EQT Corp (EQT) 2006 Q4 法說會逐字稿

Good morning, ladies and gentlemen.

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

At this time, I would like to welcome everyone to the Equitable Resources 2006 Earnings Conference Call.

All lines have been placed on mute to prevent any background noise.

After the speaker's remarks there will be a question and answer period. [OPERATOR INSTRUCTIONS].

Thank you.

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

Sir, you may begin your conference.

Thanks Brianna.

Good morning everyone and thank you for participating in Equitable's Year End 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.

Phil will review the 2006 financial results that we released this morning.

Then Murry will provide comments regarding Equitable's 2006 performance and our future prospects.

Following Murry's remarks, we will open the phone line up for questions.

But first, I would like to remind you that today's call may contain forward-looking statements related to such matters as the well drilling program and infrastructure development initiatives, our pending acquisition of Peoples Natural Gas Company and Hope Gas, Inc., the forecast capital expenditures, our plans to reorganize as a holding company, the company's long-term compensation programs, and other operational matters.

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 most recent Form 10-K, our 2006 10-Qs, as well as on our website.

I would now like to turn the call over to Phil Conti.

Thanks Pat and good morning everyone.

As you saw in the press release this morning, Equitable announced 2006 earnings per diluted share of $1.80, which compares with earnings per share of $2.10 in 2005.

You will recall that we sold out of our Kerr-McGee position in 2005, which resulted in $110 million gain in the full year 2005 results.

But there were also a variety of unusual items in both 2005 and 2006 that make year-over-year comparisons difficult.

In addition, this was the first year in quite sometime in which our results were affected by both warmer weather and lower prices compared to the prior year.

I will elaborate on each of these items as I briefly review the results and highlights for the year.

Starting with Equitable Utilities.

Of course, the highlight for the year at Utilities was our entering into a purchase and sale agreement to acquire Peoples and Hope Natural Gas, and Murry will elaborate on the status of that in a few moments.

The big operational though at Utilities though in 2006 were weather that was considerably warmer than last year, and warmer than normal, and increased asset opportunities that our marketing group was able to capture.

You probably all saw that the National Oceanic and Atmospheric Administration, or NOAA, reported a couple of weeks ago that the average annual temperature in 2006 for the lower 48 states was the warmest on record.

The heat -- the key heating months of January and December of 2006 were particularly warm and we certainly felt that in our service territory as annual heating degree days were down 10% versus 2005 and 15% versus the 30 year normal, and of course resulted in lower distribution net revenues.

On the positive side, while natural gas prices were lower than the prior year, prices were still very volatile in 2006.

And this market condition provided our marketing group with the opportunity to take advantage of our asset position and achieve record margins from that business.

In case you were unfamiliar with our marketing business, it is primarily driven by our physical and contractual gas storage assets which allow us to purchase gas and store it in lower price markets and simultaneously enter into contracts to sell it later at higher prices, taking advantage of near term seasonal gas price spreads that often arise.

Those spreads are unpredictable and at times were considerably wider in 2006 then they were in 2005.

A couple of other items worth mentioning at Utilities at the pipeline, operating income increased by $15.9 million versus last year.

Much of that increase was as a result of the Equitrans rate case settlement ,which we discussed in detail during the first quarter 2006 call.

I will remind you though that that settlement resulted in $5.4 million of operating income, which was related to periods prior 2006.

Along with higher transmission rates and volumes from the rate case settlement, the pipeline also benefited from increased gathering activity.

On the expense side at Utilities, the Utility did take a $3.8 million impairment charge for office consolidation in 2005.

The company then reversed $2.4 million of the charge in the second quarter of 2006, as we were able to put some of the abandoned office space to use for our Peoples and Hope integration planning work.

That $2.4 million expense reduction partially offset the income statement impact of $12.3 million of cash expenses spent am 2006 planning for the acquisition, for a combined negative impact from acquisition planning of $9.9 million.

We expect integration planning expenses to continue to accelerate a bit in 2007 as we move closer to the -- to closing the transaction.

And the charges realized so far and forecast for 2007 are consistent with the estimates we made when we entered into the purchase and sale agreement.

Another significant factor affecting year-over-year comparisons of Utility expenses was that 2005 results included $16 million in charges for the termination and settlement of the defined benefit pension plans.

