EQT Corp (EQT) 2007 Q3 法說會逐字稿

Good morning.

My name is Miquel and I will be your conference operator for today.

At this time I would like to welcome everyone to the Equitable Resources Third Quarter 2007 Earnings Conference Call.

(OPERATOR INSTRUCTIONS)

It is now my pleasure to turn the call over to your host, Mr.

Pat Kane, Director of Investor Relations.

Sir, you may begin your conference.

Thank you, Miquel.

Good morning everyone and thank you for participating in Equitable's Third Quarter 2007 Earnings Conference Call.

With me today are Murry Gerber, Chairman and Chief Executive Officer, Dave Porges, President and Chief Operating Officer, and Phil Conti, Senior Vice President and Chief Financial Officer.

In just a moment Phil will briefly review the third quarter financial results that were released this morning, then Murry will provide updates on the horizontal drilling and pipeline infrastructure programs, the ongoing regulatory review process for the acquisition of Peoples Gas and Hope Gas, and then we'll open up for questions after the prepared remarks.

Today's call contains forward-looking statements related to such matters as our pending acquisition of Peoples and Hope, the results of the drilling programs, the Big Sandy pipeline, the Langley processing plant and other 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 2006 Form 10-K, the 2007 third quarter 10-Q that will be released today as well as on our website.

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

Thanks, Pat, and good morning, everyone.

As you are aware, earlier this morning Equitable announced earnings per diluted share of $0.27 for the third quarter of '07, which compared to earnings per share of $0.26 in the same quarter last year.

From a news flow perspective and from a financial reporting standpoint, the quarter was pretty quiet, and for that reason my comments will be relatively brief this morning before turning the call over to Murry.

As you know, the summer and early fall is generally an uneventful period at Utilities from both an operational and a financial perspective, and that was certainly the case again this year.

However, we are hopeful that a year and a half into it, we may be on the verge of some clarity on the regulatory review of our purchase of Peoples and Hope Gas.

At Supply, we continue to see encouraging results from our horizontal drilling program and Murry will update you on both the horizontal program as well as the regulatory review in his comments.

But briefly, moving on to results in the quarter, at Equitable Supply we had operating income for the quarter of $62.2 million, which was slightly lower than the $63.2 million earned in the same period last year.

Production revenues of $93.4 million were relatively unchanged from the third quarter of '06 as slightly lower reported volumes were offset by an average wellhead price that was $0.12 per Mcf higher than last year.

NYMEX averaged $6.16 per MMBtu this quarter, which was 6.3% lower that last year.

However, our average hedge price was higher than last year resulting in the higher effective wellhead price this quarter.

Due to the Nora sale earlier this year, reported sales volumes decreased about 0.5 Bcf to 19 Bcf versus the same period last year.

However, after normalizing for the Nora sale, sales volumes were actually up over 4% in the period.

As we discussed last quarter, we have decided to drill all future Kentucky shale wells horizontally, which has resulted in fewer vertical wells being drilled than planned.

Given the lag in the land permitting process and the lengthier drilling time associated with the switch, we've also experienced lower sales volumes than originally planned in the near term.

As we continue to ramp up the horizontal effort, the increased volumes from those wells will clearly surpass the volumes we would have saw from our vertical well program.

And for 2007, we still expect sales in the 77 to 78 Bcf range, but at the lower end of that range.

Gathering operating income at Supply was $6.3 million, or $3.2 million lower than the third quarter of '06.

And the decrease in operating income there was again the result of the Nora transaction with Range, which included contributing some Nora Gathering assets to the jointly-owned Nora Gathering LLC.

Gathered volumes, gathering revenues and gathering expenses related to the Nora Field are no longer included in Equitable Supply's operating results.

The company did report equity and earnings of $1.3 million from its ownership in Nora Gathering, LLC.

A final point on Supply, as you read in today's release, we did purchase 12.3 Bcf of proved reserves as well as some 2P and 3P reserves in the Roaring Fork Field in Virginia from Penn-Virginia for $28.5 million.

