Comstock Resources, Inc. (CRK) Q1 2019 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Comstock Resources First Quarter Q2 2019 Earnings Conference Call. At this time, all phone participants are in a listen-only mode. [Operator Instructions] As a reminder, today's conference is being recorded. I'd now like to introduce your host for today's conference, Mr. Jay Allison, CEO. Sir, please go ahead.

All right, thank you, Liz, and welcome to the Comstock Resources first quarter 2019 financial and operating results conference call. Today, we will review our first quarter 2019 earnings and drilling results. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and downloading the quarterly results presentations. There you will find a presentation entitled First Quarter 2019 Results. I'm Jay Allison, CEO of Comstock. With me is Roland Burns, our President and CFO, and Dan Harrison, our Vice President of Operations. Please refer to Slide 2 in our presentations and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. Slide 3 summarizes our first quarter results. The first quarter results reflect strong growth from our Haynesville-focused drilling program, as we are seeing results from the expanded program we put in place in September of last year as we reinvested the cash flow from the Bakken shale properties into a 4-rig Haynesville drilling program. We continue to have strong results from a proven drilling program, as we have now drilled and completed 76 operated wells since 2015 which have an average IP rate of 25 million cubic feet per day. This quarter we reported on six new wells which had an average IP rate of 26 million per day. Our Haynesville/Bossier production was 57% higher this quarter than a year ago and shows we are on track to have 50% growth in our natural gas production this year. The Haynesville production growth provided for a solid first quarter. For the first quarter, we reported oil and gas sales of $132 million, EBITDAX of $97 million and operating cash flow of $71 million or $0.67 per share. We reported adjusted net income for the quarter of $24 million or $0.22 per share. I'll have Roland Burns cover the financial results in more detail. Roland?

