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EXCO Resources (NYSE:XCO)

Q3 2011 Earnings Call

November 02, 2011 10:00 am ET

Executives

Paul B. Rudnicki - Vice President of Financial Planning & Analysis

Harold L. Hickey - Chief Operating Officer and Vice President

Michael R. Chambers - Vice President of Operations, General Manager of East Texas/North Louisiana Division and Vice President of East Texas/North Louisiana Division

Unknown Executive -

Marcia Reeves Simpson - Vice President of Engineering

J. Douglas Ramsey - Treasurer and Vice President of Finance

Harold Jameson - Vice President and General Manager of East Texas/North Louisiana Joint Venture area

Douglas H. Miller - Chairman of the Board, Chief Executive Officer, Chairman of EXCO Holdings, Chief Executive Officer of EXCO Holdings

Stephen F. Smith - Vice Chairman, President, Chief Financial Officer and Director

Analysts

K. Adam Leight

Brian Singer - Goldman Sachs Group Inc., Research Division

Jeffrey W. Robertson - Barclays Capital, Research Division

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

William B. D. Butler - Stephens Inc., Research Division

Joseph D. Allman - JP Morgan Chase & Co, Research Division

Gil Yang - BofA Merrill Lynch, Research Division

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Operator

Good morning. My name is Jessica, and I will be your conference operator today. At this time, I'd like to welcome everyone to the EXCO Resources Third Quarter Earnings Release Conference Call. [Operator Instructions] Doug Miller, you may begin your conference.

Douglas H. Miller

Thank you very much. We appreciate everybody signing in for the conference call. And before we get started, Ramsey is going to go over our disclosure statement.

J. Douglas Ramsey

All right. Thanks, Doug. I'd like to remind everyone that you can go to www.excoresources.com and click on the Presentations link in the Investor Relations section at the bottom of our homepage to access today's presentation slides.

The statements that may be made on this conference call regarding future financial and operational plans, projections, structure, results, business strategies, market prices and related activities and other plans, forecasts and statements that are not historical facts are forward-looking statements as defined in Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements are based on a variety of assumptions that may change any of our future events which are difficult to predict. Actual results may differ materially from those in forward-looking statements. We caution you not to place undue, if any, reliance on such statements.

Please refer to pages 22 and 23 of the slide presentation for the complete text regarding our forward-looking statements as well as the cautionary information set forth in our most recent Form 10-K, Form 10-Q and other SEC filings which are available on our website at www.excoresources.com.

In addition, the slide presentation contains information including reconciliation regarding certain non-GAAP financial numbers which will be discussed on today's call. Doug?

Douglas H. Miller

Thank you. With me in here today, I have 11 people plus myself, and we'll be here to answer any and all questions. Harold Jameson, Marcia Simpson, Steve Smith, Paul Rudnicki, Mark Wilson, Hal Hicky, who will be speaking Rudnicki and Steve will be speaking also. Doug Ramsey, of course, Mike Chambers, John Jacoby, part of our A&D group will guide into that and then last and least, our 2 IRs, Lenny [ph] and Justin Clarke.

Let me kind of give a little brief overview. I feel like I owe everybody an apology because I heard last night as we missed, we had probably our best quarter in the history of the company. And operationally we did everything plus some that we thought, and in here we'll talk about that a little bit.

What we did miss on is estimating, bringing back on our amine plant. And the reason for that is we have us and BG, who's our partner, working to safety and engineering and just making sure we have back up and double back up, and we missed that. We kind of forecast that will be coming out on October, where we would pick up some of that production that we have shut in. We have approximately 200 million a day gross which would all go through the pipeline, and 44 million a day been shut in because of that plant. We actually have more shut in, both in Appalachia and in East Texas, not Louisiana, maybe up to 80 million a day total, but that's just normal operational. But if I were begging an apology on that, it's our fault, my fault for misjudging, but we'll get into that. The amine plant is every -- it's all hands on deck. Looks like probably the beginning of the year, we'll have it back on. But I will note that we did have 400 million a day on the new Arcadia enterprise system that turned on yesterday. And we're flowing 400 million a day down that line. So that opens up a lot of extra capacity because our marketing guys were going crazy.

Couple of other things have been going on. We had our bank meeting this quarter. We did request increasing our line from, actually the base amount from $1.5 billion to $2 billion and our bottom base from $1.5 billion to $1.6 billion that should be -- we're very confident of that happening. That should be approved by the end of this week, early next week, we'll make an announcement if and when that gets -- when that happens.

Other than that, let's kind of talk about what happened. Your operating guys had a spectacular quarter. Our volumes are up almost 70%, our midstream volumes are up 30%. We were moving 1.6 billion a day through our East Texas, North Louisiana midstream. Again, we have another 200 million a day that will be coming on hopefully right at the end of the year. Our guys have done a spectacular job in both the North Louisiana, and the East Texas is coming in slightly better than we thought. We have a little program going on, a joint venture where we're doing a significant test on both the Bossier and the Haynesville, it's under way. We probably -- what do we have? 4 rigs on that 1 section? Excuse me, 5 rigs on the 1 section. So we're actually doing a spacing test on Bossier and Haynesville at the same time in a joint venture with another operator. So that could be quite exciting, that could come on early next year also.

We've had some pretty good success up in the Marcellus. I think we hit 100 million a day yesterday. So pipelines are being built right away. It's being launched and we are actively looking at seeing if we can improve our position up in certain areas.

Both areas -- again, and I think I've told everybody, we're in discussions with BG and we have a board meeting coming up on our capital program. And with gas prices, where they are, I kind of expect that we will be reducing our rig count. I can't tell you exactly what it is because our board meeting is scheduled for November 17. But under $4, our rigs return start going below 20%. So we will -- we're scrubbing that right now. Again, we'll announce that sometime after the 17th if the board will approve that.

Again, everything has -- we had a spectacular quarter from an operational standpoint, and I'll take the hit for that misforecast on construction and engineering. But we're all involved in it. It is underway, it's all hands on deck on the ground. And we just want to make sure that we have backup and backup to the backup before we turn it on.

So with that, I'm going to turn it over to Steve.

Stephen F. Smith

If you would just flip over to Slide 5, and we will go through the numbers a little bit in detail and then we'll get into the operational areas. As Doug said, this was a strong quarter for us except for that one problem that we got on amine plant.

Our production averaged 540 million a day, that's about -- well obviously, it's 69% over last year at this time. It's about 8% over Q2 -- I mean, yes, Q2. And in spite of a decrease in gas price, about 8%, all of our numbers, our EBITDA, cash flow, et cetera, as compared to Q2 '11 were pretty either slightly more or flat to the Q2 '11 numbers. So we're pleased with it. We're very pleased operationally with what we're doing. I'll show you on the next slide.

Direct operating costs continue to trend down pretty rapidly, a 44% decrease between this year's op cost per Mcfe. And last year's G&A continues to trend down, but also EBITDA is way up year-over-year, obviously, as is cash flow, over 50% increase on cash flow. So in general, we're very pleased with where we are.

