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EXCO Resources (NYSE:XCO)

Q2 2012 Earnings Call

August 01, 2012 9:00 am ET

Executives

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

J. Douglas Ramsey - Treasurer and Vice President of Finance

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

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

Harold L. Hickey - Chief Operating Officer and Vice President

Marcia Reeves Simpson - Vice President of Engineering

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

Analysts

Brian Singer - Goldman Sachs Group Inc., Research Division

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

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

Subash Chandra - Jefferies & Company, Inc., Research Division

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Raymond Pirrello

Brad Pattarozzi - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Nathan Weiss

Anne Cameron - BNP Paribas, Research Division

David Neuhauser

Geoffrey Hulme - Porter Orlin, LLC

Amine Benali - Manulife Asset Management Limited

Operator

Good morning. My name is Matthew, and I will be your conference operator today. At this time I'd like to welcome everyone to the second quarter earnings release conference call. [Operator Instructions] Thank you. Doug Miller, you may begin your conference.

Douglas H. Miller

Thank you very much, Matthew. I'd like to welcome everybody to our second quarter earnings and production conference call and before I get started, we have to be legal. So Doug, would you read our nondisclosure disclosure?

J. Douglas Ramsey

Sure, 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.

Statements that may be made on this conference call regarding future financial and operational plans, projections, structure, results, business strategies, market prices and derivative activities or 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 depending on 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 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 reconciliations regarding certain non-GAAP financial numbers, which will be discussed on today's call.

Doug?

Douglas H. Miller

Thanks. You sound like a lawyer. Well again, welcome everybody. We've got 9 people in here prepared to stick with you and go over all Q&A that we might have and hopefully answer any and all questions.

It's been a tough first 7 months. Good news and bad news, I mean, the good news is our people, with the slowdown, have focused on cost and production. And our production is slightly better than we had forecast. That's a product of putting a lot of time and in detail and maybe doing a few changes. We'll get into that. But we're very happy with our production and all the initiatives that we've set out on. I mean, it's been tough because to increase our earnings and our cash flow, we've had to cut people. And in 35 years, it's really the first time I've ever done that. And it's really the toughest thing that we've had to do here in the first 6 months. But I'd say that I have over 300 people between contractors and employees since the first of the year, we continue to look at it. It's just something you have to do, and it's not fun. But we have to look at it because we are running a company for the shareholders. We have reduced capital at least 3 times, we continue to look at it. Capital expenditures will be driven by gas prices, mainly, and so we continue to look at that and Hal's group, everyday, we're working on it.

I think the main initiative that we've been doing and everybody in the company has been working on is saving cost, both at the operating level and at the corporate level. And you can see that stuff starting to filter in to our income statement. And I would expect to see more of that because some of that has just been done recently, more of that in future quarters. And that's a product of being at 30-something rigs running a year ago with forecast gas going up. And now we've run into gas going down. And now we have what, 8 or 9 rigs running, and we just don't need all those people. We've been releasing rigs. Now those rigs, once they leave the Haynesville, they're heading out to West Texas or down to the Eagle Ford. They're probably not coming back for a while. And so we'll get into that here lately -- I mean, later.

We are evaluating out on our West Texas, some Wolfcamp and some Cline, Hal will get into that. We've had some recent early indications that we do have Wolfcamp, and we do have Cline Shales under the Sugg Ranch, and so we're working on that. We have finalized 2 processing agreements in the Cotton Valley where we're stripping liquids. One of that is -- they're due to be in by the end of the year.

A&D, I think everybody wants to know what we're doing. I'm kind of in the penalty box for predicting dates, which I'm not going to do anymore. Steve spanked me. We are reviewing the sidecar with our conventional assets in it. We have it out with 6 people. We have had some offers that we're evaluating right now. And instead of giving you a date certain, we hope that we'll have it done by the end of the year.

Pipeline. We have been working on that, and we have had some offers there. We're evaluating that also. We've been working with BG. We actually took it off the market for a little while, while we were evaluating another transaction. We are looking at it. And again, the good news on that is the cash flow and the EBITDA continue to increase as we cut costs over there also. Hal has gotten very involved in that and so actually, the numbers are starting to look a lot better, but we are seriously looking at making a partial or full sale of that. And again, I'm not going to give you the Fourth of July, I'm going to give you by the end of the year on that one.

The rest of the activity we're working on and have bid on several deals. We do have many joint venture partners that we have teamed up with and are teaming up with. The activity is as high as I've ever seen it. It wouldn't surprise me if you didn't see $20 billion to $30 billion of transactions in the second half of the year. Some of which we're looking at and would love to bid on. Again, most of those would be done in conjunction with joint venture partners.

We're looking at the Eagle Ford. We're looking at West Texas but more importantly, we are looking inside the Haynesville where we have our best people working and have as much data and facts as anybody. We are also looking up in the Marcellus, and our deals in all cases. So we want to be -- if gas ever goes up again, we sure would like to have more of it when it goes up.

I do have a large shareholder that's been spanking me here lately, and he gave you some facts. He said you're a natural gas company, I think we're 95% natural gas. Since the beginning of the year, natural gas is up 8% and our stock is down 33%. Since the low on April 18, gas is up 65% and our stocks are up 22%. So we have to figure out what we're doing wrong. And I think a lot of people are spreading rumors about the financial jam we're in, we're not. We have $500 million of liquidity. We have assets that we're looking at doing something with, either trading or selling, and we are participating in all the deals that are for sale. And with a lot of confidence, I might add.

And we will -- if gas goes down, we will continue to reduce rig count. I mean, we're down to 5 in the Haynesville. I think the last time, we said we were going to 7. And we're prepared to go to 0 if we need to, like with many of the other operators. I think, my feeling on gas is when we look at going private, we were thinking gas was going to be cheap for 2 to 3 years, cheap meaning in the 3 to 3.50 range where there would be some areas where you would drill.

When gas caved in to actually below $2 on 4/18, it really set a panic through the gas industry. And you saw many operators absolutely quit drilling, and many of them have made the decision to leave the dry gas areas and head for oil. And so that rig count which was 1,600 at the end of '08 is down to below 500. And in the Haynesville, for example, we're below 25 after peaking at 186. So you're starting to see it slowly, but you're starting to see production down. You're starting to see storage. The margin each week, it gets lower and lower. 20 to 40 Bcf a week is digging into our storage glut. So it looks like instead of a 3-year deal, we're looking at maybe the end of this year, we're going to be at storage levels and we're going go into peak heating and peak production needs with production going down.

So I just want to get a few of these things under our belt because I think if we do have any kind of a winter, we're going to have peak demand with production actually going down. So I kind of expect to see, if there is going to be a spike, it would be January, February.

With that, I'm going to turn it over to Steve and we'll get into the financials.

Stephen F. Smith

All right. If you would, please turn to Page 5 of the presentation, just the corporate highlights. As you can see, we're displaying the first quarter of this year and this quarter and the second quarter of last year.

Again, our production level was 2.4 percentage up. If you compare it to the first quarter, it was 9% up. If you compare it with the second quarter last year, it's essentially the same as the fourth quarter of last year, so -- and ahead of guidance. So I think we had a great quarter. The average price, obviously, is still a problem. And of course, that impacts revenues. But we are operating under our average price in the same quarter of $2.36, which is not too spiffy.

