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EXCO Resources, Inc. (NYSE:XCO)

Q1 2010 Earnings Call Transcript

May 5, 2010 9:00 am ET

Executives

Doug Miller – Chairman and CEO

Justin Clarke – Assistant General Counsel and Chief Compliance Officer

Steve Smith – President

Paul Rudnicki – VP, Financial Planning & Analysis

Hal Hickey – VP & COO

Mike Chambers – VP, Operations & General Manager, East Texas/North Louisiana Division

Analysts

David Heikkinen – Tudor, Pickering, Holt

Brian Singer – Goldman Sachs

Leo Mariani – RBC

Neal Dingmann – Wunderlich Securities

Irene Haas – Canaccord

Kathryn O'Connor – Deutsche Bank

Ray Deacon – Pritchard Capital

Operator

Good morning. My name is Andrea and I will be your conference operator today. At this time, I would like to welcome everyone to the EXCO Resources, Inc. first quarter 2010 earnings release conference call. (Operator Instructions) I would now like to turn the call over to our host, Mr. Doug Miller, Chairman of EXCO Resources, Inc. Please go ahead sir.

Doug Miller

Thank you, Andrea. Again, this is Doug Miller. I will act as Chairman today. I have a full group in here, counting two lawyers so I don't say anything stupid. But before I get started, one of our lawyers will read our preamble.

Justin Clarke

Thanks, Doug. As a reminder for everybody, you can go to excoresources.com and click on the Investor Relations tab to access today's presentation. As an additional reminder, the statements may be made on this call regarding our future financial performance, structure and results, business strategies, market prices and future derivative activities, any other plans and forecasts are indeed forward-looking statements. So we caution you not to put undue reliance on those statements.

Please refer to slides three and four in the slide presentation for a complete text of our forward-looking statements. We have also made available on the website reconciliations for certain non-GAAP financial measures that may be discussed on this call. I will turn it back over to you, Doug.

Doug Miller

Thanks, Justin. I will quickly go over a couple of bullet points here that I am sure won't answer everybody's question, but will – as it is the starter. And then from an operational standpoint, Hal will get into the detail.

We continue to march on our plan. We set out a little over a year-ago to de-leverage the Company and refocus the Company in areas that we think we can – our finding cost is cheaper and more specifically our operating costs. We have been very successful. We got out of most of our conventional. We still think today that conventional gas takes at least $6.50 NYMEX to make a reasonable return.

In certain areas of the Haynesville we are seeing right now that with costs up there is only very few areas in the Haynesville that make our 20% hurdle rate. And we'll get into that a little later.

We have drilled and completed 50 Haynesville wells to date. We'll get into that. Spectacular success, our operating team is doing a great job. You will see that we are going to move some of our rigs. We're about 100% HBP on our acreage now, so we have the flexibility to move around.

We will continue to drill in DeSoto Parish, which we consider our core, and one of the major core areas. Every well we've drilled in there has exceeded our expectations – our early expectations. We now kind of expect 20 million a day. But we will continue – from a science standpoint we will be checking different proppants. We will try to figure different ways to source and clean up frac water. And most importantly, I think this year we will figure out spacing. We will get into that a little later on. We are going to be completing four wells on a 320 [ph] to test 80 acre spacing, actually later this month I think. Isn't that right?

Unidentified Company Speaker

Yes.

Doug Miller

So everything is going great there. With cheap gas, and we do think gas could be cheaper a little while, has given us some opportunities. We have recently signed up a couple of deals. Most importantly was the Common in our joint venture with BG. It is a sizable deal with at least 2,000 potential locations.

We will later on this month, we will be creating a budget. I think early on we were talking about having as many as six rigs running down there. There is some drilling obligations that we have to do. It came in a really good area with some good science and good people. We were really impressed with the data they had, so it made it very easy for us and BG to have a competitive bid.

It should close later this month. It is something that we are looking forward to drilling. It's slightly deeper, so the costs are going to be slightly higher, but there is both Haynesville and Bossier potential in there. It comes with some production. It comes with two rigs already running. And we are monitoring those and cooperating with the company right now. It will be a real seamless takeover of that.

There are other opportunities down there. So one of the challenges – and we will be meeting with BG later on here in the next couple of weeks, it is putting our development plan together along with our pipeline scheme. I mean, there is going to be some additional capital needed for the pipeline.

We did this quarter drill our first Bossier test and completed it. What was it – around 9 million or 10 million a day?

Unidentified Company Speaker

11.

Doug Miller

Excuse me, 11 million a day. It looked – it is very successful, it’s in DeSoto. We will – we have a rig running out there. I think we are completing our second one right now. That rig will stay. We are very happy with the results.

Capital spending, we will – I think Paul will go over that later on. We are right on where we expected to be. We will continue because of our theory to be an aggressive driller, but most importantly, we will continue to drill inside of our EBITDA, and that will continue even with the Common acquisition.

Lastly before we get started, Marcellus, we have made up our mind as a company to do a joint venture. We did say that we would report to everybody. We had discussions with multiple people. We are in discussions right now.

There is no assurance that anything would be done, but I would expect we have picked a partner to negotiate with. Again, it is a fairly complicated area. The good news is we are 80% HBP up there. The bad news is, there is a lot of pipeline issues and I think we have picked a partner that understands pipeline issues. So it has been a key factor in the negotiations, making sure they understood the capital needs and the speed at which we can grow and be able to sell gas up there. So I would say, again, there are no assurances that we are going to sign a deal, but I would say over the next 30 to 60 days, if everything goes well, we should be announcing. And if we do sign a purchase agreement we will announce, and we will have an additional conference call and go over how we did it, what we did, and how we expect to exploit it.

One other thing, I think everybody is scared of gas. I noticed that all of our competitors are now oil companies. We don't plan to shift our focus. We have what I consider a spectacular team. We have the two best areas with the cheapest finding cost and the cheapest operating costs.

We will continue to grow those areas. We will continue to look for tack-ons in those two areas. We are not looking for any other area. We do have one little small area out in West Texas that has a little bit of oil. We have one rig running out there. We're just slightly under 2,000 barrels a day.

