Good day, ladies and gentlemen, and welcome to the Q3 2018 Comstock Resources Inc. Earnings Conference Call. Currently, at this time, all participants are on a listen-only mode. Later, we will conduct a question-and-answer session, and instructions will follow at that time. Should anyone require assistance at any time during the conference, please press star and zero on your touch-tone telephone. Also, as a reminder, this conference call is being recorded. At this time, I'd like to turn the call over to your host, to 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 presentations there. You'll find a presentation entitled, quote, "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 two in our presentation, you'll note that our discussions today will include forward-looking statements within the meaning of securities laws.
While we believe the expectations of such statements to be reasonable, there can be no assurance that such expectations will prove to be true. Before we go to the slide three 2018 Q3 summary, I'd like to make an opening comment. I know we're going to go through all these slides, 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 that we'll present today during this call are in two pieces. I understand that. There's the predecessor company, and then there's the successor company, I know it's a little 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, I'll say this statement again. Had we closed on July 1st, 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. If you look at the future, as we have in the past, a lot of you, which are stakeholders and bondholders, analysts, as you know, as we have in the past, since we restarted our Haynesville Bossier drilling program with enhanced completion design in February of 2015, where we have delivered to each of you, our stakeholders, 62 wells we have drilled and 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. With that, I want to go back and let's start on slide three. 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 the 14th, the first accounting period is 48 days, 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, obviously, the results should give you, the investor, a really good feel for the new company. As we close, like I said earlier, on July 1, our third quarter, we'd 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 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 go through the pro forma growth on that.
We've had the very consistent results in our Haynesville drilling program, as you've monitored it since February 2015. 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 with in-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 in 31 net undrilled locations. We also sold some of our 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 proactive, it kept us from having to drill four wells that had to be drilled in the near term or this acreage would have expired. To go over to the Enduro acquisition, a great acquisition for us. That's on slide four. Slide four shows you the properties we acquired from the bankruptcy estate of Enduro Resource Partners. In the middle of completing the Jones contribution, we completed this acquisition on July 31st, 2018, through a court-directed bankruptcy sale. We acquired 23,000 gross acres, which is 12,000 net, primarily in Caddo and DeSoto parishes in Louisiana, which included 120 or really 26.2 net producing natural gas wells and 14.7 net, which produced 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. We booked 207 Bcf of proved reserves with 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. I'll turn it over to Roland to go over the financial results for the two separate periods for the third quarter. Then he'll turn it over to Dan Harrison for operation results. Roland?
All right. Thanks, Jay. On slide five, we summarized our third quarter financial results. Again, broken into the 44 days of the old Comstock and the 48 days of the new Comstock. The successive results include the Bakken Shale properties. Given the change of control, our assets were assigned a new accounting basis, there's no good comparability on the new Comstock to the predecessor. That's probably a good thing because now we're very profitable with a new consolidated low-cost structure. For the successive 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 1st.
Oil and gas sales in this quarter were $70 million for the new Comstock, $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, 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 was the unrealized mark-to-market loss on our hedged 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 six, 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. We'll see oil production decline in 2019 to 8,000-9,000 barrels a day, given that we plan to do very little oil drilling in 2019. On slide seven, 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 and 420 million per day. On slide eight, 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've had continued issues in our Caddo Parish area handling the increased volumes from our drilling in our JV area. As of now, we seem to finally overcome all the growing pains and now have the capacity to fully sell our gas volumes to that area.
In total, our shut-in volumes averaged 20.5 million per day during the third quarter of 2018. 40% of that related to our pipeline and plant problems up in Caddo Parish, 60% relates to offset frac activity. 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. In the future, we'll continue to always have 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 an offset frac.
On slide nine, 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. Our plan is to continue to add positions to hedge 50%-60% of our production for the upcoming 12 months. We're currently adding some more positions right now to build up our 2019 volumes. On slide 10, we detail our production costs per Mcfe. Operating costs were $0.61 per Mcfe in the first part of the third quarter, the predecessor part, then they increased to $0.84 after the Bakken oil wells are incorporated in. That was comprised of gathering costs of $0.20, production taxes of $0.23, and field level cost of $0.41.