Direct operating costs are $0.38 an Mcf, down by 17% from the second quarter of last year. I'll get into a little more of that in a second. G&A is another area where we have concentrated. We're at $0.37 an Mcf in this quarter versus $0.50 in the last quarter, a 26% decrease. We did have a ceiling test write-down, as expected, and have -- as we reported that we probably would in this quarter. We wrote down 429 million, and that was on an average price of $3.15 for the trailing 12 months. That average price, at this point, is still going south. So we would expect some kind of a write off over the next -- at least in the third quarter. Overall, it was a good quarter. We were pleased with our progress in all areas in terms of our cost reductions. And I think that we're on the right track.

Page 6 shows the rig counts that Doug spoke to. Actually in the first quarter comments, I think I said that we could very well go to 5 rigs in the Haynesville if gas didn't strengthen. Well it didn't strengthen, and we did go to 5 rigs right now. It was at 7 at the end of the second quarter.

Marcellus, we're at 1 rig right now; and Permian, we've increased it by 1 to up to 2 rigs, but we'll be in the 1 to 2-rig category over the rest of the year. That's just strictly economics. You -- there's no use drilling at $2.36. The Haynesville drilling and completion cost is a really bright picture, and Hal will get into that. But right now, we're drilling wells less than the 8.3 target that we have. And I think that by the end of the year, we will be at 8. And also believe that we will be -- that we have a pretty clear, or at least a reasonably clear line of sight to -- below that and I may be down to 7.5. So we'll see. That's a tough step, but we're working on it.

In the Marcellus, the costs of drilling have begun to come down as we complete our water infrastructure buildout, which has a dramatic effect on per-well cost, so we're optimistic there. As far as the costs, you can see them down at the bottom in the little table showing the actual dollars of various cost categories against the quarterly average from 11 in the Q4, et cetera. Bottom line we're down 21%, Q4 to Q2 of '12. And we're down 10% from the first quarter. Good stuff.

Page 7 has the little chart that shows our production and where we think it's going to go versus our debt levels. Our debt is down $40 million from the end of the year. It's down $70 million from the end of the first quarter. We expect it to be roughly flat at the end of the year, assuming we don't make sales. But with the sales, obviously, we will be at a very level on debt. We'll talk about production in terms of the guidance that Paul will handle. But obviously, it's going to start coming off some just because they don't have as many rigs running.

So that's the -- that's kind of a quick summary on the financial end. I'll turn it over to Paul and let him get into some liquidity and into our guidance.

Paul B. Rudnicki

Thanks, Steve. On Slide 9, I'll pickup with the liquidity and derivatives discussion. As you can see at the end of the quarter, we ended with $113 million of cash and $1.1 billion drawn under our line of credit, $750 million of notes outstanding for total debt of $1.86 billion.

Net debt was $1.7 billion and we have a $1.4 billion borrowing base, which leaves us with $400 million of total liquidity including the cash. Our leverage ratio at the end of the quarter, as calculated under our credit facility, was 3.4x. Looking at our derivative position for the rest of this year, we have added some hedges beyond 2012. For 2012, we're hedged at $5.27 on $222 million a day. We've also got 1,500 barrels of oil hedged at $98. You can see we're about 50% hedged on our gas and about 75% hedged on our oil.

Looking in 2013, we've added some calls and some swaps. We're currently swapped at 70 million a day for 2013 at $4.65, and we sold calls at $4.29 on $55 million a day. Looking at our oil position for 2013, we've got 1,000 barrels a day hedged at right at $100, and we've actually sold some calls during the quarter on 2014, 2015 oil for 1,000 barrels a day at $100.

We will continue to evaluate our hedge position as prices have strengthened here. We will be looking at potentially wearing on some more. We can get well over $4 for well over being $0.05 over for a 3-year straight swap, looking at '13, '14, '15, which materially changes the numbers from the $2 that we're realizing today.

Looking at Slide 10 to go over our second quarter guidance that we previously put out versus the actuals. As Steve mentioned and Doug both mentioned, our production in Q2 came in above the high-end of guidance primarily as a result of a general outperformance in our Haynesville wells where we are seeing a much shallower decline than we initially anticipated.

Our LOE and G&A, as mentioned before, came in well below guidance as the financial impact of our major cost reduction initiatives were realized ahead of schedule. The combination of those items and a slightly better average realized price than anticipated resulted in $112 million of EBITDA, which was $11.6 million higher than it previously guided.

Also to highlight is, as we mentioned before, the impact of TGGT's cost reduction initiatives. TGGT's adjusted equity income and adjusted EBITDA came in well above guidance, and that was a result of the higher throughput that we've put through the system. As we -- as our volumes are greater than expected, we show you our net volumes, but TGGT moves the gross volumes associated with those. And TGGT was successful in their cost reduction initiatives as well. You can see that their -- our share of their EBITDA came in at 21.1 million, well above the high end of guidance.

As for the guidance for the remainder of the year, we have raised our production forecast, lowered LOE and G&A, as well as the corresponding effects to our share of TGGT's EBITDA. And again to remind everyone, when we talk about our corporate EBITDA, that does not include any of the effects of TGGT's EBITDA as it is carried as an equity investment.

Production guidance was raised in Q3 and Q4 by $20 million and $10 million a day, and our full year volumes are now expected to be 512 million to 522 million a day as compared to prior guidance of 497 million to 512 million a day. We lowered LOE by 1 million per quarter reflecting the cost reduction initiatives implemented this year.

G&A was also lower by 2 million per quarter also reflecting the cost reduction initiatives implemented. Using $3 gas for Q3 and $3.25 NYMEX prices for Q4 and $90 oil for the remainder of this year compared to prior guidance of $3 and $3.50 and $105 for oil and incorporating all the changes outlined to our guidance, our full year EBITDA guidance is now $457 million as compared to prior guidance of $441 million. We expect to end the year 3.8x levered as calculated under our credit facility.

And finally, looking at our equity income, we've raised the equity income impact from our investments by $5.5 million for Q3 and $3 million for Q4. The increase is attributable to higher throughput than originally expected and lower operating expenses at TGGT. TGGT's EBITDA, net of our 50% interest, was raised by $2.5 million for Q3 and $2 million for Q4. We're now guiding to a full year EBITDA of $150 million for 2012, up from $130 million from our prior guidance. And that again is to 100%.

And with that, I'll hand it over to Hal to talk about the operating side of the business.

Harold L. Hickey

Thank you, Paul. Slide 13 has an overview of the company's assets. I'll point out that based on the June 22 NYMEX strip, we have proved reserves in the corporation of 1.6 Tcfe. Our net acreage is nearly 500,000.

Key focus, as Steve, Doug and Paul have all emphasized, has been on managing our base production and really having a particular focus on all of our costs, LOE, capital and G&A. I'll particularly note that our headcount has gone down on the employee front, from about 1,100 at year end '11 to approximately 960 today.

