Comstock Resources, Inc.
Q1 2017 Earnings Call Transcript

Published: 8 May 2017

[Operator:]

Good day, ladies and gentlemen, and welcome to the Comstock Resources, Inc. Q1 2017 Earnings Conference Call. At this time, all participants are in a listen-only mode, later we will conduct a question-and-answer session and instructions will follow at that time. I would now like to turn the call over to Jay Allison, CEO. Please go ahead.

[M. Jay Allison:]

Perfect. Thank you, Ayala. Welcome to the Comstock Resources first quarter 2017 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 First Quarter 2017 Results. I'm Jay Allison, Chief Executive Officer of Comstock. With me is Roland Burns, our President and Chief Financial Officer; and Mack Good, our Chief Operating Officer. During this call, we will discuss our first quarter results and financial results. Please refer to slide 2 in our presentation 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 could be no assurance that such expectations will prove to be correct. If you look at our 2017 Q1 summary, which is slide 3, I'll make a few comments before we go over that. It's our corporate goal in the first quarter to transition Comstock's operations into a steady two-rig drilling program with a third rig added in our JV area with USG. Although as you'll find out that we did have some delays in the quarter, the results today are all excellent. We currently have three rigs active in our Haynesville program and the wells from our generation two completions are performing above the top curve. In fact, two of the best wells we've ever drilled were drilled in the last three months, being the Furlow 25-36 and the Billingsley 25-24 wells, which Mack will update you on during his presentation. Also, our acreage within our Haynesville shale JV has grown and is expected to see material growth by year-end. Now, on the financial side, Roland has excellent news on where our production is today. Yes, our first quarter natural gas production averaged 156 million per day, up 23% from the fourth quarter of 2016, but our current production is much higher than that. Our cost structure improved during the first quarter, mainly due to low finding cost of the Haynesville shale wells and our total liquidity (02

[Roland O. Burns:]

Thanks, Jay. Slide 4 shows our natural gas production from major regions. In the first quarter, our natural gas production averaged 156 million per day, up 11% from the first quarter of 2016 and up 23% from the fourth quarter if you exclude production that we divested out last December. We had a 45-day delay in bringing on production from the – our two Furlow wells and the Billingsley well that we reported on in this quarter. But the results were worth a wait as these are some of the best wells we've ever drilled. We expect our natural gas production in 2017 will average between 200 to 230 million cubic feet per day, and in the second quarter, we're seeing a significant ramp-up in gas production. For April, our gas production was approximately 175 million (06

[Mack D. Good:]

Okay. Thanks, Roland. Slide 11 is the usual one that you've all seen before, it shows our 68,000 net acres in the Haynesville play. And as I mentioned in a previous conference call, we're working with USG to add to this acreage position as part of a JV and as a result of this, the JV currently has over 6,000 net acres, and during this month, we plan to spud the first of several planned 10,000-foot laterals on the JV acreage. As most of you already know, we will operate this JV, and we'll start off with 25% working interest in the first few wells. As always, we are also working on improving our acreage position both as part of the JV and outside the JV. Our efforts include increasing our ownership level in future JV wells along with leasing and/or trading acreage with various parties. All of these things will obviously create an opportunity for us to grow both production and reserves. We'll talk in greater detail about all of these efforts later after the ink is dry on that stuff. Slide 11 is also providing a quick comparison between our 2016 and 2017 drilling programs and simply put, we're drilling twice the number of wells this year than last, and we're completing those wells definitely as well. Anyway, let's flip over to the next slide, so you can get some more detail of what we've been up to in the Haynesville since we reentered the play in 2015. And I know slide 12 is getting a little busy, but we're still able to show the locations and the IPs of all the program wells we drilled and completed from 2015 through 2016 and so far this year. All of the wells that we've spud this year have the gold labels. The gold 2017 completed wells on the map have IPs ranging from 25 million MMcf a day to 36 million MMcf a day and all of them received our Gen II completion design at 3,800 pounds per foot of proppant. The lateral lengths of these wells varied from 5,396 feet to 8,521 feet. The Furlow 25-24 has the shortest lateral at 5,396 feet and as you see it tested at an IP of 25 million MMcf a day. The Furlow 25-36 has the next shortest lateral at 6,355 feet, and it tested at an IP of 32 million MMcf a day. After that, The Headrick 14-23 had a 7,514 foot-long lateral, and it tested at 26 million MMcf a day. And last, but certainly not least, the Billingsley has an 8,521 foot completed lateral and it tested at 36 million MMcf a day. Since two of the wells that we just completed recently tested over 30 million MMcf a day and the other two were in the mid-20s. I guess it's obvious that all these IPs meet or exceed our performance goals. We expected and we got the improved IP rates as a result of going with our Gen II completion design, and we'll make an effort to document this for you in the next slide. This slide compares various production information against our 7,500-foot type curve. In slide 13, we separated our Haynesville wells between the Gen I and Gen II wells, so you could get a better comparison between the two. And you can see that the red color curve on the graph represents the average production profile based on our first 12 Haynesville well completions using our Gen I design. And as you remember, our Gen I design used 2,800 pounds of proppant per completed lateral foot and targeting 250-foot long frac stages using five perforation clusters spaced 50-feet apart. Our Gen II design has 3,800 pounds of proppant per foot and it has a – targets 150-foot long frac stages using the same five perf clusters per stage, but they are spaced 30-feet apart. You can also see that the green curve represents our single Bossier completion, it too (16