Our depreciation, depletion, and amortization per Mcfe produced fell to $1.02 in the successor period as compared to $1.17 in the predecessor period, $1.19 in the quarter before that. The costs that we're presenting on this slide that are circled in the box will really give you a good roadmap to what to expect in the future, as now all the properties are in the period, that full 48 days period. 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 14th. Our new debt totals $1.3 billion, comprised of a five-year credit facility and $850 million in new eight-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 one to two months slower than operated production, and often we had to pre-pay 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.
On slide 12, we'll show you what our preliminary view is for the 2019 drilling program, how we finish up the rest of this year. We plan to operate four drilling rigs through the end of this year, we'll add that fifth rig, like Jay mentioned earlier, 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. We also expect to incur about $21 million to complete 30 Bakken Shale wells or 4.4 net to our interest. We look ahead to 2019, our first pass at our budget is that we'll spend about $377 million.
The Haynesville Bossier Shale drilling and 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. We'll continue to adjust this budget to stay within the operating cash flow that we expect to generate in 2019. I'll now turn it over to Dan, who will give you an update on what's going on with our drilling program.
Okay, thanks, Roland. On slide 13, this is the same slide you've seen several times before. This highlights our 81,000 net acres in the Haynesville and Mid-Bossier play across North Louisiana and East Texas. Since our return to the play in 2015, we've 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, by year-end, we plan to drill a total of 31 gross operated wells. On slide 14, I want to discuss the latest iteration in our completion design, which is shown on this slide here. Before I do, I'll give you a brief review of our past completion design. Our initial wells in 2015 and early 2016 were completed using our Gen 1 frac design.
The Gen 1 frac design was based on completing 250-foot stage lengths, 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 late 2016, we shifted gears to our Gen2 design, in which the goal was to reduce or tighten the spacing between clusters. The Gen2 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. For our most current completions today, we are continuing to pump our Gen2 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 Gen2 designs, we've been testing a modified cluster spacing, which is based on an even tighter 15-foot cluster spacing, and simultaneously increasing our clusters per stage from 5 up to 10. As you can see on this slide, we now refer to this modified Gen2 frac design as our Gen3 frac design. The goal of the Gen3 frac design is to increase the frac intensity near the wellbore while maintaining the same stimulated reservoir volume as the original Gen2 design. The benefits of the Gen3 design are a doubling of the number of take points along the wellbore, the minimizing of bypass reserves between clusters, fewer frac hits in our offsetting wells, and also a lessening intensity of those frac hits.
We've already observed fewer frac hits in our offset wells when we use the Gen3 frac design, and we believe that with fewer frac hits between wells, we should also experience less production interference between wells. As our development continues to migrate towards more full section development projects, we feel it is imperative that we minimize the production interference between wells while maintaining and maximizing our EURs per well and ultimately the NPV for the section. What is the best combination? We don't have the perfect answer yet, but we know the right answer depends on where a well is located in the play and the performance history of the well in that immediate area. I would say today we're very close to the optimal completion design for our area of the Haynesville. Flipping over to slide 15.
This shows the location of the 10 new wells that have been completed since our last call. 2 of the 10 wells were completed with the original Gen2 frac design, that's with the 30-foot spacing, and are denoted by the green call-outs. The remaining 8 wells were completed with what we now are calling the Gen3 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 number 3 and number 4 wells were both drilled to the Haynesville. The number 3 well having a 9,400-foot lateral, and the number 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 number 1 and number 2 wells were both drilled to the Haynesville.
The number 1 well having a 9,771-foot lateral, the number 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. The Fagley 19/18 HC number 1 and number 2 wells were drilled to the Haynesville. The number 1 well having a 9,850-foot lateral. The number 2 well having a 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 number 2 and number 3 wells were both drilled to the Haynesville. The number 2 well had a 4,539-foot lateral. The number 3 well had a 4,513-foot lateral. The initial production rates were 23 million and 24 million cubic feet per day, respectively.