The economics, we recently looked at it, it looks like at $80 oil, we are getting 70% rates of return. So we're going to make a decision here over the next week or two whether to go to two rigs or not. Big huge wells are probably 50,000 barrel wells. And the rates of return are sizable. It won't have a huge impact other than it makes a lot of money at this price. And so we probably have 300 or 400 locations out there, so we will probably put a second rig if we can find it to work out there. That's the only thing from an oil standpoint.

We are not looking to change the Company to be an oil company over the next quarter or so. The analysts like us. We are a gas company. We are going to be 90% gas. We think that gas is going to have significant demand increases over the next few years. Boone [ph] asked me here a couple of weeks ago, could we get to 25 to 30 Tcf a year.

The answer is we probably could, but we couldn't at $4 gas. Conventional gas needs to shut down – will shut down eventually at these prices. There are people drilling out there – for different reasons than economics. There are guys with long-term contracts rigs that continue to drill. We don't understand it. There are guys that have huge acreage positions that have decided to drill uneconomic wells.

We are already seeing rigs moving from the Haynesville down to the Eagle Ford. There is a huge lease play going on down there, and there's going to have to be a lot of drilling going on. And there's different areas that have oil and gas. I expect we are seeing equipment move up to the Marcellus.

I've told people – you don't know anybody – I am sure everybody on this conference call owns some acreage in Pennsylvania or West Virginia. And there are very few people that are HBP. So the bottom line is there is a lot of equipment. Costs are something we are looking at. But these are the two areas that we are going to focus on. With cheap gas – at least in the Haynesville we have a partner that kind of forecast $4 gas until the mid-2011, and wanted to make sure they were teamed up with somebody that could go out and exploit additional opportunities.

We are looking at approximately another 100,000 acres in the Haynesville, probably 10 different deals. None of which can be assured we are going to get. All of which, if the price is right, we would entertain. So we have three teams out there. We have three teams up in the Marcellus today looking at additional leases. I would say in-house today we probably have 300,000 or 400,000 additional acres.

Again, no assurances that we might do something. But these are the two areas. We are going to be a gas company. We think two, three years from now we are going to see 25 to 30 Tcf a year of demand. We are going to need all the shale. We are going to need conventional. We are going to need LNG. We are going to need Canadian imports to get to that.

Paul just gave me a slide, which is not in there, but I think January and February we had U.S. demand of 90 Bcf a day, which included a significant uptick in industrial and power. Power was the surprise, but I think between power and potential vehicles – I think demand could get – it is going to go up. And I think with demand going up, with our production rate only being at 58, 60 Bcf a day, I do believe that gas prices will start up. When, we don't know. With that, I'm going to turn it over to Steve.

Steve Smith

Let's flip over to slide five. I will just cover a couple of things that Doug has – I will just put a little color on some of the things he discussed.

One is, in the Haynesville we did complete 19 wells this quarter. We have got production in excess of 120 million a day right now net to our interest in the Haynesville. And as he said, we are looking at lots of acreage in our core areas.

We are making significant progress in the Marcellus, both in terms of acreage, and as well kicking off our drilling program. And we will get into a lot more detail about that.

As far as our organic growth is concerned, right now Companywide we began the year with 234 million a day. Q1 averaged 264. We are over 280 million cubic feet of gas a day now. And we expect to be around 300 by the end of the second quarter. So we – our growth is pretty much on plan and moving forward. As I said in one of these bullets, we expect to average 360 to 380 during the fourth quarter, and so the growth rate is pretty impressive.

One thing we did accomplish just this past Friday, on April the 30th we redid and finalized the consolidation of our two revolving credit agreements into one. We reduced the size of our bank group from 34 banks down to 20 banks. The new borrowing base is $1.3 billion, which is what we expected. There is – we have $818 million outstanding, so we've got $467 million available after you knock out letters of credit.

And we – even after the Common acquisition, when you throw in the cash and the availability, we end up with a liquidity of over $400 million. So we are in good shape going into the rest of the year.

I won't get into any more detail about the Common deal, other than to say we are very excited about it. There is lots of potential there, and we think it certainly has a chance to be comparable to our DeSoto Parish type results. So stay tuned for good news there.

On page 6, just a few corporate highlights that I will deal with. Again, it was a productive quarter. At 264 average daily production versus a pro forma of what the first quarter of '09 would have looked like had we taken out all the acquisitions and the joint venture that we did with BG in August, it would have been 237. So we had kind of an 11% quarter-over-quarter increase on a pro forma basis. When you take it from the exit rate, at the end of '09 it was about a 13% growth in the quarter. So we're pleased with that.

Oil and gas revenues, not considering hedge settlements, were up 24% on a pro forma basis. As far as – and well, net income we did have a beep there with $0.25. Oil and gas revenues, when you factor in the hedges and the terminated hedges that we realized in the first quarter, pretty flat with the pro forma '09, and only slightly below the fourth quarter of '09, which also had some of the sale stuff in it.

EBITDA is hanging in at around $150 million. We got cash flow from operations of $136 million, where our capital expenditures for the quarter were $130 million. So as promised and as expected from our perspective, we are spending within our cash flow and we intend to continue to do that. So overall one of the more impressive things about the quarter to me was our operating expense ended up Companywide at $0.81 in the first quarter of '10. That's versus $1.12 in the first quarter of '09 on an actual basis, and $1 on a pro forma basis. Obviously, we got rid of some higher operating cost properties in our divestitures. I think we were – operating costs were around $1.14 in the fourth quarter of '09.

Gathering and transportation costs, you will see an increase there as you dig into the numbers a little bit. We are right on plan. We expected about $0.50 and we – our actuals were $0.47. That includes firm transportation out of the Haynesville. And of course, we now account for our pipeline company on an equity basis, so the charges from the top line company are included in gathering at this point, as opposed to netted against revenues.

Page 7 is our little net cash operating margin chart. Obviously, the volume of hedges and the price at which we settled out in the first quarter of '10 was less than it was in some of the previous periods. But still we are netting a cash operating margin of $5.56, not counting any hedge terminations.

Our hedging program continues to be effective. We are kind of – at about the same – we are very comparable to what Q1 '09 looked like. So we think that, again, we will continue to add hedges as opportunity presents itself and try to get our overall hedge percentage up for '10, '11 and '12.

