Comstock Resources, Inc. (CRK) Q3 2014 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Quarter 3 2014 Comstock Resources Earnings Conference Call. My name is Matthew, and I will be your operator for today. [Operator Instructions] As a reminder, this call is being recorded for replay purposes. And now I would like to turn the call over to Mr. Jay Allison, Chairman and CEO. Please proceed, sir.

Matthew, thank you, and thank you for all the stakeholders that are joining us. I know there's a lot of competing conference calls during this hour, so thank you. I've got a few opening comments before we go through roughly 26 pages of slides, where we'll report our results for the quarter. We acknowledge that oil is going through an ugly cycle right now, and we don't nor does anyone else know when or where the cycle will bottom. So before Roland and Mark report, let me make some observations about Comstock. First, we are pleased to report strong growth in oil production, which drove grow revenue and cash flow growth for the quarter. Our [ph] shale drilling program in South Texas continues to be successful, and we are now derisking our 31,000 net acres in the Eagle Ford shale in East Texas. In fact we're extremely pleased that Apache, which has 8 rigs currently active in the play, may significantly increase their rig count. And Anadarko, along with partner KKR, about 10 days ago announcing that they may drill as many as 500 wells in a region that we're in. And we see Clayton Williams at Halcon continuing their drilling programs in the Eagle Ford shale and East Texas. All of that is good news for Comstock because we believe our 300-plus drilling locations in the region will be materially derisked earlier due to all the aggressive drilling in the Eagle Ford shale in East Texas. Our goal to you as a stakeholder -- we have several. We'll put them before you before we go over the results. One, we want to keep a low-cost structure; two, hopefully increase our EURs and IRRs of Eagle Ford wells with new completion designs Mark Williams will talk about in a moment; three, to test our natural gas growth opportunities with improved completion technologies in the Haynesville, where we have 6 TCF reserve potential and over 1,000 drilling locations; four, which may be more important than the others, is to maintain a strong balance sheet in 2015 as we have today. We have about $400 million in liquidity today, and we expect to target our 2015 drilling program close to operating cash flow. And we need to note that we wouldn't like to, but we can manage our drilling obligations in 2015 we think with 2 rigs. Lastly, we want to continue to provide the shareholder with return by maintaining our $0.50 per share annual dividend. When we put the dividend in place May of 2013, we had very little oil producing, and the natural gas was about the $3 range. Today, we have increased our oil production significantly, and the natural gas price is about $4. So with that, let me go to Slide 1. And welcome to the Comstock Resources Third Quarter 2014 Financial and Operating Results Conference Call. You could view a slide presentation during or after this call by going to the website at www.comstockresources.com and downloading the quarterly results presentation. There you'll find a presentation titled Third Quarter 2014 Results. I am Jay Allison, Chief Executive Officer of Comstock. With me this morning are Roland Burns, our President and Chief Financial Officer; and Mark Williams, our Chief Operating Officer. During this call, we will discuss our 2014 third quarter operating and financial results. Slide 2. Please refer to Slide 2 in our presentation and note that our discussions today will include forward-looking statements within the meaning of securities law. While we believe the expectations of such statements to be reasonable, there could be no assurance that such expectations will prove to be correct. Now our 2014 third quarter highlights, which is Slide 3. Slide 3 lists some of the highlights in our third quarter. The 78% increase in our oil production this quarter drove significant increases in our revenues, EBITDAX and cash flow. Our oil and gas sales this quarter of $145 million are up 30% over 2013's third quarter. EBITDAX this quarter of $114 million is 40% higher than 2013's third quarter, and our cash flow from operations grew 60% this quarter to $101 million or $2.10 per share. We reported a small net loss, excluding nonrecurring items, of $2.5 million or $0.05 per share for the quarter. Oil made up 41% of our total production in the third quarter and is expected to continue to increase the rest of the year. We anticipate that oil production will grow 83% to 91% over 2013 production driven by our successful drilling program. In the first 3 quarters of this year, we drilled 59 successful South Texas Eagle Ford wells and put 80 on production. Our well costs keep coming down in our South Texas Eagle Ford program. 2014 well costs have averaged $6.7 million before the KKR promote, which is 12% lower than last year's. We're very excited about recent developments in our 2 new ventures, the East Texas Eagle Ford and the TMS. Both areas have been successfully offset -- have seen successfully offset activity and have been derisked considerably since the beginning of the year. We feel we are back on track in the East Texas Eagle Ford after our second and third wells had completion problems, which Mark will review in a moment. Our fourth well, the Curington, was recently put on production at around 1,000 barrels of oil per day. We continue to increase our acreage position in the Tuscaloosa Marine shale and now have over 70,000 net acres. We're currently drilling the lateral of our first TMS well. Now, I'll let Roland review the financial results in more detail. Roland?

