update.

Including the debt and equity transactions that we have completed so far this year, we have raised under $1.1 billion of capital since March of '08.

And because of that capital raising, we will see in the Q 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 had 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.

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.

Good morning, everyone.

I did want to give you guys an update on operations for the quarter, and for the first part of 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 in the quarter.

So far we've drilled 367 wells, 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 coal bed methane or nonoperated 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, but you might be interested in the fact that of the wells we 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 P-3 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'll have four more horizontal rigs and one more for the Marcellus and Utica program.

And we normally don't get into this, but I thought you might be interested.

For the low-pressure Devonian horizontal, we're primarily using Highland Drilling and Cross Rock 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, speed stock, 200,000 hook load hydraulic drive rigs.

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 400,000-pound hook loads.

So I thought you might be interested in these.

All of the rigs are top drive.

On coal bed methane in Virginia this year we spud a total of 113 wells in the coal bed play, 48 in the quarter.

We anticipate in the 29 wells that we've 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 built 69 infilled wells and we continue to be encouraged by the results and 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.

And I want to define a little better what we mean by that.

The bread and butter has been the low-pressure Devonian shale play.

This target of this low-pressure Devonian shale package includes the Lower Huron, Cleveland, Lang Street, and the low-pressure Marcellus.

Colloquially, this play seems to be below everyone, the Lower Huron play.

Rather than fight that trend we want 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 2.5 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 -- 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 support the decline curve 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 3-P 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 on are on line.

We've reported a couple of good flow rates from the wells last quarter, the second and third wells had 30-day average daily flow rates of 1,900 MCFD and 2,100 MCFD 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 rates to be approximately 1,500 MCFD so those are looking pretty good.

The completed well costs for these Berea wells are lower than Lower Huron, 1.4 million to $1.5 million.

This is due to the fact that the Berea sandstone drilled a little lower than the shale.

We are still in the early phases of this play and have some technical uncertainty about drainage areas, laterally and vertically.

What I can say is 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 studying a total of 25 to 30 Berea wells this year with the majority of those wells being in Kentucky.

So we're gearing up that play.

On to the reserved implications for Berea, we anticipate that we had 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 using that word twice.

I went to public school.

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 seismications suggested by thousands of locations.

But suffice to say that if the drilling results continue to be satisfactory, we should start to see p-3 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 stimulating have tested other collateral unconventional non-organic sales, kind of a weird way to say it.

You know, unconventional has been bucked to be shale.

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 organic shales.

We're going to spud three Ravencliff wells, three Big Lime wells, and five horizontal wells there year.

All horizontal, to see if these collateral nonorganic, rich shale targets have some potential.

All right.

So that's the Berea, Astoria, and 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 of one of these could be re-entry with vertical well with a history citizen 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 re-entries, where we re-entered 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 re-entry 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 "Re-entry wells" are consistent with what we've seen from 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 re-entry program to date as quite encouraging so far, and again, we would anticipate P-3 additions to reserve 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 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 fact stacked multilateral in Kentucky in the third quarter.

So we -- we're a little behind on that, but we're catching up pretty quick.

In summary, on the extension and re-entry 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 play footprint.

We're continuing to add modestly to that position.

Again, we have no reserves currently in any of our P-3 categories in the 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 Wetzel County, Doddridge County, and Lewis County, West Virginia.

The horizontal Marcellus well averaged 1.9 million cubic feet per day in the first 30 days.

Keep in mind just to remind everybody, at Equitable when we talk about IP's, 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 IP's, 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 -- 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 cost $6 million to drill and complete.

We did a lot of science on this well.

Including microseismic 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.

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 -- how extensive we can apply that technology.

But anyway, we're -- we're pushing the envelope on -- on air drilling in this high-pressure Marcellus.

The three vertical Marcellus wells have not been on line for the 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 choked significantly with 850 psi case in pressure, obviously that's a midstream issue.

But anyhow, the actual flow rates are 600 MCFD averaging 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 -- 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 morning's press release, we're making our first commitments to midstream projects to support our high-pressure Marcellus development.

Equitable Midstream will build two 20 million a day stripping plants, that's 40 million a day in total, and 30 miles of supporting gathering, piping and 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 Marcellus development and give us flexibility to lead a larger collaborative midstream 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.