Thanks, Jay. Slide 4 shows that 57% production growth from the Haynesville/Bossier wells that Jay just talked about. In the first quarter of this year, our Haynesville production averaged 348 million per day as compared to 222 million per day in the first quarter of 2018. We put 6.8 net wells on production during the quarter after adding 5.1 net wells in the fourth quarter of last year. Looking ahead in the second quarter, we expect to put 7.8 net wells on production, and all but one of those will be on production by the end of next week. So we expect a really strong quarter in the second quarter for production growth in the Haynesville again. On Slide 5 we recap what production we had shut in for the quarter. First quarter shut-in volumes were 19.5 million per day, and that's about 5% of our total gas production. This is slightly higher than the amount that was shut in, in the fourth quarter at 4%. 85% of the shut-in activity in the first quarter were wells that had to be shut in for offset frac activity or other type well work. It was a very busy quarter for completion activity, as we had 19 wells being completed in the quarter. Nearly 15% of the shut-in was due to third-party pipeline curtailments, and after some modifications, we believe that we'll be able to have that to 0% here in the near future. Our goal is to try to get the shut-in production percent down to about 3%, and that's a work in process. On Slide 6 we detail our producing costs per Mcfe. Our operating cost in the quarter fell to $0.74 per Mcfe as compared to the fourth quarter of last year, which was $0.77. Gathering costs were $0.20, production taxes averaged $0.16 and field-level costs were $0.38. Our DD&A per Mcfe produced for the quarter was $0.99. It was a penny less than it was in the fourth quarter at $1.00. On Slide 7 we summarize the first quarter financial results. Our production in the first quarter was 38 Bcfe, which includes 810,000 barrels of oil. This is 67% higher than the first quarter of 2018 and 6% higher than the fourth quarter of last year. Oil and gas sales were $132 million or 79% higher than the first quarter of 2018. In the first quarter our realized oil price was $45.78 per barrel, and our realized gas price was $2.87 per Mcf. Differentials for both oil and gas prices in this quarter were wider than we normally experience. On the oil price, the Bakken bases widened considerably in December, which carried over into January due to refinery issues and other issues in the basin. By March, though, our oil differential in the Bakken was back to a normal level of about $4.50 a barrel as compared to WTI and NYMEX. On natural gas, we sold more than half our production in the quarter in the daily market versus on the index market, and usually there's not a very big difference between those two. But the first quarter was unusual, as gas prices -- Nymex gas prices for January were $3.65, and then by the time you got to March, they were $2.86. So if you looked at the month of January in particular, which was the high-price month, there was almost a $0.60 difference between the daily price and the index price for the month. The other factor kind of driving the differential a little bit is that we had a lot more production in the second half of the quarter, more into the latter part of February and March when gas prices were lower than the very high price of January. When you get back to March, our differential was back to kind of normal at about $0.20. Overall in the quarter, our EBITDAX came in at $97 million, and that's 81% higher than it was in the first quarter of 2018, and our operating cash flow was $71 million, up 98% from 2018's first quarter. As Jay mentioned, we reported adjusted net income of $23.5 million for the first quarter, or $0.22 per share. Net income was adjusted only to exclude the unrealized mark-to-market loss on our hedge contracts of $13 million in the quarter. Slide 8 summarizes the hedge positions we have in place for our oil and gas production. In the first quarter we had 222 million per day of our gas hedged and about 4,173 barrels of oil. But for the rest of the year, we've got about $181 million of our gas hedged and about 3,500 barrels of our oil hedged. And our plan is to continue to hedge 50% to 60% of our production on a rolling 12-month basis. On Slide 9 we recap our spending in the first quarter on drilling and development activity and then our estimates for all of this year. We spent $92.5 million in the quarter on development activities. $88 million of that was in our Haynesville program. We drilled 11, or 8.4 net, horizontal Haynesville wells, which had an average lateral length of approximately 7,682 feet. We also completed 17, or 5.2 net wells, that we drilled last year. We spent $5.6 million in the quarter drilling 2, or 1.1 net, Eagle Ford oil wells, and we have another two that we're drilling in the second quarter. So if you look at the entire year, we're now estimating that we'll spend about $345 million on all our capital activity. That's down from our previous estimate of $364 million, and as Dan will go over in a few minutes, that's really due to the lower frac cost that we have beginning in April, which is the largest driver of the lower cost. Slide 10 presents our balance sheet at the end of the first quarter. We ended the quarter with $29 million in cash and $1,320,000,000 in total debt, which is comprised of amounts drawn under our 5-year credit facility and $850 million in our senior notes. We ended the quarter with $259 million in liquidity, including the undrawn $230 million by credit line. We do expect to pay down our debt a little bit in the second quarter, as our cash flow is expected to exceed the drilling and completion spending in the quarter, plus we have about $22 million of an income tax refund for AMT taxes, which were eliminated in the Tax Reform Act, and we expect to receive that late in the second quarter; worst case, maybe in the third quarter. I'll now turn it over to Dan to kind of report on the drilling results.

