EQT Corp (EQT) 2006 Q3 法說會逐字稿

Good morning.

My name is Denise, and I'll be your conference operator today.

At this time I'd like welcome everyone to the Equitable Resources third quarter earnings conference call. [OPERATOR INSTRUCTIONS]

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

Sir, the floor is yours.

Thanks, Denise.

Good morning, everyone, and thank you for participating in Equitable's third quarter 2006 earnings conference call.

With me today are Murry Gerber, Chairman, President and Chief Executive Officer;

Dave Porges, Vice Chairman and Executive Vice President Finance and Administration; and Phil Conti, Vice President, Chief Financial Officer.

In just a moment, Phil will discuss our third quarter financial results that were released this morning.

Murry will then update the status of the Peoples and Hope Gas acquisition, the Big Sandy project, coal bed methane downspacing and horizontal drilling.

Following our prepared remarks, Murry, Dave and Phil will be available to answer questions.

But first I'd like to remind you that today's call may contain forward looking statements related to such matters as our pending acquisition of Peoples and Hope, and the financing of that acquisition, our plans to reorganize as a holding company, the forecasted drilling programs and sales volume and Supply segment, and other financial and operational matters.

It should be noted that a variety of factors could cause the Company's actual results to differ materially from 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 2005 form 10K, the 2006 third quarter 10Q which will be released today as well as on our website.

I'd now like to turn the call over to Phil Conti.

Thanks, Pat, and good morning everyone.

Before getting to our results for the third quarter, I wanted to mention that we expect in the near future to file applications with the Pennsylvania Public Utility Commission, as well as the Public Service Commission of West Virginia, for approvals to reorganize Equitable Resources as a holding company.

The Company has been working toward that since the repeal of the Public Utility Holding Company Act of 1935, and we believe that the reorganization is in the best interest of our customers and shareholders.

With our current organizational structure, Equitable Gas Company, the regulated LDC is a division of Equitable Resources and because of that we're required for seek regulatory approval for many Equitable actions that are not directly related to the utility business.

Examples would include a variety of corporate transactions such as acquisitions, corporate restructurings, financings with tenors of greater than 364 days, etcetera and not just utility transactions but any transactions that the parent company may pursue.

As you can imagine, this requirement can be quite cumbersome when attempting to take advantage of opportunities and market conditions.

In addition to removing this regulatory requirement, we expect that moving the holding company structure-- moving to the holding company structure will provide greater flexibility and financing Equitable's utility operations.

Potentially including the financing of the Peoples and Hope Gas acquisition.

And should result in a lower over all cost of debt for our utility operations over time.

Finally the move to a holding company structure will result in a more typical organizational structure for a company that operates both regulated and unregulated businesses.

I will now briefly review the third quarter results announced earlier today.

As you saw, Equitable announced earnings per diluted share of $0.26 for the quarter, compared with earnings per share of $0.38 in the same quarter last year.

The third quarter last year was somewhat noisy as it included a $19.4 million gain from the sale Kerr-McGee shares and a $12.7 million pension related expense at Equitable Utilities, and those items complicate any quarter-over-quarter comparison.

The details of those two items were provided in our third quarter 2005 earnings report dated October 27th, 2005.

In addition to the one-time items expenses related to the Company's executive compensation plans were $9.3 million lower in the current quarter.

We also had several unusual expense items in the third quarter of '06, which I will elaborate on as I briefly review the business unit operating results starting with Equitable Utilities.

As you know the third quarter is typically a quiet quarter from an operating standpoint for Equitable Utilities, but Utilities did have operating income in the quarter that was up $11.5 million versus the third quarter of '05.

That increase was primarily driven by the absence of the $12.7 million pension settlement expense which was recorded in the third quarter of 2005.

Utilities operating income also continues to benefit from higher pipeline revenue resulting from the Equitrans' rate case which settled earlier this year.

As well as higher commercial revenue, mostly due to the settlement of a measurement dispute with a large commercial customer and higher gathering volumes.

Those positive variances were partially offset by lower marketing revenues and $3.7 million of transition planning expenses in the third quarter associated with our preparation for the pending acquisition of Peoples and Hope Gas.

We expect transition planning expenses to continue to accelerate a bit in the fourth quarter as we move closer to closing the transaction.

Moving on to Equitable Supply.