Under the Utica, we're in the process of fracing 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 play, Equitable is turning into a reserve addition machine.

That's just what's happening.

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, 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 force 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 one 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.

The Marcellus, more wells midstream and some acreage acquisition accounts for approximately 55% of the increase.

Other midstream activity accounts for 39% of the increase.

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 with 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 the completion of making phase one 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 as we previously discussed with you.

We're not there just yet.

But I will inform when you we do get there.

To remind you, one year ago, our average daily sales rate was about 206,000 MCFD and we started the year at about 210,000 MCFD.

We are in the process of integrating this information related to emerging plays and our ability to drill faster into our 2009 business plan.

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?

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 color on how you're thinking about them with respect to proved reserves.

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 by the end of the year?

Like you would go to the end of next year, or is it still going to be that you still have to drive the location to ultimately count in the reserve category?

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's out with some comments on this and while they're asking for comments on what they've -- what they've said, I think based on what we need 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, t the notion of the risk of 3-2 and p-3 reserves particularly for the shale plays and very specifically Appalachia, isn't as troubling.

The risk isn't as troubling as it might be for other plays elsewhere.

And I made the comment that 50%-some of the wells we drilled this year weren't even on locations that were booked, you know, as -- as proved when we drilled them.

That's not a good answer.

What we will 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 models an assumption of how many of those 4,700 wells will ultimately be produced.

So I -- 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.

Murry can you talk about drilling costs per well for little bit with respect to the Marcellus play --

Yes.

The -- the re-entry specifically -- I said this before and it hasn't really changed.

Because most of the time it looks like we'll be drilling a new horizontal well, we previously drilled a vertical well, I don't anticipate that those cost are going to be substantially different.

We do have a pad so that saves a little bit of the cost.

And there's some rudimentary road to the old vertical well that we can use.

So there's a little bit of a cost and decrease versus a brand-new location.

However, that's really not the value drive for -- 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 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 really would like to try to get those horizontal Marcellus wells down to about $3 million or so.

Great.

And just one final question.

I missed, Phil, what you said how much we have on the revolver.

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 -- 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 -- 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 zoning, or it could have been better if it actually was in the Marcellus?

That is a very good question.

And -- first of all, I think the production rate is quite good.

And it started out a lot higher.

As I mentioned, we at Equitable talk about the first month average daily flow rate when we talk about these numbers, so you'll see the numbers lower.

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 that -- 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 -- 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 -- maybe a little 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 -- 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 be getting characteristics from the Hamilton in this well anyway.

So -- if that helps you or not.

But that's where we're early.

Yes.

No, that's -- that's great color.

And are you aware of like -- some of the counterparts in Appalachia what -- what they've done or pretty much are they saying in -- in the Marcellus well area you're -- having some of them done in Hamilton?

Scott, this is Dave.

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 in Hamilton.

And I think we're able to frac the entire extent of the Marcellus by going into the Hamilton.

We don't think we're missing anything in the Marcellus.

But it's much more -- early days it seems it's much more predictable.

But as we're -- it's still a tradeoff.

Okay.

No, that's great.

And could you talk more about air drilling?

Give us sort of the advantage of this, going to the air drilling what really that -- what that means.

Well, it -- it's cheaper.

I mean, it -- if it works, at least on paper, you know, you could -- you know, by the way, again, I -- I'm going to give you number, I don't want you to hold me directly to them.

But we think with the conventional -- 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 minus -- now the dry hull 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 -- you still have to frac it with slick water just like the other wells.

So it's -- it's got some significant potential leverage on cost.

If -- if we can pull it off.

However that cost is because we're drilling it quicker.

Okay.

And then the --

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

Right.

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

Okay.

One followup.

Murry, I would like you to comment on your current thoughts on the regulatory issues.

Folks talking about in the Marcellus.

Well, yes.

I think I mentioned on the last call, we were a little disappointed on how that evolved.

The water issues?

We were disappointed on how that evolved.

I would 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 dialogue surrounding what's going to happen on the water issues.

Beyond that I will say that, , Pennsylvania does not have a severance tax at this point in time.

Under certain conditions we are not -- we are not against their being some more revenues generated from the wells.

