Earnings Call: Q3 2018

Nov 8, 2018

Good day, ladies and gentlemen, and welcome to the Q3 2018 Comstock Resources Inc. Earnings Conference Call. Currently at this time, all participants are in a listen only mode. Later, we will conduct a question and answer session and instructions will follow at that time. Also as a reminder, this conference call is being recorded. At this time, I'd like to turn the call over to your host, Jay Allison, CEO of Comstock Resources. Sir, please go ahead. Perfect. Thank you for the introduction. Again, I want to welcome everybody to the Comstock Resources Q3 2018 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 presentation. There you'll find a presentation entitled, Q3 2018 Results. I am Jay Allison, Chief Executive Officer of Comstock. And with me is Roland Burns, our President and Chief Financial Officer and Dan Harrison, our Vice President of Operations. During this call, we will discuss our first reported period after we completed the Jerry Jones contribution transaction. If you go to Slide 2 in our presentation, you'll note that our discussions today will include forward looking statements within the meaning of securities laws. While we believe the expectations of such statements to be reasonable, there can be no assurance that such expectations will prove to be true. Before we go to the Slide 3, 2018 Q3 summary, I'd like to make some unopening comment. I know we're going to go through all these slides, but I don't know if you can tell in my voice, it is really hard to express to each of you how excited we are to report to you today our first period of the new Comstock. Another results we will present today during this call are in 2 pieces. I understand that. There's the predecessor company and then there's the successor company. And I know it's a little confusing, but that is how the Q3 has to be presented. We've simplified it to the best that we could. The important note and the conclusion is this, and I'll say this statement again. Had we closed on July 1, our Q3 would have had oil and gas sales of $134,000,000 EBITDAX of $102,000,000 operating cash flow of $77,000,000 and net income of $30,000,000 or $0.28 per share. Now we are now profitable. So if you look at the future, as we have in the past and a lot of you, which are stakeholders and bondholders and analysts, as you know, as we have in the past since we restarted our HaynesvilleBossier drilling program with enhanced completion design in February of 2015, where we have delivered to each of you, our stakeholders, 62 wells that we have drilled and completed, which have averaged an IP rate of 25,000,000 cubic feet a day. We've delivered that since February 2015. We fully expect to continue to deliver to you strong results as we intensely focus on our HaynesvilleBossier Shale drilling program as we will outline on Slide 12 of this presentation for the remainder of 2018, 2019 and beyond. So with that, I want to go back and let's start on Slide 3. We closed on the contribution transaction where we exchanged shares representing an 84% stake in the company for Jerry Jones' Bakken Shale assets. We will use the cash flow from these properties, which was $53,000,000 in the 3rd quarter to fund an expanded Haynesville shale drilling program to drive our growth in 2019 and beyond. We're excited to report the 1st period of the new Comstock today. Again, as we closed on August 14, the first accounting period is 48 days. So our 3rd quarter results are presented in these two pieces, the predecessor company and the successor company. Even though it is only half a quarter, you can see obviously the results should give you, the investor, a really good feel for the new company. And we closed, like I said earlier, on July 1, our Q3, we would have had oil and gas sales of $134,000,000 EBITDAX of $101,000,000 operating cash flow of $77,000,000 and net income of $30,000,000 or $0.28 a share. Our HaynesvilleBossier Shale program continues to deliver strong results as we've added now a 4th operating rig in September and we will add a 5th in March of next year and Ron will give the pro form a growth on that. We've had very consistent results in our Haynesville drilling program as you've monitored it since February 15. Since we restarted our drilling program in the Haynesville with an enhanced completion design in 2015, We have drilled and completed 62 operated wells, which have an average IP rate of 25,000,000 cubic feet of gas per day. Now this is the beauty. This drilling program within cash flow will grow our natural gas production by 30% in 2018 and 50% in 2019. Lastly, during the Q3, we closed an attractive bolt on Haynesville shale acquisition, which added approximately 12,000 net acres in 31 net undrilled locations. We also sold some of our undeveloped Eagle Ford acreage in the quarter for $13,700,000 to help fund some of the acquisition activity. The sale also kept us, this is a proactive, it kept us from having to drill 4 wells that had to be drilled in the near term or this would have expired. If you go over to the Enduro acquisition, a great acquisition for us, that's on Slide 4. Slide 4 shows you the properties we acquired from the bankruptcy estate of Enduro Resources Partners. In the middle of completing the Jones contribution, we completed this acquisition on July 31, 2018, through a court directed bankruptcy sale. We acquired 23,000 gross acres, which is 12,000 net, primarily in Caddo and Assota Parishes in Louisiana, which included 120 or really 26.2 net producing natural gas wells and 14.7 net of which are produced from the Haynesville Shale. This acquisition adds almost 19,000,000 cubic feet of gas per day to our 4th quarter production. The final purchase price was $39,300,000 and we booked 207 Bcf of proved reserves with an SEC PV-ten value of $70,000,000 related to the acquisition. The compelling reason we acquired the properties is for the 112 undrilled locations or 31 net to us. Now I'll turn it over to Roland to go over the financial