Comstock Resources Inc (CRK) 2017 Q1 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Comstock Resources Inc. Q1 2017 Earnings Conference Call. (Operator Instructions)

I would now like to turn the call over to Jay Allison, CEO. Please go ahead.

Perfect. Thank you, Ayla. Welcome to the Comstock Resources first quarter 2017 financial and operating results conference call. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and downloading the quarterly results presentations. There, you'll find a presentation entitled First Quarter 2017 Results. I am Jay Allison, Chief Executive Officer of Comstock. With me is Roland Burns, our President and Chief Financial Officer; and Mack Good, our Chief Operating Officer.

During this call, we will discuss our first quarter results and financial results. Please refer to Slide 2 in our presentation to note that our discussions today will include forward-looking statements within the meaning of Securities laws. While we believe the expectations of such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. If you look at our 2017 Q1 summary, which is Slide 3, I'll make a few comments before we go over that.

It's our corporate goal in the first quarter to transition Comstock's operations into a steady 2-rig drilling program with a third rig added in our JV area with USG. Although you'll find out that we do had some delays in the quarter, the results today are all excellent. We currently have 3 rigs active in our Haynesville program and the wells from our Generation 2 completions are performing above the type curve. In fact, 2 of the best wells we have ever drilled were drilled in the last 3 months being the Furlow 25-36 and the Billingsley 25-24 wells, which Mac will update you on during his presentation.

Also, our acreage within our Haynesville shale JV has grown and is expected to see material growth by year-end.

Now on the financial side, Roland has excellent news on where our production is today. Yes, our first quarter natural gas production averaged 156 million per day, up 23% from the fourth quarter 2016 but our current production is much higher than that. Our cost structure improved during the first quarter, mainly due to low finding cost of the Haynesville shale wells and our total liquidity [are] $155 million. Both our balance sheet and liquidity continue to improve as we grow our cash flow and EBITDAX. And in the future, it is our corporate goal, as each one of you know in this call, to give you the operation results that will result in the conversion of our second lien notes, which will significantly improve our balance sheet.

Then kind of on a side note, we want -- I don't think we can ever say thank you enough. We want to say thank you to the bond owners, the equity owners who believed in us in the Haynesville program even going back to early February 2015 when we were really the only E&P company that was just focused on the Haynesville. I've noticed since April 13 of this year through last Thursday, oil prices have dropped $7.66 a barrel while natural gas has fallen only $0.04 per 1,000 cubic feet. So as a Comstock team, I believe that we are in the right commodity, natural gas at the right time where supply is down, the demand is growing. And at the exact right field, which is the North Louisiana, Haynesville/Bossier play.

So now, I go to Slide 3. A summary of our first quarter is outlined on Slide 3. Oil and gas prices improved in the first quarter leading to stronger financial results. Oil prices were 84% higher, and natural gas prices were 57% higher than the very low prices we had in the first quarter 2016. Our sales grew by 46% to $54 million, and our EBITDAX increased by 133% to $34 million, highlighting the significant improvements to our operation -- operating cost.

Cash flow from operations for the quarter was $16 million, a $30 million turnaround from the deficit we had in the first quarter of 2016 of $14 million. Our Haynesville program is kicking into high gear now, which will be reflected in our second quarter production numbers. We grew our gas production 23% in the first quarter as compared to our fourth quarter production, adjusted for the property sale we completed in December of last year. All of the Haynesville and Bossier well drilled continue to perform above our type curve. Two of our Gen 2 completion wells recently set new IP records for us, coming in at over 30 million per day. We're very focused on improving our balance sheet, as you know, by growing our cash flow and EBITDAX. We have total liquidity of $155 million, which is more than adequate for us to carry out our current drilling program. And we have also hedged almost 100 million per day of our production in the second half of this year at an attractive $3.38 per Mcf.

Roland, I'll turn it over to you to go over the financial results.

Thanks, Jay. Slide 4 shows our natural gas production from major regions. In the first, our natural gas production averaged 156 million per day, up 11% from the first quarter of 2016, and up 23% from the fourth quarter if you exclude production that we divested up last December.