And finally on the Utilities, as discussed last quarter, Equitable has decided to form a holding company and we have taken steps toward implementation.

In the fourth quarter our bond holders gave the green light to proceed with the preferred [reorganization] structure.

We have filed with both the Pennsylvania PUC and West Virginia Public Service Commission, and are awaiting their approvals to complete the restructuring.

Utilities expensed $1.6 million of costs related to the holding company implementation in the fourth quarter, which represents about half of our total estimated reorganization expense.

Moving on to Supply, the big operational stories of Supply in 2006 were natural gas prices that were down significantly from the record 2005 levels, sales volumes that were up by over 5% year-over-year on a normalized basis, and a dramatic ramp-up in the number of wells drilled to 560 operated wells in 2006, versus 420 operated wells in 2005.

Murry will elaborate on our drilling effort in a moment.

I mentioned gas prices.

NYMEX was down $1.39 per dekatherm year-over-year.

Basis was also back to more traditional levels versus 2005's unusually high level.

And together those items were the main drivers in the 7% reduction in average well [inaudible] sales price in 2006.

The NYMEX price impact was greatest in the fourth quarter when the NYMEX averaged $6.56 per dekatherm in 2006 versus down from -- down by $6.41 versus the fourth quarter 2005 when prices did hit record levels following the couple of big hurricanes in the Gulf of Mexico.

I also mentioned sales volumes were up in 2006.

We are reporting a 2.3 BCF increase in total sales volumes.

But I think to get a clearer picture of our operational progress you should consider the 1.5 BCF of sales volumes from properties that we sold about halfway through 2005.

When you make that normalization, sales were up a little over 5% in 2006, and as you saw in the release this morning we expect another greater than 5% increase in sales volumes in 2007.

Operating expenses at Supply were up about $24 million.

SG&A expenses were a major contributor to the increase due to $9.9 million in reserves taken in 2006 for the West Virginia royalty disputes and a bad debt expense, both of which we discussed last quarter.

Higher gathering and compression expenses also contributed to the overall expense increase. $3.3 million of the $7.8 million increase in gathering and compression expense was related to an early retirement program, with the rest attributable to our increased activity levels including higher labor, higher electricity, compliance costs and insurance expenses just to name a few.

The remainder of the operating expense increase was largely due to DD&A expenses resulting from our ramped up drilling and infrastructure investments in Supply.

Just to help you out with the year-over-year comparisons, I already mentioned the Kerr-McGee sale which resulted in a net pretax gain of $110.3 million in 2005, as well as several other unusual items throwing the Utility and Supply business unit reviews.

We also have significantly lower executive compensation expense in 2006.

For the year, we recorded a compensation expenses associated with our executive performance incentive programs, or EPIPs as we have often referred to them, of $21.1 million versus 2005 EPIP expenses of $43.8 million.

That $22.7 million decrease was primarily driven by the fact that during 2005 we were accruing for two programs, one of which paid out at the end of the year.

So not coincidentally '06 EPIP expense was cut by a little over half.

In 2007 there still is only one EPIP in effect which runs through the end of 2008.

And we have no plans to implement another long-term compensation program for executives through at least the end of 2007.

A quick note, on income taxes, you recall in 2005 we incurred a $15.3 million tax loss disallowance under internal revenue code Section 162(m), as a result of terminating our deferred compensation plans and payout of the 2003 EPIP.

NORESCO, recall last year we sold NORESCO basically on the last day of the year.

In 2005 income from discontinued operations was $1.5 million.

In the fourth quarter 2006, Equitable recorded income of $4.3 million from discontinued operations, primarily resulting from a reduced tax liability on the NORESCO sale.

Finally in today's press release we provided you with data on our 2006 capital expenditures and our 2007 capital budget.

The capital budget refers to our intent to commit capital, while capital expenditures represents actual cash spent.

So each year there are capital expenditures from commitments made in previous periods, and capital commitments made, the funding of which will carry forward into the following year.

Our estimate for capital expenditures in 2007, adjusting for carryovers from 2006 and projected carry forwards into 2008, is approximately $700 million versus $405 million in 2006.

Along with our ramped up drilling program, the Big Sandy project, which we committed to in '06 but will spend the majority of the capital for in 2007, is a major contributor to that increase.

And with that, I will turn the call over to Murry Gerber.

Thanks, Phil.

Good morning, everybody.