results for the 2 separate periods for the Q3, and then he'll turn it over to Dan Harrison for operational results. Roland? All right. Thanks, Jay. On Slide 5, we summarize our Q3 financial results, again broken into the 44 days of the old Comstock and the 48 days of the new Comstock. The successor results included the Bakken Shale properties. Given the change of control, our assets were assigned a new accounting basis, so there's no good comparability on the new Comstock to the predecessor. But that's probably a good thing because now we're very profitable with a new consolidated low cost structure. For the successor period, our production for the 48 day period was 17.4 Bcfe, including 542,000 barrels of oil. In the predecessor period, our production was 11.9 Bcfe with very little oil. The pro form a 3rd quarter production would have been 27.1 Bcfe of natural gas with an additional 1,023,000 barrels of oil had we closed the Jones contribution on July 1. Oil and gas sales in this quarter were $70,000,000 for the new Comstock and then $33,000,000 for the old. Pro form a sales would have been $134,000,000 EBITDAX came in at $53,000,000 in the last 48 days of the Q3 and $24,000,000 in the 1st 44 days and was $102,000,000 on a pro form a basis. Operating cash flow was $39,000,000 in the last part of the Q3 and $10,000,000 in the first part, which the first part excluded the Boisne and Shale properties. Pro form a cash flow was $77,000,000 We reported net income of $13,800,000 for the 48 day period or $0.13 per share. The only unusual items in this period was unrealized mark to market loss on our hedge contracts of $2,200,000 and a very small gain on property sales. Without these items, net income would have been $15,900,000 or $0.15 per share for that period. Pro form a for the quarter, net income would have been $26,000,000 without these items or $0.28 On Slide 6, we show our oil production by quarter. You can see that all of our historical oil production from the Eagle Ford was sold in the Q2 of this year. But starting in the predecessor period of Q3, we averaged 11,300 barrels of oil per day, mainly attributable to the contribution of the Bakken Shale properties. We expect 4th quarter oil will be a similar number, then we'll see oil production decline in 2019 to 8000 to 9000 barrels a day given that we plan to do very little oil drilling in 2019. On Slide 7, we recap our natural gas production by quarter. Our Haynesville production increased from 222,000,000 per day in the 2nd quarter to over 250,000,000 a day in the 3rd quarter. We expect 4th quarter natural gas production to increase to over $300,000,000 per day with significant growth in store for 2019 where we see our gas production averaging between $370,000,000 $420,000,000 per day. On Slide 8, we give you accounting for what was shut in for the quarter. Our natural gas production in the 3rd quarter was again substantially impacted by shut in production either related to offset frac activity or pipeline curtailments. We've had continued issues in our Caddo Parish area handling the increased volumes from our drilling in our JV area. As of now, we seem to finally overcome all the growing pains and now have the capacity to fully sell our gas volumes to that area. In total, our shut in volumes averaged $20,500,000 per day during the Q3 of 2018, 40% of that related to our pipeline and plant problems up in Caddo Parish. And then 60% relates to offset frac activity. We were doing we had quite a bit of fracs during this period around some of our high volume wells, which had to be shut in to protect them from the offset frac. We do expect to see shut in volumes finally much lower in the Q4 as we have the gas flowing in Caddo Parish properly now and just the location of our activity hopefully will allow us to shut in fewer wells. But in the future, we'll continue to always have a probably a significant amount of shut in activity given all the activity going on in the Haynesville and the need to shut in wells near and near and offset frac. On Slide 9, we summarize our hedge position, which we have in place both for our oil and gas production. In the upcoming Q4, we have 133,000,000 per day of our gas hedged and about 3,500 barrels of our oil hedged. And our plan is to continue to add positions to hedge 50% to 60% of our production for the upcoming 12 months. And we're currently adding some more positions right now to kind of build up our 2019 volumes. On Slide 10, we detail our producing costs per Mcfe. Operating costs were $0.61 per Mcfe in the first part of the Q3, the predecessor part, and then they increased to $0.84 after the Bakken oil wells are incorporated in. That was comprised of gathering costs of $0.20 production taxes of $0.23 and field lever cost of $0.41 Our depreciation, depletion and amortization per Mcfe produced fell to $1.02 in the successor period as compared to $1.17 in the predecessor period and then 1.19 dollars so in the quarter before that. The costs that we're presenting on this slide that are kind of circled with the in the box will really give you a good roadmap to what to expect in the future as now all the properties are kind of in the period that full 48 days period. So this should be a good indication of what we expect these costs to look like as we go forward into the Q4 2019. Slide 11 presents our balance sheet at the end of the quarter. We ended the quarter with $32,000,000 in cash after retiring all of our debt on August 14. Our new debt totals $1,300,000,000 comprised of a 5 year credit facility and $850,000,000 in new 8 year senior notes. We had $282,000,000 in liquidity at the end of the quarter. We had about $50,000,000 more outstanding on the credit facility and the pro form a amount after the refinancing and the Enduro acquisition, and that was really due to an increase in working capital. With the new non operated properties coming into the company, the timing of revenue receipts is often 1 to 2 months slower than operated production. And often