We had a 45-day delay in bringing on production from the -- our 2 Furlow wells and the Billingsley well that we reported on this quarter, but the results were worth the wait as these were some of the best wells we've ever drilled. We expect our natural gas production in 2017 will average between 200 million to 230 million cubic feet per day. And in the second quarter, we're seeing a significant ramp up in gas production. For April, our gas production was approximately 175 million per day. And for this month, we're averaging over 200 million a day.

Slide 5 shows our hedge position we put in place to lock in the high returns on the Haynesville shale wells that we're drilling in 2017. We had 70 million per day hedged in the first quarter at $3.37 per Mcf. This increases to 81 million per day in the second quarter and 99 million per day in the last 2 quarters, all at $3.38 per Mcf. We've also hedged a -- just part of our 2018 production at the same price.

On Slide 6, we summarize our oil production. Our oil production averaged 2,900 barrels per day in the first quarter, showing a continual decline due to the lack of any oil drilling since 2014 and the sale of our Burleson properties in 2015. With no drilling activity budgeted for this year at our oil properties, we expect our oil production to decline further and expect oil production this year will approximate between 2,225 barrels per day.

On Slide 7, we show how our producing costs have trended as we've shifted towards our lower cost Haynesville shale properties versus the higher cost oil properties. Operating cost have improved at $0.97 per Mcfe this quarter as compared to $1.40 per Mcfe at -- back in 2014, and $1.10 that we averaged in 2016. With much of our production from the new wells in the Haynesville shale being exempt from production taxes in their early years, our production average -- our production taxes averaged only $0.07 in the first quarter as compared to $0.36 back in 2014 and $0.08 in 2016.

Field level costs are also down. They averaged $0.64 in the first quarter of this year compared to $0.97 last year -- I mean $0.97 back in 2015 and $0.76 per Mcfe in 2016.

Our DD&A per Mcfe produced has come down dramatically also and had averaged $1.90 per Mcfe in the first quarter compared to $5.74 back in 2014 and $2.26 in 2016. The improvement with our cost is due to the low finding cost of the Haynesville shale wells. We expect to see further improvements to our producing cost and expect the per-unit cost to continue to improve as our gas production volumes grow the rest of this year.

On Slide 8, we summarize our first quarter financial results. Improved oil and natural gas prices and lower operating costs drove improvements to our sales and cash flow. Oil prices improved by 84% and natural gas prices increased by 57%. Our oil and gas sales for the first quarter were up 46% to $54.3 million from the very weak first quarter 2016. EBITDAX was up 133% to $34.2 million, and operating cash flow of $15.9 million was substantially improved from the cash flow deficit of $13.9 million in the first quarter 2016.

As we pointed out a minute ago, we had very significant improvements to many of the operating cost items. Lifting costs in the quarter were down 18%, and our DD&A was down 23% due to those lower operating costs rates we talked about a minute ago.

Our G&A costs were up by 15% as our activity level has increased substantially over last year. Overall, we reported a loss of $22.9 million in the quarter or $1.61 per share. Unusual items in the loss we reported in the quarter included an unrealized mark-to-market gain at our hedge position of $7.4 million and noncash amortization of the discount recognized on the bond exchange we completed last September of $55.4 million.

Slide 9 shows our balance sheet at the end of the first quarter. We ended the quarter with $30 million of cash on hand and $1,172,000,000 of total debt outstanding. Including our undrawn credit facility and the available pay-in-kind interest feature of our first lien bonds, our total liquidity is $155 million.

On Slide 10, we recap our capital spending in the first quarter and then our drilling budget for all of this year. We spent $36.8 million in the first quarter drilling 3 wells, 2.5 net wells and completing 9 other wells, which were about 4 net wells.

We plan to drill 20 or 15.3 net additional Haynesville -- total Haynesville shale wells this year for a total estimated capital (inaudible) first quarter of $145 million. We also have about $5 million budgeted for nondrilling expenditures. And we're tentatively budgeting an additional $17.6 million for 2 or 1.7 net Bossier shale wells that may be drilled later year depending on natural gas prices. So basically, we're very much on track for our original capital budget put out for this year and we really see no changes in those numbers.

And Mack will now kind of takeover and bring you up to date on how our drilling program is going.