I would like to spend a few minutes updating you on the progress we are making on the various elements of the growth strategy and I'll start with the Peoples Hope acquisition and the regulatory approval issues.

In Pennsylvania, we reached agreements with the majority but not all of the parties.

And since we did not reach agreement with all, we are going through with the full hearing schedule initiated by the Public Utility Commission of Pennsylvania.

The administrative law judge ruling is scheduled for mid-February.

A final order from the commission will likely be issued in late March or early April.

In West Virginia, the final Public Service Commission hearing is scheduled for early May.

There are just a few interveners, a settlement prior to that date is still a possibility we think.

And on the FTC side, there is not a set schedule for that review, but we are hopeful a definitive ruling by the Pennsylvania Utility Commission and the West Virginia PSC will be persuasive in moving the FTC process to completion.

One other small item, although it's culturally fairly significant for me anyway, is that at -- just after the first of the year we entered into an agreement with one of our unions that allows for that union a structure that will cause them to be included in our short-term incentive plan, our management bonus plan basically.

With that contract change, every employee in Equitable Resources, union and nonunion, is now included in a management short-term incentive plan ,and I think that's great testimony both to the management here at Equitable, not me so much as the people that have to execute these contracts, and in particular it's a testimony to the wisdom and leadership of the union management.

And I do want to get that out there.

When I got to the company that a dozen people were in the bonus program and now everybody in the whole company is in the bonus program.

So, just FYI.

On Big Sandy, we received our FERC certificate on November 15.

We are on schedule for a late third quarter completion of that project.

Just a couple of facts.

The project preparedness, the right-of-way acquisition is a little over 90%.

We've cleared about 10 miles of right-of-way so far and are doing other activities with the contractors, hiring and training, et cetera, et cetera.

All the pipe is on the ground.

All the 20-inch pipe is on the ground and in Kentucky.

All other materials are ordered. 6000 of the 9000-horsepower that's necessary for Big Sandy is going to be on site in early February, so that's moving well.

And as you recall in the Kentucky hydrocarbon expansion, what we are calling Langley now, the total throughput capacity will be about 175,000 deckatherms a day, 100,000 new plus 75,000 old, so that's pretty special.

So we're moving smartly along on the Big Sandy project.

Moving on to natural gas reserves, I know everybody is interested in that.

We are currently finalizing our reserve report for the year end 2006.

So I'm not going to review all of the numbers just yet but I will offer a few of them.

And these are all approximate at this point in time.

Just as a headline, our 2006 reserve replacement ratio will be about 250% in 2006.

We produced about 81 BCFE net and added 210 BCFE.

So the proved reserves are going to come in at 2.5 TCFE or about a 5% increase year on year.

And I will remind investors that all of this increase in reserves is based on -- is organic.

It's based on our own activity.

There are no purchases and sales involved in that.

The main reasons for reserve increases year on year relate to a few factors.

One drilling in West Virginia that opened up some new areas.

We certainly expanded our programs in Kentucky and Virginia.

And that added more crude reserves there.

And then some of our drilling locations in 2006 were previously classified as unproved, and so offsets for those successful wells moved reserves from the unproved categories to the proved categories.

So that was another big factor.

On the unproved reserve category side, we have got a little bit more work to do, but I will say that those categories will be up substantially for 2006 versus 2005.

We are finalizing the numbers.

Suffice to say that our reserve report for unproved reserves will align more closely to that of some of the other mainstream operators.

But I will tell investors that we think it is still appropriate to be slightly conservative in those numbers.

So that's on reserves.

On drilling, Phil mentioned 2006 was a record year for Equitable.

We participated in the drilling of about 655 gross wells.

Of those as Phil mentioned we operated 560, 33% more of than 420 wells we operated in 2005.

This year we intend to drill at least 650 operated wells, including at least 25 horizontal wells, and this is an increase of 16% over 2006.

And in addition we will participate in as many profitable nonoperated wells as are presented to us by our various partners.

Last year was a big, big year for nonoperated wells and we are presuming this year will also be a big year for nonoperated wells.

On the coal bed methane down spacing, you'll recall we're testing the economics of down spacing our coal bed wells from 60-acre spacing to 30-acre spacing.

The most important data we need to collect from these wells right now is the impact and interaction of the new wells with the offsetting wells, and importantly the resulting type curves for both the original and offset wells.

We need to have those.