we had to prepay drilling and completion costs to the operators in advance. The 3rd Q4 of this year have a significant amount of non operated projects, both on the Bakken shale properties and on the non operated part of the Embureau properties. We don't expect many non operated projects, however, as we get into 2019. And on Slide 12, we'll show you kind of what we our preliminary view is for the 2019 drilling program and then how we finish up the rest of this year. We plan to operate 4 drilling rigs to the end of this year and then we'll add that 5th rig, like Jay mentioned earlier, in somewhere sometime around March of 2019. We're estimating that our capital expenditures in the 4th quarter will be about $90,000,000 and that's made up of $69,000,000 to drill 21 Haynesville Shale Wells, but 6.6 net wells, including 12 operated wells or 6.3 net. And then we also have we also expect to incur about $21,000,000 to complete 30 Bakken Shale wells or 4.4 net to our interest. As we look ahead to 2019, our first path at our budget is that we'll spend about $377,000,000 The HaynesvilleBossier Shale drilling and completion activities make up $361,000,000 of 20 nineteen's activity and involve drilling 57 wells or 38.2 net wells and there will be about $25,000,000 to complete wells that were drilled in 2018. We do expect to spend another $60,000,000 on all our other properties, including the Bakken Shale properties. But we'll continue to adjust this budget to stay within the operating cash flow that we expect to generate in 2019. I'll now turn it over to Dan who will give you an update on what's going on with our drilling program. Okay. Thanks, Roland. On Slide 13, this is the same slide you've seen several times before. This highlights our 81,000 net acres in the Haynesville and Mid Bossier play across North Louisiana and East Texas. Since our return to the play in 2015, we drilled 62 operated wells with an average IP of 25,000,000 cubic feet per day. We're currently running the 4 rigs in the play, and by year end, we plan to drill a total of 31 gross operated wells. Overall, Slide 14. I want to discuss the latest iteration in our completion design, which is shown on this slide here. Before I do, I'll give you a brief review of our past completion design. Our initial wells in 2015 early 20 16 were completed using our Gen 1 frac design. The Gen 1 frac design was based on completing 2 50 foot stage lengths, which is 5 clusters per stage at 50 foot spacing between clusters and was designed for £3,000 of sand per foot. This design worked very well, but we knew we could improve. In late 2016, we shifted gears to our Gen 2 design, which the goal was to reduce or tighten the spacing between clusters. The Gen 2 frac design was based on completing shorter 150 foot stages, which is 5 clusters at a reduced 30 foot spacing. At the same time, we increased our sand loading from £3,000 per foot to £3,800 per foot. The Rorvo's current completions today, we are continuing to pump our Gen 2 frac design based on 150 foot stage lengths and the sand loading remaining the same at the £3,800 per foot. Several of our Gen 2 designs, we've been testing a modified cluster spacing, which is based on an even tighter 15 foot cluster spacing and simultaneously increasing our clusters per stage from 5 up to 10. As you can see on this slide, we now refer to this modified our modified Gen 2 frac design as our Gen 3 frac design. The goal of the Gen 3 frac design is to increase the frac intensity near the wellbore while maintaining the same stimulated reservoir volume as the original Gen 2 design. The benefit to the Gen 3 design or doubling of the number of take points along the wellbore, minimizing of bypass reserves between clusters, fewer frac hits in our offsetting wells and also lessening intensity of those frac hits. We've already observed fewer frac hits at our offset wells when we use the Gen 3 frac design, and we believe that with fewer frac hits between wells, we should also experience less production interference between wells. As our development continues to migrate towards more full section development projects, we feel it is imperative that we minimize the production interference between wells while maintaining and maximizing our EURs per well and ultimately the NPV for the section. So what is the best combination? We don't have the perfect answer yet, but we know the right answer depends on where a well is located in the play and the performance history of the wells in that immediate area. I would say today, we're very close to the optimal completion design for our area of the Haynesville. Looking over to Slide 15. This shows the location of the 10 new wells that we have that have been completed since our last call. 2 of the 10 wells were completed with the original Gen 2 frac design, that's with the 30 foot spacing, and are denoted by the green callouts. The remaining of those 2 wells were completed with what we now are calling the Gen 3 frac design and are denoted by the red callouts. The average initial production rate of all 10 wells was 25,000,000 cubic feet per day. The Cook 2120 8 HC 3 and 4 wells were both drilled at the Haynesville, the 3 well having a 9,400 foot lateral and the 4 well having a 9,000 183 foot lateral. The initial production rates were 21,000,000 cubic feet per day and 24,000,000 cubic feet per day, respectively. The round 718 HZ 1 and 2 wells were both drilled at the Haynesville, the 1 well having a 9,771 foot lateral and the 2 well having a 9,837 foot lateral. Initial production rates were 24,000,000 cubic feet per day and 25,000,000 cubic feet per day, respectively. The Fagley, 1918 HC No. 1 and No. 2 wells were drilled at the Haynesville. No. 1 well having a 9,850 foot lateral. The No. 2 well having a 9,865 foot lateral. Initial production rates were 25,000,000 cubic feet per day and 26,000,000 cubic feet per day, respectively. The Bagley A 4 HZ 2 and 3 wells were both drilled to the Haynesville. The 2 well had a 4,539 foot lateral. The