[M. Jay Allison:]

All right, if everyone will turn to slide 16. It's a 2017 outlook, kind of what I've got from Mack and Roland is that we have our rigs placed, and they're performing. We have an excellent JV partner who wants to grow the volumes materially in the Haynesville. Our costs are dropping and our production is growing, and we're hedging. So, with that Mack, thank you. Thank you, Roland. Let me refer to slide 16 where I'll cover our outlook for 2017. We're very optimistic about 2017 after the struggles of the last two years, which were severe. We have a high degree of confidence that our high return Haynesville shale asset will provide us the means to achieve strong growth this year. Our enhanced completion design has transformed the Haynesville shale into one of North America's highest return natural gas basins, and our acreage position gives over 700 operating locations. We're expecting our natural gas production to grow by more than 40% driven by 22 well drilling program funded primarily with operating cash flow. The production increase will cause our EBITDAX and cash flow to increase significantly. Our already low-cost structure is expected to improve with new low cost Haynesville shale production. Our producing costs per Mcfe in 2017 are expected to decrease by $0.20 per Mcfe, which is 18% lower than this year. Our balance sheet and liquidity continue to improve as we grow our cash flow and EBITDAX. Our Haynesville JV is gathering steam, and could and should be a major contributor to growth for us in the future. So, for the rest of this call, we'll take questions only from the analysts who follow the company. So, Ayala, I'll turn it over to you.

[Operator:]

Thank you. Ladies and gentleman, Our first question is from Ron Mills with Johnson Rice. Your line is now open.

[Ronald E. Mills:]

Good morning, Jay. Question on the staggered/stack test, I think you referenced in DeSoto Parish, the non-op interest you're in. Can you talk a little bit and maybe Mack about those wells and to the extent staggered/stack works cannot be additive to your current inventory, (24

[M. Jay Allison:]

Ron, this issue is one that we – we have a lot of information about, we think it will add additional locations across our acreage position in the play. I let the operator those three wells that you mentioned give greater detail in our guidance concerning the results of their wells. We do – we are very encouraged by the results. I will leave it at that. We like the opportunity. We think it will add to our inventory. But right now we're focused on the primary targets in the Haynesville going forward and drilling our first 10,000-foot lateral.

[Mack D. Good:]

And Ron, I think my only comment is that we probably a year ago thought that the staggered procedure would work, and we're very encouraged to see other operators that are testing that.

[Ronald E. Mills:]

And then may be for Roland, in terms of the remaining wells, just curious about the expected timing of completions, are they going to be fairly steady through the year, so your – the growth will be fairly steady the remaining quarters in that guidance, is it based on your published type curve. So, as these wells continue to outperform, is there potential where those guidance numbers move up with the outperformance?

[Roland O. Burns:]

Yes – yeah, Ron. Yeah, the biggest factor in our – what our actual production will be is probably more production scheduling. I think the wells – the wells have performed great and it's just the, actually when the wells come online is a bigger factor. As you saw from the first quarter, we had hoped to have some of those wells online during the first quarter instead they all came in during April or early May. But May, we've got a lot of production coming on in the month of May, like we referenced, and we have more, we have another well starting to flow back now. It's not in those numbers yet. We have several more that'll be completed in June. So, lot of stuff comes on, just happens to come on in the second quarter, and the only really lumpiness in our production scheduling is when we're doing the two well pads, so we have one rig that's doing that. The two Furlow wells are example of that. Now, the two, I think, (27

[M. Jay Allison:]

And I think, Ron, and that's a really great question because I think that there's an (28

[Ronald E. Mills:]

Great. Thank you, guys.

[Operator:]

Our next question is from David Beard with Coker Palmer. Your line is now open.

