Comstock Resources, Inc. (CRK) Q4 2018 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2018 Comstock Resources Earnings Conference Call. [Operator Instructions]. As a reminder, this call is being recorded. I would now like to introduce your host for today's conference, Mr. Jay Allison, Chief Executive Officer. Please go ahead.

Perfect. And thank you, Christy. And what a day. What a - we waited a long time for a day like today. Before I start the formal presentation, I'd like to kind of go over a little bit why we have these numbers. One year ago yesterday, Comstock Resources had its first detailed conversation with Jerry Jones family that resulted really to many iterations into what is today the new Comstock with Jerry Jones owning 84% of Comstock Resources. When Jerry Jones' family, along with his longtime oil and gas partners, Mike Mccoy and Bob Rowe, looked at Comstock, they discovered we had high-quality drill site locations in the Haynesville/Bossier, but we needed cash to drill the locations. The Jones family then made a decision to contribute their Bakken oil assets production into Comstock, debt-free, roughly 14,330 barrels of oil equivalent per day in order for Comstock to use that cash to drill the Haynesville/Bossier locations. So the financial results you see today in our fourth quarter are a direct result of that decision and only the very beginning of the new Comstock. Jerry Jones is known as a man that can create tremendous wealth in businesses as he did with the Dallas Cowboys. It was the single most valuable sports franchise in the world. Jerry Jones says, those who have followed us and have known us for a long time, they know he changed Comstock. We are who we are today because of his belief, his investment. He saw quality Haynesville drill sites. He recognized growth opportunities within the distressed Haynesville natural gas region. And as he said in March of 2018, "I like what I saw, so I put my money where my mouth was." He did. He made the investment. He is engaged to the Comstock, and the goal is to create tremendous wealth in this natural gas play for years to come. So with that, everybody on the phone, welcome to the Comstock Resources Fourth Quarter 2018 Financial and Operating Results Conference Call. We're excited today, as I've already said, to be able to talk about the full first quarter results since closing on the Jerry Jones Contribution transaction. You can view a slide presentation today after this call by going through our website at www.comstockresources.com by downloading the quarterly results presentation. There, you'll find a presentation entitled Fourth Quarter 2018 Results. I'm Jay Allison, Chief Executive Officer of Comstock. With me is Roland Burns, our President and Chief Financial Officer; and Dan Harrison to my left, our Vice President of Operations. Please refer to Slide 2 in our presentation and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. Now if everybody would go to Slide 3, it's an incredible slide, we'll summarize the major achievements in 2018. The most important, we completed comprehensive refinancing of the balance sheet made possible by the transformative transaction we completed with Jerry Jones when he contributed his Bakken shale properties for 84% stake in the company. The added cash flow and reserve value allowed us to enter into a new bank credit facility with a borrowing base of $700 million and to complete an $850 million senior notes offering. We were able to return all of our outstanding debt, which substantially lowered our interest costs and extended our debt maturities. As a result, our leverage improved from 6x to 2.8x at the end of the fourth quarter, which Roland will go over with you in a moment. We also had a great, great year with the drill bit. We drilled 49 successful Haynesville/Bossier wells, which had an average IP rate of 25 million cubic feet a day. The drilling program was the largest contributor to the 36% growth we had in natural gas production. We also completed two value-added bolt-on Haynesville shale acquisitions in 2018. We acquired 17,386 net with 225 or 66.4 net undrilled Haynesville shale locations and added 220 Bcf of proved reserves with a PV-10 value of $72 million and an additional 505 Bcf on probable reserves with a PV value - 10 value of $147 million. The acquisitions and our drilling program grew our proved reserve base at a very, very low finding costs of $0.25 per Mcfe in 2018. The additions, combined with properties contributed by Jerry Jones, grew our proved reserves by 109% to 2.4 Tcfe. Our PV-10 value of the proved reserves grew by 103% to $1.8 billion. Lastly, one of our major achievements in 2018 was returning Comstock to profitability subsequent to the August 14 closing of the Jones Contribution. To go to Slide 4. It summarizes our first full quarter results since the August 14 closing. For the fourth quarter, we reported oil and gas sales of $148 million, EBITDAX of $113 million and operating cash flow of $96 million or $0.91 per share. Most importantly, we reported net income for the quarter of $50 million or $0.48 per share. We expanded our Haynesville/Bossier shale drilling program by adding a fourth operated rig in September. We continue to have strong results from a proven drilling program as we have now drilled and completed 70 operated wells since 2015, which have an average IP rate of 25 million cubic feet equivalent per day. This quarter, we reported on 13 new wells, which had an average IP rate of 28 million a day. As we look ahead to the year, we believe we are positioned to have approximately a 50% growth in our natural gas production from the 58 Haynesville/Bossier wells we plan to drill. The next two slides were about acquisition. Slide 5 recaps the Enduro acquisition we completed in July for $41.5 million. We acquired 22,559 gross acres or 12,085 net acres in Caddo and DeSoto Parishes in Louisiana and Shelby County, Texas, which included 114 or 27.8 net producing natural gas wells, 47 or 14.6 net of which produced from the Haynesville shale. The acquisition added 220 Bcf of proved reserves with a PV-10 value of $72 million. We also acquired 257 Bcf of additional probable reserves with a PV-10 value of $46 million. On Slide 6, we cover the acquisition of undrilled Haynesville shale acreage that we closed on December 19, 2018. We entered into an agreement with Shelby operating to acquire 6,159 gross acres or 5,301 net acres of Harrison and Panola counties in Texas, offsetting our recent drilling activities in Caddo Parish and the Enduro properties. We're paying $20.5 million for the acreage in the form of a 12% carry on every well drilled on the acreage up to the total purchase price. There are 33 or 22.7 net high-quality drilling locations on the acreage. These locations represent 248 Bcf of probable reserves with a PV-10 of $101 million. I'll now have Roland go over the financial results for the fourth quarter. Roland?