On Page 6, it's a kind of an interesting chart. We tried to keep this updated at all times, and it's really a cash operating margin chart. The first shaded area is the operating margin before any hedging impact is considered. And you can see there that in spite of the gas prices, we're still hanging in at a decent margin of over $3, around $3.17 for the third quarter, which is 76% of the realized gas price per Mcfe. And then when you roll in the derivatives, even though obviously we don't have as many on the books as we did, we're still -- we're hanging in that as well.

Again, G&A, you can see is kind of trending downward with a little kick in the third quarter due to some bonuses that were paid.

But overall, margins are strong, even in this environment, and we're very pleased to where we are on our cost control, both operating capital, et cetera, and that's a strong area of focus for us.

Page 7 is the chart that we have each quarter just to kind of show you were we've been from a debt and production standpoint and where we are now and where we're headed for the fourth quarter. Our debt was, back in Q1 '09, was about $2.8 billion, it's now or will be, we expect at the end of the year around $1.6 billion net production. We've gained back everything that we sold in the '09, '10 time frame and should exit in the 5.75 range, maybe more if we can get the plan on a little earlier than we're currently forecasting.

Our leverage metrics look great. The balance sheet is in good shape. So we're poised to continue the kind of activities that we've had in the past.

So I'm going to turn it over to Paul and let him get into a little more detail on our liquidity, et cetera.

Paul B. Rudnicki

Thanks, Steve. I'll pick up on Slide 9. Looking at our summary liquidity and our current derivative position. As you can see, our cash at the end of the quarter was $174 million, of which $170 million was related to the escrow account that we hold for our joint venture. And just to remind everybody, we pre-fund a quarter's worth of capital in operating expenses related to our Haynesville shale development, and that's why we carry that large cash balance.

Bank debt was $972.5 million drawn under $1.5 billion revolver. The senior notes outstanding continued at $750 million. So, total debt was $1.7 billion. Net of the cash, it was $1.5 billion, leaving us with total liquidity of $692 million. As Doug already mentioned, we're in the process of finalizing the borrowing base redetermination, and we'll get that out as soon as we get that.

You can look at our derivatives for the rest of this year. And going into next year, we're about 56% hedged for the remainder of this year at an equivalent price of $5.52 in Mcf. And looking into 2012, we're just under 40% at an equivalent price of $5.49.

Looking at the guidance on Slide 10 for the third quarter versus our actuals, as we've discussed, we initially anticipated the shut-ins or the curtailments related to the amine facility being down to account for 2/3 of the quarter. And the actualities we've discussed, it was the entire quarter which led to a higher shut-in volume of 44 million versus our initial estimates of 27 million. All differentials and gas differentials remained strong. Our gas differentials are a little weaker this quarter as we use some interruptible transportation to move our gas.

Operating expenses, as we've discussed, coming down dramatically on a per Mcf basis and on a low-end of our guidance for the quarter, gathering expenses on the low end, production taxes below the low end. DD&A was a little uptick from where we expected, mainly resulting from the lower gas prices used for SEC purposes in determining the reserved base for calculating the depletion rate. All other items basically in line as we discussed.

And then on our capital side, we're a little bit over on the high end, mainly just due to the timing of activities during the quarter.

EBITDA of $164 million and the primary driver for the difference again is the lower production from the 3 facilities.

On Slide 11, we're looking into the fourth quarter. Basically, all of our guidance remains unchanged from the prior quarter. Other than the production, we've lowered our guidance from 30 million to 60 million a day, expecting on average of around 45 million a day shut in. Our midpoint was 610 million a day. As you can see we're at 565 million a day for the quarter. And as I mentioned, all other line items in the guidance remained unchanged from the prior guidance that we have put out.

Looking at our EBITDA forecast for the fourth quarter, we're coming in at $167 million versus our prior forecast of $201 million. $24 million of that is due to the decrease in price. Our prior guidance is assumed for $4.75 an Mcf for the fourth quarter, and we're now currently using $3.75 for the NYMEX. That was $24 million of the decrease, and the $10 million decrease is related to the lower production.

With that, I'll turn it over to Hal.

Harold L. Hickey

Thank you, Paul. Slide 13, I'll give you some color on the excellent operational results we had during the third quarter of '11. Haynesville, in both of our areas, continues to perform very well. In DeSoto, we've had very steady performance as we've continued to realize IP rates in the 19 million a day range. In East Texas, the performance is very exciting as we continue to see IP rates in the 28 million a day rates from the Haynesville wells and 26 million, 27 million a day from the Bossier wells.

We have a record production volumes of 540 million a day, we've exceeded 1.2 Bcf a day of gross operating production East Texas/North Louisiana when you add OBO in with that. We're over 1.7 Bcf a day. All the wells we drilled during the quarter and completed came in successfully as we forecast, so 100% drilling success rate from our 27 operated rigs. And you can see that of those 27 rigs, 4 in Appalachia, only 1 in the Permian, 22 in East Texas/North Louisiana. Of those 22 in East Texas/North Louisiana, we have 15 in our Holly area and 7 down in Shelby. And I'll note, that we've also got about 8 outside the operating wells drilling in the East Texas/North Louisiana region for this week. Hence, working interest there is about 15%.

Marcellus program will really get some traction in the Northeast area, particularly in Lycoming County. We've had some really good results there. We started our development program, we're drilling multiple wells off of pads and completing them simultaneously, and we'll get into some of the details on those results in a minute.

Paul referenced a minute ago that our activities have driven some of our capital up. You'll note our completed wells, 79 in the third quarter, that's versus 71 in the second quarter in East Texas/North Louisiana, because we've been drilling so efficiently and so quickly. We're actually going to end up drilling some 8 or 10 more wells this year than we originally had in our budget.

So that will drive some of our CapEx up, which is a good lead into Slide 14 where we're going to forecast slightly over $1 billion of spending this year. We're up about $17 million from what we had originally forecasted, that's a combination of drilling more wells. I think we're going to drill about 3 more wells in the quarter than we forecast. Then also, we really increased our activity around $2. So what we've done is we've taken advantage of some of the curtailments that's existed from the midstream activity, and in turn, done more on the operating upstream side to go ahead and just have a business there.

On the drilling and completion, the one thing I'll note is Appalachia looks a little bit low because we continue to have a significant input there of BG Carry, and we still have nearly $80 million of Carry remaining as of the end of Q3 for us to use in conjunction with BG as we implement our drilling and completion program in Appalachia.

Slide 15 is more detail on East Texas/North Louisiana. I've talked about our volume there on a gross basis. Net production totaled some for 419 million a day as of a couple of weeks ago. We currently have 264 operated wells and 144 wells that are operated by others. Haynesville horizontals are actually flowing to sales. And we're seeing some good improvement in our drilling and optimization of our frac designs.

I'll remind you that we have 2 focus areas, the DeSoto or Holly area up in the Northern DeSoto Parish and then our Shelby area down in East Texas in Nacogdoches, San Augustine and Shelby counties. I'll remind you that in Shelby, the drilling is a little bit tougher. It's high pressure, high temperature, a little deeper, a little longer laterals, so some of our costs are there, and I'll talk about that in a minute.