Okay. Thanks, Roland. Slide 11 is the usual one that you've all seen before. It shows our 68,000 net acres in the Haynesville play. And as I mentioned in a previous conference call, we're working with USG to add to this acreage position as part of a JV. And as a result of this, the JV currently has over 6,000 net acres and during this month, we plan to spud the first of several planned 10,000-foot laterals on the JV acreage. As most of you already know, we will operate this JV and we'll start off with a 25% working interest in the first few wells. As always, we are also working on improving our acreage position both as part of the JV and outside the JV. Our efforts include increasing our ownership level in future JV wells along with leasing and/or trading acreage with various parties. All of these things will obviously create an opportunity for us to grow both production and reserves. We'll talk in greater detail about all of these efforts later after the ink is dry and [latched] up.

Slide 11 is also providing a quick comparison between our 2016 and 2017 drilling programs. And simply put, we're drilling twice the number of wells this year than last, and we're completing those wells differently as well.

Anyway, let's flip over to the next slide so you can get some more detail on what we've been up to in the Haynesville since we reentered the play in 2015. And I know Slide 12 is getting a little busy, but we're still able to show the locations and the IPs of all the program wells we drilled and completed from 2015 through 2016 and so far this year. All of the wells that we spud this year have the gold labels. The gold 2017 completed wells on the map have IPs ranging from 25 million a day to 36 million a day, and all of them received our June 2 completion design at 3,800 pounds per foot of profit. The lateral lengths of these wells vary from 5,396 feet to 8,521 feet. The Furlow 25-24 has the shortest lateral at 5,396 feet. And you see, it tested at an IP of 25 million a day. The Furlow 25-36 has the next shortest lateral at 6,355 feet and it tested at an IP of 32 million a day. After that, the Headrick 14-23 at a 7,514-foot long lateral and it tested at 26 million a day. And last, but certainly not least, the Billingsley has an 8,521 foot completed lateral and it tested at 36 million a day. Since 2 of the wells that we just completed recently tested over 30 million a day and the other 2 were in the mid-20s, I guess it's obvious that all of these IPs meet or exceed our performance goals. We expected and we got the improved IP rates as a result of going with our Gen 2 completion design, and we'll make an effort to document this for you in the next slide.

This slide compares various production information against our 7,500-foot type curve. In Slide 13, we separated our Haynesville wells between the Gen 1 and the Gen 2 wells so you could get a better comparison between the 2. And you can see that the red colored curve on the graph represents the average production profile based on our first 12 Haynesville well completions using our Gen 1 design. And as you remember, our Gen 1 design used 2,800 pounds of proppant per completed lateral foot, targeting 250-foot long frac stages using 5 perforation cluster space 50 feet apart. Our Gen 2 design has 3,800 pounds of proppant per foot, and it has 100 -- targets 150-foot long frac stages using the same 5 perf clusters per stage but they're spaced 30 feet apart. You can also see that the green curve represents our single Bossier completion, yet 2 is above the type curve. And finally, the purple curve. That's showing the average of our 4 Gen 2 wells that we've completed so far this year.

So the good news is that all of these curves are above the type curve, but even better news is that the Gen 2 average curve is the best of all of them. And right now, we definitely like what we're seeing. The Gen 2 design not only gave us 2 wells out of 4 with IPs greater than 30 million a day, but it's also giving us an early production profile significantly better than our average Gen 1 profile.

Slide 14 provides even more support to document this Gen 2 improvement. Slide 14 shows a simple 2-bar graph that's providing a straightforward comparison of the average IP per 1,000 foot of lateral length between the 2 groups of wells, the Gen 1 group and the Gen 2 group. There are 13 Gen 1 wells and there are 7 Gen 2 wells that have IP rates. And yes, we realize there are a lot of variables that impact an IP rate, but obviously 2 of the largest factors are the length of the well's completed lateral and the well's completion efficiency. Both of these factors go directly to determining the amount of effective stimulated reservoir volume or ESRV contributing to production. And I know that some of you might remember that I droned on about the ESRV in the previous conference call or 2. But anyway, what this slide does is simply compare the Gen 1 versus Gen 2 average IP rates when normalized per 1,000 feet of lateral length. And as the graph shows, the Gen 1 average is 3.3 million a day IP rate per 1,000 feet of lateral length and the Gen 2 average is 4.4 million. That a 34% improvement. And what we're saying here is that based on these averages, if you assume a 7,500-foot lateral, then the Gen 1 will give your an IP approaching 25 million a day, and a Gen 2 will give an IP approaching 33 million a day on average. So if you drill multiple wells, you should realize an average increase of about 8 million a day per well in IP rate when using the Gen 2 versus the Gen 1. The bottom line about this graph is that we view it as an early time confirmation that our Gen 2 design is a significant improvement over the Gen 1 and has definitely supporting its continued use.