Thanks, Jay. On Slide 4, we recap our oil production growth, which has been driving the growth that we've had in revenues, cash flow and earnings this year so far. Our oil production increased to 12,200 barrels per day this quarter, which is flat to the second quarter rate. We've fallen behind in our new ventures area given the completion setbacks in Burleson County, and then we've had higher-than-expected shut-in activity and especially in the month of September for offset frac activity on 14 wells. Our oil production has increased 78% from the third quarter of 2013. The last quarter of this year, we're expecting oil production to average between 11,500 barrels to 13,500 barrels per day, and that rate will be very dependent on the timing of completions that we have planned for the fourth quarter. Overall, this would give us 83% to 91% growth over last year. Slide 5 shows our natural gas production, which continues to decline and was down 29% from the third quarter last year to 105 million cubic feet per day. With no natural gas-directed drilling taking place this year, we expect our natural gas production to decline further into the fourth quarter and to average around 96 million to 101 million per day. Slide 6 shows our realized oil prices this quarter. Oil price realizations as compared to WTI continued to improve in the third quarter of 2014 but were not as strong as they were last year. We realized $95.92 per barrel, down from the $104.83 per barrel we realized in the third quarter of 2013. Our realized price averaged 99% of the average benchmark at NYMEX-WTI price; 56% of our oil production was hedged in the quarter at a NYMEX-WTI price of $96.60 per barrel. So after our hedging program, our realized price decreased slightly to $95.59 per barrel, 4% less than our after-hedging oil price we averaged in the third quarter of 2013 of $99.20. Slide 7 shows our realized oil prices for the first 9 months of 2014. We realized $97.51 per barrel in the first 9 months of 2014, down from the $103.47 that we realized in the first 9 months of 2013. Our realized price average 98% of the average benchmark NYMEX-WTI price. And 57% of that production was hedged at a WTI price of $96.54. So after hedging, our realized price decreased to $95.71, 8% less than our after-hedging price we averaged in the first 9 months of last year of $104.49. Slide 8 shows our current oil hedges that are outstanding for the last quarter of 2014, where we have 7,000 barrels per day hedged at $96.60. This represents around half of our projected production. We'll look to add some hedges for 2015 maybe for oil or gas depending on how we come up with our 2015 drilling program, but right now, we don't have any positions in place for next year. Slide 9 shows our average gas price, which improved by 16% in the third quarter to $3.85 per MCF as compared to $3.33 in the third quarter of 2013. Our realized price was 95% of the average NYMEX Henry Hub gas price for the quarter. Our average gas price improved by 28% in the first 9 months of this year to $4.34 per MCF as compared to $3.39 in the first 9 months of 2013. Our realized gas price was also 95% of the Henry Hub NYMEX gas price. On Slide 10, we cover our oil and gas sales, which includes realized hedging gains or losses. The 78% increase in oil production and improved natural gas prices offset lower natural gas production this quarter and drove sales up 34% over the third quarter of 2013. Our sales increased to $145 million this quarter as compared to $108 million in last year's third quarter. Oil was 74% of total sales this quarter as compared to 58% in the third quarter of last year. Our sales increased 38% to $437 million for the first 9 months of this year as compared to $316 million in last year's first 9 months. Our earnings before interest, taxes, depreciation and amortization and exploration expense and other noncash expenses or EBITDAX increased by 40% to $114 million this quarter from $82 million in 2013's third quarter as shown on Slide 11. Our EBITDAX for the first 9 months of this year increased by 45% to $346 million from $238 million in 2013's first 9 months. Cash flow has increased significantly this quarter driven by the increase in oil sales and lower interest cost. On Slide 12, you see our operating cash flow for the quarter came in at $101 million, increasing 60% from cash flow of $63 million in 2013's third quarter. Cash flow per share this quarter of $2.10 was also up 60% from cash flow per share of $1.31 in the third quarter of 2013. Our operating cash flow for the first 9 months of 2014 came in at $306 million, increasing 65% from cash flow of $185 million in 2013's first 9 months. On Slide 13, we outline the earnings reported for the quarter and for the first 9 months. We reported a net loss of $1.9 million or $0.04 per share this quarter as compared to a net loss from continuing operations of $24 million or $0.52 per share in 2013's third quarter. Unusual items in our third quarter results include a $12.4 million unrealized gain related to our oil hedges and $11.4 million charge to write off the Mach well. Excluding these items, we would've reported a net loss of $0.05 per share as compared to the recurring loss from continuing operations of $0.40 per share in 2013's third quarter. For the first 9 months of 2014, net income was $1.2 million or $0.02 per share as compared to a net loss of $70.1 million or $1.45 per share in 2013's first 9 months. Unusual items in our year-to-date results were a $2.9 million unrealized gain related to our oil hedges and the impairment and the dry hold costs. Excluding these items, we would've reported net income of $0.14 per share as compared to a recurring loss from continuing operations of $1.15 per share in 2013's first 9 months. On Slide 14, we show our lifting cost per Mcfe produced by quarter related to our continuing operations. Our total lifting costs were $1.55 per Mcfe this quarter as compared to $1.24 in the third quarter of 2013 and have increased from the $1.41 rate we had in the second quarter of 2014. The increase in 2014 is mainly due to higher ad valorem taxes and other field operating cost on the increased oil production we have. Production taxes were $0.39 per Mcfe. Our transportation costs averaged $0.19 in the third quarter. These were the same rates that we had in the second quarter. On Slide 15, we show our cash, G&A per Mcfe produced by quarter excluding stock-based compensation. Our general and administrative costs improved to $0.31 per Mcfe produced this quarter as compared to $0.41 in the second quarter of 2014. Our depreciation, depletion and amortization per Mcfe produced is shown on Slide 16. Our DD&A rate in the third quarter averaged $6.10 per Mcfe as compared to our $4.93 rate in the third quarter of 2013 and the $5.64 rate we averaged in the second quarter of this year. The higher rate is due to the oil production representing a higher percentage of our -- of the total -- of the company's total equivalent production. As we're able to add some proved reserves on the new plays, we hope to see this rate start coming down. On Slide 17, we detail our capital expenditures related to our continuing operations. We spent $446 million in the first 9 months of this year as compared to $249 million that we spent in 2013's first 9 months on our continuing operations. The $446 million includes $71 million of lease acquisition costs, including the acquisition of that 30% interest in the East Texas Eagle Ford shale acreage in Burleson County that we completed in the first quarter. On Slide 18, we outline the components of our 2014 capital budget. We currently are on track to stay within our budget on drilling and completion costs, and we expect to spend about $505 million in total on all our development and our exploration drilling. We now expect to spend about $75 million for all our lease acquisition activity, including the first quarter acquisitions. Slide 19 recaps our balance sheet at the end of the third quarter. We had $6 million in cash on hand and about $1 billion of total debt at September 30. Debt represents about 51% of our total book capitalization. The borrowing base under our $1 billion bank credit facility is currently at $700 million, giving us availability of $395 million. I'll now hand it over to Mark Williams to go over the operations and drilling activity.

