Good day, ladies and gentlemen, and welcome to the Third Quarter 2016 Comstock Resources, Inc. Earnings Conference Call. At this time, all participants are in listen-only mode. Later, we will conduct a question-and-answer session and instructions will be given at that time. As a reminder, today's program is being recorded. I would now like to introduce your host for today's program, Jay Allison, CEO. Please go ahead, sir.

All right. Thank you, Jonathan. I like your tone. Welcome to the Comstock Resources third quarter 2016 financial and operating results conference call. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and downloading the quarterly results presentation. There, you'll find a presentation titled Third Quarter 2016 Results. I'm Jay Allison, Chief Executive Officer of Comstock. And 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 third quarter operating and financial results, and also the successful debt exchange we just completed in September. 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 can be no assurance that such expectations will prove to be correct. 2016 third quarter highlights. Some of the highlights of our third quarter are summarized on slide 3. On September 6, we completed the debt exchange transaction we launched on August 1. 98% of our bondholders participated in this par-for-par exchange. The primary impact of the exchange was to free up our operating cash to invest in our very successful high-return Haynesville shale drilling program. This will allow us to grow our natural gas production, revenues and cash flow in a substantial way in 2017. The exchange reduced our annual cash interest burden by $37 million and allows us to pay an additional $75 million in kind at any time. The future conversion of the new second lien notes will de-lever the balance sheet and open the door to refinancing our remaining debt at lower rates. At a special meeting of our stockholders that we…

Thanks, Jay. Slide 5 shows our natural gas production. And despite having limited capital available for drilling this year, we are expecting to grow our natural gas production by anywhere from 10% to 15% over 2015. We did put a rig to work in March of this year, and we drilled three 7,500-foot horizontal lateral wells, but we released that rig in July in order to conserve our liquidity. With the completion of the debt exchange, we're starting drilling again, and in late September, put a rig to work, and then we added a second rig late last week. For this quarter, our gas production averaged 153 million cubic feet per day, which was 4% higher than the third quarter of last year. 10 million cubic feet per day of our third quarter production is related to our South Texas gas properties that we are selling. With the drilling program we announced today, we expect our natural gas production in 2017 will average between 200 million to 230 million cubic feet per day after taking account the divestiture of the South Texas property. Slide 6 shows our hedge position. We have 35 million per day hedged for next year at $3.27 per Mcf. That's about a third of the positions we like to put in place for our 2017 drilling program. On slide 7 we summarize our oil production. Our oil production averaged 3,500 barrels per day in the third quarter, which was a 50% decrease from the third quarter of last year. That large decline is due to the sale of our Burleson properties in July of last year, and then also shutting down our oil drilling program at the end of 2014. With little drilling activity this year, our plan for next year, we expect oil production to…

Okay, Roland. Thanks. Well, I'll start off just like I usually do in these conference calls and talk a little bit about our Haynesville and Bossier acreage positions. You can see on slide 12 that we have 67,000 net acres, and they're more important than they've ever been to us. As usual, the map shows our acreage position in both plays and it's basically the same map that you've been shown before. The area highlighted in blue on the map is our acreage position, and we're looking to add some more blue to that map. We're looking at several different arrangements that will increase our position in both plays, but the details on that will have to wait. I can also tell you that after drilling 10 wells in 2015, three wells so far in the first few months of 2016, we've restarted our program in Haynesville. And currently, we're running two rigs and we're completing the one well. So that's the new news. What is old and new at the same time is something that's been on the map, slide 12, for a long time, but I don't think it's been given the significant attention that it deserves. That's something as our belief that the Haynesville and the Bossier acreage has 6 Tcf of resource potential. It's been on this map for several quarters, but now it carries a lot of additional support. That support comes from the fact that every well we have drilled since 2015 has had a greater than 20 million a day IP rate at an average recovery approaching 15.6 Bcf. But we think we can do better than that, so we've decided to make some improvements. And I'll tell you what I mean on the next slide. During our last conference call, we summarized…