But one thing that's happened in Shelby that really encouraged about is the fact that the wells have really, really high pressures. They're coming on in over 10,000 pounds, so really good results there as we start to move toward the development program.

Slide 16, we can see how we've improved some of our cycle times and completions as we've driven down some of our cost. Now we'll say this cost isn’t quite as low as what we've forecast. We've had some increased labor cost from some of our drilling contractors. We had to pay a bit more for jail and diesel in some of our operating activities. But we're still targeting on bringing that down a bit more as we improve our cycle time and when we manage our business there.

In Holly, one of the big effort is continue to modify the profit mix and clusters spacing in order to optimize our completions. And in Shelby, Doug referenced it, it's a very, very important point that we have a very significant test ongoing in Shelby where we're drilling across 2 sections, and it's us and another working interest partner that we're going to drill both Haynesville and Bossier well in a section for doing that simultaneously. We're going to bring those wells on. We'll complete them all together, so we could have some 200-plus million a day and probably even more than that gross flow into sales in middle of the first quarter of next year. So that will be a very, very exciting activity for us to monitor and manage.

In Marcellus, like I said, we're having some really good results up there that's noted on Slide 17. We have a strong acreage position. We're currently producing about 104 million a day on a gross basis out of the Marcellus. It's about 25 head-to-head [ph] build up from yesterday's numbers. We have 54 operated and 4 outside-operated horizontal wells flowing to sales. Now our Northeast areas where we're really focusing and that's where our development program is, that's where 3 of our 4 drilling rigs are operating. Across our central areas where we're continuing some appraisal and delineation work.

And across both of these areas, we're seeing some very interesting results. I noted this last quarter, we're still continuing to evaluate this. But in certain areas, our production rates have improved between when we first bring the wells on and 3, 4, 5, 6 months down the road. And we're also seeing some very, very interesting flattening of our production curves as these wells come on. So very interesting in what's happening up there, we're very excited about the opportunity and we're going to continue to drill in the Northeast area with at least 3 of the rigs.

The results you can see on Slide 18. In Northeast area, we dropped 6 wells on line. They had average IPs of 6.4 million a day, somewhere over 8 million, somewhere around 5 million. Average lateral link is about 3,400 feet. These are all in Lycoming County. And we're continuing to evaluate our tubing program there and evaluate what's the best way to bring these wells online.

In the central area, our wells were completed in Armstrong and Clarion Clarion counties in the second quarter. And you can see there, there are some very interesting results as well, averaged about 5 million a day, and some of those were up over 6 million. So we're seeing some areas there. We're going to do some further investigation and we'll move into development.

Slide 19. The peak in our non-shale assets. This covers the Permian area where we've got about 22 million a day which is our oiliest area, as well about 45% of that 22 Mcfe a day is oily. Our Appalachia region, where we have about 17 million a day net, our interest of shallow production. And in East Texas/North Louisiana, primarily from the Cotton Valley, we have about 82 million a day. So you can see we have 120 million a day which is about like, I said, 22% of our net production coming from these more conventional assets.

Permian, very good cash margin, over $10 per Mcfe as a result of the oily content out there. But across all of these regions, we're very focused on cost management and flattening our declines, recompletion and work over program seem to be very successful across these areas. These assets also do a lot for us and give us an operational footprint in our shale areas. And very importantly, it allows us to hold a lot of our acreage and provide cash flow.

Last couple of slides I'm going to address, talk about TGGT, our equity midstream company that we own 50-50 with BG. We're over 1.6 Bcf a day of input and set a record in Q3 when we averaged over 1.5 Bcf a day. Our primary focus there is in the Holly area, is on restoring and increasing treating capacity. In the Shelby area, it's on continuing to build out our infrastructure as we move towards development in that region and also bringing on some additional treating capacity. And we're also looking at our tight-way ability down there for third parties.

Last slide on 21. I will highlight that after the incident occurred in the second quarter, we actually shut down all of our similar amine treating stock [ph] portfolio. We did bring on the amine treating system at Holly 3. Most recently, it's working very fine. It's in excellent operation at this point. We're installing temporary amine at Holly 6, and those will be on, like Doug said, early in '12. And we're going to restart the treating train in Holly 6 also early in '12. And Holly 6, you recall, is where we had our incident.

The restart was delayed for a couple of reasons. First and foremost, we wanted to bring in our experts and third-party experts to really assess what happened, why it happened and what was damaged. And in turn, we've decided to make some improvements, particularly to our control systems, our release systems, and ensure that our operators have the best training we can possibly give them. And I'm confident that these things, when we bring them back online, are going to have minimal risks associated with them. That's where the big driver is, to drive down our risk and make sure that there's minimal, minimal chance that we're going to have what we had experienced and may never occur again.

You can see the results on the bottom of Page 21, the impacts of this. We'll probably have a total adjusted EBITDA impact at EXCO for the full year 2011 of just slightly over $10 million.

With that, I'll turn the call back over to Mr. Miller.

Douglas H. Miller

Okay, thanks. Final comments, just talking a little bit about gas prices. Again, we're reviewing that and going around the table. I have 12 different forecasts as we would have talked to all over investors. So I think the main thing we can do is look at the forward curve, make decisions based on economics and that's what we'll be doing here over the next month for our capital budget.

It frustrates me and does a lot of people in the room here and in the business that we have a country with no energy plan. And I think we are and will be forever an importer of crude oil, 5 million barrels of which comes from an enemy that we're funding. We have begun exporting coal, and we are looking like we're going to be a major exporter of natural gas. So here's a country, the only one in the world, I might add, that has no energy policy. We're going to be an importer of crude from our enemy and an exporter of coal and natural gas to China to build them up. It does not make sense.

Now with that, gas prices being as cheap as they are and without any energy policy, you are going to see facilities built to export because gas is so cheap. We're selling it today at $3.70-ish, China is paying $17 to $20, Japan is paying $17 to $20, and they want a bunch more gas. We do have power plants being built today. Our forecast is over the next 3 to 4 years power demand to go out by 10 to 12 Bcf a day. And it looks like if gas prices stay cheap and our branch stay is high that over the next 4 or 5 years, you could get exports in the 15 to 20 Bcf a day. So it's going to take a lot of capital or up in prices to do what we're doing. It's a shame that -- Boone is on our onboard, he's a good friend, and he's been working and spending a lot of money on this natural gas vehicle because it does work, we've proven it. I think it will work on its own math. But there's over 5 billion vehicles around the world working on natural gas. And we have 100,000 of them. It doesn't make sense that we can't create a policy.

With that, I'll shut up and get off the soapbox and open it up to questions.

Question-and-Answer Session

Operator

[Operator Instructions] Our first question comes from the line of William Butler with Stephens.

William B. D. Butler - Stephens Inc., Research Division

I'm just wondering if I can get a little more color on -- in the Marcellus, with the higher IPs, you got there any indication yet as to sort of the EUR expectations associated with those?

Douglas H. Miller

I have some, but Marcia has given me the no. I think it ranges -- but she won't let me give you a number. I think it's a little early. Four is easy, 5 is probable and maybe higher. I mean, the biggest issue right now is the curve is not like we had initially forecast with the hyperbolic. It's kind of flatter, and I think we need some time. Marcia, jump in here.