Thanks, Roland. Slide 20 shows our South Texas acreage and our 2013 and 2014 drilling activity. We have completed 181 wells so far on our South Texas Eagle Ford acreage through October of this year. Our wells have had an average per-well initial production rate of 736 barrels of oil equivalent per day. Wells reported this quarter averaged 792 BOE per day, higher than last year's average of 780 BOE per day. Slide 21 illustrates our well cost history in our South Texas Eagle Ford program. The cost of our Eagle Ford wells have decreased considerably since we started drilling in August of 2010. In 2010, our first 2 wells averaged $11.4 million. So far this year, we reduced our average well cost to $6.7 million. Faster drilling times, lower well stimulation costs and more efficient field operations account for much of the savings. Our joint venture further enhances our return as the effective average well cost in 2014 to Comstock on an 8-age [ph] basis improves to $5.7 million when that KKR spud fee is considered. Our next group of completions, we will reverse this trend with larger stimulation treatments. The larger frac jobs, which involve more stages, more proppant and more fluid, will increase costs by 20% to 25%. We expect to see improved IP rates and EURs of up to 30% based on this change. The net result could be up to a 50% improvement in well rate of return. Slide 22 shows the acreage we have accumulated in Burleson County, targeting the Eagle Ford shale. We are up to 31,000 net acres in this play. Slide 23 shows recent activity in the vicinity of our East Texas Eagle Ford acreage where we are currently operating 3 drilling rigs. Our first well, the Henry A #1, located in the center of our acreage, had an initial production rate of 1,267 BOE per day. Since then, we've had 2 completion setbacks on the next 2 wells. The casing in the Mach A #1H was damaged beyond repair during completion, and we had to abandon this well. In the Flencher well, only 2,645 feet of the total 7,449-foot lateral is producing due to location restriction in the lateral. With the shorter lateral, this well had an initial daily production rate of 327 BOE per day. On a per-foot basis, this well is performing in line with other wells on the field. We recently completed our fourth well, the Curington, which was drilled to a total depth of 16,620 feet with a 7,095-foot lateral. This well had an initial daily production rate of 996 BOE per day, of which 83% is oil. We are currently completing the Kovar, which is our fifth well, and the frac was completed on November 2, and we're currently drilling frac loads. Our sixth well, the Ozell A #1H, has been drilled and is scheduled for completion in November. We are also moving the larger stimulation treatments in this area with more stages, proppant and fluid. The Ozell will be the first with the new design. While the new design will increase costs, we expect higher production and improved IRRs here also. On Slide 24, we outline our current lease position on the TMS. Our ownership is up to 71,000 net acres at the end of the third quarter. We would -- we should end the year with over 75,000 net acres in this play. Slide 25 shows recent TMS wells, including the very successful Goodrich Crosby well in Wilkinson County. Recent results continue to be encouraging and are illustrating the consistency of this play. Our first well, the CMR Foster Creek 28-40 #1H, is currently drilling just north of the Goodrich Crosby well in Wilkinson County, Mississippi. We have drilled approximately 4,500 feet of the planned 7,500-foot lateral. We plan to drill a second well near the Crosby well and then start the Meeks 56 #1H in St. Helena Parish in Louisiana around the end of this year. I'll now turn it back over to Jay.

