Comstock Resources, Inc. (CRK) Q3 2018 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen and welcome to the Q3 2018 Comstock Resources, Inc. Earnings Conference Call. [Operator Instructions] 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 third quarter 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 presentations. There you will find a presentation entitled Third Quarter 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 in such statements to be reasonable, there could 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 opening comment. I know we’re going to go through all these slides, but I don’t know if you can tell them my voice it’s really hard to express each of you how excited we are to report to you today our first period of the new Comstock. I know the results we’ll present today during this call are in two pieces I understand that. There is predecessor companies and there is a successor company. And I know it’s a little confusing but that is how the third quarter has to be presented. We’ve simplified to the best that we could. The important note in the conclusion is this and I’ll say this statement again, had we closed on July 1, our third quarter would have had oil and gas sales of $144 million EBITDAX of $102 million, operating cash flow of $77 million and net income of $30 million 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 with your stakeholders and bondholders and analysts as you know as we have in the past, since we restarted our Haynesville Bossier drilling program with enhanced completion decided in February 2015, 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 million cubic feet a day. We delivered that since February 2015 we fully expect to continue to deliver to you strong results as we intensely focus on our Haynesville Bossier 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 million in the third quarter to fund an expanded Haynesville Shale drilling program to drive our growth in 2019 and beyond. We're excited to report the first period of the new Comstock today. Again as we closed on August 14, the first accounting period is 48 days so our third 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 it obviously the results should give you the investor a really good feel for the new company. Had we closed like I said earlier on July 1, our third quarter we had oil and gas sales of $134 million, EBITDAX of $101 million, operating cash flow of $77 million and net income of $30 million or $0.28 a share. Our Haynesville Bossier Shale program continues to deliver strong results as we’ve added now a fourth operating rig in September and we will add a fifth in March of next year round for the pro forma growth on that. We had very consistent results in our Haynesville drilling program as we monitored it since February 2015. Since we re-stared 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 million cubic feet of gas per day. Now this is the beauty. This drilling problem within cash flow will grow our natural gas production by 30% in 2018 and 50% in 2019. Lastly during the third quarter, we closed an attractive bolt-on Haynesville Shale acquisition which added approximately 12,000 net acres and 31 net un-drilled locations. We also sold of our undeveloped Eagle Ford acreage in the quarter for $13.7 million to help fund somebody acquisition activity. The sale also kept us - this is a proactive, it kept us from having to drill four wells and had to be drilled in the near-term as this rig was expired. To go over to the Enduro acquisition a great acquisition for us that’s on Slide 4. Slide 4 shows you the properties that we acquired from the bankruptcy state of Enduro Resource 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 43,000 gross acres which is 12,000 net primarily in Caddo and DeSoto Parish in Louisiana which included 120 really 26.2 net producing natural gas wells and 14.7 net which have produced from the Haynesville Shale. This acquisition has almost 19 million cubic feet of gas per day through our fourth quarter production, the final purchase price was $39.3 million and we booked 207 BCF of proved reserved with an SEC PV 10 value of $70 million related to the acquisition. The compelling reason we’re acquired the properties is for the 112 un-drilled locations or 31 net to us. Now I'll turn it over to Roland to go over the financial results for the two separate periods for the third quarter and then he will turn it over to Dan Harrison for operation results. Roland?

