Good day, ladies and gentlemen, and welcome to the Q3 2017 Comstock Resources, Inc. Earnings Conference Call. [Operator Instructions] As a reminder, this conference call is being recorded. I would now like to introduce your host for today's conference, Jay Allison, you may begin.

Thanks, Jiji. And I know this is a busy hour for earnings so call of – people who are attending thank you listening to us. Welcome to the Comstock Resources Third 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 results presentations. There you'll find a presentation titled Third Quarter 2017 Results. I am Jay Allison, Chief Executive Officer of Comstock. With me is Roland Burns, our President and Chief Financial Officer; and Dan Harrison, our Vice President of Operations is making his first conference call appearance today. Dan joined Comstock in 2008. He graduated in 1985 from LSU with Petroleum Engineering degree and has held positions at Sun Exploration, Oryx, Pioneer Natural Resources, [Pras] Energy, Cimarex Energy in various capacities including production engineer, drilling engineer and operations engineer. Our entire operations team has delivered stellar performance in our third quarter as Dan will discuss during his reports, so welcome Dan. During this call, we will discuss our third quarter operating and financial results as well as covering our outlook for 2018, if you go to Slide 2. 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 of such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. Our 2017 third quarter summary slide 3. A summary of our third quarter is outlined on Slide 3, where you can see we had a solid quarter driven by our successful Haynesville shale program. The recent fall in our thought process is not correlated to the company's operating performance and outlook for next…

Thanks Jay. Slide 5 shows the growth in our natural gas production being generated by our Haynesville shale drilling program. In the third quarter our natural gas production averaged 217 million per day up 51% from the third quarter of 2016 and up 14% from this year's second quarter if you exclude the production we divested in December of last year. In October we averaged 213 million a day and we expect to see the fourth quarter average in the neighborhood of 240 million per day and then with the drilling program in 2018 which is fairly similar to this year in cost we estimate that our 2018 natural gas production would average between 250 to 270 million per day. This is little higher than the press release guidance as those estimates were very conservative. It's always important to point out that our Haynesville operations are in an area with a substantial regional natural gas price advantage compared to the Northeast markets and we have not committed to onerous firm transportation and gathering arrangements like many of the other large things Haynesville producers. As shown on slide 6, our regional basis differential to Henry Hub is only around $0.12 for the last 12 months and while the transportation to Henry Hub from the Northeast which is about 1,200 miles away is averaged $0.94 for the same period. Gulf Coast industrial demand, exports to Mexico and LNG exports continue to grow in the Gulf Coast region. Our gathering and treating costs to get our gas to the major markets is around $0.22 given us high price realizations which are very important in this current lower gas price environment. Slide 7 shows our hedge position we put in place to lock in the high returns of the Haynesville Shale drilling program. We…

Thanks Ronald. I am excited that to take over for Mac and update you on what's going on with our Haynesville Shale operations. You can see on slide 16, is a good overview of the Haynesville Shale and Mid Bossier Shale play in the North Louisiana and East Texas. All 69,000 of our net acres in the Haynesville play is reflected in blue on this map. We operate the majority of our net acreage position and have an average working interest of 78.7% over the 88,000 gross acres we have an interest in. The average net revenue interest in our acreage is 80.5%. We are drilling 25 wells in our acreage this year and tentatively plan to drill a same number next year. As most of you know, the Haynesville Shale is undergoing resurgence in recent years as longer levels and larger stimulations must have led the much higher production rates and EURs. As a result, which also relayed that the Haynesville Shale wells have strong returns in today's $3 natural gas price. The location of the Haynesville near the Henry Hub combined with our competitive gathering and treating contracts gives is the premium natural gas market for Haynesville production. We recently finished remapping our acreage after the completion of acreage swaps of two offset operators as well as adding new acreage. We have been able to greatly increase our inventory of 10,000 foot laterals or two section laterals as we call them which now stands at 163 in the Haynesville and 183 in the Bossier. Our bread and butter liable of 75000 feet of section and half laterals stand at 97 in the Haynesville and 88 in the Bossier. And our single section inventory stands at 200 in the Haynesville and 118 in the Bossier. So this gives us…