Yes. Thanks, Jay. On Slide 7, we summarize our fourth quarter financial results and the results for the 140-day successor period post the Jones Contribution. The successor results include the Bakken Shale properties. Production in the fourth quarter was 36 Bcfe, including 843,000 barrels of oil. This is 53% higher than our fourth quarter of 2017. Production for the 140-day successor period was 53 Bcfe, including 1,385,000 barrels of oil. Our oil and gas sales were $148 million or 91% higher than the fourth quarter of 2017 and the fourth - and this most recent reported fourth quarter. Our total successor period sales were $218 million. Our EBITDAX for the quarter came in at $113 million, 101% higher than the fourth quarter of 2017. For the entire successor period, EBITDAX totaled $165 million. Operating cash flow this quarter was $96 million, 154% higher than our cash flow from the fourth quarter of 2017. For the entire successor period, cash flow was $134 million. We reported income of $50 million for the fourth quarter or $0.48 per share and $64 million or $0.61 per share for the entire successor period. The only unusual item to the quarter was the unrealized mark-to-market gain on our hedge contracts of $18 million in the quarter and $16 million for the successor period. Excluding the unrealized gain that we'll recognize or realize in the future, net income would have been $0.35 per share in this quarter and $0.49 per share for the entire successor period. On Slide 8, we recap our Haynesville/Bossier shale natural gas production by quarter along with a number of net wells that we put online on each quarter. Our Haynesville production increased from 256 million per day in the third quarter to 295 million per day in the fourth quarter. And this was caused by the 5.1 net wells that we brought on during the fourth quarter. Slide 9 recaps the production we had shut-in for the quarter. The fourth quarter shut-in volumes were down from the third quarter level of 20.5 million per day, but we still average 13.6 million a day of shut-in production. We didn't have any significant pipeline curtailments in the quarter like we had in the third quarter, but we did have wells shut-in for offset frac activity, both are offset activity and other operators in the basin. But Dan is really working on - in 2019 this year to figure out how we can try to minimize the amount of wells we have to shut-in for the year. So we'll always have to have shut-in production where we're doing offset fracks. On Slide 10, we detail our producing cost per Mcfe. Operating costs were $0.77 per Mcfe in the fourth quarter as compared to $0.84 in just the successor part of the third quarter. Gathering costs were $0.20. Our production taxes average $0.20, and our field level operating costs were $0.37 per Mcfe produced. The improvement in the rate is really due to the higher volumes that we had in the Haynesville - from our Haynesville wells, which have our lowest lifting costs. Our depreciation, depletion and amortization per Mcfe produced in the quarter fell to $1 per Mcfe as compared to $1.02 in the successor part of the third quarter. On Slide 11, we recap the growth we had in our proved reserve base in 2018. We grew our proved reserves from 1.2 Tcfe to 2.4 Tcfe in 2018, primarily from the contribution of 22.9 million barrels of oil and 51 billion cubic feet of natural gas by Jerry Jones, the expansion of our future drilling plans for 20 - for this year and for the next four years after that, resulting from the additional cash flow that's available to the company from the contributing properties and from our successful results from our Haynesville shale drilling and from our acquisition activities in the year. In 2018, we acquired Haynesville shale properties for 254 Bcfe of proved reserves, and we added 1 Tcfe of proved reserves from our drilling program in 2018 and the expected increase in drilling activities in the future. The 2018 proved reserve estimates include 187.4 net proved undeveloped Haynesville or Bossier shale locations as compared to 60.7 net proved undeveloped locations at December 31, 2017. So we're able to double the number of proved undeveloped locations that we could book in our SEC proved reserve estimates with the expanded drilling plans we now have for the next five years. Performance related revisions also contributed another 42 Bcfe to our reserve growth in 2018. If you look at our finding cost for 2018 with the acquisitions and the additions from the drilling program and the additional future drilling, it all - it came in at a very attractive $0.25 per Mcfe. 29% of our reserves on a volume basis were developed at the end of 2018, and our reserves were 94% natural gas. The PV-10 value of adjusted undeveloped reserves was $1.2 billion. 90% of our proved reserves are in the Haynesville/Bossier Shale and 7% are in the Bakken Shale, just on a volume basis. But on a value basis, the Bakken makes up 31% of our PV-10 value. On Slide 12, we recap our spending in 2018 on drilling and development activity and then what our estimates are for this year. In 2018, we spent $267 million on development activities. $224 million was in the Haynesville/Bossier Shale. And that was made up of $197 million of drilling - for drilling and completing wells and additional $27 million on refrac and other development activity. We drilled 49 or 17 net wells to our interest in the Haynesville or Bossier Shale, which had an average lateral length of approximately 8,300 feet. We also completed 16 or 4.2 net wells to our interest that were drilled in 2017. 30 or 11.9 net wells drilled in 2018 were also completed in 2018. And the remaining 19 wells or 5.1 net wells will be completed this year. We also spent $43 million of our total development cost at our other properties, the bulk of that going to completing 24 or 7 net Bakken Shale wells. Our planned capital expenditures for this year are $364 million. Haynesville/Bossier Shale drilling and completion activities comprised $340 million of that activity in 2019, which will allow us to drill 58 wells or 36.4 net wells and to complete 16 wells or 5.7 net wells that we drilled in 2018. We'll also spend an additional $24 million on our Bakken Shale and Eagle Ford shale properties. On Slide 13, we present our balance sheet at the end of the - at the end of 2018. We had $23 million in cash and $1.3 billion of total debt, which is comprised of amounts outstanding under our five year credit facility and $850 million in the new eight year senior notes that we issued in connection with the refinancing of our balance sheet. So at the end of the year, we had $273 million of - in total liquidity to help support the company's future drilling activities. We were able to reduce our leverage ratio as a growth - as a factor of both the refinancing and also really the big growth in our EBITDA. And that fell to 2.8x based on annualizing our fourth quarter EBITDA. On Slide 14, we have a summary of the hedge position that we have in place for our future oil and gas production. In the fourth quarter, we had 133 million per day of our gas hedged and about 3,600 barrels of oil per day hedged. In the first quarter of 2019, we have 222 million of our gas hedged, including 97 million a day that's hedged at an attractive swap price of $3.84 per Mcf. And then we have about 4,173 barrels of oil per day hedged. Our plan is to continue to target hedging 50% to 60% of our production on a rolling 12-month basis. So I now turn it over to Dan to kind of report on our drilling programs.