Our contractor headcount is down even more dramatically. And as Doug said, when you look at the contractors and our employees together, we're down about 300 people from year end to the end of the quarter -- or to today. Big focus in our operating areas of Haynesville/Bossier is on manufacturing in DeSoto Parish with 5 rigs. Our volumes stayed very strong.

In the Marcellus, our focus is on development in Northeast Pennsylvania and appraisal in Central Pennsylvania, which has been particularly encouraging. In the Marcellus, our production is up to 146 million a day on a gross basis from 116 million in the first quarter. Permian, we're continuing our Sugg Ranch Canyon sand development, and we're testing other opportunities there. And in TGGT, our volumes have held pretty steady, but the big focus there is the wrap up of our significant capital program. I'll give you details on all of these areas in a minute.

On Slide 14, you can see that our capital budget is $470 million, which is significantly less than our '11 capital spend and less than what we've actually entered the year thinking we were going to spend. 84% of our capital budget remains dedicated to development, and that 84% entails our drilling and completion in our field operations areas of focus.

Field operations includes activities such as artificial lift and managing our existing assets. I will say that of our rig count, as Steve said, in the Permian, we have 2 today. One of those rigs is focused on the Canyon sands and its development, the second rig we've been using to test other opportunities. And so we'll bounce a little bit between 1 and 2 rig count through the rest of this year as we have to this point.

Appalachia, we're probably going to stay with 1 rig for the remainder of this year and we'll consider ramping that up next year depending on what prices do. In the East Texas and North Louisiana, as we've noted, we have 5 rigs. There's actually a couple of those that go off contract in September. We're not saying we're going to release those at this point in time, but we're going to evaluate what our opportunities are and what gas prices do and make a decision on those 2 rigs here in the next few weeks.

Slide 15, I want to spend a little bit of time on. On the capital, the focus on the drilling and completion cost, Steve noted the detail on how we were targeting 8 million by Q4 and even lower dollars in 2013. But it's really been driven by some strong, strong efforts on our guys' parts. In both the Haynesville and in the Marcellus, we've negotiated with our frac service providers, and they've been very responsive to the current environment. And we've had reductions in our frac service cost in both areas, but we're negotiating reductions on all of our services on our rig operations. And like I said, our contractors has been very responsive.

And our operating expense, we did shut down wells in the first quarter. We've kept them shutdown, particularly in Cotton Valley. And we have initiatives underway to reduce our OpEx 15% to 20%. We've met those targets. Now work-over program, we actually had as many as 11 work-over rigs operating for us last year. We're down to 3 today. We did a lot of work that's allowed us to get to that point. The chemical program, while we've cut the cost, we've also improved it. It's allowing us not have to do with much intervention as we had to before, hence some of the work-over rigs cut back.

A big, big focus that I want to emphasize is always on our company and contract labor. Now we have used technology, we've developed the control room here in Dallas that allows us to every hour look at all of the wells across our Haynesville portfolio. And in turn, we're going to do surveillance -- we've got enhance surveillance, we're doing work on those wells on a more selective basis. And in turn, it's allowed us to keep our base volumes at a higher level than we had originally anticipated. And I will also note that our safety and compliance efforts haven't been compromised at all. We've had an excellent safety record across our portfolio and actually within EXCO, our TRIR or total recordable incident rate is at 0.6, which is literally 50% of what our industry average is.

East Texas/North Louisiana is depicted on Slide 16. We've got over 60,000 net acres with Haynesville Shale, Haynesville and Bossier Shale potential, more than 90% of that acreage is held by production. But we have 346 operated wells, and with our OBO wells, we've participated in more than 525 wells in the Haynesville/Bossier. One point that I really want to emphasize is that as a reduction in activities occur and as our surveillance has taken hold, we've actually brought down our net volume on average that we shut in or curtailed during the first quarter, 72 million a day down to 22 million a day, strong efforts on our people's parts.

The restricted rate program where we typically go up to about an 18/64ths choke as opposed to when we're first drilling and completing in the Haynesville, we're going up to 28 to 30 to even 32/64ths chokes. We're managing our pressures and our drawdown and we think that over time, that's going to enhance our EUR and in fact, it's actually helping maintain the base as we held the pressures up. But base performances being higher than forecast, it's really attributable to a lot of good work on a lot of people's part, with the well surveillance, our control room, we really do well reviews daily.

Last thing I'll talk about on this slide is we do have a good inventory of wells waiting on completion. At the end of June, we had 6 rigs operating. As we noted we're down to 5 today, but we have 37 wells waiting on completion. We'll be working that all. But that's going to allow us to keep our volumes strong through the year.

Going to an Appalachia discussion on Slide 17, we have more than 135,000 net acres with Marcellus Shale potential. About 2/3 of that acreage is HBP. We're currently producing 146 million, and we've reduced our rig count as we've noted. We do have about 6 million to 8 million a day shut in, net shut-in volumes in Appalachia as we have some ongoing offset activity. But one of the most exciting things that's occurred up there in the last quarter is in our central area, and you'll it depicted on the map, our 4 wells that we brought on there had average IPs of 7.2 million a day from average laterals between 4,600 and 4,700 feet. So that's something that we're going to take a look at. And we actually may end up drilling some more wells there in the second half of the year than we had originally forecasted based on these results.

And finally, we're doing some similar activities up in Appalachia to enhance our production as we have in the Haynesville, and we're looking at our seasoning time and completion method. We're managing our simultaneous operations, and we're going to drill where we think we have the best opportunities to realize the economic -- good strong economic returns.

And finally, I'll note that we have a good inventory of wells in Appalachia as well that we'll be completing during the year. Again, even with the reduced rig activity, we will still bring in a significant number of wells online.

Slide 18 depicts our non-shale assets. It's a significantly large part of our portfolio, more than 20% of our net production. We are drilling a lot in those, as we noted. As always, we're only drilling in the Permian area there, as always, over the last couple of years. We're waiting on prices to go back up, and there will be some drilling locations that we can bring about when prices recover. We're negotiating a joint venture opportunity with private investors in this portfolio, and Doug will update us on that.

Slide 19 depicts Permian Basin, and you can see on the map there, the yellow depicts the acreage that we currently hold. That's more than 25,000 acres depicted right there. Now that's where we're doing the bulk of our Canyon Sands, or all of our Canyon sands development. But right in that area, we're testing Cline and Wolfcamp opportunities. We've drilled, I think, 4 vertical wells at this point. We've taken core samples. We're analyzing that and will evaluate if we want to drill the horizontal well in this part of our portfolio later this year.

The waterflood has been very successful. It's doing just as we had forecast. We've seen well up to 470 barrels of oil a day during the last week, and the forecast EUR of 875 is going to be moving into the proved reserve category as we realize the results that we had hope for. We still have a really good cash margin out here.

Now one more thing before I get off of this page is on the map, you can see that both -- that to the South, the West, to the North of our acreage, there's some active horizontal drilling in both the Cline and the Wolfcamp. We're encouraged by results that we're seeing from our competitors, but we're also encouraged by the results we're seeing from some of our vertical testing in core. So standby for news on that.