Right, I will take it from here. Thank you, Dan. If you go to the outlook which is slide 24, let me refer you slide 24, I’ll cover the outlook for the reminder of the 2017 and 2018. Our high return Haynesville Shale assets are driving our strong growth this year as Roland has demonstrated and Dan has demonstrated. Our Haynesville completion has transformed the Haynesville Shale at one of North America's highest return natural gas price in our acreage position gives us over 800 featured drilling locations. We are expecting our natural gas production to grow by more than 40% driven by 26 well drilling program, a similar 26 well drilling program in 2018 will allow us to go natural gas production by at least 30%. The production increase will cause our EBITDAX and cash flow to continue to grow and it's important to note that we have already grown our cash flow to fully fund the drilling program. Our already low cost structure has continued to improve with new low cost Haynesville Shale production and to third quarter there we reported on today our lifting cost per Mcfe have decreased by 34%, our DD&A per Mcfe has improved by 35% as compared to 2016. Balance sheet and liquidity continue to improve as we grow our cash flow and EBITDAX the potential sale of our Eagle Ford shale assets combined with growth in EBITDAX should allow refinancing of our secured debt in early 2018 as Roland has mentioned. For the rest of the call we will take questions from the analyst to follow the company. So Jiji, I’ll turn it back to you.

[Operator Instruction] Our first question is from Michael Kelly from Seaport Global Securities. Your line is now open.

Hey guys, good morning. Jay, Ronald I am just a stupid equity guy here so you are going to have to maybe lay out the playbook how you proceed with this asset sale and debt refinance, I guess I’m curious really kind of what you think the company will look like post execution what in your mind is the critical steps to actually make this happen and then what concessions if any you think you’ve to give the bond holders to make this happen as well? Thank you.

Yes thanks. Yes I don't know that we can lay out the playbook. I don’t think that makes a lot of sense. But I think we think that with the additional cash generated by the divestiture of the assets there will have all the tools in hand to refinance all our bonds. And so, potentially we call all the bonds, save the shares that were designated by the shareholders for the conversion. So that's our goal. So I don't, there is certainly I mean certainly no concessions to be made to the bond holder. So I think they expect and they will get 100% repayment of their bonds and we think we – by growing the reserve base, the cash flow we will be able to refinance a lot of that debt and then use some of the cash to retire some of that debt. So that's the playbook.

Yes Mike, I want to come in on that that's a, if you look at the recap the company had in November of 2016 I mean the second lien bond holders made a concession to be converted into equity and if the stock is 12-32 then that will happen. If it doesn't which I think that's been the recent pull back in the stock because of this uncertainty if it doesn't what will happen. So what we got to do today and today is the first time we have been able to do this publicly is to say we have added more Haynesville acreage for our partner USG. We have increased our EBITDAX materially. We funded a program we think would grow production 30% to 40% next year for 2018. We have funded it already. And what we think will be our EBITDAX number and we should have some material reserve. So if you take that and then you look at a pity 2-3 dollar oil cost whatever it is today, you look at tier 1 oil asset, which is our South Texas Eagle Ford because we took that 18,000 -19,000 acres which has helped our production. We grew from zero oil to almost 13,000 barrels a day. We hadn't spent any money on it really since 2014. So it’s 2,200 barrels, 2,300 barrels per day but we set the infrastructure and to drill the remaining 300 locations. So I think our timing will be good to monetize that I think that will give us that extra chip that we need as our borrowing base is growing because it's growing materially and our goal is to go back to much less expensive money and a balance sheet it’s in the middle of a fairway and for everybody to be rewarded for what all they have done I mean whether you are first-lien owner or second-lien or an equity owner, I think we truly have protected everybody. And there is something that can happen because [indiscernible] as many shares or any shares we tend to buy out the second lien positions and that be even better for the equity owner let's just say we’re that much stronger as a company. So that's why we even gave a range of what we thought the Eagle Ford shale, we don't really know that's a target range, it's an indication range so the goal is that we will use that to refinance our balance sheet and I think it look wonderful and Dan has done really, really good job taking up the time for Mac and so also the whole team. So I hope that helps.