This transaction was a purchase of working interest in a field Equitable operates and where we already own an 83% working interest, so following the transaction, the company owns a 97% working interest in these Virginia wells.

You probably recall that we have set aside $95 million of the proceeds from the Nora sale to be used for possible like kind exchange transactions.

This Roaring Fork Field transaction qualified and we used a portion of the Nora sale proceeds to effect the transaction dues, effectively reducing cash taxes paid on the Nora gain.

Just a quick point on Equitable Utilities, as I stated up front not much to report this period at Utilities.

Operating income of $4.1 million was essentially flat with last year.

I will mention that as we wait for some resolution on the acquisition Peoples and Hope Gathering planning costs associated with preparing to integrate the transaction were $1.3 million in the period or $2.4 million lower then in the third quarter last year.

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

Okay.

Thanks, Phil.

Good morning everybody.

Just briefly on the Dominion Hope regulatory approval as you know Pennsylvania has approved the transaction.

With respect to the FTC, on May 14th, the District Court Judge granted Equitable's motion to dismiss an FTC opposing the transaction on the grounds of state's rights.

The FTC appealed the decision and an injunction was entered prejudicial to the deal.

Briefs have been filed, oral arguments were held on October 3rd and we are now awaiting the final opinion on that matter.

In West Virginia, the hearings have been held.

The PSC procedural schedule for briefs has been set, although, that schedule doesn't include a final approval date.

Initial briefs will be filed on November 1st.

The reply briefs will be filed on November 1st, reply briefs due on November 16th and Equitable continues to meet with intervening parties regarding possible settlements.

And, obviously, given this, the timing on West Virginia approval is not known at this particular time.

Moving on to drilling.

The current drilling status through the quarter end, this just represents the quarter end, I'll give you some updates on horizontal in just a second.

But, in total we've drilled 397 vertical wells, and 50 horizontal for total 447 gross wells this year so far versus 371 last year and at this time we'd only drilled three horizontals last year.

So, in total that's about a 20% increase.

The transition from vertical to horizontal causes us to rethink how we present the drilling activity in a way that's informative to you and us in projecting how that activity may lead to future sales volume growth.

Currently, from an activity standpoint, we do the drilling of one horizontal well as being equivalent roughly to the drilling to three vertical wells.

But, that's a relatively simple translation and as you know, we will begin drilling multi lateral wells pretty soon and, those wells will add another layer of a complexity to the well counting exercise.

Suffice to say that now we're drilling as many horizontals as we can and the limitations to that number is only related to our ability to secure permits.

Regardless, in the future, we'll be reporting activity levels, too, broken out among the various categories of well types, coalbed methane, conventional, vertical, shale horizontal, shale multilateral and so on, so that we can give you data that I hope is helpful to you.

On horizontal, to date, now in this case we're talking currently.

We have spud 67 horizontal wells in the Devonian Shale play, 62 in 2007 and 5 in 2006.

51 of those wells have reached TD and 40 have been turned in line, 8 are currently drilling.

We are now planning to drill at least 80 horizontal wells this year so that's up from our previous estimates.

We currently have eight rigs active in the program.

We are doing sort of a piggy-back system of drilling here where we are using a couple of rigs to drill the vertical portions of the wells and six are dedicated exclusively to drilling the horizontal portions of the wells and we will be ramping up that fleet as we go on down the road here.

Some of the highlights since our last call.

We continue to have success in our Kentucky horizontal program and have significantly increased the pace of horizontal drilling in the state.

Of particular note, we have had recent success in the Cleveland Shale in Kentucky.

This is a little bit above the Lower Huron Shale.

In the third quarter we drilled three Cleveland shale tests, all of which had significant natural flows.

Although they're not on line yet, the final open flow rates on these wells were between .9 and 1.1 million cubic feet a day.

For those who were on the field trip, some of you may have been on the field trip, the well that we actually visited on that tour ended up having a final open flow rate of 1.1 million cubic feet a day.

Incidentally, the final costs for those wells range between $0.5 and $0.6 million.

Again, you shouldn't project that cost to all the wells, we still would anticipate that most wells need stimulation but this gives you some idea of what can happen if there is no need for stimulation on the wells.