All right. Thank you, Mark. And also thank you, Roland. On Slide 26, I'll summarize our outlook for the rest of the year. Growth in our oil production has more than offset the natural gas production declines that we have seen. Our oil made up 41% of our production this quarter as expected to increase 83% to 91% over last year. We're expanding our inventory of oil drilling locations by acquiring acreage in 2 emerging oil plays. We're excited about the level of activity in both of those plays as offset operators have had successful wells near our acreage, and we've now drilled our own successful wells in the middle of the new play in Burleson County. We think we've added over 300 locations in our inventory in Burleson County. We continue to have one of the lowest overall cost structures in the industry. In fact our new completion designs, as kind of Mark alluded to for our Eagle Ford wells, should increase our EURs and our IRRs. Larger fracs can result in 30% higher IP rates and 20% higher EURs. The result is a potential for a 50% improvement in the well's IRR, which could help offset lower realization of oil prices. Improved completion technology opens the door for our natural gas properties in the Haynesville. We have to have good returns even in the current natural gas pricing environment. The longer laterals and better fracs allow these wells to have much higher IRRs. We also have the potential to refrac our 135 producing Haynesville wells, which could increase gas production for a small capital investment. The most important message we want to deliver today is that we will maintain a strong balance sheet rolling into 2015 with the current oil and gas price uncertainty. We have around $400 million of current liquidity, and we'll be targeting our 2015 drilling program to stay close to the cash flow that we will generate. We have a lot of flexibility with our assets and can manage drilling obligations in 2015 with only a 2-rig program. Lastly, again, we currently plan to maintain our $0.50 annual dividend. So for the rest of the call, we'll take questions only from the research analysts who follow the stock. So Matthew, I'll turn it back over to you.

[Operator Instructions] And your first question comes from the line of Don Crist of Johnson Rice. Donald P. Crist - Johnson Rice & Company, L.L.C., Research Division: Starting in East Texas, Jay, can you talk about the current well cost? I mean, obviously, we know what the Mach costs with the write-down. But can you talk about what the Curington costs and what EURs you're are using for that and what you think that will go to with the enhanced completion?

Mark -- yes, I'll let Mark start it. And then, Don, I'll finish it.

Yes, Don, this is Mark. Our type curve has not changed for the area. We don't have enough information yet really to make a change to the type curves. I think our original type curve was around 400 MBO, and that's kind of what we're basing our economics on and our decision-making on. As far as well costs, our first 2 wells were pilot holes. Those costs you can kind of throw out the window with all the science and learning curve and everything else. Our Curington I think should run around 9.5 million, which is kind of what we expected these individual wells to cost with their -- with the original frac design. I think the Flencher was actually a little bit less than that even, probably average maybe in the 9 million range on those. And then the frac design change in this area is not quite as dramatic as it is in South Texas. So we're probably looking at about $1 million to $1.5 million increase in the frac design cost.

And Don, we've -- again, we've -- I think we're on our ninth well now in that East Texas Eagle Ford program. I know we're drilling on Platsach [ph] With 2 rigs. We have 3 rigs active there today. We've got a Helmerich & Payne rig that's kind of the roving rig, and it's drilling on all 4 to 6 sides of the acreage that we own, the 31,000 net acres. And then we're infill drilling the first Henry well that we drilled. We've got 2 rigs active infill drilling that. And again, if you -- I mentioned earlier that's -- kind of to the west and to the north of that is where Anadarko had announced their big program. We think with KKR and Apache it's like, I think, to the north of it. So -- now, and another thing I would comment on, the well spacing. The wells that we're drilling right now are anywhere from 800 to maybe 1,000 feet apart. We're going to drill probably 6 or 7 of those. I think some of the offset operators are drilling wells on 500-foot spacing, so we don't really know which is the best formula there. We're going to do both. And in the interim, we're going to drill, hopefully, on all 4 to 6 sides of our footprint and materially derisk that by year end. Our goal beginning of -- really the end of 2012, beginning of 2013 when we knew that we would monetize the Permian -- and if you think about the time frame on that, I think it was May of 2013 that we got the wire and we made the $231 million of profit. So we knew that by the end of this year, our South Texas program we would've drilled at least 2/3 of our locations in South Texas, and that's going to be true. So we knew a year ago that we had to start adding new regions, and that's when we added the East Texas Eagle Ford. Again, we think we have more drill sites there than we've ever had in South Texas because we have more acreage and we don't have a partner. And people would ask, "Do you know -- do you -- can you get a partner?" Well, I don't know. Well, a week ago Monday, 10 days ago, KKR, which is our partner in the South Texas Eagle Ford, joined Anadarko. And I think the lease cost were anywhere from $10,000 to $12,000 an acre. We've got -- I think, we have $100 million in our 31,000 net acres more or less. So it looks like people are excited about the area. It looks like there's a lot of activity in the area. It looks like we did trip and fall on 2 wells, and we acknowledged that early on. If you notice in South Texas, we were at 59 for 59 or whatever. So we've got a really great track record there. And I think the wells that we're drilling now we're experimenting a little bit on do we need to increase the cost to drill and complete this wells, mainly the fracs; and if we can spend another $1 million and have a 50% increase in our IRRs, then that would make sense. If not, Don, we can pull back in and we can drill wells for less money and put a smaller frac on them and downspace and drill more of them. But I think to enter the Burleson County area when we did and how we did with -- again, I think we could keep one rig busy there for all of 2015 and meet all of our lease obligations. I think we've made some good moves. Again, we -- I think this time last year we had about 6,600 barrels of oil per day in our South Texas Eagle Ford, and they were, what, 12,000, 12,500 or something and growing. So I think the program works even though it doesn't show up in the stock. And our liquidity, we haven't given up any of our liquidity to add the plays out of the East Texas Eagle Ford or the TMS. So I guess that's a long way to answer your question, but it gives you a little bit of the future and how we got here and where we think we're going. Mark didn't comment on the William well. We're at about 3,400-foot in our lateral length. And then on the Henry 3, we're about 6,400-foot on our lateral length. So the wells after the Flencher and the Mach -- knock on wood -- we haven't had issues. So maybe we're through that turbulence. But I think you need to know we'll tell you when we have some turbulence. And we had it, and we report it, and we wouldn't be adding a second, third rig in that area if we didn't get a [indiscernible] so... Donald P. Crist - Johnson Rice & Company, L.L.C., Research Division: Right, and you touched on it in some of your comments there, but can you walk us through your current 5-rig contract schedule and the flexibility that you have in actually dropping those rigs and when those can be dropped if the current environment persist?

