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EXCO Resources (NYSE:XCO)

Q2 2011 Earnings Call

August 03, 2011 10:00 am ET

Executives

Stephen Smith - Vice Chairman, President and Chief Financial Officer

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

J. Douglas Ramsey - Vice President, Chief Financial Officer, Chief Accounting Officer and Treasurer

Paul Rudnicki - Vice President of Financial Planning & Analysis

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

Harold Hickey - Chief Operating Officer and Vice President

Analysts

Brian Singer - Goldman Sachs Group Inc.

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

Gil Yang - BofA Merrill Lynch

Marshall Carver - Capital One Southcoast, Inc.

Operator

Good morning. My name is Sarah, and I will be your conference operator today. At this time, I would like to welcome everyone to the EXCO Resources Inc. Second Quarter 2011 Earnings Release Conference Call. [Operator Instructions] I would now like to turn the call over to Mr. Doug Miller. Mr. Miller, you may begin your conference.

Douglas Miller

Thank you, Sarah. I'm Doug Miller, and I'll be the leader of the conference call today. With me today I have Steve Smith; and Hal Hickey; and Mike Chambers; Marcia Simpson; Doug Ramsey; Paul Rudnicki; Mark Wilson; and last and least, our lawyer Lanny Boeing, who will keep the necklace around me.

But I kind of expect this is going to be kind of a boring conference call, because we -- on July 13, we kind of went over almost all this stuff for everybody, which was kind of a good, real good CliffsNotes version of what was going on in our data room over the last 6 or 8 months. So all we're going to be doing is bringing everybody up to date.

And before I get started, I'm going to have Ramsey do 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 our future financial operating performance, structure and results, business strategies, market prices and future commodity price risk, management activities, plans and forecasts and other 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. Please refer to Pages 23 to 24 of the slide presentation for the complete text regarding our forward-looking statements.

In addition, please refer to our website for the earnings release, which contains additional information regarding our forward-looking statements and the preparation of our financial disclosures, including reconciliations and other statements, regarding non-GAAP financial numbers, which will be discussed on today's call.

Doug?

Douglas Miller

Okay. Thanks. With this, I hope everybody has the slides because we're going to quickly go over the slides, then we'll open it up for questions.

We've had expected accurate results, mostly in our Haynesville area. Our operating people have done a great job. Our partnership with BG continues to be running smooth. We have 22 rigs running out there. Hal and Mike will get into that in a little while. But our volumes were really in development mode up in DeSoto. And we're really working hard down in Texas, slightly deeper, but I think we've had some pretty good results down there. I think they'll get into that. But volumes up. Production, significant.

Midstream volumes up significantly. We continue to add on to our Midstream assets in East Texas and North Louisiana. It is growing again. It's a joint venture with BG, growing with leaps and bounds. We're starting to put in some infrastructure up early in the Marcellus, and Hal will get into that a little later. I think, in the middle of the page there, we recently had a couple of delineation wells down in the Shelby area, a couple of them over 30 million a day, and Hal might talk about a couple of them that are -- I got some news this morning that looked pretty good also.

We're still buying in both the Haynesville and the Marcellus area. John's in here. I think he's probably got 20 deals, none of them big, but a lot of little deals in the Haynesville and the Marcellus that we're looking at. We have had one recent, what we call, a real good well that IP-ed at 10 million, but Hal will get into -- we're seeing some stuff that's a little unique for shale plays. Hal will get into that here in a minute.

And I think the key to this whole thing has been the people. And I told you I've had the best people I've ever had here, the last 2 to 3 years, and it's really showing down in the Haynesville. And we're marching up in the Marcellus. And I know our people are cooperating with the mistakes that we made early on in the Haynesville, they're sharing them with the guys up in the Marcellus.

And so we're starting to ramp that up. Again, we'll be a little bit slower there for several reasons. Number one is the bulk of our acreage is held by production. Number two, we have 4 or 5 different areas that we're focusing on. And most importantly, again, is service companies moving around the areas in infrastructure. So that'll be a slower ramp up like I've been saying for the last 2 years. But it continues and it looks like we're starting to get some encouraging results there.

With that, I'm going to turn over to Steve. Steve?