Okay. Thank you, Roland. On Slide 15, you'll see that we've showed before the satellites our 87,000 net acre position in the Haynesville and the mid-Bossier shale play. And since our return in 2015, we're now up to have completed 70 operated wells in the play with an average IP rate of 25 million cubic feet per day. This year's drilling program will currently run at four rigs. And by year-end, we plan to drill a total of 55 operated wells. Over on Slide 16. This is a summary of our current Haynesville and mid-Bossier drilling inventory. At this time, our total gross operated inventory stands at 963 locations with an average net interest of 76% or 735 net operated locations. This represents nearly 18 years' worth of drilling activity based on our current activity levels. The 963 gross operated locations consist of 413 10,000-foot laterals, 209 7,500-foot laterals and 341 4,500-foot laterals. The 963 gross operated locations consist of 518 locations in the Haynesville and 445 locations in the mid-Bossier. In addition to these 963 gross operated locations, we also have 607 gross non-operated locations with an average net interest of 14% or 84 net non-operated locations. This brings our total gross location count to 1,570 and our total net location count to 819. On Slide 17. This shows the location of the eight new operated wells that have been completed since our last update. And these are denoted by the red callouts. Only the operated wells were drilled at the Haynesville and were completed using our latest Gen 3 frac design that serves to fracking 3,800 pounds per foot at 15-foot cluster spacing. With the exception of our Jackson 21-28 #2 well, all the wells were completed at the nominal 10K laterals. The actual lateral lengths of these 10K wells range from 9,384 feet to 10,168 feet with an average lateral length of 9,650 feet. The initial production rates from these 10K wells range from 22 million a day to 30 million cubic feet a day with an average initial rate of 26 million cubic feet a day. The Jackson 21-28 number two well was the fill - well completed with a 5,239-foot lateral and had an initial production rate of 17 million cubic feet a day. In addition, the green callouts on the slide illustrate the strong results from five non-operated wells that were recently completed on the acreage acquired in the Enduro transaction. All five non-operated wells were completed as nominal 10K laterals and had an average lateral length of 10,087 feet. The initial production rates from these non-operated wells range from 28 million cubic feet a day up to 40 million cubic feet a day with an average initial rate of 32 million per day. Comstock's working interest in this non-operated acreage is approximately 30%. At this time, we currently have four additional 10K wells that we're in the process of completing. Over on Slide 18. This is just an updated illustration of the long-term performance of our wells that have sufficient production history. The decline curves are split out by the different completion of vintage in lateral lengths. The red, brown and purple curves represent our Gen 1, Gen 2 and Gen 3 completions, respectively, with a longer lateral completions of 7,500 feet to 10,000 feet. The data continues to show that the newer vintage, the Gen 3 completions with the heavier 3,800 pounds per foot sand loading and the tighter 15-foot cluster spacing, are continuing to hold up and outperform the earlier vintage completions. This is also an illustration of our short lateral wells. Our short lateral Gen 3 wells represented by the dark blue curve are also outperforming our short laterals Gen two wells represented by the lighter blue curve. And the green curve here, which represents our four Bossier wells has continued to outperform the Gen 1 wells over the long term. And with that, I will now turn it over to Jay to sum things up.