Yes, we have a rig on contract through November of 2015. We have another one August '15. We have another one December '14 and another one. The other 2 are kind of mid '15. So all of those, I mean, they're all in pretty good shape. If we wanted to drop a couple of rigs, we could have. We have a 5-rig program right now. We have 1 in South Texas, 3 in East Texas, 1 in the TMS. We do have a rig that is on order that we can bring in and either add it to the fleet or get rid of one that we have, but there's some flexibility in what we're doing. We don't have 2- and 3-year rig contracts at all. Mark may want to add some color to that, but that's what I know.

That's exactly right. Everything that we currently operate expires by the end of next year between now and -- between December 31 this year and the end of next year, so we have a lot of flexibility to reduce the rig count if we feel we need to.

And I think that going into the TMS, I mean, we're extremely positive about the TMS. I mean, we think the reserves are in place. The issue there is can you reduce the cost? And I think the other operators in that area have shown you that their EURs are exceptionally strong, and their drilling costs are coming down. Now the wells that we're drilling, I mean, we're going to spend probably 80 days or so drilling this well, maybe longer because it's the first well. We're drilling a pilot hole. We had to deepen it. We had to log it. We had to plug it back and then we had to -- and that's the well that we contribute the data to this consortium of companies. And so you -- we knew it'd be longer, take a longer time to drill it, but the question is can we drill those wells in the TMS in 35 days or less? And we think we can. But I think more important in the ugly oil cycle that we're in is do we have to drill any wells in the TMS to hold our 70,000, 75,000 net acres. And what we've looked at, right now we would keep this rig busy through the third well, which is the Meeks well. We'll drill the 2 Foster Creek wells. And again, the well we're drilling now in the TMS we're offsetting the single best well in the play, which is the Crosby well -- the Goodrich well. So we'll complete that. We'll drill another well pretty close to that. We'll drill the Meek well, and then at that point in time, with a low oil environment, we could shut the program down and -- I mean I don't think we'd lose any acreage in 2015. I mean, maybe we have to pay $1 million or $2 million to extend some leases or something, but it's very, very nominal. We could shut the program down after these 3 wells. And we're going to look at doing that. We may take this -- it's $72 million a year to keep a rig busy. I mean, the stock is $10 today. I'd rather own 20% of the company for that amount of money. I mean, our liquidity is almost equal to our market cap. It's that type of silliness that's going on out there. We didn't enter the Burleson area at $10,000, $11,000 and $12,000 an acre. We've got 31,000 net acres net for about $100 million. We didn't pay up to get in the TMS. We've 70,000 to 74,000 net acres for about $74 million. We've spent $10 million or $12 million, whatever it is, on one well. We hadn't spent hundreds of millions on wells out there. We hadn't spent anything on the Haynesville in 3 -- in 2 years except 2 wells that we drilled in 2013. And you may want, Mark, to go into a little bit about what we're thinking about the refracking of the 135 wells that we drilled and the longer laterals. I mean, our return to the $4 gas in a vast majority of the Haynesville area, they're pretty phenomenal, and they whip the returns we get on our oil play. Now we've got to go in and see if they're real because we haven't drilled a longer lateral and we hadn't refracked any of these wells. But that's what we think. And we're going to focus on that in 2015 also.

Your next question comes from the line of David Amoss of Iberia Capital.

Jay, I want to ask again on -- a follow-up on the refracs in the Haynesville. Do you guys have kind of an order of magnitude estimate on what that may cost? And then, how quickly can you get going on those? And when should we see the first flood [ph] of results from that program?

Yes, and again, I want to preface all this. This is kind of early innings, but I mean, we're super excited about it. But it is early innings, and what we don't want to do is go spend a whole lot of money and figure out it doesn't really work as we would project it to work, even though there's 2 or 3 companies out there doing it right now. So I mean, we're -- we always take that baby attitude; that's a little bitty baby step at a time. And if we see it works and we'll be a Michael Johnson and be a world-class sprinter but -- so with that, let me give it over to Mark, and he can give you the color that he wants to give you right now.