Stephen Smith

Okay. Quickly, Slide #5 is what I'll be focusing on to start with. It was a good quarter, really an excellent quarter for us. Every -- all metrics are up pretty significantly over the first quarter and dramatically over the second quarter of 2010. Our production continues to increase. We were up 23% quarter over the first quarter and 71% versus last year. So it's -- everything is going as we had planned.

I think that we expect to continue that kind of growth. We're guiding towards an overall average of 529 million, I believe it is, for the year and probably an exit rate in excess of 600 million a day. So guiding to $668 million of EBITDA. So we're on our way. We're -- our cost structure, we're seeing some really good improvements in the cost per Mcf of operating costs, and that's very encouraging.

On Slide 6 is I think a real good presentation of our cash operating margins of our quarter, from all the way from the second quarter last year till now and also the projection for the year. We're over -- when you compare the second quarter '10 to the second quarter of '11, we're up 25% on our cash operating margin, and we're 8% up between quarters. So we're rocking along just exactly like we want to be. We've still got some derivatives out there. We'll talk about those a little more in detail in a minute, but they are certainly still contributing to the overall cash operating margin.

Page 7 is a slide that we show each quarter. Just to show you where we were at the end of '08, that was in production-wise, what has happened in terms of divestitures over the period and then where we are now, which we've replaced all of the production that we sold and then some. We're at about $1.5 billion of debt now, and we're projecting I think somewhere around $1.6 billion net of cash. And you can see what the projection is on our production. So this is just a good snapshot of where we are and where we're headed toward the end of the year and for the year.

I'm going to turn it over to Paul and get in a little bit more detail on some of these financial metrics.

Paul Rudnicki

Thanks, Steve. I'll pick up on Slide 9 with our liquidity and financial position. At the end of the quarter, we had $214 million of cash. We had $851 million drawn under our line of credit, which, again, has a $1.5 billion borrowing base. The rate on that debt is LIBOR plus one and a -- 1.5% to 2.5% senior notes that we issued last September, $750 million a 7.5%. Net debt of the $214 million of cash was $1.4 billion -- just under $1.4 billion, which led us with -- which we left the quarter with $853 million of liquidity.

You can see one month later, we're still virtually flat. Cash is down a little bit as we cycle through. And as Steve said, we should -- we'll be expecting to borrow a little bit more money during the rest of this year to fund our capital program.

Slide 10, no new changes to our derivative position, since we reported this at the end -- in July, as Doug mentioned. We continue to be about 55% to 60% hedged for the remainder of this year and 25% to 36% hedged for next year. We'll continue to monitor the markets, and if we have some strength, we will continue to look to layering some hedges on. You can see what our targets are on the bottom of the slide there as well.

Slide 11, the capital forecast. We did increase the forecast by about $20 million from our prior guidance. The main result there is from the increased pace that we're working with in the Haynesville. Our cycle times are coming in much faster, and we're going to be able to get some more well spud by the end of this year. It's not going to contribute to production for the year, as these wells will all be coming online in 2012.

On Slide 12, looking at our actual performance against our guidance. And again, this is our updated guidance that we presented back on July 13, so there's not a lot of variance from there. We had a pretty good look at the quarter and had some pretty good confidence around what the numbers we're going to come in on. Again, we came in at 500 million a day and -- which included the impact of having approximately 23 million a day curtailed as a result of our pipeline incident. So without that, we would have exceeded even our prior guidance.

And the other thing to point out is just again to highlight on the equity income, which is primarily from our 50% interest in the pipeline company. There was an impairment, noncash impairment charge of $6 million, net to EXCO, which affected our equity income.

Slide 13, looking at our guidance for the rest of this year. Again, no major changes from before. We have tightened up our range for the rest of this year, made some minor adjustments to LOE and operating costs and obviously updated our CapEx to reflect the current spending level and made some other adjustments to the G&A and noncash interest expense.

With that, I will hand it over to Hal to go over the operations.

Harold Hickey

Thanks, Paul. Go over to Slide 15, if you will. We got some great things happening operationally across our portfolio. We've moved into manufacturing mode in certain areas in the DeSoto area of our Haynesville operation. The appraisal program is going really well up in Appalachia. Some outstanding works being done in reducing some of our capital costs on our drill wells, and our unit cost, as Steve said, are down dramatically. So we're really happy at what we've been able to do on the operational front.