Marcia Reeves Simpson

Now, I mean, we're in the process of reevaluating everything for year-end reserves. So we'll be publishing numbers on that fairly at the end of the year.

Douglas H. Miller

So you're going to keep me quiet till the end of the year?

Marcia Reeves Simpson

Probably.

Douglas H. Miller

Okay, sorry.

William B. D. Butler - Stephens Inc., Research Division

That's okay. And then also, up there, can you speak a little bit to pipeline capacity or if you are seeing any constraints.

Douglas H. Miller

Not right now. Now, we are in the throes and planning up there of building our own gathering and creating interest rate [ph]. But where we're developing right now in Lycoming. It's sitting right on the Transco line. And so, it's pretty easy and there is capacity in there. So we're not having any problem, it's just going from the least to get to Transco.

William B. D. Butler - Stephens Inc., Research Division

And same back on the -- back to the West?

Douglas H. Miller

Back to the West, no, it's a little different challenge. But we've had guys working on it for 4 years. One spot may have 20 million or 30 million a day, another spot may have 40 million or 50 million a day. There is some gathering and some build out. If we were to get really big there, there could be a challenge. But that's why we're going slow. If we really got cooking down there and our guys are doing what we think they're starting to do, we'll have a capital program to do some significant build out there.

William B. D. Butler - Stephens Inc., Research Division

Okay. One other question, going back to that down spacing pilot in the Shelby Trough area, how many wells, how many Haynesville and how many Bossier wells per section are we talking again?

Harold L. Hickey

In one of the sessions, we'll have 5 Haynesvilles and Bossiers. And in the section that's operated by our partner, we'll have 4 Haynesvilles and 3 Bossiers.

William B. D. Butler - Stephens Inc., Research Division

What do you think -- assuming this works, I mean, is that sort of max or could we ultimately go to 6 and 6, do you think?

Harold L. Hickey

We're tapping it to see. So...

Douglas H. Miller

Well, let me give you a tip. Marcia is shaking her head yes, so she thinks that...

Harold L. Hickey

[indiscernible]

Douglas H. Miller

Yes. But if Marcia says yes, there's a good possibility. That's where we are.

Operator

Your next question comes from the line of David Heikkinen with Tudor, Pickering.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

As I think about where you are in the fourth quarter, do you have a thought around exit rates as you bring back pipeline and the plant back on?

Douglas H. Miller

Well, if we were going to bring it on the fourth quarter, my target at the beginning of the year was to do 400, 450, 500, 550, and try to close that at 600. We clearly...

Stephen F. Smith

We're being [indiscernible]

Douglas H. Miller

Yes, I don't think we're going to get the plant back up. I mean, it would -- I think that's a January event. I think we've drilled enough wells and have enough potential production to be over 600. And it's just going to be if we get the plant on or not. I would expect to be right at or around 600 by the end of the -- with production. But I think the first and second quarter next year, we have a lot of stuff coming on. That's already been drilled.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And so as you think about that inventory of drilled non-completed and things in backlog versus your spending, I mean, how much benefit do you get going into next year? I mean, how many wells you think you have to drill on non-completed that kind of give you a lower boost and maintain production?

Douglas H. Miller

Well, we drilled back non-completed, the bad one. I think drill...

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

You took back or...

Douglas H. Miller

Yes, we have drilled and choked back on some maybe 50 million a day to exit with. But I think the one that's exciting, which is kind of a delay also, between us and our partner, we're going to have 15, 20 wells that are kind of being delayed just by the way we're doing it. We're going to drill all those wells, we have 5 rigs running on 1 section right now. We're going to drill all of those wells, case them and then move the rigs off, then we're going to bring in, how many frac crews?

Harold L. Hickey

Probably 4, total.

Douglas H. Miller

4 total frac crews. We're going to frac them all at once, and then we'll pull the plugs up and put them all in. So that's a slight delay, but it's for a reason and it's scheduled. Typically, when you got 5 rigs running, you got a well coming on every month, and we're going to have 15 wells coming on 6 months from now.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And so when I think about that, you'll have a surge of production I guess in the first quarter and carry through the second quarter and then it will decline after that?

Douglas H. Miller

Yes, exactly. That's kind of the way we're forecasting. And it depends and will -- as soon as we figure out what our capital program is and how many rigs we have running, we'll update all of production for all of '12 and get with you. It's going to be volatile between now and the end of the first quarter, but we just want to tell everybody where we're going to stand because we just have to -- we're going to be drilling inside our capital.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Yes. And kind of inside your cash or cash flow and kind of think about EBITDA that ranges between kind of $700 million and $800 million, depending upon prices and hedges, that seems fair?

Douglas H. Miller

Yes, I think that seems fair. But one of the things -- we'll get with you on that. It's a wide range. Tell me what gas price is.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

It costs $4. Is the $80 million carried for BG used up this year or is it incremental to spending next year? Is that kind of an added stuff there?

Douglas H. Miller

It will get used next year. We cannot forecast first half of next year in it, boys? Yes?

Harold L. Hickey

We're kind of on a $20 million a quarter, $20 million to 30 million a quarter of use, so that will get us through at least the first quarter if not probably in the second.

Douglas H. Miller

Yes, we'll be done by midyear.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And then your Appalachian results I think is something that you have highlighted, and clearly doubling that production rate by mid-2012 at your current rig program, how do you think about the kind of types of wells that you're drilling? Does that change next? Are you still in the science mode or is it really going into a true development?

Douglas H. Miller

We're in -- how can I answer it better...

Harold L. Hickey

Yes, in the Northeast, where we have a true development mode noting that we're still testing, for example, some of our flowback methodologies and some of the cluster spacing. But no, we're moving towards development. But as always, just as we continue to do in the Haynesville, we're always going to continue its improvement and trying and make sure we're doing the right thing, but it will be development.

Douglas H. Miller

We have a lot of acreage -- yes, we have a lot of acreage up there. It's all 90% HBP. So we don't have to rush the monkey as Boone would say. There are deals all over the place up there for sale. John's got a group. We're probably looking at 20 of them right now. So one of the things we're trying to do is identify the areas where want to focus. We think Lycoming is what we call an A area. We have 2 or 3 areas that look like they could be B and maybe A areas. We wish we were where Cabot is where there is an A++ area. That's all taken. But he's a good friend, and it looks like I'm going to lose a bet to him because first 6 months we bet on who had the most production we beat [ph] in. I look bad early on this quarter -- I mean, this half. So I think of all the areas, and we just did a study this quarter, on all shale across North America, and I think where we are in the Haynesville and where we are up in the Northeast part are the 2 top areas with the exception of where Cabot is. I mean, I don't think there's any question and we would love to find another area. And we're looking -- we probably, John help me out, we probably have 40 deals in the house right now we're looking at. We can't find anything that's any better. We're looking though.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

And so as you think about your non-shale and conventional assets versus acreage that's held by production primarily in the Marcellus and Haynesville, how do you think about the opportunity for guys that are trying to grow oil and they're selling gas assets. It seems like for discount versus very long-term price could be, does that present an opportunity for you?