In a moment Murry will update you on the Company's progress with some of our more unconventional activities at Supply.

But first I'll give you a brief update on the continued progress of our more conventional production and drilling operation.

The production and gathering segments operating income of $63.2 million in the third quarter was down significantly, about 21% compared to last year.

That decline was driven primarily by a lower average well-head sales price of $4.66 per Mcf which was $0.77 per Mcf less than the average price in the third quarter last year and I'll give you more on that in a moment.

Higher operating cost much of which were of the unusual variety also contributed to the reduction in operating income and more than offset a 772 million cubic feet, or over 4% increase in sales volumes in the quarter.

Year-to-date adjusting for the sale of our Pennsylvania and Ohio properties in 2005, our sales volumes are up 5.4% and we do remain on track to meet our sales target for the year.

I mentioned the $0.77 per Mcf decline an average well-head price, that decline was driven by three main factors.

First more than half of the decline was due to the average NYMEX price for the third quarter 2006 of $6.58 per Mcf, which was down almost $2 per Mcf from the third quarter of 2005 when the impact of the hurricanes caused the NYMEX to rise dramatically.

In addition, the average gathering fee in 2006 was $0.24 higher than last year.

And finally take away capacity in Appalachia is extremely tight, as we mentioned before.

And as a result, a small number of our many sales point, so there's been a significant competition among producers to sell gas to buyers on a take away capacity.

Because of that constraint we have decided to enter into certain discounted sales arrangements to ensure that our gas continues to flow.

This quarter about one Bcf of Supply sales were discounted by an average price of approximately $1.75 per Mcf, from the index price.

These arrangements had the affect of lowering the average well-head price by about $0.08 per Mcf in the third quarter.

Looking forward, the Company has entered into agreements to sell about one Bcf of gas per quarter at a similar discount through 2008.

We have entered in the contracts out as far as 2009 due to the fact that some of these arrangements were only available as multi-year deals.

Comparing our low cost structure to the near term forward sales curve, it was clearly economic to sell this gas at a discount rather than shut the wells in.

Once completed, the Big Sandy pipeline is expected to provide relief to this takeaway constraint for Equitable Resources as well as third party producers in the region, and Murry will update you on that in just a minute.

Since the majority of Supply’s equity production has gathered in-house the flip side of the increasing gathering fees, which I mentioned reduced our effective well-head price, is that gathering revenues of Supply were 18% higher than last year, as a 30% increase in quarter-over-quarter average gathering rates more than offset an 8.6% reduction in gathered volumes.

The reduction in gathered volumes is primarily a result of transfer of West Virginia gathering assets to utilities at the beginning of '06.

Supply operating expenses were $10.4 million higher than the previous year, some of that was expected but as I alluded to a significant percentage was somewhat unusual.

Per unit lease operating expenses or LOE were $0.32 per Mcf, 10% higher than last year.

And gathering in compression or G&NC unit costs were $0.42 per Mcf or about 45% higher than last year.

As a reminder these expenses are lumpy from quarter-to-quarter.

Our per unit forecast for the full year 2006 is an average LOE of approximately $0.30 per Mcf, and an average G&C unit rate of approximately $0.40 per Mcf.

The increase in gathering and compression expenses was expected and is due to the ongoing addition of compression, higher electricity rates, and increased metering and maintenance as we continue to improve the operation and integrity of our gathering system.

Also as expected, DD&A expenses was 11% higher as a result of increased volumes and higher DD&A rates resulting from our stepped up fueling program and infrastructure investment.

As to the more unusual expense increases in the quarter SG&A expenses were $5.1 million higher than last year.

Mainly due to higher than normal legal fees and bad debt expense as well as a reserve for West Virginia royalty disputes.

In 2006, the West Virginia Supreme Court issued its decision in a case involving an unrelated party, in which royalty owners in the state filed a lawsuit, claiming that the defendant in the case underpaid royalties by improperly deducting certain post-production costs and not paying a fair value for the gas produced from the royalty owners leases.

The court ruled in favor of the royalty owners and since the ruling suits have been filed against other producers in West Virginia, including Equitable, on similar claims.

We've made an assessment of the possible adverse impact to Equitable, and that impact is reflected in our current financials.

So the combined impact of the West Virginia royalty situation, unusually high legal fees and bad debt expense related to an entity that hauls crude oil, explain the majority or about $7.3 million of the $10.4 million increase in operating expenses.