Before I close, you have to look at Roland's side, and you have to have this comprehensive refinancing of the balance sheet, which Roland went over, and it looks really, really strong. But then you've got to have a great year to drill bit. And I think that's what Dan just delivered, a great year. So if you go to Slide 19, we'll summarize our outlook for this year. Our Haynesville/Bossier shale asset provides us the opportunity to create value by using our operating cash flow to drill consistent, high return and low-risk wells. We plan to drill 58 or 36.4 net Haynesville/Bossier horizontal wells this year out of an extensive inventory of 819 net drilling locations. We expect the drilling program to drive very strong production growth and estimate that will produce anywhere from 385 million to 415 million cubic feet of natural gas per day in 2019. We expect the oil production to average somewhere between 8,000 and 9,000 barrels per day. We are very focused on creating cost savings in 2019. We are looking to reduce well costs by 5% to 10% by changing the completion design. And we are in negotiations to reduce the transportation costs for our Haynesville production for savings of anywhere from 10% to 20%. Our Bakken shale oil-weighted production provides leverage to oil prices as we use that cash flow to fund our drilling program. Our Eagle Ford joint venture across one - 14,600 net acres targets about 225 or 126 net potential locations, and it does add future oil growth to Comstock. Our primary strategy is to generate disciplined growth by operating within our cash flow. We believe this is the best way to continue to improve our balance sheet. Our leverage based on the fourth quarter EBITDAX, as Roland said, was 2.8x. Our goal is to reduce this to 2x over the next several years. We are hedging the next 12 months production to protect our drilling returns, and we ended 2018 with liquidity of $273 million. For the rest of the call, we'll take questions from the analysts who follow the company. So Christy, I'll turn it back over to you.

[Operator Instructions]. Our first question is from Ron Mills with Johnson Rice.

Jay, a question. I - you know we had talked about last fall, you were potentially looking to add a 5th rig in March. I know you said you're currently at four rigs. Is the plan to stay at four rigs? Or you're going to add a fifth rig? And if you do add the fifth rig, any color in terms of where that rig may be utilized?

Ron, this is Roland. Yes, I think that we are going to have a fifth rig, but not really necessarily to add to the wells in the drilling budget. It's really to kind of culminate some of the wells that we're drilling with lower working interest. So - and generally, and that will probably later in the year. And then we'd hope that next year, the 2020 program, based on where we are - the amount of cash flow we're producing for 2020 with the higher production levels would then justify kind of using the - a more of a five rig program on Comstock's acreage.

Yes. If you notice, Ron, well, the - kind of the guidance we put out at the end of '18 or what we put out today, we lowered the CapEx. Now we're going to toggle back and forth a fourth rig or whatever to stay within this operating cash flow. So that's the growth that we've given you. It's kind of a toggle program. We do have four solid rigs or there might be another one that kind of comes and goes, but depending upon frac schedules and stuff. So we're going to work that program really hard. [Indiscernible], you'd probably file this for 10 or 11 years. I would tell you, this is the single best vetted drilling program we have ever had because we look at offset operators. We figure out when they're going to drill or complete their wells as we have a slide on the shut-in. So we've got about 13 million a day shut-in, in the last quarter. We're kind of working on that, too, with offset operators. So it'll be a toggle of a fourth, fifth op rig, but it'll all be within this operating cash flow is our goal. It'll be a good year.

And it seems like in - versus December, so your Haynesville is coming down in terms of allocation, but the Eagle Ford's gone up a little bit. What are you - are you returning to your old operating areas? Or what's driven that change on the Eagle Ford side?

Well, I think the Eagle Ford, as oil prices have recovered a little bit from where they were back in late last year, we're in a joint venture there. And those are kind of projects that we have now teed up in the Eagle Ford. So we'll be drilling some wells in the Eagle Ford. Basically, on the Haynesville, we - instead of employing that fifth rig like we originally planned, we kind of a limited that coming in until very late in the year. So that's why we were able to kind of get CapEx down a little bit in the Haynesville. And - but the other activity that's not in the Haynesville is fairly - is mostly not operated for us. So we kind of respond to what the partners want to do. So there's a little bit of dollars allocated to complete the remaining docks in the Bakken. A lot of that work was done in the fourth quarter and late in the third quarter. And the Eagle Ford, we'll finally start actually drilling our first new Eagle Ford wells since we haven't drilled there in years. So we're excited about that.

Now that is a good point, though, because we've got about, again, one net Bakken well, which were mostly at nothing at 2018. But on the Eagle Ford, we don't highlight this with the slide, but we do have 126 net potential locations out of 225 gross. And we've had stellar success there for many years. We sold the PDP part, but we do have that upside. So we've got almost two net wells, kind of four gross wells budgeted. So I think that's something that's value added that we have started in a long time. So that's a good question there, Ron.