We completed 71 gross, 40.6 net wells during the quarter. We're continuing to drill with 27 operated rigs today. We're seeing 99%-type drilling success rates. We've got about 5 operated by other rigs, all in the Haynesville, that are also drilling in our portfolio.

Down in the Shelby area of East Texas, in our Highlander region there, we're just seeing some really strong, strong results. We note on here that we've had average rates of greater than 28 million a day on IP basis. We've got a couple of wells that are coming on now, that Doug referenced earlier. They're over 10,000 psi. We're seeing 29 million a day flow rates. And this is an area we're going to continue to concentrate some of our delineation in, moving toward development there, because it's just really an outstanding portion of the play.

Up in the Marcellus area in northeast PA, our appraisal results have been particularly encouraging of late. We're going to get into a little bit of detail on that in a couple of slides back. We're currently completing 6 wells on development acreage in northeast Pennsylvania, and those are going just as we would have anticipated. This is mostly on the chief acreage that we acquired late last year.

Slide 16, getting in to some of the details in North Louisiana. You can see that our current operated shale production is actually now over 1.2 Bcf a day, and last week, we were at 391 million a day net production. We're actually about 410 million today, so we're marching along.

We have some 350 to 360 wells that are flowing to sales now. The bulk of those are, of course, operated. We're seeing some continuous improvement in not just the cost of our drilling activity, but also the time from spud to rig release is marching right down. So we're really happy on that front.

And then another thing that's a very significant statistic for us. We only have 6 wells that are waiting on completion. So between our efforts of our people, the management of our logistics, the responsiveness and capabilities of our frac crews, we've brought that really down. So we're in good shape there, and we're continuing to have appropriate water management across this portfolio.

17 gets into some of the details on the capital cost reduction in North Louisiana on our drilling wells, and you can see we're targeting $8.8 million to $8.9 million a day in the second half. We're doing similar reductions in East Texas. But I will say, in East Texas, you're starting at $11 million to $12 million, depending on where you are in that portion of the play. So they'll come down probably another $500,000 or $600,000 there as well.

We're looking at things on the drilling and completion front. We were talking about our cost reductions. Our guys have done some really good job working with our contractors on our bits. We're very much efficient when it comes to our pad and road locations. Development and construction, that's getting better. We're focused on reducing our nonproductive time. And the completions front, like I said, we're working very well on that.

Slide 18 starts to go -- move over into the Appalachia portion, and really the focus up there, of course, is in our Marcellus shale. We've got 3 rigs operating up there today, 2 are in the development area, 1's doing appraisal. And a fourth rig is literally moving in as we speak, and it's going to be working on development as well on our northeast area, predominantly in Lycoming County. We're likely to have one more rig, either late this year or early next year. But that's the plan as that stands. We won't have anything between now and then.

Drilling days are continuing to improve up there. The 6 wells in the Northeast Development Area that we have completed, we've seen some in excess of 10 million a day. On average, it's probably more in the 6 million a day realm.

One thing though that I'd point out, it's on the bottom of this page, that we're really trying to get our hands around and we're understanding it better and better is that in certain areas, our production rates improved dramatically from the initial IP that we see in the first 7 days or so of production. About 60 days in, we're seeing 15% and more improvement in our production rates. So we're working on that. We're working on spacing. We're working on our completion methodologies, and we're very excited about the potential that we're identifying up there.

So the focus for '11 is noted on Slide 19: implement development in the northeast area, where we'll have, like I said, 3 rigs drilling there shortly. We've got the 2 today; very big focus on improving our technical understanding of the Marcellus shale play. We're making great progress there. There's a lot of technical sharing across our asset boundaries, and I'm really proud that our people are engaged in; big focus is on identifying the best rock in areas outside of the development area as well. So we're looking for acquisition opportunities wherever we find that best rock; and then we're going to continue to optimize the portfolio and hopefully, move into gas manufacturing very, very soon.

Infrastructure development in the Marcellus is something that we've got a team of probably 20 guys working on every day. We've got some pipe being laid in the ground. We're looking at third party opportunities. In our development area, we're actually working with a third party who has an established midstream there when we bought the assets.