All right. Yes, David, this is Mark. As far as costs go, we think those costs will range between $1.5 million and $1.8 million per well to go [indiscernible]. We've got to remove the tubing, clean the well out, refrac it, reinstall the tubing, flow the well back, do all that to get them cleaned up. So that's kind of what we're looking at. We're screening candidates right now and plan to have something in place to -- kind of a pilot project on this about right around the end of the year. And then we'll look at those results and build the component of our budget next year based on those results. It'll probably be an add-on to the budget or a change in the budget sometime next year if we see the results are positive, but we're not talking about a big incremental change in budget dollars when you're talking about $1.5 million a well. And if you did 10 of them, you're -- it's $15 million, so it doesn't really move the needle much capital-wise. But results, we've heard anywhere from $1.5 million a day up to about $4 million a day, kind of on the high end is what we've been hearing from some of the other operators. We plan to try to share information with some of them to obtain more data on what they've done and what's been successful to help us along the way too. But right now, I'd call it kind of a pilot project and not really an implementation of something known. Kind of like Jay said, we want to prove to ourselves it works and then we'll look at implementing it on a grander scale.

Now in addition to that, we are thinking about redrilling -- drilling some of the Haynesville wells and drilling them out either 5,000-foot or 7,500-foot laterals. And with the new completion techniques that debuts in the Marcellus, elsewhere, you take that new-age technology in the Haynesville, I mean -- yes, the Marcellus is the #1 shale gas field in the world, but it had to jump over to Haynesville in 2012 to get there. And the Haynesville was developed with old completion technology. You add some of that in -- the new technology in today, and it's going to be pretty eye-opening we think. As far as the rate of return we might get at the Haynesville program, again, we've owned that acreage forever. It's been paid for forever, and we've only drilled 10% of our footprint. So we think there's a lot of upside, particularly gas is $4 today, and winter has just started. So we will take a hard look at that, and sometime in the middle of December, we'll come out with our 2015 budget. And if you need to know as a stakeholder, we have no hedges in play for oil or gas in 2015 right now. So we're going to take where the SRP [ph] is and work in a budget and see what that will allow us to spend in all of our areas knowing that the 2-rig program we can keep all of our acreage, but knowing that we need to grow our production. But more than grow it, we're going to look at rate of return. That's where we're going to be focused on.

Okay, got it. And then one more. In East Texas, some exciting results there. It sounds like you're increasing the rig count as we speak. Mark, can you kind of give us -- if you're in development in '15 and your pads, how quickly are you drilling those wells? And I guess, the number I'm really after is 3 rigs can drill how many wells in development mode in '15.

David, we've been drilling our wells -- our well time from spud to TD has been averaging about 19 days. So on -- pad to pad, you're looking at about 10 days. And on an existing pad, you're looking at about 5 days. So say, on average, about 26, 27 days. So you're looking at 13 wells per year per rig is about a pretty good average. Maybe 14 if we improve things a little bit.

Your next question comes from the line of Jeffrey Campbell of Thule Investment Research.

First thing I wanted to find-- this is -- not trying to kick you when you're down. I just want to kind of understand it better. Can you add some color on why you had the casing failures in East Texas and what you're doing differently to avoid it in the future? What you learned from it?

Yes, look. That's not kicking us when we're down. That's just a good, honest question, so we should be accountable for that. And I'll turn it over to Mark to be accountable. Mr. Williams?

Yes, Jeffrey. Yes, really we had 2 different issues on 2 different wells. The first one, the Mach, we kind of -- an issue where we perforated a little bit higher in the section than we really probably should have, and we had ended up resulting in a casing collapse above the last set of perforations. When you run the calculations on the strengths of materials and things like that, there's no reason it should do that, but it did. So it's -- one of the things we're doing there is we're going to be cognizant of that fact and be more careful to stay away from our intermediate streams, stay away from the upper part of the Eagle Ford down -- stay more down in the target window with our perforations and eliminate that issue in the future.

And even though we shouldn't have collapsed with the integrity of the casing, we did make a human error, and we completed it too far into a depleted formation. So it's a human error. We did that. That's a corporate failure. And we -- it is what is, so we don't color it any different.

On the second well, on the Flencher well, we had a casing obstruction after the sixth set of -- sixth frac stage when we went in to drill out the plugs. And we've looked at our frac data. We don't see any indication of that during the frac job. We believe that is probably a geologic hazard that we -- a small fault or some type of movement that we created with the high pressures of the frac job. We see that on a rare occasion in both the Haynesville and the Eagle Ford, and we hear about it in the other plays as well. It doesn't happen often. I mean, it's been much more prevalent in the TMS than it has been in the other plays. It doesn't happen very often, but it does happen. The main things you try to do there is you try to minimize drilling through any geohazard that you can see with any seismic that you have available. The other thing we did is we changed our casing design. We basically strengthened it one step up. And even though there, again, when you run the numbers, it shouldn't have come close to a failure point; but just to provide us more safety factor, we've increased that, and then we're looking for any geohazards on our steering plots. And if we see one, we'll adjust the perforations to try to avoid that a little bit more than we have in the past to try to minimize that risk of that happening in the future.

Okay, that was more forthright color. I appreciate it. You brought up the subject of TMS and cost, and I think it's pretty obvious that's what people care about because we're seeing good wells coming out and no one seems to care. Can you give us some kind of idea of what sort of combination of EUR and well cost you would need to get to, to be able to be able to make acceptable returns in the TMS if we stay in this sort of persistently low oil price for a while?