The next slide, Slide 15, I'd like to change topics and talk a little bit more about our JV with USG. Slide 15 shows the approximate location of the JV. And I mentioned in my earlier comments that later this month, we plan to spud the first of several 10,000-foot laterals currently scheduled as part of our 2017 JV drilling program. And during Comstock's previous conference call in February, we told you that the JV had about 3,700 acres in Caddo Parish, Louisiana targeted for development. Since that time, the partnership has increased its position to about 6,100 net acres. We expect to significantly expand the JV acreage footprint going forward and with that expansion will come additionally -- additional future drilling programs in various areas throughout the play. This development is a potential springboard for Comstock's growth within an evolving and rapidly changing JV. And I can assure you that we're preparing for that growth opportunity as we speak.

So let me sum up our operations in a nutshell for you. We continue to execute and deliver strong results in our Haynesville play. We know it's early in our program this year but our initial assessment is that our Gen 2 completion approach is yielding much better results than our Gen 1 design. Right now, we're running 3 drilling rigs in the Haynesville play and all of these rigs are configured so we can drill 10,000-foot or longer Haynesville laterals when desired.

In keeping with that capability, we're moving forward with our Haynesville CRK-USG JV partnership that will target drilling several 10,000-foot laterals over the remainder of the year. And as we continue to build up our Haynesville activity, we're also pursuing multiple arrangements that will expand our Haynesville acreage position and our extended lateral drillable inventory. We expect to talk about these arrangements, as I mentioned earlier, in greater detail in future conference calls. And beyond all that, we now have an executable plan to drill infill in our stacked/staggered Eagle Ford oil wells when the oil price justifies that investment.

So that's my quick summary of our operations, and I guess I should stop right here and give it back to Jay.

All right. If everyone will turn to Slide 16. It's the 2017 outlook. Kind of what I got from Mack and Roland is that we have a rig place and they're performing. We have an excellent JV partner that wants to grow the volumes materially in the Haynesville. Our cost are dropping and our production is growing and we're hedging. So with that, Mack, thank you. Thank you, Roland. Let me refer to Slide 16 where I will cover our outlook for 2017. We're very optimistic about 2017 after the struggles of the last 2 years, which were severe. We have a high degree of confidence, and our high return Haynesville shale assets will provide us the means to achieve strong growth this year. Our enhanced completion design has transformed the Haynesville shale onto one of North America's highest return natural gas basins, and our acreage position gives us over 700 operated locations. We're expecting our natural gas production to grow by more than 40% driven by 22 well drilling program funded primarily with operating cash flow. The production increase will cause our EBITDAX and cash flow to increase significantly. Our already low cost structure is expected to improve with new low cost Haynesville shale production. Our producing cost per Mcfe in 2017 are expected to decrease by $0.20 per Mcfe, which is 18% lower than this year. Our balance sheet and liquidity continue to improve as we grow our cash flow and EBITDAX. Our Haynesville JV is gathering steam and could and should be a major contributor to growth for us in the future.

So for the rest of this call, we'll take questions only from the analysts who follow the company. So Ayla, I'll turn it over to you.

(Operator Instructions) Our first question is from Ron Mills with Jason -- with Johnson Rice.

Jay, question on the stagger/stack test. I think you referenced in DeSoto Parish the non-op interest you are in. Can you talk a little bit, and maybe, Mack, about those wells? And to the extent stagger/stack works, can that be additive to your current inventory? Because I'm not -- I don't remember how many locations you think you can drill across a section and if that is just in one portion of the Haynesville.

Ron, this issue is one that we have a lot of information about. We think it will add additional locations across our acreage position in the play. I'll let the operator of those 3 wells that you mentioned give greater detail in their guidance concerning the results of their wells. We do -- we're very encouraged by the results, and we'll leave it at that. We like the opportunity. We think it will add to our inventory. But right now, we're focused on the primary targets in the Haynesville going forward and drilling our first 10,000-foot lateral.