On our Brantley 21 HZ number 1 and number 2 wells, they were also both drilled to the Haynesville. The number 1 well having a 4,532-foot lateral. The number 2 well having a 4,502-foot lateral. The initial production rates were 28 million and 27 million cubic feet per day, respectively. As of today, we are currently fracking two additional wells. Flipping over to slide 16. Slide 16 is the same slide that we showed before. This shows the latest update to how the wells with sufficient amount of production history are performing against our 7,500-foot type curve. On this slide, we have separated out the new Gen3 wells from the original Gen2 design wells. This slide clearly shows the distinction between the performance of the Gen3 wells and the Gen2 wells, both for the longer laterals and for the shorter sectional laterals as well.
The key takeaways from this slide are really simple. The new Gen3 wells are outperforming the Gen2 wells today, and the Gen2 wells are continuing to outperform the Gen1 wells. The green curve, which represents four Bossier wells, continues to outperform our average Gen1 wells over time. Slide 17 provides an updated summary of the underlying assumptions and economics for the different lateral length cases we're now using for our Gen3 frac design. As everyone knows, frac costs are the driver for our total well costs. With the softening frac market, we've been able to drive down our total well cost, which has bolstered our economics. At $3 flat gas price, we're generating a 57% rate of return on our 4,500-foot laterals and a 75% return on our 10,000-foot laterals.
As we increase the price to $3.50, the rate of return increases to 86% for the 4,500-foot laterals and over 100% for our longest 10,000-foot laterals. For our 2019 Haynesville Bossier Shale program, we're planning to run five rigs throughout most of the year, and we'll drill 52 operated wells. Approximately 70% of the wells are planned to be drilled as 10,000-foot laterals, which will give us an average lateral length of 8,400 foot for the program next year. We're continuing to push down well costs, improve our well performance, and also improve our gas takeaway cost structure. All of these measures employed together will generate strong returns and cash flows going forward. That's a quick summary of the operations, and I'm now going to turn it back over to Jay.
Remember, Dan's been here since 2008. He sat on the very first well we drilled, and he's still here today. If you look at the slides, I love slide 16, 17, that he went over. Our Gen 1 was good. Gen2's better, and Gen3 is better than Gen 1 or 2. That's a really good slide. Then, of course, the well economics. We're just fortunate to be in this area. The well economics are stellar. If you go to slide 16, we summarize our outlook for the rest of this year and for 2019. We will look to our Haynesville and Bossier Shale assets to generate 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 weighted production will provide future exposure to oil prices as we use that cash flow to fund an expanded drilling program. We also have acreage in [Adelpha Shale that we'll develop with our partners starting next year. We have the asset base to generate substantial production growth all within operating cash flow. The growth will help us make progress toward reducing our leverage from 3 times to getting us under that 2.5 times as a goal in 2019. We'll also hedge 50%-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. For the rest of the call, I think we'll take questions from the analysts who follow the company. Any questions from the analysts?
Thank you, sir. Ladies and gentlemen, if you have a question at this time, please press star and one. If your question has been answered or you wish to remove yourself from the queue, please press the pound key. Our first question comes from Ron Mills from Johnson Rice. Please go ahead.
Morning, guys. A couple questions on the Gen3 completions. You talked about completion costs coming down a little bit. When I look at your slide deck, it shows the well costs are pretty similar to your last presentation. Where do you see those cost savings on the completion side? Is it just current market for pressure pumping? Are you using local sands, or what's driving that?
Yeah, you pretty much hit the nail on the head. It is basically the frac cost. That does include, we have switched from using the Northern White sand to the local 40/70 sand. That's included into our lower frac cost that we're projecting. From this time last year, we have seen a pretty rapid, pretty significant reduction in frac cost, nearly 30%. We just went out and bid our 2019 work. We're looking at costs lower than what we have today, probably another 10%-15%. That is pretty much the main thing that's driving the cost down, the total well cost.