On the drilling front, the Supply unit did drill 174 wells in the current quarter and 449 wells year-to-date versus 137 wells in the third quarter of '05 and 310 wells through the first three quarters of last year.

In fact, we have drilled nearly as many wells through the third quarter as we did in all of 2005 and Supply is on track in '06 to exceed it's drilling target of 550 wells.

Finally as you may have noticed for the first time we have provided our 2009 hedges in the earnings release.

As you can see on an absolute volume basis we are currently significantly less hedged in '09 than the prior years.

And actually the average price of the hedges that we do have in place for '09 and beyond is well over $1 higher than the average hedged price in the preceding years.

And with that, I'll turn the call over to Murry.

Thanks Phil.

Welcome everybody.

I'm going to take a few minutes to update you on the considerable progress we're making on several elements of the growth strategy.

First we'll go through the Dominion acquisition.

Just in short there the settlement discussions are ongoing.

Our strategy is to reach settlement with the majority of the parties prior to the hearing date which is the week of November 13th, in Pennsylvania I'm talking about now, and request that the administrative law judge would certify the settlement to the PUC prior to the year end and close in, sometime shortly thereafter.

If we can't reach settlement by the hearing week, November 13th, because for whatever reason we believe that the settlement, the interveners are just not, not lining up in the right way, we will go through the full hearing schedule instituted by the Pennsylvania PUC, which will result in our having approval sometime probably late in the first quarter.

But as I said, we're moving swiftly at this point to try to reach settlement before that November 13th, week of November 13th hearing date.

In West Virginia, the hearings are tentatively scheduled in December.

We're feeling like that order will probably go through at year end or slightly thereafter.

So we're kind of on track there in West Virginia, and with the FTC obviously, they're-- we have to deal with the FTC on this as well, and we're optimistic that definitive rulings by the State Utility Commissions will move that process to completion pretty well.

So things are pretty well on track there, and the hearing, the hearings are moving along and everybody's filed all their stuff, and we're working with them to try to get settlement as soon as we possibly can.

On Big Sandy, we are expecting at this point to receive our certificate a little later than we had mentioned previously by the end of November or early December this year.

It's a little later than we'd hoped, but we're still targeting the same date for startup in '07.

We had, obviously some cushion built in our schedule, we are very prepared for this project.

We have 87% of the right-of-way acquired.

All of the pipeline has been delivered to us.

So that's, that's good.

And all along lead time items including compression, extraction facilities, all that stuff has been ordered and firm delivery dates have been provided.

So as soon as this certificate comes our way, we are moving ahead.

Our team is chomping at the bit to get this important pipeline done so we're full speed ahead on this project.

Moving to drilling, Phil mentioned that our conventional drilling is well ahead of last year's pace.

Parenthetically, rate availability continues not to be a problem for us.

We're currently running 20 rigs in Appalachia right now, 18 for our conventional program, and and two rigs for our horizontal program.

I've just updated you to current.

Phil gave you some quarter end numbers, but we have drilled 500 gross wells as of the 25th of this month.

And we are quite confident in comfortably exceeding our 550 growth well target for the year so that's a great milestone, great credit to the team.

Obviously this is a record drilling year for Equitable Resources.

On coal bed methane down-spacing, you'll recall that we're testing the economics of down-spacing from 60 to 30 wells; we're on track to drill our pilot program.

We intend to have 17 wells drilled by the end of the year.

Seven have been drilled, five have been fractured, and two have been turned in line so far, although the production results aren't quite ready to make any definitive comments.

You should be aware that excluding the pilot production from our Nora field, which is dominantly coal bed methane is up 12% and 12. -- 12% for the quarter and 12.3% year-to-date versus the 2005 period.

As I said it's a little too early to make any broad conclusions from the volumes we've seen so far.

The value driver for this down-spacing project-- yet they're two value drivers.

Ones to accelerate production from coal bed methane and hopefully to add reserves.

Investors should be aware that it's going to take some time measured in quarters not weeks or months, to assure that these drivers are being achieved.

Production acceleration without reserve addition could occur, it could also be very value accretive at current prices, but obviously we're hopeful for both production, acceleration, and reserve additions.

We'll update you at our next call on how that evaluation is proceeding.

Lastly I do want to spend a little more time on horizontal.