At this point I'm going to turn it over to Paul and let him take off and explain a little more of the details.

Paul Rudnicki

Thanks, Steve. I will pick up on slide 9, discussing our liquidity and financial position at the end of the quarter. We had $118 million in cash. We had bank debt of $763 million and our senior notes at $445 million for total debt of $1.2 billion, with a net debt of just under $1.1 billion. Leaving us liquidity with the cash of $640 million at quarter end.

Pro forma for the Common transaction, that liquidity goes to $417 million. And as Steve mentioned, we did consolidate the credit facility into one during the second quarter. The rate on our bank debt is going to go up from the LIBOR plus 175 to 2.5. The new facility will have a grade of LIBOR plus two to three.

On slide 10, just highlighting our derivatives position. No new changes there. We are still monitoring the prices and we will act accordingly. Just again, highlighting that we did have $39 million of normal course hedge settlements and $38 million in connection with early termination. Of that $38 million, $4.3 million was related to first quarter 2010 positions.

On slide 11, looking at our capital – .

Doug Miller

The main reason for the early termination was when we went from 34 banks down to 20 banks what we did is we covered with the banks that we're leaving the credit facility and then re-hedged with banks that we're going to be in the facility. So there was – that was the only reason we covered.

Paul Rudnicki

On slide 11, looking at our capital forecast, as Steve mentioned, we came in with $130 million of total capital. We also made equity contributions to TGGT, our jointly owned pipeline company, for $45 million. We made some small acquisitions and we received $67 million of sales proceeds. So you can see that our total investing activities were $117 million net for the quarter.

Looking at the rest of this year we haven't adjusted our budget, as Doug mentioned, in light of all the moving pieces with the acquisition of Common. Looking at the rig count that we expect there of – we are picking up two rigs going to maybe four to six by year-end.

We are evaluating if that's all going to be incremental, or if that will just be replacement or a combination of the two. But you can see, we are also forecasting $69 million of additional sales. Again, mainly related to the joint venture with BG, as we make acquisitions and they elect – and pay for their half.

We expect to make an additional $30 million of equity contributions to TGGT. For the full year, as of right now we are expecting net capital investing activities of $411 million.

One of the highlights for the first quarter, we did spend $50 million in leasing, of which, $33 million was in Appalachia. Again, we did get an approval from the Board in April to raise the full-year equity contribution at TGGT to $75 million.

On slide 12, looking at our guidance versus our actuals, as Steve mentioned, we came in just under the high end of our guidance for production. Our gas differentials really came in very strongly, much better than we expected. The main reasons were the continued high prices we are getting in the Permian as a result of our high BTU gas. With gas prices as low as they are, and oil and NGL prices as high as they are, it makes our differential look like a 60% premium to gas prices out there.

And in East Texas and North Louisiana in the first quarter we were a little nervous before our firm transportation came in that we would be taking some price risks. Our marketing group did an unbelievable job, and helped our differential there. So we came in at a total of – 2% discount, 1.7% discount to NYMEX versus the 6% we were expecting.

LOE came in better than expected and mainly as a result of some deferred activity due to the weather, as well as discontinued decreases across our portfolio.

One thing I do want to highlight is on our depletion rate, it did come in higher than the guidance. And the main reason there is we are adding additional PUD locations without the benefit of the BG Carry against that future capital associated with those locations, and it's just dragging us up a little bit on the weighted average depletion rate.

Legal was up a little bit in the G&A, the main reason for those costs. And then the other big difference in our interest, we had forecasted interest rates to go up this year, and it just ran a higher LIBOR for the full year and we haven't seen that creep up yet. And then the borrowing base, the new facility didn't close until April.

As the Common deal became much more evident, we wanted to make sure we had that in the deal, so we deferred the new borrowing base. And those costs will now show up in the second quarter.

Looking at our guidance for the rest of the year, again other than the depletion rate and looking at our interest expense for the rest of the year, at this point we really haven't made any changes to the guidance. And we expect to update the community – and the investment community, sometime in June after our next Board meeting, as we incorporate all these – as we incorporate Common acquisition into our plan for the rest of the year.

With that, I will hand it over to Hal.

Hal Hickey

Thanks, Paul. Go to slide 15. The focus for this year has been to manage our capital spending, grow our acreage, enhance our midstream business, continue to improve our organizational effectiveness, and of course create alliances with service companies.

On the capital spending front, like Steve said, we are staying within our EBITDA as we promised. And we're very aware of the weak natural gas pricing and the increases from drilling and completion service costs, and in turn we're monitoring our program. We do have flexibility. About half of our rigs are on long-term contracts, but other half or so are on well-to-well contracts. So if we aren't realizing the economic returns that we demand, we do have some flexibility that we may exercise.

And in fact, we have elected to defer of the drilling in parts of the Haynesville play. We are focusing on DeSoto. Some of those other parts don't give us the economic returns we want, and in turn we are moving out of those areas.

Our acreage position, we continue to grow. As we promised, we've added or contracted to add over 30,000 acres. By this point we're looking, like Doug said, at over 100,000 acres in East Texas/North Louisiana and a similarly large number up in the Marcellus play.

Our midstream business continues to grow dramatically. We've got over 900 million a day flowing through our TGGT system. About two-thirds of that is equity gas, about one-third of it is third-party gas.

We are finished with the first phase of our big Haynesville header system, and we're adding onto the header system as we make acquisitions.

All of our treating facility progress is working very well. We've got nearly 800 million a day of treating capacity as of this month. We will grow that to over one billion day later this year. And we're continuing to have good success with our strategic alignment between the midstream and the upstream, particularly in North Louisiana, as we hook up virtually all of our wells during the initial flow back period to get them to sales. On an organization – .

Doug Miller

I might add there, people don't realize how good a job those guys are doing. And we had over 55 projects they were working on, on Monday; most of them were for hookups for either us or third parties. In the last two quarters they have gotten about 25 or 30 inches of rain over there. And so we've had some delays, but they've worked in the mud up to their knees and they've done a spectacular job. Now we have had some delays, but they're mostly weather related and they are catching up right now.