All right, thanks Jay. On Slide 5 we summarize our third quarter financial results again broken into the 44 days of the old Comstock and the 48 days of the new Comstock. The successful results includes the Bakken Shale properties. Given the change to control our assets we have assigned a new accounting basis that has no good comparability on the new Comstock to the predecessor. It is probably a good thing because now we’re very profitable with the 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 forma third quarter production would have been 27.1 Bcfe of natural gas with an additional 1,023,000 barrels of oil as we close the Jones contribution on July 1. Oil and gas sale in this quarter were $70 million for the new Comstock and then $33 million for the old. Pro forma sales would have been $134 million. EBITDAX came in at $53 million in the last 48 days for the third quarter and $24 million in the first 44 days and with a $102 million on a pro forma basis. Operating cash flow was $39 million in the last part of the third quarter and $10 million in the first part which the first part excluded the Bakken Shale properties. Pro forma cash flow was $77 million. We reported net income of $13.8 million for the 48 day period or $0.13 per share. The only unusual items in this period with an unrealized mark to market loss on our hedge contracts of $2.2 million and a very small gain on property sales. Without these items, net income would have been $15.9 million or $0.15 per share for that period. Pro forma for the quarter net income would have been $26 million 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 second quarter of this year. Starting in the predecessor period of the third quarter, we averaged 11,300 barrels of oil per day, mainly attributable to the contribution of the Bakken Shale properties. We expect fourth quarter oil will be at similar number. Then we'll see oil production decline in 2019 to 8,000 to 9,000 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 for production increase from 222 million per day in the second quarter to over 250 million a day in the third quarter. We expect fourth quarter natural gas production to increase to over 300 million per day with significant growth in store for 2019, where we receive our gas production averaging between 370 million and 420 million per day. On Slide 8, we give you accounting for what we shut-in for the quarter. Our natural gas production in the third quarter was again substantially impacted by shut-in production either related offset frac activity or pipeline curtailments. We've had continued issues in our Caddo Parish area, handling to increase volumes from our drilling and 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 in that area. In total, our shut-in volumes averaged 20.5 million per day during the third quarter 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're at 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 volume finally much lower in the fourth quarter 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 that all the activity going in the Haynesville and the need to shut-in wells near and offset frac. On Slide 9, we summarized our hedge position, which we had in place both for our oil and gas expansion. In the upcoming fourth quarter, we have 133 million per day of our gas hedged and about 3,500 barrels of our oil hedged. And our plan is to continue to add permissions 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 detailed our operating cost per Mcfe. Operating costs were $0.61 per Mcfe in the first part of the third quarter, a predecessor part and then they increased to $0.84 after the Bakken oil wells are incorporated in. Now this comprised of gathering cost of $0.20, production taxes of $0.23, and field level cost of $0.41. Our depreciation, depletion and amortization per Mcfe produced fell by $1.02 in the successor period as compared to $1.17 in the credit facility period and then $1.19 saw in the quarter before that. The cost deck representing this slide that are kind of circled in the box will really give you a good road map what to expect in the future as to how now all the properties are kind of in the period, that 448 days period. So this would be a good indication of what we expect these costs to look like as we go forward into the fourth quarter and 2019. Slide 11, presents our balance sheet at the end of the quarter. We ended the quarter with $32 million in cash after retiring all of our debt on August 14. Our new debt totals $1.3 billion comprised of a 5-year credit facility, and $850 million in new 8-year senior notes. We had $282 million in liquidity at the end of the quarter. We had about $50 million more outstanding on the credit facility and the pro forma amount after the refinancing and the Enduro acquisition. And that was really due to an increase in working capital. With the new non-operating properties coming into the Company, the timing of revenue receipts is often one to too much slower the operated productions. And often we had to prepay drilling and completion costs to the operators in advance. The third and fourth quarter of this year have a significant amount of non-operative projects both in the Bakken Shale properties and other non-operating part of the Enduro properties. We don't expect non-operating projects however as we get into 2019. And on Slide 12, I'll show you kind of what we are preliminary view is for the 2019 drilling program and then how we finish up the rest of this year. We're planning to operate four drilling rigs through the end of this year and they will add that fifth rig like Jay mentioned earlier in some time around March of 2019. We're estimating down our capital expenditures in the fourth quarter will be about $90 million, and that's made up of $69 million to drill 21 Haynesville shale wells but 6.5 net wells including 12 operated wells or 6.3 net. And then we also have - we also expect to incur about $21 million to complete 30 Bakken Shale wells or 4.4 net to our interest. As we look ahead to 2019, our first pass at our budget is that we'll spend about $337 million. The Haynesville/Bossier shale drilling and complete activities make $361 million, up 2019s activity. and involve drilling 57 wells or 38.2 net wells and there will be about $25 million of cost to complete wells that were drilled in 2018. We do expect to spend another $60 million 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'll give you an update on what's going on with our drilling program.

