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EXCO Resources (NYSE:XCO)

Q4 2012 Earnings Call

February 21, 2013 10:00 am ET

Executives

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

J. Douglas Ramsey - Treasurer and Vice President of Finance

John D. Jacobi - Vice President of Business Development and Marketing

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

Harold L. Hickey - Chief Operating Officer and Vice President

Mark E. Wilson - Chief Accounting Officer, Vice President and Controller

Marcia Reeves Simpson - Vice President of Engineering

Analysts

Brian Singer - Goldman Sachs Group Inc., Research Division

David Neuhauser

Howard Henick

Mario Barraza - Tuohy Brothers Investment Research, Inc.

Operator

Good morning, my name is Brad, and I will be your conference operator today. At this time, I would like to welcome everyone to the Fourth Quarter and Year-End Earnings Release Conference Call. [Operator Instructions] Chairman, Doug Miller, you may begin your conference.

Douglas H. Miller

Thank you very much. Welcome, everybody, to our call. We have approximately 12 in here today, so we're prepared for any and all questions. Before I get started, Doug, why don't you read what you are supposed to read?

J. Douglas Ramsey

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

The statements that may be made on this conference call regarding future financial and operational plans, projections, structure, results, business strategies, market prices and 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 the cautionary information set forth in our most recent Form 10-K, Form 10-Q and other SEC filings, which are available on our website at www.excoresources.com.

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

Douglas H. Miller

Thanks. That seems to be getting longer. Well, welcome everybody, and this call will go over last year and the fourth quarter, but I think as part of it we're going to start giving you a couple of hints on going forward. It was a tough year. Weathering the storm is getting tiresome. But I would say that our group did a spectacular job in an environment that really wasn't a lot of fun. Gas prices got down below $2 last year. We had to shrink. We're a gas company. We're over 95% gas, have been. We'll discuss if we, probably, will be going forward. But everybody around here work together. We were able to cut our capital program as the year went by. We had to cut a lot of people, which is the worst part of this whole thing. We worked within cash flow. We actually paid down a little debt. We spent a lot of time working on a couple of transactions, one of which is closed, pipeline is underway. So anyhow, we have plenty of dry powder, and we'll talk about our plan here in a little while.

Just a few bullets. We cut capital 48%. It's a challenge going from 30-something rigs to 5 rigs but Mike and Harold and their group did it, and we've been doing a pretty good job on that. But at the same time, they were actually able to cut our costs per well, significantly. We'll get into that in a minute. And despite of that, we actually had some pretty good production results, considering we were crash diving with moving rigs out. They did a great job, we averaged 519, I think, for the year; 477 for the quarter. I think we forecast maybe lower than that. I think, it came in slightly better. Haynesville cost down to 8, and I think Harold, actually, would like to bet you he can get it under that. Marcellus, we've had some recent decent success. We're going to be doing a consolidation up there. I'll let Hal talk about that a little later. I think that's going to be a significant asset for us going forward, and there's going to be a significant focus on that going forward.

Over on Slide 4. We just recently had a special board meeting. We've been working on a business strategy here pretty significantly for the last 6, 8 months. We had a special board meeting 2 weeks ago. The board approved it. It is a very significant plan. It is a plan that excels and helps shareholders, everybody, if gas stays cheap. So it's a model but it will include significant acquisitions. We've had 40 or 50 people around here over the last of months evaluating all areas of North America, even. We actually looked at some Canadian shales. We're going to target 4 or 5 of them. And yes, we're working on several deals as we speak. We probably had 15, 20 partners come to us, including foreigners from Japan and China, et cetera. You just wouldn't believe some of the things that are going on, on people wanting to buy gas. Now, obviously, they're not getting a lot of transactions done, but we're looking at a lot of things including companies, including assets, including areas. We're looking for production as part of the deal. If it has some oil with it, we have modeled and worked -- working on moving some rigs to work over there. So it isn't 100% gas we're looking at, there are some oil plays that we're interested in, eagle Ford in West Texas, specifically. I think our guys have gotten our arms around the areas. Expect us to start drilling out near our Sugg Ranch. We have done some studies, pouring in seismic out there, on an area that have some Wolfcamp potential and some Cline potential. So I would expect that we would have a rig running there by the end of the first quarter, and hopefully, we'll have some decent results. There's been some really good results out in the neighborhood with some other operators. So we think we're in a pretty good spot. Again, we're going to keep managing our capital spending. The board approved only $273 million. We would not go up on that unless we have additional cash flow, but we do have the ability to go down if prices come down some and we have done that in the past, and we will continue to do that.