Yes that helps. Let me just pick a little bit more on that I mean what in broad strokes of course, I don’t want you to – the whole playbook here but in broad strokes where do you think this puts you if everything goes as planned maybe if we are looking at leverage metrics how do you think you come up the other side of this what's kind of the goal in your mind?. Thanks.

Well, obviously our goal is to get the total leverage down to under 3 times, but I think that as you could see from recent deals done in the market that their company is at much higher leverage issued new bonds, so but our goal is to get to that under 3 times and that's kind of a middle of the fairway type of balance sheet and we think that's achievable. The Shale Eagle Ford will be big step toward helping reduce the overall debt level of the company.

Our goal is not to kind of put a band-aid on our balance sheet either. I mean our goal really is to fix it and if the interest expense is killing us it's not all liquidity we have liquidity. It's not our inventory of location. We have increased our inventory. It's not the quality of our assets. It's not the profit margins we have. It's just a sheer amount of expensive debt we had to put on to dance of way through the worse stock we have had in the generation. So and I think we will continue to do that and like Ronald said if we get our leverage below three times I mean I think on the equity side which you are talking about I mean I think the stock class will explode in value and that's our goal because we own a lot of it.

Good stuff. That's great color and I would concur with whatever you just said. Just maybe one operational one from me, if I will look at the number of wells that you put out for next year, 26 gross if I just divide that by three rigs it's each rig line average an 8.6 wells annually I am not sure if that's the right way to look at it if there is the third rig that's being phased in later. How should we think about each rig lines capabilities now and the potential for that number to have some sort of fluctuation on the gross wells are? Thanks.

Yes, I will answer this correctly for Dan and -- but basically I think that the base budget there doesn't assume that one of those rigs get released before probably late third quarter of next year. So but generally, a lot of the wells are 10,000 foot laterals so they definitely take longer so it's a – they are going to take longer to drill. So I will let Dan kind of comment and we will phrase for those.

Yes. So really the majority of the locations we are going to be drilling next year too wells we have got a lot more the 10K lateral we are drilling next year. They do take longer you can’t get quite as many wells per year. We do have just one of the rigs is going to be running in our legacy area we are going to have two of the three rigs that will be running on our JV acreage. We will be participating in a lot lower working interest to keep our capital requirements so much lower but as Roland said we have got with the plan now maybe roll off one of the rigs towards the end of the next year.

One other thing Mike you asked and I think it's a key question. What is your playbook even though we can't tell you what it is totally I think today the market can see we have one. We are not going to tell you that we are going to attempt to sell Eagle Ford but until we put it in writing and have somebody to do it, maybe we don't. But today we are going to do that. Our goal is to have EBITDAX of $50 million well you didn't know that until this morning at 5:45 that we do that so our goal is to grow our JV acreage. You didn’t know we really brought it 7000 acreage to this morning. Our goal was to add some value in Texas in the Marion, Harrison County. I guess what we bought a new SG which has great muscles. There is a financial partner and we will drill Haynesville wells there. We want to drill more Bossier wells. So we go to the mineral owner and we know them since 1995 and they have got us fixed two or three and we are working deal so we drill Bossier wells too with the partner we promote the partners. So all these things are part of the playbook that are accretive and I think as it plays out month to month to month I think will get stronger and stronger and stronger and stronger and stronger. I do believe our worst days are in rear view mirror. So we will see what happens to commodity prices but from the operations financial side it couldn't be better than –

Great guys. Thanks for answering my questions.

Thanks Mike.

Thank you. And our next question is from Ronald Mills from Johnson Rice & Company. Your line is now open.

Hey good morning Jay. Question on maybe for Dan, but when I look at your Haynesville position it's gone up about a 1,000 acres I am assuming that maybe related to the JV acreage increasing yet the number of total Haynesville and Bossier locations went up by plus or minus 20%. What's driving the increase in the number of locations given a fairly similar amount of acreage and then also there is a big shift in terms of 56% of the Haynesville locations you’re now 7,500 foot to 10,000 versus 40 so it's a combination of what's driving the absolute level of inventory increase and then also is it acreage drops is driving the higher percentage of longer laterals?