number 3 well had a 4,513 foot lateral. The initial production rates were 23,000,000 24,000,000 cubic feet per day, respectively. And then on our Brantley 21HZ 1 and 2 wells, they were also both drilled to the Haynesville. The number 1 well having a 4,532 foot lateral, the number 2 well having a 4,502 foot lateral. The initial production rates were 28,000,000 27,000,000 cubic feet per day, respectively. As of today, we are currently fracking 2 additional wells. Flipping over to Slide 16. So Slide 16 is the same slide that we showed before. This shows the latest update to how the wells with sufficient amount of production history are performing against our 7,500 foot type curve. On this slide, we have separated out the new Gen 3 wells from the original Gen 2 the original Gen 2 design wells. This slide clearly shows the distinction between the performance of the Gen 3 wells and the Gen II wells, both for the longer laterals and for the shorter sectional laterals as well. So the key takeaways from this slide are really simple. The new Gen III wells are outperforming the Gen II wells to date, and the Gen II wells are continuing to outperform the Gen I wells. The green curve, which represents 4 Bossier wells, continues to outperform our average Gen 1 wells over time. Slide 17 provides an updated summary of the underlying assumptions and economics for the different lateral length cases we're now using for our Gen III frac design. As everyone knows, frac costs are the driver for our total well cost. With the softening frac market, we've been able to drive down our total well cost, which has bolstered our economics. At $3 flat gas price, we're generating a 57% rate of return on our 4,500 foot laterals and a 75% return on our 10,000 foot laterals. As we increase the price to 3.50, the rate of return increases to 86 percent for the 4,500 foot laterals and over 100% for our longer 10,000 foot levels. For our 2019 HaynesvilleBossier shale program, we're planning to run 5 rigs throughout most of the year and will drill 52 operated wells. Approximately 70% of the wells are planned to be drilled at 10,000 foot laterals, which will give us an average lateral length of 8,400 foot for the program next year. We're continuing to push down well costs, improve our well performance and also improve our gas takeaway cost structure. All of these measures employed together will generate strong returns and cash flows going forward. That's a quick summary of the operations, and I'm now going to turn it back over to Jay. And remember, Dan has been here since 'eight. He said on the very first well we drilled, and he's still here today. If you look at the slides, I love slide 16, 17 that he went over, our Gen 1 was good, Gen 2 is better and Gen 3 is better than Gen 1 or 2. So that's a really good slide. And then, of course, the well economics, we're just fortunate to be in this area. The well economics are stellar. If you go to Slide 16, we summarize our outlook for the rest of this year and for 2019. We will look to our Haynesville and Bossier shale assets to generate preserve and production growth in 2019, as Roland said. We have an extensive acreage position of over 900 locations in this prolific natural gas basin. The Bakken shale oil weighted production will provide future exposure to oil prices as we use that cash flow to fund an expanded drilling program. We also have acreage in the Eagle Ford Shale that we'll develop with our partners starting next year. We have the asset base to generate substantial production growth all within operating cash flow. The growth will help us make progress toward reducing our leverage from 3x to getting us under that 2.5 times as a goal in 2019. We'll also hedge 50% to 60% of our anticipated next 12 months production, as Roland has mentioned, to reduce our exposure to oil and gas prices. We have great liquidity of $282,000,000 entering the 4th quarter. Now for the rest of the call, I think we'll take questions from the analysts who filed the company. So any questions from the analysts? Thank you, sir. Our first question comes from Ron Mills from Johnson Rice. Please go ahead. Good morning, guys. A couple of questions on the Gen 3 completions. You talked about completion costs coming down a little bit. When I look at your slide deck, it shows the well costs are pretty similar to your last presentation. Where do you see those cost savings on the completion side? Is it just current market for pressure pumping? Are you using local sands? Or what's driving that? So yes, you pretty much hit the nail on the head. It is basically the frac cost. Now that does include we have switched from using the Northern White sand to the local fortyseventy sand that's kind of included into our lower frac cost that we're projecting. But we've seen from this time last year, we have seen a pretty rapid pretty significant reduction in frac cost, nearly 30%. We've just went out and bid our 2019 work. We've had we're looking at costs lower than what we have today, probably another 10% to 15%. So that is pretty much the main thing that's driving the cost down, the total well cost. Okay. And then from a completion design standpoint, the Gen 3 really is just a perf cluster. I think you mentioned some the fact you're trying to get just near wellbore contribution higher. Can you just expand a little bit on what you've seen on those Gen 3 wells in terms of to explain what you were saying about minimize or to minimize risk of offset frac hits and ability to potentially drill, I'm assuming on tighter spacing. Is that right? Well, this all started out. We've this has been a natural progression when you look at Gen 1, 2 and 3. So we decided to go to the 10 clusters per stage. We could have went to, I mean, 15 foot spacing at 10 clusters. But if you make really small changes, you get small results and you really can't tell if you're making a difference or not. So we went a little bit bolder when we basically cut in half the spacing that we had from 30 to 