It's going to take some time to confirm those issues definitively.

I mentioned that to many of you over the year, but right now we've got 11 wells that are producing from that initial pilot.

And what we do know is this.

That there are 20 existing wells that might have been affected by the drilling of the 11 infield well.

To date we have observed a minor reduction in the production from only a few of those 20 offsetting wells.

We are encouraged enough by what we see so far.

It's quite early to expand the CBM infield program in 2007.

On horizontal drilling, as I told you, I'm encouraged by what I have seen so far on our program.

Our status is as follows.

Five wells have been drilled.

Three have been completed and online.

One well is drilled, completed, and currently being cleaned up, and one well is drilled and awaiting completion.

A sixth well is being drilled on the same location as the fifth well.

We will complete both of those wells after the sixth is drilled.

We also have a rig being moved to the 7th well location.

We have two rigs dedicated to this program currently and we plan to add a third.

We, like you, want to know with confidence what the type curves are going to be for this program and we don't have enough data yet to make an informed decision about that.

But what we do know is this.

We can drill and complete horizontal wells within our cost estimates.

That's a big thing.

We can drill and complete wells over the range of depths available on our acreage for these [devonian] shales.

The range of vertical depths to targeted formations has ranged so far from 2200 feet to 5000 feet vertical.

We can use existing Appalachian rigs.

They need some upgrades.

They need some more frequent maintenance, better handling tools, some ancillary equipment needs to be upgrade there.

There is a rig crew learning curve.

But this is not an insignificant issue.

We believe that at least there seem to be enough rigs in the fleet to be able to handle the kind of work we need to do.

That's positive.

We also have learned that it's possible and we think very desirable to extend our laterals from about 1800 feet which is where we have been for the first few wells to 3000 feet.

And in a couple wells we've also seen large natural flows and natural gas from the wells before fracturing.

That is an interesting learning.

And lastly, to date we have seen initial flow rates after fracturing that are multiples of the flow rates from nearby vertical wells.

Right now we think deeper, more mature, more organic rich and siltier zones might be best but that's a working hypothesis from limited data and not necessarily a firm conclusion.

We got a couple of surprises and I will share one of those with you as an anecdote.

You recall that we intended to drill two wells from the same pad in our Hazard area to test two separate geologic formations, the upper [Huron] and the Cleveland shales.

These shales are 250 vertical feet apart.

We drill the wells on the same azimuth.

That is to say that one well was drilled directly on top of the other well and we anticipated two separate completions.

Turns out after drilling and fracturing both wells that the induced fractures were sufficiently extensive to allow communication between the two wells.

What this suggests is that, in Hazard, one well is capable of producing from two separate zones without directly intersecting both zones.

Following up on this operation, we use the micro seismic technology in our fourth well, the Jenkins prospect.

Micro seismic, as many of you know, is a technique involving the use of [geophones] in a vertical well, that pick up vibrations from induced fractures generated during the fracturing process of a horizontal well.

This technology provides a three dimensional map, if you will, of the distribution and extent of the induced fractured system.

We are currently analyzing the data from this well and are intending to go back to Hazard and test our ability to intentionally drill and complete two zones from one horizontal well.

As an aside, Hazard area has not been a great area for shale production from vertical wells and success in this endeavor could be quite meaningful.

All of this information has caused us to accelerate into phase two of our horizontal program.

In 2007 we will drill at least 25 horizontal wells with the intent to tune our completion techniques and further define the geologic opportunities.

On the geological side we are evaluating thickness, maturities, organic content, [porosity] permeability, and other shale formation.

We would also like to test the Marcel shale in Pennsylvania.

We have about 150 -- 115,000 acres in Pennsylvania and the shale there is about 7000, 8500 feet deep.

So we'll be taking a look at that this year as well.

The drilling and completion techniques we'll be testing including eliminating casing from the curve, we talked about that before, longer lateral length, I mentioned that, increasing the number of frac stages, open hole versus cemented casing, frac size, frac fluids, frac fluid effectiveness, foam, nitrogen, slick water, we'll be testing a few more of these just to tune.

Tune the system to see how we can best get the most out of these wells.

To summarize, the objective of Phase 2 in our horizontal program is to gather data to define the best combination of geology and completion techniques that will prepare us for a profitable development program.

Again I'm encouraged by what I see and will continue to give regular updates on our progress on this and all of the rest of our growth drivers at Equitable and with that I'll turn it back to Pat and we'll take questions.