And Ron, I think my only comment is that we, probably a year ago, thought that the staggered procedure would work and we're very encouraged to see other operators out there testing that.

And then maybe for Roland. In terms of the remaining wells, just curious about the expected timing of completions. Are they going to be fairly steady through the year so your -- the growth will be fairly steady the remaining quarters? And that guidance, is it based on your published type curves? So as these wells continue to outperform, is there a potential where those guidance numbers move up with the outperformance?

Yes, Ron. The biggest factor in our -- what our actual production will be is probably more production scheduling. I think the wells have performed great -- and just actually when the wells come online is a bigger factor. As you saw for the first quarter, we had hoped to have some of those wells online during the first quarter and instead, they all came in either April or early May. But May, we've got a lot of production coming on in the month of May like we referenced. And we have -- or we have another well starting to flow back now. It's not in those numbers yet. We have several more that will be completed in June. So yes, a lot of stuff comes on. It just happens to come on in the second quarter. And the only really lumpiness in our production scheduling are -- is when we're doing the 2 well pads. So we have one rig that's doing that. The 2 Furlow wells are example of that. Now the 2, I think, [Nash] wells are our next 2 well pads but they're finishing up shortly and should be online. I think that what we can't foresee is when you have a just unexpected delays, and that's what happened with the Furlow wells. They should have -- they were -- they had to be -- their completion had to be kind of postponed and for over just almost 45 days because of the drilling operations in the Billingsley and there was some conflict between the 2. That was unforeseen and that was a significant delay and it turns out to be our 3 probably highest flowing wells today. But hopefully, we'll -- yes, we've taken that in account for the rest of the year and hopefully, we'll be -- have smooth kind of timing. You can never totally predict when the frac crews will be available. And so sometimes -- yes, so far, we haven't had more than a week or so delay from those. So yes, we're -- we think we're catching up to our guidance in this quarter. So let's catch up and then start to look at and see if we can get ahead of it later. But I do think the second quarter, you'll see us kind of catch up to where we should be, and maybe the well performance could lead us to want to add to our production guidance in the second half of the year.

And I think, Ron, that's a really great question because I think if there's an Achilles out there, I mean, we've got 2 to 3 rigs busy. The question is when will that production come online because it's not an issue of do you have bad wells because we don't. So that's a completely different issue. There are some companies out there that just have bad wells. We don't have any bad wells. The question is, do we have any delays in any of our great wells. And I think coming out of the shoot, Mack did a really good job. We had to get a second rig in because year 2016, we had 1 rig for 3 months, we had no rigs for 6 or 7 months. We had another rig, another rig. Finally, you get those 2 rigs and then you'd negotiate your JV with USG. Then you get a third rig and now, everything has kind of settled out a little bit better. So our goal, it's an impossible goal to hit but it's to not have any surprises in the quarter. I think what we've been able to do this quarter is kind of smooth it out, give you the facts and show you that our well count is really good, and our production per well is good. And the Gen 2 completions are incredibly positive. So that's a great question, though. That's a question, I think, we'll be asked more and more.

Our next question is from David Beard with Coker Palmer.

A big picture question. Could you just comment a little bit on cost inflation especially relative to sand cost?

Yes. We are seeing some cost increases across the board. Proppant costs are pretty much what we're seeing on the inflation there is about the same as what we're seeing overall with the completion cost in general. So we've factored in a 10% increase in our cost structure. We anticipate with increased activity in the Haynesville that those costs will rise some more before the end of the year. So we're not surprised or taken aback by any of that. Proppant supply is keeping up with the demand and we have various arrangements that have secured the proppant supply of our 2017 program wells. So hopefully, that gives you a little color on the cost structure that we see for the remainder of the year.

Some -- a question that people never ask is what it cost you to lease an acre. Has it cost you $1 million? $30,000? What does it cost you? And in the Haynesville, we've had this acreage for 20 years, most of it. So you got to factor that in whether the wells are economic or not. So I think when you go into well cost, I mean, Mack gives you some pretty good numbers on one of the wells are 4,500 foot, 7,500 feet or 10,000 feet. And yes, our proppant cost may increase by 10%. I think our rigs are locked in anywhere from 6 months to a year. That's not a big cost, and it'll be completion cost. But the total cost of well includes what the acreage cost as well as the drilling completion side. I don't know that any area can beat us right now as far as how we position the company with the acreage so many years ago, and the fact that when we say we have 52 of the best wells you'll ever have in the Haynesville, that includes 120 wells that we drilled in the Haynesville back in 2007, '08, '09, '10, '11. So it looks pretty good as long as we can have some decent gas prices and we can hedge.