Yes. We haven't really Ron refreshed that numbers since last year. So there is a lot of things have happened and we just finished the remapping but we did some pretty very productive trades with two operators in the Haynesville and that added new locations that before we didn't have enough acreage to have a location but it also definitely helped on the more longer laterals especially in the 10,000 foot area. The JV operations which doesn't show up a lot in the net acres that was added a lot of locations. They really – the number before really didn't include the JV. So I think it's and then I think a lot of work in Harrison County since we have done a ton of work locations so there expects before we didn't have any extended laterals in Harrison County. So yes, I think it's just a – it's really a one that number is very stale that has been out there since last probably almost a couple of years old number. So this reflects all the work that we have been doing to enhance the inventory across the board. So it's rigid snapshot today but obviously didn't happen just on the last month. It's the combination of everything including the new relationship with USG that has built up the inventory.

And well, I think it's driven by the importance of locations. When we started the first Haynesville well in February of 15, it didn't really matter how many locations we really had because we didn't have one extended lateral has completed well by the end of 15 you have got ten including Bossier by 16 you still don’t have much money. You drilled three wells and you drilled some more and then you get serious because you got a partner and any contiguous acreage you can have, you tried to have it and then you add like Roland said the Vast Marian and Texas so you end up with what we have now. A lot of trades happened last year. We saw Chesapeake and other sell out some of their acreage so the new acquiring operators were able to trade some acreage that they want, we want we have more locations and so -

And we didn't report those earlier because those hadn't closed yet. That takes a long time to complete acreage swap and these took almost a year and I think we are really waiting to get those trades completed before kind of remapping or representing the numbers and so all that kind of came together in the third quarter and so I think this is a great base and it will – we hope to continue to add locations as we continue to work our acreage positions.

Do you mind if I do these exercise a couple of times I know there have been some recent A&D transactions over there where Rockcliffe has amount of couple of assets. Can you talk about any recent activities of people drilled extended lateral wells with the newer completion techniques? What's driving the confidence to start including those locations?

Hey Ron this is Dan. So we got – we have had the history on we drilled approximately 7 Haynesville wells over in that area back several years ago in the first go around in Haynesville. We have got pretty good handle on, we kind of worked with multipliers are for the newer, larger stimulation, more intense stimulation jobs are. So when you go just look at those multipliers and go apply to some of the wells in those areas we feel like the economics are very favorable to drill in that area. We just have it been through into that area yet but there was another operator that has drilled some newer, they didn't drill longer laterals but they did drill a handful of shorter laterals and that had some very good results. So everything is basically based on that information.

And really what's changed for us Ron is that we have done extensive land work and add into that area to allow us to be able to drill longer laterals and so and traded acreage, moved acreage, lease new acreage, acreage does not drill-able and some of that is not even taken out of numbers so there I think before we just hadn't done all that work or had even had ability to drill the longer laterals and we think that's important to have the economics to be on par with other programs is to be able to drill the extended laterals and that's why we now have created the ability to drill the 34 so long laterals over there. That's the work in process. We really expect to be able to continue to add on acreage and do trades and make more of our acreage over there drill-able and the long units. So it's an area focus now and especially with in partnership with our JV partner we have the resources to put some capital in to getting new leases. I know these wells are going to get drilled.

What is interesting Ron you can go back where to probably 08 when we drilled the first Haynesville well and the first four wells we ever drilled back in 08-09, let's say one was Bossier kind of where we are drilling the Bossier today. Second one was in Waskom, Harrison County. Third was in Caddo and we ended up in [indiscernible] so kind of those four may not be an exact order but that's where we targeted growth back in 08-09. So that goes back and Dan joined us in 08 so that goes back to the history and I think that's one of the reasons we had USG as a partner because I said you got depth of history we need that. Well, that's a good thing because this is win-win for everybody.

And then on the updated well cost, you have increased more in line with what other guys have been talking about for 7500 and 8500 in 10,000 foot laterals. Is that inclusive of savings that would come from two well pads or in terms of the economics that you now provide are those still for single well pads?

