Comstock Resources, Inc. (CRK) Q2 2017 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Comstock Resources Second Quarter 2017 Earnings Conference Call. [Operator Instructions]. As a reminder, this conference call is being recorded. I would now like to introduce your host for today's conference, Mr. Jay Allison. Sir, you may begin.

Thanks, Kayleigh. Welcome to the Comstock Resources Second 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 titled Second Quarter 2017 Results. I am Jay Allison, Chief Executive Officer of Comstock. And 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 second quarter operating and financial results. Please refer to Slide 2 in our presentations, and note that our discussion 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 expectation will prove to be correct. You should go to Slide 3. A summary of our second quarter is outlined on Slide 3, where you can see the improvements in our financial results, driven by the growth in our natural gas production. Oil and gas prices were also improved in the quarter as compared to last quarter. Our natural gas production grew by 28% over last year and was 22% higher than last quarter. Our natural gas prices were 50% higher, and oil prices were 7% higher than the second quarter of 2016. Our sales grew by 50% to $63 million, and our EBITDAX increased by 127% to $44 million, highlighting the significant improvements to our operating costs. Cash flow from operations for the quarter was $26 million, a $34 million turnaround from the deficit we had in the second quarter 2016 of $8 million. Our Haynesville drilling program is driving the production increases. All of the Haynesville and Bossier wells drilled continued to perform above our type curve. One of the wells we reported on today set a new IP record at over 37 million cubic feet per day, as Mack will review later in his presentation. And we are very focused on improving our balance sheet by growing our cash flow and EBITDAX. We have total liquidity of $160 million, which is more than adequate for us to carry out our current drilling program. We have also hedged about $100 million per day of our production for the second half of this year at an attractive $3.38 per Mcf. Roland will now go over the financial results. Roland?