No. Understood. And just as a follow-up. Given the well results you reported, would you plan on changing your mix of laterals relative to your drilling program this year? Or kind of stick with what you laid out at the end of the year?

I think right now we're going to stick with our original plan. We do -- we're blessed to be able to be extremely flexible going forward. We'd like to get some different lateral lengths completed so we can measure the relative performance between those laterals and basically confirm what we think we know at this point. Like I mentioned earlier in some comments that I made, we have several 10,000-foot laterals that we're going to drill. We have several 7,500-foot laterals we're going to drill through the remainder of this year and intermixed, we will have some 5,000-foot laterals as well. And by the end of the year, we'll have a significant data set that we'll be able to look at and evaluate and set the stage for our 2018 program.

Okay. And as an aside, does the joint venture want to do mostly 10,000-foot laterals? Or is that just what you're going to do out of the shoot and that may change?

Well, again, we're flexible on that as well but we do plan to drill 10,000-foot laterals for the remainder of this year in the JV. The JV acreage lends itself to drilling some shorter laterals but for the first several wells, we're going to target the extra long laterals.

Our next question is from Chris Stevens with KeyBanc.

I was just hoping to maybe get a little bit more color on the JV and just sort of what the vision is out there, how big that JV could get? And are there any sort of plans to maybe increase your working interest on that acreage? And maybe if you could just touch on how many rigs you could potentially get to out there.

Sure. Yes, there are -- both us and our partner, yes, really want to continue to see the JV grow and set lofty goals for acreage acquisitions. I would see us being able to target getting to well over 10,000 acres by the end of this year. But possibly, the real goal is to get to substantial acreage position that would be 50,000, 60,000 acres. That will take several years to get to our large transaction. But we do want to -- I think overall, the goal for the JV is to, by the end of the year, to be running 2 rigs. The first rig is -- will be starting here shortly. And then the idea is to get to 2 rigs and then ultimately try to end next year close to 4 rigs. So you can kind of see the -- we think there needs to be a lot more acreage acquired to support the a 4-program and that's what's in process now. So the acquisitions will kind of drive the time frame in getting to 4 rigs. As part of that, we've seen this as a great opportunity to capture future inventory for the company without really having to use a lot of the balance sheet. And so we are looking to see if there are ways to increase our interest, getting closer to -- I think our goal is try to get closer to 35% to 40% of the JV activity versus 25%. And so that may be something we work our way into. So yes, lots of plans. We're really excited about the relationship and ability it gives us to grow our Haynesville kind of overall acreage footprint.

(inaudible) I think again might add on that is at one point in time, we had 7 rigs busy in the Haynesville. So that would not be a new number for us although these are horizontal. I think USG trusts us in our operations, which I think Mack is excellent in that. And then I think that as we had this acreage, like Roland said, we'll increase our drill site and at the same time, not give up any of our 700 operated locations. So we just continue to be stronger, which, I mean, that helps our balance sheet, that helps everything and it's a win-win. So I think we're very fortunate to be associated with that JV.

Absolutely. And maybe if you could just provide a little bit more on the sort of mix between running rigs on your JV acreage versus your existing sort of legacy acreage right now. And I know that you ramp to 2 to 4 rigs by the end of this year and into next year, and would that just be incremental to what you're doing on the operation -- on your -- relative to the legacy acreage that you have out there? Or would this be still spending within cash flow and just maybe increasing the allocation of CapEx to the JV area?

Well, we'll look to next year. The spending within cash flow will be our target. So yes, we'll look at the activity levels and then decide how many rigs are run on the company acreage based on kind of what we see for next year's cash flow, et cetera. So I think it's still early for us to really put together the plan yet for next year. We'll have lots of opportunities, lots of places to go to drill wells. And so we'll fit the 2 together appropriately.

Yes. And I think the denominator, again, is cash flow. What's our cash and then we'll allocate that toward the wells that are being drilled.