Thank you, Roland. On Slide 11 you'll see this is the usual slide I like to start off with. It shows our 88,000 net acre position in the Haynesville and the Bossier shale play. So since returning to the play in 2015, we've now completed a total of 76 operated wells with an average IP rate of 25 million cubic feet a day. We are currently running four rigs in the play. We plan to drill a total of 49 operated wells by the end of the year. Turn over to Slide 12. You'll see the locations of six new operated wells that have been completed since our last update. All six wells were drilled in the Haynesville and completed using our Gen III frac design with 3,800 pounds of sand per foot. Five of these wells were completed with our normal 10-by-15-foot cluster spacing, and we did test one of the new wells with seven clusters at 20-foot spacing. All six wells were nominal 10K laterals. The actual lateral lengths ranged from 9,646 feet to 9,913 feet. The initial rates ranged from 21 million cubic feet a day to 30 million cubic feet a day and had an average in this rate of 26 million cubic feet a day. At this time, we currently have eight wells that are in the process of being completed, and we anticipate turning seven of these eight wells to sales by early next week. On Slide 13, this is an illustration of the long-term performance of our Gen I vintage wells compared to the Gen III vintage wells. This is with the wells that have sufficient production history. Our Gen I wells were predominantly drilled as 7,500-foot laterals back when we returned to the play. Our newer Gen III wells have been predominantly drilled as 10,000-foot laterals. The Gen III completions continue to outperform our earlier vintage wells. This slide clearly illustrates the uplift in recovery as a result of drilling longer laterals, opping larger frac jobs coupled with the tighter cluster spacing. Our average Gen I well today is currently forecasted to recover 15 Bcf or 2.1 Bcf per 1,000 foot of lateral. Our current average of our Gen III wells is on track to recover 22 Bcf or 2.4 Bcf per 1,000 foot of lateral, or nearly 50% more recovery than the average Gen I well. This change, coupled with our continually improving cost structure, is what is driving the increase in our returns. Slide 14 is an update and summary of the underlying assumptions and economics of the different lateral link cases using the Gen III frac design. As everyone knows, the frac costs are the driver for our total well cost. With the softening frac market, we've been able to drive down our total well cost, which has bolstered our economics. At the $2.50 flat gas price, we're generating approximately a 37% rate of return on our 4,500-foot laterals and up to a 76% rate of return for our 10,000-foot laterals. With the gas price increasing to $3.00, the rate increases to approximately 76% for the 4,500-foot laterals and well over 100% for the 10,000-foot laterals. For the remainder of our 2019 Haynesville/Bossier shale program, we are planning to run five rigs throughout most of the year and drill a total of 49 operated wells. Approximately 60% of these wells are planned to be 10,000-foot laterals. We're continuing to push down our well costs, improve our well performance and improve our gas takeaway cost structure. All of these measures deployed together will generate strong returns and cash flow into the future. That is a quick summary of the operations. I'm now going to turn it back over to Jay.

All right. On Slide 15 we summarize our outlook for the year. Our Haynesville and Bossier shale assets provide us the opportunity to create value by using our operating cash flow to drill consistent, high-return and low-risk wells. We plan to drill 52, or 34.6 net, Haynesville/Bossier horizontal wells this year out of our extensive inventory of 819 net drilling locations. We're on track to generate the production growth we estimated for this year and still estimate that we'll produce 385 million to 415 million cubic feet of natural gas per day in 2019, we expect our oil production to average 8,000 to 9,000 barrels per day and we are very focused on improving our cost structure, as Dan and Roland reported earlier. Our new frac design and lower per-well frac costs from our providers are driving lower well costs this year. We're also lowering our transportation costs with new contracts, which should lower our lifting cost on a per-Mcfe basis. We just started drilling on our 95,400 undeveloped net acres in the Eagle Ford, where we have 126 net potential drilling locations for future oil growth, and expect to complete those wells next quarter. Our primary strategy remains to generate disciplined growth by operating within our cash flow. We're hedging the next 12 months' production to protect our drilling returns, and we ended the quarter with liquidity of $259 million. For the rest of the call, we'll take questions from the analysts who follow the Company. So Liz, I'll turn it back to you.

Our first question comes from the line of Ron Mills with Johnson Rice. Your line is now open.

A quick question on the well cost savings and also the gathering fees. It seems like most of the well cost savings are coming on, on the completion side. I just want to confirm that and see if there are any other kind of completion efficiencies you expect. And then on the gathering side, how much of an impact do you think that you can have on your overall LOE costs in terms of what order of magnitude can the new arrangements impact the LOE outlook?

Well, Ron, the main cost of these wells are frac costs, as you know. So I'll let Dan address the frac costs and how they've been coming down.

So the frac costs definitely have just come down just with the market softening up. We've also tweaked our frac designs a little bit. We've been able to kind of ramp up our concentrations a little bit higher. We're using a little bit less water, so basically we've shortened the pump times slightly. So just in addition to just kind of the market forces, we've also been able to capture some savings by basically, and if you want to call it an increase in efficiency, increased speed, less drilling time per se has been part of our cost savings.