Douglas H. Miller

We believe so. Are you reading our mail? We have that meeting yesterday.

David Heikkinen - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

So the 20 deals or so going, how much of that is in that kind of shallow or decline conventional on this -- probably in the side mix as we think about a little bit more versus trying to add more acreage? And it sounds like more production...

Douglas H. Miller

It's out there, it's out there. We're looking. We think even though they have a low margin to them because of high operating cost, you're talking about Cotton Valley our shallow Appalachia, $1.30 versus $1.50 an Mcf versus $0.20 in these other 2 areas but you're saying it's a low margin. Yes, those 2.5 [ph] you're almost double your margin. So right on, were looking at it. It's easily financed. That's one of the things. We're seeing some, but we're not the only guy looking. I would say there's 3 or 4 private equity guys that want to do that also. Now we may team up with some of those guys. But if you invite a PV 15 [ph] just send it in because will just buy it. But I mean, that is not available.

Operator

Your next question comes from the line of Brian Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

Doug, what opportunities or impact, if any, does this BG participating in LNG exports out of few years here have for EXCO either in thinking about potential opportunities for TGGT or in making BG more interested in aggressively drilling and growing production from your JV?

Douglas H. Miller

Yes, I think BG is a major factor around the world in LNG. As you know, they made over $2 billion last year. They are the main player. I think initially they came into the U.S. thinking we are the largest buyer of natural gas. Now with the advent of all of these shales, we're in a joint venture, and I believe you'll see BG have more than one facility here because they have the relationships with China and India and Japan. And I think they believe that there's going to be huge potential there. If they can get gas around the world at the right price, the margin is unbelievable. Now I think you can debate. I believe that we're within 2 years of physical gas trading at a premium. I think utilities can't burn paper. And I think that the LNG outtakes are going to have to get tied up physical gas. With us being BG's partner, now we don't have an investment in the plant and we don't have the access over there, so sharing that would probably be a long shot. But I wish you'd harp on them a little. But I think maybe us getting a small premium for being able to sell gas into that plant is something that's probably -- we haven't discussed it yet, but I can -- they're going to need a lot of gas. And we're a partner and we get along great. And I just -- we do not -- we're not big enough to put up $5 billion to participate in the plant. I think there'll be opportunities and I'm sure we'll have the discussions. But I don't see us making $10 an Mcf because we're their partner.

Brian Singer - Goldman Sachs Group Inc., Research Division

I guess, does it -- do you think it will make BG more willing to kind of push you within the JV to aggressively ramp up production? Or do you feel kind of a line when you think about the capital allocation relative to gas price?

Douglas H. Miller

I think we got -- we were getting that early in the year, and we have had a lot of meetings. And I think we're totally in alignment right now on capital budget. It's pure math. If and when I think overproducing today at 350 when there's going to be -- ready to be export and utilities coming. I think what we need to do as a partnership is define where our areas are and what our potential is and be prepared. Gas gets back to 6 when we have 100%-type rate of return year and they need gas. I think we'll both want to push the pedal. But I'd say we're totally aligned right now. We've had a lot of discussions with them. And we're working on the pipeline. We're talking about a potential monetization of our pipeline asset either into an MLP or a partial sale. So we're all -- everything that we're working on right now, there's no disputes and we're totally in line.

Brian Singer - Goldman Sachs Group Inc., Research Division

Got you. And then I guess if we do -- maybe you've mentioned this, of which guys apologies, but at least it's kind of come up loosely. If share prices hold today, what would that imply for a Haynesville rig count for next year?

Douglas H. Miller

Let say what?

Brian Singer - Goldman Sachs Group Inc., Research Division

If the current strip holds today where it stands for 2012, what would your -- what would you think your Haynesville rig count...

Douglas H. Miller

I can't answer that. We're running all kinds of different models. We're 22 today. We’ve run 17. We’ve run 12. We're going to our board with all different, and I'm highly confident it will be a reduction. And whether it ends up being 17 or 15, I just don't know. It will be lower.

Operator

Your next question comes from the line of Amir Arif with Stifel.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Just a follow-up to Brian's question there. In terms of the lower rig count, how would you just rate the Shelby versus Holly versus the Marcellus in terms of incrementally where you would take rigs off?

Douglas H. Miller

Well, I think 2 things. You get in an area and you hire people and you get a plan going. It's a little tougher to move people out. So that's part of the consideration. I would say where we are in the Marcellus right now, we're planning on going to 5 rigs. I don't think we'll change that. We just have -- there's opportunities up there. We do have an area where we do have some lease expirations that we have to deal with up in the Northeast, and were actually trying to add. So I would say 3 to 4 rigs up there. One rig doing delineation is probably where we plan on being. I think BG agrees with that. Hal, what do you think?

Harold L. Hickey

Yes, sir.

Douglas H. Miller

Yes. Now down on the Haynesville, we have figured out the Holly area. And we're really starting to figure out the Highlander area. Now the rate of return isn't quite as good down there because we're spending $12 million instead of $9 million. So we have to take that into consideration. We have plenty of areas to drill, but at $4 gas, it's a math problem. If our rate of return gets -- starts getting below 20%, we'll move out of the area.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

But I mean, Shelby is more delineation rather than development in terms of [indiscernible]

Douglas H. Miller

Right. I think that's where we are. I'd say Holly is pure development and Harold can tell you what the IP rate and the pressure is going to be before we start drilling. We're not quite there yet. But I'd say next year sometime, we'll get there. I mean, it is faulted deeper, higher pressure, a little more volatility. But so far, we've had some spectacular result.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Yes, how would you compare the IRRs between Holly and Shelby. I mean, Shelby costs more deeper but that's, again, better rates.

Douglas H. Miller

They're very similar. I think we're kind of thinking Holly at $4 in the 30% range, maybe down there where it's a little bit deeper. It depends -- I'd say 20 to 25. It's a little bit lower.

Harold L. Hickey

It's around [ph] 25. And again, every area has subregions within that area. And if you go down into what we call our Highlander area of Shelby where we're getting some of our most outstanding results, you got very, very profitable rates of return. Obviously, that's where we'd move toward development first. If you get into some of the northern parts of the Shelby area where the results are quite as stellar, then you probably back up some of the drilling there because some of your rates of return are going to be more...

Douglas H. Miller

Yes, and the thing about is here we are making an excuse for 13 million to 15 million a day wells. But a $4 gas, because it's not 25, the IRR goes down. And we've got those things held, we'll just defer them.

Harold L. Hickey

Bottom line is we've got plenty of locations that are going to light up economically and we'll have a very stellar program going forward. And if we don't get the 20% rates of return hurdle, we'll reduce our drilling dramatically.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

A different question just on the midstream side. I mean, you have a lot of value tied up TGGT. But the question is, strategically, how are you thinking about timing or when you would want to try to unlock some of that value? You talked about potentially monetizing some [indiscernible]

Douglas H. Miller

Yes, I think we're looking at all options. One of them is sale, one of them is a joint venture with the infrastructure fund and one of them is on MLP. We're going through that process right now. We've had every investment banker in the world in here telling us that their #1 in MLPs. So we've kind of got that. We'd like to take a proposal to the board, again, on November 17 and maybe get an idea where that comes up. But I think we'll -- we'll know which way we're heading by the end of the year, but it won't happen until next year.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Okay, good. And then just a final question on the -- you talked about a lot of deals. Obviously, the gas deal is being cheaper. But are you comfortable just being mostly a gas company the way it is? Or would you rather look at deals on the other side even though you got to pay up for it?