[David Earl Beard:]

Good morning, gentlemen and congratulations on the well results.

[M. Jay Allison:]

Good morning. Thank you.

[David Earl Beard:]

Big picture question, could you just comment a little bit on cost inflation, especially relative to sand cost?

[M. Jay Allison:]

Yeah. We are seeing some cost increases across the board. Proppant costs are putting much what we're seeing on the inflation there is about the same as we're seeing overall with completion cost in general. So we've factored in a 10% increase in our cost structure. We anticipate with increased activity in the Haynesville that those costs will rise some more before the end of the year, so we're not surprised or taken aback by any of that. Proppant supply is keeping up with the demand and we have various arrangements that have secured the proppant supply of our 2017 program wells. So hopefully that gives you a little color on the cost structure that we see for the remainder of the year.

[Roland O. Burns:]

You know some – a question that people never ask is, what did it cost you to lease an acre, may be cost you $1 million, $30,000, what does it cost you. And then the Haynesville, we've had this acreage for 20 years most of it, so you got to factor that in whether the well's economic or not. So, I think when you go into well cost, I mean, Mack gave you some pretty good numbers on whether the wells are 4,500-foot 7,500 feet or 10,000 feet. And yeah, our proppant cost may increase by 10%. I think our rigs are locked in anywhere from six months to a year. That's (31

[David Earl Beard:]

Now I understood. I appreciate the color. And just as a follow up given the well results you reported, would you plan on changing your mix of laterals relative to your drilling program this year, or kind of stick with what you laid out at the end of the year?

[M. Jay Allison:]

I think right now, we're – we're going to stick with our original plan. We do – we're blessed to be able to be extremely flexible going forward. We'd like to get some different lateral lengths completed, so we can measure the relative performance between those laterals and basically confirm what we think we know at this point. Like I mentioned earlier in some comments that I made, we have several 10,000-foot laterals that we're going to drill. We have several 7,500-foot laterals we are going to drill through the remainder of this year, and intermixed, we will have some 5,000-foot laterals as well. And by the end of the year, we'll have a significant dataset that we'll be able to look at and evaluate and set the stage for our 2018 program.

[David Earl Beard:]

Okay. And so, does the joint venture want to do mostly 10,000-foot laterals, or is that just what you're going to do out of the shoot and that may change?

[M. Jay Allison:]

Well, again, we're flexible on that as well. But we do plan to drill 10,000-foot laterals for the remainder of this year in the JV. The JV acreage lends itself to drilling some shorter laterals, but for the first several wells, we're going to target the extra long laterals.

[David Earl Beard:]

Great. Appreciate all the color, and thanks for the time.

[M. Jay Allison:]

You bet.

[Roland O. Burns:]

Thank you.

[Operator:]

Our next question is from Chris Stevens with KeyBanc. Your line is now open.

[Chris S. Stevens:]

Hey, good morning, guys. I was just hoping to maybe get a little bit more color on the JV and to just sort of what the vision is out there, how big that JV could get and are there any sort of plans to maybe increase your working interest on that acreage? And maybe, if you could just touch on how many rigs you could potentially get to out there?

[M. Jay Allison:]

Sure. Yeah. There are both us and our partner really want to continue to see the JV grow, and have set lofty goals for acreage acquisitions. I would see us being able to target getting to well over 10,000 acres by the end of this year. But possibly, the real goal is to get a substantial acreage position that would be 50,000, 60,000 acres that will take several years to get into or a (35

[Chris S. Stevens:]

Okay.

[M. Jay Allison:]

I think, again, I'd like to add on that is (36

[Chris S. Stevens:]

Absolutely. And maybe if you could just provide a little bit more on the sort of mix between running rigs on your JV acreage versus your existing sort of legacy acreage right now. And as you ramp two to four rigs by the end of this year and into next year and would that just be incremental to what you're doing on the operation – on your – relative to the legacy acreage you have out there or will this be still spending within cash flow and just maybe increasing the allocation of CapEx to the JV area?

[Roland O. Burns:]

Well, we'll look to next year to spending – within cash flow will be our target. So we'll look at the activity levels and then decide how many rigs to run on the company acreage based on kind of what we see for next year's cash flow, et cetera. So I think it's too early for us to really – we have put together the plan you had for next year. We'll have lots of opportunities to – lots of places to go and to drill wells. And so we'll fit the two together appropriately.

[M. Jay Allison:]

Yeah. And I think the denominator again is cash flow. What's our cash flow and then we'll allocate that for the wells that are being drilled.