If you return to slide 21, I think the two things that are important; one, in order to get to this slide, we had to firm up our balance sheet; we had to have a successful recap, which literally happened about an hour ago, and I give thanks to Roland and his group for doing that. So you firm up your balance sheet. And then the second thing you have to have, you have a core asset that you could focus on that's real. So, I thank Mack and his group for really, as he said, telling a really great story, which is result of what our talented group focusing on the Haynesville and Bossier. So, with a firm balance sheet and the focus on core assets – we'll go to slide 21. Let me refer you to slide 21 where I will cover our outlook for 2017. Our high return Haynesville shale assets will provide us the means to achieve strong growth in 2017. 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 us over 700 operated locations. Next year, we expect our natural gas production to grow by around 40%, driven by 22 well drilling program funded primarily with operating cash flow. In combination with an improving natural gas market, we hope our EBITDAX and cash flow are expected to increase significantly. Our already low-cost structure is expected to improve with our new low-cost Haynesville shale production. Our producing costs per Mcfe in 2017 are expected to decrease by $0.20 per Mcfe, which is 14% lower than this year. Our balance sheet and liquidity continue to improve. During the down cycle, we've retired $237 million of our senior notes generating annual interest savings of $21 million with total interest savings to maturity of $83 million. The recently completed debt exchange reduces our annual cash interest burden by $37 million and allows us to pay an additional $75 million in kind if we choose to. The future conversion of our second lien notes now possible with a successful shareholder vote earlier today will de-lever our balance sheet. For the rest of the call, I will now take questions only from analysts who follow the company. So, Jonathan, turn it over to you.

Certainly. Our first question comes from the line of Ron Mills from Johnson Rice. Your question please. Ronald E. Mills - Johnson Rice & Co. LLC: Good morning, Mack. On slides 17 and 18, can you walk through just some of the differences on those, the economics versus the PV? And are you assuming the same shape of the curve to drive a similar IRR, but a much higher PV for the 10,000-foot laterals?

Yes. Ron, what we've done is, we've assumed no change in the profile of the type curve, we just lowered the IP that we feel is representative of a given lateral length based on all our correlation work and the data that we've evaluated, which is several hundred wells. So, anyway, the bottom line is, the profile of the type curve remains the same. It basically follows the same shape, just that it starts off at a different IP rate. And if you look at the different gas price assumptions here that's a flat gas price for the life of the well applied to the type curve for that given lateral length. And one thing that I'd like to point out is, as you can see from the slide that compares the actual well performance to the type curve, almost all of our wells have been producing above that type curve. So, we think we're providing a fairly conservative forecast on the production for the different lateral lengths. As far as the 10,000-foot versus the 7,500-foot lateral length, we've assumed a pretty conservative ratio based on the data analysis that we've done, the ratio between the 10,000-foot IP rate and the 7,500-foot IP rate. So, we've lowered the expectation basically to parallel the economic results for the 7,500-footer although there's an expectation yet to be confirmed through actual well performance that the 10,000-footer will provide better economics than the 7,500-footer. Being able to take advantage over the acreage configuration that we have out there is really important to us. We certainly going to drill a number of 10,000-foot laterals during 2017 to confirm this concept. But anyway, in a nutshell, the assumptions that we built to provide the economics are fairly conservative in our opinion. Ronald E. Mills - Johnson Rice & Co. LLC: Okay. And then, am I correct in, all your wells so far have been 7,500 feet? So you alluded to my next question. If you look out at your wells next year, how do you envision the split being between the 7,500-foot and the 10,000-foot laterals?

We've got a variety of lateral lengths scheduled to be drilled, Ron. We've got five or six of our wells that are going to be targeting between 4,500-foot and 6,000-foot lateral lengths. We have about the same number between 6,000-foot and 8,000-foot. And then, of course, we have several wells that were scheduled to drill between 8,000-foot and 10,000-foot lateral lengths. One of the wells that we drilled of the 13 that we mentioned, had a lateral length of about 5,600-feet, and it's the Caraway well that's producing well above the type curve. And that type curve, by the way, is for a 7,500-foot lateral length. And here we have a shorter lateral length well producing above the 7,500-foot type curve at the 2,800 pound per foot proppant loading. So, again, it's a conservative approach providing production guidance not only to ourselves, but to you all as well. So, we're targeting the shorter lateral lengths with the increased proppant loading so we can assess the improvements that we certainly expect based on a comparison against the 7,500-foot type curve. Ronald E. Mills - Johnson Rice & Co. LLC: And then lastly, look at your inventory, you have a lot of 4,500-foot laterals. I know, within the past few months, had swapped some acreage. You talked about expanding your positioning. Can you provide a little bit more color in terms of whether they're additional exchanges or leasing or acquisitions? And are those designed to increase to shift some of those 4,500-foot laterals into the longer lateral categories? Thanks.