Thanks, Roland. On our Slide 13, this is the same slide you're seeing double times before. This highlights our 81,000 net acres in the Haynesville and mid-Bossier. They are across North Louisiana and East Texas. Since I returned to the play in 2015, we drilled 62 operated wells with an average IP of 25 million cubic feet per day. We're currently running the four rigs in the play and by year end we plan to drill a total of 31 wells operated wells. Over on Slide 14, I want to discuss the latest iteration in our completion design, which is shown on the slide here. Before that, I'll give you a brief review on our past completion design. Our initial wells in 2015 and early 2016, were completed using our June go on frac zone. The June on frac zone based on completing 250 foot stage, which is 5% foot space at 50 foot spacing between clusters 3,000 pounds of sands per say. [indiscernible] looks very well but we know you can prove. Like 2016 we shift a gear to our Gen 2 design and which our goal was to reduce the tighten the spacing between clusters. The Gen 2 frac is on is based on completing the shorter 150 foot stages which is five clusters and at least 30 foot spacing. At the same time we increased our sand oil from 3000 pounds per foot to 4800 per foot. The robust current completions today here 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 pounds per foot. Several of our Gen 2 designs we've been testing are modified cluster spacing which is based on an even tighter 15 foot cluster spacing and simultaneously increasing of clusters per stage from 5 up to 10. As you can see on the slide, we now refer to this modified - our modified GMC 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 Gen2 design. The benefit of the Gen 3 design or doubling of the number takes place around the wellbore minimizing by fast reserves between clusters, fewer fracs yes in the offsetting wells and also the lessening intensity of those fracs hits. We've already observed few frac hits at our offset wells and have used the Gen 3 frac and we believe that with a fewer frac hits between wells we should also experience less production interference between wells. As our development continues to moderate towards more full section development projects, we feel it’s imperative that we minimize the production interference between wells while maintaining and maximizing our EU ore core well and ultimately the NPV for the section. So what is the best combination, we don't have to postpone so yes but we know that the right answer depends on oil wells located in the play in the performance history of the wells in that immediate area. I would say today we are very close to the optimum completion design for our area of Haynesville. Looking over to Slide 15, this shows the location of the 10 new wells that had been completed since our last call. Two of the same wells were completed with the original Gen 2 frac design that’s with the [indiscernible] and was denoted by the green callouts. The remaining two wells were completed with what we now call them the Gen 3 frac design and are denoted by red callouts. The average initial production of three wells was 25 million cubic feet per day. The Cook 21-28 HC number three and number four wells were both drilled in the Haynesville. The number 3 well having a 9400 foot lateral and number four well having 9483 foot lateral and this production rates were 21 million cubic feet per day at 24 million cubic feet per day respectively. The Brown 7-18 HC number 1 and number 2 wells were both drilled at the Haynesville the number 1 well having 9771 foot lateral and number 2 well had again 9837 foot lateral. Initial production rates were 24 million cubic feet per day and 25 million cubic feet per day respectively. The Bagley 19-18 HC number 1 and number 2 wells were drilled with the Haynesville number 1 well having a 9850 foot lateral and number 2 well having a 9865 foot lateral initial production rates were 25 million cubic feet per day and 26 million cubic feet per day respectively. The Bagley A 4 HC number 2 and number 3 wells were both drilled to the Haynesville. The number 2 well had a 4539 foot lateral the number 3 well had 4513 foot lateral the initial production rates were 23 million and 24 cubic feet per day respectively. And then on Brantley 21 HC number 1 and number 2 wells I will also go through the Haynesville the number 1 well having 4532 foot lateral the number 2 well having a 4503 foot lateral the initial production rights were 28 million and 27 million cubic feet per day were slightly below. As of today we are currently fracing two additional wells. Flipping over to Slide 16, so slide 16 is a same slide that we showed before. This shows the latest update to how the [indiscernible] history are performing against our 7500 acre. On this slide we have separated each 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 2 wells both for the longer laterals and for the shorter obstructional lateral as well. So a few take away from the slide a really sample the middle three wells are outperforming the Gen 2 well to-date and then Gen-2 wells are continuing to outperform the Gen 1 wells. The gray curve which represents four major wells continue to outperform our average Gen 1 wells overtime. Slide 17 provides an updated summary of the underlying sessions and economics for the different level and cases, the case we may use for Gen 3 frac design. As everyone knows, frac cost or these are up for total well cost with the softening frac market we have been able to drop down our total well cost which have bolstered our economics. At $3 flat gas price we are generating a 50% to 57% rate of return on our 4500 foot laterals and a 75% return on our 10,000 foot laterals as we increased the product to 350 the rate of return increases to 86% for the 4500 foot laterals and over 100% for a longer 10,000 foot laterals. For our 2019 Haynesville-Bossier shale we currently to launch viable rates throughout most of the year and we drill 52 operated well. Approximately 70% of the wells are planned to be drilled at 10,000 foot laterals this will give us an average lateral acres of 8400 foot for the program next year. We continue to push that well cost and improve our well performance and also improve our gas take away cost structure. All these measures employed together will generate strong returns in cash flows looking forward. As quick summary of the operations and now I turn it back over Jay.