So, we are quite encouraged by the Cleveland Shale.

That's new news for us.

We have drilled nine wells to date in West Virginia with currently five of those wells in line.

The data is young, but we do have some data from these five that has been very encouraging.

Initial indications are that the West Virginia Shale wells may perform as well or better than the Kentucky wells, but again, the data set is small.

We're quite encouraged.

We anticipate spudding our first horizontal multilateral well in December, so that's sort of on the horizon here right now.

We will spud a Marcellus test in Pennsylvania, either in late December or early January, we're still having some permit issues there.

We will spud a Marcellus well or two in West Virginia this year also.

We will be drilling the first two horizontal shale wells in Virginia, the first in the Nora Field.

We'll be drilling that for Range and then once we're finished with that well -- by the way, these are for Huron shales, we'll move the rig over to Roaring Fork to drill that well.

We'll be doing that in November.

On the drilling side, we've made some good progress on this MWD technology, which allows us to receive directional survey data, electromagnetically through the earth rather than through wires hooked on to the drill bit.

Using this technology, we recently drilled 4,006 feet of directional well bore in only 55 hours and that's our current world record for drilling horizontal wells.

We're updating our decline curve this quarter to reflect our view that the upper end of the EUR range for horizontal wells should be increased from 1 Bcfe to 1.5 Bcfe.

So, we're getting enough results to be able to project that at least the best of the wells seem to be a bit more than the early indications that our early models showed.

We'll continue to update this information each quarter.

For 2008, we are still currently planning to drill at least 200 horizontal wells.

In Nora, the deal with Range is working out pretty well.

We've been pretty encouraged by the early results there.

As you know, we have a 50% interest and as I said earlier, we're going to be drilling the first horizontal well there coming in November.

On Big Sandy and Langley, as you recall, the current capacity there is 130,000 decatherms a day, which has been fully subscribed and of course, that capacity has expanded a little with further compression.

Langley, once upgraded, will provide 170 million cubic feet a day of gas processing capacity.

Turn-in line of the combined projects, both of which are critical to ensuring increasing gas sales, will be Q2 of 2008 and those need to be operational to get to the point where we're starting to alleviate these bottlenecks.

The completion of Langley helps a lot with the gas processing side.

The gas from the Kentucky horizontal wells is hot, with a BTU content of about 1290 per cubic foot, compared to a pipeline spec of about 1,100, plus or minus.

Given the results from the horizontal drilling, we will soon exceed our current capacity to process this gas, making completion of the Langley facility a critical-path item.

Incidentally, the first pieces of the new processing plant have arrived on the Langley site.

Beyond gas processing and the larger pipeline projects like Big Sandy and Blue Ridge, horizontal drilling has required us to commit to an expanded gathering compression infrastructure upstream of the major pipeline and compressor processing facilities.

The existing infrastructure size to support vertical program is inadequate.

We are undertaking a significant build-out of these upstream systems which involves construction of a network of medium and low-pressure pipelines and attendant compression throughout our acreage in Kentucky and West Virginia where horizontal wells have been successful.

This build-out is the reason why our projected growth rate in the sale of gas over the next couple years is less than the capacity to produce gas would indicate that it should be.

In a perfect world, it would be ideal to drill wells only when capacity, broadly defined, is available.

Unfortunately, things aren't perfect.

We need to drill enough horizontal wells in an area to confirm the need for expanded infrastructure capital, and the act of drilling these wells is now frequently, these horizontal wells is frequently swamping existing capacity to carry the flows.

The ultimate goal is to assure that volumes produced at the well are delivered and sold at the sales meter.

In Virginia this is happening today.

In Kentucky and West Virginia it is not.

While the whole capacity shortage problem will not be solved completely in 2008, we are segmenting the problem into actionable pieces so that we can demonstrate to ourselves next year, particularly in Kentucky, that it can be solved in some discrete areas where we have these large flows from the new horizontal wells.

Overall, I would say that we're very encouraged about our prospects for organic growth.