If it facilitates the bureaucracy that needs to be in place to approve the wells and -- and get through all the permitting processes, etc., etc.

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 a rocky

We do view this as being just growing pains.

I'm sure for the two companies who got particularly hammered hard, if you ask them, it may have been a portion at the time.

But we did -- to everybody in the Marcellus, these are just growing pains.

Okay.

And you don't see any permit going forward, you know, executing at least over the next, say, 12 months, the --

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 Authority.

We are mostly in the Ohio River basin.

And to this point in time, there is no Ohio rIver Basin Water Authority that is required -- that is being required to issue a permit for water, so we have a little bit of a special situation in southwestern Pennsylvania.

None of the things you have heard about pertain directly to the areas in which we have acreage.

Keep in mind, all 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.

Please go ahead.

Yes, hi, this is [Jay Burny] actually.

Oh, oh, okay.

Hey, Murry, how are you?

Well, thank you.

Just a quick question on the comment you just made about severance tax.

Is that something being discussed now?

That's the first eye heard of it in Appalachia?

It's very loosey goosy right now.

I just wanted to point out that that's -- yes, Pennsylvania is unique in the fact that it doesn't have one.

We do need cooperation.

Everyone in the industry does need cooperation from -- 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.

Then the other question was regarding the industry.

Resources announced a deals here with Mark West.

And is that the kind of stuff that you would also be I guess competing with Mark West on, and, , if that's the case, then how does one pick one versus the mother just how does the industry play out for the gathering and buildout given the reversions in production in

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 -- 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 I think we've mentioned before in this Marcellus play, no individual operator has more than 20% of any area that would -- 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 the team have decided to do for our initial work in the Marcellus is put two skids out there.

20 million 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 -- So we're trying to build some backbone.

But it is not possible, I don't think, for Equitable to sort of go out and it's too big a project for one company at this point at its sole risk to take this on as a major corridor.

A couple, $3 billion-type investment Now I think it's my view to develop little patches for a little while.

Would you consider contracting with companies like Mark West?

I mean, it's a being enough industry, big enough players, enough players.

Is that something to consider, or are you --

Yes, absolutely.

But just as you read about one small announcement.

They're talking about a 30 million-a-day deal --

Actually 150 I thought --

I'm talking about what the processing is with Mark.

There's a bunch of other midstream companies who are now up here talking to a lot of us.

They talked to Equitable, I'm sure they talk to Range, and Chesapeake, and et cetera.

They're companies that never used interested in this basin who are now interested in this basin who are much more pure, midstream 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?

Talking about the geology, but it seems that some of the changes as geography change, 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, probably anybody you think of as being a sizable midstream company is in discussions with multiple producers up here.

Okay.

One last question.

And kind of a theoretical one.

Are you ready to think for Equitable as the reserve life peaks out at, obviously identifies so much in reserve --

Yes.

Good question.

Where do you think it peaks out for --

That's a great question.

Since Dave and I have been here, we've continued to struggle with trying to get our repeat down.

And if t seems the more we do -- and it seems the more we do the more it goes up.

It's been 35 years, we're getting updates --

Clearly that's the wrong answer.

These over Ps are way too high.

That means of necessity production has to go up one way or the other.

Otherwise this question about whether the relatives 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, R over P is not going down given the number of thing that we're doing and the number of opportunities that we're getting.

I hope a few years from now we're going to start saying that it's coming down, although that will be a gone/bad news story, right?

Sure.

Again, good quarter and thank you for the update.

Good.

Thank you.

Our next question is coming from Rick Gross.

Please go ahead.

Good morning.

Hello.

Yes --

Hello?

Yes, we can hear you.

Sort of.

Sort of?

Yes.

Hello?

Yes.

Go ahead.

Okay, I'm sorry.

In regards to kind of NPV, 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 NPV, you don't have lease expiration problems like a lot of these guys do in these new shale plays, is there a -- a possibility that we -- we accelerate the processing of this by bringing in somebody else on a promoted basis, maybe not right away?

But as we think about how do we get, you know, under a 30-year reserve life.

Is that --

Yes, hi Rick, obviously the shale value going to drive all of these decisions.

The question is what kind of trade do you make when knowledge is insufficient to be able to figure out what to do.