The last slide I'll talk about is on Page 20, TGGT. We have current throughputs approximately 1.5 Bcf a day. We've done a good focus on cost control here, and we're looking at an annualized EBITDA run rate based on our most recent months of around $150 million. And of course, EXCO share would be half of that. The EBITDA is up 22% from the first quarter. All of our capital programs are being funded from a combination of cash flow and debt. We haven't had any drawdowns of late. I don't see that we foresee any additional debt drawdowns in the immediate future. And we are working with an -- our equity partner to evaluate the sale of the interest here.

With that, I will turn it back over to Mr. Miller, who will open it up for questions and answers.

Douglas H. Miller

Okay. And as you can kind of see that even though we're in difficult times, we have a lot of people who've been through this before. It was worse than this in the '80s, and the guys that came out of that had liquidity, and there are lot of transactions during the '80s. And so it lasted a lot longer, but we had shallower decline, gas and oil. Both commodities went down at once. I think this is the first time in my history, probably Steve's also, that one commodity crashed and the other one went up. So from a service company standpoint, I think they like it better because as idiots like us quit drilling, there's other guys that are way smarter than us out in the oilfield that will take the rigs.

So I think you can kind of see with the power plants switching from coal to gas in many of the ones that we're in contact with are shutting down coal, and many, many more gas-powered plants coming online here in the next couple of quarters. So they're taking up gas. Many of them have been in here. I don't think many of them are hedged, so a lot of them are looking for long-term contracts. We're also starting to see nat gas go into vehicles. We know it works. Boone has been at the forefront of that. It works in cars, trucks. But I think you're starting to see -- in the oilfield, you're actually seeing people switch drilling rigs to the natural gas, and you're starting to see frac fleet switch to natural gas, too. So a lot of demand in the oil and gas fields for nat gas. It really saves costs, and it works like a charm.

But I think the big thing that everybody is up in over is shipping gas to other countries, at least 1 permit has been approved. I know there's another 10 underway. I think that could begin as early as '15 or '16. Keep in mind, there is real economics in that. We're producing gas like dopes at $3 today. And the Chinese and the Japanese are paying $15 to $18 an Mcf. Now it cost a lot of money to build a plant. It costs a lot of money to get it over there, but the math really does work. And so I think there's a lot of guys talking about -- and I noticed here this last week, India is having a little bit of problem. I think they had half their population without power a couple of days ago because of their grid. But they're a significant buyer also. They're not paying exactly what China and Japan is, but they are paying and looking for a lot of gas.

And I think the other thing, once we get into shortage, either this winter or next winter -- now we do have a lot of import facilities because they were all built because we were the highest user with the highest prices. I don't know a lot of people that will bring LNG to the United States at $3 or $4 or $5 or $6 when there's somebody in China willing to pay them $18. I may be wrong, but I don't see many of those people.

So I think -- and I also don't believe, like a lot of analysts are saying, that now that gas is up to $3.08, that people come rushing back in to drill wells. We have checked our portfolio and checked other people's portfolios, and the economics on the conventional gas across the country, you can't even make a reasonable rate of return until it's north of $6. Some of the shales start turning on at $4 and $5, but not many of them. So people are saying, "If gas goes back to $4, we're going to flood the market with gas." Ain't happening. People are saying, "If gas goes back to $5, we're going to flood the market with gas." It ain't happening. So I think we have a little debate going on here, but I can tell you that the people in the industry that I know will not be moving rigs back in at $4 or $5 or $6.

With that, come I'm going to shut up and turn it over to questions. Matthew?

Question-and-Answer Session

Operator

[Operator Instructions] Your first question comes from the line of Bryan Singer with Goldman Sachs.

Brian Singer - Goldman Sachs Group Inc., Research Division

Looking at your gas production, which was above the top end of the guidance and then kind of the comments that you made in terms of some of the improved well productivity in the Haynesville, when you consider the well productivity gains and your backlog there, does that make sense that your gas production should still fall here over the next couple of quarters?

Douglas H. Miller

Well, the answer is yes. When you have 22 rigs running and you shut it down as fast as we did, it just automatically going to fall. I think our guys are doing everything they can to work the problem. But these things, as you've seen, 70%, 80% first-year decline rate. And even with the choke that we're putting on -- Marcia, what are the first year declines on these things?

Marcia Reeves Simpson

Well, we're running probably about 60%.

Douglas H. Miller

60%. So even with the restricted choke, instead of 80% or 90%, we're still running 60%. So a lot of wells came on here in the last 12 months. And I think you're just seeing that decline and the reduced activity.

Brian Singer - Goldman Sachs Group Inc., Research Division

Yes. And if we look at that strong performance of nat gas during the quarter, would you attribute the bulk of that to the productivity gains, or was there an element of backlog reduction that went into that as well?

Douglas H. Miller

Productivity gains would be #1. Even as we were shutting the rigs down, we've slowed down the fracs. And today, we only have 1 frac crew out there, where 8 months ago we had 4 of them out there. And so we just slowed down the fracs. So we're bringing the wells on slower, which gives us the backlog. But that will be caught up by the end of the year.

Brian Singer - Goldman Sachs Group Inc., Research Division

Okay. And then when we look at your asset sale and acquisition objectives, should we assume that whatever proceeds you may get from some kind of TGGT monetization would be used to acquire gas assets, or do you expect that the net asset sales you're contemplating will ultimately lead to a reduction in your debt?

Douglas H. Miller

I would say reduction in debt. We are looking at deals, have bid on deals. We're looking at both oil and gas. And we're most comfortable bidding on gas in our neighborhood. We have bid on 3 oil deals with a partner, came close on one of them. But I'm still of the opinion that we have -- it's 50-50 up to down on oil. And I'd say we're 2 or 3 to 1 up to down on gas. So we're leaning towards gas. But any asset sale we made today would just reduce.

Brian Singer - Goldman Sachs Group Inc., Research Division

And would that then imply that any acquisition that you do would get funded by some kind of equity or equity infusion, or it would just come out of it -- it would come out of debt or there'll be some additional asset sale?

Douglas H. Miller

No, it depends on the size, Brian. I think if we did -- if we raise $0.5 billion or $1.5 billion and reduce debt, our borrowing base is going to probably be maintained, and our cheapest cost, LIBOR plus 175, is still that. It just depends on the component of PDP and hedgeability. So I'm leaning towards gas. I think most people that are invested in us think of us as a gas company. But we're having some pretty good success out in West Texas, and we have seen some pretty good success and gotten close on a couple of Eagle Ford deals. So we're looking at all, it's just math.

Operator

Your next question comes from the line of William Butler with Stephens.

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

Looking at your restricted cash balance, what is the minimum that, that can go to? Do you anticipate going forward?

Douglas H. Miller

It can go to 0. The restricted cash is really us and BG. That's our next 3 months of operating cost and drilling cost. So if we went to 0 rigs, well, it can't go to 0 because we always have operating, but it can get pretty close.

Paul B. Rudnicki

We're expecting it to be in the $40 million range by year end.

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

And then on the cost cuts -- with the cost cuts you've made so far both on the operating side and the G&A side, how much really left is -- how much is there left in the structure of the company to go down? I know you've all got it in your guidance, I mean, do we think that's kind of the bare minimum as we look at '13 or?