Thanks, Jay. On Slide 4, we outline our national gas production from our major regions, as always in our conference calls. And in the second quarter our natural gas production averaged 190 million cubic feet per day, increasing 37% from the second quarter of 2016 and up 22% from our first quarter, if you exclude the production we divested of in December of last year. As I'll cover in the next slide, our second quarter gas production rate would have been 198 million a day, except for the impact of wells we had to shut in during the quarter. We've also fallen a little behind on getting our wells completed this year. We have 4 wells drilled and waiting on completion, 2 of those is because we've gone to drilling 2 well pads to reduce our drilling complete costs. The other 2, though, are waiting for our frac crew to become available. We've just added a second frac crew, which will begin completing one of these wells and will help us catch up on our schedule. With these delays, we expect our natural gas production in 2017 will average between 195 million to 215 million cubic feet per day but will still exit about the similar level that we planned to earlier in the year. Slide 5 shows how much of the production we had to shut in, in the first 2 quarters of this year. Shut-in natural gas production averaged 2 million per day in the first quarter, which is all related to wells shut in for offset frac activity. However, in the second quarter, shut-in production averaged 8.2 million per day, much of which was related to severe storms and tornadoes at our Haynesville operating area in May of this year, which caused electrical power outages in the region. These power outages caused certain natural gas treating facilities go off-line, making it necessary for us to shut in our wells during the quarter. Our oil production has been shut in to a small extent also due to offset frac activity, which impacted our oil production by 105 barrels per day in the first quarter and about 59 barrels per day in the second quarter. Slide 6 shows our hedge position we have in place to lock in the high returns of the Haynesville shale drilling program. We had 81 million per day hedged in the second quarter at $3.38 per Mcf, and we've increased that -- the hedge position to 99 million per day in the last 2 quarters of this year also at $3.38 per Mcf. And we have part of 2018 hedged also at the same price. Our Haynesville operations are in an area with substantial regional natural gas price advantage compared to the Marcellus Shale markets, which is shown on Slide 7. Our regional basis differential to Henry Hub is only $0.11, while transportation to Henry Hub from the Northeast, which is 1,200 miles away, has averaged $1 per Mcf over the last 12 months. Gulf Coast industrial demand, exports to Mexico and LNG exports are expected to increase over 17 Bcfe per day by 2020, meaning that most of the growth in gas demand is going to come from our region. We have minimal firm transportation obligations, and our gathering and treating costs to get our gas to the major markets is averaging around $0.25 per Mcfe. This gives us high price realizations, which are very important in the current low gas price environment that we're in. Slide 8, we summarize our oil production. Our oil production averaged 2,700 barrels per day in the second quarter, showing continual decline due to lack of any drilling activity since 2014. And with no activity budgeted for this year, we expect oil production to decline further and with that go approximately between 2,200 and 2,500 barrels per day for the entire year. On Slide 9, we show how our producing costs have improved as we have shifted toward drilling the lower-cost Haynesville Shale properties versus the higher-cost oil projects that we have. Operating costs have improved to $0.75 per Mcfe this quarter. That's compared to $1.48 per Mcfe back in 2014 and $1.10 just last year. Since our new wells in the Haynesville Shale are exempt from production taxes, our production taxes averaged only $0.06 this quarter as compared to $0.36 back in 2014 and $0.08 in 2016. Gathering costs were down to $0.19 in the second quarter compared to $0.26 in 2016, which is mainly reflecting renegotiations of certain gathering contracts for our Haynesville Shale gas. The second quarter results include some retroactive adjustments. So a go-forward rate for our transportation costs, which is shown up -- we show in our operating costs, should be closer to $0.23 per Mcfe. The field level costs were also down to $0.50 in the second quarter compared to $0.97 in 2015 and $0.76 in 2016. And our DD&A per Mcfe produced has come down dramatically to $1.60 per Mcfe this quarter as compared to $5.74 back in 2014 and $2.26 in 2016. All of that improvement is due to the very low funding costs of our Haynesville Shale wells. On Slide 10, we summarize the second quarter financial results. The growth in gas production, improved prices and lower operating costs drove improvements to our sales and cash flow in the quarter. Our natural gas production increased 20%, and natural gas prices increased 50%. As a result, oil and gas sales this quarter were up 50% to $62.9 million compared to the second quarter of 2016. Our EBITDAX was also up 127% to $43.8 million. And operating cash flow came in at $25.9 million, a substantial improvement from the cash flow deficit of $8.3 million we had in the second quarter of 2016. As we reviewed a minute ago, the producing costs have come down substantially, which is reflecting one of the benefits from the low-cost Haynesville Shale drilling program. Lifting costs in the quarter were down 23%; and DD&A was down 16%, despite the higher production level that we had. Our G&A costs were up by 16% just due to the increase of activity that we have this year compared to last year. So overall, we reported a net loss of $21.4 million in the quarter or $1.45 per share. The unusual items included in that net loss number in the quarter included an unrealized mark-to-market gain on our hedged contracts of $3.9 million and a noncash amortization of the discounts recognized on the bond exchange we completed last year of $9.5 million, which has offset the $100 million gain that we reported on the exchange. Without these items, the net loss for the quarter would have been $1.07 per share. On Slide 11, we show the financial results for the first half of this year. During that period, natural gas production grew by 15% and gas prices increased by 54% and oil prices were also up by 40%. So oil and gas sales for the first 6 months of this year were up 48% to $117.2 million as compared to 2016's first 6 months. EBITDAX was up 129% to $78 million, and operating cash flow of $41.9 million was, again, substantially improved from the cash flow deficit of $22.3 million we had in 2016. Producing costs were down for the 6-month period, as you saw from the quarter, which also contributed to the improved financial results. Lifting costs were down 21%, and our DD&A was down 20%. And again, our G&A costs were up about 16%, slightly kind of increase you saw in this last quarter. For the whole period, the first 6 months of 2017, we had a net loss of $44.4 million or $3.06 per share. This number included some unusual items, including the unrealized mark-to-market gain on our hedged contracts of $11.3 million and again the noncash amortization at the discount on the bond exchange of $14.9 million. So without these items, the net loss for the 6 months would have been $2.81 per share. Slide 12 shows our balance sheet at the end of the second quarter. Very similar to the -- where it was at, the end of the first quarter, we have $35 million of cash on hand, $1,175,000,000 of total debt outstanding. Including our undrawn credit facility and the available pay-in-kind feature we have on our first-lien bonds, our total liquidity is $160 million. On Slide 13, we recap our capital spending for the first half of this year and our drilling budget for all of 2017. In the first 6 months, we spent $86.6 million on drilling 10 wells or 8.1 net wells. We currently plan to drill a total of 24 or 15.6 Haynesville Shale wells this year, which will cost about $153 million. We also have budgeted $9.6 million to drill 3 or 1.5 net Bossier shale wells, and we have about $4.9 million estimated for other activity. We have recently adjusted our 2017 drilling plans to drill more 2-well pad projects to help offset some of the rising completion costs. So from our previous budget, you can see that we're drilling more wells but very similar number of net wells as compared to the original plan. So Mack will now take over and kind of bring you up-to-date on the Haynesville Shale drilling program.