Douglas H. Miller

We're looking at both. And believe it or not, there's some pretty reasonably prized oil deals in the market. We're looking at probably 4 deals in the Bakken, 4 or 5 deals in the Eagle Ford, 3 or 4 deals in West Texas. We're not afraid of oil. Everybody here has been in the business over 30 years, so we had a company that was 95% oil last time. So if the right deal comes along, and we're looking at them, and we'll bid on them, and they're oily, we'll do it. It's just cost to poker is pretty high. I mean, what we're against is paying $500 million or $600 million for a bunch of acreage that's going to take us 10 years to drill up. Actually, we put acreage cost in when we drill the well. We think that's probably your thoughts, unlike some of our competitors.

Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division

Yes, but you don't feel like you need some oil to give yourselves some more flexibility in terms of how you allocate your capital on a go-forward basis?

Douglas H. Miller

Well, I mean, I wish we had 50% oil and 50% gas like that on that, but we don't. We have focused on these 2 areas. We're now got them. And we're going to try to expand in other areas. We’re looking at every single area where the economics are best. But part of some of the oil deals we're looking at, the other [ph] deals sell the oil. It's now going truck and rail to get it moving, and you got to take that into consideration, including West Texas. We had a meeting yesterday, a potential railing of crude oil in what county area. I mean, that had never happened before.

Operator

Your next question comes from the line of Leo Mariani with RBC.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Just wanted to check in on your position there in the Haynesville. Are you guys pretty much all HBP on DeSoto at this point? And where are you at in the process HBP in your Shelby Trough acreage?

Douglas H. Miller

I'd say we're 100% HBP in DeSoto. And I know we've been telling everybody we're going to be all HBP down in Texas by the end of the year. How are we on target?

Harold Jameson

We're north of 80% right now. And everything we're drilling right now, with the exception of the spacing project, we'll finish out that drilling, I mean, completing the unit wells for the sections. So we're virtually all HBP by the end of the year.

Douglas H. Miller

Okay, so we're right on target.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

So I guess, obviously, you guys talked about currently being in, I guess, you said 15 or so rigs in Holly, 7 or so in the Shelby area. Would you imagine a proportional basis to see a similar breakdown on your rigs next year given that you're Holly IRRs are a little higher?

Douglas H. Miller

Not necessarily, I think that's all part of the planning. That's going to be Harold and Mike. We probably going to have about 8 scenarios that we're going to take to the board. One of them is we would reduce more in Holly, but probably we won't. I mean, we're leaving it up to them because they've got it figured out up there.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

All right. How well do you think the Bossier is delineated in your Shelby area at this point? I mean, I guess how many industry...

Douglas H. Miller

We have one in a row.

Unknown Executive

Two in a row.

Douglas H. Miller

Yes, I'll cancel it. Two in a row, I'm sorry.

Unknown Executive

Three. It's going well.

Douglas H. Miller

So I mean, it's going well. But saying it's delineated, where Marcia will give us some reserves is the stretch. I think we've got to have about 30 wells before she will give us anything.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Has there been any industry wells that have tested the Bossier or kind of in the area there and Shelby that give you confidence at all?

Marcia Reeves Simpson

I think we've got producing better run [ph], only our rates are rather low. We're establishing a better rate [indiscernible]

Douglas H. Miller

There had been some and we kind of -- the geologists and geophysicists have kind of tried to pick the sweet spot down there. If the Bossier is not as good across the play, and there's a window in there where it looks like the Bossier and the Haynesville are both good and that's what we're testing right now. It isn't going to be across the play both Bossier and Haynesville. Did I lie on that one? No? Okay. Leo, Mike just spoke up, we better listen.

Michael R. Chambers

I think we're very encouraged with the Bossier down there. In fact, in some areas the Bossier has been a little better than Haynesville. The results are not [ph], I think we're very -- especially north, the Bossier looks stronger down there. So I think we're very happy with it. Much better than DeSoto.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

And I guess, what percentage your acreage down in that Shelby area is kind of in this Highland area which you guys have kind of quoted as the better?

Michael R. Chambers

How many units...

Harold L. Hickey

Probably 1/3. Yes, 25%, 30%.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay. And I guess just to clarify on your midstream monetization you guys have talked about. Is that pretty much just TGGT that you guys are looking at?

Douglas H. Miller

Yes. We're going to keep the burning separate for right now, and we're also keeping all of Appalachia. Appalachia is early on. We'll do that jointly right now with BG, maybe set up another animal base. It's so small you wouldn't want to put all that in there.

Operator

Your next question comes from the line of Gil Yang with Bank of America Merrill Lynch.

Gil Yang - BofA Merrill Lynch, Research Division

If you are to do -- you said you're sort of looking at both gas and oil acquisitions. Would BG be interested in being a partner if it was an oil acquisition? And would they be interested in being a partner for those new gas acquisitions?

Douglas H. Miller

I don't know. I would say they're a good partner. I would say we would invite them in. We're not afraid. I mean, they're a good partner. They bring a lot to the table. We do not have to, outside of those areas, bring them in. One of our challenges in growth around here is we have small working interest. Like we said we have 1.2 Bcf a day in the Holly area and only 400 net of that is ours. So we're not afraid to ask them in. And if the math works, I'm sure they'll be a partner.

Gil Yang - BofA Merrill Lynch, Research Division

Have they expressed an interest in opening the door wider than the existing joint ventures?

Douglas H. Miller

Well, the answer is not really. But Betsy Spomer our contact. She loves doing deals. And if they make sense, I'm sure that we would bring her in. We've got other guys also if we need a partner. We've been approached by 10 different people including private equity and industry. And the deals that we're looking at right now, Gil, our most of them are in the $50 million to $100 million, where we would probably not need or even look for a partner. If we find a little oil deal that maybe could expand where we could drill, have 1 rig or 2 running over there. And if our guys like it and we think it has the right rates of return, I think that's something we got to do ourselves.

Gil Yang - BofA Merrill Lynch, Research Division

Sure, okay. Can you talk about your sort of interest, relative interest, in buying, producing properties versus unproved acreage?

Douglas H. Miller

Yes, my first choice is producing properties that have acreage within them that you don't have to pay for.

Gil Yang - BofA Merrill Lynch, Research Division

Anything for free, right, Doug?

Douglas H. Miller

Well, typically, that's over the last 30 years, that's what we've done. When gas prices are down, we bought production where the locations were worth 0. I mean, if we bought a Cotton Valley deal today, none of the locations are economic. Now gas goes back to 6, all of those locations light up and you start drilling them. That's been our model for the last 30 years. Buy production, it's easily financed. There's plenty of money available to finance. And when prices are low, you pay nothing for the locations, and then if prices go up, you drill them. And so you got -- right now, that's the challenge with oil. Oil is kind of up and you have the pay for the locations. That's just the way it works.