Hal Hickey

On our organizational effectiveness front, we continue to add good technical people. We have about 805 employees as of the end of the quarter, and that is growing every week, as we find the right people to add to help us with our science and our development program.

We are working on our business processes. We spend a lot of time with BG and they have some very complementary skills, and we're working on everything from supply chain to how we manage our projects. And then, of course, it is very important to create alliances with service companies. We're working with completion service providers, proppant suppliers and drillers to continue to lock in services and supplies for our program forward.

Slide 16, takes a hard look down at our capital program, and we're evaluating our development pace in light of the current pricing environment. We do believe we have a strategic advantage in the Marcellus and in our legacy Haynesville properties, because we have such a high level of held by production acreage. So in turn, we can manage the pace of development and decide what we want to do.

Like I said, we have deferred drilling in parts of the Haynesville play where we aren't receiving our rate – achieving the rate of return targets. And these two tables on the bottom of this slide sort of frame up what your returns could be expected to be when you range from $8.5 million to $10 million well costs, drilling and completion, and when your IPs range from 10 to 20.

At 20 million a day this thing works at $3 gas. If you get down to 10 million a day IP, this is a tough ticket. So we're managing this. We are working very diligently to manage our drilling and completion costs. We've got teams focused on that every day. And we're trying some things that I'll talk about in a few minutes or how we're going to continue to manage those costs down.

We were consistently below $9 million. With the recent demand on services, we've seen that creep back up. And it's in the $9.5 million to $10 million range in our core areas. We do have some ideas on how we are going to bring that down.

Slide 17 shows our production profile. And of course, the big message on this slide is we are doing exactly what we said we were going to do. In '09 we sold the properties that we had committed to sell. We managed our balance sheet, and we've gotten it down to an area that's going to allow us some real flexibility going forward. We've got a portfolio now that is focused on the Haynesville, Bossier and Marcellus shale. And we shrunk to grow, and we're going to deliver this 60% or so organic growth over this year.

Slide 18 gives you a picture of what we are doing today with our rig count. We've got 17 operated rigs and eight non-operated rigs, for a total of about 25. We spud some 53 wells in the first quarter, completed 42, and we remain on budget at this point to spud nearly 200 wells. I will note that in the non-operated portfolio the bulk of those wells are in – or virtually all of them were in the Haynesville/Bossier area.

Our average working interest there is pretty low, guys. It's in the 6% to 8% working interest range. So it doesn't have a huge impact on our capital program. It is something we monitor, and it's a good data source for us to learn from what's going on with other peers in the play.

Currently we have about 90 Haynesville wells flowing to sales. We're going to complete 20 to 30 per quarter for the remainder of '10 as long as we stay in our own task. We completed two horizontal Marcellus wells in the quarter. Those were from 2,500 foot laterals, and they had IPs of 2.2 and 2.3. We are preparing for the development program there and continuing to enhance our science and our understanding.

Our first frac or completion in the Bossier horizontally drilled, we did exactly as we completed our initial Haynesville wells. That gives us a baseline to learn from. Now we're going to start refining that completion procedure. And we're going to – in the drilling procedure, and we're going to drill up to six additional test wells this year.

And we are continuing at this point with one rig drilling for us in the Permian, where we get the 60% or 70% rates of return thanks to the oil contribution. We could very easily – in fact, we are going to analyze adding a second rig in that area in the near future.

Slide 19 digs a little deeper into the Haynesville. It shows how we have expanded our footprint. And the Common acquisition area is down to the southwest of where our normal DeSoto Parish assets have been, and where we've been focusing. In DeSoto we've had a very good, consistent IP rate of 22 million, 23 million a day. And that IP rate is the first – during the first flow back period, it's the highest 24 hour period of volume we have going to sales.

We are testing various drilling and completion methods to improve our recoveries and reduce our costs. The guys are doing a great job here. Like Doug mentioned, we've done some pad drilling, and we are actually going to complete four wells off one pad 80 acre test this May.

And we are excited about what we going to find out there. We're testing our frac sizes and our cluster spacing, as we have shrunk the spacing from 80 feet to 60 feet on some of our wells.

We've got some frac optimization studies ongoing. Traditionally we've used about on 380,000 pounds of proppant, we used about 300,000 pounds of an intermediate strength proppant, about 80,000 pounds of 100 mesh sand. We're going to try 50-50 and see what that does. We think that, that continuing to look at opportunities like these and manage our operations have given us some opportunities to maintain some of the same sorts of results we've achieved that we are very proud of, and at the same time continue to manage our costs.

A couple of other things that are happening in the Haynesville that I want to mention, we're continuing to gather data. We've got – we are in the final stages of a 3-D group shot where we're getting 168 square miles of 3-D over DeSoto.

We're continuing to build an acreage position, like I said. We are working very well with some third parties on getting water sources. And in fact, we've got a contract with a paper mill in the area that we announced this quarter, and we are going to commit getting up to a 100 million barrels of water that comes as residue from that type plants that we can use for frac water.

We've tested it. It works very well, and it's something that we think is going to be a very good project, in fact, precedent setting for the area and that it's going to allow that source is not directly from surface water.

Slide 20, Common Resources. We hope to close that acquisition later this month. There is a combination of vertical and horizontal wells that the team has been working in Common. The Common guys have analyzed. They have great data, 3-D seismic. And it's been, like Doug said, an easy transition for our technical people to learn and get a hold of what the opportunities are down here.

It's in the Shelby Trough, spread mainly across Shelby, San Augustine and Nacogdoches Counties in East Texas. They have eight horizontal wells flowing to sale. They've got one additional that's in the flow back period now. And one that's actually being fraced. And they are continuing to drill with two rigs. We're going to evaluate our development plan in light of the opportunities, in light of the lease expiration timing. 2010 we are in great shape. There is a little more exploration that will occur in 2011. We have plenty of time to manage our plan and decide what we're going to do. And we may deploy, like Paul said, some rigs from some of our other Haynesville operations down here. We may end up deciding to add additional rigs. That's going to be decided over the next few weeks. A great opportunity for us and gives us another core area that we have added to our footprint.

Midstream, Doug talked about a little bit, and I mentioned it. That's on slide 21. As I noted, we've completed the 36 inch initial header system. It's got about 200 million a day running through it, as we speak. It's got huge capacity remaining. And we've continued to do a good job in the midstream adding our high-pressure flow lines and gathering production.