Thanks, Roland. Well, you're all eager to see Slide 14, as usual. So here, I'll go again with this slide, highlighting our 68,000 net acres in the Haynesville play. And that's worth [indiscernible] for us right now, the Haynesville, obviously. Along with this acreage position comes another part that I definitely want to mention, and that's our position in the Bossier target that sits a few hundred feet above the top of the Haynesville. And I'm sure most of you out there remember our Jordan well. We've talked about it a few times. This completion got our and everyone else's attention. That's definitely one of the best Bossier wells in the play, and after it IP-ed around 22 million a day, we dialed it back a little bit. And you'll see in the later slide that it is still producing well above the type curve almost 1.5 years after its completion. There's absolutely no doubt we like both the Haynesville and the Bossier, and we're continuing to grow our position in it. We've been and are still moving with various acreage adds while being careful to target only what we consider high-quality Haynesville and Bossier targets. In keeping with that growth effort, our JV with UGS is one other path we're following. And so far, our partnership has gained about 6,400 acres of quality Haynesville in the play. And we're closing in on a number of other acreage additions through it, the JV and other means. Lease additions include acreage that's located inside as well as outside our JV area. Coupled with our effort to grow our Haynesville acreage position, our JV partnership with UGS is starting to rev up at the drill bit. During mid-June, we spud our first 10K Haynesville horizontal well off a 2-well pad as part of this partnership. And we're currently drilling the second 10K JV well of that same pad. Along with these first 2 wells, we plan to drill several more of these 10K wells off various 2-well pads before the end of the year. And at the beginning, we'll have a 25% working interest position in the first few 10K wells, with the option of increasing our interest to 40% after an initial group of wells has been drilled. The next slide will show the locations of the various non-JV horizontal drilling projects that we've started since the beginning of our program in 2015. All of these projects have been and continue to be very successful, so let's swing over to Slide 15 and get a visual on that. Slide 15 shows you all 24 wells, plus the Haynesville wells, plus the 1 Bossier well that we've put to sale since the beginning of our program in 2015. Just for the record, we're fracking 2 additional wells, and we have 3 drilling rigs active on 2-well pads in the play, each of which are configured to drill 10K laterals. Each rig is configured to drill 10K laterals, pardon me. Anyway, as you can see, the 20 red labels in Slide 14 -- 15 show the locations and IPs of the various wells that we've put the sales from 2015 through the first quarter of this year. And the gold labels show you the same thing for our 5 newest second quarter Y '17 wells. During the first 2 quarters of this year, we've put a total of 9 wells to sales, and some of you listened to us as we discussed the first 4 of them during our first quarter conference call. These first 4 wells that we reported on in the first quarter had lateral lengths varying from 5,396 to 8,521 feet and had IPs varying from 25.4 million to 36 million a day. In this first quarter, 4-well group had an average lateral length of 6,946 feet at an average IP of about 30 million a day, which would suggest an IP per 1,000 feet of about 4.3 million cubic feet per 1,000 feet of lateral length. Our second quarter 5-well group had lateral lengths varying from 4,453 to 7,471 and had IPs varying from 20 million to 37 million a day. It is important to note that this second quarter group also included our highest IP performing Haynesville well to date, the Headrick 14-11 #2 well, which has a 6,861 feet lateral length and, as I mentioned, the 37 million a day IP. This IP is slightly better than our previous record holder, the Billingsley 25-24 #1, which had a 36 million a day IP and an 8,521 feet lateral length we reported on the Billingsley during our first quarter conference call. And you can see that the difference in the lateral lengths between these 2 record-setting wells is about 1,660 feet, but the IP rates are about the same. We believe that this is in part due to our continuing improvement in the execution of our Gen 2 completion design. And this business, as it is, with almost anything else you want to discuss, things can always be improved upon. And that is what Comstock is always trying to do across the board. But anyway, getting back to some specifics about our second quarter 5-well group. These 5 wells had an average lateral length of 5,903 feet, which is about 1,040 feet less in length than our first quarter 4-well group average. And they had an average IP of about 27 million a day. Doing the arithmetic, it'll give you an average IP per 1,000 of about 4.6 million a day per 1,000 feet of lateral length, and this is better than our 4.3 million first quarter number. Another difference to emphasize is that during the second quarter, we obviously tested shorter lateral Haynesville completions, and we changed our views of diverter drops. So based on all these numbers that I've just gone over, what would I say are the main takeaways here? The first one would be that we have continued to improve our completion efficiency by using our current completion design, Gen 2, coupled with the changes in our use of diverter materials. We think that our results confirm that our short lateral well completions will yield excellent results going forward via our improved Gen 2 completion efficiency. By testing a broad range of laterals length, we are also getting a pretty good test of our Gen 2 completion performance. And since we know that the proof is in the pudding, let's go to the next slide to see how the wells stack up against the type curve. Slide 16 is a composite that shows you how our various wells have sufficient -- that have production history are performing against our 7,500-foot type curve. This time, we show a red curve, representing the average of our 12 Gen 1 wells; and the purple curve representing the average of our 6 Gen 2 wells that have enough production to compare against the type curve. The comparison between these 2 curves shows you that both Gen 1 and Gen 2 are outperforming the type curve, but our Gen 2 completion design is the better performer. We also give you a light blue curve, which is the average of our 5 short lateral wells. And it, unsurprisingly, is performing under the 7,500-foot type curve since it represents wells with almost 2,000 feet less length. But you can see that even the light blue curve appears to be flattening. And if this trend continues, and we believe it will, it may very well be producing above our 7,500-foot type curve within the next 100 days or so. This is telling. And finally, you can see the green curve that represents our Bossier well, which has now produced well over 500 days and has been above the type curve for well over a year. All of these curves indicate that we continue to create substantial value at the drill bit and that we are continuing to see improving results as we go forward with our program from our Gen 1 through our Gen 2 completion designs. The next slide will give you a quick indicator of this improvement. Slide 17 shows you a simple comparison of our Gen 1 and Gen 2 completion IP results averaged over 1,000 feet of completed lateral length. Once again, to make sure that everybody understands, our Gen 1 design used a 2,800 pounds per foot proppant loading applied over a 250-foot frac length involving 5 perforation clusters, with 50-feet spacing between clusters. Our Gen 2 design uses a 3,800 pounds per foot proppant loading applied over a 150-foot frac length involving 5 clusters with 30-feet spacing. Our 13 Gen 1 wells gave us a 3.3 million a day per 1,000 feet of lateral length, while our 12 Gen 2 wells has given us a 5 -- a 4.5 million a day per 1,000 feet of lateral length. So Gen 2 has given us around a 36% improvement in our IP ratio over Gen 1. And interestingly, if you think about it, our Gen 2 design would have about 10 perforation clusters over a 300 feet of fracked interval compared to 6 clusters over that same length than our Gen 1 design. So Gen 2 has about 67% more perforated connections to the reservoir than our Gen 1 design. And to go along with that, we're pumping about 36% more proppant per foot over the fracked interval, along the various diverter drops that I've mentioned before. And we believe all of this helps increase the probability of a significantly improved completion efficiency. I think the results speak to that as well. Moving on to Slide 18. After all my talk about Gen 1 and Gen 2, let me say a little bit more about our JV with USG. In my earlier comments, I mentioned that we're drilling our 10K lateral as part of this JV and that we plan to drill several more before the end of the year. And then we have about 6,400 net acres in this JV at this point. We expect to expand that acreage footprint going forward. That expansion will involve additional potential future drilling locations and programs within various areas throughout the play and areas that have been high-graded and targeted by us and our JV partners. So the conclusion. Let me sum up the second quarter operations. During this quarter, we started our JV program with UGS at the drill bit, and we're currently drilling our second 10K lateral as part of this program. We have also drilled and completed our best IP well to date at 37 million a day, and it's located within our legacy acreage block that we have held since the mid-'90s. And so far, the 9 Haynesville Gen 2 wells we've reported on, 3 of them have IPs equal to or greater than 32 million a day. We also continue to build our position within the JV in the Bossier via our JV partnership. We're also pursuing other trades and arrangements to add acreage or improve our acreage configuration to drill extra long lateral horizontal wells. And finally, as I have mentioned on several occasions and previous conference calls, we have an executable plan to drill numerous infill or stack/staggered Eagle Ford oil wells when the oil price justifies that investment. So that's my quick summary of our operations. And I guess, that means I should turn this thing back over to Jay.