Slide 20 starts to get into some TGGT discussions. [indiscernible] TGGT is our East Texas/North Louisiana equity JV that we have with BG Group. In Q2, we set a record, exceeding 1.4 Bcf a day. The other day, we were almost at 1.6 Bcf. We're marching one of the biggest growth areas we're seeing in Shelby, which I talked about where we're seeing the good well results. We're actually pushing 250 million a day down there today. So that's growing rapidly.

We've talked about the incident that occurred and that -- back in May, where we had a problem at one of our treating facilities over in Red River Parish. That thing remained shut down, but we're quickly moving in some lease, at least, amine treating facility. So we're going to be back having full treating capabilities here shortly in the third quarter.

21 gets into some detail on the timing of what we're going to do about bringing the treating facilities back online. We're going to start the undamaged units later this quarter. We're actually leasing temporary units. They'll be on later this quarter. So like I said, we're going to have full treating capacity late in the third quarter. Some of those leased units that we're bringing on will be released by late in the fourth quarter, early next year, and we'll be back with our normal treating capability by late December, early January.

The bottom part of this slide shows the impacts to our operating results. TGGT, entity itself, is going to have about $13 million of EBITDA impact. And then in addition to that $13 million of EBITDA impact from revenue and operating expense, there's going to be $12 million noncash impairment charge. So net to EXCO, we're going to have an equity income hit of about $12.5 million in the quarter.

The last slide I'm going to talk about is on Page 22. Paul noted that our E&P budget forecast now is $997 million. That's slightly up as we're drilling wells faster with our contracted rigs. The performance remained stellar in the Haynesville. We've got existing infrastructure market access, so that's allowing us to get our gas to market. Marcellus, like we said, is very much progressing. The results and technical understanding in the play are rapidly improving. We've got to work on the infrastructure. And I will note that down in the Permian, we were making some 1,600 or so barrels of oil a day. We're still drilling with the 2 rigs, and we're getting some very good results.

Last thing I'll point out on this page, and you heard me say this before, that in Appalachia, our drilling and completion dollars are artificially low as there's still some -- oh, as of June 30, roughly $90 million to $100 million of BG carry remaining. So in the JV entity in Appalachia, we're actually spending about $280 million on drilling and completion, EXCO is net of that this year is only about $35 million.

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

Douglas Miller

Okay. I had a couple of calls last night after our earnings, and a couple of questions coming up is what do we think about gas price. And gas price is soft.

What are we going to do about our capital program? We begin our capital budgeting program here next week. We go to our board sometime in November. So we remain flexible. And our original forecast was $4.50 for this year and $5 for next year, it's down below that. We do have hedges in place. I think we'll look at all. I think initially, for next year, we were talking about roughly $1 billion capital program. That is something that we will have debate with, including our partner BG and including our board, and we remain flexible on that. We continue to look up in Appalachia.

But gas price, it still surprises me slightly that gas is down here. By the way, any of you guys in New York if you want to come to a steam room, come to Dallas, it's going to be 110 [degrees] today. So I think, we're starting to see a lot of utilities approach a lot of the producers, including us, as far as tying up long-term supply on some of these plants that they're finishing up construction and in construction on shutting down coal plants and natural gas. So I kind of expect some demand to be picking up over the next 12 to 18 months from the utilities.

And if gas prices stay cheap, it looks like there's 3 or 4 export facilities coming in. I'd say over the next 2 or 3 years, if gas stays where it is, we're going to be a significant exporter. And we're looking at -- into opportunities there. And I think our partner, BG, will be one of the significant players in that, if it happens. But I expect it will with the price -- with the difference. When you can sell it at $10 in China and Japan and you can buy it of $4 in the U.S., it don't cost that much to move it over there, there's a lot of potential profit in the middle.

And I think, there's also -- I've seen Aubrey chat. This natural gas to liquids is something that is working. Shell, I think, is doing that, and so it wouldn't surprise me to see some fairly significant projects pop up where there's a lot of gas, whether it be in Louisiana or whether it be in Pennsylvania, converting natural gas to liquids because the economics work.

Other than that, I think the most positive thing that's happened in the last 2 weeks, watching the turmoil that we've been going through here, unwinding our go private and the turmoil in Washington, is that we have a full Congress going on vacation for a month. So I kind of expect the next month to be a good month.

With that, I'm going to turn it over to questions, and we'll stick with you as long as you need us. Sarah?