15. And when you go to full stage development, it's key that you don't have interference between wells that lead to degradation in your EURs. So the goal really was to maintain our where our performance was while minimizing the interference. Now we've been kind of pleasantly surprised that the production has actually shown to be a little bit higher, higher to date anyway for the Gen 3 design. But the goal is to preserve the EURs and not have any degradation when you do a full section development. I mean that was the goal. Okay. And then great. Last one for me on the Haynesville. When you think about JV acreage up in Caddo Parish versus DeSoto Parish, you think about 5 rigs. How does split how do you think the split looks between those two areas given that your higher working interest in So to than Caddo? Yes. Yes, Ron. Yes, Ron, this is Roland. Yes, what we kind of see is running 1 rig on the JV acreage in Caddo next year and that's and you'll see kind of the net even though the gross wells don't seem to dramatically change as much, but the net wells definitely do. So we are drilling having really 4 rigs, drilling higher interest wells, more concentrated in DeSoto Parish for the most part and just running one rig up and to kind of continue to develop our North Haynesville area in Caddo Parish. So a little different mix, but I mean really going back to because of the additional capital we have after the Jones contribution, we're really going after some of our best projects that we have in inventory in next year's program and it's really we're picking out. So we think you'll see and if you look back to 20 18, we're trying to really minimize capital expenditures, but also provide growth. So we kind of leaned more on lower interest projects to kind of to get exposure to the basin that had less capital cost to us. And now we're going to kind of go and kind of pull from the best part of the inventory in the 2019 program. So thank you all and you all start we started that in September. So I think you'll start seeing a bigger impact from the drilling program even in the 4th quarter because of the high better concentration in the net wells, but a good observation that you made. Ron, the other thing, I mean, we've been in the area one. We drilled our 1st Haynesville well in, of course, 2,008. And we're just well connected with the other Haynesville operators. So what we've done now, we've tried to reach out. We've got a consortium group and they kind of say, well, where are you drilling? Where are you completing? So we try to front run that too. So every Haynesville operator has the least amount of interference with shut in well. So I think with our acreage position spread out, you know, Harrison County, Panola County, you've got Caddo Parish, Chassota Parish, etcetera. We've also tried to spread out our drilling rigs, so we'll have the least amount of interference in a planned 2019 program. I think that's really important. Dan has done a really good job for his role and on working on that. So that is that's big. And again, we've got so much of the Tier 1 acreage in locations, we can't do that. One thing, Ron, I think they'll start to show if we want to take credit for it before it happens. But I think what's given the additional strength we have in the balance sheet, the larger program, yes, I think we're going to drive more synergies and lower service costs. I mean, we already saw that immediately when with much more competitive frac contracts. We're working on reducing our gathering cost and being able to do that with a lot of strength because of the bigger program. So I think you'll see us be able to drive cost reductions just in all different parts of the company, with and didn't show up in the Q3 yet, because remember, we were only we just got out of the nursery on August 14. So we haven't been yet see the results yet, but I think you'll be pleased with seeing improvements in those numbers as the company could start really using more stream. And Ron, that's why we started it. It is a little confusing and how we had to break it out to the predecessor and successor, but that's as simple as we could get. From here on out, it will be very simplified and it's going to be beautiful. So anyhow. Great. Thank you very much. Thank you. Our next question comes from Jane Trotsenko from Stifel. Please go ahead. Good morning. I have a question on crude oil and natural gas price realizations. I'm curious which pricing points your Bakken crude oil and natural gas are priced at? Well, I mean, we basically have different operators operating the Bakken Shale properties. All non operated. So I mean, I think that question varies depending on which projects it is. But you kind of see and the gap up there is processed. So a lot of the we report on a 2 stream basis, so all the cost to process and all that deducted out of the gas price up in the Bakken. So there's not an easy answer to that question without getting into kind of well by well. If you can kind of see the basic realizations, we think we kind of we tend to should average about $4 to $4.50 under WTI kind of all in. That's kind of how we see the Bakken properties. I just want to make sure that you guys don't have like a large exposure to Clearbrook differentials in Bakken, right? Right. Well, I mean, the I think the number is going to show exactly where we are, yes. Okay. Okay. And then my second question is related more like to Haynesville macro. So we have heard that several Haynesville let's say several Haynesville pipelines have been proposed by mid stream operators, which would point to strong production growth expected to come from the basin. But at the same time, the rig count stabilized at around 50 rigs. And you just mentioned that you have talked that you are constantly talking to other operators. I'm just curious what you are hearing on the overall 2019 activity levels in the basin. Are they going to be relatively flat year over year? Or should we see an increase in overall activity levels