The horizontal program is good, it's providing tremendous organic growth opportunities.

And while the gathering and processing system build-out presents some challenges, the fact that we've got more gas to sell than we ever thought we would that has IRBU content than we thought we would is a pretty high class problem for us.

And with that I'll turn it over to Pat to take your questions.

Thank you, Murry.

That concludes the comments portion of the call.

Miquel can we please now open the call for questions?

Thank you.

(OPERATOR INSTRUCTIONS) Your first question is coming from Carl Kirst from Credit Suisse.

Hey, good morning everybody.

Hey, Murry, just to start with the Peoples and Hope to kind of get that out of the way.

With respect to the scheduling that we're kind of looking at now is there a move afoot officially to change that November 1st date or is that not something that at this point you are terribly concerned with?

There is no move afoot at this point.

We talk to Dominion every day and I think both of us are looking towards some clarity on the issue which it looks like could be happening with a ruling from the Third Circuit hopefully soon.

I mean, at least they indicated that they'd be making some rulings soon so we'll have to see.

Okay, so I take it then whatever phone call settlement discussions that were had with the FTC pretty much as expected, didn't really go anywhere, we're basically just waiting right now to hear from the judge.

That is correct.

There was nothing proffered from them that was acceptable to either party.

Surprise, surprise.

Two other questions if I could.

The first is you mentioned the average cost for the unstimulated wells in the Cleveland shales, what about if you looked at the horizontal wells that were drilled in the third quarter as a whole, stimulated and unstimulated, what do the average costs come out to be?

Yes, I didn't give you that number and I hesitate to do it because here's the reason.

Even though we're seeing some great natural flows from these wells it's not entirely clear to me that those wells wouldn't perform even better at times stimulated.

And so we're sort of, we're in an experimental phase right now.

The reason we're letting these wells flow naturally is just to see what they can do for a while.

Right?

And it may be that we don't go back to them to stimulate for some period of time if they continue to flow at these high rates.

It's possible, however, that we might find that we see declines there and potential, let's say, to stimulate the wells and actually make them better down the road.

So I'm really hesitating to give a number there because I think it would generate a whole lot of not necessarily confusion, but you might take the data and use it in the wrong way.

I'm not trying to protect you from that, but suffice it to say that the next, the near term issue or the near term milestone that we really are looking forward to, to see what these multilaterals do.

Right?

Fair enough.

And lastly, I don't remember hearing this number before if you've thrown it out before, but looking at West Virginia, understanding we have a very, very small data set.

But from what I recall, at this time last year you were just kind of breaking open into Kentucky.

You guys did throw out the number of possible locations that could be applied to horizontal drilling in Kentucky.

Do you have a similar type of metric that you could throw to West Virginia if indeed this should work?

Well, I think you're asking basically a reserve question, and I don't have that number because we're experimenting around West Virginia right now to see how broadly this horizontal drilling is going to be applicable.

But you should expect that we will update our reserve report the same time that we're putting out the Form 10-K this year, and included in that will be update on reserves, which will obviously be related to updated to updates on number of well locations that we think are applicable.

Great.

So the answer is no right now, but stay tuned.

Fair enough.

Good luck.

Thank you.

Thank you.

Your next question is coming from Faisel Khan from Citi.

Morning.

Good morning.

Just trying to go back to some of the comments and prepared remarks.

You said in Kentucky and West Virginia, I think you said your horizontal well production is not really getting to market because of the constraints?

Right.

Not all of it is.

That's correct.

Not all of it is.

Right.

And do you think that with, I mean when Langley comes online and Big Sandy comes online, how much of that capacity do you think will be used up right away?

Or how long will it take to fill capacity at those facilities?

Well, it's going to take sometime to fill it up, but the key constraint on the Langley/Big Sandy at this point is not the pipeline.

The pipeline is clearly capable of carrying more gas, particularly with added compression.

So that's not what we're concerned about at this moment.

It's the fact that we're getting all this hot gas, and that's why Langley is so important, and that facility is currently being upgraded to 170 million a day, which will carry us.