We finally closed our JV with Harbinger. I know we talked about it. It took us quite a bit of extra time. There was a lot of approvals that we had to get, but it is done. Probably, it took us 3 months longer than we expected. Done, closed and first acquisition signed up. We're actually in that partnership. We're going to buy BG's interest in the Cotton Valley, which I guess is 20 million or 30 million a day, $132 million deal. We kind of expect that everything is signed, sealed and delivered sometime early March, is that right?

Unknown Executive

Yes.

Douglas H. Miller

With that, we'll keep maintaining a significant hedge program. I think, the partnership is hedged at roughly 80% for the first year on its gas. So we're locking in some stuff there. The idea here is to buy conventional assets. As we look at companies and significant assets and some of the shale plays, a lot of times, there are conventional assets that come along, it's a perfect area for them. So we're going to try to grow that, all the interests are aligned. We have 25% of the LP units and 50% of the GP. We have a team down there that's looking for deals. But I would say that about 10% or 20% of the deals we're looking at today, John, help me, have conventional assets that fits the partnership.

John D. Jacobi

Yes, or at least 25% of each one them.

Douglas H. Miller

Yes, yes. So with that, I'm sure that we're going to get a lot of questions with that. Let's go over the company. I'll turn it over to Steve right now.

Stephen F. Smith

Let's go to Slide 6 and we'll talk about the year quickly. First, it was a year of gas price, was the big story, where our gas price year-over-year was down 30%. In any business, when you have that kind of a decline in your book, essentially, it's your only product that's a -- that makes it -- makes for a difficult year. On the other hand, we did our guidance. Year-over-year was up slightly, and we had guided in the fourth quarter, to 465 million a day, we got to 477. For the year, for next year, obviously, we're going to have some -- we'll have a decline in production because of the partnership, but also just natural declines in the Haynesville and in the Marcellus. And we'll talk about that in a second when we get to guidance. So revenues were -- after cash settlements from hedges, were down 16% year-over-year. So the hedge program obviously helped. Our operating costs were down 11% on a unit basis and our G&A was down 24%. So we made a lot of progress and it's -- we -- I think that we're very proud of our group to accomplish what we've accomplished. In our guidance on adjusted EBITDA for the fourth quarter, we were right -- nearly right on. I think we're 1.6% less than what we have guided toward. And net income, adjusted net income was $0.17 for the quarter, which also beat what the Street was estimating. So all in all, a good year, a good quarter, given the price that we're having, the work with and the problems that result from that price.

Let's go to Slide 7. It's just a brief summary of the partnership transaction. This is -- it was $725 million property. A group of properties, the cashed to us was $573 million in the closing. As Doug said, we own 1/4 of the partnership and 1/2 of the general partner. We expect to make -- continue to make a lot of acquisitions of conventional assets in this entity and that's the whole reason that we set it up. If you look down -- there's a little table down at the bottom here that just shows the pro forma impact. The way we account for this is on a proportionate consolidation basis. So if you look at this, it's just kind of pro forma of 2012, our historical numbers, less the partnership, that's the 8H on the partnership, and then add back our 25.5% share, and that's the way that the numbers will work. Now after the end of the year, of course, is when we closed this, we closed it actually on February 14, effective February 14. And at the same time, signed a purchase and sale agreement with BG Group to acquire their share of our Cotton Valley, share of Cotton Valley assets in East Texas, North Louisiana, EMI. So that will be taking place, hopefully, by the 5th of March and the BG properties, I think, actually, will -- I think they add about 23 million a day, taking into account just the fourth quarter production. I think, overall, projection for the year is somewhere around 20 or about that. So it was a -- the BG transaction was a good transaction for the partnership. It just increased our interest in the very same wells that we already own in the partnership, so it was an accretive deal.

On Page 8, when we talk about our liquidity, as you can see, we've got at the year end, we were at $1.1 billion on our bank debt. That's down to $534 million as of February 19, for a total debt, companywide, of $1.3 billion versus $1.9 billion where we were at the end of the year. We have about $445 million of borrowing capacity plus cash and less the letters of credit. I've got the partnership column over there as well. This is the closing balance sheet of the partnership. We will be increasing the bank borrowing base to account for the acquisition, a portion of the acquisition of the BG properties, and so we would expect that to increase up to around $470 million after -- when we close that particular one. We do not guarantee, as EXCO, the debt of the partnership, nor do they guarantee or any way have any pledge toward our debt. So it's a standalone deal.

Hedging on page 9. We have about 44% of our 2013 estimated production swapped, not counting anything in the partnership. The partnership right now, as Doug said, is up around 80% of gas and more than 80% of oil for '13 and we're adding some hedges. We have added some in the last couple of days and intend to add more. We are well within where we need to be from a banking standpoint on the gas and oil, and then we need a little more hedging on 2014, that will come.