Okay. And then one last one. Just maybe more for Dan. Can you comment - I know you've talked extensively about stage spacing or frac spacing and - in proppant. But are you doing anything different from a flowback standpoint? Do you continue to see continued improvements on flowback? I'm just curious if that's all driven to completion design, if you're flowing it back differently. And are you seeing any risk of - or could you potentially flow it back more aggressively than you started out without any risk of damaging the productivity?

Yes. So that - Ron, that's definitely something that we've been looking at very closely. We have just here recently the last 4, 5 wells going through a little bit more aggressive flowback. I wouldn't say that it's a very big material change, but we're always trying to look at maximizing the return on the well. We're always looking at how the other operators are flowing their wells back. And I think that we feel that we probably can do a little more aggressive flowback, and we have done that probably on the last 5 or 6 completions that we've done.

Yes, Ron, we've tweaked those and they look really good. Again, we don't want to come out and say we're going to do that to all of them. But the ones that we have fought a little harder, they look a lot better. So I mean, we're not seeing any signs of any kind of degradation whatsoever. I mean, we want to basically get them flowed up and get them cleaned up quicker and get the flowback crew all sooner, save a little bit of money. And I think, overall, it's going to help the return of the well. And so far, I mean, the results have looked really good. We haven't seen any increased water production or anything that you might have expected beforehand.

I think one thing, Ron, we're 70 per 70 since 2015. And what we haven't done is become reckless. We're going to stay disciplined. We'll see what our peer companies are doing. We'll evaluate that. And then we'll evaluate our wells well-to-well. Like Dan said, we've got five of them. They look really good. So maybe we'll change it.

Our next question is from David Beard with Coker & Palmer.

Just a little bit of clarification on your view towards cash flow neutrality. It seems like you're pretty committed to growing within cash flow. Is that a proper way to think about the next couple of years?

Definitely. Our goals are to - are really to - the major goal is to reduce leverage. And our goal is to get to that 2x. So starting now, the 2.8, we've got work to do in opaque, putting on commodity prices. It could take a couple of years to really get there or if prices are better, we could get there quicker. But - so I think we'd look at how do we do that. And we don't - we want to keep - we don't want to add to that, but we do get there - we do reduce our leverage faster by growing EBITDAX. So I think we do want to kind of reinvest the cash flow into the drilling program as long as the returns are high in this - in the current price environment. We think that's the best way to go. But since the leverage reduction goal is a very important one, we don't want to increase that. So I think as we progress through the year, we'll - or see where gas prices are, we have some hedge protection. But I think that will be kind of how we look at the year. But yes, we want to stay as that operating cash flow is kind of the governor of the CapEx spending. And that's how we redesigned the program that we laid out today that's a - it's a little different than the one we had earlier.

Yes, we want to keep our liquidity and grow it. We want to be very disciplined in the locations that we drill. I think we're drilling some of the best of the best in 2019. I think you'll see that and that'll decrease our leverage.

Now that makes sense. And then just what would be the - how would you gate, let's say, if prices were better, would you need a quarter or two? Or is it really based if you can get some favorable hedges off before you would pick up activity?

Well, I think, yes. I think if we could get - if we had the opportunity to lock in prices that were higher because you get some sort of improvement in the longer term gas prices, that would be the real driver, the wanting to add more services to the program we have now. So I think that - I think this program is a great program for us this year. It provides a lot of gas growth. And I don't see us increasing it a lot unless there's a big shift in gas prices later. I think to the extent that oil prices continue to improve and get better, I could see us and our partner in the Eagle Ford wanting to do more there. So there could be growth there responding to prices probably faster than on the gas side, and we'll see the results of our first wells. We'll drill that first batch of wells there, which also helps meet any acreage obligations on that acreage. And then if those look really good and these will be the first wells we drill there in a while, that could be a bigger program for us later in the year or into 2020.

Yes. But remember, don't lose focus. We really are drilling Haynesville/Bossier. I mean, if the Eagle Ford turns out good, which we think that will happen, then that'll just be an additional value area. And again, remember, our board policy is to hedge - our goal is to hedge 50% to 60% of our production. So we always try to hit that number. We - that is our target. And I know we've added hedges lately and you've seen that on one of the slides. But we're going to be disciplined. When the Jones family invested, like you said, I don't have any debt. I don't really like debt. I want to delever it. And we had a material delevering of debt when they contributed the Bakken asset. We go from a 6 to a 2.8 leverage number, then we'll be coming down in 2019. So that's a pretty good governor right there.

Now all of that makes sense. And maybe just a little bit of a detailed question. When you look at where you'd allocate any excess cash flow between Bossier and Haynesville, historically, Haynesville have gotten the nod in terms of IRRs. And I guess if you look at Slide 18, the Bossier wells are certainly good, but your completion continues to improve. Do the Haynesville still get the nod relative to the first dollar or capital? Or can Bossier catch up? Or how do you look at that?