We are on track to drill our first five horizontal wells in the Devonian shales that we previously discussed.

I am encouraged by what I have seen so far to the point that I am, I'm saying internally that horizontal drilling in Appalachia has the distinct potential to be a game changer for this basin.

Our status is as our follows.

We have drilled one well, completed it and it is under test.

We have one well drilled and that well is awaiting completion which will be done next week.

We have two wells drilling, one of these two will also be completed next week, because it's on the same location as well number two.

And the last well is in permit process.

Highlights so far.

We drilled the curve and the lateral in the first two wells which means this is including setting of the completion system.

That's about 2,500 feet of drilling, 1,800 feet is lateral.

We did that drilling in seven to eight days, seven wells -- seven to one, eight on the other.

Timing on this part of the operation was more than 35% better than anticipated, which is a staggering achievement I think.

We drilled and completed the first well for about $1.5 million, you'll recall that that's about $200,000 less than I mentioned to you at our last call, and remember we're casing the curve in these first few wells to make sure that we don't have any undue operational problems.

Let me tell you why I'm so encouraged so far.

When we started our horizontal drilling program we had four major concerns and questions.

First could we drill a horizontal well to our planned total depth in these shales?

Given the nature of the low pressure in these shales, accomplishing that first basic step was not a given.

Second, could we subsequently put equipment into the hole that'll allow us to fracture and complete the well as a producing well?

Results were not clear to us originally that we could get our packer and completion equipment to the total depth of the hole.

We've been able to do that very well.

Third could we do these first two things at a reasonable cost?

And of course lastly, the fourth concern, probably the Babe Ruth of the concern is, would the wells produce enough gas to be economic and a corollary, would this technology result in lowering unit development costs, or if not lowering unit development costs at least accelerating production enough to offset flat or increase development costs.

It is fair for me to say at this time that we are pretty darn confident that we have satisfactorily answered and addressed the first three concerns.

We can drill and complete horizontal wells in this space and at a very reasonable cost.

Well within the guidance I have given up in the past.

And there is scope for further cost reduction in doing these horizontal wells.

This has been an extremely encouraging milestone for the Company to have passed in this quarter.

Now, the last milestone obviously is very important relating to the economics.

While it is, still too early to tell how the economics are going to work definitively, there is nothing I have seen that would cause us to stop our horizontal program.

Quite to the contrary.

At this point we are in the planning phase of a much expanded horizontal drilling program.

That expansion will be designed to sort of move beyond some of the technology issues although we're still testing different schemes.

But the main goal of the expanded program is to assess reserve addition and production acceleration potential.

Now I don't have a specific well number on that yet.

This is all happening pretty fast around here.

But I will keep you updated as soon as we know on what that number is, and what the specific goals and value drivers will be for that expanded program.

Obviously it's again early in our analysis of both the horizontal and the in-field drilling program, it'll take some time to evaluate the economics, but I think the bottom line is, so far, so good for Equitable.

And with that I'll turn the conversation back to Pat who'll open the line for questions.

Thank you, Murry.

That concludes the comments portion of the call.

Denise can we please now open the call up for questions?

[OPERATOR INSTRUCTIONS] And we'll take our first question from Ray Deacon of BMO Capital Markets.

Please go ahead, sir.

Yes, hi Murry.

Congratulations.

That's great news on the horizontal wells.

Thanks, Ray.

Yes thanks.

I was just wondering, I think earlier you had talked about if you were able to-- maybe it was the last conference call, that the potential you viewed as much as 900 Bcf if you were able to pick that one area in southeast Kentucky and be able to drill in on horizontal wells.

I guess it's going to be probably be what, three, four quarters before you really know that, but I guess, does that 900 Bcf number still seem like a reasonable guess?

Well, in answer to the first question, yes.

It is a reasonable guess.

In answer to the second one, Ray, I think and you know this from evaluating the Company, there's going to be a process of moving these reserves through the probable, possible categories into the develop categories, and that's going to play out over sometime.

And the point of the expanded program at this point, in my view, is to set a milestone -- set milestones for those reserve additions and that the movement of those reserve additions through the various categories.

That's not a trivial process and I'm not in a position today to give you the timing on how that's all going to play out.

I'm very hopeful though that over the next quarter or so, and perhaps before the-well, by the time we have our investor meeting early next year, we'll give you as much as we can on that particular issue.