All right, on guidance, Page 10. The fourth quarter, nothing particularly exciting except we did beat production, which is always exciting. We had a bit of a blowout on differential in the Permian, that has now kind of cured itself. I think that differential yesterday was around -- well, yesterday, it was really low but the average for the year, so far, has been about $1.80. So that is getting back in line. We were at the low end of guidance on operating cost, a little bit high on G&A, cash G&A, because we -- there were some severance costs included in that. As I said, on EBITDA, we're just about straight on, just 2% less than what we have guided to, so good quarter.

Our 2013 guidance, the third -- this includes the partnership effective from February 15 on, at a 25%, and then for the first 1.5 months it will be -- it's in there at 100%, of course, on those properties. So the first quarter is anomalous. The second quarter, you start picking up just EXCO without -- and 25% of the partnership versus the full impact of those properties. It looks like, not considering anything having to do with the partnership, it will probably have around a 12% or maybe 14% decline overall in production. We could very well do better than that because a lot of the performance of our wells, our shale wells is certainly surprising to the extent on the upside, but that's kind of what we are guiding towards. On the differentials, as I said, that we fell like that, that problem has been pretty much rectified, and so we've guiding to $5 to $7 a barrel on oil. And so operating expenses, we're kind of, again, holding the line. If prices don't improve, we may be further reducing operating expenses. Gathering is kind of is what it is. It's a little higher in the Haynesville than it is on those conventional assets that move out of here. But we -- I think, we'll be well within those ranges for guidance. So if you look down at the adjusted EBITDA line, we're pretty -- once we get past the first quarter and get the noise out, we're pretty flat at around $70 million of EBITDA per quarter. Our capital budget's at midpoint of $273 million. So we're going to be within cash flow and if -- again, if prices don't improve or deteriorate, then we'll be looking at that capital program further.

The last slide that I have is Page 12. It's just a very rough picture of the partnership for the year '13. We purposely guided a little bit on the low side of this particular side because we got noise, we've got to clean out -- I mean, clean up the purchase price adjustments and all that stuff and then we also had the BG acquisition to be considered. It's not in these numbers. Actually, our budget for this partnership, to be honest, is a little bit higher than our high point of guidance. But we will be adjusting that as we go throughout the year. But -- so that kind of gives you just a good feel for where we are on the partnership for '13. And with that, I'm going to turn it over to Hal Hickey, and he'll deal with the operations.

Harold L. Hickey

Thanks, Steve. I'll begin on Slide 14. And if you look at the map, you can see our 3 core areas that we had at year-end, Appalachia, East Texas, North Louisiana and Permian. Overall EXCO, when you look at our proved reserves on a 12/31 NYMEX pricing case, we had 1.6 Tcfe or about 93% gas. Our net acreage at year-end is about 478,000 and we had 919 employees. I'll say that was down from nearly 1,100 a year ago. We're actually down to about 900 today.

Let me explain the way we broke out this map, so you can see. In blue, these are assets that are going into the partnership. So virtually, all of our year end Permian assets except for the 15,000-or-so acres that Doug referenced earlier, where we picked up some leasehold and we're going to start drilling on the additional acreage, probably, around the end of the quarter, no later than during the second quarter. So the Permian is standalone. It's virtually all going into the partnership except for the 15,000 acres. Then you see East Texas, North Louisiana conventional in blue. That's a subset of our East Texas, North Louisiana shown in green. So we're going to have, within the partnership, about 1/2 the Tcfe of reserves, about 95 million to 100 million a day of production and net acreage of some 130,000 acres. In Appalachia, still our biggest portfolio, we have net acreage of about 312,000, production is about 50 million a day and that's made up of 36 million to 38 million a day of Marcellus, 12 million to 14 million a day of conventional. In East Texas, North Louisiana, which is our largest production base of the 400-plus million a day, some 330 million to 340 million a day is Marcellus and the balance would be in our conventional assets, it's about 70 million a day.

So going over to some of the verbiage here, Haynesville/Bossier, we're going to continue manufacturing only in DeSoto Parish in the Haynesville. We're down dramatically in rig count from when we peaked at about 22 rigs in 2011, we're down to 3 today. And like I said, they're all in DeSoto Parish. Our other key areas in the Haynesville/Bossier is in Shelby, down in East Texas. We've got the majority of our leases held, but we deferred drilling until 2014 until prices recover. I'm going to give you some detail on where we are on well costs and some of our additional plans when we get into further detail on Haynesville/Bossier.