[Chris S. Stevens:]

Okay, great. And then – and maybe just one more question here on the completion design, it looks like those 3,800 pound per foot tests are looking pretty solid so far. Any plans to test anything else? I know there's other operators out there testing some pretty big fracs? Any other ideas on additional tests for your completion design?

[Mack D. Good:]

Well, we like the 3,800 pounds per foot design and we see no reason to change while we accumulate the information that we'll need to decide if we do want to increase the proppant. We do think that the use of diverted (39

[Chris S. Stevens:]

Great. Thank you.

[Mack D. Good:]

Yes, sir.

[Operator:]

Our next question is from Jeffrey Campbell with Tuohy Brothers. Your line is now open.

[Jeffrey L. Campbell:]

Good morning, and congratulations on a strong quarter.

[M. Jay Allison:]

Thank you.

[Jeffrey L. Campbell:]

Slide 16 highlights 18% year-over-year per million cubic foot equivalent cost reductions. I'm just wondering will the remaining reduction in 2017 mainly be the result of the increased production that you're expecting or there is still some cash costs that can come down.

[Roland O. Burns:]

That's primarily going to be the production increases that drive – there's a lot of fixed costs in those numbers. And the Haynesville – new Haynesville production, the only really variable cost is the gathering cost. But the – a lot of the other cost is allocated to the wells. And so, that's – I think that's going to end up – we'll exceed that 18% comparison based on our volume growth.

[Jeffrey L. Campbell:]

Okay, great. Thank you. Just kind of sticking on costs, what was – and round numbers, what's the additional cost incurred with Gen 2 versus Gen 1?

[Mack D. Good:]

Well, that's variable depending upon the lateral length of the well. But basically, it's around 400,000 to 600,000, something like that.

[Jeffrey L. Campbell:]

Okay. What's the standard lateral length that you'd like to correlate that 400,000 to 600,000 to?

[Mack D. Good:]

7,500 footer.

[Jeffrey L. Campbell:]

Okay. Great. Thanks.

[Mack D. Good:]

Yeah.

[Jeffrey L. Campbell:]

And then finally, when you resume – you mentioned potential infill activity in the Eagle Ford when the oil price is where you wanted. I was just wondering, when you resume your D&C activity in the Eagle Ford, will you be completing the wells differently than you have in the past?

[Mack D. Good:]

Absolutely.

[Jeffrey L. Campbell:]

And could you give a little color on that? I'm assuming there's got to be some lessons from the Haynesville that are going to head over to the Eagle Ford when you start up...?

[Mack D. Good:]

Well, there is significant number of lessons available in the Eagle Ford as well that are required (42

[Jeffrey L. Campbell:]

Okay. Well, great, thanks for the color.

[M. Jay Allison:]

If you look at the operators and how they've completed their wells versus how we completed our wells years ago is like night and day difference, that's why their wells are so much better.

[Jeffrey L. Campbell:]

Well, that's – yeah, that's an interesting observation because we've certainly seen some oil window (43

[M. Jay Allison:]

Although we've got offset wells, we've (43

[Jeffrey L. Campbell:]

Okay, great. Well, that's great color. I appreciate it.

[Operator:]

We have a follow-up question from Ron Mills. Your line is now open.

[Ronald E. Mills:]

Just a clarification on the – on the 20 gross Haynesville wells this year, do you all have an expected split between the JV acreage and your legacy acreage?

[Roland O. Burns:]

Yes, Ron. I think there are four gross wells and really one net well kind of included in there for the JV in our total. The rest of them are the company acreage wells.

[Ronald E. Mills:]

Great. And then just a clarification on the cost. I know you'd been talking about $8.5 million well cost, Mack, for a 7,500-foot lateral. Is that – have you already factored in your 10% increase in those well economics you've presented in prior presentations?

[Mack D. Good:]

Yes.

[Ronald E. Mills:]

Great. That was all.

[Mack D. Good:]

Yeah. So, Ron, yes. We did factor that in.

[Ronald E. Mills:]

Okay. Great. That's all I had. Thank you.

[Operator:]

Thank you. And I'm showing no further questions. I would now like to turn the call back to Jay Allison for any further remarks.

[M. Jay Allison:]

All right. Again, everyone that's continued to listen, I mean, we cannot, as a management group, thank you enough for trusting us. And as I said at the very beginning of this call, in the future it's our corporate goal to give you the operational results that would result in the conversion of our second lien notes, which again we talk about liquidity and balance sheet, but that will significantly improve our balance sheet, so that's what we're working for and all of you know that. So, again, thank you for listening.

[Operator:]

Ladies and gentlemen, thank you for participating in today's conference. You may all disconnect. Everyone, have a great day