M. Jay Allison - Chairman & Chief Executive Officer Roland O. Burns - President and Chief Financial Officer Mack D. Good - Chief Operating Officer.

Ronald E. Mills - Johnson Rice & Co. LLC Kim Marie Pacanovsky - Imperial Capital LLC Brian Michael Corales - Scotia Howard Weil Phillips Johnston - Capital One Securities, Inc. Chris S. Stevens - KeyBanc Capital Markets, Inc. Daniel Guffey - Stifel, Nicolaus & Co., Inc. Michael Douglas Breard - Hodges Capital Management, Inc..

Good day, ladies and gentlemen, and welcome to the Comstock Resources Fourth Quarter 2015 Financial Results 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. As a reminder, this conference call is being recorded.

I would now like to turn the conference over to Jay Allison, CEO. Please begin..

one, be frugal in our spending; two, protect our balance sheet; three, keep a flexible budget, our Helmerich & Payne rig is contracted to drill three rigs at a $10,000 day rate lower than it was last year; four, to continue to reduce debt levels as we did the last nine months.

We recognized, as management, a company, as a board that our debt level is too high for our current cash flow levels at current commodity prices; and five, finally, maybe the most important point other than our leverage, continue to show stellar operational performance in the Haynesville and Bossier play.

Mack Good and his team had drilled and completed probably the best 10 wells in a row in our corporate history in the Haynesville/Bossier. They've reduced costs. They've proven that the play is repeatable and predictable.

We've added valuable drilling locations this year at no costs, and can deliver rate of return at 30% at $2.50 gas and 200% rate of return at $2 gas. And our last well drilled in 2015, it was completed in 2016, the Jordan No. 1 well, maybe the single best Bossier well ever drilled in the region. Mack has a comment on that later.

We had 350 Haynesville locations from 4,500-foot to 10,000-foot laterals. We had 286 Bossier locations from 4,500 foot to 10,000 foot laterals. That is quite an inventory starting from where we were this exact day last year, would know that is no extended lateral Haynesville or Bossier wells completed.

Plus, you'll see on slide 20, of our Haynesville staggered lateral well potential is viable which we think it is, we could potentially add another 83 extended Haynesville lateral locations.

Make note that about it, we're a natural gas company, focused on natural gas with a stellar oil position in the South Texas Eagle Ford, that is HBP, but not really drillable in the oil market that we all live in, versus our Haynesville/Bossier play, we have optionality that is very unusual in this current distressed E&P market.

With that, Roland, I will go over to you for financial results..

Thanks, Jay. On slide four, we show our increasing natural gas production. Our Haynesville shale drilling program is driving the growth we've had in natural gas this year. Our gas production increased 65% in the fourth quarter to 162 million cubic feet per day as compared to the fourth quarter of last year.

Gas production was also up 78% from our first quarter rate of 91 million per day. We expect our natural gas production in 2016 will average between 135 million cubic feet a day to 160 million cubic feet a day depending on the number of wells that we end up drilling in 2016. On slide five, we summarize our oil production.

Our oil production averaged 5,400 barrels per day in the fourth quarter, which was a 57% decrease from the fourth quarter of last year. The lower production level reflects the sale of the Burleson properties back in July 2015 and shutting down our oil drilling program in late December of 2014.

With little drilling activity planned for this year, we do expect our oil production to decline further. We expect oil production in 2016 will approximate between 4,200 barrels per day and 4,500 barrels per day. Slide six shows our hedge position.

We still have only 10 million Mbtu per day (08:03) of our natural gas production hedged this year at $3.20 per Mcf. And to the extent that there are better prices available later this year, we'd like to put in more hedges.

Slide seven shows our Haynesville shale basis differential, going into 2016 our all-in differential from the Henry Hub price is about $0.42, which includes $0.26 in transportation costs that are reflected in our lease operating expenses in our income statement.

Most of the other large Haynesville operators have substantial firm transportation obligations, some of which they don't have enough production to meet. Most of their overall differentials are well over a $1 per Mcf. On slide eight, we summarize our fourth quarter financial results.

We had a 65% increase in gas production, which was offset by a 57% decrease in oil production in the quarter. This combined with the 57% lower oil prices and 43% lower gas prices, caused our revenues, cash flow, and EBITDA to decline. Revenues this quarter were down 62% to $48 million, and EBITDAX was down to $27 million.

Lifting costs in the quarter were down 13% mainly due to lower production taxes and lower gathering costs. Our DD&A, or depreciation, depletion and amortization was also down 37% that was due to an improvement in our DD&A rate. Our DD&A rate in the quarter was $3.32 per Mcfe, which improved 44% from the fourth quarter 2014 rate of $5.97 per Mcfe.