The Marcellus focuses on appraisal this year. We're gathering data and we're continuing to hold acreage. We've got some 60% to 70% of our Marcellus acreage as HBP. We've got our development drilling on hold here, and I'm going to give you some more detail on what we're doing with the organization that supports the Marcellus, how we're moving the bulk of that team down from Warrendale to here.

Permian, the deep rights. This is outside of the partnership. We continue to test in the Wolfcamp and Cline. We did increase our acreage position and that's referenced in the guidance, where you saw we've spent some $30 million or so in acquiring this acreage, 38 -- $30 million plus. And we're in the steps of finalizing a joint venture to exploit this deep acreage holdings.

TGGT is a 50-50 equity company held between us and BG to gather and transport and treat gas. It's a midstream company. Throughputs held steady at about 1.4 Bcf a day. We've had some great results there this year, as we've cut capital, cut OpEx, and increase our volume throughput. So we actually made -- and I'll go over that detail further, about $158 million of EBITDA in TGGT.

In the partnership assets, which we have 25.5% of, we're going to continue drilling with 1 rig in our Sugg Ranch, Canyon Sand area. Probably, spud some 36 to 38 wells there this year. And in Cotton Valley partnership assets, the focus will be on managing our base decline and, of course, our costs. And the decline will be managed as we do additional workovers and recompletion.

Slide 15 goes into our SEC reserve case. First thing I'll point out is that our pricing for SEC proved reserves for full year '12, had a reference price of $2.76, as shown in the footnote. That's down from $4.12 since a year ago. So we have gone from 1.3 Tcf, as you can see in the water fall on the bottom of the page, to slightly over 1 Tcf of proved reserves on an SEC basis. We did have some good performance. We have extensions and discoveries in excess of 100 Bcf. Our wells continued to perform better than we had thought a year ago, so we increased the reserves through the performance of the wells about 40 Bcf. And then because of our cost-cutting efforts on both LOE and capital and some revisions in working interest, we were able to add some 200 or 197, specifically, reserves through the revisions as the result of cost-cutting. We did produce about 190 Bcf, and we sold just a small amount. But price had the biggest impact on our reserves this year as revisions due to price totaled some 467 Bcfe. I will say that when you look at F&D not necessarily on an annualized basis but in a period of time, so when you look at 4-year period, our F&D was about $1.51. The way our reserves are run now, the bulk of our reserves are proved developed, some 96% of our total proved reserves. And our proved developed F&D was about $1.60 this year. And the PV-10 of our proved reserves using strip pricing is $1.8 billion on a pretax PV-10 versus $0.7 million when you use SEC pricing.

Going over to Slide 16. This gives some color or detail on the $273 million budget for 2013 that Doug and Steve referenced. I will say that's down from $1 billion of spending in '11 and about $500 million of spending in '12. So we continue to manage our capital budget. Some 75% of the budget will be focused on drilling and completion, some $207 million -- $206 million of the $273 million and about 66% of our budget will continue to be focused in the Haynesville Shale area. Our corporate spending entails capitalized interest, capitalized salaries and some IT and other corporate capital as well. Appalachia will get $53 million of our spend.

And then on Slide 17, you can see what the partnership capital budget entails. Some $37 million, and this is 100% to the partnership. So EXCO would have about 25.5% of that total amount there. Where we're continuing to drill in the partnership is in our high rate of return, liquids-rich Permian project. We're seeing 40% to 60% rates of returns from those wells. We expect to turn some 37 wells to sell there. And you can see that the bulk of the spending of the partnership goes to that drilling program in the Permian. Vernon in East Texas and North Louisiana, like I said, are built around recompletions and some artificial wells and operations improvement.

Going over to Slide 18. I'll give you some additional detail on what's going on in our East Texas/North Louisiana core Haynesville Shale, Haynesville/Bossier shale area. Holly, we've got about 99% of our acreage held by production. Holly, of course, is predominantly in northern DeSoto Parish and that will be the area where we continue to manufacture. We've got some 34 or 35 units fully manufactured at this point. We're about halfway through that program. Down in Shelby, our acreage where we'll start drilling again, if prices continue to improve, we'll start drilling again in 2014. We've got about 93% of that acreage as HBP.