That is processing capability, 170 million a day, so that we can strip the gas down to pipeline quality, and we think that's going to be okay for a while, but if these wells keep coming in and we're going to be drilling more, we're going to probably have to expand that at some point as well.

Is there any way for you to quantify right now how much gas is not effectively making it to market because of this constraint?

No, no, we're working on that, and we have some anecdotal evidence about that.

We obviously are measuring the production from these new horizontal wells and looking at the sales meter to determine exactly what that number is, but it's not 100% and we have some ranges but I'm not prepared to give those out just yet.

Fair enough and I think missed it when you said, you're drilling a Pennsylvania -- you're drilling into the Marcellus shale in Pennsylvania in December or January?

Right.

And I think you said also a Marcellus well somewhere else?

Two.

Two in West Virginia.

Yes, we've got some -- the Marcellus is actually bifurcated into a couple of different plays.

In Pennsylvania where range has had some success it looks like Marcellus is a fairly, higher pressure shale so we're going to drill a well there nearby where they have drilled some verticals and I think a horizontal well as well.

Down further south we've -- in previous drilling we've tagged the Marcellus occasionally and had a little bit of flow rate there.

Enough to be encouraging, but we think that might be a little bit lower pressure.

So we really have two Marcellus plays, a West Virginia "low pressure play" and a -- I'm sorry West Virginia Marcellus low pressure play and a Pennsylvania Marcellus high pressure play and this quarter and maybe leaking into to early next year, very early next year we'll be spudding wells to test both of those plays.

Okay fair enough.

Thanks guys.

Thank you.

(OPERATOR INSTRUCTIONS) Your next question is coming from Shannon Nome from Deutsche Bank.

Thanks.

Good morning, Murry.

Hi Shannon.

Just two points of clarification, one is if November 1st comes and goes and we haven't heard anything, what happens then?

When November 1st, occurs either Dominion or Equitable has the right to terminate the deal.

And if that occurs, where is your head at right now?

How many years in are we on this process?

I know you're probably as weary, or more so than we are of it.

What's your feeling on the transaction?

Well, no, I think to start out with -- although we haven't given tremendous amount of clarity on this fact, we still believe that the Dominion/Hope transaction will earn more than the cost of capital on the money that is provided there.

I don't think that's the question you're asking though.

We're also mindful of the fact that we've got a rocket ship growing here in the production side and the midstream side and clearly the growth prospects there, if you just look at the growth are greater, but there's EVA created on both sides of this deal.

The real issue, where my head is at, and I think where Dominion's head is at, although I can't speak for them is that both of us want to see some clarity one way or the other one this deal.

And at this moment in time, sitting here today, there are at least a couple of things that could provide clarity in the near future on the transaction.

One is, the Third Circuit is going to rule here shortly, at least that is what we are told, and West Virginia is proceeding with the collection of data to complete their process of regulations.

So where that might not be crystal clarity it is at least more clarity than we've had in some time so we're inclined to watch and see what happens on those events and then Dominion and Equitable, we talk every day.

We'll have to decide what we're going to do in the long run if clarity does not continue to emerge.

Okay, helpful, thank you.

And the other question is on the type curve, pretty big increase to the upper end of the range.

Yes.

Can you tell us some of what's behind that?

Was it observing decline rates or --?

Yes, yes, yes.

I mean, I think it's -- we had initial flow rates from some of these wells early along that seemed better than our model, but we wanted to watch those for a while to see how they started to play out.

And even though we're kind of early in the process we felt it prudent at this point in time to say that we think the upper end is going to be higher, which is a good thing.

Now, the important issue is what is the distribution around these wells and we're not quite ready to lay that out yet because we still want to see a little bit more but we do feel comfortable enough on based on what we've seen to raise the upper end.

And how far flung are the wells that you've drilled so far in terms of how well they cover the acreage?

Obviously, you haven't drilled enough to know the whole story.

No, we haven't, but I think we had a map in our recent presentation that showed that we've got a distribution around Eastern Kentucky pretty well that covers our acreage and we're getting pretty consistent results.