In the quarter, our G&A costs were down 58% to just under $3 million. But also during the fourth quarter, we had a large impairment on our producing properties and our unevaluated acreage of $255 million. We also had a gain on the extinguishment of debt of $23 million.

Including these items, we had a $289 million loss or $6.25 per share in the fourth quarter. If we exclude these items, we had a net loss of $42 million or $0.91 per share. On slide nine, we summarize our annual 2015 financial results.

For the year, our oil production decreased by 28% and our gas production grew by 20% as compared to 2014, but this combined with 50% lower oil prices, and 44% lower gas prices, again caused our revenues, cash flow, and EBITDAX to be lower in 2015 than 2014.

Revenues in 2015 were down 55% to $254 million, EBITDAX was down to $150 million and cash flow declined to $36 million. Lifting costs in 2015 were down 8% with the lower sales level. And our DD&A was down 15% and our G&A cost decreased 27% to $24 million for the full year.

For the year, we had large impairments on our producing properties and unevaluated acreage caused by the decline in oil and gas prices. They totaled $872 million. And we also had a loss on the sale of properties of $112 million. We had an unrealized hedging gain of $1.4 million in the year.

And we also had a net gain on extinguishment of debt of $79 million. So, including all these items, we had a $1 billion loss or $22.71 per share. But excluding these items, we had a net loss of $189 million or $4.10 per share. On slide 10, we cover the capital spending that we had for 2015.

For the year, we spent $241.4 million on our 2015 drilling programs. $105.3 million was spent in the East Texas, North Louisiana region to drill nine Haynesville wells and one Bossier shale well. We also re-fracked two Haynesville wells.

We spent $119.6 million for our South Texas region; $77 million of this was spent on the properties that we sold in July, and the remaining $42.6 million was spent on our Eagleville properties, where we completed four wells that were drilled back in 2014, and we installed artificial lift on many of the wells in that field.

As shown on slide 11, we outline our proved reserve estimates at the end of 2015. We grew our proved reserves slightly from 620 Bcfe to 625 Bcfe, but the reserve growth this year, which mainly came from the Haynesville shale drilling program, was offset by price related downward revisions of 107 Bcfe.

The SEC prices that we used in the reserve report fell to $46.88 per barrel compared to $92.55 per barrel in 2014 for oil and $2.34 per Mcf compared to $3.96 per Mcf in 2014 for natural gas. In the year, we also divested of 27 Bcfe, which represents a sale of our East Texas Eagle Ford properties.

The reserve additions in 2015 came almost exclusively from our Haynesville program and they totaled 170 Bcfe. We also had upward revisions of 38 Bcfe, again coming from the strong well performance in the Haynesville.

The level of proved undeveloped reserves at December 31, 2015 that we could book was limited by our available capital to develop these reserves in the future. So, for that reason, we included only 35 Haynesville and Bossier shale proved undeveloped locations.

We have a total of 636 operated locations including 286 extended lateral locations; many of these would otherwise qualify as proved undeveloped locations in the reserve report. If you exclude the price related revisions we had this year, our Haynesville and Bossier shale drilling program achieved an all-in finding cost of $0.66 per Mcf.

You could obtain that by dividing the 161 Bcfe that was added by that program compared to the total cost incurred of $110.7 million. Slide 12 shows our capital expenditure budget for 2016.

Our drilling activity will again be focused on our Haynesville shale properties in Louisiana where the extended lateral wells have economic returns even in this low natural gas price environment. We plan to commence drilling sometime in March, utilizing the one drilling rig that we have under contract.

This one rig can drill about nine extended lateral wells for all of 2016. So our total capital expenditures in 2016 would be approximately $98 million, if we continue to drill throughout all of 2016. However, after drilling three wells, we may discontinue our drilling program depending on the current industry conditions.

So our capital could be as low as $46 million for just drilling the three wells plus other maintenance capital that we have for the year. We're currently working on a drilling joint venture in the Haynesville that could fund much of this capital budget this year.

We also may divest of some non-core natural gas properties and then use the proceeds to fund this drilling program. Slide 13 shows our balance sheet at the end of 2015. We had $134 million of cash on hand and $1.270 billion of total debt outstanding. Including our undrawn credit facility, our total liquidity is $184 million.

We retired $130 million in face amount of our bonds in 2015 for cash payments of $43 million and recognized gains of $83 million on these repurchases. In February of this year, we retired an additional $40 million of face amount of bonds by exchanging common stock for the bonds.

So pro forma for this debt for equity exchange, our total debt is $1.230 billion. We plan to continue to pursue strategies for retiring more of these bonds in 2016. The first maturities we have are not until 2019, so we still believe we have a long runway to survive the cycle.