I remember Dan has been here since [indiscernible] first well we drilled and he still here today if you look at the slides - last slide 16 and 17 that he went over and our Gen 1 was good Gen 2 is better and Gen 3 is better than Gen 1 or 2. So that’s really good slide and in the course of well economic we’re just fortunate to be in this area. The well economics are stellar. If you get to Slide 16, we summarize our outlook for the rest of this year and for 2019. We will look through our Haynesville/Bossier shale assets to generate preserve production growth in 2019 as Roland said and we have an extensive acreage position of over 900 locations this prolific natural gas basin. The Bakken shale oil well production will provide future exposure to oil prices as we use net cash flow to fund on expanded drilling program. We’ll also have acreage in Eagle Ford shale that will develop with our partners starting next year. We have the asset base to generate substantial production growth all of within operating cash flow. The growth will help us make progress for reducing our leverage and three times to getting under that 2.5 times as goal in 2019 and we will also edge 50% to 60% of our anticipated next 12 months production. As Roland mentioned to reduce our exposure to lower gas prices we great liquidity of $282 million entering the fourth quarter. Now for the rest of the call, I think we’ll take questions from the analysts who called the company. So any questions from the analysts.

[Operator Instructions] Our first question comes from Ron Mills from Johnson Rice. Please go ahead.

Couple of questions on the Gen 3 completions, you talked about completion cost coming down a little bit when I look at your slide deck, it shows the well cost are pretty similar to your last presentation. What do you see those cost savings on the completion side is it just current market for pressure pumping, are you using local sands so what's driving that?

Yes pretty push at the nail on head it is basically the frac. Now that does include what we have switched from using our northern white sands to the local 40/70 kind of included in our lower frac cost that we’re projecting. But we seen a - from this time last year we have seen a pretty rapid - pretty significant reduction in frac calls nearly 30%. We just went out and bid our 2019 work, we had we looking at cost 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.

And then from a completion design standpoint, the Gen 3 really is just a cluster I think you mentioned some that actually kind of 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 are you were saying about to minimize risk of offset frac hits and inability to potentially drill, I am assuming on tighter spacing is that right?

Well this all started out - this has been a natural possession when we look at Gen 1, Gen 2 and Gen 3. So we decided to go to the 10 cluster per se, we could have went - I mean 15 for slating a 10 clusters. If you make really small frac you get small results and it really can’t tell if you're making a difference or not. So we went a little bit milder than the – and basically cut in half the spacing that was happening 30 to 15. And when you go to full fledge driving those where it's key that you don't have interference between wells that leave the degradation in the 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 is actually shown to be a little bit higher to date in the life of Gen 3 design. But the goal is to preserve the EUR to not have any degradation when you do a full section of oil a month, I mean that is the goal.

Last one from me on the Haynesville. Do you think about JV acreage up in Caddo Parish versus the DeSoto Parish you think about 5 or 8, how does the split - how do you think the split looks between those two areas given that your higher working interest in DeSoto and in Caddo?

Yes, what we kind of see is running one rig on the JV acreage in Caddo next year and EOC kind of the net even though the gross well don't seem to dramatically change as much but the net wells definitely do. So we are drilling having really four rigs drilling higher interest wells, more concentrated in DeSoto Parish for the most part, and just running one rig up to kind of continue to develop our North Haynesville area in Caddo Parish. So, little different mix but then really going back [indiscernible] additional capital we have after the Jones' contribution. Yeah, we're really going after some of our best projects that we have in inventory in next year's program. And that's really we're picking up. So we think you'll see - and if you look back 2018, 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 in kind of and perform the best part of the inventory now in the 2019 program. We started that in September but I think you'll start seeing bigger impact from the drilling program even in the fourth quarter because of the better concentration in the net wells, but a good observation that you made.