All right. As always, thanks, Mack. Excellent conclusion that summarized your presentation. Let me refer you to Slide 19, where I will cover our outlook for the remainder of 2017. We continue, as you can see, to be very optimistic for this year. Our high-return Haynesville Shale assets are driving our strong growth this year, as Mack outlined in his report. Our enhanced completion design has transformed the Haynesville Shale into one of North America's highest-return natural gas basins and our acreage position just has over 700 operated locations. We're expecting our natural gas production to grow by more than 40%, driven by 27-well drilling program. The production increase will cause our EBITDAX and cash flow to increase significantly, as Roland has pointed out in his slides. Our already low cost structure has improved. With new low cost Haynesville Shale production, our lifting costs for Mcfe have decreased by 26%. And our DD&A per Mcfe has improved by 25% this year. Our balance sheet and liquidity continue to improve as we grow our cash flow and EBITDAX. Our Haynesville JV is gathering stream and is expected to be a major contributor of growth for us in the future. For the rest of the call, we'll take questions from the analysts who follow the company. I'll turn it over to Keyleigh to control that. Thank you.

[Operator Instructions]. Our first question comes from line of Ron Mills with Johnson Rice.

A couple of questions. Just as it relates to production in the profile. I don't know, Roland, you talked about having the exit rate being unchanged, although the move to some 2-well pads kind of changes the pace of third and fourth quarter production. Can you remind us what you had thought your exit rate would be? And I know, preliminary, nothing's been budgeted, but what that can portend to 2018 outlook?

Sure, Ron. Yes, we think that we can exit close to 240 million a day for the gas, which is the main driver for the production. And -- but yes, we have -- some of it's coming on a little slower than we'd hoped, and the power shut-ins in the second quarter probably affect the second quarter a little bit. So we have reconfigured the drilling budget a little bit to have a lot more 2-well pads that are originally in there, which slows the completion down quite a bit on at least one of the 2 wells. And yes, we're -- toward the second half of the year, we're drilling much more of the longer laterals in the JV wells, which all are 10,000-foot laterals right now as they are configured.

And then can you also just -- you lost me a little bit when you talked about the number of drilled wells going up, the number of net wells going down. Why does that impact -- why does 2-well pads impact the number of net wells? Are you trying to talk about number of wells drilled versus number of wells that come online?

Well, that doesn't necessarily change the net number. But that's just how our -- we have changed kind of the makeup of some of the wells we plan to drill. There are more JV wells than originally in the budget. So that -- obviously we have 25% interest in those. So that's probably the biggest part of the change and just some other reconfigurations kind of if we wanted to stay on budget overall and wanted to also keep all the rigs. We also -- we're looking for a plan to keep all the rigs utilized through the end of 2017. Our original budget did not contemplate having 3 rigs during the end of the year because we had finished up a lot of our other projects. So that's a little bit of a change but pretty much kept it in the same ballpark drilling a little bit more lower interest wells.

Well, then -- and like Roland said, Ron, I think, one, we wanted to keep this third rig busy because these rigs are hard to get. We didn't want to let it go. And the other thing, we wanted to add another well or so in the Bossier. You'll notice we have like 1.5 net wells in the Bossier. We'll drill 3 wells or so gross. So we've added the Bossier, which goes back to Mack's comments that we're very positive on the Bossier results, and we would like to have 2 or 3 of those wells drilled by year-end. [Indiscernible] little less interest in those as we project in the future of those wells, but we do want to get some drilled and keep the rig busy there. So that'll impact the production a little bit.