I wish I could give you, chapter and verse on that.

I mean, we have to watch these wells for a while and see how they go.

My major encouragement on this was that we accomplish things that I, at this point did not think we would accomplish so quickly or so well.

And that relates to the costs.

And now we've got to kind of scope this out and make sure we're, you're executing to move those reserves to the proved developed category as soon as possible.

And there are a lot of different paths and I'm just not ready to pick one one yet, but I'm very encouraged.

Great, well thanks.

Is there anything on the technology side that has made this more viable or is it just that it hasn't been tried before?

Well, to be honest, I'd rather not talk about that.

Okay.

All right.

I mean, I can-- you could probably see why.

I think though as much as technology, which, sort of there's lot of that out there these days, as much as technology-- I mean this is a testimony to something that I've been confident in throughout, and that Equitable Resources has a fabulous team in the Appalachian basin, that is what's this is all about.

Okay great, great.

Just one more quick one.

It seems like there's a lot confusion among some shareholders I've spoken to about how, how much-- what exactly I guess are you saying about financing the Utility, you've talk about a combination of debt and equity, and what's your view I guess what the split would be at this point?

Phil will take that, Ray, if that's okay.

Sure.

Yes, Ray nothing has really changed since the last call.

You're right, we're still going to-- we still believe we'll finance it with a combination of debt equity and possibly asset sales.

We mentioned on the last call that probably it's unrealistic, even without this acquisition, for Equitable to stay an A-rated credit rating, so-- but that's as far as we're going to go with that right now..

We'll give you more as we get a little closer to the closing of the acquisition.

Okay thanks, Phil.

Thank you.

Our next question is coming from Carl Kirst of Credit Suisse.

Please go ahead.

Hi good morning everybody.

Hi Carl.

Just staying with the horizontal for a second, and I understand we don't have time frames here, but are you still thinking that to get enough -- the data that you need to kind of make these decisions as we go through the pilot program we're looking for around roughly 20 well data points or as--I guess has the early positive data perhaps accelerated that, pushed that down?

Maybe we only need 15 data points.

The latter, the latter.

I mean, the positive early results, are -- and that's what my comments are meant to say, Carl.

The positive early results are causing us to rethink a much expanded horizontal program.

I just don't have the number right now and that's all I'm going to say at this point in time, but much expanded.

Fair enough.

Just with respect to, and not sure if Phil can be able to comment on this or not, but with respect to potential noncore asset sales, reserve sales.

Can you, I guess comment that whether or not the volatility of late of gas prices what happened at the send of September the rally here, has that any of that impacted the process at all or are you finding area producers interested?

The answer to your question is we haven't found that to be an impact at this point.

People are interested.

Great.

And then just lastly, Murry, any update as far as thinking or progress, you got a lot on your plate here, but identifying a partner for maybe some deeper zone explorations?

No, no progress on that.

And just so we're clear, I-- we will do this with a partner if we do it, and I'm happy that others are starting to experiment with this.

I think this play will come to Equitable at one point or another and we don't feel any particular urgency to be the technology leader on this.

I don't feel the same way about horizontal, incidentally, I think we do need to be a technology leader, but on this other one I don't feel any urgency at this point to do that.

Great can I ask one other question here on the horizontal.

There's other people, other people who are looking at doing the horizontal as well.

And from my own standpoint, should we be looking at some of the other's experience, are there crossovers or is it enough that, as you mentioned earlier, it's really the team at Equitable, perhaps you guys have hit the learning curve in a little bit different way.

Do you guys, -- are you guys closely watching the other horizontal drillers or is it hey look--?

Oh, yes, no, there's no question about it.

We hope they're all successful, as a matter of fact, because to the extent we can -- I think, this is my opinion.

I think we've taken this up a notch but we hope they're all successful because we'll end up learning from each other on this one way or the other.

And as I said we drill this curve to TD in seven days, it causes us to think, for example, about considerably longer laterals for example, because of the cost and all that, and that's all sort -- those are sort of exciting things.

But anybody that can learn here is going to be, or anybody that learns something, we're going to take advantage of it.

I think it's just that we sort of taken it up a notch.

Great.

Good luck.

Thanks.

Thank you.

Our next question is coming from Sam Brothwell of Wachovia.

Please go ahead.

Hi, Sam.

Hello?

Your line is live, Mr. Brothwell.

