Comstock Resources Inc (CRK) 2018 Q3 法說會逐字稿

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 would like to turn your call 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 result presentation, there you'll 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 of our presentation, you will note that our discussion today will include forward-looking statements, within the meaning of security 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 -- an opening comment. I know we're going to get through all the 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. I know the results we'll 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 confusing, but that is how the third quarter has to be presented. We've simplified it to the best that we could. The important note in the conclusion is this, and I'll say the statement again, had we closed on July 1, our third quarter would have had oil and gas sales of $134 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 which are 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 design in February, 2015, where we have delivered to each of you, our stakeholders, 62 wells that we drilled, completed which have averaged an IP rate of 25 million 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 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 84% stake in the company for Jerry Jones' Bakken shale assets, where we used 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 the 14th, the first accounting period is 48 days. So our third quarter results are presented in these 2 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. Had we closed, like I said earlier, on July 1, our third quarter we would have 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. Roland will show the pro forma growth on that. We've had very consistent results in our Haynesville drilling program as you've monitored it since February of '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 million cubic feet of gas per day. Now this is the beauty, this drilling program, within the 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 undrilled locations. We also sold undeveloped Eagle Ford acreage in the quarter for $13.7 million to help fund some of the acquisition activity. The sale also kept us, this is a positive, it kept us from having to drill 4 wells that had to be drilled in the near term or this acreage 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 property 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 DeSoto Parish in Louisiana, which included 120, or really 26.2 net producing natural gas wells and 14.7 net of which produce from the Haynesville shale. This acquisition adds almost 19 million cubic feet of gas per day to our fourth quarter production. The final purchase price was $39.3 million and we booked 207 Bcf of proved reserves within an SEC PV-10 value of $70 million 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 and turn over to Roland to go over the financial results for the 2 separate periods for the third quarter, and he will turn it over to Dan Harrison for operational 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 new Comstock. The successor results include the Bakken shale properties. Given the change of control, our assets were assigned a new accounting basis, so there's not 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 forma third 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 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 of the third quarter and $24 million in the first 44 days and was $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 were the 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 a similar number, but then we will 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 production increased 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 see our gas production averaging between 370 million and 420 million per day.

On Slide 8, we give you accounting for what was shut in for the quarter. Our natural gas production in the third quarter was again substantially impacted by shut-in production, either related to offset frac activity or pipeline curtailments. We have had continued issues in our Caddo Parish area handling the increased volumes from our drilling in our JV area. As of now, we've seem to have 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 were due -- 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 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 all the activity going on in the Haynesville and the need to shut in wells 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 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 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 cost per Mcfe. Operating costs were $0.61 per Mcfe in the first part of third quarter, the predecessor part, and then they increased to $0.84 after the Bakken oil wells incorporated in. That was comprised of gathering costs of $0.20, production taxes of $0.23 and field level costs 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, 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 are -- will really give you a good road map 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 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 than 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-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 third and fourth quarter 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 Enduro 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 fifth rig, like Jay mentioned earlier, in -- somewhere -- sometime around March of 2019. We're estimating that 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 6.6 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 $377 million. The Haynesville/Bossier shale drilling completion activities make up $361 million of 2019's 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 $16 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 will give you an update on what's going on with our drilling program.

Great, thanks, Roland. On a 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 play in 2015, we've drilled 62 operated wells with an average IP of 25 million 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.

Over on Slide 14. I want to discuss the latest iteration in our completion design, which is shown on the slide here, but before I do I'll give you a brief review of our past completion design. Our initial wells in 2015 and early 2016 were completed using our Gen 1 frac design. The Gen 1 frac design was based on completing 250-foot stage length, which is 5 clusters per stage at 50-foot spacing between clusters and was designed for 3,000 pounds of sand per foot. This design worked very well but we knew we could improve.