Question-and-Answer Session

Operator

[Operator Instructions] And your first question comes from the line of David Heikkinen from Tudor, Pickering, Holt.

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

First question, can you walk through how you'd model the -- a Marcellus-type curve. I'm not exactly sure how to model increasing well production over the first 60 days. And kind of what you're thinking of how that will actually result in if you are...

Douglas Miller

Hey David. I mean, here's the problem. We just started seeing the results on some of those wells. It's way early. I think initially, as you know, we were using the same type curve across the play, and we adjusted it depending on the lateral length and the IP. But I would say, right now, with some of the recent results, Marcia would spank me if I start talking about decline curves on this. I think our people are actually going up tomorrow, and that's going to be a topic. All I can tell you is that it's going to change. When you have increasing production for the first 60 days, it, for sure, doesn't fitting in of our existing type curves. So the answer is I can't tell you because we don't know.

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

Doug, on the Shelby-type curves then. Can you walk through kind of how you're thinking about those wells versus your core wells where you have more production history?

Douglas Miller

Yes. And I think the best thing I can say there is DeSoto Parish, where we have a couple of hundred wells in 2 to 3 years of history, our type curves there have evolved. And we're in really -- I mean, they really have evolved to where we now have a 4-type type curve, a 4-piece type curve, and we're very confident when we drill a well up there. And I would say with the limited data we have there in Shelby, I'd say we have estimates. But for us to start putting out type curves there, we need more data points. And I think -- we're starting very conservative down there. But I would say, Marcia would again spank me if I start talking too much about -- because it's going to evolve. And I'd say about a year from now, we're going to have a real good idea, and I'm sure it's going to be a 3 or 4-part type curve. You just don't have enough production data. When these wells come in at 26 million to 29 million with 10,000 pounds casing pressure versus 18 million and 7,000 pounds, they're going to be different, and they talk to you. And in 6 months, a year and 2 years out, before you start seeing those decline curves change much, and I just don't want to sit here and tell you what I think it's going to be until we know.

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

So as I look at your TGGT system, yes, it's obviously big growth in Shelby from second quarter to today. How many wells did you tie into the system?

Harold Hickey

Probably, 15-ish in Shelby.

Douglas Miller

And the TGGT, that's the part of our challenge down there, because it's slightly better than we thought it was going to be down there. And so we're aggressively building pipe, and we're tying into third parties. And we have a debate right now with BG, should we build over to the Holly system from there, should we go up to Carthage. And each one of those is a couple hundred million dollar program. So we don't have a meeting on that until this afternoon. But we're working on that. And by the way, that TGGT pipeline, it's about 1.5 billion today, but I kind of expect that thing to be pushing 2 Bcf a day by the end of the year. Hope I'm not supposed to say that, but Marcia don't mind me saying that one. All right.

Stephen Smith

Remember, Doug, to -- down in Shelby we laid a 36-inch trunk line.

Douglas Miller

Right, and we're tying in to everything else. But we do have some pretty good production coming on there. We do have some restricted.

Operator

And your next question comes from the line of Brian Singer from Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc.

So following up on the question on inclining production in the Marcellus, and you may have mentioned this, I apologize. But which counties are those specific to? Is it just the appraisal areas that you're seeing? And can you maybe put into context anything you're doing on West Virginia?

Harold Hickey

We're seeing it across the play. We're seeing some increases, and -- but I will say, we're only drilling in a very few counties at this point. We're not active in West Virginia at this time. All of our acreage there is HBP, and we won't be drilling there at all this year.

Douglas Miller

It's mostly central. And we're not going to name counties because Jacobi is trying to buy stuff there.

Brian Singer - Goldman Sachs Group Inc.

Got it, okay. And then what are you doing, if anything, on lateral lengths in the Marcellus? What do you expect in -- to be your kind of going-forward lateral length there, or do you expect that to vary across your areas?

Harold Hickey

It'll vary across the areas, but I will offer that we're not necessarily seeing linearity between lateral length and production rates. So it's all a function of where the best rock is and getting your seismic down and understanding everything from your faulting to your land position. So the lateral lengths will vary and we're seeing very good results from some short laterals, and we're seeing some unexpected results from some long laterals as well, so.

Douglas Miller

And I'd say when we model here, 3,500 to 4,000 is kind of our modeled lateral length. I mean, we don't expect any 9,000 footers, and we hope we don't have any 2,000 footers.