Okay, from a completion design standpoint, the Gen3 really is just a perf cluster. I think you mentioned the fact you're trying to get just near wellbore contribution higher. Can you just expand a little bit on what you've seen on those Gen3 wells in terms of minimizing risk of offset frac hits and ability to potentially drill, I'm assuming, on tighter spacing. Is that right?
Well, this has been a natural progression, when you look at Gen 1, 2, and 3. We decided to go to the 10 clusters per stage. We could've went to 15-foot spacing at 10 clusters. If you make really small changes, you get small results, and you really can't tell if you're making a difference or not. We went a little bit bolder when we basically cut in half the spacing that we had from 30 to 15. When you go to full section development, it's key that you don't have interference between wells that lead to degradation in your EURs. The goal really was to maintain where our performance was while minimizing the interference. We've been pleasantly surprised that the production has actually shown to be a little bit higher to date anyway, for the Gen3 design.
The goal is to preserve the EURs and not have any degradation when you do a full section development. That was the goal.
Okay. Great. Last one for me on the Haynesville. When you think about JV acreage up in Caddo Parish versus DeSoto Parish, you think about five rigs. How do you think the split looks between those two areas, given that you're higher working interest in DeSoto than Caddo?
Yes. Ron, this is Roland. What we kind of see is running one rig on the JV acreage in Caddo next year, you'll see the net, even though the gross wells don't seem to dramatically change as much, the net wells definitely do. We're drilling, having really four rigs drilling higher interest wells, more concentrated in DeSoto Parish for the most part, just running one rig up and to continue to develop our North Haynesville area in Caddo Parish. It's a little different mix, really going back to because of the additional capital we have after the Jones contribution. We're really going after some of our best projects that we have in inventory in next year's program, it's really we're picking up. We think you'll see.
If you look back to 2018, we were trying to really minimize capital expenditures but also provide growth. We leaned more on lower interest projects, to get exposure to the basin, but at less capital cost to us. Now we're going to go and pull from the best part of the inventory in the 2019 program. We started that in September, I think you'll start seeing a bigger impact from the drilling program even in the fourth quarter because of the better concentration in the net wells. A good observation that you made.
Ron, the other thing, we've been in the area since 1991. We drilled our first Haynesville well in course 2008. We're just well connected with the other Haynesville operators. What we've done now, we've tried to reach out. We've got a consortium group, they say, "Well, where are you drilling? Where are you completing?" We try to front-run that too so every Haynesville operator has the least amount of interference with shut-in wells. I think with our acreage position spread out, Harrison County, Panola County, you've 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's done a really good job with Roland on working on that. That's big.
Again, we've got so much of the Tier One acreage and locations, we can do that.
One thing, Ron, I think they'll start to show up. We want to take credit for it before it happens. 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 costs. We already saw that immediately with much more competitive frac contracts. We're working on reducing our gathering cost and being able to do that with a lot of strength because of the bigger program. I think you'll see us be able to drive cost reductions just in all different parts of the company. It didn't show up in the third quarter yet because remember, we just got out of the nursery on August 14th, so we haven't seen the results yet.
I think you'll be pleased with seeing improvements in those numbers as the company can start really using more strength.
Ron, that's why we started it. It is a little confusing in 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'll be very simplified. It's going to be beautiful.
Great. Thank you very much.
Thank you. Our next question comes from Jane Trotsenko from Stifel. Please go ahead.
Good morning. I have a question on crude oil and natural gas price realizations. I'm curious which pricing points your Bakken crude oil and natural gas are priced at?
Well, we basically have different operators operating the Bakken Shale properties. It's all non-operated. I think that question varies depending on which projects it is. You can kind of see, and the gas up there is processed. We report on a two-stream basis, so all the costs are processed and all that's deducted out of the gas price up in the Bakken. There's not an easy answer to that question without getting into well by well. You can see the basic realizations. We think we should average about $4-$4.50 under WTI all in. That's how we see the Bakken properties.
I just want to make sure that you guys don't have a large exposure to Clearbrook differentials in Bakken. Right?
Right. Well, I think the numbers show exactly where we are, yeah.