You might mention the rig rates, too, slightly down, right?

Yes, so the rig rates also are down slightly. I know that's not a big needle-mover for the total well cost, but of course we saw increasing rig rates for the last several quarters, and here in the last quarter, we've seen that reverse slightly. We've renewed -- we've got two new rig contracts that were approximately $1,000 a day less, and have had one that we renewed that also dropped about $1,000 a day. So that helps a little bit also.

Yes, Ron, I can tell you the handful of Tier 1 providers, either drilling contractors or frac providers, they're all in the Haynesville, and they've all been very competitive with each other. So we're talking about quality service, and it's lower cost because it's a little more competitive. And then again, as Dan had said, we shaved off a lot of time when we completed these wells in our frac stages, and time is money. So I think you're starting to see that money dribble into our numbers. That's why we can cut our CapEx budget for the year almost $20 million and still hit our production guidance, which we are way ahead of it this quarter.

And Ron, the last part of your question was on the gathering rates, and we are putting in new contracts, especially in our core kind of Logansport kind of DeSoto Parish area. And the magnitude of that is probably $0.02 to $0.03 kind of coming off our lifting cost. When you look at the Company composite, I think that one particular area, though, savings could be -- are closer to almost $0.10. But yes, our highest gathering cost is our non-operated stuff, and I think we've got -- we had probably a big increase in production from our non-operated stuff in Caddo Parish, which has the highest lifting costs. That was from activity at wells we put online last year. That's -- so some of the savings you probably would have seen already this quarter, that probably offset, but as all our new wells come on, you'll start to see that lifting cost, I think, come down in that $0.02 to $0.03 range as we go out into the next quarters.

Okay, great. And given what's going on the market, this is a pretty common question now. But you've been talking about kind of acquisition and/or growth opportunities. You've been very successful picking up smaller pieces around your Haynesville position. Can you talk a little bit about kind of the state of that market right now, how your discussions are going as you continue to kick tires, particularly in the Haynesville, but it also looks like you recently added a little bit of acreage in the Eagle Ford, and how you kind of weigh those two areas? Thanks.

Well, I would say that any company that has the growth that we have and the stability that we have, and really, the turnaround that we've had -- we are always, kind of like Columbo, we're always looking for something that is accretive, that lowers our debt, that adds to our inventory. But it has to make sense, so we -- with these 819 locations we have, we're not pressed to do anything. In fact, if you look at our Gen I versus our Gen III wells, our Gen III wells, they probably recover 50% more reserves than Gen I. So I think as a public company -- really, almost a pure public company except for the Bakken production -- I think we're well positioned to kind of review any opportunities that are out there, as we have been doing. And you followed this. Even in the third and fourth quarter of 2018, we're continuing to do that in an aggressive way. I think you should be doing that, particularly in this market.

I think what we've done that you've noticed, like this quarter, we have picked up adjacent or additional interests in our existing Haynesville acreage on a fairly small scale, but really have been focused on looking for those opportunities of any type of unleased acreage or also worked on acreage trades with some other operators. So really been focused on making our overall acreage position better, and you can see some of that this quarter. And what we continue to be looking for great opportunities. But we have a great asset base now, so that's not -- if we were to make any type of acquisitions, they'd have to kind of check all the boxes as making the Company a better company.

A great question, though, Ron.

And Dan, can you just -- I missed a couple of the numbers. When you talked about with the lower well costs, you updated the IRRs at $2.50 and $3.00 for those 7,500- and 10,000-foot lateral links. I'm trying to look at the slide. I think I'm trying to eyeball it. But I think you gave the numbers. Can you just repeat those, please?