I -- I will say this, though, we've been very consistent in this overall development model.

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 are confident that there are reserves there and that there's -- there's a sufficient incentive to build midstream infrastructure.

And you can argue whether it's us build it or others build it.

But to have midstream infrastructure.

So phase one is we build a little -- get enough wells there that you can define a reserve base.

Second, commit to and build midstream, and then drill the heck out it to build the midstream infrastructure.

That is our overall business model.

Now the question you're asking is -- 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 don't know which are the best and which 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 wore 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 this -- each corridor 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, 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 various, it's not as though your patented drilling and drilling 20 drills off a given path.

You have a multiridge, flat trucks, all this kind of stuff.

Is there anything in the way of, as you build kind of scale that from a statistical cost curve that will help you mitigate costs so that you aren't spending all your time loading the equipment around from sample to sample as opposed to drilling a venture configuration of things?

Well, I think --

I don't -- I don't know --

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 sail that we have here and the fact -- of the scale that we have here and the fact that we can go back.

A lot of these wells are patented and have already been there.

So, you know, 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 an outstanding job on.

I think what we're hoping for is that we get a little bit more recovery per well.

So -- the proof is 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's clearly scoped for technology improvements is there.

I don't know that helps or not.

I think logistically, I mean, Equitable -- 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 part of being in Berea that you had kind of gone back into Kentucky.

You may have some areas where you've historically had -- called vertical walls.

And maybe you haven't exploited the other areas for whatever reason that you may have not commercially -- Weir, Big Line and places that people 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 for the areas that to some degree are worth contemplating or aren't anywhere near, we'll call it the reserve --

I think -- you know, where those other zones had previously produced, Rick, were at the -- the reservoirs were more conventional, high-permeability reservoirs.

I think that's happening with the new technology in those reservoirs, the Berea, Big Line, Weir, etc., hopefully is that you're going into the zones where those sands have become less permeable, less porous, and the factors were less sufficient to make economic wells -- economic vertical wells.

So in a way, there's -- they're not shales, but they're near shales from a -- 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, stripping plants, this is going to be a full-scale call extract everything in sight calls.

You assume correctly, and just like the others from Marcellus, we will find out if we need something bigger as it comes down the road.

An earlier caller had made a comment about the range will we think that misunderstood what range is.

They were talking the 150 they were talking about was pipeline capacity.

The 30, the stripping.

Okay.

And who's the big pipe outlet for this?

Theres -- Every big pipe in the country is having discussions, as well.

Obviously the Ohio valley is a major conduit in that its through the Appalachian basin.

And this gathers --

The gathering -- No, the gathering is going to be bits and peas.

You know, I think it's -- we think it's going to depend on where in the Marcellus.

The big part, we can get it to market.

Actually it's going to be multiple solution -- Yes.

Kind of say Dominion, you know, mostly up here.

You've seen a variety of announcement.

I think it's fair to say that if there's a pipeline company where they haven't said anything about wanting to do something in Marcellus, they 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, it's Faisel from Citi.

Good morning.

How you doing?

Fine, thank you.

If I could 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 production do you think you guys have in -- in the backlog?

Is there a way to answer that now that you have more experience in the 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?

Yes.

Until you run the perfect experiment.

Where you have pipes that are clearly unfilled.

And you can compare the production from the wells to a time when you had pipes that were filled.

You can't run that experiment.

I mean, it has the potential perhaps to give us some insight on that.

But I can't give you a number right now.

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

That's the roadmark that we're looking for, right?

Yes.

What's the timing on that?

When do you have more information?

If we do it, I'm sure it would be in the context of our annual plan and budget.

That process is just getting underway.

On the CapEx budget, that's going to -- that's going from 122 to 1.6 billion.

Is that correct?

That's correct.

Okay.

And in terms of -- in terms of -- of that CapEx budget carrying forward, giving your drilling plan and your structure 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 that carry that number forward.

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.

The team's really doing a good job.

We're doing all that and putting it into the 2009 plan.

And -- and I really don't want to forecast the number at this point in time.

Okay.

With your cash flow that you have been helped by the deferred tax line.

I mean, how does that look going forward?

Is there -- is there a way to -- does that come back to you any time soon?