Okay. Then my second question is related more to Haynesville macro. We have heard that, let's say, several Haynesville pipelines have been proposed by midstream operators, which would point to strong production growth expected to come from the basin. At the same time, the rig count stabilized at around 50 rigs. You just mentioned 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?
Yeah, that's a good question. Overall, the Haynesville, we've seen, like you said, you've observed, it's very flat rig count in the Haynesville. I think a lot of that's more pointing to the weakness of the capital markets and the nature of the operators in the Haynesville. We see that being very flat. We are having, and we're working to optimize as a lot of the producers are, wanting to get the gas to go directly down to the LNG markets. That's the premium markets, looking for direct access, where you would not go through the Perryville hub, can gain another $0.05 or $0.06 per Mcfe. That's the trend, 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 the Haynesville area, obviously, to be one of the top highest realization basins in the country. That's the trend. As producers, we all want to get access to the premium Gulf market, the most direct way, and that's the trend. We see production, given the rig activity, I think that's going to drive the production, and we don't see the rig activity ramping up at all dramatically right now.
No, the takeaway, again, like Roland said, we can go east and west, we're trying to go south directly to the LNG demand. We're working on that. I think that'll 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, no direct pipeline going south, like a new takeaway, has not been announced yet, right?
There are several in the works, I don't know.
In the works, but not in construction, right?
Yeah, I don't know if they're in construction.
I think that's correct.
You're right.
Okay. My last question is concerning Bossier wells, if you're going to drill any of those wells next year.
We are going to go back to the Bossier. We like the results of our first handful of wells. They're different wells. They don't have IPs as high as the Haynesville, they do have a lower decline as our batch has proven out. We've got some Bossier wells in our budget, I think about three or so is what's in our initial budget now.
I think it's three to four Bossier wells right now. Yes.
Back in the same area, I think, that we drilled before. The Haynesville, that's really the top projects, that's why the budget with a lot of inventory to choose from is your top projects, especially for production right now, is the Haynesville projects. Even the short laterals, long laterals, they provide a lot of production per CapEx spend.
Got it. Thank you so much.
Great questions. Thank you.
Thank you. Our next question comes from David Deckelbaum from Coker Palmer. Please go ahead.
Hey, good morning, gentlemen. Thanks for the time.
You bet.
A micro and a macro question. On the micro front, given your guidance for production, what would you expect for seasonality as the quarters roll out? Would it be steady or stronger in the first half than the second half relative to sequential? Any kind of color you could give us on that would be appreciated.
Sure. You're talking about as we look at bringing the volumes on. We have good growth as we get into especially the first quarter next year, as you start to see the impact of running four rigs.
Remember, the fifth rig comes in March.
Since the fifth rig comes in March, you're really seeing the impact of that not till the second half of next year. The second half is going to be a little bit stronger than the first half for our growth plan. That gives us the flexibility to react, because if gas prices underperform where we are and where we're hedged at, we can delay that fifth rig or eliminate that fifth rig. We're pretty comfortable that the four rigs is very solid in not a great gas price environment, and the fifth rig is more of the, how do we invest the cash flow, and it's more of the one we want to add. You notice we're waiting to add that when all these non-operated expenditures from the Bakken, where there's a lot of DUCs being completed there, and then even our recent Enduro acquisition.
There's five wells being drilled there, that we have a fairly big interest in. That non-operated activity is all completed in the fourth quarter. Next year, we don't see a lot of non-operated activity. That's another reason why we're keeping that rig back until we make sure we have all that covered.
Hey, David, this is Dan. I'll add, too, that. We got a really good mix on our rig contracts currently. We got some that are on very short-term contracts and some a little bit longer contracts. We got a lot of flexibility. If we need to drop a rig on short notice, we can do that next year.
Got you, that makes sense, especially given the curve is so strong in the front months here and then who knows back half. Switching over to a bigger picture question, relative to M&A and the Haynesville, obviously a lot of companies, large and small out there, and you guys have a goal to de-lever. How should we think about leverage metrics relative to doing a sizable acquisition? Or asked another way, if you did do that, what leverage metrics would you be looking at if you did a large acquisition?