Well, at a $2.50 flat gas price -- remember, we got a 37% rate of return on a 4,500-foot lateral -- we've got a 76% rate of return on a 10,000-foot lateral. But then if you look more at the $3.00, which historically gas has been the rate, you've got a 76% rate of return on a 4,500-foot lateral and you've got a 152% rate of return on a 10,000-foot lateral. And remember, most of the planned laterals we have this year, or 61% of them, are going to be at the 10,000-foot, and we'll have the five rigs running.

Our next question comes from the line of Rehan Rashid with B. Riley FBR. Your Line is now open.

A couple of quick questions, maybe, on the completion design first. Have you guys been changing how you manage your choke and kind of what portion of your portfolio is kind of going through that, and then kind of what impact would you see on kind of production because of it? And then a little bit more color on the 126 Eagle Ford locations. How de-risked are they and kind of how aggressively are you going to go after it this year and next year?

Well, I'll let Dan -- and again, Rehan, welcome back. I'm sorry I didn't say it with any emphasis, though. And you remember Dan Harrison, who's been on every well we've ever drilled in the Haynesville going back to 2008. So if anybody should have the correct answer as of today, it would be Dan, I would think. So I'll let Dan answer that. Dan?

So the flowbacks are basically what we've reported on today, including the six wells that we have announced for the first quarter have basically been flowing back kind of the same way we had been flowing them back. We are looking at, and have been working on now for a little while, kind of the transitioning over into what we call, I guess, a managed flowback. It would be a little bit smaller IPs, but obviously, much, much shallower climbs would be a lot more production in year 1 and year 2, which is going to drive the return higher. And we just, we don't have anything on our results yet to show actual data on that, but we are in the middle of trying to get transitioned over to that new, kind of that new flowback method.

Okay, okay. And then on the Eagle Ford, please?

Yes, on the Eagle Ford, that's the -- we typically have a 50% to 55% interest in those locations. That's the undeveloped part of the properties that we sold to our partner there, USG. And we retained interest in the undeveloped part. And so after they -- we just now started drilling some wells, and so we have the four wells this year. I think they really want to kind of see the results of those. We do think they're all -- it's obviously a very de-risked area because it's all around stuff we drilled years ago and other operators -- Venado, Chesapeake EOG -- are all around this acreage. Some of that acreage we sold last year because we had a great offer on it, and then our goal is to get the full value out of the properties. But we're kind of excited to see what these four wells will look like. It's our first wells drilled since -- it's been at least 4-plus years, it seems like, since we drilled one. And then I think as we kind of do those, we'll kind of assess the economics of drilling the Eagle Ford and compare it to the inventory in the Haynesville and make real decisions about do we accelerate that or just kind of continue to drill what's needed to keep -- make sure we don't lose any acreage.

Yes, Rehan, remember that acreage, we started adding that acreage in 2010, and we own probably 197 of the Eagle Ford wells. And then as Roland said, we monetized the PDP portion about a year ago. So this is kind of that remaining acreage.

Good, good. One last quick question. I apologize, Dan. What's the cost per 1,000 lateral foot now after you kind of -- the new run rate for Haynesville wells?

The D&C costs for 1,000 foot for the three lengths, is that what you're asking?

Yes, sir, yes.

Okay, so we're, kind of just look back on that Slide 14, so we're down with the -- with the frac costs being pushed down, we're at about $10.8 million for the 9,500-foot laterals. So it's going to be -- don't have it exactly.

Dan, I've got it.

Right off the top of my head, but $9.5 million for the 7,500-foot laterals, and we're down to $6.6 million on the 4,500-foot laterals. We, just some of these wells we're turning into sales next week are some of the 4,500-foot laterals, and we're right on the money there on that $6.6 million.

Our next question comes from the line of Sean Sneeden with Guggenheim. Your line is now open.

Could you guys talk a little bit about adding the fifth rig, and I guess how do you guys kind of think about that process in the context of current liquidity and trying to manage the leverage profile?