In the late '16, we shifted gears to our Gen 2 design, in 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 pounds per foot to 3,800 pounds per foot. Through our most 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 3,800 pounds per foot. Several of our Gen 2 designs, we have 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, 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 benefits of the Gen 3 design are 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 in 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 inference 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 the oil 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 had been completed since our last 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 call outs. The remaining of the wells were completed with what we now are calling the Gen 3 frac design and are denoted by the red call outs. The average initial production rate of all 10 wells was 25 million cubic feet per day. The Cook 21-28 HC, #3 and #4 wells were both drilled to the Haynesville and the #3 well having a 9,400-foot lateral and the #4 well having a 9,483-foot lateral. The initial production rates were 21 million cubic feet per day and 24 million cubic feet per day, respectively. The Brown 7-18 HZ #1 and #2 wells were both drilled to 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 million cubic feet per day and 25 million cubic feet per day, respectively. Faglie 19-18 HC #1 and #2 wells were drilled to Haynesville, #1 well having a 9,850-foot lateral, #2 well having 9,865-foot lateral. Initial production rates were 25 million cubic feet per day and 26 million 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 #3 well had 4,513-foot lateral, the initial production rates were 23 million and 24 million cubic feet per day respectively. And then on Brantley 21 HZ #1 and #2 wells, they were also both drilled to the Haynesville. The #1 well having a 4,532-foot lateral, #2 well having a 4,502-foot lateral. The initial production rates were 28 million and 27 million 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 the Slide, we have separated out the new Gen 3 wells from the original Gen 2 design wells. This slide clearly shows the distinction between the performance of the Gen 3 wells and Gen 2 well both for the longer laterals and for the shorter sectional laterals as well. So the key takeaways from the slide are really simple: The new Gen 3 wells are outperforming and the Gen 2 wells to date; and the Gen 2 wells are continuing to outperform the Gen 1 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 in economics for the different lateral length cases, cases we are now using to our Gen 3 frac design. As everyone knows, frac costs are the driver for our total well cost. With the softening frac market, we have been able to drive down our total well cost which has bolstered our economics. At $3.00 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% for the 4,500-foot laterals and over 100% for our longer 10,000-foot laterals. For our 2019 Haynesville/Bossier shale program we are planning to run 5 rigs throughout most of the year and to 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 our well cost, improve our well performance and also improve our gas takeaway cost structure. All of these measures employed together will generate strong returns on 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's been here since '08, he's set on the very first well we drilled and he's still here today. If you look at the slide, the look slide, 16, 17, that he went over, you know our Gen 1 was good, Gen 2 is better, Gen 3 is better than Gen 1 or Gen 2. So that's a really good slide and 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 (sic) [Slide 18], 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 reserve 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 production will provide future exposure to oil prices as we use that cash flow to fund an expanded drilling program. And we also have acreage in the Eagle Ford shale that we'll develop with our partner 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 towards reducing our leverage from 3x to getting us under that 2.5x 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 million entering the fourth quarter.

Now for the rest of the call, I think we'll take questions from the analysts who follow the company. So any questions from the analysts.

(Operator Instructions) Our first question comes from Ron Mills from Johnson Rice.

Couple of questions on the Gen 3 completions. You talked about completion costs come down a little bit. When I look at your slide deck, it shows that 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 sand or what's driving that?

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 40/70 sand, that's kind of included into our lower frac cost that we are projecting. But we've seen -- from this time last year, we have seen a pretty rapid, pretty significant reduction in frac costs, 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 costs 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 that you are 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 the 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, we basically, cut in half the spacing that we have 30 feet to 15 feet. And when you go to the full section development you know, 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. And we've been kind of pleasantly surprise that production is actually showing to be a little bit higher, higher to date anyway, for the Gen 3 design. But as you know, the goal is to preserve the EURs and not have any degradation when you do full-section development, I mean, that was the goal.

Okay, and great. Last one for me on the Haynesville. What do you think about JV acreage up in Caddo Parish versus DeSoto Parish, when you think about 5 rigs, how does that split -- how do you think the split looks between those 2 areas given that you're higher working interest in DeSoto than Caddo?

Yes, Ron, this is Roland. 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 1 rig up in -- to kind of continue to develop our North Haynesville area in Caddo Parish. So a little different mix, but really going back to because of the additional capital we have after the Jones contribution, we're really going after our -- some of our best projects that we have in inventory in next year's program and that's really what we're picking out. So we think you'll see and, if you look back to 2018, we were 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 and at less capital cost to us. And now we're kind of go and kind of pull from the best part of inventory in the 2019 program. So I think you'll -- and you'll start -- we started that in September. So I think you'll start seeing a bigger impact from the drilling program even in the fourth quarter because of the high -- the better concentration in the net wells. But a good observation that you made.

Ron, I think we've been in here since '91, we drilled our first Haynesville well in course 2008, 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 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 wells. So I think with our acreage positions spread out, Harrison County, Panola County, you got Caddo Parish, DeSoto Parish, et cetera. We have 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's done a really good job with Roland on working on that. So that's big, and again, we've got so much of the Tier 1 acreage in locations we can't do that. So.