Well, I think we try to sprinkle in some Bossier wells. I think we have some in our plans for 2019 right now. I think we have like three. And I think it's a play that's - still, there's a lot of activity going on with other operators. It's a play we're still learning about, make sure that we have the optimal completion there. Well, the Haynesville is such a proven play for us. So I mean, it's - so I would say that most likely if we expanded the Haynesville, it's still going to be the first place you go. Although we continue to want to add to our Bossier activity. And like I said, we're investing some this year to continue to look at the Bossier, look at what other companies are doing and try to optimize the complete [Technical Difficulty].

Yes, and the other thing we look at, we look at where the other offset operators are active. We don't want to have any takeaway issues because these wells commanded 25 million, 30 million a day. So we look at that and then we plan it out. We do plan it. And I think on Slide 16, it's pretty phenomenal. We have 18 years' worth of drilling activity. So we can do a lot of planning.

Our next question is from Gregg Brody of Bank of America.

Just a few question for you. You mentioned the cash flow neutrality goal. I think in the last quarter - and I may be able to figure out what happened this quarter, you had some working capital for us that were negative I think because of some of your acquisitions, and you pointed to that. Is that - is there - should we expect any impact this year from that? Or should we expect generally no negative or no positive working capital adjustment?

Yes, Gregg, I think the - our working capital changes, you'll see that they are pretty immaterial in the fourth quarter. I guess now we've adjusted to kind of the activity level and the timing of non-operated versus operated. As you want to look ahead into 2019, we have kind of a positive $10 million of working capital coming in mainly, which is income tax refunds that we're seeing as soon as we file our return. So that - other than that, that's the only real we see kind of atypical kind of working capital kind of balancing out over the year.

And when you noticed even on Shelby's case, you pay as you go. We carry them for 12% on the well up to $20.5 million. And we picked up...

Yes, and we're on working that.

Yes, the 23 locations.

Got it. Slide 15 was - is very helpful. I appreciate you updating that and for sharing it with us. I know there are some incremental adds here from acquisitions. I'm just - I'm curious sort of - from what you'd - from your learnings in 2018 and I guess from the years before that, did that create - was there any rigs or were there any locations added from sort of performance? Any sort of acreage or swaps that allowed you to drill on the laterals? And are you still assuming six wells per section? I'm just trying to figure out if there's anything incremental in the acquisition.

Right. So it's not by the location count. I mean, I think what you see kind of presented today is kind of a really detailed accounting for the non-operated especially, which we really - is much harder to get your hands around. But yes, we have a real accounting for the non-operated locations, which we really didn't do in the past. But I think we still are drilling six wells pretty much within as far as in a section or six wells in two sections at the 10,000-foot laterals. And so the spacing has been very consistent. And we have done acreage swaps. We've done acquisitions. We've done new leasing. So all of the above, really. And we always are looking to optimize the situation around us. So when we have an interest in a lease and it's a single section, yes, we're - we work really hard to either lease that adjacent section to create more long laterals or do an acreage swap. We have at least one pretty good acreage swap still on the process that we hope to close maybe by the time we report next time, which will allow us to realign some laterals to their optimal way.

And typically, they're relatively easy to do because both sides win.

Yes.

We get longer laterals. They get longer laterals. Maybe we've got acreage in another area that we can trade, but it is usually...

There isn't a day where they take a lot of long time because you got to get it exactly equal and you got to clear every single issue from title to...

Maybe some production, maybe a little production you've got to change.

And then dedicate it. And I think sometimes - then you have to kind of do swaps to get the acreage dedicated to your providers versus theirs. So it's a great concept, and both companies win. But it's - it can take a while to actually get all the - everything lined up. But given the - given now that there are other active operators unlike we had years ago, we've got motivated parties that also can win by the acreage swaps.

Yes, that's helpful. Maybe sort of the ability to add your inventory through M&A. What's that environment look like right now? Obviously, you had some - it's a nice success in 2018. Do you think that's something that - are there opportunities in '19? And how would you fund that?

Yes, we think it's a - there'll be continued opportunities to do some bolt-on acquisitions like we've done - we did in '18. I mean, those were pretty impactful and didn't use a lot of capital. And we'd like to be able to accomplish more of those. And so I think as smaller companies, they can see the success we've had and we have the scale of operations. So I think there's a lot of benefit to some of the smaller companies kind of like we did most recently on December wanting to team up with Comstock to develop their acreage and have us, yes, lead the way there. So there are opportunities for that and opportunities for consolidation in the basin, too, potentially with the - with these markets right now, it's a - fairly weak M&A markets as far as if you're a seller and a great market if you're a buyer.

But what we do, we look at the locations that these other companies have as good as ours or better because you don't want to done down your quality of assets and then we say, can we do something with another company and continue to delever our balance sheet. So that's the things we look at. And we do look at it.

Do you have a rule of thumb of how you think about funding smaller acquisitions? And it seems like cash was devious. But at what point you'd start thinking about equity or some other creative financing?