Yes, I think the fifth rig, I wouldn't look at it as like -- it's really, it's going to drill wells we have a very small and low interest in, so it was more to accommodate kind of wells that we're operating we have a low interest in as opposed to trying to ramp up the program. So it was always kind of needed in order not to ramp down the program, because these projects need to get drilled. So that's why they're -- it was always in our plans to add it. So we really have kind of kept the exact same rig program. I wouldn't view it as a move that we looked at adding activity.

Well, in fact, we demonstrate that by reducing our CapEx costs for the whole year.

Yes, and it's for the most part drilling wells we have a very low interest in.

Got it. That's helpful. And so I guess once that the low interest wells are done, you plan to drop that, or would you kind of look into maybe keeping that?

Well, I think it will be more that as we look ahead to next year and we'll decide what's needed, but I think it's definitely something that we'd have to look at. Do we need five rigs next year or not? And so I think if we're not thinking we will, we'll be dropping it toward the end of the year. The current plans are to drop it by the end of the year.

I think that this year rig count is a little illusional, because.

Yes, because it really isn't added, yes.

You could say we're maybe we're at 4.1 rigs, is really more realistic. But the good thing is it will generate good operating fee income and it has other kind of nice overhead aspects to be running the rig for other parties.

And those wells had to be drilled.

Got it. I think that makes sense. And I guess when you think about the kind of end of the year position as you start planning 2020, is the goal to try to attain certain size and scale that you're ultimately solving for when you think about how a fifth rig would play into that, or how are you guys kind of thinking about that at this point?

The goal is really to improve the Company's leverage, and it's a balancing act between growth and EBITDAX and not growing debt. And so I think operating cash flow is the governor, and as we get into -- with the bigger production base that we'll have generated in 2019, I think that we'll be looking to set a program in 2020 that generates free cash flow, so that's the real plan. The real plan is not to -- is really to -- what's the best way to continue to reach our goal of reducing leverage to under 2x, and so how the drilling program can contribute and how it will basically contribute will be all looked at. And out-spending cash flow is definitely off the table, for sure. And so that's kind of how we look at it. So we are very -- we have lots of flexibility. There's very little drilling that has to be done by the Company. We could probably run a rig and probably meet any kind of drilling obligation we have, so it's -- the scheduling's all based on what we think is the best program, and we'll continue to assess that. But this year's program can also be adjusted by releasing rigs earlier than what we have in here now. So we'll continue to monitor it quarter by quarter. I think we've been real -- the way Dan's been able to drive down the well cost was a nice offset to where we otherwise would probably be looking to release one of the rigs earlier this year, given the little bit lower commodity prices that we now are expecting.

Well, to Roland's point, it's unusual to have a material feed in our production and to have cost reduction and to have the type cars turn out better, and now we have 76 of these wells that we've drilled and we've operated. And like Roland said, we're going to have the production volumes by year end, so we'll see where the commodity price cycle is, and we're not in need of locations. We'll more than replenish what we drill this year just through land swaps, et cetera, add-on, bolt-on, smaller deals that we do yearly. So we really are in a great seat to create wealth in the Haynesville.

I think that's pretty helpful. Appreciate all the comments guys. Thanks.

Great question.

Our next question comes from the line of Gregg Brody with Bank of America. Your line is now open.

I think there was a comment made earlier about trying to reduce the production, amount of production that's shut in, in the quarter. I guess what's the plan? How do you do that?

One of it is really, I think, we a lot of times looking really hard at trying to optimize the schedule because where you drill determine -- where you drill if you're going to try to drill a well next to your brand-new, high-volume wells and then have to shut them in, that's what contributes to the shut-in.

Remember, 85% of that was because of the offset wells.

You can't eliminate all of it, but I think a lot of it is to drive the -- I think that 15% of areas up in Caddo where they're adding a new compression project to kind of allow us to flow those wells like they should be flowed. Even our last two wells up there, we didn't -- we couldn't even bring them up to a normal IP because we didn't want to have to shut in other wells. But I think that will kind of alleviate that area, and that's within a few weeks. Yes, next month we'll have that. So that will eliminate that small part, and then I think we feel really good about the rest of the year as far as takeaway capability. So then it's all about trying to optimize where you're drilling, where you're fracking, and a lot of that's how we try to look at the schedule so -- to kind of get it down. We think that 3% level is a kind of, is a normal level that you're going to have unless you're just not active.