Douglas H. Miller

No, no, no. It just depends on the deals. We have people right now -- we don't want to fire anybody. We just don't want to do that. It hurts, and we don't have any bad people. We have people that are aggressive and working on it. There's a lot of other costs we're cutting, tickets to ballgames and things like that were down. And I mean it's just, we're cutting everything we can. But if gas goes down and we reduce to 0 rigs, there -- we could have another cut. The size of the company is reflected by these commodity prices. We have great assets and great people, and we'd like to keep them coupled. And we have a couple things we're talking about selling, and we got a lot of things that are potential to buy. I think I'd like to buy some things and keep some of these people working. But they -- it has to make sense.

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

May I switch on that, in the Haynesville, who were the net sellers in the Haynesville? The public operators, or there's still plenty of private acreage?

Douglas H. Miller

If I told you, I'd have to kill you.

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

And then last question, on the Marcellus, with your improved results in Central PA, what do we do with that since we're restricted with 1 rig and focusing on Lycoming? I mean, it was good that we put that up, but I mean does that change your plans, or is it still just to...

Douglas H. Miller

Well, I think we're meeting -- yes, I hear you. I think we're meeting, and you'll note that we didn't tell you what county it was in because we don't want any of you guys out running around leasing. There is acreage available. We're working on a couple of plans there, and I think we're going to detail that and see if want to buy any acreage in the neighborhood because the math looks pretty intriguing. And so if we can -- good news about Chesapeake not being in the game much is acreage costs have come down in almost every play across the country. So there is availability. We're looking at that availability. And before we put 4 rigs up there, we're going to make sure our land position is proper.

Harold L. Hickey

I will add, William, that we are evaluating a 4-well development in the Central area that we could drill in the third quarter. I'm not promising we will, but we're looking at that as we speak. So we may remove the rig over there for a brief period of time.

Paul B. Rudnicki

In lieu of other.

Harold L. Hickey

In lieu of other opportunities.

Douglas H. Miller

Yes.

Operator

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

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

Just curious in terms of your bank credit facility. What's your next redetermination date? And you all mentioned you'd be 3.8x levered for the credit facility by the end of the year. What's sort of the max allowable on the facility there?

Douglas H. Miller

4.5x is the covenant and our next redetermination is scheduled to be October. Then we're already in discussions with the bank group.

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

Okay. In terms of the Marcellus, can you give us some color on sort of where well costs are now? Where do you think those are trending to as we get further along in the year?

Harold L. Hickey

Our development well costs are in the $6.3 million to $6.5 million per well range, that’s for drilling and completion, and we're targeting getting down to around $6 million sometime early next year, with aspirations to go below that during the year.

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

Okay. And in terms of your conventional asset sales, just curious in terms of how we should think about that structurally. Would you guys like to potentially divest all of your conventional assets where you wouldn't own anything, or would you want to sell an interest, or is it kind of early to say what type of structure that might take?

Douglas H. Miller

Well, we're looking at -- it's called -- I'm calling it kind of a sidecar private MLP where it will be structured like an MLP, where we've maintained an ownership, we operated it, and had distributions. I think everybody is intrigued with that. Many private equity guys have shown interest. We've had an offer or 2, we have it out with 4 or 5 people, and we'll be getting those back in. And hopefully there's a transaction, but nothing can be assured.

Operator

Your next question comes from the line of Subash Chandra with Jefferies.

Subash Chandra - Jefferies & Company, Inc., Research Division

On TGGT, so the net was up quite a bit. The throughput was up, I guess. It was flat overall and your equity throughput was up. I'm just curious, some more color on how you were able to squeeze so much more out of the cost line and the outlook for that? And if you have the TGGT Q2 revenue number handy?

Paul B. Rudnicki

I don't think I have TGGT in front of me, Subash. I can follow-up with you on that. The bottom line is, when you've got an organization that for a year has been scrambling to reinstall, rebuild facilities from our incident last year, just like when we're running with 30 rigs on the corporate side, it's the focus of the organization. And once that got done in the beginning of the second quarter, we started looking hard at costs and seeing where we're going to be more effective. So as compared to guidance, prior guidance, the revenues are higher than we anticipated because of the flatter EXCO throughput. But most of the -- a lot of the deed is going to be related to the cost side.

Harold L. Hickey

And I will add that we've had a significant reduction contract labor there as well, similar to what we did in the upstream. We've had some cuts in the employee headcount as well.

Paul B. Rudnicki

And to kind of follow up on that, it's also -- we staffed up to build a couple hundred million dollars a year of projects, and those are all behind us.

Douglas H. Miller

And I think you can figure out what the revenue is. We were running 1.5 Bcf average throughput through there a day, and we probably averaged $3.

Subash Chandra - Jefferies & Company, Inc., Research Division

Yes. I guess I'm trying to understand how more equity revenues, probably dumb question, but how more equity throughput increases your revenue. So do you -- you just charge more for equity?

Stephen F. Smith

No. It's a contract.

Paul B. Rudnicki

It's simple math, more volumes at the same rate equal more revenues.

Harold L. Hickey

The bulk of the TGGT's revenues come from the gathering, trading, transportation, et cetera, that we charge. EXCO is an arms-length organization.

Paul B. Rudnicki

It's the same rate we charge any third party...

Douglas H. Miller

Yes, we have other operators on the system and they get charged the same thing we do. It is a standalone animal.

Subash Chandra - Jefferies & Company, Inc., Research Division

Right. But in Q1, wasn't throughput around 1.5 Bcf, too, or do I have the wrong number there?

Stephen F. Smith

No, it was, right at it.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay, I'll just follow up later. And then -- so in the contractors, do they show up in lifting costs or G&A costs?

Stephen F. Smith

EXCO contractors?

Subash Chandra - Jefferies & Company, Inc., Research Division

Yes.

Harold L. Hickey

Depends on type of contractors.

Douglas H. Miller

I mean they are all over the place. We could have IT contractors in G&A and we have well head contractors that are in LOE.

Paul B. Rudnicki

And some in capital.

Douglas H. Miller

And some in capital.

Subash Chandra - Jefferies & Company, Inc., Research Division

Okay. In the Marcellus, do you expect -- I think you said earlier in your public comments that you expected growth. And I'm just reading, I guess, the ops update. What are your latest thoughts on how many wells you want to complete out there this year?

Harold L. Hickey

We're still sticking with the original budget plan that's noted in the press release, so that could alter. I think we put some language in the press release that we're evaluating that as we speak, and it could change our activity levels as such. But right now, our target remains to drill 49 gross wells, that's 12.4 net. We’d complete them. So we'll complete on the order of about 40 wells this year.

Douglas H. Miller

That ain't going to move the needle.

Operator

Your next question comes from the line of Michael Hall with Robert W. Baird.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

I guess first on my end, on the TGGT side, do you have an estimate or current thinking on what, let's say, next 12-months EBITDA will look like at an exit rate basis from 2012? So I guess what '13 EBITDA will look like based on the new cost improvements year-to-date?