Gil Yang - BofA Merrill Lynch, Research Division

Right. In the Marcellus, you don't seem to be -- at least you highlight in your slide where the 2 focus areas are. What is about Clearfield County that you're not focusing on the area right now?

Harold L. Hickey

It's part of our appraisal area. We'll drill some wells there overtime. It's all HBP. We've picked out some certain areas and you look at a lot of different factors when you decide what areas to appraise at that one time. But we haven't eliminated Clearfield from our portfolio. It's part of [indiscernible]

Douglas H. Miller

No, no. Usually, when we get a question like that, Gil, you don't own acreage in Clearfield County, do you? It's an area where we have acreage, where we have production, shallow production. It's on our list of things to do and we kind of expect that it's going to be a B-type area.

Harold L. Hickey

And in fact, one of the appraisal wells we drilled in Centre County is right on the central Clearfield line. I mean, you can throw a rock from one of the other. So it's a...

Douglas H. Miller

It's going to be on the radar this year. But again, it's all HBP. We're leaving that to the guys when it's time to go over there, go over there. We're not in a hurry.

Gil Yang - BofA Merrill Lynch, Research Division

Okay, so the large expense, because there's no urgency, so you're, I mean...

Douglas H. Miller

Right, exactly. We don't think it's bad. We just have plenty of time.

Gil Yang - BofA Merrill Lynch, Research Division

Okay. And when you look at the improvements in the -- to talk about cost. When you look at the improvements in the drilling cost in the Haynesville, is the improvements with cycle time -- or can you break out the amount of improvement from cycle time versus optimization and completions versus pad drilling versus the cost?

Douglas H. Miller

I love the question because we're going to stump Harold. Well, let's start with days. The biggest thing that I've seen and heard is they're proud of we've gone from x days to x days, what are those days?

Harold Jameson

Well, our current well in the Holly area, our wells are being -- the band, the number of days to drill from spud to rig release is tightened. We're coming in just under 40 days on average right now.

Douglas H. Miller

Where we were at....

Harold Jameson

The original wells had science. When you got those down, get the science removed, you're in the 60s and the 50s, and those were now in the upper 30s typically. So that's kind of the -- that's how we transform [indiscernible]

Douglas H. Miller

And it isn't -- and the cost per day is not just the $20,000 a day on the drilling rig. We estimate, while we're drilling a well, it's about $60,000 a day. So it's not just the drilling rig cost. So bringing that down is significant. Okay. Next one is pad drilling. That's just saving time, right?

Harold Jameson

Yes, it saves time. And we're essentially drilling 2 wells from 1 brick side, 1 pad. The rig, we'll drill the first well, drill cases then move to the next drill cases to stand and move the rig off...

Douglas H. Miller

But that kind of saves you 2 days.

Harold Jameson

That saves -- it shortens the time on that location between the wells. And then the big challenge is just the coordination of the frac activity. When you have 4 rigs, typically in Holly drilling side by side, they're each drilling 1 to 2 wells. And move the rigs up and it's the coordination keeping all things lined up. So that impacts your cycle time quite a bit. But I mean, we've really worked on our inventory. We've dropped over inventory at completions. We were typically running 20 plus or minus completions. Now we're less than, we're almost 1/2 that in terms of wells waiting on completion. And it's just really just the coordination of all the frac activity happening simultaneously. That's really the big challenge there, just keeping everything lined up.

Douglas H. Miller

What was the other one he was asking about? Frac cost.

Gil Yang - BofA Merrill Lynch, Research Division

Yes, cost.

Harold Jameson

We -- over time, we changed our profit mixture. Our initial wells were all intermediate-strength proppants. We've experimented over time. We've reduced that to about a 50-50 blend. And then we're taking steps to reduce that even further, like 3:1 blend with a smaller intermediate strength portion. That has a pretty significant cost impact. We're working towards that now. And we've actually got some completions going on right now at blend.

Harold L. Hickey

A pound of intermediate-strength proppant process costs probably 5 to 6x more than a pound of sand.

Michael R. Chambers

It has been kind of a lot of little things. I mean, we've been very encouraged here lately. We've switched a lot of rigs to buy fuel where we buy natural gas and diesel. I mean, that's like a $50,000 a well savings. So a lot of it, the big chunks are kind of gone, and so we're working with small fine-tuning.

Douglas H. Miller

This year -- everybody around here, if we can save $1, we're saving $1. But I think we've gone through the big savings and the testing. And now we're down to the little things. If gas stays where it is, I would expect you're going to see some rig cost start coming down and maybe even some frac fleets so they continue build them. But if all stays up, they'll all move over there.

Gil Yang - BofA Merrill Lynch, Research Division

And are you seeing any indications that those rig costs and frac costs are coming -- after the services are coming down? Or...

Douglas H. Miller

Well, we've had -- I think we went out for bids on the frac fleets here about 4 or 5 months ago, and it was pretty aggressive. I don't want to say they're coming down because Halliburton and BJ Services are probably listening. But I'd say it's more competitive. When you get a couple of fleets in East Texas and the choice is either stay or move down to the Eagle Ford, they have people that want to stay. They're doing everything they can to keep those fleets busy in the area were they have expertise. They found the rigs. We have 22 rigs running out there, and we're finally getting it to running smooth. The people are trained right now. We drill well after well. And I feel bad about releasing some of those but it's a math problem we have to. Every one of those rigs with the exception of maybe one is purring like a kitten right now.

Operator

Your next question comes from the line of Joe Allman with JPMorgan.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

A follow-up question on the Marcellus. So I think, how you said you've drilled one well in the Centre County Clearfield County line, so what are your plans in terms of developing that? Any thoughts about trading the acreage or selling the acreage? I'm really just trying to get a sense of the productivity or the prospectivity on your entire 140,000 net acres of perspective merciless acreage.

Harold L. Hickey

Our development focus is going to be in the Lycoming County area for the foreseeable future. So we're going to continue to delineate and appraise areas outside of that over the next year. So probably we'll say we're ready to move into a new development area. Like Doug said earlier, you're looking for the other As. We think we got an A in Lycoming. We think this looks encouraging in the Central Clearfield area, in the Armstrong area and in the Jefferson area. But we want to drill a few more wells there and really make our plans before we move forward.

Douglas H. Miller

And Joe, I don't think were a seller of that acreage. I think, if anything, if we saw a deal, we'll be a buyer in those areas, and John is trying to do that right now. We have a little play with 5,000 or 10,000 acres down in West Virginia. We're trying to buy -- we think we're going to be buying some acreage down there. We're not a seller yet.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

That's helpful. And of this 140,000 perspective Marcellus acres net, how much of that do you think you've proven up at this point?

Douglas H. Miller

10 acres. No, I'm kidding. A small percentage, very small percentage. Marcie, you got any ideas on that?

Marcia Reeves Simpson

[indiscernible] is 50,000.

Douglas H. Miller

50,000 is proven up. But I mean, that's -- a big significant piece of that is up in Lycoming County. That's probably -- I don't even know if we have any reserves book down on it yet, but it sure proved. Are you going to give us some...?