And Ron, I'd like to add just one comment about -- just using Roland and Jay's remarks as a springboard. By staying on budget and keeping the rigs busy at the same time, it offers a segue into Y '18 to be able to drill higher interest rate -- working interest in that interest wells if we so choose will have the 3 rigs that are capable of drilling 10K laterals each one of them. 2 of our rigs are walking rigs, which offer additional efficiencies. So it's a big game for Comstock to be able to continue to work those rigs at -- on wells with slightly lower working and net revenue interest, as Roland mentioned, to maintain continuity of the program into Y '18. And it kind of goes to your question about how it might affect Y '18 rollover.

And really, I think, Ron, what you see here is you see this flexing of this muscle with this JV partner with USG because their goal at the end of '18 is to have 4 rigs busy. While we didn't want to give up a rig now, these HP rigs and neighbor rigs that we have, they're hard to find. So we're just with our JV partner and said what if we reconfigure our program, we reduce ourself a little bit of interest, we drill a few more wells, we drill some of the Bossier wells and that's -- this is the new budget. And the key thing also, Ron, it keeps us within this $150 million to $160 million total CapEx, which is a goal that we had to preserve our liquidity. So I think it's a real big win for everyone, and it's just now showing up. And particularly with the well results that we've had, it's incredible well results.

And then, lastly, just on the leasing. I know you talked about the JV, your 6,400 acres. If USG, wanted to get to a 4-rig program, what kind of acreage number would you all have to get to up there? And then, secondly, just in your legacy area. Any update on ability to either do some bolt-ons or do some swaps? And where are you in that process?

Sure. Yes, there's a lot going on, on all those fronts. The JV, the goal of the JV is around 3 to 4 rigs next year. We think we've got kind of some plans where it can be running 3. There is a fair amount of acreage deals they're working on, but depends on exactly where it's located as how many rigs you can support on it because if it's all too close together, it's hard to drill. You can't really drill and frac right next to each other. So -- but that's all starting to take shape. And I think by the next quarter conference call, we have a really good plan for next year where they are running at least 3 rigs. I don't think -- and maybe 4 if some acquisitions come together. Yes, we -- and our acreage continues to change. If anybody studied it, it's not the same acreage that was there given what we saw this quarter. We have some new sections that weren't there before, and we've traded sections and moved things around and have slightly more acreage than we started out the year with. So that process is always ongoing. And although we have some other trades we're trying to finalize and -- that will show up hopefully next quarter, those all take a while to do. But yes, our acreage continues to change all the time. It's changed probably every quarter. But still -- but it's getting more and more drillable as you do these trades.

Well, Ron, I guess, two extra comments. As the big purchases had closed last year to beginning of this year, you'll see contiguous operators exchange acreage so that both operators have a win-win position so we can both drill longer laterals. And that's what Roland's talking about. So I mean, our acreage position continues to get better. And then, I think, on the USG, we feel like they have to have probably 3 different areas at all times that they can keep a rig in, so you don't have any interference. So while we're working toward having at least 3 different areas, all within this core area that what we think is Tier 1 of the Haynesville/Bossier. And that really is materializing. I think you could probably get a much clearer vision on that at the end of this next quarter. If the things that we have in place are working, I think we control most of what could happen there. So it looks good. It's all driven, as you know, by the performance of the wells. And that goes back to Mack's presentation as Gen 2 materially trumps the Gen 1 and even the shorter laterals, like you said, you give another 3, 4 months, I mean, maybe that curve will hit our top curve for the 7,500-foot laterals. So it is all looking good.

Our goal is probably by the fourth or third quarter is to kind of have a 2018 plan, where the base level is mostly the JV wells with a lower interest that will service all of our dedicated rigs and frac crews, et cetera, and then have the flexibility to bring in high-interest wells depending on the -- what we see -- what the gas prices are next year. So kind of have a baseline that's more conservative. In that way, as we go through this -- as we go through winter this year, it will really dictate whether or not you guys are one play or the other. But that's our goal that we're going to create. I think we'll have that put together by the end of the third quarter.

Well, and again, Ron, you usually always ask our goal. We have 100 million a day hedged today at $3.38. I mean, our goal, hopefully, this winter, we have winter. Unlike the last 2, we didn't have winter. And you'll see gas prices pop up north of $3 again. I think if you go out 4, 5 months, you're $3.17 or so. I know they're $2.70, $2.75 or whatever today. But we do think that the fundamentals are gas and the number of storage is pretty healthy right now. It looks pretty good. So we have a decent winter. We plan on aggressively hedging through '18 or maybe fourth of '19 as we've done this year and the very first quarter of next year.

Our next question comes from the line of Mike Kelly with Seaport Global.

So the economics on these Gen 2 wells look fairly compelling. I was hoping maybe you could just frame that a little bit for us. It is encouraging to see steady, upward progression in the IP rates here in a per lateral foot basis. But can you remind us what's the well cost we should assume for the Gen 2-type well? And then what do you think is a good ballpark kind of project return maybe at $3 or $2.50, however you want to have us look at it?

Mike, I'll give you a couple of click numbers for a 7,500-foot lateral. Current cost estimate's about $10 million, maybe a tad over that depending upon certain other items. But that's the ballpark number. That's going to get you pretty close. And if you look at the economics and you use our Gen 2, so at a $3 gas price, you're going to be -- with a 7,500-foot lateral, you're going to be over 70% rate of return. So the economics are really compelling with our Gen 2 7,500-foot laterals. We've got -- of course, as you would expect, we've looked at the economics for all of our lateral length targets. And -- but our 7,500-footer is kind of the bell cow, that's what we reference our type curve to.