Well, I think what we look at initially, I mean, we were hoping we could have somewhere north of 500,000 recoverable EUR and -- I mean, I think Goodrich averages 500,000 to 600,000. I think that's very achievable. And I think even in Canada, they said 600,000 to 750,000. I mean, we -- when we went in the TMS -- you have to go back when we went in. And when we went in it, Encanca have not had the success they had this year. They had failures. Devon had had their failures. Halcon had had failures, and then they reentered it. Sanchez is not there, and Goodrich was struggling. In 2013, I think, there's 6, 7, 8 of the TMS wells may be drilling completed. This year maybe there's 50 or 60. And we went back in it geologically because our geological -- geophysical group felt like the oil was in place. So that's one of the big checks is if we can reduce the drilling and completion costs for the reserves there, we've got to let [ph] that work. That's why we've got that little stretch of property maybe 60 miles long, 20 miles wide or so. And then as Halcon comes back in and Encana has success and others have success, we say, "Wow, we think our geological group was right in the core." And then again, we -- the very first anchor that we put in the TMS was Wilkinson County because we wanted to -- the big old oak tree is the Crosby well, which Goodrich has, and we wanted to be near it. So we lease from the Crosby family that 33,000 net acres. So as it has been derisked, we said, "Well, okay, the reserves are there." The question is though, do you drill above or below the rubble? Well, it took companies a couple of hundred million of dollars to figure out you probably drill below. And then the question is, well, what are your real costs? I mean, these costs initially to drill and complete were $14 million, $15 million, $16 million. Then they were coming in at $14 million and then $13 million. And then when you see this kind of these companies being able to repeat their success without having glitches, that was the big thing for us. I mean Goodrich, I mean, they had 5 or 6 wells with no glitches, and then Encana had wells with no glitches. Now again, we're -- if you look at our first Foster Creek well, you'll say, Oh, my goodness. This horrible, terrible, Charles Barkley bad." No, it's our well, and it's the well that we said we did all the science [ph] project and we would contribute to the other 4, 5 in this consortium of companies. We're 4,700 feet to lateral on that, but we think that you should be able to TD these wells anywhere from 30 to 35 days. And if we can have 500,000 to 600,000 EUR, not even a 750,000, and have $11.5 million well cost, we think it will be -- I mean, these are going to be viable at $80 oil. That's what we think. Now we -- we're not there. And I think the beauty of that is other people have had great success. We're not there, but quite frankly, we don't have to be there right now because when we leased our footprint we assumed that it would be the end of 2015 before that play would start being derisked, and it's been accelerated with the success that the peer companies have had. So that's how we look at it. We look at risk. We look at rate of return. We focus on return. We don't focus on aggressive production ramps [ph]. We don't focus on, "Well, how many acres per well? Is it 160 acres? Do you have 200 to 400 drill sites?" We don't really care. We try to blend the company in with what kind of gas opportunities, what kind of oil opportunities, and then there's all kinds of different regions for oil opportunities to not get in trouble and to grow and to create value per share. And again, we haven't issued any equity for 10 years. So we're trying to protect that share value, and that's our -- that's how we look at it in the TMS. Now, Mark, do you want to add to that?

I can add a little bit to that, Jeffrey. Jay was accurate on the cost. I mean, our initial model was around $14 million for these first wells without problems. And then once we got into kind of drilling mode on single well pads, we're looking at about $13 million. And then our plan in kind of full a development mode with the efficiencies of scale, which should get cost down between $11 million and $12 million. So if you look at that at $80 oil and 600,000 to, say, a 500,000 MBO type curve, you're still looking at probably 25% to 30% IRR. If you're at a 600,000 MBO-type curve, like Encana and Goodrich, or projecting off their wells, you're probably still looking in between 30% and 45% IRRs. So I mean, it's an economic play. If you can eliminate the problems and get more consistent results. And obviously, with us, we just have to drill one well. So far, we don't have anything to make -- to talk about from a consistency point of view, but we're seeing it with Encana and Goodrich and Halcon in the field in terms of being able to drill the wells with many less problems than they were having early on and stimulate them and get them on production at pretty significant rates, and the wells are holding up. So we're pleased with everything we're seeing. We just need to get on that learner curve with those guys and prove we can do it.

Yes, that repeatability factor, that's what the play needs. It needs to be repeatable from 1 or 2 or 3 operators, including ourselves. And then you can structure in that cost and then -- I think the EURs are going to be really good. We would never worry about the EURs. We always worried about the costs.

I think that was a very helpful overview. If I can ask one last question. I was just wondering -- because we've talked about this before -- what's the current timeline to do a test of the wet gas in the East Texas acreage? And is that going to be delayed due to the current commodity prices? And that's it.

Now once the William well is KD'ed [ph], which the William I think we're 3,400-foot lateral right now, I think that well moves over to the Lewis. I may be wrong, and then the Lewis is kind of southeast. Is that right, Mark? Is that where it goes?

Yes.

And then that'll start testing -- again, the southeastern part, which is where we think we'll probably have 60%, 70% oil, and the rest gas. I mean it'll be...

Yes, I think we -- we're working our way down depth kind of as we built units and can get units put together. Texas is a much more difficult land situation to build long units than Mississippi and Louisiana or so it -- it just takes more work to do that. But I'll say this, we don't have any wet gas acreage that we -- as far as we understand it, we think we are either black oil or volatile oil. So I don't know that we're going to test the wet gas anywhere.