We are starting up a 500 million a day treating facility at the very northwest corner of Red River Parish, Louisiana. It ties into Regency, where we have a large firm transportation commitment with them. We have about 475 million a day at that interconnect.

We'll have over 1 billion a day of treating capacity by later this year. And we continue to evaluate our market access, but we've got nearly 1 billion a day or so of firm transportation across the major pipelines that we've noted between Regency, Crosstex, Centerpoint, Gulf South, Enterprise and Energy Transfer.

Shifting focus to the Marcellus activity noted on slide 22. We're initiating our drilling program. We will drill 11 horizontal wells this year. We got our first long-term commitment rig delivered to us in February. It's working very well. And it's helping us to improve our drilling efficiencies.

We are negotiating to add two additional rigs later this year. And we believe that we will ramp up our activity and begin our development program in earnest next year. Like Doug said, we're evaluating a JV opportunity. We continue to gather some science. We've shot 3-D. We continue to add 3-D.

Our two wells that we've completed at this point, one of them was a planned 2,500 foot lateral. It had an IP of 2.2 million a day. The second well we drilled out to about a 4,600 foot lateral. The drilling went great, but then there was some damage to the casing, and in turn we elected to only complete the well at this point over the first 2,500 foot of lateral. So we've got the opportunity to go in and complete the remaining stages of that lateral at a later date. So we'll keep you posted on that.

Land position continues to grow dramatically. Development of this play is going to be keyed around the growth of the infrastructure. So we are very focused on what we can do on the midstream side and ensuring we have access to downstream markets. That seems to be going very well.

With that, I will turn the discussion back over to Mr. Miller.

Doug Miller

Okay. I think most of you know us, and I have been in – many of our major shareholders been in and met Mike and Harold and all the people around here. So the team has been working great.

We are doing what we told you we're going to do. I think we are at or above what we expected. I have kind of a year-end mental target. I am not going to tell anybody. If we can pull off the joint venture, my goal would be to be as close to zero debt as we can get by year-end. But both of the lawyers are scrounging around here, so I probably shouldn't say that. I probably shouldn't say that. With that, I think there are a lot of questions; I am going to open it for questions. We will stick with you as long as you want.

Question-and-Answer Session

Operator

(Operator Instructions) David Heikkinen with Tudor, Pickering, Holt. Your line is open.

David Heikkinen – Tudor, Pickering, Holt

As you think about the joint venture, Doug, and how the structure of combining in the Haynesville, both the pipeline and the E&P business together. That's worked pretty well. Do you think that same structure is integral it sounds like for the Marcellus? Am I hearing you correctly?

Doug Miller

Yes, I think it's more integral up there than it really was in Haynesville. We thought it was critical for us to try to tie them together because of the third-party gas, especially in the Cotton Valley section. We already had a significant pipeline, so we were looking – we interviewed 17 people in the Haynesville, and we actually were looking for somebody that did have an understanding of pipeline and marketing. BG was clearly a perfect fit for us. They market 3.5 Bcf a day around the United States. And it worked out great. We would love to have – I think it's more integral here. That's why we've been delayed.

There is a lot of interest from around the world in doing a joint venture in the Marcellus. And I think a lot of them have just been told by their management, go make a deal in the United States as fast as you can. But there are very few people out there that understand both the pipeline, the marketing, and the critical timing of this high-pressure – I mean, it is basically was non-existent three years ago, high-pressure gathering.

And there is a lot of hoops to jump through. There is environmental issues. There is permitting issues. And it is nothing that's going to happen as fast as the Haynesville. I have been harping on that for two years.

I think this is a development that has huge potential. It's probably five times, six times the size in aerial extent as the Haynesville. It again there will be a few winners and a lot of losers up there with 24 million acres, most of which is under term leases. So we have an attractive position. But teaming up with the right guy is more important right now than teaming up with the wrong guy. And that's what we – we think we have the partner identified.

And we're going to try get over the finish line here in the next – but again, to finish up on your question, we think it's more important here than it really was even in the Haynesville on the pipeline.

David Heikkinen – Tudor, Pickering, Holt

Okay. And as you think about, shifting gears a little bit, on the total leasing and kind of where your targets could go, doing a little less drilling, maybe a little more leasing. How do you think your positions in the Haynesville and the Marcellus look a year from now on a net acre basis?

Doug Miller

David, you're killing me. The thing about it is, if gas stays at $4 or below, they will be a lot bigger. Because what we have seen here over the last, especially six months, with gas cheap I think the big three in the Haynesville with huge acreage positions and drilling commitments pretty much have stopped leasing. So we are seeing a lot of opportunities.

Our group has made some trades in the area. There aren't going to be that many people buying acreage with $4 gas and commit to drill a $10 million well. So most of the smaller guys are not involved. And so we are just seeing opportunities. I think if gas is $6 next year, those opportunities go away. So now up in the Marcellus, you're seeing a lot of big joint ventures. And so those joint ventures, at least, were out looking for additional acreage. But it's so big that we have five focus areas and there is acreage available.

David Heikkinen – Tudor, Pickering, Holt

Okay.

Doug Miller

It's competitive, but it is available. So at $4 gas it wouldn't surprise me if we didn't double the size in each area.

David Heikkinen – Tudor, Pickering, Holt

Okay. And as you think about in the Haynesville specifically, can you talk about terms and opportunities to top lease? And are people looking for less lease bonus and more royalty? Is there a transition as –

Doug Miller

Yes that's a – we have paid since last August as low as $5,000 an acre and as high as $17,500 an acre. I would say – we just did $10,000 an acre on some and got turned down. It's all over the place. But if we run each area as different economics, and our engineers will run it on a risk basis, what can we pay and how much drilling do we have to do to make that rate of return. We are not interested in going out there and leasing 200,000 acres and sitting on it for the rest of our lives. If we look at something, we want to make a rate of return on that asset, and it will be engineered and evaluated appropriately. And whether we have $3 gas or $4 gas or $6 gas, we are going to start monetizing it.