Ron, I think we've been in here since 1991. We drilled our first Haynesville well of course in 2008. And we're just well connected with the other Haynesville operators. So what we've done there, we try to reach out we've got a consortium group and they kind of say where are you drilling when are you completing. So we try to front run that too. So every Haynesville operators has least amount of interference which shut-in well. So I think with our acreage position spread out in our Harrison County, Panola County, you got Caddo parish DeSoto Parish et cetera. We've also tried to spread out our drilling rigs so that 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 development and working on that. So that's big. And again we've got so much of Tier 1 acreage and locations, we can't do that.

One thing Ron, I think they'll start to show if we want to take credit for it happens. But I think what's given the additional strength we have in the balance sheet the larger program. And I think we're going to drive more synergies and lower service cost. And I mean we already saw that immediately when with much more competitive fresh contracts, we're working on reducing our gathering cost and be able to do that with a lot of strength in the bigger program. So I think you'll see us to be able to drive cost reductions just in all different parts of the company, [indiscernible] the third quarter yet, because remember we were only, we just got out of the nursery on the April 4 and August 14 so we haven't been see the results yet. But I think you'll be pleased with the - see an improvement in those numbers as the Company can start really using more strength.

And Ron that's why we started it again. It is little confusing and how we have to break it down to the predecessor successor. But that's as simple as we could get. From here on now it will be very simplified and it's going to be beautiful. So anyhow.

Our next question comes from [indiscernible] from Stifel. Please go ahead.

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?

We basically have different operators operating in the Bakken shale properties. It's all non-operated. So I mean I think that that question varies depend on which project it is. But you kind of see - and the gap that there is process so a lot of that -- we report on a two stream basis our other cost and process and all that ducted out the gas price up in the Bakken. So you know there's not a easy answer to that question without getting into kind of well-by-well. The basic realizations you know we think we kind of - we tend to should average about $4 to $4.50 under WTI kind of LA that's kind of how we see the Bakken properties.

I just wanted to make sure, is that you guys don't have like large exposure to clear book differentials in Bakken, right?

Right. Well, I mean I think the number is going to show exactly where we are here.

And then my second question is related more like to Haynesville macro. So we have heard that several Haynesville pipelines have been proposed by midstream operators which would point to strong production growth expected to come from the basin. But at the same time the recount stabilized at around 50 rigs and you just mentioned that you have talked – or that you are constantly talking to other traders. 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 all activity levels in the Haynesville.

Yes that's a good question. Overall the Haynesville we've seen yeah like you said, you've observed it's very kind of flat kind of rig count in the Haynesville. I think a lot of that's more pointing to the weakness as a capital markets and the nature of the operators in the Haynesville. So we see that being very flat. [indiscernible] 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 - that's the premium markets and kind of looking for a direct access where you don't go through the Perryville well hub and can gain another $0.05 or $0.06 per Mcfe. So that's the trend and that's what a lot of the -- that's the new projects are 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 the 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.

The takeaway again like Roland said, we can go east, 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 more gas we produce, more leverage we'll have to get there.

Correct me if I'm wrong but no direct pipeline going south like a new takeaway has not been announced yet, right?

There are several in the works but I don't know.

In the works but not like in construction, right?

I don't know if they're in construction.

I think that's correct.

And then my last question is concerning Bossier wells. If you are going to drill any of those wells next year?

We are going to go back to the Bossier. Again, we liked the results of our first handful of wells, they're different wells. They don't have IPs as high as the Haynesville but they do have a lower decline, it's kind of our batch is proven out. So we've got some Bossier wells in our budget but I think about 3 or so, its kind of --

Yes, I think it's three to four Bossier wells --

Yes, back in the same area, I think that we drilled before. But again, the Haynesville is, that's really that top projects and that's why the budget with the lot of inventory the key trial is saying it's hot products, especially for production right now is the Haynesville projects, even if the short laterals, long laterals, they provide a lot of production per CapEx.

Our next question comes from David Beard from Coker Palmer. Please go ahead.