in the Haynesville? Yes, that's a good question. Overall, the Haynesville, we've seen, like you said, you've observed, it's a very kind of flat kind of rig count in the Haynesville. I think a lot of that's more pointing to the weakness of the capital markets and the nature of the operators in the Haynesville. So we see that being very flat. We are having and we're working to optimize as a lot of the producers are wanting to get the gas to go directly down to the LNG markets. That's going to be the premium markets and kind of looking for direct access where you would now go through the Perryville hub and can gain another $0.05 or 0 point 0 $6 per NCFE. So that's the trend and that's what a lot of the that's the new projects. They're not necessarily to handle a lot of probably new volumes. So they are probably designed to take the Haynesville gas to a more direct path to the premium market and keep that Haynesville area obviously to be one of the top highest realization basins in the country. And so that's the trend. We're all as producers, we all want to get access to the premium Gulf market, the most direct way and that's the trend. But we see production given the rig activity, I think that's going to drive the production and we don't see the rig activity ramping up at all dramatically right now. No, the takeaway again, like Roland said, we can go east and west. We're trying to go south directly to the LNG demand. So we're working on that. I think that will make us even more profitable and valuable, particularly as the more gas we produce, the more leverage we'll have to get there. Correct me if I'm wrong, but no direct pipeline going south, like new takeaway has not been announced yet, right? There are several in the works, but I don't know how to think. In the works, but not like in construction, right? Yes. I don't know if they're in construction. I think that's correct. You're right. Okay. And then my last question is concerning Bossier wells, if you're going to drill any of those wells next year? Yes. We are going to go back to the Bossier. Again, we'd like the results of our first handful of wells. They have they're different wells. They don't have the IPs as high as the Haynesville, but they do have a lower decline as kind of our batch is proven out. So we've got some Bossier wells in our budget, but I think about 3 or so is kind of within our budget. Yes, it's 3 to 4. 3 to 4 Bossier wells right now, yes. Back in the same area, I think, that we drilled before. But again, the Haynesville, that's really the top projects and that's why the budget with a lot of inventory to choose from is kind of your top projects, especially for production right now is the Haynesville projects, even the short laterals, long laterals, they provide a lot of production per CapEx spend. Got it. Thank you so much. Great questions. Thank you. Thank you. Our next question comes from David Barrett from Coker Palmer. Please go ahead. Hey, good morning, gentlemen. Thanks for the time. You bet. A micro and a macro question. Micro and a macro question on the micro front, given your guidance for production, what would you expect for seasonality as the quarters roll out? Would it be steady or stronger in the first half than the second half relative to sequential? But any kind of color you could give us on that would be appreciated. Sure. You're talking about, yes, as we look at bringing the volumes on, it's obviously it's probably a little we have good growth as we get into the especially the Q1 next year if you start to see the impact of running 4 rigs. Maybe the 5th rig comes in March. Yes. So since the 5th rig comes in March, you're really seeing the impact of that not till the second half of next year. So the second half is going to be a little bit stronger than the first half for our growth plan. And that gives us the flexibility to say to react because if we gas prices underperform where we are and where we're hedged at, we can delay that 5th rig or eliminate that 5th rig. So we're pretty comfortable that the 4 rigs is very solid in a not a great gas price environment. And the 5th rig is more of a how do we invest the cash flow and it's more of the one we want to add. And if you notice we're waiting to add that when all these non operated expenditures from the Bakken where there's a lot of DUCs being completed there. And then even our recent Enduro acquisition, there was there's 5 wells being drilled there that we have a fairly big interest in. So that non operated activity kind of is all kind of washed is kind of completed in the Q4. Next year, we don't see a lot of non operated activity. So that's another reason why we kind of keeping that rig back until we make sure we have all that covered. Hey, David, this is Dan. I'll add to that we've got a really good mix on our rig contracts currently. We've got some that are very short term contracts and some a little bit longer contracts. So we got a lot of flexibility. If we need to drop a rig on short notice, I mean, we could do that next year. Got you. That makes sense, especially given the curve is so strong in the front months here and then who knows back half. Switching over to a bigger picture question relative to M and A in the Haynesville, obviously a lot of companies large and small out there and you guys have a goal to delever. How should we think about leverage metrics relative to doing a sizable acquisition Or asked another way, if you did do that, where what leverage metrics would you be looking at if you did a large acquisition? Well, obviously the Haynesville cut an area that's opportunity rich is on the M and A front given there's we're one of the few public companies out there. It's a lot of private companies. And but I think we just had a transformational transaction and with a real goal of reducing leverage over the next couple of years by developing our Haynesville properties. So if we were to entertain anything other than a small bolt on acquisition like Endura was, we'd have to