I'll now hand it over to Mack for an update on the Haynesville drilling program..

Thanks, Roland, and good morning to everybody. I won't spend a lot of time talking about slide 14 that shows our acreage positions in the Haynesville and the Bossier other than to say that, during 2015, we drilled 10 horizontal wells last year in this area.

Each of those wells are currently projected to recover over 15 Bcf and the average IP rate of those wells is around 24 million cubic feet per day. Not too bad. And during 2016, we have up to nine wells teed up to drill and complete as conditions warrant to do the exact same thing.

As you can see in the next slide, slide 15, we believe that the results for 2015 drilling program confirmed that a Comstock Haynesville well completion targeting a horizontal length between 7,500 feet and 10,000 feet can deliver a rate of return between 30% to 51% at a gas price between $2.50 to $3.

It is a real plus that we have a sizable inventory of these extended 7,500 foot to 10,000 foot lateral horizontal wells for future development.

And our review of the way our acreage is laid out shows that we have at least 125 operated extended lateral Haynesville locations and 161 extended lateral Bossier locations with horizontal lateral lengths between 7,500 feet and 10,000 feet.

And we believe that our new Jordan wells current performance indicates that the Bossier potential could rival the economics we project for our extended lateral Haynesville wells, but we definitely want to get some more production history (19:46) to confirm that. Last but not least, all of this production potential is supported by a simple fact.

That fact is that our acreage is close to the Henry Hub, which obviously means, we don't have to suffer the long-haul transportation cost that others who are less well located might have to suffer.

Moving onto slide 16, we'll breakout some of the Haynesville metrics for you for our extended lateral wells, and I won't go over every number in the slide but I'd like to highlight a few points. First we believe that our D&C costs for those wells will be between $9.5 million for a 7,500 foot lateral and about $11.5 million for a 10,000 foot lateral.

We're confident that our IP rates for those wells will be over 20 million a day for the 7,500 footer and over 30 million a day for the 10,000 foot horizontal completion and the EURs would vary between 15 Bcf to 20 Bcf, respectively, 15 Bcf for the 7,500 footer, 20 Bcf plus for the 10,000 footer.

We're looking for ways to improve these results and several ideas are under consideration. But that discussion is for another day. Next on slide 17, you'll see a map showing the approximate locations and IP rates for our two re-frac wells, along with the 10 wells we've been talking about that we drilled and completed in 2015.

Just to summarize things a little, the first nine wells we drilled were Haynesville wells, while the last well was a Bossier test. The first eight of our Haynesville wells were drilled in the first three quarters of the year. They had an average lateral length of 7,290 feet and an average IP of about 24 million a day.

And all of these wells are at or above our type curve as Roland and Jay have both indicated and so I think you could say that they are doing better than we expected and we expect a lot. During the fourth quarter, we drilled two more wells, one was our ninth and final Haynesville well of the year and the 10th well was our Bossier test.

Our ninth well, the Caraway 20-29 targeted a shorter 5,950 foot lateral length completion, but it IP'ed extremely well at 24 million a day. This well, just like the others, is producing above the type curve. And our 10th and final well, the Jordan was our only Bossier test of the year as we have indicated.

Its completion targeted a 7,430 foot lateral length and it IP'ed at 22 million a day. I'll talk a little more about that Jordan Bossier well in just a minute. Anyway, after drilling the Jordan, we laid down our rig during late November of 2015 to finish the year's drilling program.

And just to mention this, we also highlight on the map that we have 3,637 net acres that we acquired earlier in the year in exchange for about 2,550 or so net acres in Atascosa County that increased our Haynesville and Bossier drilling inventory and it's in a great location.

Slide 18 is one most of you have seen before, if not all of you have seen before. It just shows the production information of our new wells plotted against our Haynesville type curve. The graph includes all nine of our 2015 Haynesville wells, along with our one Bossier well.

You can see that all nine of our Haynesville wells are producing above the type curve rates. So, what about the Jordan Bossier well? I know the graph is a little busy at the beginning of it, at the early production time, so it's difficult to isolate out the Jordan well production data.

But I can tell you this, we believe that based on its current performance that if it is not the best Bossier well in the play, it's definitely in the top three. The well has been producing for about 50 days and it is following a different production profile than our Haynesville wells follow, and keep in mind that I've said different, not worse.

It is currently producing flat at 14 million a day with very little pressure decline after 50 days of flowing to sales and even though the well is slightly below the Haynesville type curve at this point, it is producing on a flat line, very little decline.