Sorry about that, the mute button was on.

I can be touched.

You like talking to yourself these days.

Yes, nobody else will listen.

Anyway I think we've beaten the horizontal up pretty good but I had a couple of questions procedurally on--you mentioned moving this holding companies structure in on a parallel path getting approval for the Dominion asset acquisition.

Does the former complicate the later at all or how do those play off of each other, number one?

And number two with respect to Dominion approval, Murry can you kind of characterize-- are you kind of like looking at one or two hold outs on the, the folks across the table, the interveners?

Or do you have broad buy-in or are you kind of give us a little more flavor on how you see the progress there?

I'll take the latter question and maybe Phil can talk a little bit more to the issue of the holding company versus the approval.

They're the usual suspects there, Sam.

The vast majority of them have, and this is in Pennsylvania primarily, they have said that they approve of the transaction with conditions.

And that is, it's the with conditions part that is the subject of all of the interactions that the utility's having at this particular this point time.

I don't think there's anything particularly unusual in this from the standpoint that, any time a utility yield is happening recently, people, want to see what's in it for them.

And they're, they're all lining up.

And so I don't think there's anything particularly unusual here.

As I said, Randy’s moving swiftly to try to get everything settled before this hearing date the 13th.

All the submittals are in, we know all the noise, we've heard all the stuff so far, but we'd like to try to get to the point where we're-- where we can be [inaudible] to submit something that settled to the Commission.

And that's really where we are right now.

And we still think that's a distinct possibility.

So that, and that's more than you want to know but if ever-- people are supportive with conditions, and then we're just working through the conditions.

I don't really want to go into them right now.

I don't think that's useful.

Understood.

Okay, Phil will take the other matter.

Yes, as far as complicating the process as I mentioned, Sam, we were preparing to go down this holding company road anyway.

And certainly we'll stage it appropriately so as not to delay the acquisition process.

It just seemed to us more practical and efficient to establish the holding company prior to closing the acquisition if we can so that we can keep all our financing alternatives open to us.

And just to add on to that, if I may Murry, obviously the decision to go to a holding company structure invites a whole host of other questions such as, your view for-- what does the Company look like a year or two down the road?

Can you comment about your view with respect to the, if we think about Equitable's individual pieces and their ability to exist to stand alone entities?

Yes, I--Sam, I think we've said this before I think, but when we first announced the Dominion deal, what we said was that there was significant -- could be significant heft in both the Utility and the Supply group post Dominion close, course we, we have to close that, of course, but post Dominion close to consider whether it's in everybody's best interest, the shareholders' best interest and of course I'm a significant shareholder too, is it in our all best interests to have one company or multiple companies.

And I think that is still being -- we're thinking through those issues as much as we possibly can.

But I don't have anything to add right now to those, to those -- that strategic direction.

That's not what the holding company files and stuff.

Right, right.

The holding company filing was just because it makes sense -- setting aside any other issues of strategic structure, the holding company is valuable to us, makes money, it's less costly.

Okay, thanks a lot.

Thank you.

Our next question is coming from Rick Gross of Lehman Brothers.

Please go ahead.

Good morning.

Hi.

I'm going to beat on the horizontal a little bit more.

Okay.

My assumption from what you've said was that the well that was completed was the tip-top well.

Yes.

You indicated that the lateral was 1,800 feet.

Yes.

[Would you like to] do better.

Cabot's done about 3,000--

Yes.

On a couple of theirs.

Is that order of magnitude kind of what you're talking about?

Yes.

From a standpoint of the well, itself, do you have to file test results with the State?

I don't know the answer to that.

I don't think so.

I don't think you do.

I'm not sure, I'm not sure though Rick, I can find that out, I don't know.

I was going to say that's too bad because if you did, then I'd ask you to cough up the number.

First of all it'll be a full month anyway, so I wouldn't do it ahead of any, if we had to file, I don't think we do actually, but I'll find that out.

In any event you'll know what it is.

From the standpoint of drilling out the curve in the lateral.

Yes.

You were going to fully case it and you indicated that it drilled reasonably well, you were able to get the packers, all the stuff down there.

Right.

Are you going to have to use all the fancy equipment to keep the shales from sloughing or are you going to be able to do it without all that hardware?

No, well no.

There's got to be a completion.

There's got to be completion equipment in the well no matter what presuming we're going to frac these wells.