You may recall that there was one little area in the western part of our acreage called the Tip Top area that we weren't too happy about, but all of the rest of the areas there looked pretty good.

In West Virginia, we're really just starting so we don't have a good, broad distribution in West Virginia yet.

We've drilled a little bit into the central area and then we're drilling some down in the south, but we need to get a few more wells to make a more general comment.

My general comment is Eastern Kentucky looks pretty darn good for horizontal drilling generally and West Virginia we're getting some encouraging results in a couple of areas and we need to get some more wells drilled.

Excellent, thank you.

Thank you.

Your next question is coming from Ray Deacon from BMO Capital Markets.

Yes.

Hi Murry, I was wondering with Nora, I was wondering what your approach is going to be to reserve booking at year end that you haven't been super focused on trying to a lot of reserves but Range has made some positive comments this morning in their release.

You've been very positive on early results.

How do you think the reserve engineers would look at that?

Everyday that goes by gives us a little bit more data on this in-fill project and I think Range and us are going to have to put our heads together on this to see how confident we feel.

So we're going to be working together on that and beyond that I want to see what happens on these deep wells, these deep horizontal wells.

I think that could have some impact in Nora and in Roaring Fork, by the way, which ia Phil mentioned we've got a 97% interest and there adjacent in the oil field.

So we'll be reviewing that this year.

I don't want to front-run the reserve report.

I think we got work to do on the proved side there and we have work to do on the unproved side, both based on what we've seen this year.

Okay, got it.

And then just one more quick one.

In the Northern, more in Pennsylvania with the more zealous, because it's over pressured are you able to drill those with fluids and could you maybe have lower cost?

Yes, I want to clarify.

This low pressure, high pressure, sort of the boundary's a little bit unknown, admitted, but it looks like the higher pressure area could leak into the Northern-most area of West Virginia as well, at least based on existing pressure data up there.

But you are quite right.

We're considering drilling the Pennsylvania, the higher-pressure Marcellus wells with fluid, more conventional and I don't know what the costs are going to be but we'll see.

Got it.

Thanks very much.

At least the higher pressure presents that opportunity.

So we will check it out to see if it works.

Okay, got it.

Thanks.

Thank you.

Your next question is coming from Brooke Glenn Mullin from JPMorgan.

Thank you.

Could you give us a sense, even just a ballpark of how much capital you might be looking at in order to put the necessary infrastructure in place?

Yes, it's, I mean obviously you should be thinking that the capital is probably in the neighborhood or a little north of where we were this year.

It's going to take some more but we're not going to put that number out until the board approves the capital budget which they don't do until December.

I also just want to clarify really quickly, the reserve updates, the year-end timing, is that both proved and your 2 and 3P?

Yes.

This year, as you recall, we put the prove reserves out with the K and then we updated our unproved reserves a little bit later.

This year what I want to do is much sure that it's all together in one place.

So we'll do it all at the same time and coincident with the K.

Okay thank you.

Thank you.

(OPERATOR INSTRUCTIONS) Your next question is a follow up from Faisel Khan from Citi.

Yes, sorry.

No problem.

Can I get a bit of a breakdown of the CapEx for '07 for the nine months on your production again?

It looks like you have $470 million there -- I'm just trying to break out what's drilling and what's infrastructure.

We're just checking to make sure we've got that broken down here.

Might as well, hang on just a second.

Okay.

We don't have it off the top of my head.

I don't want to give you a number that's off because it's not quite the same percentage to date as we projected it would be for the year so I don't want to give you a false number.

Okay.

and I was also looking at the Utility side of the equation too.

Hang on just a second.

It looks like on the development side it's about 187, on the infrastructure side about 132, Big Sandy is 89, Langley is 40, and the rest is the Penn-Virginia purchase and some other claims.

Okay so Big Sandy shows up underneath the production CapEx, not the utility CapEx because it's got pipelines?

Yes, yes.

Okay, fair enough.

But those were additive numbers you're aware, right?

Yes.

130 that was infrastructure excluding Big Sandy and Langley.

Big Sandy and Langley together about 125, 128.