That concludes the comments portion of the call.

Brianna, can we please now open the call to questions.

Thank you. [OPERATOR INSTRUCTIONS].

Our first question comes from Shneur Gershuni.

Hi.

Good morning, guys.

I just want to get some clarification on the comments that you said when you were talking about the multiples with respect to the IP rates.

How does that compare to what your expectations were.

Is that above your expectation of what initial production flows would be or is that in line with what you were expecting?

Given that we have to watch the wells for a long time, I can't say either way at this point in time.

And I will tell you why.

The initial production and maybe we should have been clearer about this earlier, but the initial production for me involves not only how fast the wells decline at first.

That is to say how fast they come in initially, but how fast they decline in the first six, eight, twelve months.

And so I think what I'm think being initial production, I'm think being how much gas are we going to get out in the first year, versus, horizontal versus a vertical well.

And that's extremely important.

So I can't really comment one way or the other.

I'm just encouraged by what I see.

With respect to the Peoples and Hope transactions, so forth, it looks like it will be somewhere within the next 90 to 180 days hopefully.

Can you give us an idea where your cash and debt position is and where you think you would like it to be following the acquisition?

As we've said on past calls, we are still talking to the rating agencies about how we are going to finance the acquisitions.

So we aren't really going out there with that information just yet.

In fact, we haven't even gone to our board with that yet.

As far as our debt position, we are -- did not release a balance sheet today.

But I do have some balance sheet information if you are interested in that.

Sure, if you have it.

Our short-term debt balance is at 12/31, '06 was $136 million.

That's down from obviously a year ago.

When we had the higher gas prices it was $365 million.

And long-term debt is basically unchanged from the 9/30, 2006 Q that we put out, at $763.5 million.

So total net debt of $899.5 million is what we expect to report.

Would it be fair to think that the delay in the closing has actually helped the financial situation with respect to the funding that you need?

No.

No.

Okay.

All right, that actually takes care of the balance of my questions.

Thank you.

Good.

Thanks.

Thank you.

Our next question comes from Faisel Khan with Citigroup.

Hi Faisel.

Hi, how you doing?

Fine.

Going back to the horizontal loan program for a second.

When you said multiples of initial of your vertical well IP, what multiples are we talking about?

I haven't released those yet.

Okay.

And, you said you'd completed three horizontal wells.

You said you were cleaning up another one?

Right.

What did you mean by cleaning up?

Were you able to -- is there any mechanical issues or anything like that with the horizontals you were drilling?

No no no.

The process of -- we've been staging the drilling and then the completion a little bit kind of separately for these wells for various logistical reasons.

No.

All this is just routine stuff.

Going in and making sure that all of the sand is out from the fracturing process and all of the little -- all the equipment is cleaned up.

That's all that is.

You haven't had any casing issues, have you?

Casing issues?

I mean in that you talked about before I think on the previous call how as you reached the vertical, the target depth of the vertical portion of the well and then curve over to the horizontal well, there were issues there.

We were concerned about them and that's why we took the fairly conservative position to case the holes through that curve.

But no, we are not finding formational issues that are really troubling us on that.

As a matter of fact, we intend hopefully when we get a couple wells in any given area to try to eliminate that curve completely.

The cased curve completely.

Okay.

And when I was looking at your production guidance for '07, you did give production guidance of roughly 81 [B's] is that correct?

Right.

Does that include any horizontal production at all?

Yes.

By a minor amount.

Because the number of wells that will actually enter into that number by the time the end of the year is, comes is going to be relatively minor.

Okay.

And then the number of wells --

Hey Faisel, I want to just correct you, that was sales guidance.

Not production guidance, just so we are clear.

Right.

Yes.

So that's after your line loss, right?

Yes.

Right.

And it's net, right?

It's net.

Right.

And when I think about your production guidance for next year, I look at what you did this year and I go back in time and also look at how you have grown production. 5% seems a little conservative given the increased amount of wells you plan to drill for '07.

Is that -- it seems like your growing production at roughly the same rate you were in the past although you are increasing the amount of wells you are drilling also.

Right.

But keep in mind it's two factors there.

Number one that the more wells you drill, the more new wells you have and the more -- those new well decline at a fairly rapid rate so the pace at which drilling has to keep up to grow production in one of these sort of farming operations or resource plays is fairly staggering.