And Mike, all the wells we're drilling now, the rigs we have, the 2 HP and the neighbors are all capable of drilling the 10,000-foot. And our goal in the JV is to try to drill closer to 10,000 than the 7,500-foot.

That's right.

Got it. Appreciate it. And Roland, just maybe you could kind of frame the balance sheet health in your eyes, too. It's -- through the first half of the year, still a decent outspend, but production is ramping now. It seems like cash flows could catch up to CapEx real quick. And just wanted to get a sense, from your eyes, how flexible you remain on the balance sheet side and have the ability to kind of ramp activity levels? And I think the one thing that really stands out is if you assume that these converts don't convert, leverage looks pretty high optically. If they do convert, seems a lot more manageable. Just seeing if there's anything that you guys would potentially be working on to make that -- the leverage metrics look a little bit more appealing.

Sure, Mike. That's a good question. I think we do see cash flow catching up with the CapEx as we finish off this year. And a lot depends on the strength of gas prices there this year with the hedges we have. It's not quite as impactful. And then the next year, I think we have flexibility to really adjusting to the cash flow levels that we see based on what we're able to hedge next year at with that program that, yes, we can still be active with mainly JV wells or could ramp up pretty quickly with high-interest wells in our core area. So that's the -- we're trying to create that flexibly around the capital spending, which is it's tricky because you have to commit to these services in order to have them. And you can't just pick up a rig and a frac crew just if you decide overnight to do it. So that -- I think weaker prices make that easier to do. So I think everything's kind of in this kind of crossroads that is it going to be we're going to have winter or not, and that's really going to dictate, I think, the health of gas prices in '18. And I think we're positioned for either way. Now we can't really -- the conversion of the bonds would be great that there's such a negative sentiment in the equity world. I think average companies are down over close to 30% this year. So I mean, it's just -- that's the whole -- the atmosphere. The -- I mean, the environment for E&Ps has not been strong since January. And I think we look at alternative plans for potentially maybe there's some divestitures that allow us to retire some of those bonds versus having them convert would be one possibility to -- and then that then, if you're able to retire some of the bonds, I think, then you open the door to refinancing all the bonds and lower costs. So I think that -- I think we feel pretty good that there are different options out there. We still think the major focus of this year was to grow the production and EBITDAX back up to a good level. And we're going to accomplish that just like we hoped to and have -- on an annualized basis, have more than $200 million of EBITDAX. That's kind of our goal to grow into. So I think we're keeping lots of flexibility. We always have them put [indiscernible] the $160 million if we need it. We're trying to preserve most of that to take into '18 to have that same sort of flexibility in '18 to navigate this environment that we're in.

So Mike, my comment is I think those are 2 great, simple questions. What's your economics at $3? What's your rate of return? What does it cost? And what about your cash flow? Is it going to catch up with your spending? I mean, those are really simple questions. And once you get the answers to those then you can say "Okay, well, how is Comstock going to manage that?" And particularly, we started out not knowing that Gen 1 much less the Gen 2 in the Haynesville would work. And you can see how we progressed from January of 2015 through today. And what we've brought back earlier in the comment was we do have a partner. USG is a strong partner that wants to keep the rigs and the frac crews. So we have one frac crew, like we said. Now we have a second frac crew. We want to have a permanent second frac crew. Now instead of losing a rig, we kept a rig. And why could we do that? We can keep the super-spec rig or we could do it because of our relationship with USG, our partner. So that's going to be the difference, I think. Instead of owning 40%, 50%, 80% of a well, maybe we own 1/3 or 40%. And maybe in the new areas that we've added acreage in, the 6,400 acreage with the USG, we have the right to own. After the eighth or ninth well, I think we can have a 40% interest in the program. But we've got a 25% interest now. So we can kind of throttle up or down based on that. And a lot of that will be based upon what kind of hedge position we've put in also. But again, when you took a total look at Comstock again, after not liking what we looked like before the Haynesville, which is probably a proper thought, you see the Haynesville and it continues to be the go-to play for gas in North America because of where we're located and because the 2 questions that you asked earlier, it's our economic return. So hope that answers your question.

Our next question comes from the line of David Beard with Coker Palmer.

I don't know if this is going to be too complicated. But just as a follow-up, when you look at the shifting and your positioning entering '18, how do we think about the Eagle Ford?

That's a great question. Mack, you want to go at Eagle Ford? We don't -- we didn't -- we left the slide out on Eagle Ford. We'll go over it and say what our -- we think the future may look like. [Indiscernible] part of Mike Kelly's question, too, and Ron's.

And briefly, it goes to the point of flexibility that Roland mentioned earlier. We know that we can drill numerous wells. We have numerous locations infill in stack/staggered locations. The bottom line is what are your best economics? And the best economics right now are in the Haynesville. But we certainly have the flexibility to go to the Eagle Ford.

And did it change at all, the time frame or acceleration of potential sale of that asset?