Operated shale production about 1.1 Bcf a day and our net production at year-end, we had an exit rate of 353 million a day from 378 operated and 178 OBO horizontal shale wells. We had, for full year 2012, about 70-or-so wells that we brought online, very consistent performance through our restricted choke program. We brought them on at about 12 million to 13 million a day at an average PSI of about -- taking pressure of about 7,800 pounds. We've made continuous improvements in our drilling and completion operations. We brought the cost down from $9.5 million in Q4 '11 to about $8 million currently. And we've actually think some of our wells come in at sub $8 million on our total cost. I will say that in our budget, we're getting 33% to 34% rates of return in this Holly core area as we drill our wells. And at $4 gas, we expect 40% rates of return. OpEx, we've reduced some 32% year-over-year for fourth quarter of '11 compared to fourth quarter of '12. We've brought our production downtime to approximately 4% of late, I think, 2.5% to 3%. But we've had a key effort in doing that is bringing an operations control room into Dallas where we implement well surveillance, and we actually can control the wells from here. This creates a lot of efficiency in our field operations, and with these virtual operations from Dallas, we can actually send our operators out to problem wells. They don't have to go look at wells that are chugging along just fine. So it's been very, very fruitful for us to have this operations control room in place.

You can see on the bottom, the right-hand quadrant of this chart -- of this slide, how in green, you can see the EXCO wells that we've drilled. We've actually brought our wells time from spud to rig to TD, down to about 30 days and our spud to rig release, which isn't depicted on this chart is down to about 36 days. So we've had some outstanding performance, and I firmly believe we continue to be a premier operator in this area.

In Appalachia, we've got about 312 -- as shown on Slide 19, we've got some 312,000 net acres, about 128,000 net acres are -- have Marcellus Shale potential. Roughly 2/3 to 3/4 of our Marcellus Shale acreage is HBPd. The total net production is about 58 million a day and in Appalachian area with some 43-plus million a day. Coming from the Marcellus, we've had a great increased year-over-year from end of '11 to end of '12, as the Marcellus has increased dramatically as we turned 38 wells to sales during '12. We've seen some really good results of late. We've had some 7-plus million a day IPs on average. We are slowing down up there because of natural gas pricing. And in turn, most of our efforts this year will be on appraisal and holding acreage. We'll focus on the delineation of select acreage block, so that in 2014, we'll reinitiate a development program. Well, we have seen some significant cuts in drilling cost. Our drilling cost are down 46%. You can see that over here in the chart, in the bottom right-hand corner of the bar chart. You can see that our drilling cost have actually dropped from an average of $4.6 million a day, down to, most recently, it's about $2.5 million a day. Now with completions, our average well costs run at about $6 million a day for a development type well. Now appraisal well, where we have more science, of course, the costs are going to be higher. But our drilling costs are down 46%, our completion costs are down 11%. We are integrating the asset team into Dallas. And at year-end, we had some 120 to 130 people inclusive of both EXCO and BG employees in place in Warrendale. We're going to keep about 40 to 45 in Warrendale. We'll move some 25 to 30 here, and the balance will leave the company. And this is being done in response to natural gas prices, to reduce our cost, but probably and most importantly, to enhance our collaborative efforts across the company and we're doing this with the full support and cooperation of our 50-50 partner BG in the Appalachia JV.

Slide 20 goes into some detail on our partnership operating areas. You can see West Texas Permian, it's dominated by Sugg Ranch, where we're doing our drilling. Long-life reserves, very concentrated area. This does not show where we've acquired some acreage outside of the partnership, which is just to the south of Sugg Ranch. In East Texas/North Louisiana, you see our 4 major areas: Waskom, Holly, Cotton Valley, Danville, but Vernon dominates the volumes in the -- it's got 65% or more of our partnerships East Texas/North Louisiana production. Again, upside potential exists at higher gas prices but it's got to be $5 to $6-plus before we really start drilling here again on most of these assets, but we are going to continue with what I call the low hanging fruit. There's some behind pipe recompletions where we get some excellent rates of return. And we've also implemented recently some agreements with third parties to process gas and realize more revenues from our natural gas liquids content of this gas.

The last slide I'll address is on Page 21. TGGT is the 50-50 equity company that we hold with BG Group. We are in the throes of marketing this property or these assets. We've had several parties in, and we'll talk about the timing on that, I'm sure in the Q&A session. But it's progressing very well. We've got management presentations ongoing, and we will move forward with this asset sale. But it's had great performance, frankly, Q4 throughput were 1.4 Bcf a day. The last couple of days, it's actually been about 1.43 Bcf a day as we brought on some additional wells and some third-party volumes. EBITDA for full-year '12 was $158 million, outstanding performance. I will say as volumes decrease, as we reduce our drilling program, we're forecasting an equity -- I mean, an EBITDA for 2013 of about $126 million, $125 million. Our debt position, we paid down of late, we have $600 million facility in place. We've got about $512 million to $515 million of net debt, and now it's down to about $484 million. Our capital budget has been reduced dramatically. We spent about $126 million for full-year '12, that compared to some $300 million in full-year '11. But we're forecasting that to go down to about $40 million for '13 as our major facility infrastructure has been built. Most of what you'll be seeing us spend is capital loan. It's combination of continued well hookups for equity volumes from BG EXCO and some costs that we'll incur as we go out and acquire third-party volumes. That's probably a 50-50 split at this point. With that, I will turn the floor back over to Mr. Miller for Q&A session.