Okay, great. And then maybe just one more question here. On the completion design, it looks like those 3,800 pound per foot tests are looking pretty solid so far. Any plans to test anything else? I know there's other operators out there testing some pretty big fracs. Any other ideas on additional tests for your completion design?

Well, we like the 3,800 pound per foot design and we see no reason to change while we accumulate the information that we'll need to decide if we do want to increase the proppant. We do think that the use of the [deferred] materials is something that could yield additional benefit at very minor cost. We don't buy into the premise that more proppant is better necessarily. There's a point where there's the return on investment doesn't justify going to the large proppant loadings. So we like the 3,800 pounds per foot design. We'll continue to use that design along with some (inaudible) materials and accumulate the information.

Our next question is from Jeffrey Campbell with Tuohy Brothers.

Slide 16 highlights 18% year-over-year per 1 million cubic foot equivalent cost reductions. I'm just wondering, will the remaining reduction in 2017 mainly be the result of the increased production that you're expecting? Or are there still some cash costs that can come down?

That's primarily going to be the production increases to drive -- there's a lot fixed cost in those numbers. And the Haynesville -- new Haynesville production, the only really variable cost is the gathering cost but the -- a lot of the other cost is allocated to the wells. And so that's -- I think that's going to end up -- we'll exceed that 18% comparison based on our volume growth.

Okay, great. Just kind of sticking on cost. What will -- in round numbers, what's the additional cost incurred with Gen 2 versus Gen 1?

Well, that's a variable depending upon the lateral length of the well. But basically, it's around 400k to 600k. Something like that.

Okay. What's the standard lateral length that you like to correlate that for? The 600,000?

The 7,500 footer.

Okay, great. And then finally, when you resume, you mentioned potential infill activity in the Eagle Ford when the oil price is where you want it. I was just wondering, when you resume your D&C activity in the Eagle Ford, will you be completing the wells differently than you have in the past?

Absolutely.

And could you give a little color on that? I'm assuming there's going to be some lessons from the Haynesville that are going to head over to Eagle Ford when you start up again.

Well, there's a significant number of lessons available on the Eagle Ford as well that apply directly to what we plan to do. Obviously, the cleaner fluids will be used in the Eagle Ford just as it is in the Haynesville. So that's similar. Proppant loading is also something that we're looking it, different types of proppant, different types of staging than we did in the past. So yes. And the short answer to your question is, absolutely. We'll be doing a lot of things differently in the Eagle Ford when we get back into that play.

If you're looking at the ops and -- operators and how they completed their wells versus how we completed our wells years ago, it's like night and day difference. That's why their wells are so much better.

That's an interesting observation because we've certainly seen some oil window wells, for example, that look really good now and they're -- in areas that weren't being drilled 2 years ago. So I think that's...

And we've got offset wells that we've -- we're nonop in average 1,600, 1,800 barrels a day as IP rate. So we're privy to how they completed that and Mike knows that. So yes, I mean, we look at that. And that's why we think instead of 83 or 85 additional undrilled locations, we probably have maybe 230 something undrilled locations because the spacing is completely different than our old spacing and our performance is materially better than our old performance.

(Operator Instructions) We have a follow-up question from Ron Mills.

Just clarification on the 20 gross Haynesville wells this year, is -- do you all have an expected split between the JV acreage and your legacy acreage?

Yes, Ron. I think there are 4 gross wells and really 1 net well kind of included in there for the JV in our total. The rest of them are the company acreage wells.

Great. And then just a clarification on the cost. I know you've been talking about $8.5 million well cost, Mack, for a 7,500-foot lateral. Is that -- have you already factored in your -- a 10% increase in those well economics you presented in prior presentations?

Yes. Yes, sorry, Ron. Yes, we did factor that in.

And I'm showing no further questions. I would now like to turn the call back to Jay Allison for any further remarks.

All right. Again, everyone that's continued to listen, I mean, we cannot, as a management group, thank you enough for trusting us. And as I've said at the very beginning of this call, in the future, it's our corporate goal to give you the operation results that were a result in the conversion of our second lien notes, which, again, would talk about liquidity and balance sheet but that will significantly improve our balance sheet. So that's what we're working for, and all of you know that. So again, thank you for listening.

Ladies and gentlemen, thank you for participating in today's conference. You may all disconnect. Everyone, have a great day.