Brian Singer - Goldman Sachs Group Inc.

Got it, okay. And lastly, when you're talking about this year's budget earlier in the year, you talked about $4 in Mmbtu as that threshold price below which we should expect that you would more meaningfully drop rigs in the Haynesville. Is that still the threshold price for next year, relative to the budget that you put out a month ago?

Douglas Miller

Yes, yes.

Brian Singer - Goldman Sachs Group Inc.

i.e. if gas prices are where they are today at $4.16, $4.25 and that holds through next year, we should expect no different to budget than what the...

Douglas Miller

No, no, no, I wouldn't say that. I would say that we were kind of hoping for $5 next year. We were $4.50 for this year, but we thought we would really have a significant slowdown at current costs and current prices if they got down to $4. And I would say that there's still cost tugs. And I think it's only smart -- I don't want to -- we kind of have budgeted $1 billion for next year. And -- but our EBITDA, if gas is below $5, it's going to be below our forecast. So we're going to take a hard look, and if rates return, aren't -- don't exceed 20% in the gas area or better, we're not afraid to slow down, and we will. I mean, I think it's going to be a good debate coming up, with both BG and our Board. Our board wanted to slow down last year, but we already had a contract with BG. So I think it's going to be a good debate, and we know exactly -- it only takes 7 rigs in the Haynesville to maintain our production. So anywhere from 7 to 22 should add growth, and so we have plenty of locations. We have plenty of flexibility, and I don't think it'll go to $7. But we're looking it all, including an increase.

Operator

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

Gil Yang - BofA Merrill Lynch

Doug, just to follow up on your last comment. So the board had been considering slowing down in 2011, but the BG contract, i.e. the carry, was sort of what gave you the incentive to get going this year?

Douglas Miller

Well, I think when we -- no, it didn't give us any incentive. Basically, when we sold the deal to them, we agreed to a program, which was kind of a 3-year estimate and a 1-year firm. And we agreed to that and our board agreed to it, and that's the 22-rig program that we have underway. And what our guys have been able to do is drill a little bit faster. We're actually drilling a few more wells than we had in our forecast, because drilling days, I think, we initially forecast 45 and we're down to 40 or something like that. Is that right, Mike?

Michael Chambers

42.

Douglas Miller

42?

Michael Chambers

Yes. From those PUDs' spud.

Douglas Miller

Yes. So in 3 or 4 days per rig, it adds more wells. Excuse me. I would say we do have a good partnership. It's 50-50. And we'll sit down with them. And it's math. Prices are down. And we can slow down and look at acquisitions, or we can slow down and just take the cash flow and pay down debt. We're not afraid of doing that.

Gil Yang - BofA Merrill Lynch

Were there any conversation coming from their side that maybe they were willing to forgo the 22-rig program for this year?

Douglas Miller

No, no, no. I mean, one thing about BG is they like going faster. They're great partners, but they have their pedal down around the world and we're part of that. So it will be a spirited debate.

Stephen Smith

And I will add that we're aligned in the sense that if it doesn't meet the hurdle rates, and our hurdle rates are very similar, nobody wants to keep drilling if we don't meet the hurdle rates. We will build the program around that.

Gil Yang - BofA Merrill Lynch

Okay. In terms of the Haynesville, you commented on some terrific results. What is the -- if you were to draw circles around the Haynesville, what is the comp, in terms of IP rate, that you think is the minimum in terms of where you want to drill? You mentioned, I think, Doug, that you had some wells that were 10 million a day. Could you elaborate on those areas or to kind of...

Douglas Miller

Well, I'm looking at the map right now. And as you may or may not remember, that was a 6-million-acre play 3 years ago, and you didn't know anybody that went into play. And it has evolved. We have maps by year. And I'd say a little over a year ago, it was the 600,000-acre economic play. And it has -- I'm looking at our new map right now, and it is DeSoto area. And it goes a little bit to the southwest and a little bit to the northeast of us is what I call the A area. And that is -- IP rates in that area range anywhere from 10 million to 20 million a day. Ours have been averaging 18 million a day. Most importantly is the rock and the pressures that we're looking at and gas in place. And then down in the Shelby Trough, between 2 big faults, and they don't match up. I mean, it's deeper, higher pressures, cost more. But there's a small area down there, and I guarantee it's not 600,000 acres today. And we have acreage in other areas where the IPs are 5 million to 10 million over in Harrison County and some of the other areas, where we tested a year or 2 ago, and we quit drilling just because the rate of return does not hit our hurdle rate. But we're HBP over there. If we're not HBP, we're dropping the acreage.