Obviously, the Haynesville's an area that's opportunity rich, on the M&A front, given that we're one of the few public companies out there. It's a lot of private companies. I think, we just had a transformational transaction and with the real goal of reducing leverage over the next couple of years by developing our Haynesville properties. 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. If those gave us the opportunity to improve leverage and made the company better all the way around, I think our major stockholder, Jerry Jones, would consider it. To the extent that it requires us becoming more levered, I think it would be a kind of a non-starter.
More leverage, David, would be a deal killer. If they had inferior acreage, that'd be a deal killer. If the core were not in the Haynesville Bossier, which is our backyard, that'd be a deal killer. If they had a 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 the Jerry Jones, I think he'd be smart enough to want to do that. I think the world's pretty bright for us in the future right now. Like Roland said, we do, in our opinion, have a great reputation, or I don't think the Joneses would've dealt with us. Second of all, we've been here a long time. We've got a deep route structure, and I think we're just now starting to grow the tree. It looks pretty good.
I think specifically looks like if you get to the 2.5 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 then maybe go up a little bit, that seems to be a ceiling versus a floor.
Yeah. I think we'd agree with that.
Look, we've been in a ditch. I hate it, been muddy, and I hate it, and I don't want to get in it. I want to stay in the middle of the road, okay?
Oh, yeah. Understood. Thank you, gentlemen. Appreciate the time.
Yes, sir. Thank you.
Thank you. Our next question comes from Gregg Brody from Bank of America. Please go ahead.
Good morning, guys.
Morning.
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 through 2019? How should we think about that, and maybe just in general, are there anything else working capital-wise we should be thinking about going into next year?
Yeah, Gregg, I don't know if we call it cash burn, but I guess what we really saw was Comstock historically we've operated 98% of everything. The timing of operated revenues and expenditures are a lot different than non-operated. We'll receive the cash from the sale of operated production, maybe two months quicker than non-operated production because the operator has to process it, hang on to it, and probably waits a while to send it to us. That's the typical way. We were on the other side, and that's why we love to operate. The same thing on expenditures. It's really the opposite there. Usually you're cash called and have to pay for the CapEx in advance. We have a significant amount of prepayments that we just never have because we obviously don't cash call ourselves.
I think that big shift was a pretty big shift. I think what happens is the CapEx part will reverse because those projects are gonna be finished up, but by the most part early next year. The Bakken opportunity was kind of contained. We don't see a lot more of that. You'll see a big reversal of that. Some of the CapEx that's in our budget, we've already paid for, and it's paid for up there, and we've got the advances up there and other current assets. You can see that number's really big compared to what it used to be. As far as the oil and gas receipts, those will come slower. They'll come, and so we'll have a bigger amount of our revenue inside accounts receivable for the oil production than we do for the gas.
That won't reverse because what happens is, as the company's growing, it's really growing on the gas side, so the effect of that you'll see diminish. Long answer to your question, but basically I would say a good bit of it's going to reverse, but some of it we'll be carrying more receivables on non-operated properties than operated.
Got it. You don't see any increase through 2019, just you getting some of it back?
Yeah, we see it reversing back, and we do want to pay down the credit facility as we get, especially get all those, since we prepaid capital expenditures, and even though we haven't expensed that yet, that's part of our budget we won't actually have to pay. That's when we'll pay that cash flow down on the credit facility. A little bit of a transition there to have a good bit of our revenue stream non-operated with the transaction.
That's helpful. You gave these pro forma production numbers as if Bakken was in for the full year on your slides. I believe you said all the-
The full quarter.
Yeah, the full quarter.
Yeah.
You also mentioned that the constraints for the shut-in production that's behind you, did that impact fourth Q at all? Should we be reducing those numbers a bit, or is it completely behind you by the time the fourth quarter started?