Paul B. Rudnicki

Yes, I mean, we're expecting fourth quarter EBITDA kind of annualize based on the guidance at about $140 million. And I think that as we've kind of said, going back to some prior questions too about the difference in production and is that going to change your forecast, what's happening to us is our -- we're going to bottom out in our decline rate sooner rather than later. And as we've kind of talked about early on that if you look at our fourth quarter, generally speaking annualized, that's a pretty decent look at '13, all things being equal and subject to change.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Right. So are the declines material enough to meaningfully impact that EBITDA rate that you're thinking currently?

Douglas H. Miller

No.

Paul B. Rudnicki

No, we're not -- what I'm saying is I think basically the fourth quarter volumes are reflective of what the bottoming out in our decline and our current capital expectations would do for us in '13. And so that all translates right back into TGGT.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Okay. And then as it relates to the sale of that asset, can you provide any color around maybe how conversations evolved with BG and the thinking of the sale there? And how that maybe helped move the process into a more formal type status?

Douglas H. Miller

I think they're totally onboard, we're in communication with them on a daily basis, and everybody’s aligned on that.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Okay. And then in Haynesville, what are current returns looking like on that $8 million well target current stroke?

Douglas H. Miller

Right on 20%, which is about our minimum. So they keep showing me 20%. So it looks like that's it. We’d rather have 40%.

Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division

Sure. All right. Then last one on my end is just any indications yet from the bank group what the price tag might look in that following determination?

Douglas H. Miller

Well, we've had discussions and then course with 20 banks in there, they’re kind of -- we have heard maybe $3 for next year, but then we've heard from other ones $3.50 for it so I'm kind of guessing that they're going to settle in, if nothing changes, at $3.50 for next year going up a quarter to $0.50 a year to at top of $4.50. That's kind of the indications we're getting. But again, I think they're all evaluating it. I think coming in 3 months ago, if you'd ask, they are going down. And today, they're looking at maintaining. Is that right Paul?

Paul B. Rudnicki

That's what we have -- that's what we believe.

Douglas H. Miller

We haven't talked to him since yesterday, so that's pretty current.

Operator

Your next question comes from the line of Raymond Pirrello with Pendulum Capital Markets.

Raymond Pirrello

Last quarter, you guys made a statement that the sale of the TGGT pipeline will bring in about $500 million to $700 million to EXCO. With the recent change in the price of natural gas, do you see that valuation coming up some more or?

Douglas H. Miller

I'm not ready to say that yet, Ray. That was for our 1/2 interest, I think that was a target. And we were in this negotiations and discussions where -- and one of the parties was in that range for 1/2 interest. Part of the thing we're evaluating is 100% or 50%. And I think you can stick with that range. But I've been told to quit predicting, so I'm not predicting anymore. We're not winning the Super Bowl this year.

Raymond Pirrello

All right. Well last year, you guys offered $18.50 a share for the company to take a private. Based on the valuation of natural gas last year, the levels at where they were and also the assets of EXCO, you guys made the decision in that price. Where do you see that valuation today for the price of EXCO? I mean, if there was to be the same multiple used then today, where would you put the price of EXCO on a pegging private number?

Douglas H. Miller

It would be lower. But I haven't looked at it. I think back then, we're -- the forward curve got up to $5.50. I think the forward curve is $4.50 right now, and that has a lot to do with it. So capital budgets back then were faster. Capital budgets today are slower. I'm not going to sit here and predict numbers, but it's lower than $18.50. But it's purely price. The assets haven't gone anywhere. We're just differing drilling.

Raymond Pirrello

Okay. In terms of the daily activity of the company, what has Wilbur Ross’ activity been in terms of the bid activity of the company and/or these negotiations with these projects?

Douglas H. Miller

He comes in every morning early and gets lunches for everybody and leaves late. Wilbur is on the board. He is a large shareholder. We have a lot of dialogue with him. He helps us. He's a smart guy. We met with him in New York last week. He's got ideas. He's got suggestions. He's been through this before, and he's somebody that we talk to 3 or 4 times a week. But from an activity standpoint, he got into this because he thinks gas -- he wanted to be a consolidator of gas. He loves the idea of us acquiring more gas. And as we look at deals, we run them by him. And so far, we're totally aligned and trying to do the same thing he is.

Operator

Your next question comes from the line of Brad Pattarozzi with Tudor, Pickering, Holt.

Brad Pattarozzi - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

With the Marcellus acreage 2/3 held by production and going down to 1 rig currently, how long can you stay at 1 rig and still hold all your acreage?

Douglas H. Miller

Well, 2 things. We're evaluating -- we don't have to hold our acreage, let's start with that. We're looking at acreage that expires in the next couple of years, and we have options to renew. And with acreage costs going down, if it's marginal, then we'll let it expire because we can lease it cheaper. All those are underway. Just because acreage -- just because it's not held, doesn't mean you can't let it go.

Brad Pattarozzi - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Any focus on which area, central versus northeast, you would prefer to keep?

Douglas H. Miller

We prefer to keep both, but I'd say that both areas have spots where we're looking at leasing more and will ensure HBP. And we're in good shape on the key areas.

Brad Pattarozzi - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. And going to your commentary earlier on kind of gas prices in the current market and what basins are economic or not, where would you need to see gas price to go back to 3 rigs in the Marcellus?

Douglas H. Miller

Well, we're having meetings on that right now. I think where our acreage is, we probably need $4. If we were Cabot, we'd only need $2.50.

Brad Pattarozzi - Tudor, Pickering, Holt & Co. Securities, Inc., Research Division

Okay. And then lastly on the Marcellus, you had some issues lately with the drought in the Northeast. Any operational hiccups on your end?

Douglas H. Miller

No.

Harold L. Hickey

No, not any impact at all from excess water.

Douglas H. Miller

We spent a lot of time and a lot of effort and a lot of money over the last 3 years insuring our water supply and our water disposal. And so we're in great shape.

Operator

The next question comes from the line Nathan Weiss with Unit Economics.

Nathan Weiss

A couple of questions regarding production and the productivity enhancements. First, it looks like you actually revised up last quarter's gas production by a little over 4 million a day. Is that correct?

Paul B. Rudnicki

It's the effect of the NGL breakout in our Permian.

Nathan Weiss

Okay. But the total production number, both from the Qs and the slideshow actually went up from what you reported in the second quarter.

Paul B. Rudnicki

I mean we are, on a non-equivalent basis, reporting a little more volume because we are reporting the NGLs.

Nathan Weiss

Okay. Secondly, can you talk about your backlog of uncompleted wells from the end of the first quarter to the end of second quarter?

Douglas H. Miller

I think we have it on the chart, Nathan. Did you miss the call?

Nathan Weiss

No, I was sitting here. It's actually pretty entertaining but...

Douglas H. Miller

Okay, it's in there. You have it on the tip of your tongue. We'll point you to the right slide.

Nathan Weiss

I mean, you show on the Appalachia like on 17, but you actually...

Douglas H. Miller

You're talking about wells, drills and not completed? I think we have 37 in the Haynesville and how many we have in Appalachia?

Harold L. Hickey

28.

Douglas H. Miller

28.

Harold L. Hickey

As of June 30.

Douglas H. Miller

Yes, as of June 30.

Harold L. Hickey

And we did one...