Micro and macro question, on the micro front, given your guidance for production. What would you expect for seasonality as a quarter is rollout, would it be steady or you're stronger in the first half then the second half against the sequential, but any kind of color you could give us on that would be appreciated?

Sure, 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 first quarter next year, if you start to see the impact of running 4 rigs.

The fifth rig comes in March.

Yes, so the fifth 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 during the first half for our growth plan. And I think that gives us the flexibility, to say, to react because if the gas prices underperform, where we are and where we're hedged at, we can delay that 5 rig or eliminate that 5 rig. So we're pretty comfortable with the fourth rigs is very solid and not a great gas prices environment and the fifth rig is more of that, how do we invest the cash flow and it's more of the one we want to add, you notice we're waiting to have that, when all these non-operated expenditures, from the Bakken where there's a lot of duck to be been completed in and even our recent Enduro acquisition. There is 5 wells being drilled there and we have a fairly big interest in. So that non-operating activity kind of develop, kind of wash this kind of completed in the fourth quarter. Next year, we don't see a lot of nonoperating activity that's another reason why we kind of keep an outbreak back until we make sure we have all that covered.

David, this is Dan. I'll add to that, we've got a really good mix on a rig contracts currently. We 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 in short notice, I mean we could do that next year.

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&A and Haynesville obviously a lot of companies large and small out there, and you guys have a goal to delever. How should we think about the leverage metrics relative to doing a sizable acquisition or was asked another way, if you did do that, you don't, where, when leverage metrics would you be looking at, if you did a large acquisitions?

Obviously, the Haynesville cut an area that's opportunity rich and that was on M&A process given there's - where is 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 the real goal of reducing leverage over the next couple of years by helping our Haynesville properties. So if we were to entertain anything other than those small bolt-on acquisition like drill was, it would have to improve the leverage metric. So I think that's a key attribute we're not looking to grow at costs 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 to the extent that it requires a couple more leverage. I think it would be a kind of a non-starter.

Yes, more leverage David would be a deal killer. As I had inferior acreage at deal killer. If the core we're not in handful budget, which is our backyard that be a deal killer. If I had a - some farm transportation agreements so killer economics, that's a deal killer. If there's something we can do this transformation like we did with the Jerry Jones, I think he is the smartest one to do that, so yes I think the world is pretty broad for us in the future right now, like Roland said we do in our opinion have a great reputation of how Jerry Jones going to deal with this, second of all we’ve been here long, long, long, long time we’ve got a deep root structure and I think we just now starting to grow the tree. So it looks pretty good.

Right. Now and I think specific looks like if you get to the 2.5 leverage, you now looking to go back to that even with a acquisition that becomes a ceiling in terms of leverage, if you got down below that at some point in time, that 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 on that and money and hided and I don’t want to get into that side, I’m middle of the road, okay.

Our next question comes from Gregg Brody from Bank of America. Please go ahead.

Just two quick ones for you, you mentioned the cash burns associated with the non-ops above $50 million, should we expect that to reverse next quarter, is this of course it’s going to face over through 2019, how should we think about that and maybe just in general, are there anything else working capital, why should we be thinking about going into next year?

Yes, Gregg. I don’t know we talked cash burn but I guess what we really saw was Comstock, historically has been we've operated 98% of everything. So the timing, the timing of operated revenues and expenditures are a lot different than non-operated, I mean we will receive the cash from the sale of operating production may be too much quicker than operated non-operated production because the operator have to process to hang onto it, probably waits a lot and send it to us, that’s the typical way and we're used, we're 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 your cash calls 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 have cash call ourselves. So I think that big shift was a pretty big shift that that now I think what happens is the CapEx part will reverse because we're going to those projects are going to be finished not 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 see a big reversal on that, some of the CapEx that we have within our budget we've already paid for and it's paid for that there and we got the advances up there and other current assets, we see that number is really big compared to what we see today. So thanks 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 in fact accounts receivable for the oil production that we do for the gas, that won't reverse because then what happens is as the company is growing, it’s really growing on the gas, 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's going to reverse but some of it, we're going to we will be carrying more and more receivables on non-operated properties than operated.

But 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 especially get all of those as such we prepay in capital expenditures and even though we haven’t expense that yet, that's been part of our budget, we 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 an almost good bit of our revenue stream is non-operated with the transaction.