One thing Ron, I think that will start to show up, we don't 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, I think we're going to drive more synergies and lower service cost. I mean, we already saw that immediately when -- with much more competitive frac contracts. We're working on and reducing our gathering cost and been 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 -- didn't show up in the third quarter yet, because remember, we were only -- we just got out of the nursery on April 14 -- on August 14. So we haven't been -- seen the results yet. But I think you'll be pleased with the -- seeing improvements in those numbers as the company can start really using more strength.

And Ron, that's why we started it. You know, 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.

Our next question comes from Jane Trotsenko from Stifel.

I have a question on crude oil and natural gas price realizations. I'm curious which pricing points you're back in crude oil and natural gas are priced at?

Well we basically have different operators, operating in the Bakken shale properties, it's all non-operated. So I mean, I think that -- it -- that question varies depending on which project it is. But you kind of see -- and the gas up there is processed, you know, so a lot of the -- we report on a 2-stream basis, so all the cost to process and all that is 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 dig -- 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 says, 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 rig count stabilized at around 50 rigs and you just mentioned that you have talked or 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 Haynesville. I think a lot of that is 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 are 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 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, they're not necessarily to handle a lot of probably new volumes, but they are probably designed to take the Haynesville gas to a more direct path to the premium market and keep that -- 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 and given the rig activity, I think, that's going to drive the production. We don't see the rig activity ramping up at all dramatically right now.

Now the take away, again, as 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 it 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?

Yes, there are several in the works, but I don't how the...

But not like in construction, right?

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

Yes, I think that's correct.

Right.

Okay, and then my last question is concerning Bossier wells, if you're going to drill any of those wells next year?

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

Yes, it's 3 to 4 Bossier wells on that, yes.

Back in the same area, I think that we drilled before. But again, the Haynesville is -- that's really the top projects and that's why the budget with a lot of inventory to choose from is -- you know your top projects especially for production right now is the Haynesville projects, even if the -- even the short laterals, long laterals, they provide a lot of production per CapEx spent.

Our next question comes from David Beard from Coker Palmer.

A micro and 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 you're 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 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 first quarter next year as you start to see the impact of running 4 rigs.

Remember the fifth rig comes in March.

Yes, so since the fifth rig comes in March, you're really seeing the impact of that not until 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 fifth rig or eliminate that fifth rig. So we're pretty comfortable that 4 rigs very solid in not a great gas price environment, and the fifth rig is more or the -- yes, how do we invest the cash flow. And it's more of the 1 we want to add. And 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 now and then even our recent Enduro acquisition, there was 5 wells being drilled there and we have a fairly big interest in. So that non-operated activity kind of is all kind of washed, it's kind of completed in the fourth quarter. 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 too that we've got a really good mix on our rig contracts currently. We've got some that are on very short-term contracts and some a little bit longer contracts. So we've got a lot of flexibility if we need to drop a rig on short notice, I mean we can do that next year.

Got it, that make 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&A in the Haynesville. Obviously, a lot of companies large and small out there and you guys have a goal to delever. So how should we think about leverage metrics relative to doing a sizeable 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's got an area that's opportunity rich on the M&A front, given there's -- we're one of the few public companies out there, there'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 by developing our Haynesville property. So if we were to entertain anything other than a small bolt-on acquisition, like Enduro was, it would have to improve the leverage metrics, I think that's a key attribute. We're not looking to grow at the cost of going backwards there. So if 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 us becoming more levered, I think it would be kind of a nonstarter.

Yes, more leverage, David, would be a deal killer. If they had inferior acreage that would be a deal killer. If the core were not in the Haynesville/Bossier, which is our backyard, that'd be 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 Jones' would have dealt with us. Second of all we've been here a long, long, long time. We've got a deep root structure and I think we're just now starting to grow the tree. So it's looks pretty good.

Right, right. No, and I think specifically it looks like if you get to the 2.5x leverage, you're not looking to go backwards at all even with an acquisition.

No.

That becomes a ceiling in terms of leverage. If you got down below that at some point in time, you could get may be go up a little, but that seems to be ceiling versus a floor.

Yes, I think we would agree with that.

Look, we've been in the ditch, I hate it. And been muddy and I hated and I don't want to get in it, I want to stay in the middle of the road. Okay.