So Ron that's a good average of kind of single wells and two well pads. We really haven't done too many two well pads to-date. They really have a good historical ground but most everything we are going to be doing going forward is going to on two well pads. So I think we have actually got the potential in there to probably show you few extra dollars off of what we have presented here.

Great. Thank you.

Thank you. And our next question comes from David Epstein from Cowen, your line is now open.

Hi folks. You guys said you don't want to give too much about the playbook of the refi and that's fine. I am not looking to price, but I just want to make sure I heard something correctly. Did you say that no part of that is changing like the conversion ratio on the second liens?

Yes that's correct. Obviously, the bonds are what they are and the authorizations are what they are. So the plan is I think with the sale proceeds to look at all the tools we have in hand and we think mostly likely and that’s the stock really causes conversions those bonds probably will be called diversified, converted. That's a good possibility.

Okay and on Grantham, I think you guys said higher water production and limited capacity limited the IP to 20 million cubic feet a day. Is that strictly in IP? How much does it hit like your – will it catch up overtime it will the EURs look any closure to sort of your type curve?

Yes. So this is Dan. I think time will tell, we don’t have that well in production for probably couple of months now and two and half months. And typically the wells, all of these wells with the newer larger frac jobs we do flow back a lot of water obviously in the early timeframe and so when we go to these longer laterals we had to flow them little bit longer just even basically every well form longer to achieve an IP. This well is an area where we did have just a little bit higher average water production and with the larger frac job that we put on it we got a lot larger water rate down initially and it just restricted being able to get an IP in that early timeframe and of course as it keeps flowing the well you lose a little bit of flowing pressure. It kind of diminishes being able to get the normal IP that you normally would. We are definitely limited with being able to get rid of the water off the location that was also a fact we just can't find enough trucks to basically to dispose of it. So we had to cut right back little bit.

Okay. Thank you.

Thank you. [Operator Instruction] And our next question comes from Joshua Gale from Nomura Securities. Your line is now open.

Hey guys thanks for sliding me in the queue. I appreciate all that color on the location count it’s immensely helpful. I just had a question about the wells, if I take the net well count and the CapEx budget for 2018 and implying about 10.5 million on average but I know that two-thirds of the rig activities is going to be focusing areas where there is a lot of 10,000 foot laterals. So the well cost in slide 23 is that maybe a conservative estimate by drilling two well pads and completing in batches of two or four there is potentially some savings baked into that operating plan for 2018?

This is Dan. So there is, the prices that we have here the cost are really kind of -- really some single well pads and two well pads. With exclusive basically for the remainder of this year and into next year with most being all two wells pad there is some potential there to probably save off a little bit of cost from what the numbers are here. But I’ll also caution that we it also depends on what our service cost are going to be next year. We think we have kind of gotten past most of the really rapid increase in cost we had this year and hopefully this year and the next year we are looking at something a little bit kind of level from here going forward just talking to our service providers, we are expecting the cost to kind of level out where we are at.

Alright, thanks. And then just if I could slide in one more, the commentary in the press release about funding with operating cash flow I know you have a plan to do something in March of next year with the first lien notes but is that like a status quo assumption and does that basically take into account the interest that you pay on the first lien notes for the year?

Yes that's a status quo type of assumption. We are not assuming a different capital structure for this basic drilling program that we are putting in. I think post refinance if we have a lot lower interest cost that we could, we probably would have a larger capital program, drive more growth. But that's a status quo assumption that the capital structure stays the same and we always budget to pay the first lane interest in cash. So that's also comes out of the cash flow also.

Right. So I know you didn't formally guide but if I take 70 million of cash interest and $170 million budget subject to gas prices that implies $240 million in EBITDA is that fair?

That is pretty fair.

Great, thanks a lot.

Thank you. At this time I am showing no further questions. I will now like to turn the call back over to Jay Allison, CEO for closing remarks.

All right Jiji, going back to Mike Kelly who is from Houston, which is home of the Astros and his word playbook, I would tell you that Astros won the world series of baseball last night. When they did that they gave us the playbook so let's just hope we can implement the playbook we have that have given us as well as they do. If we do they will do what they did which is be really successful. That's it. Thank you Jiji.

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