Nathan Weiss

In the first quarter call, you actually -- or in the slide show, you only show the Appalachia breakout you don't show the...

Douglas H. Miller

The first quarter, well I don't have all my slides from the first quarter. This is now the second quarter.

Harold L. Hickey

Similar number.

Nathan Weiss

Understand. Just trying to change from first quarter to...

Douglas H. Miller

Got you, got you.

Harold L. Hickey

We can get that.

Douglas H. Miller

We'll get it back to you. I can't remember. I'll say probably it was less because we had more rigs, and we -- I think we had 2 frac fleets working. Same thing in the Haynesville, I think we were 4 going to 3 frac fleets. So the wells that are waiting on completion is a product of frac fleets. And we only have 1 in each area working. We'll get back to you on that. Do I have your phone number?

Nathan Weiss

Sure.

Douglas H. Miller

Okay.

Nathan Weiss

I can shoot you an e-mail.

Douglas H. Miller

I don't think I've ever called you back.

Nathan Weiss

I think we've talked a couple of times, actually, but..

Douglas H. Miller

No, I'm kidding, I'm kidding.

Nathan Weiss

And then last question, looking at curtailments, I mean, you went to 72 -- or to 22 million sequentially. So the underlying production increase, the 13 that you reported was net of that $50 million?

Douglas H. Miller

Yes, yes. And that's a product of slowing down activity. As we're drilling more wells and have more frac leads, we shut in the offset production. And so our guys have done a good job but most importantly, our activity goes down, we don't have as many shut-ins.

Paul B. Rudnicki

Keep in mind our guidance -- original guidance for Q2 embedded in that was about -- was 20 million to 25 million a day of net shut-ins. So the 22 million that we reported was right in line with what we expected. So the outperformance is not because of a reduced volume shut-in, it is purely the wells are performing materially better than we initially anticipated.

Operator

Your next question comes from the line of Anne Cameron with BNP Paribas.

Anne Cameron - BNP Paribas, Research Division

Just a question on the restricted choke, the new restricted choke, the 18/64th. Can you quantify what that does to your tight curve and the sort of the first and the second year decline?

Douglas H. Miller

I thought you'd never ask. Are you still playing softball?

Anne Cameron - BNP Paribas, Research Division

I am.

Douglas H. Miller

Okay. Marcia, can you answer her question?

Marcia Reeves Simpson

Well, I mean the intent there is -- on the restriction is to write in the initial -- the IP, so we're bringing those down at a starting point to around 11 million, 12 million a day and that affects then the initial decline. It flattens out mainly affecting years 2, 3 and 4. So I don't have the number in front of me exactly, but it does flatten out the curve and therefore, we're getting a little higher EURs as a result of that.

Douglas H. Miller

No, I mean, operationally -- Mike, we're leaving the pressure out more so it's staying open longer. Is that right?

Michael R. Chambers

That's correct, higher pressure.

Douglas H. Miller

Yes. So it's keeping the pressure higher longer in those fractures, and I think the idea is we're getting slightly more gas out even at a slower rate.

Anne Cameron - BNP Paribas, Research Division

Okay. And so from the first month to, let's say the 12 month, what do you think that decline is?

Marcia Reeves Simpson

What we were saying is like 50% to 60% from the beginning of the year to the end of the year. And what we had before was a completely different profile, where we're -- I'm paying at 20 million a day. The initial month decline was -- the first month decline was 90-some percent flattened out, it will be a factor of point A to [indiscernible] so it's a completely different profile, much flatter. And as I mentioned, we really believe it's a result of keeping the conduits and the reservoir open longer by keeping the pressure from -- flatter through that profile in the reservoir, keeping it open longer.

Douglas H. Miller

Anne, I think the thing that I look at is from present value standpoint, the crossover from our old way to this way -- Marcia, when do we produce the same amount of gas as we did the old way?

Marcia Reeves Simpson

Well we're looking at slightly 1 year to 1.5 year.

Douglas H. Miller

Like between 12 and 18 months, we're producing the same amount of gas. But with the new one, our -- the production rate after crossover is significantly higher. Is that right?

Marcia Reeves Simpson

Yes. So what we're saying is the higher rates in years 2 and 3 as a result of this and therefore, propping up that base production.

Anne Cameron - BNP Paribas, Research Division

Okay, got it.

Douglas H. Miller

Did we answer it, did we answer it?

Anne Cameron - BNP Paribas, Research Division

Yes, yes, yes, you did. I think I can work with that. And then the second question is about the cost in the Haynesville. From your reduction down to about 8, how much of that, say from 9.5, is service cost coming down? And how much of it is efficiency gains? And I guess sort of coupled with that, how much -- what's really happened to your cycle time like your spud-to-spud between wells?

Douglas H. Miller

Boy, you hit it one right down, right up the middle for Harold. Harold, take it.

Harold L. Hickey

Okay. On the cost side, really there's a -- the function -- the cost reduction efforts are really a function of changes -- in design changes that we've made [indiscernible] changes in procedure in terms of our 2-bit procedure and then obviously, the market adjustment. So in trying to take a look at that to say, "Okay, what is controllable from a standpoint of design specifications?" I would say, "2/3 of that number that we've realized to date are things that are controllable to the changes, procedural changes and design changes." So let's say about 2/3 of that reduction is truly on our side.

Douglas H. Miller

And then the rest of it is rig and mostly frac fleets.

Harold L. Hickey

Correct. And I will add that about 1 year ago or so, our spud to rig release time was probably 40 to 42 days. The last 16 wells our guys have drilled, the spud-to-rig release time is 35 days. So we're seeing some definite improvement in our drilling efficiency.

Douglas H. Miller

That's significant savings because I think we look at that on a daily full, about 60,000 a day. So everyday, we save on that average of 60,000, even though the contract drill -- the rig is only 20 of it.

Operator

Your next question comes from the line of David Neuhauser with Livermore Partners.

David Neuhauser

I wanted to kind of touch on what you mentioned earlier regarding a large shareholder who were saying there's a -- there's still a substantial disconnect in the current equity price based on the bounce in price of gas from Q2. So I kind of want to touch on, I think, what's management's view and the board as far as the cost of that?

Douglas H. Miller

Well, I mean I think a little bit of it is a result of not doing the go private. So we have a lot of [indiscernible] on it. We've got a lot of new guys coming in shorting it. We've got up to 35 million shares short. So that's an extra 35 million shares we're lugging around as that goes. And we're having to take a lot of bullets out there. The guys that are short keep spreading rumors -- we're going bankrupt next week, so I don't like it, but we don't have time to really battle the battle. So -- and being a gas producer has been like producing poison for the last 6 to 12 months. And so what, okay. But I don't know, I think it's a product of all of it.

David Neuhauser

Okay. And then going forward, I know, obviously there's a bunch of balls in that air as far as what kind of acquisition on potential properties and opportunities, as well at the same time monetization of some of the assets to help either alleviate debt or use that cash for other purposes. I mean, are you looking at maybe helping provide further clarity to the business model as we go into this end of the year here? And with those proceeds, if you don't find the right opportunity for maybe an acquisition, is there any potential to either look to buy shares back or special dividends, things that help sort of create the confidence in the business plan going forward?