Ron, you've cited all of the options that we're looking at. And certainly, you have 4,500-foot lateral opportunities that will provide significant value, but other companies have those opportunities as well. I mean, (33:38) 100-foot lateral opportunities. If we can trade or make other arrangements, whereby we can trade one of our 4,500-foot lateral section opportunities for one of theirs and they can stack ours and we can stack theirs to another section and get a 10,000-footer or a 7,500-footer or stack three sections and now you're talking two 7,500-foot cross unit laterals, one North theoretically and one South. That's a win-win for both parties. So, yeah, we're looking at all the above that you cited. But certainly, the combination that I mentioned of trading section per section is appealing to a number of different groups that we've been talking to. We just have to work out the proper slots. Ronald E. Mills - Johnson Rice & Co. LLC: Great. Thank you.

Sure.

Thank you. Our next question comes from the line of Jeffrey Campbell from Tuohy Brothers. Your question, please.

Good afternoon. First question I wanted to ask was just, do you have a hedged nat gas price in mind that forms the floor for your 2017 program?

Well, we don't really want to discuss specific targets on our hedging strategy, but you see a third of the divisions in place now and we like to add, really add, triple that to get kind of the level of 60% or so of the production level. So, no.

Okay. And that's helpful. In a similar vein, do you have an operating cash flow overspend ceiling in mind for 2017?

Yeah. We would want that number to be very small. I mean, I think that, yeah, we're hoping to bring the CapEx and cash flow into alignment. If we don't, it'll just be because gas prices are lower than our forecast. And we haven't got as many hedge of that as we wanted, but we think that's going to be not a very large number maybe $10 million, $20 million. We really want to keep the level of liquidity that will end the year with kind of out in place. And we don't expect to use the pay-in-kind provision on the first lien notes we're expecting that to not use that and not incur that additional debt.

Okay. And then last question I want to ask, and I'm actually referring to your corporate presentation rather than the one for the quarter. It's, I believe, slide 14, where you give an illustration of the staggered lateral potential in the Haynesville. I was just wondering if you have a time in mind when you're going to begin to test that upper/lower stack concepts. And also if you could add some color on how this approach will increase your extended lateral locations?

I've got a quick answer for that. I'd like to test it toward the end of the year if we're hitting our production goals. So, we could certainly absorb that slight additional risk that would come with the testing that concept. We think it's highly probable that it would be successful, but I'd want to tailor that test schedule to make sure that we achieve our production goals that we set in front of us.

Okay. And can you just explain quickly how it adds extended lateral locations as opposed to drilling one zone in isolation, how putting them together increases lateral locations.

Well, if you just said – look at that illustration, you'll see that the space in between the wells are such that you can, using the staggered concept, you can add an additional two locations per section if you're talking about 4,500-foot laterals. If you're talking about 7,500-footers, you're talking the same addition. So, number of staggered laterals is what I'm talking about. So, the idea being that the well spacing can be narrowed by targeting the lower intervals in the staggered lateral versus where most of our current laterals are placed and that would be in the upper Haynesville.

So the net effect is that instead of putting six wells in, you can get in eight?

Yes, sir.

Okay. Great. Thank you. I appreciate it.

You bet.

Thank you. Our next question comes from the line of Sean Sneeden from Oppenheimer. Your question, please. Sean M. Sneeden - Oppenheimer & Co., Inc. (Broker): Hi. Thank you for taking the questions. Roland, maybe as a follow-up to one of your answers there, but on the 10s (38:47), can you maybe just discuss a little bit more about how we should think about or how you guys are thinking about your paying PIK versus cash as you go forward? What would you need to see in order to pick those bonds versus pay cash?

Well, we don't – we want to plan not to. So, I guess, it's there to kind of underpin the overall liquidity of the company, but that's not at all. We want to de-lever the balance sheet. So, we don't want to add back additional debt to repay. So, we're really planning and, as we said that all along, not to use that provision. So, right now, based on even where gas prices are now, we don't believe we'll need to. Sean M. Sneeden - Oppenheimer & Co., Inc. (Broker): Okay. That's helpful. I know you guys had highlighted the potential conversion of the second liens to help you expedite your deleveraging process. What's your ultimate goal or how are you guys thinking about de-leveraging the balance sheet? Any kind of targets you guys are thinking about it as you're putting out some 2017 guidance in that sense?