Gil Yang - BofA Merrill Lynch

So when you guys look at deals for a grant of small acreage packages, are you seeing a lot of acreage for sale in these fringy areas, of people just trying to recover some of the...

Douglas Miller

Oh, yes. I mean, if you want acreage in the Harrison County, we can line you up. We get you 100,000 acreage over there for $500 an acre whenever you want you some. Then -- and we'll sell ours.

Gil Yang - BofA Merrill Lynch

Right, right. Okay. And lastly, can you just -- Hal, I think you talked about the Permian results really quickly. Can you just comment on what you're doing there, and what kind of well results you're getting?

Harold Hickey

Yes. At this point, we're still pursuing mostly Canyon Sand drilling. We've got 2 rigs that are operating out there. The costs are in the $700,000 to $800,000 range, and we're getting 50%, 60% rates return, and our production today is about 50-50 oil and gas.

Douglas Miller

They're small oil wells, and they're very economic.

Harold Hickey

We drilled up 72 wells out there this year.

Gil Yang - BofA Merrill Lynch

How many wells at inventory do you have?

Harold Hickey

Oh, in inventory, we only got 3 years of inventory or so left.

Operator

[Operator Instructions] And your next question comes from the line of Marshall Carver from Capital One Southcoast.

Marshall Carver - Capital One Southcoast, Inc.

On the acreage acquisitions, are there-- would -- I mean, could you give some sort of feel on the size of those packages? I mean, are they significant compared to your...

Douglas Miller

No, no, no. I'd say in the last 3 months, we bought 900 acres, one deal down in Shelby. Most of the stuff that we're buying up in the DeSoto area is 50 acres, 100 acres, 200 acres. It is detail right now. We have land people in -- looking at minerals, looking at surface, looking at working interest, looking at small private operators that would like to sell. So no, it's little tiny stuff. But 80 acres is the location up there. 900 acres down by where Mike's filling these wells, could be 6, 8 locations. So up in the Marcellus, it's slightly different. In our areas that -- where we're were doing this work, because it started out so big and because there was a lot of leasing going on, that tends to be larger in acreage size. But we're having success adding 2,000 acres at a time, 5,000. I think John's looking at a 40,000-acre deal right now. It's slightly larger up there, just because the size is bigger. It's down to detail now.

Operator

And your next question comes from the line of David Heikkinen from Tudor, Pickering, Holt.

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

Just a follow-up. As you think about BG and their activity levels, it's been one of the keys for them to making their production guidance and their 2015 plan is keeping their U.S. business going at this level. Can you really slow down given where their plans are? Because it's been the enabler for them to make guidance.

Douglas Miller

How did you know, David? I would say that whenever one of their 27 countries go down, then it seems like our accelerator gets pushed. So if Australia and Egypt would come back on, I think they'd be a little more flexible. But we have had the ability to accelerate and help them, and we will continue to look at doing that. I mean, they are a great partner, and our models and their models are right aligned. And I think right now, our model for next year is right on top of each other. I think it's just driven by gas price. And again, the bottom line is they're driven by a simple math just like we are.

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

Okay. Your returns are acceptable so I wouldn't expect it to slow in this type of environment, with the hedges particularly.

Douglas Miller

I would agree. And I have a feeling they may be hedged, also.

Operator

And with no further questions in queue, I turn the call back over to the presenters for any closing remarks.

Douglas Miller

Thank you. I didn't cuss once. This was pretty easy. So Lanny, I got a A or a B, or at least I passed.

Again, thanks everybody for being on. I know this was a little repetitive from our July 13. But everybody around here is working hard, and we're continuing to try to grow this thing but it's a challenge with pricing where it is. But there's a lot of deals out there available. We will continue to look. We may start looking at other areas. There seems to be other areas, shale plays that are interesting. Our group has looked at 5 or 6 deals, nothing that we're looking at. But I sure appreciate everybody.

And with that, I'll finish it up. Thanks for coming.

Operator

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

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