Well, I think you've seen that we haven't used very much cash to do the acquisitions. So yes, we would - I think as far as doing a - we don't want to incur a lot of new leverage in doing acquisitions. So I think if we were to do an acquisition, we want to see the company less levered afterwards. So I mean, I think that we have a lot of resources at hand that maybe are on the company's balance sheet that help if there was a significant acquisition. So I think you just have to look at each one individually and kind of put them together kind of like we did on our December acquisition where - and really, we're going to pay that over a long period of time as we drill the wells. That was kind of a perfect use of - a perfect way to acquire it. So there's - it's hard to answer what it would look like in the future. But we're not looking to buy a whole lot of acreage and increase leverage. That's not going to be a part of our plan at all.

No.

And then my last question for you. So just wanted your views on takeaway and midstream capacity, especially in the context of availability, especially in the context of what you're suggesting you're going to reduce - potentially renegotiate rates this year for transport or reduce costs sort of - it's my understanding that perhaps, there are debottlenecks coming in the next few years. It's a bit of a surprise to hear your people negotiate rates lower.

Yes. I think where we are - I mean, we do have and we - we'll have that in place soon, that there still is a lot of capacity in the area. Now maybe it's not always in the right spot and there are some capital to upgrade or reconnect. But there's a tremendous amount of interest from the midstream companies to team up with the active operators and they're back and very compelling. Yes, we had a lot of undedicated acreage that we put together with just the bolt-on acquisitions that we did last year. And that gave us a lot of leverage to say, hey, you want to be our provider? Put out your best proposal. And we've got some great proposals. And in the process, we'll be able to lower existing - some of the existing costs we have now and also serve as the expansions that we're doing.

Yes, what we've seen is, again, with the Jones family backing us, like Roland had mentioned, the midstream companies have come in, and we've talked to them. And they're very excited about our growth. So I mean, we're working with them. And I think we'll reduce transportation costs and mainly, the debottlenecks are just from the wellhead or where the bottleneck is. So it's not the frontline.

Yes, they're very easy to solve. And it doesn't take a lot of capital, it's just they - they have a lot - they still have a lot of idle systems or systems underutilized. And if they can spend some capital to optimize that, I mean, that's kind of what they're - the ones that own the midstream in our area are doing.

And the midstream, they're excited about the industrial growth in that corridor, and they're excited about the LNG. So they're looking a year or 2, 3 out for that demand.

Right. Yes, we're looking at direct access to the Gulf markets in about half - some of the hubs that we typically sell out now. Those are the projects that we want to make sure are part of our - as we enter into new arrangements, that we have that - those accesses in the projects that are going to come online in the next year or so to give us direct access to where the biggest growth will be that - the LNG shippers along the Gulf Coast.

Our next question is from Jane Trotsenko with Stifel.

I have a question on lease operating expenses. They were below what the consensus expected. And that I was just curious if this is something that we are going to see going forward. Or how should we think about lease operating expenses changing given that Bakken acquisition?

Yes, that's a good question, Jane. On the - yes, we did - we will see a trend on the lifting costs continue to trend down as we go through '19, just like they were doing before we had at the Bakken properties. And the reason for that is because the new volumes that are coming on in the Haynesville have the absolute lowest lifting costs of our portfolio. And as they grow, their - the incremental new costs that we have for those volumes are so much less their average of that total of $0.77. So you should see that trend down and - just like you saw a trend down from the third to the fourth quarter. Probably just not dramatically, but maybe $0.02 to $0.03 a quarter kind of see that kind of movement downward in the lifting cost as we progress. Taken out whatever happens to production taxes is going to be more tied to oil prices and a little - yes, because if oil prices went up a lot, we'd have new production taxes. A lot of the new gas that we are bring on does have this kind of exempt period for the first couple of years. You're not having a lot of severance taxes on the new gas. So all the new production is definitely - should contribute to operating costs coming down a couple of pennies per quarter as we kind of march through 2019.

Got it. And then you had the positive commentary on transportation costs that you might be able to negotiate. Do you think we can expect that update sometime during the first half of '19? Or how should we kind of think about the timing of that?

So we hope to have that in place when we report next. So it's something that we can benefit of, the benefit of during - for most of 2019. And that will also help drive that because gathering costs is a big component of our lifting costs. So that can help drive that down some, too. So you got just the lower comp volumes coming in plus improved treating and transportation rates, both should contribute to lower costs for '19 and what you even seen in this fourth quarter.

That's very helpful. And my last question is more like a macro question. We have seen Appalachian produces - reducing their production growth rates going forward. So their overall Appalachia production could be lower than originally expected, let's say, like half a year ago. Do you think that we should maybe expect the same dynamics from the Haynesville basin like overall for all Haynesville producers? Or do you think the outlook is unchanged for Haynesville versus six months ago?

It's hard to say because of the different companies in the Haynesville. Yes, it's kind of a lot of private companies which all have different goals. But I would say that given that the economics are very good in the Haynesville unless you have kind of onerous marketing obligations and - that are causing your economics to be different, which is in place in parts of the Haynesville that we would think that the outlook would probably be pretty similar as we see the activity level kind of constant at the same number of rigs that we've seen.

Yes, we look at the rig count, 55-or-so rigs. That's probably a good number.

And our next question is from Ron Mills with Johnson Rice.