improve the leverage metrics. I think that's a key attribute. We're not looking to grow at cost of going backwards there. So those gave us the opportunity to improve leverage and make the company better all the way around. I think our primary our major stockholder Jerry Jones would consider it. But the extent that it requires us becoming more levered, I think it would be a kind of a nonstarter. Yes, more leverage, David, would be a deal killer. If they had inferior acreage, it'd be a deal killer. If the core were not in the HaynesvilleBossier, which is our backyard, it'd be a deal killer. If they had burdensome firm transportation agreements that kill their economics, that's a deal killer. If there's something we can do that's transformational like we did with Jerry Jones, I think he'd be smart enough to want to do that. So yes, I think the world is pretty bright for us in the future right now. Like Roland said, we do, in our opinion, have a great reputation or I don't think the Joneses would have dealt with this. 2nd of all, we've been here a long, long, long, long time. We've got a we've got a deep root structure, and I think we're just now starting to grow the tree. So it looks pretty good. Right, right. No, and I think specifically, it looks like if you get to the 2.5 leverage, you're not looking to go backwards at all even with an acquisition. That becomes a ceiling in terms of leverage. If you got down below that at some point in time, you could then maybe go up a little bit, but that seems to be a ceiling versus a floor. Yes, I think we would agree with that. Look, we've been in that ditch. I hate it. Been muddy, and I hate it, and I don't want to get in it. I want to stay in the middle of the road, okay? Yes. Understood. Thank you, gentlemen. Appreciate the time. Yes, sir. Thank you. Thank you. Our next question comes from Gregg Brody from Bank of America. Please go ahead. Good morning, guys. Good morning. Just a couple of quick ones for you. You mentioned the cash burn associated with the non op about $50,000,000 Should we expect that to reverse next quarter or is it going to place over the through 2019? How should we think about that? And maybe just in general, are there anything else working capital wise we should be thinking about going into next year? Yes, Greg, I don't know if we call it cash burn, but I guess what we really saw was Comstock historically has been we've operated 98% of everything. So the timing of operated revenues and expenditures are a lot different than non operated. I mean, we'll receive the cash from the sale of operating production maybe 2 months quicker than operated the non operated production because the operator has to process it, hang on to it and probably waits a while to send it to us. That's the typical way. And we were on the other side, and that's why we love to operate. And then the same thing on expenditures, it's really the opposite there. I mean, usually, you're cash called and have to pay for the CapEx in advance. And so we have a significant amount of prepayments that we just never have because we don't, obviously, don't cash call ourselves. So I think that big shift was a pretty big shift that now I think what happens is the CapEx part will reverse because we're going to those projects are going to be finished up, but by the most part early next year. And we don't really see the Bakken opportunity was kind of contained. So we don't see a lot more of that. So you'll see a big reversal of that. Some of the CapEx that we haven't within our budget, we've already paid for and it's paid for up there and we've got the advances up there and other current assets. As you see, that number is really big compared to what it used to be. So I think but as far as the receipts, the oil and gas receipts, that's probably those will come slower. They'll come and so we'll have a bigger amount of our revenue inside accounts receivable for the oil production than we do for the gas. That won't reverse because that will be what happens is as the company is growing, it's really growing on the gas side. So the effect of that will also you'll see diminish. So long answer to your question, but basically I would say a good bit of it is going to reverse, but some of it's we're going to have to be we'll be carrying more receivables than we on non operated properties than operated. Got it. But you don't see any increase through 2019, just getting some of it back? Yes, we see it kind of reversing back and we do want to kind of pay down the credit facility as we get as we get all those as the since we prepaid capital expenditures. And even though we haven't expensed that yet, that's going to part of our budget, we won't actually have to pay. So that's when we'll pay that cash flow down on the credit facility. So a little bit of a transition there to have it almost a good bit of our revenue stream non operated with the transaction. That's helpful. And you gave these pro form a production numbers for as if Bakken was in for the full year in your slides. And I believe you said all the The full quarter, I guess. Yes. You had also mentioned that the constraints for the shut in production that's behind you, did that impact 4Q at all? Should we be taking some should we be reducing those numbers a bit? Or is it completely behind you by the time the Q4 started? We're always going to have some shut in volumes, so we always factor in for offset frac activity. Sometimes that can be more intensive, especially we're shutting in our some of our best wells, which we were as we were setting in some real racehorses down there when we did like the Brantley and some of those wells. So it can be more impactful than not depending on where that is. But there's always going to be an element of shut in offset frac now. But we expect and we're holding them accountable that our midstream partners are not going to have the issues. Now we grew production so fast up in Caddo Parish in an area that hasn't seen that kind of production in God knows