Well, I think you know that we also looked at trying to find the most cost-effective way to -- if we do want to market the asset, to get -- to prove up the value. And so we're still looking at that. There are quite a bit of nonoperated kind of plants surrounding our Eagle Ford that's maybe a much -- a fairly inexpensive way to prove up our locations by having a smaller interest. And that's something another operator is doing. So oil prices are also a big factor in that. I mean, are they going to be weak or strong? So Eagle Ford is still a bench player for us and we'll hopefully find a good role for it next year depending on the environment.

Well, and like we said at the last conference call, there are 11 offset operators that are derisking the Eagle Ford that's in our area. There's been a couple of trades lately in our area. I think they started freezing up the value. We did test the lower Eagle Ford, not the upper. But we do have the stack/staggered program, and I do think it would work. The question is, can we get enough value for that if we decide to sell it or have a game changer for it that's left within the Comstock facilities? So we do have this -- it's called CEAP, which is the Comstock and Eagle Ford Acquisition Plan. And Mack will tell you that probably within 2 months, if we decide to drill a well there, we could probably drill an Eagle Ford well. One of the goals will look like we'd 3, 4 wells there, we derisk at our shale. Another goal is let's see how the offset operators continue to derisk it. But we've planned it up and teed it up to do something where is it depending upon where oil prices are in the future. That'll go back to what happens if the bonds don't convert. There might be an asset that would just be up for sale. I mean, as we've said, Eagle Ford might be that asset. We got to get enough money for it or have a game changer for Comstock.

Our next question comes from the line of Jeffrey Campbell with Tuohy Brothers.

Let me ask you a couple of Haynesville questions. First one is, how would you handicap the Headrick well's massive outperformance on acreage quality versus Gen 2 completion effectiveness?

Well, the Headrick has been an excellent position within our overall Haynesville acreage position or holdings. Both Headrick wells were efficiently completed with, as I mentioned in my presentation, the diverter materials. They -- one of the wells, the 37 million a day well, was -- had a lateral length of about 6,800 feet. So certainly, there's some additional lateral length that we could be striving for on future Headrick wells. And we have 2 more posted for the remainder of the year. Compared to the geology and other parts of the area that we control, I wouldn't say there's an appreciable difference. There's an offset environment -- offset well environment that a number of our wells are completed within that -- and that differs across the area that we have. Some areas have only 2 offset wells, some distance away. Other operators have offset wells closer in. So that changes the envelope, if you will, the production envelope from those offset wells that we try to address with our completion strategies. And by completion strategies, I mean perforation placement and use of diverter materials. So it's a great question. I think the Headrick is certainly up there in terms of the density, porosity and thickness, et cetera. But we have numerous other areas that are equivalent to that.

My only comment, not being an engineer or a geologist, just looking at the numbers that Mack gives and his group. If you look on Slide 15 and you look at the Headrick and you look at the 37 million a day, the Headrick was pretty flawless. I mean, we -- it took a little while to complete it. The completion crew is a little slower than we thought. But other than the slowness, it was pretty perfect. If you look on the west side, in the Logansport area, the Pace well, 25 million a day. We did have -- was surrounded by some other wells. So you would have a little depletion there probably. It would have been maybe a better well. But all those wells there, 24, 22, 26, 25, 27, I mean, they're really, really great wells. And they'll be better wells, I think, for this Gen 2. So you kind of blend it in. The acreage looks really good. You have any depletion. How many old wells are you drilling around? Remember, our typical well, if we're nearing all the offset well, that offset wells production goes up about 1 million a day. We don't talk about that very often, but that is part of the equation, too. But this whole area, this area on Slide 15, it is just a very consistent Tier 1 area that we have hundreds and hundreds of locations to drill in.

Well, and I think that you kind of anticipated something I was curious about because I was focused on Slide 15 and it looks like that the Headrick acreage is quite isolated from some of your larger, more contiguous portions. But it sounds like what you're, telling me is you think that it's, in terms of the geology, still quite consistent irrespective of the breaks that we see on the slide.

Exactly.

I guess, the last question with regard to the Haynesville is just wondering how many more of these Gen 2 well results do you require before you're ready to publish an upwardly revised Gen 2 type curve?

We're pretty close to a revision. I'd say, we just need to get a little more history. It's not the number of wells. It's getting a little more history on the Gen 2, especially the more recent wells to make sure the profile is consistent with what we think it's going to be and then -- and adjust the type curve at that time.

Yes. Remember, on '16, we had 6. We've got another 5 that you'll see at the end of next quarter. So I think we'll be getting closer. And then the exciting part on Slide 15, we won't have them producing, but we'll have another 3 wells drilled on the far bottom portion of Slide 15, which is the Vincent area, the Jordan area. And that's just a big blue slab right now, but -- there's also an [indiscernible] at Bossier wells. But once we have 3 or 4 more of our own, the whole map starts to glow. But let's see if it's a lot better.

Well, and to your point on rate in history. I mean, what -- just to kind of give me a number, I mean, what do you want to say? Like a certain amount of 180-day production or 90-day? Or what are you thinking about?

Yes. At least, 6 months. Yes, sir.

That's fair. Okay, great. That's it for me. And by the way, Jay, we look forward to seeing you tomorrow in New York City.

Yes, sir. We'll be there tonight and be with you all day tomorrow.

Our next question comes from the line of Chris Stevens with KeyBanc.