And then what's the CapEx on the Utility side of the equation?

The 61 million there?

You mean what are the activities related to that?

Yes, if Big Sandy is in the production and gathering side of the CapEx, the 470?

So more than half of it, almost 60% of it is just normal mainline replacements.

Okay.

That's part of our program that we've talked about for awhile.

There is some other infrastructure in there and a fair amount of that would have to do with gathering et cetera.

It's expansion of projects around the Equitrans system to serve third-party producers primarily.

But more than half of it is mainline replacement and then the rest would be other infrastructure.

And Faisel, as go forward we'll probably try to do a better job of pulling together the infrastructure businesses that are both in the Utility and in Supply.

Okay.

So that we can distinguish that from production on the one hand and distribution on the other hand.

Yes, right.

And then on the acquisition or the small increase in working interest, what's the production associated with that increase?

Between 1 million and 1.5 million a day, as you can see.

Perfect, okay thanks guys.

Thank you.

Your next question is a follow-up from Carl Kirst of Credit Suisse.

Yes.

Hello, guys.

Just a quick follow-up.

I wanted to touch base on the Roaring Fork Penn-Virginia purchase.

I guess the first question is, is the economics of that purchase, was that pretty much all built on the field reserves or was part of that kind of a look through to the multilateral that you're doing at year end?

We'd say it's based on the entire field.

And just so you have a sense of why that came about, Penn-Virginia decided they wanted to sell.

As Bill explained, we had over 80% of the interest there anyway.

They decided they wanted to sell, and in the end what we wound up doing is just exercising our preemptive right.

And the reason we did is consistent with the logic we've given before on inside Appalachia acquisitions and divestitures.

We just thought it was operationally more efficient for us to own closer to 100%, given that we were over 80% already.

And that was really what drove our willingness to look at that.

If someone were just presenting a 13% or thereabouts working interest in a field even inside Appalachia that we weren't already in, we wouldn't have been interested in it no matter what.

But being able to have a little bit more influence or ability to control what is going on in a field where we already have easily a large majority stake, was what made it interesting.

The economics did work based on all that's going on in Virginia, but that's really what drove it, is moving ourselves up from 83%, pushing 100.

I would say that since we hadn't drilled, and haven't really drilled any deep horizontal wells in the Huron Shale yet in Virginia, that we didn't build that opportunity into the purchase.

I mean certainly it's upside, but it wasn't built into our original economic assumption.

And hopefully that will work out.

But again, since it's a preemptive right, of course, we were presented with a number.

And it was, do you want to buy it at this number or do you want to let it go to the other folks that Penn-Virginia had found and we decided that our economics worked to buy it at that number.

Right.

Again, and then the upside will come hopefully from the expansion of horizontal drilling.

Right, and I appreciate that color.

And as far then as the deterrent test is concerned, my recollection is it has to be done in December, 14 days for drilling.

So should we have a good idea of that when we reconvene in the January, early February --?

Yes, by that time we ought to have some knowledge of -- yes, absolutely of what's going on in the Nora well and perhaps even the Roaring Fork well, hopefully; I mean, we'll certainly, knock on wood.

We should have had it drilled, and we should have some indications of what's going on in the drilling, does it flow, does it not flow?

And, of course, in Nora, particularly, and this is a positive.

In Nora, and in Roaring Fork, to a great extent also, the capacity there is capable of taking that gas to market.

And hopefully, we can drill them fast, as we have elsewhere, and hook them up fast, too.

So that'll be positive.

Great, thanks.

Thank you.

There appears to be no further questions at this time.

I would like to turn the floor back over to Mr.

Kane for any closing remarks.

Thank you, Miquel.

That concludes today's call.

The call will be replayed for seven days, beginning today, at approximately 1.30 Eastern Time.

The phone-in number for the replay is area code (973), 341-3080.

You will need a confirmation code to access the replay.

That code is 8104546.

The replay will also be available on our website for seven days.

Thank you, everybody, for participating.

Thank you.

This does conclude today's Equitable Resources, Inc.

conference call.

You may now disconnect, and have a pleasant morning.