how long. So they had all they thought their facilities could handle it, but then they didn't. They had to and that happened like 4 or 5 times, very frustrating. But we do see that it seems to knock on wood that they it seems to be flowing good up there. And hopefully they've made all the improvements they can to the volumes up in Caddo Parish. This is Dan. I'll echo what Roland just said. I mean, we've been for the last month, we've been flowing without any issues up there. They just had some they had to get they did some upgrades to the treating plant. They had some hiccups, should have been on and flowing well, had some hiccups that they had to go back and fix again. Then our downstream pipe ran into few little more issues that they had to get solved. But for the last month or so, we've been flowing basically unrestrained. So just just dealing with the offset frac activity. Which should mean that we should have a significantly better looking chart on the shut in production for the 4th quarter because that's going to be most of the Q4 there that we've been flowing good. So we're optimistic there that you don't have to be as worried about it. Hopefully, we kind of grew through that adjustment up there. And now we're kind of the 1 rig program up there. I think the production is going to be more the growth is as dramatic as going from 0 to the large number that we started producing up there. Yes, we stress test all the pipes up there. That's what happened. And again, that part of it was these wells are producing at a much higher rate than we told them they would. So they a little bit it was a little bit of a good problem. But now we everybody knows what to expect. Yes. I'm just trying to figure out 4Q production. It looks like so prior to the last two quarters, 4,500 to 5,000 cubic feet per day was what or sorry, 1,000,000 cubic feet per day is what you were shut in. That's is that a probably the right number that you're Yes. Well, I think 8,000,000 I think 8,000,000 a day is kind of a if we're this active, we're more active than we were back in those earlier numbers. And generally though, in a little bit, we can have activity from an offset operator that can cause the same thing. A lot of this we do to ourselves, I think. Yes. This is Dan. I'll just add that a lot of this a decent amount of the offset the volumes that are shut in for frac activity is for offset operators, and that's something that's a little bit harder for us to predict. Got it. Thank you for the color guys. Thank you. Our last question comes from Ron Mills from Johnson Rice. Please go ahead. David asked my question on the acquisitions, but one other thing. Just the short two areas where you had the shorter laterals, the Bagleys and the Bagleys, I guess, and the Brantleys had some of the higher rates. Is that just owing to the rock down in that part of DeSoto Parish? Or is there something else going on? So we this is Dan again. We get really good we get really good IPs out of the short laterals. It really torques up our production. But the Brantley is I mean, obviously, the Brantley is in a very good area of the Haynesville when you look at the acreage, the Bagley is also. But we I mean, even though the returns are a little less on the 4,500, you do get really good IPs. They clean up faster. They make less water. You get the production ramped up faster in the 1st 30, 60, 90 days. Dan, you might add on the long laterals, Steve, we've been trying to adjust the way we clean up those wells, and we haven't been able to get the higher IPs on those. Yes. So if you look at a plot of basically IP per 1,000, I mean, you get much better IPs on the shorter laterals they do clean up faster. They got less water to recover. We have noticed on the 10ks and especially since we've gone with this Gen 3 completion design, we got so many more take points on the wellbore that when we're IP ing the wells, we tend to make more water just upfront, which does kind of hinder our ability to get the same IPs we got with the earlier Gen 1 and Gen 2 designs. And so it does force us sometimes to flow the wells back a little bit longer than we normally do, just trying to get those tests. But it's you do get lower IPs per 1,000 as the laterals get longer. Okay, great. Thank you for the clarification. Thank you. This concludes our Q and A session. At this time, I'd like to turn the call back to Jay Allison, CEO of Comstock Resources for closing remarks. Please go ahead. All right. Again, thank you again. We've been on the phone about an hour. If you look at a $3 flat gas price, we generate a 57% rate of return on our 4,500 foot laterals, which is what Ron just kind of asked about, the 4,500 foot laterals, and a 70% rate of return on our 10,000 foot laterals. As the price increases to 3.50 dollars rate of return increases to 86% on our 4,500 foot laterals and over 100% on our 10,000 foot laterals. Now to the stakeholders and the bondholders and the banks and the analysts that are on the call, we all know that there are not many true proven crown jewel oil and gas asset basins in America, not when you consider takeaway issues, differentials, etcetera. We at Comstock, we are super fortunate to have a crown jewel asset like the HaynesvilleBossier Shell. We commit to you that we will intentionally focus on growing Comstock in 2019 and beyond. In this prolific region, we'll continue to attempt to reduce drilling and completion costs, like kind of like Dan said, to create even a greater wealth on a per well basis. And I truly believe that the first ray of sunlight has just shown on the face of Comstock, and we're in the very beginning of many, many bright days as we focus on delivering to you, our stakeholder, strong, predictable results in the coming quarters and years ahead. So again, thank you for the hour that you've spent on the call. We greatly appreciate it. Thank you. Thank you, ladies and gentlemen, for attending today's conference. This concludes the program. You may all disconnect. Good day.