Marcia Reeves Simpson

Well, at the end we're producing where we have some.

Douglas H. Miller

Okay, good. So I think, it's way -- Joe, it's way early. And John's group is trying to buy more, and we clearly have one area where we'd like to be focused. But those other areas, we haven't written them off yet. Our guys are starting to finally get it up there, and everybody's working together and they're making some good wells outside of Lycoming.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

So I guess, using the term proven is probably an incorrect term. What I meant to ask was how much of the 140,000 do you think is going to work based on the data you have?

Douglas H. Miller

That's another question. I would say the majority of it is going to work. It will range from good to great. And by the time we figured that out, we'll have another 140,000. There's stuff for sale up there.

Joseph D. Allman - JP Morgan Chase & Co, Research Division

That's helpful. And then just one follow-up to the LNG question. So Doug, are you saying that you think that EXCO has no direct implications and no direct impact from BG's plan to export or to buy LNG?

Douglas H. Miller

Let me tell you, that is an expensive man's game. We talk to them a lot. We have not pushed to become a partner. I don't know if they'd let us if they could. They help us as far as worldwide demand and what the worldwide prices are. And we talk to them a lot about what they think gas price is going to be because they have a little different view because they're looking at the whole world where we're looking at Louisiana. I think we'll have some opportunities, but it maybe they want to buy all the gas we have. And all we do is market our gas based on Henry Hub. And we're probably going to start -- we're in discussions, and we can mark at our 50% to whoever want to. We're in discussion with several utilities. We have not made a deal on any of our gas physically long-term yet. But before we do, we will have a chat with BG.

Operator

Your next question comes from the line of Adam Leight with RBC Capital Markets.

K. Adam Leight

I think most of my questions have been exhausted. One quick follow-up on drilling and completion cost. Just to clarify, is there any friction in terms of crews that are going to stay or rigs that may stay in Haynesville? Do you have contracts rolling over that can benefit from some lower costs there?

Douglas H. Miller

Yes, well, that's something these guys have done a great job on. I'd say if we just let our contracts run off, better in effect, we could go down to 11 rigs by the end of the year, and that's the way it works.

Michael R. Chambers

No, I think it's even lower.

Douglas H. Miller

Oh, it's even lower.

Harold L. Hickey

By the end of '12.

Douglas H. Miller

Yes, by the end of '12. So I mean, the answer is we have contracts rolling off. Typically, we would expect to renew those. Our guys are right now evaluating which rigs and which companies that are preferred contractors. And do we want to have 4 different contractors or 1 or 2. That's in Mike's and Harold's hands right now. They're going to come back with recommendations. They clearly are crews and rigs that do a better job in every play.

K. Adam Leight

And then quickly on differentials. It looks like your forecasting some improvements. Is that because you have more Marcellus gas coming on. Is that marketing? Is that pipeline take away?

Douglas H. Miller

Mainly, Adam, it's all -- its' mainly just the Arcadian system coming on where we'll be able to access our own firm and get to the better markets than we've had to in the third quarter using interruptible. We had to go pay for interruptible or pay a little additional cost while this plant's down. And so it's going to get better just by moving that gas off some of the place where we had to pay an extra few cents on to some where we've already paid for.

K. Adam Leight

And then finally, your -- a question on larger bank facility, you've got a $1 billion drawn. What's your comfort level ratio for bank in your capital structure?

Douglas H. Miller

We're targeting 2:1 debt-to-EBITDA. I understand. I'd say the sweet spot on our bank draw is 70%. We've gone higher. If we do, you'll see significant hedging going on and pay it down quicker. But if you talk to the banks or us, kind of the sweet spot and high is around 70% of capacity.

Operator

Your next question comes from the line of Jeff Robertson with Barclays Capital.

Jeffrey W. Robertson - Barclays Capital, Research Division

The only question I have left was did you talk at all in the discussion about TGGT about what you thought the EBITDA profile would be over the next couple of years? And can you talk about that?

Douglas H. Miller

We can't talk about it right now because the rig count is very critical there because we have very little third-party because of our operating guys. We've gone out to get third party twice and brought them back in because they keep making better wells than we forecast. So as soon as we get our rig count confirmed at the board level, we'll readjust that, and we'll do an upgrade on that, maybe on the 18 or 19 also. It moves around just based on the rig count.

Jeffrey W. Robertson - Barclays Capital, Research Division

Okay. And that's this month, right? That's not December?

Douglas H. Miller

No, it's November, right.

Operator

[Operator Instructions] Your next our question comes from the line of William Butler with Stephens.

William B. D. Butler - Stephens Inc., Research Division

Sorry, quick follow-up. On the Shelby, completed well cost of $13 million plus that you all experienced in the first half and just under that now, the IRRs that you discussed a few minutes ago, was that assuming $12 million or the $13 million that you're experiencing now? And how soon can we actually see a get to the $12 million target?

Harold L. Hickey

We've been running our economics on $12.5 million well cost. And we expect over the next 3 to 6 months that we'll bring that down to about $12 million.

William B. D. Butler - Stephens Inc., Research Division

You said 6 months?

Harold L. Hickey

3 to 6.

Douglas H. Miller

But we're using $12.5 million on our modeling right now, yes.

William B. D. Butler - Stephens Inc., Research Division

Okay. So that 20% to 25% at a $4 gas?

Douglas H. Miller

At $4 gas and $12.5 million cost.

William B. D. Butler - Stephens Inc., Research Division

Okay. And then one final question. Just thinking about capital allocation, Doug. How many with, you've got the share buyback program of $200 million, you've talked about producing property acquisitions, it sounds like that's pretty competitive with -- if you're thinking about production and thinking about the private equity firms out there. And I’ll throw out the thing is corporate M&A. I mean, how do you prioritize the three uses of capital there?

Douglas H. Miller

Well, our stocks are trading at $10 and we can liquidate it at $20, it's pretty ideal buy. That's a debate at the board level. I mean, I promise you if we weren't restricted, we would have been buying stock. Board has been pushing us. We just been restricted and we will be restricted until Friday, I think. Is that right, Lanny? But I'd say this, if we can buy a $50 million or $100 million deal in the Cotton Valley or the Haynesville with 3 locations and finance it right, I think we can make 25%, 30% rates of return by the stock. It's all things around the table, we have 4, 5 partners that want to invest with us. And so we're not going to stretch our balance sheet by doing a big deal. If there's a big deal out there where the market -- where it works, will bring in a partner. And we're not issuing any stock right here. I don't think I answered that right but that's the answer.

Operator

And there are no further questions at this time. I'll turn the call back over to the presenters.

Douglas H. Miller

Okay, thanks, everybody. Good questions, you guys. Again, sorry, we can't forecast when a plant is coming back on. But I think it's in everybody's best interest, we did what we did and delayed it. And we'll have that back on and report back to everybody. But operationally, our guys did a spectacular job, and they're going to keep it up. And we'll have some -- probably by the end of the week, early next week, we'll report to you on the bank deal. And then shortly after the 17th, will get back to you on our rig counts, capital budget and there will be an update on TGGT.

Again, thanks for calling. Bye.

Operator

This conclude today's conference call. You may now disconnect.

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