Yes. It -- I mean, we're as excited about that acreage as any of our acreage. And then we'll move that rig north, kind of northeast, and it's what's what we call the Kathy well. And that's an H&P rig. It's kind of the roaming rig that's drilling all 4 to 6 sides. And then we'll use a couple of rigs to drill these pad wells with the Henry, and they will come out in the middle of December with a budget for 2015.

Okay. That's helpful. And yes, we'll stand corrected and call it volatile oil from now on.

Your next question comes from the line of Sean Sneeden of Oppenheimer.

Roland, certainly appreciate the commentary on living within cash flow next year. Just assuming if you were to do that, what do you think your overall production decline profile might look like?

I think looking that we'll -- looking at next year's opportunities, that we won't have a production decline. We'll actually be able to -- if we add some -- a little capital toward the gas side, I think we'll be able to maybe have a little bit of growth in gas production and then have a -- we'll probably have a fairly low increase in oil production given that we ramped it up so much this year. So we're still looking at what and where we want to allocate the capital to, to generate the best type of production profile for next year. And given commodity prices are moving around a lot now, we'll make our final decisions in December. But I think by taking away the gas decline we've had this year I think our overall production probably won't be down next year like it is this year.

The models we've looked at right now -- we've got several different models,. We've already looked at them. We -- like Roland said, we'll have -- if you stay total within cash flow, we should have slight oil growth, and we could have -- depending [ph] upon how the wells turn out in the Haynesville, you could have some pretty decent growth in gas, and the numbers look pretty decent. And that, again, that's keeping our almost $400 million of liquidity. That's pretty phenomenal for a company like ours.

Sure. No, that's helpful. Maybe as a follow-up to that. If you were to kind of ballpark your current corporate PDP decline, where do you think that stands as we sit here today?

That's hard to gauge, but I think the gas is, obviously, a lot much more mature now and not near a lot of -- we don't have a lot of the -- the higher -- the early years that have the higher declines in the gas production. So it's probably 15% to 18% kind of base decline expected as we get beyond the fourth quarter.

Well, we've got a lot of new oil online, so I'm sure that GDP is fairly -- is still fairly high, over 50% type decline in our oil production with no new drilling.

Okay. No, that's helpful. Maybe just one last one on the balance sheet. In order to have -- how I should be thinking about next year, but would you say in broad strokes that your general goals is to maintain leverage under 3x and have a minimum of, call it, $150 million or so of liquidity? Or maybe talk to me -- talk a little bit about how you're thinking about that.

Yes, definitely. Those -- we would definitely want to exceed the 2 goals that you just said, both on the leverage -- our overall target is to stay at 2.5x, and that's been -- that's our -- one of our -- that's the number we feel like we should be -- try to keep the company around, so -- and then we'd like to have a little more liquidity than that, so at least a couple of hundred million, $250 million of liquidity that's just available that's not committed to a capital program. So yes, we really have more than that now, so it's really about what do we spending for next year. This year, we invested a lot in acreage. We don't really see a need to invest in acreage next year. We've got a lot of big portfolio projects to work on. So we'll see -- we'll just see maintenance costs to maintain our acreage next year and not the big investment there.

Well, I think with the derisking of our East Texas Eagle Ford footprint, I mean we're -- when you add that with the TMS, companywide we'll have never had more drilling locations, period. Plus we will have never had higher oil production rate. Plus we've never had a higher potential program in the Haynesville. When we first drilled the Haynesville in '08, '09, '10, '11, it was in the infancy of shale completions. I mean, I think we're sitting on a gold mine. So with a good balance sheet -- and all that was because we never really felt comfortable that oil is $100-plus commodity, and we made the greatest derisking move in our corporate history by selling the Permian and monetizing that. And like Roland said, then we spent -- out of our $231 million of profit from that, we spent about $175 million on the acreage position that we have in the TMS and East Texas Eagle Ford, and I think those were good bets. And we intentionally looked at how the leases were structured because we thought if oil prices collapsed which -- I've been doing this 20 -- 34 years and at least 6, 7, 8 of these horrible cycles -- and that's not only oil, it's gas too -- you have to prepare for some downtime. And we didn't want to monetize the Permian and get in trouble with lease obligations and get back in the same rut, and you can see today we're not in that rut. But that's -- a lot of that was -- most of that was intentional. Some good fortune, but it was intentional.

I now would like to turn the call over to Mr. Jay Allison for the closing remarks.

Matthew, again, I love your speech. I know you're not from Texas, and I'm so thankful that with the competitive companies that have the conference call between 10:00 and 11:00 those of you that chose to listen to this, I mean, we're going to work our hardest every day. We're not going to color something different than what it is. If it's really good, you'll know it. If it's really bad, you'll know it. And if we're in tents [ph] somewhere in between, you'll know that, too. We acknowledge that oil is in an ugly cycle, and we think it could get worse. Now I hope it doesn't. We hope gas stays at $4 or above. And our commitment to you is to not lose our liquidity and to manage this company as you would expect us to because you trust us if you're a stockholder. So with that, I'll adjourn the meeting. Thank you.

Thank you for joining today's conference, ladies and gentlemen. This concludes the presentation. You may now disconnect. Good day.