David Heikkinen – Tudor, Pickering, Holt

Okay. And then just specifically on 3-D in the Haynesville, what is that going to accomplish for you?

Doug Miller

Well, what it accomplishes is our faults. And we're trying to identify exactly where the faults are, because we have proven to ourselves that drilling into a fault is a problem. And so there are clearly bigger faults in the area, which we – we know where they are. But I would say that identifying the smaller faults and knowing exactly where you are is going to make it a lot easier.

David Heikkinen – Tudor, Pickering, Holt

Okay.

Doug Miller

And that's all that is. But up in the Marcellus 3-D has faulted, and it's even worse than it is in the Haynesville. So it will be more critical to have 3-D up there even then it is here in Haynesville.

David Heikkinen – Tudor, Pickering, Holt

Okay. Thanks guys.

Doug Miller

Thank you.

Operator

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

Brian Singer – Goldman Sachs

Thanks good morning.

Doug Miller

Hey, Brian.

Brian Singer – Goldman Sachs

Going to the Marcellus, can you just add some more color on the well that you completed, and what you think the well would have otherwise produced without any of the issues had it gone to the full lateral length? And then any learning from the couple of wells you've completed in terms of how you are choosing your future drilling locations?

Doug Miller

That would have to be Hal, because I can't answer that one.

Hal Hickey

Yes. Well first from the shorter lateral, obviously we think if we had drilled – if we had completed it over the entire lateral length, we think we would have had significantly more volume, probably in the four plus million a day range in total. We think that from the drilling that we've done to this point we are learning from both the drilling side and the completion side. We are learning what works best. We are learning what type of steering mechanism to use. We are learning all across the Board. Brian, so it's something that we are continuing with monitor wells.

We drill monitor wells and understand what our frac patterns look like. So we are doing some science there as we do these completions. So there is a lot of opportunity in front of us. There is still a lot of science to be had. But we've made tremendous strides and we understand the rock very well. We understand what it is going to take to complete these wells. But the 3D seismic is going to be critical going forward in certain areas particularly.

Doug Miller

I think another thing Brian is as we ramp up, we will have the ability to get better crews from our service. There are two or three guys out there that are very busy that are keeping the Halliburton's and the Patterson's working pretty good and so as we get busier, we're going to be able to demand better quality equipment and crews.

Brian Singer – Goldman Sachs

Great, thanks. And then in the Haynesville how are you thinking about – and you touched a little bit on this earlier, if gas prices do stay here when you look at your current rig count between – plus the couple of rigs that the Common has, how do you think about total rig count and positioning between DeSoto Parish, Common acreage, and outer-lying counties, assuming gas stays here? Do you just, do you drop rigs? Do you just reallocate to the Common and the DeSoto areas?

Doug Miller

I think that's a question – I think right now we're going to be meeting with BG, because they are our partner. I think right now if with the current curve at $4 here or $4.50, it was going to be our suggestion to shut down in Harrison County and allocate some of those rigs that we have that were budgeted over there and move those down.

I think – we evaluated Common with six rigs running at year-end. I think both us and BG still contemplate that. I think the land is in good shape. I think the opportunity is there. Now the question is, is it four incremental or is it four that we move from Caddo and Harrison? And right now I think me and Steve and Hal are kind of pushing towards let's shut her down in Harrison County, because HBP over there. And at 12 million a day, you saw our chart, the rate of return is less than 10%, and we shouldn't be drilling over there. So I think right now we might – I think we only have two or three rigs up there, so we could incrementally be up one or two with the Common deal, but we would be moving rigs from northern Caddo and Harrison.

Isn't that right, Hal? But I think right now – we have a partner on this. I am giving you my opinion. And we've got a lot of engineers and geologists that are going to be involved in the decision. And I would say over the next 30 days we will make a decision. We will go to our Board and we will give you a new budget. Fair enough?

Brian Singer – Goldman Sachs

Yes. And then very quickly. The common acreage that they don't necessarily have a 100% interest in it, is that something that you and BG would like to ultimately own 100% interest in or are you –

Doug Miller

It is pretty tough to own 100% interest. The two partners in there are large companies that have rights to join, and one of them has been joining. So the answer is, we would love to own more in DeSoto and on this, and we will – we will at least make an attempt.

Brian Singer – Goldman Sachs

Thank you.

Operator

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

Leo Mariani – RBC

Hey good morning guys. A question on couple of Marcellus wells that you guys drilled. What county were those located in?

Doug Miller

Centre?

Unidentified Company Speaker

Centre and Clearfield.

Doug Miller

Oh, it was Clearfield and Centre? Okay, Centre and Clearfield.

Leo Mariani – RBC

All right. Obviously you've got about 11 more wells to drill. Are you planning on kind of spacing it out around your acreage at this point and kind of testing everything? Just give us a little sense of the game plan this year.

Hal Hickey

The focus, like you could see on the slide 22, we are going to drill about nine of those, mainly in sea [ph] counties area in Central Pennsylvania, and we will drill a couple a little farther west. But the big focus is going to be right in Central PA.

Leo Mariani – RBC

Okay. And is that driven by infrastructure? Have you got infrastructure to get wells to sales in the Centre counties and ramp it up during 2010 here?

Hal Hickey

The answer is yes. We are working – there is five different areas, but that one right now, we can go easily to 25 million a day. And with a little bit of capital, it to go up to as much as 200 million a day right there, so that is part of the decision.

Leo Mariani – RBC

Okay. And I guess – obviously, you mentioned midstream as being a pretty big key to the play. Can you kind of give us a sense where you are? You have got five different areas you've identified. Are you actively working in each of those areas to get midstream in place? And when do you think it will be to the point where you can start getting production from each of the five areas?

Doug Miller

Well we are working on it, we have been for the last three or four months. As part of our budgeting for this year, we did budget capital. With the partner that we are talking to, we have gone over it. It's going to be significant. We can expect that – it's a $100 million a year capital program on larger – we are in discussions with big third parties as far as takeaway. We are on target. And it is a – every meeting that we have on the Marcellus, that is a key component of the meeting. But we are working it. And where we are drilling right now we'll be able to take away gas immediately.