Hey, Gregg, this is Dan. I just want to add so that the majority, most all of that shut-in production due to pipeline curtailment was up in our JV area with USG, and it's been so successful that they couldn't keep up with the volume amount that we were producing. And so they've kicked off a big compression project that will -- should get going first of next month that, hopefully, will wipe that out. Then as far as the shut-in production due to the offset fracs, we're going to a lot more full section development projects to try to eliminate that. And that's -- we've got one of those we just completed, and that's why we're going to be -- that's why we've got so many wells we're turning to production last week because we've got one of those projects that we just completed.

I guess it's a good thing. The Caddo wells came in as good or a lot better than we thought, consistently. So that's where Dan said and Roland commented the modifications that we're going to have in Caddo, it should get us down to 0% for shut-ins.

And that area's starting to get fairly developed, so that's kind of, as you look ahead past this year especially, that area's fairly developed, and we'll be focused more on the other properties of the Company -- DeSoto Parish and the new areas that we acquired with Enduro. That's kind of where you see the shift is. And for Enduro acreage that we bought around it, we now have much bigger expectations for those wells than we did back when we put together the acreage with USG up there. And so we're definitely going to be sized right for the wells for the -- as we start developing that acreage we bought in the Enduro acquisition.

Yes, and I can say, Gregg, we've got really good relationships with the 4 or 5 midstream companies there. They see we're growing, so I think that helps, too. Because in our planning for our budget in '19 and '20, whatever, we look at the takeaway issues and we look at offset well issues, and I think we have a -- we try to figure out what the peer operators are doing -- and we all are friendly with each other -- to find out what wells they're drilling and what we have to shut in and what they have to shut in. So I think we're all getting a little better at that.

You related it perfectly to my next question, which is could you talk a little bit about the basin takeaway capacity issues you may see, how much you're -- you've given me some answers as to what you're doing to address it. But maybe more around pipeline would be helpful. And then just your perspective on basis. What do you think is the right way to think about it?

Yes, that's a good question, and I think obviously, the basin's producing more than it has in recent years with the successful wells that the Haynesville companies are drilling. We've been planning for expansions, and actually, that was the catalyst to the reduction in our midstream costs by adding, having a lot of this new acreage that we acquired in the Enduro and Shelby acquisitions that was not dedicated, like so much of the acreage is dedicated out there. That was the catalyst to driving down the cost, plus having new capacity put in. So I think that as you look at, in our more active area like DeSoto Parish, there are some very low-cost expansion projects that we're talking with our major providers there that can really increase the capacity of the pipes there. You still have a lot of availability in the current pipe, so it's really planning for the future. And as far as the basis differential, the largest hub a lot of the gas is sold at is Perryville, and that has over time crept up a few pennies over the last several years. It hasn't had dramatic moves, but it still -- and we see that -- maybe that trend of continuing to creep up a penny or two is probably what you should expect. But we are looking for ways to sell gas away from Perryville, and I think that's the real initiative, and there are several projects where gas eventually will bypass that area and go directly down to the coast, the Gulf Coast. So I think that we feel really good about the situation and don't see, other than potentially basis widening by $0.02 to $0.05 over the next couple of years, that's the real potential. But hopefully, we're improving our other gathering and other arrangements where we're actually going to offset that with other arrangements.

That's helpful. And you mentioned that DeSoto has a lot of projects. What's it like up in -- I'm just blanking here for a second.

The Carthage area?