Yeah. It's really the path that we have and the roadmap we have to gain the balance sheet back in great shape is the – next step is the conversion of the second lien bonds. And I think when that happens, it puts our overall borrowing ability back to where we can potentially refinance our first lien bonds to something at a lower rate. So, I think step one is that we believe that step needs to happen first (40:38) conversion to happen and then it really opens the door to further improving the balance sheet in at least getting our debt down by much lower cost than it is now. Sean M. Sneeden - Oppenheimer & Co., Inc. (Broker): Okay. That's helpful. Thank you very much.

Thank you. Our next question comes from the line of David Epstein from Cowen. Your question please. David Epstein - Cowen & Co. LLC: Hi, guys. I wanted to get a sense of the additional cost of the added proppant and the new design. I know for, say, a 7,500-foot lateral that you guys are showing like $8.5 million. And I think in the past before you showed this new well design, you were showing costs anywhere from, I think like, $8.1 million to $8.5 million over time depending on the presentation. Maybe just get a sense of what the additional costs are. Maybe very little.

Yeah. The additional costs is between $200,000 to $500,000 depending on the lateral length. And that includes all of the different aspects of the completion, which would obviously include the proppant. What we've done, as most operators that have a volume of work, we've packaged that work to the various vendors so we could take advantage of volume discounting. So, the bottom line is, the additional proppant costs through the discounting of the volume work is negligible. Overall, we've looked at the additional cost of – obviously, with the 7,500-foot lateral, the older completion design, the one we used last year, we had about 30 frac stages over a 250-foot stage length into a 7,500-foot it gives you about 30 stages. Now we're talking about 50 stages that are smaller, 150-foot length, but they'll pump faster. So, the amount of time we're estimating, the additional time it will take to frac the new completion design is probably an additional two days or so if everything goes well, and normally, it does. So, hopefully that answers your question on cost. The bottom line there is volume discounting to keep your costs as low as possible obviously.

And then the slide that Mack presented on slide 17 and 18, he did make the comment that if the cost would increase from $200,000 to $500,000, so those costs have been added to the rate of return and the NPV slides on 17, 18. So they're already in there.

That's right.

So you'll know that. David Epstein - Cowen & Co. LLC: Okay. Great. And the $0.20 per Mcfe costs that you're talking about the next year. So that is full year 2017 versus full year 2016 as opposed to like exit to exit? And that is oil and gas, as far as the LOE improvement?

Right. That's full year to full year on an Mcfe basis, right. David Epstein - Cowen & Co. LLC: Okay.

Yeah. The total company cost structure. It will be predominantly just nat gas next year, obviously. David Epstein - Cowen & Co. LLC: Right. Thank you.

Thank you. Our next question comes from the line of Chris Stevens from KeyBanc. Your question, please.

Hey. Good afternoon, guys. Thanks for taking my question. I was just hoping that you can provide a quick update on the Bossier well you guys have been producing, and what the plans are to drill more Bossier wells in 2017.

Sure. The Jordan continues to produce at a production profile that is now above the type curve. If you go back to slide 15, it's that black line amidst of all the other colorful lines. That's the Jordan. We did have every intention of drilling some Bossier wells in the latter part of the year. And our current plan is to drill one 7,500-footer, and if everything is working as planned, we also have on the board a 10,000-foot lateral length Bossier well.

Okay. And I guess in general, is it accurate to say that the decline profile of the Bossier is flatter than that of the Haynesville?

It certainly appears to be the case so far. Production history matters. And right now, we're being very careful with forecasting the Bossier, the Jordan. But certainly, you can see that the Jordan is producing at a different profile than our Haynesville type curve. So, we're waiting for some additional production to build the Bossier type curves that we think is representative.

Okay. Got it. And then in regards to the 20% increase to your EUR that you assume for the 3,800 pound per foot completion design, what do you base that 20% increase on at this point?

Well, boy, that's a longer explanation. But in short, it is based on data then analysis from several hundreds of wells where we track for different lateral lengths, the amount of proppant that was pumped and then look at the EUR forecast for those wells. So, if you look at proppant loading per foot, proppant loading per cluster, proppant loading total over the length of the lateral lengths you can develop correlations that suggest certain EURs. And then if you look at our performance last year, the correlations worked quite well as we anticipated and that's represented by the type curve of 15.6 Bcf EUR for our Haynesville completions given the proppant loading in the 7,500-foot lateral length. So, we have confirmation here that correlations are valid. So, the basis is that then analysis, data analysis that I referred to earlier. And then the 7,500-footers and the shorter lateral length that I mentioned earlier in the Caraway more than confirmed, it verified that our correlations were quite good.