Leo Mariani – RBC

Okay. You talked about spending, I think, $33 million in Marcellus acreage in the first quarter. Just looking our presentation, that you guys are still hanging in there right around 186,000 net acres in the play. Are you dropping acres and kind of hydrating here? It just looks like your acreage total hasn't moved very much there.

Paul Rudnicki

No, that is just as of year-end.

Leo Mariani – RBC

Okay.

Doug Miller

I think right now, I think we probably closed 10,000 or 12,000 acres in the first quarter or it was in the last 30 days. And we are trying negotiations, title work on another 30,000.There is a lot of opportunities up there right now, with a big variance in range on the term and on the quality of the leases. We don't want to get into some of these leases in outlying areas where there is two years of term left. We are not interested in those, and we're seeing some of those right now.

Leo Mariani – RBC

Okay. Do you guys still getting five-year terms up there or – ?

Doug Miller

If we are leasing, we are still seeing five to seven years terms with options. Now the price of workers [ph] goes up with every joint venture that gets done, as you can imagine.

Leo Mariani – RBC

Right and what are you guys seeing on royalties these days?

Doug Miller

Good question. The last one we saw – it's hanging in 80% or better. I think the worst we've done is a 20%, but most of ours is in eight.

Leo Mariani – RBC

Okay thanks Doug.

Doug Miller

All right. Thanks Leo.

Operator

Your next question comes from the line of Neal Dingmann with Wunderlich Securities. Your line is open.

Neal Dingmann – Wunderlich Securities

Just had a couple of questions. First, just on Paul's prepared remarks, I think on one of the slides, I'm looking at your slide 10, and it talks about adding additional hedges for 2011 and 2012. Would you do that here or that is more of a, if prices come back up a little bit? If you could discuss hedges a little bit.

Doug Miller

Well, we're actually looking at it right now. It is something that we look at every day. As you can see, with the Common acquisition, if we ramp up to six rigs and to where we think it works, if we – at 549 or 550, whatever 11 is today, if we could lock in a 40% type rate of return, it is something we'd consider.

Neal Dingmann – Wunderlich Securities

Do you think, Doug, it is still just the swaps, the best way to go versus a dollar or something?

Doug Miller

Absolutely. (inaudible) and the reason for – .

Neal Dingmann – Wunderlich Securities

And then just looking on – as far as some of these Haynesville wells, I know I think you'd said – or earlier, had said on another call about on drilling fluids, I think you've gone over now to water-based fluids on a couple of these. What's your thoughts on that? And that is that something you continue to do going forward on more of these rigs?

Doug Miller

Wrong call. Neal, wrong call. I never said that one. That would have been somebody else.

Unidentified Company Speaker

At this point, we are still using oil-based muds.

Unidentified Company Speaker

We are studying water-based. We've got five different companies we are looking at, but we haven't done our first well yet. (inaudible) But, we are studying it.

Doug Miller

Yes. All we are doing is studying it right now.

Unidentified Company Speaker

We will at some point.

Neal Dingmann – Wunderlich Securities

Okay. Okay and then just in these wells, obviously you had mentioned cost. They continue to – despite obviously service costs even coming up little bit, you continue to hold your costs down. Are you still studying sort of fracs, different things to bring these costs down, or should we expect them to kind of come in line around here?

Steve Smith

We're definitely looking at ways that we can bring costs down; it's everything from our completion costs to different drilling. Like you said, water-based mud versus oil-based mud. There are some opportunities out there to cut our costs.

Doug Miller

I think the problem is simple supply and demand has got us. And it is the first time in my 40 years that prices are crashing and prices – and costs are going up. I mean, cost in the last six months – drilling, casing, proppant, everything, and it's purely demand. When you've got Chesapeake, Encana and Petrohawk drilling to hold leases as fast as they are drilling – they have to drill, and they have a lot of demand for services, and it's hurting us. Our costs are up $1 million to $1.5 million a well and gas prices are down 30%. So it's something we're looking at. And I mean we talk about it every day. But I mean it's simple supply and demand right now.

Neal Dingmann – Wunderlich Securities

Sure, sure. And Doug, are you being approached by some of the smaller guys? I guess, as you said, prices continue to sort of stay in here. Is that going to force some of these smaller guys to maybe approach you and have to do something as far as sale some acreage they may be not able to hold?

Doug Miller

Yes, we haven't been approached. Well, we have been approached by some small privates. But another reason for us trying to get as liquid as we can – this kind of reminds me of 1983. Gas price doesn't have to go back to $7 next week. If gas stays at $4 or below for the next six months to 12 months, I think there is going to be a lot of opportunity. I think there is totally – there's a lot of guys up here drilling uneconomic wells today. It won't go on forever. As long as you guys keep feeding them equity and cheap debt, they will keep doing it. But as soon as you quit, we will get an opportunity to buy them. (inaudible).

Neal Dingmann – Wunderlich Securities

Just lastly then on – I know previously you were a little bit aggressive – I don't want to say aggressive, but you were active in the lease block sale out in the Marcellus area. Is there any more of this lease block sales coming up, and would you continue to look at them?

Doug Miller

Well we are looking. We have heard that the state is maybe going to shut some of that down. But any that comes up in our area we will participate in.

Neal Dingmann – Wunderlich Securities

Okay. Thanks guys. Great answer.

Doug Miller

Thank you.

Operator

Your next question comes from the line of Irene Haas of Canaccord. Your line is open.

Irene Haas – Canaccord

Yes hi everybody. One of your competitors, one of the first movers in Haynesville, are talking about testing we restricted flow up in the Haynesville. And I would like your comment, your technical viewpoint on this particular approach.

Doug Miller

Yes. We have heard the same, and we've had a lot of communication with the engineers. We have tested it. Keep in mind, our guys from the very beginning were ramping these things up, and then immediately restricting. And so we have done at least two. Mike and Harold, how are those going? I think we are doing it right to start with.

Mike Chambers

You want to elaborate, Harold?

Hal Hickey

The couple of restricted choke tests Doug is referring to, we've seen a lot of the information that's out there publicly. We feel really good about the choke program we have in place. As Doug mentioned, all the way back – if you go back to our first completion back in December of 2008, we actually introduced a choke management program at that point. So every well we've ever tested we've restricted the draw down and restricted the choke. But some of the other operators are holding further back. They are pulling – they're holding the wells back on, for example, like a 14 or a 16 – 64 inch choke. We've got a couple of wells we've tested. And I would say basically we are probably almost two months into those tests right now. And if you look at the results, it's hard to get real excited about it when you compare those results to our regional wells. But we're watching it. We're going to continue to monitor it and be aware of what others are doing as well.