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

Just a couple of quick ones for you. You mentioned the cash burn associated with the non-op about $50 million. Should we expect that to reverse next quarter or? Is it going to take place over the -- through '19? 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, Gregg, 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, 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 maybe 2 months quicker than operated -- than non-operated production, because the operator has to process and hang on to it, probably waits a while to send it us, you know, that's the typical way. And we were on the other side and that is why we love to operate. And then the same thing with expenditures, it's really the opposite there. Usually, your cash called and have to pay for the CapEx in advance. And so we have a significant amount of the prepayments that we just never had because, obviously, we don't cash call ourselves. So I think that shift was a pretty big shift. Now I think what happened to the CapEx part will reverse because we're going to -- those projects are going to be finished up, 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 -- that's within our budget, we've already paid for in the -- 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 that -- oil and gas receipts, that's probably a -- those will come slower. They will 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 -- now what happens is that 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's 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 an increase through '19, just that you're 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 the -- since we prepaid capital expenditures. And even though we haven't expensed that yet, that's going to -- part of our budget, we'd have -- 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 an almost -- a good bit of our revenue stream non-operated with the transaction.

That's helpful. And you gave these pro forma production numbers for -- as if Bakken was in for the full year in your slides. I believe, you said all the takeaway --

The full quarter. The full quarter, again. Yes.

The full quarter, yes. You then also mentioned that constraints for the shut-in production that's behind you. Did that impact fourth Q at all? Should we be taking some -- should we be reducing those numbers a bit? Or was it completely behind you by the time the fourth quarter started?

We're always going to have shut-in volumes but we always factor in for offset frac activity. Sometimes it can be more intensive, especially, we're shutting in some of our best wells, which we were -- as we were shutting in some real race horses down there when we did, like the Brantleys and some of those wells. So it can be more impactful or 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 are holding them accountable that our midstream partners are not going to have the issues. Now we grew production so fast up in Caddo Parish and that area that hasn't seen that kind of production, you know, in God knows how long. So they had -- they thought their facilities could handle it but they didn't, they had to -- and that happened like 4 or 5 times, very frustrating, but we do see that this seems to 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 handle 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 have some hiccups, should have been on and flowing well, had some hiccups that they had to go back and fix again. Our downstream pipe ran into a 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 -- now just dealing with the offset frac activity.

Which should mean that the -- 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 we have been flowing good. So we're optimistic there that you don't have to be as worried about it. And hopefully, we kind of grew through that adjustment up there. And now, we're kind of just a 1 rig program up there, I think the production is going to be more -- the growth isn't as dramatic as going from 0 to the large number that we start producing up there.

Yes, we stress test all the pipes up there, that what happened, so.

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 2 quarters, 4,500 to 5000 cubic feet per day was what -- sorry million cubic feet per day is what you were shut-in, that's -- is that probably the right number that you're going to?

Yes, I -- well 5 to 8, I think 8 you know, I think 8 million a day is kind of a -- if we're this active -- we were more active than we were back in those earlier numbers. And generally though, in a little bit, we can have an activity from an offset operator that can cause the same thing, but a lot of this we do to ourselves, I think.

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 is a little bit harder for us to predict.

Our next question comes from Ron Mills from Johnson Rice.

David asked my question on the acquisitions, but one other thing. Just the short 2 areas where you have shorter laterals, the Bagleys and -- the Bagleys 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 did -- this is Dan, again. 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 less on the 4,500 you do get really good IPs, they clean up faster, they make less water, you get the production ramped faster in the first 30, 60, 90 days.

Dan, you might add on the longer laterals too 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.

So if you look at a plot of basically, IP per thousand, you get much better IPs on the shorter laterals, because they do clean up less water to recover. We have noticed on the 10,000s and especially since we gone to this Gen 3 completion design, we've 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 test, but it's -- you do get lower IPs per thousand as the laterals get longer.

Thank you. And 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.

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 return on our 4,500-foot laterals which is what Ron just kind of asked about, the 4,500-foot laterals, and a 75% rate 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, you know, 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 assets basins in America. Not when you consider takeaway issues, differentials, et cetera. We at Comstock, we're super fortunate to have a crown jewel asset like the Haynesville/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 costs, 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 shone on the face of Comstock, and we're in the very beginning of the 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 appreciated. Thank you.

Thank you, ladies and gentlemen for attending today's conference. This concludes the program. You may all disconnect. Good day.