No, no I understand that.

The issue is is whether you're going to have to case through the curve and do all --

I don't know yet.

I mean right now, it's move-- it's gone so slick with the curve, with the curve case, that we'll have to make a determination at some point in time whether -- and we'll have to drill some without the casing to make sure.

But, but, we're-- that's where I said in my comments today, there is scope for further reduction in costs beyond what we're currently seeing.

I mean, we basically drill this first well at the cost that we thought we would drill it without casing.

Right.

You know, three or four months ago, so that-- when I say there's scope for further reduction it includes eliminating that step.

Okay, from a standpoint of under pressure, the other issue would be initial production rates.

Right.

From a standpoint of under pressuring, has that influenced the results?

I get the impression that you're encouraged enough from what you've seen that the underpressure issue either from a drilling standpoint or a completion standpoint, is not as significant as you might have thought to begin with.

Yes.

I mean, resounding.

What did it test?

Okay, no.

I'm not going to tell you.

Resoundingly.

Okay.

I--listen, I think this -- you keep in mind in the first five wells we're testing a lot of geologies, a lot of technologies.

I wouldn't be as encouraged as I am right now if it hadn't been for technologically what's happened so far and what I expect to happen.

Okay from a standpoint of expanding the program, is it entirely possible that you can have a half-dozen rigs running this?

Again, Rick, I am working on an expanded program.

I mean, there's whole range of potential strategies at this point in time.

But what I've got to do now is use, or drill the wells we need to drill to define the scope of this opportunity.

I mean I've got to be able to say to myself, you, others, how big this is bread box and that requires a -- I mean, we've been thinking about it, but we've got to now -- at this point I thought we'd be worrying about how to complete different, and all this other [expletive], but now that's not what we are thinking about.

We're thinking about how to plan for success rather than how to plan for drilling a well that we couldn't drill, or drilling it too expensively or whatever.

So that's where we are, and I'm really-- I'm not ready to talk about that today, but I will soon.

I mean I've got to put a budget together here pretty soon.

From a standpoint of-- just one last question.

From a standpoint of developing a type curve, how many wells do you think you'll have to have?

That's a great question.

I don't know yet.

And I think it's going to be region-- area-by-area.

We're going to have multiple wells per area and some production history to get it to the proved category.

Now, keep in mind, as you know very well, we often, and we're probably doing it today, we will often move a reserve from the probable or possible category directly into the proved developed, because of the nature of how these reserves are booked in Appalachia.

So I've got to be very targeted in how we drill these next wells to try to move those reserves from nothing to the probables and then on into the proved categories.

You see.

And I just -- until -- you know me, I'm not going to tell you until I've got the plan.

Okay.

And I don't have the plan today.

Okay, one last and I will shut up.

These -- the first five wells are sampling different counties.

They're in general sampling the lower Huron, but you're sampling in a variety of different areas.

Are you going to -- in the new program, do more spatial sampling as opposed to confirming type curves or how is all of that going to sort out?

It's going to be both.

It's going to be both.

I mean we need to sample all the areas where we think this technology is going to be valid with enough tests to prove that A, the technology works and the reserves are worth being booked.

Okay.

That's really what it boils down to.

So as far as other geologies, we've got some thoughts on that, but right now we're targeting the shales.

Okay.

The shale, the Devonian shales.

Okay thank you.

Okay.

[OPERATOR INSTRUCTIONS] We have our next question coming from Faisel Khan of Citigroup.

Please go ahead.

Good morning.

Hi Faisel.

Hi.

I wanted to go back to something I think Phil said, you had to sell gas at $1.75 discount to get the gas out of the basin?

Is that, was I understanding that correctly?

Certain places where we don't have firm transportation, there's a lot of competition.

As you see it's a small percentage of the gas, around 5%.

But yes, there are places where you have to compete and enter into a long-term arrangement to sell that gas at that discount if you want to be sure that your gas is going to move.

And we have entered a few multi-year deals to do that.

It's not a big percentage.

It's about 1 Bcf a quarter.

Keep in mind, Faisel, it's also in recognition that, firm is not necessarily firm any more.

That's a big issue.

Okay.

And this was for, how many years was this for?

Some of them go out as far as early '09, but think about it as about a Bcf a quarter through '08.

Okay.