Douglas H. Miller

Okay. One of the things, I think, everybody -- I'm positive most people realize is -- especially companies like us, gas company, who, 4 years ago, had thousands of proved undeveloped locations. Two things happened with SEC. As prices come down and they don't hit a certain hurdle rate, you got to write them off. That doesn't they're gone. They're just now in probable. The second thing that happens is if -- the new rule is if you don't have it on your schedule in the next 5 years, you have to take it off. That doesn't mean it's gone, that means it's in probable or possible. So we started it early, so we haven't had any explosive. But keep in mind, this is -- what you have today is 96% PDP. I mean, we only have 4% left, and I think we're drilling those, so we shouldn't have a lot of write-offs going forward. But the bottom line is, and we've done a study on this, if prices, we say when, but if prices go up, we have potential for 5 to 6 Tcf in our asset base where it is now, if prices go up. And they kind of turn on -- we run a model at $4, $5, $6, $7, each area brings on a lot of these things, and we're looking at wells that we would drill that have a 20% rate of return. So this asset base is still spectacular. It looks like it's going away, but it isn't going away. We're just writing it down. So with that, I'm going to shut up and see if anybody wants to ask any questions.

Question-and-Answer Session

Operator

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

Brian Singer - Goldman Sachs Group Inc., Research Division

I just wanted to follow up on some of your comments on acquisitions. I guess, as we go through the year, or as we get to the end of the year, should we expect that EXCO will look materially different in terms of its exposure either regionally or production mix wise from where you are now or should we see more smaller deals potentially by your JV partner or partners that don't necessarily move the needle as much?

Douglas H. Miller

Well I'm hoping we have a significant change. The board approved a fairly aggressive acquisition effort. We're looking a lot of deals. I would say, we're working with a lot of guys right now. We kicked it off, and we had an all employee meeting here a couple of weeks ago, as you can imagine, as we are cutting people and we're going slow, we probably had a slight morale problem around here. But with the board's decision to do an aggressive acquisition effort, we had an all-employee meeting and we told everybody to get some new tennis shoes because we're going to be speedily running forward. I would hope it's significant change, Brian. But I would say this, the 2 main areas of focus are going to be the Haynesville and the Marcellus. Now, we are -- and we're working probably 7 investment bankers as we speak, have deals in here that we're negotiating on. There are a couple of deals that has some oil. I told everybody that we could turn around oil if we start buying. Just thinking about it, we've turned it around in the last 2 days. So we're bragging oil down. But I would say, if we're going to drill wells, they're going to probably be in the oily areas. A lot of acquisitions we are looking at in the Haynesville and the Marcellus have production with them. Those, we would not anticipate doing much drilling. But I would say, all in all, expect some changes.

Brian Singer - Goldman Sachs Group Inc., Research Division

Okay. Just so I could clarify that, because you did just referred to the focusing on Haynesville and the Marcellus, which are the 2 main areas where you are pretty focused on now. So I guess, should we expect originally that you would stay there or that -- I'm trying to...

Douglas H. Miller

Yes, we're going to stay there. I mean, we're working on 4 or 5 areas right now. The easiest ones for us to evaluate are the Haynesville and the Marcellus because we have the most experience there, and we have operations, and there are several -- there just aren't many deals in the Haynesville for sale. Most of -- I would say, the 2 core areas and really, the only one we would really buy is around Holly. Now we're doing some studies and Harold has -- I've heard him say, "I'd like to get back into that area where some other operators drilled some wells that we're not sure are done right." But I'd say in the Holly area, between Chesapeake and in Cana and El Paso and Shell, it's pretty much taken up. Now there are some small deals that we're working on. Don't expect a lot of action in the Haynesville. But up in the Marcellus, there seems to be quite a few deals for sale.

Brian Singer - Goldman Sachs Group Inc., Research Division

Okay. And then just looking at the production profile here, I mean, yes, your gas production is in decline, which probably shouldn't be a surprise given the activity levels. But at the conventional wisdom would be that the Haynesville should be declining pretty rapidly. And can you just talk about what you've done to mitigate that? Is that just lower than expected decline rates or is it bringing backlog on, how should we think about that?

Douglas H. Miller

I'd say, Mark, can you speak to that? or Hal?