I guess, in regards to the JV area, do you have an updated thought on, I guess, how much acreage you could have there by year-end? And in regards to the option to increase your working interest to 40% next year, is that really going to be a function of your cash flows and whether or not you would have the cash flows to, I guess, effectively fund the CapEx program associated with that 40% working interest?

Yes, both those things are moving -- are not settled items yet so we can't really get into detail. I mean, there's a lot of acreage we're chasing [indiscernible] close because there's a problem with it. But I mean, their goal is to get well over 10,000 net acres in the JV. But the timing of when it's done is going to -- in the future, as is the 40%.

Well, I can say we're actively doing that every single week.

But by the end of the year, we think we'll have kind of against that group of assets and a plan for 2018.

Well, and then under one of Mack's slide, it's not quantity. We do want quantity, but it's quality. We think we've already had quantity. But once we add acreage, it's got to be quality. It's going to be drillable or you won't see it presented by us.

Right, understood. And then if you were to run, I guess, 3 rigs on that JV acreage next year, would there be activity on the legacy acreage at that point?

There'd be. I mean, that's -- again, that's -- we're going to build a flexible program, which isn't built yet. So that's -- we're going to have the base of the JV activity.

That'd be an option.

And then look at where gas prices are and where cash flow is, and we can plug in the activity as it makes sense to fill that out.

Well, the beauty of a Comstock story is we have few acreage in Eagle Ford that we might lose if we don't extend the drill. But the Haynesville is all HBP, I mean, all the important part of it. So there's no pressing area where we have to drill something or lose something material value.

Understood. Maybe I can just ask one on the Bossier as well. That Jordan well does look very strong after, I guess, 1.5 years at this point. I guess, what's the impetus behind adding another well to the program this year? Is it to test other areas of the acreage or test the Gen 3? Just any color around that?

It's mainly to keep the rigs utilized. I think it's more of that's where we kind of see the -- instead of releasing the rigs in November like originally planned, maybe go there a little earlier and then stay down there, kind of targeting a little bit lower interest ownership area. So it kind of still fits into the same budget.

And we picked up a few acreage there, and we have a little bit of royalty related there. So the economics were even a little bit better now. And we do want to keep these super-spec rigs busy. We don't want to lose one of them.

And our next question comes from the line of Mike Breard with Hodges Capital.

The Bossier acreage is not strictly yours. I think that's not part of the JV?

That's correct. Yes.

Yes, yes, sir.

Okay. Your JV partner's market cap is approaching $70 billion. And then, even with 3 rigs, you had peanuts with them. What might they be doing in 2019, 2020?

Well, we're obviously not the only thing they -- they have lots of other interest in oil and gas world and other projects. But I think they've been very interested in building the Haynesville that we built it from the ground floor. So that just takes a long time. We didn't turn over ready to drill acreage to them and start drilling in right away. We went out there and helped to create new acreage. So that's the slow way to do it, but it adds a lot of value to us to just bringing new assets in. So they're playing -- their desire is still there to definitely have 4 rigs in the Haynesville and then potentially those interest [indiscernible] some real result. We haven't yet put a well on line with them. So the early next year, they start getting real results. So I think real results, if they're anything like our wells, they're going to really be wanting more.

Well, and I think, Mike, that's a good question. We've had a relationship now with USG for a year. You only saw a press release out in January of this year. We've known them and been trying to work with them for a year. And to Roland's point, I mean, we've been very cautious on the acreage that we've added and advise them on. And we would report today, if their appetite was not to have 3 or 4 rigs busy by end of '18, we would tell you that. And their appetite is as stronger today or stronger [indiscernible]. And gas is $2.80 to $3, and they see more and more and more of our well results. And now they see that we drilled the first well under the JV and now we're drilling the second well. So those are all good things because it gives us great flexibility with the rigs and the frac crews. So we won't be back [indiscernible] this much on this production guidance. Because we tell anybody, 15, 16 net wells a year, I mean, you can take the top 3 or 4 producers in the Permian only to give them 16, 17 net wells. I mean, it's pretty scary because you get a 1- or 2-well delay or you get it early, I mean, it has a big, big timing effect. So we're trying to be as consistent as we can with the few net wells that we are drilling. And I think Mack and Ron did a really good job reporting that and keeping everybody updated on it. And the well results, again, the denominator is, they've been excellent.

Okay. I guess, my fear is they're going to try and go to 10 rigs in 2019. How would you keep up financially?

Well, I mean, we run the program. So I mean, we choose how many rigs we go to. They can obviously have other operators, and they do. They have other programs going on. We're not -- this is not all they're doing.

No.

They're in the other basins and they have other drilling programs going on.

I mean, right now, in the Haynesville [indiscernible] the other one on the throttle. I mean, if they...

Yes, there's -- we control the timing and everything about the program and always will.

Okay. How are the wells in also these other areas [indiscernible]?

We don't really monitor that. We have no idea.

And at this time, I'd like to turn the call back to Mr. Allison for closing remarks.

All right. Again, it's been, I guess, almost an hour. It's always a privilege to report whether it's good news or bad news. I think we had really good news today from Mack and from Roland and from all the staff and employees of Comstock to give you all these numbers. And it is fun to start and end with a pleasant voice like Kayleigh. So thanks for the pleasant voice, and it's a good way to start a Monday. And we'll be in New York tomorrow at the conference. So thanks for your time.

Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program, and you may all disconnect. Everyone, have a wonderful day.