Mike Chambers

You might elaborate that down in the Common area; their choke program was a little different. And we've implemented our choke program now on those wells down there. I think we are seeing some benefits from that as well.

Doug Miller

I think our guys, whether they are smart or lucky, talked about it a lot when we first started it. And one of the things they came to me and Steve with was, do you want to maximize the life of these things or are you going to show off and have a high IP? And I said, I want to maximize the life. And so that had something to do with our choke program. And it looks like it is working fine, because I'm looking at some of these (inaudible) on these early wells and they are pretty good. We are going to approach 4 Bcf on a couple of wells here that have been on for 18 months pretty quickly.

Irene Haas – Canaccord

Thank you.

Operator

(Operator Instructions) Your next question comes from the line of Kathryn O'Connor with Deutsche Bank. Your line is open.

Kathryn O'Connor – Deutsche Bank

Morning.

Doug Miller

Hi, Kathryn.

Kathryn O'Connor – Deutsche Bank

When you are talking about having a goal of zero debt by the end of the year, how should we think about that in terms of your current capital structure?

Doug Miller

I knew I was going to get trapped when I said that. People here are looking at me. We have about $1 billion of total debt. We have a joint venture, and we also have a possibility of doing a bond offering here over the next little while. I think we have a couple of transactions to either get on or get off of, including the joint venture.

Then we want to scrub or redo our capital program and get it to the rating agencies and go up and see them as soon as we can. And give them – and get these things across the finish line as far as the closing goes. Once we do that then I think I will have a better idea. That's my target. That's my mental target. And with acquisitions coming up I may not – that are out there, we may not be able to achieve it. That assumes no more acquisitions too.

Kathryn O'Connor – Deutsche Bank

Okay. So that was – I guess, getting to my next question was, I guess, in light of the opportunities out there with zero debt really make sense. And I guess what you are saying – .

Doug Miller

Well, zero debt is just kind of – we said out last year we had $3 billion of debt. And we said if we sold this and this and this, we might potentially get to zero. And we are right on target with that. But the thing about it is with cheap gas along comes opportunities, and we are not going to go zero debt just to go to zero debt. We have one – that bank flexibility gives us a lot. We've always used it. With a hedging program and that bank credit facility, if we can find tack-ons, we are going to tack them on.

Kathryn O'Connor – Deutsche Bank

Okay. But I guess if I go back to one of your previous statement, you want to get the JV in order – you want to get your new capital program after your Board meeting, and you want to visit the rating agencies, I guess, before you think about any transactions?

Doug Miller

Exactly.

Kathryn O'Connor – Deutsche Bank

Okay, perfect. Thanks a lot.

Doug Miller

Thank you.

Operator

Your final question comes from the line of Ray Deacon with Pritchard Capital. Your line is open.

Doug Miller

Hey Ray. Hello?

Ray Deacon – Pritchard Capital

Yes hey Doug. Sorry I was on mute. I was wondering, do you see any value in putting capital into the midstream in the Marcellus, or are you going to let somebody else pay for that?

Doug Miller

No, we do see value. The main value is being able to schedule your production. We have been very successful – we see 20% to 30% type rates of return in the Haynesville if we do it right with third parties. I don't know what the rate of return is up there. It's not that great. But I will tell you this, I think one of the things is, we don't want to go out there and spend a lot of capital drilling wells and not produce the well. Steve told me that was a bad rate of return. So there is two things. I believe that done properly in coordination with other operators it could be capital well spent, and we can make a decent rate of return.

Unidentified Company Speaker

Ray, if you don't spend the capital, and you pay for it in a production fee, you end up paying for it anyways and you don't own the asset.

Ray Deacon – Pritchard Capital

Right, okay, it makes sense. I guess just one other question. It looks like if you can back into some math on the Haynesville there is still north of 500,000 acres that's going to have to get held by production. So does this trend continue where your costs in the Haynesville can continue to escalate without the gas price going up?

Doug Miller

I don't know. Ray I think we are at a level right now that is stress point. We are – though we are pushing 200 rigs running in the Haynesville. And the three main guys – and I think it is more than 500,000 acres, by the way, if you add Shell, Encana and Chesapeake and Petrohawk. I am closer to one million to 1.5 million. I think over the next two to three years those guys, if they run it on economics and they have some really good acreage, all three of them are going to drill those wells so they don't lose the leases. Now I think they will also – there is going to be some peripheral acreage that I think they will end up dropping unless gas prices come back. But – .

Unidentified Company Speaker

200 rigs is a stress. I don't see more coming. I think there is better – I think a lot of players think there is better opportunities down in the oil leg of the Eagle Ford so they are going to go spend some money down there. We are not going with them.

Ray Deacon – Pritchard Capital

All right. Got it, got it. Thanks very much.

Operator

There are no further questions at this time. I would like to turn the call back over to Mr. Doug Miller for closing remarks.

Doug Miller

Okay. Well, we should appreciate everybody tuning in. I think what you've seen is, we continue to do what we said we are going to do. We have a couple of wildcards here that hopefully this quarter we're going to get answered for everybody. And that would be a capital program for the Common acreage. We should know that within the next 30 days. And deciding on our joint venture and trying to get it across the finish line. Again, no assurances. And again if we do one, it will get announced. If we sign a purchase agreement, and only if we sign a purchase agreement, and then we will again advise you on a capital program.

We are very enthusiastic on both fronts. We are perfectly happy where we are and we are excited. I think as people come in here, you see that there is a lot of work being done; there is a lot of enthusiasm. We have several thousand quality, what I call, A locations in the Haynesville. So those people are busy. I think what we are trying to determine is how many A locations we have up in the Marcellus. So we are very happy with where we are. We should appreciate your ownership and your patience. But our growth rate is good, and our capital budget is proper. And we continue to drill inside of our EBITDA. And I thank you for tuning in.

Operator

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

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