Mark E. Wilson

There's couple of things. One, we brought in a significant inventory of wells from '11 into '12 that completed, and we also are bringing a significant inventory of wells from '12 into '13. Our restrictive choke program has mitigated the decline significantly. You might recall that we're bringing on wells that at 25 million to 30 million a day early in the program. Now we significantly cut that choke, put the choke program in place. Bringing wells from '12 to '13, that definitely mitigates the decline. I'm not saying you don't have significant declines, you do. But it has been mitigated accordingly.

Marcia Reeves Simpson

Right. Plus now we have years of wells that are on for 3 years in our base. They are the lower decline rates. So the incremental coming on is not as effective as on the decline side. So that's up there.

Douglas H. Miller

Yes. The thing is -- keep in mind, at these production numbers, we have a production meeting every Monday and we have had some pipeline issues, not necessarily ours, where I've seen weekends where we have 300 million or 400 million a day shut in. This is in spite of several weeks where we had 100 or 200 million a day shut in. So this -- I think, this is kind of spectacular results. And as we go forward with less and less wells being drilled, we're down to about 2%, 3% shut in. It looks like average over the last week or 2, month or 2.

Unknown Executive

So if you look at historically, we were more 7% or 8% downtime. And then now, we've been running more in the 2% to 4%.

Douglas H. Miller

Right. So that's helping too, Brian. I think -- there's one of the guys that we share a lot of data with, there's been some new techniques and we're sharing it in Cana. I mentioned a couple of days ago, they're talking about some 18 Bcf wells. We'd love to have that because we're prying in the 6 Bcf to 8 Bcf. But what they're doing is they absolutely change a lot of things and there wasn't the best operators out there, but they're doing a lot longer laterals, different frac jobs and in different areas. But they're testing and testing, and we share data with them and we're rooting for them.

Operator

Your next question comes in line of David Neuhauser of Livermore Partners.

David Neuhauser

I know where, I mean, in these quarterly conference calls, of course, with gas prices still depressed but -- and I know it's a bit frustrating, but kind of what's the longer-term plan here as how you're sort of recalibrating EXCO to look into next year or 2?

Douglas H. Miller

Well, I think, you're going to start getting a hint on it. I mean, we're going to be focusing on some acquisition. Keep in mind, when gas prices are cheap, the value of the asset's cheap and we're going to be attempting to make some acquisitions in areas we'd like to expand. We're tired going backwards. The one thing about oil and gas companies, there's only 2 ways. You're either going forward or you're going backwards. There's no such thing as standing still. So we've gone backwards here in the last 1.5 years. We've weathered the storm and the other thing that I've told you guys, time and time again, is gas prices can go lower in your forecast and they can stay longer in your forecast. So we have a plan in place right now, if gas prices stay between $2 and $3. We have a plan for the next 2 to 3 years, the board has approved it and employees are on board, and now it's time to execute.

David Neuhauser

And how is your -- at this point, how is your feeling on -- like your liquidity position? I know we've been waiting, of course, on some further asset disposition, so how are you feeling about that?

Douglas H. Miller

We have $500 million today. We probably have 8 partners waiting that have $1 billion plus each, willing to spend -- actually, driving us crazy to do joint ventures with them. So liquidity isn't going to be the issue. And then we have TGGT, I know it's later. I predicted last July 4, I screwed that up. It's taking longer. We have Goldman Sachs and Morgan Stanley working on it as we speak. We've had 4 people through a data room. We have another 16 request to come through a data room. Blair is going crazy. About half of them are strategic, about half of them are infrastructure funds. And I would say, we would have an answer on that by mid-April. And I think, in theory, between that and the joint venture, we'll come close to 0 outstanding under our revolver, so we have plenty of dry powder. But again, we have 5 or 6 major institutions that are friendly with us that would like to do some strategic joint ventures. Maybe we put up 10% and they put -- there's a million of ways of skinning the cat. But our job right now is to find good deals. If we can find good deals, there are plenty of good partners out there. And discipline has to be underlined. One way to make a good deal a bad deal is to pay too much for it.

David Neuhauser

I understand that. But I know a lot of these joint ventures, like you said, you're not going to have a whole lot of equity to put in. I guess my point is, even if you find some good deals here, are these joint ventures going to end up creating tremendous value for the shareholders over time?

Douglas H. Miller

Yes, sure. I mean, we're not going to do it for free. If we put up 10%, and they put up 90% and we operate it and grow it, we're going to end up with a lot more than 10%. I kind of expect on a deal like that, we might end up with 25% in -- by the PDPs and over time. So I mean, there's structures that work for both. I mean, we agree that it has to work for shareholders. We have a plan.