We're always going to have some shut-in volumes. We always factor in for offset frac activity. Sometimes that can be more intensive, especially, we're shutting in some of our best wells, which we were, as we were shutting in some real racehorses down there when we did the Brantleys and some of those wells. It can be more impactful than not, depending on where that is. There's always going to be an element of shut-in offset frac now. We expect, and we're holding them accountable that our midstream partners are not going to have the issues. We grew production so fast up in Caddo Parish, in an area that hasn't seen that kind of production, and God knows how long. They thought their facilities could handle it, but then they didn't. That happened four or five times. Very frustrating.
We do see that it seems to, knock on wood, that 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, for the last month, we've been flowing without any issues up there. They did some upgrades to the treating plant. They had some hiccups, should've 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 minor issues that they had to get solved. For the last month or so, we've been flowing basically unrestrained. Now just dealing with the offset frac activity.
Which should mean that we should have a significantly better-looking chart on the shut-in production for the fourth quarter, because that's going to be most of the fourth quarter there that we've been flowing good. We're optimistic there that you don't have to be as worried about it. Hopefully, we grew through that adjustment up there. Now, with the one rig program up there, I think the production isn't going to be more The growth isn't as dramatic as going from zero to the large number that we started producing up there.
Yeah, we stress tested all the pipes up there. That's what happened, so.
Again, part of it was these wells are producing at a much higher rate than we told them they would. It was a little bit of a good problem. Now everybody knows what to expect.
Yeah, I'm just trying to figure out 4Q production. It looks like, prior to the last two quarters, four and a half to 5,000 cubic feet per day was what Or sorry, 1 million cubic feet per day is what you were shut in. Is that probably the right number that you-
Yeah. Well, five to eight. I think eight. I think 8 million a day is if we're this active. We're more active than we were back in those earlier numbers. Typically, though, in a little bit, we could have activity from an offset operator that can cause the same thing. A lot of this we do to ourselves, I think.
Yeah. This is Dan. I'll just add that a decent amount of the volumes that are shut in for frac activity is for offset operators, and that's something that's a little bit harder for us to predict.
Got it. Thank you for the color, guys.
Thank you. Our last question comes from Ron Mills from Johnson Rice. Please go ahead.
David asked my question on the acquisitions, but one other thing. Just the short two areas where you had the shorter laterals, the Bagleys, I guess, and the Brantleys had some of the higher rates. Is that just owing to the rock down in that part of DeSoto Parish, or is there something else going on?
This is Dan again. We get really good IPs out of the short laterals that really torques up our production. Obviously, the Brantley is in a very good area of the Haynesville when you look at the acreage. The Bagley is also. Even though the returns are a little less on the 4500, you do get really good IPs. They clean up faster. They make less water. You get the production ramped up faster in the first 30, 60, 90 days.
Dan, you might add on the long 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.
Yeah. If you look at a plot of basically IP per 1,000, you get much better IPs on the shorter laterals, because they do clean up faster. They got less water to recover. We have noticed on the 10Ks, especially since we've gone with this Gen3 completion design, we got so many more take points on the wellbore that when we're IP-ing the wells, we tend to make more water just up front, which does hinder our ability to get the same IPs we got with the earlier Gen1 and Gen2 designs. It does force us sometimes to flow the wells back a little bit longer than we normally do, just trying to get those tests. You do get lower IPs per 1,000 as the laterals get longer.
All right. Okay, great. Hey, thank you for the clarification.
Thank you. 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 of return on our 4,500-foot laterals, which is what Ron just asked about, the 4,500-foot laterals, and a 70% rate of return on our 10,000-foot laterals. As the price increases to $3.50, the rate of return increases to 86% on our 4,500-foot laterals and over 100% on our 10,000-foot laterals. To the stakeholders and the bondholders and the banks and the analysts that are on the call, we all know that there are not many true proven crown jewel oil and gas asset basins in America. Not when you consider takeaway issues, differentials, et cetera. We at Comstock, we are 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, like Dan said, to create even a greater wealth on a per well basis. 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 many bright days as we focus on delivering to you, our stakeholder, strong, predictable results in the coming quarters and years ahead. Again, thank you for the hour that you've spent on the call. We greatly appreciate it. Thank you.
Thank you, ladies and gentlemen, for attending today's conference. This concludes the program. You may all disconnect. Good day.