Or is that going to be kind of a -- a temporary source 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 and get a refund which we will receive in 2009.

For the rest of 2008 and actually for the foreseeable future as -- 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 back again.

And from there forward, it will be carried forward.

So I -- I don't know if that answers your question --

Yes, but certainly for --

For the rest of this year we'll continue to be in that situation while we're generating net operating losses.

Okay.

Again, on the -- on the executive plant, the employee cost that you guys had designed there to export the strength of your numbers, you didn't have it this last quarter.

But the stock price came off kind of after the quarter ended.

Trying to figure out how that exactly looks and gets booked.

Well, we -- we've currently booked -- actually a little more expenses 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 Q 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.

Getting back to the Sandstone, do you guys have any feel for when you're going to give us the metrics on EURs-type curve and where you think the cost could go on these wells?

Yes.

It's going to be year end, I think, Becca.

We're still wondering how much we're draining with these things.

We've got to kind of -- we're doing some more technical work, some engineering work on that.

And I really got to watch these wells very carefully for a while.

I mean, not to put too fine a 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 more confident in our ability to project EURs and decline curves because the models matched the verticals matched the horizontals, so it all sort of fit tightly together.

This is bit of a new world for us.

And I'm going to be a little more cautious on projecting EURs for a while.

So I don't know.

End of the year, I'll -- give you updates every quarter on how I feel about that -- I'll give you updates every quarter on how I feel about that.

My own guess, it will probably been of the year or so.

The 3,800 locations, you've IPd this cost, it's significant potential that clearly is not your stock, and so --

Where at --

Just -- just like to see that.

How much incremental infrastructure are you guys looking at putting in for the Berea?

You mentioned incremental --

Right.

I mean, it would be wonderful if all this stuff was at exactly the same place.

But Dave is in the position of getting a Berea kind of corridor together now.

It's not we have none, we just need to upgrade it substantially to cover the kind of flow rates that we're expected from the Berea.

Dave, you want to talk about that at all?

Yes.

Yes.

So again, it's -- more gathering is required, etc., etc.

Bigger pipes.

So we're -- we're moving quickly ahead on that.

Okay.

The next question -- how much overlap do you have that with the Marcellus --

Yes, there are places where it overlaps.

That's a great question, Becca.

I've tried now over the past 18 months to classify this whole opportunity in a couple of different ways.

And I've probably been unsuccessful and not as clear as I want to be.

What I'm saying now is the Lower Huron play are a bunch of shales.

They're not all called Huron, but they're a bunch of shales.

And then there's Berea, and in any one location, we could have Berea and a bunch of the lower Huron shales.

One location that we're drilling 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'll be picking all of the zones that we think are potential.

And without putting this on the map it's hard to describe over the phone.

We'll try to start generating maps so you can see the areas where you have multiple zones.

I still think on average over our entire acreage suite, on average there's a little more than two locations per -- two wells per location.

On average.

You ought to get some kind of a sense of the big picture on that.

But for infrastructure the Berea is much -- 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.

Modified as opposed to greenfield?

Exactly.

Okay.

Two other questions -- sorry for taking too much time.

For Marcellus EURs at year-end also?

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 EURs 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 LBC fit with that?

Light of that, and in light of a lot of needing a lot of capital?

Yes.

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 public sector 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 with that, Becca, is we're in for a rate case, and I want to see that rate case carried forward, and beyond that, we don't really have anything structurally to say about the LDC.

And is there any supply comment on the rate case?

Is there a mandatory time where they have to get a decision?

Early next year.

Okay, thank you.

Thank you.

Our next question is coming from Holly Stewart.

Please go ahead.

Good morning.

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

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 than some places, the Cleveland will be better and worse in some places.

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's such a broad range.

It's not constructive.

Plus we don't have enough Cleveland wells anyhow to make a specific decline could have been.

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.

Yes.

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 with Reed].

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 about there being tightness in the market.

Can you talk about there being slowness at all, or how are you handling it?

We're handling it by putting in preorders and ordering a few months ahead of time.

That's basically how we're handling it.

So our view has been, 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 -- right.

They can go up and be a higher percentage.

Generally speaking, that's how you might calculate the increase in -- in well costs that are coming from the steel.

Okay.

And 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?

Yes --

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.

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 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.