David Neuhauser

Okay, that sounds good. And my last question is again, I know you're saying a lot of joint ventures, strategic partnerships, but that makes things look a little messy from an investor's point of view when a company has all those partners. I mean, at some point, again, if things stay where we're at today and it's 1 year from now, 2 years from now, you're even adding some joint ventures and assets to the mix. I mean, the company essentially looking at that point to go private with their -- would go private and look to recalibrate in that way, or is the company just going sort of look to maintain and grow shareholder value in a way you're describing?

Douglas H. Miller

You're the one who brought it up. I'd love to be private. I'm not working on any deal right now, but it would be a lot easier in this industry to be private right now. And I'm not the only one that's thinking that way.

Operator

Your next question comes from the line of Howard Henick of Scurlydog.

Howard Henick

TGGT, could you take me through what kind of return you think you're going to get if that thing gets sold, because the number -- if you basically think your -- will have no more draw down on the revolver, that seems like a big number. So if you could flush that out a little bit.

Douglas H. Miller

No draw down under their revolver, is that what you're asking?

Howard Henick

No, no, no. You said if you do the -- if you get that -- the pipeline sale off, the whole thing of the deal sold.

Douglas H. Miller

Yes, yes, yes. Well, if -- our equity interest if we sell that...

Mario Barraza - Tuohy Brothers Investment Research, Inc.

Yes, that's my question.

Douglas H. Miller

Yes, we'll just pay down our oil and gas revolver. It's not pledged at all. So if we got $300 million or $400 million or whatever we got for it, it would just reduce our revolver and give us dry powder for our acquisition effort.

Howard Henick

But what's your draw down on your revolver currently? Isn't it more than that?

Douglas H. Miller

$550 million-ish, out of the $900 million revolver.

Howard Henick

Right. So you don't think you're getting $550 million, that's what I thought you were saying, which seemed like a lot of money.

Douglas H. Miller

Say what?

Howard Henick

You didn't think you're going to get $550 million-ish for the sale.

Douglas H. Miller

No, no, no. We have another joint venture working where I expect to get $50 million in here over the next 2 quarters. You just never know. We have a couple of things that me and Ramsey are working on. That could help a lot here shortly.

Howard Henick

Well that's good. I look forward to that. And the other question is, it gets a little confusing with me, obviously, with all the write-downs on the gas, and the stuff in the ground, the valuation of it, which I understand it's mostly due to price. But if you looked at your overall reserves, then you can break it down totally or just gas. In terms of reserves in the ground, what do you think you have versus a year ago, on basically constant dollar, like the price of gas never changed? Is it up or down and by how?

Douglas H. Miller

Well, I would say it's probably slightly down. I'd say look at our production versus our discoveries.

Marcia Reeves Simpson

Just take the Tcf and add back the 467 and that's kind of where we'll be.

Douglas H. Miller

We did about 15.

Harold L. Hickey

And practically it's 15, the water fall and there it is.

Marcia Reeves Simpson

Yes. And we've quoted around -- our NYMEX strip we're at 1.6 Tcf, I mean -- that all those cards and the tails of the wells that are on production come back at the NYMEX.

Douglas H. Miller

Yes. I mean, what we do around here, what we do around here, and Marcia goes crazy with her group, we actually do 3 engineering reports every quarter. We do a SEC reserve report, we do a bank reserve report, which is a forward curve at a discount to the actual curve and then we do an actual curve. So we literally do 3 different engineering reports every single quarter. And the difference between the SEC and the NYMEX, which is where properties are trading right now, is significant, maybe as much as 50%.

Unknown Executive

Our reserves, to answer your question, would be up year-over-year were it not for price.

Howard Henick

So you would be up? And what -- up like 10%, 20%, 50%, 2%?

Unknown Executive

About 10%, I think.

Howard Henick

About -- close to 10%?

Harold L. Hickey

Almost -- yes, just over 10%. At slide 15.

Douglas H. Miller

Slide 15 tells the story.

Howard Henick

I'm looking at Slide 15, I don't quite follow that. But that's okay. That's very helpful. It looks like they're down slightly.

Douglas H. Miller

We'll give you a crash course.

Howard Henick

No, but I'll take your word for it. So you think they're up slightly, that's fine. They're not down dramatically is what I was concerned about.

Douglas H. Miller

No, no, no.

Unknown Executive

No, no.

Operator

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

Douglas H. Miller

Wow. There must be too many conference calls going on today. Well, with that, I appreciate everybody being on. It's been a tough year but I think the management has put together a plan and the board has 100% bought off on it and I expect that everybody to see a lot of changes over the next 12 months and hopefully, we can get them kicked off here in the next few months. Again, thanks for being here. Meeting adjourned.

Operator

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

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