Okay. And have you guys varied the completion design among the wells you've completed since 2015 with different varying proppant concentrations or stage length?

Yes. And the average that I gave you, the 2,800 pounds per foot was the average for all wells, but we did have some variance between certain wells. And we also varied the completion style on the Bossier. The Bossier is completed differently from the Haynesville. And so, we're keeping that completion design somewhat under wraps for now, but that certainly is the difference between the Bossier and the Haynesville.

Okay. Got it. Thank you, guys.

Yes, sir.

Thank you.

Thank you. Our next question comes from the line of Mike Breard from Hodges Capital. Your question, please.

Yeah. Some of your new Haynesville wells have been on-stream now for a year, year-and-a-half. Is the production from the offsetting wells still holding up at a decent rate?

Yes, Mike. We're quite pleased by that. And it certainly has been a great benefit. We have not counted nor have we worked into the economics on any of our forecast. So, appreciate you bringing that up. We will have that same opportunity in 2017.

Okay. So the projected rate of returns you're showing are actually very, very conservative?

Yes, sir.

Okay. Good. Good.

They're based on the type curve at flat gas price and most of the wells, you can see on slide 15, are producing above that and as well we do not include any of the additional production gains from the offset wells.

But you're getting now, what, 10 million, 15 million a day from those offsets?

Right now, it's around 10 million a day. Yes, sir.

Okay. And that's with no extra cost?

No, sir.

Okay. Thanks.

It's freebie.

Thank you. Our next question comes from the line of Ray Deacon from Coker & Palmer. Your question please. Ray Deacon - Coker & Palmer, Inc.: Yeah. Hey. Mack, I was wondering if I could ask what your completion schedule looks like kind of in 4Q and 1Q like net wells and what kind of lateral lengths?

Well, we're drilling two now. We've got one that's going to start completion here in about five days or six days. We should be in completion mode on an additional three wells before the end of the year. Lateral length, the first well we drill is about an 8,000-foot lateral length. We have a couple of 4,500 footers that are being drilled. One is the 7,000 footer. So, we're going to be quite busy during the fourth quarter. That's for sure, Ray. Ray Deacon - Coker & Palmer, Inc.: That's great. So first quarter that'll look great. That's good. And I was wondering could you just talk about how your marketing and gathering work and kind of pipeline capacity. And I guess your cash costs slide that does not include transportation, right? Or it does? No, it does include the...

No, it does. It's all in. Some of that cost is reflected in the gas price differential. And then some of it's in our lifting cost and we call that in the line item gathering cost. It's an all-in cost from the wellhead to the market. Ray Deacon - Coker & Palmer, Inc.: Got it. Got it. Great. Thank you.

Thank you. And this does conclude the question-and-answer session of today's program. I'd like to hand the program back to Jay Allison for any further remarks.

All right, Jonathan. Thank you. As Mack kind of things going here, that then and the now, I'd like the now better than the then. And I look at the now and I just kind put some notes, we had no hedges, now we've got a third kind of our hedge goal completed. We didn't know what 2017 drilling program will look like, now you know what it looks like. Our goal is not to incur any additional dip, you know that we've taken greater steps toward firming up the 6-plus Tcf of reserves, 700-plus locations. You've heard from Mack, we've materially improved the economics on our Haynesville Bossier program. It's not by reading somebody else's press release. A couple of hours ago, we've really finalized our recap, it's complete. And a question was asked, the Bossier, the Jordan well it continues to look exemplary. And then I've got and Mike Breard asked this, and we do have some gas – when we complete these wells, we've got 13 million, 14 million , 15 million a day of "other gas" from as a result of just the wells we've been completing. So those are all good things. It's a tough market. We'll see what old man winter does for us and, I think, we're on the right path. It took a really great effort from Mack, Roland and the board and the shareholders, and again the bondholders, whether you're secured or unsecured, in order for us to have a day like today. And everyone at Comstock is thankful for each one of you. So, go out and vote. Jonathan, that's it.

Thank you. And thank you, ladies and gentlemen, for your participation in today's conference. This does conclude the program. You may now disconnect. Good day.