Yes. Roland Burns: Yes, Caddo and Carthage, kind of the northern. That's probably where there are definitely projects under construction right now because of that increased development of that area. And that's the key one that we've already contracted with a -- that was again part of this big new contract, and so that is probably ahead of where the needs are, even. And a lot more of the gas from Caddo is actually going to be routed back toward that direction versus down -- instead of to Perryville. We see a lot of that gas really going into that Texas market, and there's more demand there, more -- so that's, as we get that acreage within the next couple of quarters, we're probably sending more gas to that area as that new area opens up for us. Great, that's helpful. And just one small item. I think you mentioned there was a tax refund expected in 2Q or 3Q. What's the -- I didn't hear the actual number.

Oh, yes, I think it's $10.2 million. So it's -- actually, it's one of the tax -- the Tax and Jobs Act. One of the big things it did was eliminate corporate AMT, and we've paid a lot of corporate AMT in the past. And so it was all refundable, but it's refundable, and they kind of delayed how quickly you could get it. So half of it you get this year and the other half you get in 2020. So it's -- so we expect to receive that, hopefully, second quarter. But that's $10.2 million this year and $10.2 million next year.

And then you have for our cash taxes otherwise, given the level of IDC that we generate from the drilling program, we really don't see having any significant cash taxes, even at the new lower rate that's in place of the new act.

[Operator Instructions] We have a follow-up question from the line of Ron Mills with Johnson Rice. Your line is now open.

Hey, Roland, I see the overall production guidance is kind of the same as before. You referenced, or maybe it was Dan, the number of completions here in the second quarter, and they're really going to be on by the middle part of May. So when we think about kind of the production cadence, and maybe even the CapEx cadence over the remainder of the year, how should we think about the production cadence on a quarterly basis?

Yes, the second quarter as we see it coming together, it should be a really good one for both those numbers. I think it will be significant growth in the second quarter production. And then if you kind of, given the way that -- it's all about when these completions happen, because they kind of, they don't cluster, they cluster together kind of in little packs, especially when Dan tries to minimize the shut-in time. So the third quarter is more -- there will be less production growth from quarter to quarter. We think we'll be maintaining a slight build, but the big, if you're looking at the guidance, which we feel very good about, especially with the good start we're at and the good second quarter, so I think you'd see the same quarter have a lot of kind of a moderate in the third quarter because it's just, given the completion activity, and then another big kind of growth spurt in the fourth quarter. That's kind of the -- now the CapEx, unusually enough, we did a lot of that frac work in the first quarter for these wells than the second quarter. The CapEx we see going in an opposite trend. We see it being one of the lighter quarters of the whole year will be the second quarter because we're only running one frac crew now. We actually don't even have the second one. It's been released. So just the volume of, and it's really the frac crews. They drive the costs. The drilling rigs are very consistent, always doing the same thing. But when you frac these wells, it's kind of how we try to look at how the CapEx schedule then, and the second quarter should have a nice delta between the best production growth in the year, maybe, and the lowest capo cost.

Okay, great. And then just to clarify again on the gas differential, you said it's gotten back to normal. I think it had been running kind of $0.15 to $0.20. Is that the right number, or did you reference a different number?

Yes, $0.20 is the right number for the basic, and that's good. It's kind of where it was in March. It was just dramatically different in January and even February. And we see the gas, as we've gone into March and April, we've seen it kind of back to normal. And that's -- out of last year you had kind of stability. You had pretty stable basis during all of last year. So it's a really wacky first quarter for gas prices as they ratcheted way up and came way down, I think created a lot of unusual, very unusual quarter. And then, and we were probably, because of the big growth in the quarter, selling off a whole lot into the daily market versus the index market, so didn't get the benefit of the prices when they were there.

And I'm showing no further questions in queue at this time. I'd like to turn the call back to Mr. Allison for closing remarks.

All right, Liz, and again, I want to thank everybody for sticking with us, and I think we're producing what you expected us to produce. And we're trying to even get better at that. So again, thank you for trusting us and believing us and supporting us.

Ladies and gentlemen, thank you for your participation in today's conference. This concludes the program, and you may now disconnect. Everyone have a great day.