Douglas H. Miller

You sound like you're a board member. The answer is -- let's make it clear. For the last 30 years, we've been an acquisition and development-type company. We have bought over $10 billion worth of assets over the last 7 years. We've created a team that has been very instrumental and involved in the shale opportunities that now exist. So we're changing on the run, but if we were to sell assets and can't make any significant acquisition and we have to be disciplined at that, and the reason I say you sound like a board member, we have a lot of guys that want to buy stock, and we have a lot of guys that have had discussions around special dividends. So all of that's on the table. But being clear about what the company is, I think we are clear. We're a gas company first and foremost, and we've got a team set up to look at and acquire additional assets, and we do have experience out in the oil areas, and we're not afraid of bidding on them. But I think -- think of us as a gas company in spite of being bad.

David Neuhauser

And then just my last question. I know there's a lot of -- again, a lot of things going on. But if you look out the next 2 years, and not just 2013, which I think is still going to be somewhat challenging, well let's say 2014, '15, '16, and prices are within the ballpark of where they are today. I mean, how do you look or envision EXCO -- the type of company EXCO will be a few years down the road? Will you be -- I know you're doing a lot of rationalization on the cost side. So are you attempting to become lean and mean so that 3, 4 years down the road, you're this extremely strong, powerful company? Or what's sort of your view looking at the company several years out? What do you want to -- what do you envision?

Douglas H. Miller

We're pretty lean and mean right now. We're just getting old. But I would say if gas is $3.50 3, 4, 5 years from now, we've made a mistake. But we will have acquired a lot, and we will have hedged a lot and the world would have come to an end because China -- as long as China is paying what they're paying and Japan is paying what they're paying, gas ain't going to be $3.50. But if it is, we will be making acquisition and hedging them and be fine. We just won't be drilling.

Operator

[Operator Instructions] Your next question comes from the line of Geoff Hulme with Porter Orlin.

Geoffrey Hulme - Porter Orlin, LLC

Just a follow-up on Page 16. The -- what kind of time frame or backlog does that 37 wells waiting on completion? You said it's a function of a frac availability or frac contracting. So when you slow it down, how long does it take to bring that on? And does that give you some kind of low cost -- low overhead costs production growth as you bring those on?

Douglas H. Miller

Hal, do you want to -- I mean, I think that that's a product of having 5 rigs running and only 1 frac fleet and being able to time it.

Harold L. Hickey

It's an upside for us to have this on our books. When we complete these, we will move them into the proved category, and we'll probably bring some 28 to 35 of those on this year. We don't have any problem with our frac fleets. We've got one under long-term contract. So we're methodically going through and developing units, and it's manufacturing mode and as these units are developed, then we move into frac fleet. And it's all scheduled, and this is something that we'll work off very methodically and...

Douglas H. Miller

Yes. The way I look at it is each one of those, we've already spent $6.5 million. And they're not in PDP. And we're scheduling $1.5 million frac job. Each one of those, we spent another $1.5 million to bring them into PDP and significant production. I mean -- I think the way their booked is proved behind pipe in the Haynesville and as we bring them on, they go into PDP. And it's just a timing and scheduling, and we're able to save costs as we do it.

Harold L. Hickey

It's under our control.

Douglas H. Miller

Yes. Each one of those is going to get approximately an 11-stage frac, and it's going to take how long, Harold, each frac?

Harold L. Hickey

For a 4-day job, we're looking at 4 to 5 days, typically 4 days. We're just running daylight operation from the frac which was -- that's what we're doing right now.

Douglas H. Miller

Yes. When we were going crazy, Geoff, we had 2 of the 4 that we’re working 24/7. And so right now, we're just working daylight. It's safer, but it's a little slower, and we're not in a hurry to put gas on at $2.14 or whatever it is.

Operator

Your next question comes from the line of Amine Benali with Manulife Asset Management.

Amine Benali - Manulife Asset Management Limited

At the end of your call, you made a statement that people might be worried that if gas price was to be $4, $5 that -- in your words, we might flood the market with gas. And I think you're referring to the industry. I wanted to ask more about your insight or what gives you confidence that, that is not going to happen? And that's the only question I have.

Douglas H. Miller

Okay. The main thing is we look across our asset base, which is pretty common. We have Cotton Valley, we probably have 1,500 development locations in there that we've taken out of the proved category and move them to probable and possible. At current costs, that takes between $6 and $6.50 to make an economic return. So we're not going to drill it. And we happen to know 50 other operators in the neighborhood that will not be drilling them also because the economics -- we could actually go to the Bakken if we were in the heart of it, which we're not, and we're not going. But those rate of returns are probably 70%, 80% up there. And so if Chesapeake or XTO or one of those guys, if they have x amount of capital to spend, I think they would logically look at what's my highest rate of return and let's spend the capital there. But if you go to the Rockies, you go to Appalachia, you go to West Texas, you go to the Barnett and look at what kind of -- what price gas do you need to move rigs in and begin developing again, 90% of the assets out there take somewhere between 5 and 8. I mean we have areas in the Haynesville where we won't drill unless gas gets to 8. So which means it's totally off the table right now. But I think there's very few areas of this country that are pure gas where people will drill under $4, $5.

Paul B. Rudnicki

And you have look at the operators, too. In fact, to Doug's point, just because the Basin might start becoming economic at a certain level, you have to look at who the operators are and what their other capital allocation could be. And so unless oil gets below 60 and in some places maybe 80, there are better returns that's still going to be on the oil plays that most companies have either leased up and so now they have the same drill hole -- on the oil plays as they did on the gas or it's just pure economics...

Douglas H. Miller

We've just gone through a period where there are 3 or 4 operators that had 50 to 180 rigs running that weren't drilling them based on economics. They were drilling based on whole acreage. And I think they've all slowed down now because acreage costs are coming down, so I think you're going to get a more disciplined industry allocating their capital to making rates of return. I can't even believe that's going to happen.

Amine Benali - Manulife Asset Management Limited

No, I appreciate that. So as we're watching the gas rig count collapse and hopefully dip below 500, then we can take comfort and maybe some of that is sustainable, or at least some of that...

Douglas H. Miller

No, no. I think that's right. And I think we can debate when gas is going to start going up. And our opinion when we were going private it was going to be a 3- or 4-year period, but I can't expect the gas to go to 3. Since it's done to 2 and below, you've seen reports of some of the largest operators, including somebody like Encana and Chevron and some of those guys say, "We're not drilling dry gas anymore until further notice." Once they move out of those areas, they usually don't come back in a week or 2.

Operator

We have no further questions at this time. I'll turn the call back over to our presenters for any closing remarks.

Douglas H. Miller

Okay, thanks, Matthew. I appreciate everybody being on the call. I hope we answered all questions. I think we have 1 or 2 to get back to -- Nathan, I got that one. And we appreciate everybody. Our noses are down and our butts are up. We're working hard as we can, and we're looking at costs. You can see a product of the work the first half of the year. We'll continue to look at costs. Everybody here is working as hard as they can in a really, really tough gas environment. And I think the fruits of our labor you'll be seeing by the end of the year. Thanks, everybody. Bye.

Operator

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

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