You gave these pro forma production numbers for as Bakken was into the full-year in your sites, I believe you said all this…

The full quarter.

Yes, you also mentioned that the constraints for the second production that's behind you, do that impact 4Q at all, should we be taking some, should we be producing those numbers a bit or is it was this completely behind you by the time fourth quarter started?

We’re going to have some shut-in volumes, so we always factor in process 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 shutting in some real, some real hoses down there and we did like the brand, even some of those wells. So second it can be more impactful than not because where that is but there is always going to be an element of shut-in offset frac now. But we expect, we were held accountable that our Midstream Partners are not going to have the issues now, we grew production so fast up in Caddo Parish area that hasn't seen that kind of production and got those. They had, they thought, so they got facilities to handle it, but then they didn’t, they had that happened like four to five times, very frustrating. But we do see that it seems to knock on wood that they seem to be flowing good up there and hopefully they've made all the improvement they can with the volumes up in Caddo Parish.

This is Dan. I would like to what Roland just said, I mean for the last month we’ve been dealing without any issues that fairly just had some, they had to get, they did some upgrades to the plant, they had some hiccups, should been on wells has to be addressed as they had to go back and fix again. Our downstream pipe entity, few little more issues that they had to get solved but for last month or so, we have been following basically unrestrained. So just now just dealing with the offset frac activity.

Shifting we should have a significantly better looking chart on the shut-in production for the fourth quarter because that’s going to be most of the fourth quarter there that we have been flowing good. So we’re optimistic there that you don’t have to be as worried about it and hopefully we can agree through that adjustment out there. And now we’re kind of just the one rate program out there, I think that production is going to be lower, the growth is dramatic as going from zero to the large number that we sort of produced in there.

Yes, we stress test all the process this is what happens.

Again that is part of it was these wells are producing at a much higher rate than we tell them they would, so they are little bit good problem but now we - everybody knows what to expect.

Yes, I’m just trying to figure out key production, it looks like prior to the last two quarters 4,500 to 5,000 cubic feet per day was what sorry million cubic per day is what you were shut-in, that is, is that a probably right number?

I think I mean 8 million a day is kind of we’re active, we’re more active than we were back in as earlier numbers and typically 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 it ourselves I think.

Yes, this is Dan. I will just add a lot of this, a decent amount of the offset the volumes that are shared in for frac activities will offset operators and that’s something that is little bit harder for us to predict.

Our last question comes from Ron Mills from Johnson Rice. Please go ahead.

David asked my question on the acquisitions but one of the things, the short two areas where you had short [indiscernible] I think in the Brent lease had some of the higher rates, is that just owing to the rock count in that part of territories or is there something else going on?

We did really good, we didn’t really get after these sure levels and really step up production but the Brent lease is obviously the leasing is in a very good area the Haynesville and when you look at the average, the Brent lease is also - I mean I didn’t know little less on the 4500, you think it is really good of these bring that faster, they make less water and gets the production ramped up faster the first 30, 60, 90 days.

Dan you might add on the long laterals we’ve been trying to adjust the way we clean up those wells and we haven’t been able to get the higher RPs on that.

Yes, so if you look at - if you look at that basically RP per wells and I mean you get much better ops on the shorter laterals because they do clean up after they got less water to recover. We got noticed on the same case and especially since we rounded this June 3 completion to that. We got so many more take on the well board we're happy in the wells. We tend to make more water just upfront which does kind of hinder our ability to get the same up lease we got with our 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 stuff. But it's - you do get lower RPs per wells and as the laterals get longer.

This concludes our Q&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.

Well again, thank you again. We've been on the phone for about an hour. If you look at a $3 flat gas price, we generated 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 at 75% rate of return on our 10,000 foot laterals. As the price increases to $3.50, the rate of return increases to 86% on our 4,500 foot laterals and over 100% on our 10,000 foot laterals. Now, and those through the stakeholders, and the bondholders, and the banks, the analyst are on the call, we all know that there are not many true proven crown jewel oil and gas asset basins in America. Now when you consider tank issue differentials et cetera. We at Comstock we are super fortunate to have a gradual asset like the Hazel- Bossier Shale. 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 cost like Dan said, to create even a greater wealth on a pro well basis. And I fairly believe that the first ray of sunlight is 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 hours that you 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.