There are people that have put out some papers on that and I think they are quite right in making that judgment.

The other thing of course is that we are, as we mentioned before the infrastructure constraints still are somewhat troubling out there.

Of course we are doing the Big Sandy project and other things.

But we're not ready to -- you have to factor in potential ,at least I factor in, potential interruptions of production when I make those forecasts to you guys.

Okay.

And then for '06 --

And Big Sandy doesn't kick in until the last quarter, so --

With that, with Big Sandy coming online, does that actually help your production growth in the outer years?

Well, again, Faisel you are asking me to make a prediction on future production growth and I'm not going do that today.

Okay.

Okay.

But I will say that we are intentionally building that pipeline to improve production growth over time.

Assume we would have produced more in 2006 if Sandy had been in place.

Yes.

Right.

But we again the amount that we would hope that we could have potentially gotten from having Big Sandy in just now is not -- we haven't give than number out.

Okay.

And when I look at the net number of wells you completed in '06, that the five six [total], that's gross is 560, right?

In '06 that were completed?

The gross operated wells, yes.

It was 560 and 95.

Now, if I look at it overall, what was the net number of wells you completed?

The net number -- you mean talking about after all --

After all -- I'm trying to get -- I see your CapEx budget CapEx for '06 and I'm looking for '07 and it looks like the cost per well actually came down.

The net wells are 456, Faisel.

456 in '06.

And what about for '07, what would that net number be?

We haven't give a forecast on that.

Well, because it involves some -- there will probably be some nonoperated wells too.

I think we can give -- Pat, why don't you --

For the operated wells it's about 75% working interest and for the nonop it's about 25% working interest, is what our expectation is for '07.

Okay.

I got you.

So the operated target is 650.

So you should be able to --

Yes.

I got it.

And then the nonops would be additional to that.

That would suggest your well development -- your well development costs are being roughly the same year-over-year.

Is that fair to say, Murry?

I haven't give that point, but I haven't given you a specific numbers because I really would like to do that in a more organized way than today.

But as I mentioned earlier, I think if we haven't reached the top, we are certainly within sight of the top of seeing some of the stresses be relieved on this whole thing on drilling costs, on drilling costs a little bit.

So I'm encouraged by what I see on the cost side.

Okay.

Great.

And on the marketing side of the equation, what -- you talked about how you had the opportunity to take advantage of physical gas storage opportunities in the fourth quarter.

But it seemed to be pretty significant because your net revenues were -- almost half your net revenues for the year were in the fourth quarter.

And if you can go to elaborate a little bit more in terms of what happened there.

That's just the nature of those transactions.

They tend to be seasonal spreads, so you'll buy gas, perhaps in the spring and summer when gas prices are lower, and then simultaneously do a sale, the prices tend to be higher in the fourth quarter.

So you record the income when the sale actually occurs and that's why you are always going to see, as long as that dynamic I just described exists, you are always going to see that income show up late in the year.

We're on a, as you know we're on an accrual basis with respect to these things, not mark to market.

Right.

And then in terms of the closing on the transaction , the utilities transaction, the financing in terms of what have you come to any conclusion yet on how you would intend to finance the transaction?

Equity and possibly asset sales.

I'm repeating what we said already.

Okay.

So nothing's changed.

Nothing has changed.

Same story.

Okay.

I appreciate the time guys.

Thanks.

Okay.

Thanks Faisel.

[OPERATOR INSTRUCTIONS].

Our next question comes from Raymond Deacon with BMO Capital Markets.

Hey, how are you?

Hi, Ray.

Was just had a question on the -- can you remind what the number is for CapEx for the Big Sandy pipeline and whether you expect any third party gathering revenues when that comes online?

The question -- the number we have given, Pat, I think is 190. 190 for total capital which includes not only the Big Sandy pipeline but also includes the Langley expansion, what we used to call the Kentucky hydrocarbon plant.

And the answer -- so that's that number.

And yes, indeed, we do expect third party gathering revenues from this pipeline and we are sort of -- we had a lot of precedent agreements signed when we first announced this program.

Now that we are building it, those agreements are being -- and we have a FERC certificate and those agreements are now being turned into perm contracts.

So we are in the process of converting all those precedents, the perm contracts and moving right along there.

Okay.

Great.