At which time, and hopefully before that we'll have the Big Sandy going, but we did have to enter into a few multi-year deals to get what we wanted right now.

So Big Sandy should relieve all these issues?

Boy, that's-- it's going to relieve a [expletive] of a lot of them, Faisel.

I mean, this-- that's why we're going full speed ahead of on it.

Okay so assuming that the -- that is does-- are these capacity constraints in the pipeline system anywhere near where you're doing the horizontal drilling program?

Well there--Kentucky's got-- is a problem.

There's no question, and that's why we got to get this Big Sandy thing in it as soon as we can.

But there's sufficient capacity on Big Sandy to handle -- I would like to say that the capacity in the Big Sandy is insufficient to handle the production we're going to get for the horizontals, but I'm not ready to say that yet.

Right now looks like it is certainly.

Okay, got you.

And then just to make sure on the pipeline and gathering segments, the quarter-over-quarter change because you moved some gathering volumes into the pipeline, into the pipeline segment.

That's actually--it should be-- that's basically a one-for-one kind of exchange in terms of revenues.

Is that the way to look at it?

Yes.

Okay, got you.

And then on the marketing, on the gas marketing side, how do we look at that part of the business going forward?

I know it's going to be volatile based on storage, but can you go into a little more granularity in terms of what happened in the quarter?

You said it, it's volatile.

We try to I can take advantage of seasonal spreads, and we don't know ahead of time what they're going to be.

So we try to capitalize on the market when it's there, and I think you're going to just see volatility going forward on that line item.

Okay does the level of earnings at all dictated by how much excess storage capacity there is for you to play around with.

So given a storage that's full, there isn't enough capacity for you guys to use the, to use those assets to arbitrage.

I think you're going to-- wait for the fourth quarter.

You're looking at one quarter, we look-- we take advantage of opportunities that are sort of moving from the spring to the winter.

Okay.

And so this quarter isn't a quarter where we typically have big results there, it tends to be more, as we get into the winter where you'll see the impact of us taking advantage of our storage assets.

Okay then was there any mark-to-market impacts that we should be looking at this in this quarter?

Pardon, could you reask the question?

Sorry, was there any mark-to-market impact from--?

No.

Okay.

And then just on the EMP side the line loss looked a little higher sequentially quarter-over-quarter.

Just curious if that-- if there's anything we should read into that?

Not really.

I mean I think there's -- the pipeline's pressure up in the summertime it tends to be a little bit more line loss just because the pipes are under more stress, Faisel.

But generally speaking the trend is down.

Got you.

Okay thanks for the time, guys.

Okay, thanks.

Thank you.

Our next question is coming from [Rob Mullen] of [inaudible] Capital.

Please go ahead.

Thanks.

I just wondered if you could talk a little bit just about what you're seeing in terms of rig availability in general, day rates, directionally, new supply rigs coming online.

Just give a little bit of overview there.

I mentioned this just a little bit in our comments.

We've got rig companies knocking our door down to work for Equitable, I don't know what the general state of rig availability is out there.

I'm taking from that, that we're-- I'm hopeful, not cross my finger, cross your fingers that we've, we're reaching a tipping point on rig costs.

And hopefully things are going to start moving down.

I'm hopeful because we've-- I could employ more rigs if I had more locations ready.

I don't know, and I don't know anybody else's situation, and I can't really comment generally.

I just know about what's happened with us.

Great, thank you.

Thank you. [OPERATOR INSTRUCTIONS] And our next question is from Rick Gross of Lehman Brothers.

Please go ahead.

Yes, how much are you are going to take down of your own FT on Big Sandy?

Well Rick, we've-- a lot of it, a lot of it will be ours.

Okay.

And the question is, I'm sorry I don't want to give you, the reason I'm not going to give you a number, is because as we build this midstream business up a bit more, the question is how much we're going to want to take for potential third party usage or selling to customers, or whatever.

All is beyond what's been signed up for in precedent agreements.

So I'd rather not give you a number at this moment in time.

But we're going to need a lot of it just for ourselves.

And I-- we gave a number at one point that it was, but I can't remember what it is pretty honestly.

Around 60%.

Yes 60% was what we said previously, thanks Pat.

Thank you.

Seeing there are no further questions, I'd now like to turn the floor back to Management for any closing remarks.

That concludes today's call.

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Thank you.

That does conclude today's Equitable Resources conference call.