Just a couple of follow-ups. On the transportation costs, you talked about 10% to 20% potential savings through this negotiation with the providers. Is that 10% to 20% on new areas? Or would that be 10% to 20% off of your existing $0.20 number that you posted in the fourth quarter? And what are the - I guess what's the backbone of that negotiation in [indiscernible]?

So I think it's fair that we - right. Good question, Ron. I think the - well, basically, a lot of our contracts, we haven't done long, long term contracts. So a lot of the contracts, even that we redid several years ago, yes, maybe only have a few years left and then all of a sudden, we have a lot of acreage that we are planning for to develop that we acquired in 2018. So I think the combination of that is to say who wants to be the preferred provider of those treating and transportation services. So I think having that new business and the activity level of the company now is more robust with Jerry Jones backing. I think all those are the drivers of why it makes sense for that to happen. So I think we're looking to kind of be both program. I mean, obviously, the cost of the new areas, transportation rates being a little lower than what we've had in the past. But in combination of lowering some of our core transportation in our core kind of Logansport area, too, is kind of part of it. So I think you'll see - when we talk about the 10% to 20%, that's kind of what we had expected to see of the top line numbers at company-wide.

Well, Ron, and that - Ron, that kind of goes back to the fact that they do want the gas. They want the gas because they see the demand. And they're thinking, good for years out in the future. They do want this gas and they know we're going to be very active, and our production is going to go up a lot.

And then one quick one on the Eagle Ford and then one more. The Eagle Ford, who drives the activity down there? Is it USG or your JV partner? Is it you? I'm just trying to get a sense as to are you an activity maker there or an activity taker in terms of potential activity over time?

Well, I would say, we're - we have a unique partnership with USG. So I think we're - I would not say that we're either the maker or the taker, but we're a great partner. And that we - together, we kind of are both of those.

Yes, yes. So when...

And that - so we don't - so I think we - we're both anxious to see some new wells drilled. And there's some need to drill some wells on some acreage, to keep all the acreage, which we're dedicated both to do. And that's why I said that there were maybe some changes is because we both - we get so excited about the results in oil prices, make you want to drill more. But I think we're really doing that work midyear. So you're really not talking about a 2019 big change. It's a - what does the Eagle Ford look like for us in 2020 kind of based on we reiterate that doing some work in 2019.

Yes. And of course, Ron, all this is based upon the success we've had with them as they've had with us over the last three years.

Right. Remember, we're - we work together on the Haynesville acreage where we are our operator. So I mean, it's a unique relationship. It's not just like - this is just non-operated acreage and they're off doing something different.

And then lastly, you mentioned a couple of times growing industrial men, you have the LNG impact down on the cost. How do you plan on - do you have - consensually tapping that maybe with direct contracts with some of those users? And how does that impact potential consolidation? Does that bring bigger kind of more capitalized, maybe even foreign companies that are looking for exposure to LNG and maybe buy reserves? And I bring that up because you've talked about wanting to be a consolidator in the Haynesville. And this is - does all that impact that plan a little bit?

As you've read, there are lot of companies, including foreign entities, that have made some pretty bold statements that they would like the gas from the Haynesville/Bossier for their LNG facilities. You see the tens upon tens of billions of dollars that are being spent for the facilities. They kind of kept that a little bit in 2019. And then I think we have more capacity in a couple of years after that. But as you look at the export or other LNG or pipeline export to Mexico, and you look at the industrial demand growth, the chemical demand growth and you look at where the Haynesville/Bossier gas is. I think that's the romance of it. And I think that's why the Jones are there. And if we can continue to grow our footprint, and that's why we give you a sheet on our inventory, then we can continue to reduce these costs and we continue to really connect with the midstream because they know we want to consolidate the best we can and grow. I mean, even when the Jones family was attempting to cause the transaction with Comstock. I mean, we were looking at Shelby area. We're looking at Enduro. So we were doing all those things anticipating growth. And we're doing those same things today. So when the midstream comes in, and I want to - they want to work with Comstock so that we can provide gas directly to the Gulf ports, we're all ears. It's going to be I think a new type of partnership that we have with them. I don't think you'll see some of that in the first quarter.

Thank you. And that does conclude our Q&A session for today. I'd like to turn the call back over to Mr. Jay Allison for any further remarks.

Great. Again, I know everybody has been on the phone about an hour, but we've had a - we had a great year in 2018 at the drill bit. And we expect that same type year to drill bit in 2019. We delivered at the drill bit even under dire financial pressure. And we are now playing offense. We haven't played offense in 3.5 years. So we even expect to up our game and contribute even better results to everybody using our operating cash flow, which we've mentioned earlier, to drill consistent high return, low-risk wells that should drive strong production in 2019. And at the same time, we just got off that question with Ron. We fully expect to reduce our well costs and transportation costs, which should result in, really, an outstanding year in 2019. We're focused. We want to play aggressive offense. We're thankful we can do that. Again, I want to thank everybody for your support, for your ears for the last hour, for continuing to look at Comstock. And we commit to you disciplined growth and 100% dedication. So anyhow, thank you.

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