And one more quick one on the shale wells in Pennsylvania.

Will you drilled those as vertical wells and will you have a partner there?

The answer to the second question first, no.

And in the first question, we are just sorting out to see where exactly we want to be in that play.

We've heard some success around.

We are trying to, sort of gather our thoughts on what we think our stuff looks like compared to the others.

And we haven't decided if it's vertical or horizontal.

We don't know yet.

Okay.

Thanks.

Thank you.

Our next question comes from Sam Brothwell with Wachovia.

Hi, everybody.

Hey, Sam.

Hey, a couple questions.

Murry, first of all, are you getting at all concerned or frustrated about the length of time it's taking to get regulatory approval on the Dominion properties?

And secondly, I noticed you indicated no change to your hedge position in the fourth quarter.

Is there is anything further that we should be thinking about or reading into that?

Not really on the second question.

And on the first question, Sam, I'm frustrated about everything that doesn't happen when it's supposed to.

Yes, look, the regulatory process just takes time.

I don't know -- I don't want to front run it or cause -- lay blame or whatever.

It's just, Sam, it seems like it's taken longer to do these deals.

And of course, you've noticed in the press that some deals haven't gotten done at all.

Right?

And so, now we are confident this deal will get done.

It's just that the questions and all that just take a long time to answer.

And the process seems to kind of go on.

So, you know, this is a tremendously great deal for this community and the communities that we serve here.

It's -- it makes a lot of economic sense for the customers.

Makes economic sense for the shareholders.

Et cetera, et cetera.

But you know, we can't front run the process.

The process kind of, just sort of is what it is, I guess.

One other if I may, as you come to putting the Big Sandy project together, do you see more opportunities similar to that in that region?

Or is that kind of like the big one?

No.

There are other projects, Sam, that we think are possible there.

And a little later on we will talk about those.

Okay.

Thanks a lot.

Thank you.

Our next question comes from Rebecca Followill with Howard Weil.

Hi.

Two questions for you.

One, in the Marcel shale that you are targeting in Pennsylvania, your acreage runs kind of in a northeasterly direction.

What specific area of Pennsylvania if you can tell me at this point.

Don't know.

But it's going to be deeper, hotter, more thermal -- more organic content.

That's kind of what we are going to be looking for.

Okay.

And then second, if I can be a pest, when you talked about what was going on when you were individually testing the upper Huron and then the Cleveland shales, had the communication, can you run that by just real quick the big picture then and what the implications are for well costs since these do seem to be able to do it with one well versus two.

Well, yes.

We were -- we had of course not very good knowledge, Rebecca, about the extent of the fracturing systems.

And frankly any information for the vertical wells wouldn't have, wouldn't necessarily have been relevant here because the fracturing could propagate up more than down, or down more than up, or laterally, you know, more one way or the other depending on as you know on the stresses, the earth stresses that are existing in that geology.

So there wasn't really a way to kind of figure it out.

And I guess for lack of a better word we didn't think they would go 250 feet.

I mean, that was, clearly we didn't think that, so we were quite surprised to see that it could occur.

I think what we are going to want to do is try this test again intentionally to try to produce both zones from one well and sort of we're working through the engineering of that right now.

And as I said, we did get from our fourth well some results, micro seismic results, which we are now evaluating, as to sort of extent of fractures, and sort of the -- the [oreal] of fracture intensity that occurs around that bore hole and I think that's going to help inform us about where we go.

I mean, I don't want to belabor this but you could drill a well in the Huron -- depending on which way the fractures most easily propagate, you could drill one in the Cleveland or the Huron or in between, so we are kind of working that out right now.

Okay, thank you.

Thank you.

Our final question is coming from Marshall Carver from Pickering Energy.

Yes.

One question.

You said you were able to drill the horizontal wells within cost.

What ballpark costs are you finding for horizontal wells and for vertical wells?

Well, what we think we are going to be able to do in the long term is keep the costs and the -- these kind of wells in the sort of 1.5 to $2 million range and maybe less.

Depending on the depths.

And I'm talking about the deeper wells now.

In the shallower zones earlier we drilled a well which was significantly less than that.

But that's kind of, sort of where we were targeting generally.

Okay.

And those will be for the horizontal wells?

Yes.

That's right, yes.

And what about for verticals?

Well the verticals have been between 350 and 400 generally speaking.

Okay.

Thank you very much.

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