And we expect it to cross the Haynesville type curve in about two weeks to three weeks and produce above the Haynesville type curve at that point. After we get additional information on the well, production history, et cetera, we'll build the Bossier type curve that will be supported by well performance and evaluate the well's EUR.

I'd just say, we like what we see so far and we like it a lot. Additional benefit that our new Haynesville completions are providing is shown in the next slide, on slide 19. We estimate that our new 2015 Haynesville wells improved the offset well production performance by a total of 10 million a day.

And as we've said before, we think this kind of impact is due to the new well fracture treatment, reopening and re-pressurizing an older offset well fracture network. We've been monitoring this impact since the beginning of our program and it's obviously an additional benefit to our overall Haynesville economics.

One easy way to look at this is that since the average benefit, 10 million a day divided by 10 wells gives 1 million a day for our Y15 (25:34) wells, you could simply add this 1 million a day to each well's production plot against the Haynesville type curve, and get a visual estimate of the offset well impact.

Slide 20 is our attempt to show you some of the additional potential that we believe exists across our position in the Haynesville using the staggered lateral concepts and I know most of you, again if not all of you, are probably familiar with it.

Basically this is a concept that's been successfully applied by some operators of the Eagle Ford and it is one that we believe applies to our future Haynesville development.

Since the Haynesville is about a 150 feet to 200 feet thick, mostly 200 feet thick, across our acreage position, we do not believe that this entire section is treated by an Upper Haynesville horizontal completion.

So by targeting the Lower Haynesville as a separate horizontal well target, we believe that we can capture additional reserves, similar if not equivalent to those we are currently capturing with our Upper Haynesville horizontal completions.

This approach has a potential to give us an additional 83 horizontal Haynesville locations with lateral lengths between 7,500 feet and 10,000 feet. So, it would increase our extended Haynesville drilling inventory by about 40% or so. So, obviously, we are planning to drill a staggered lateral well to prove this idea once market conditions improve.

So after covering all of that, I guess, I should send it back to Jay to sum up everything for you..

That's the slide 20 that I mentioned earlier. Before I have some closing comments, it's always nice again if you are so fortunate as to be the CEO to have great people that kind of do their job. I mean, Mack is a proven executive, he is COO. I mean, he's been here forever and ever, and ever. He was here when the first Haynesville well was ever drilled.

Roland, you don't need to talk about Roland. He has been here 26 years and all the financial levers we have, Roland controls them. I mean you don't get a better proven executive than Roland, so.

And the results, I mean when you are in an environment like we're in today, you expect the Rolands and the Macks of the world to give you the best results possible whatever that might be. And I think that that's what we have given you. We will go to slide 21 where I'll summarize our plans for the year.

The strong results from our proved Haynesville and Bossier shale wells provide us with growth opportunities in the current low natural gas price environment.

Our achieved results are demonstrating that our improved completion design has substantially improved the economic supply and we – I emphasize we, as a company, we have a vast resource with over 6 Tcf of reserve potential. We have mapped 286 operated extended lateral locations on our acreage.

We will continue to maintain a low cost structure, as we have one of the lowest overall cost structures in the industry and are working to lower our drilling and overhead cost wherever we can. We substantially reduced our overhead in 2015. And we elected to forgo bonuses that were earned in our incentive plan, we did that.

We will work on 2016 to improve our balance sheet, the bondholders and the equity owners because we own both. We will limit drilling activities as needed to conserve liquidity. We expect that the proceeds from the sale of certain of our non-core gas properties, which Roland mentioned, will help fund the drilling program this year.

And we also are working with several investors in the drilling venture, as Roland mentioned, that could fund drilling activity in 2016. We will continue to work hard to reduce our long-term debt with more repurchases and exchanges, as we have done in the last three quarters.

For the rest of the call, we'll take questions from only the research analysts who follow the company. Latoya, back to you..

Thank you. And the first question comes from Ron Mills of Johnson Rice. Your line is open..

Good morning. A quick question for Mack. If you look at the Bossier versus the Haynesville, I know, it's 50 days into that well.

But what were your expectations on the Bossier versus the Haynesville? Were you expecting similar results? Were you expecting EURs or IP rates to be 80% to 90% of Haynesville? Just trying to get a sense on that color and then as we get more data see how this well's performing versus what you may have thought?.

Ron, we anticipated that the Bossier would give us about 75% of our expectations that we had for the Haynesville. But the caveat here is that we had prior to the Jordan well not drilled a 7,500 foot Bossier horizontal well, nor had we tried to complete it with the new approach that had performed so well for us during 2015.

And as we completed the Jordan, we realized that we couldn't follow the same completion design as we had followed for the Haynesville wells, and we changed that design appropriately about two-thirds or so from the end of the completion. About one-third of the way into the completion we realized we had too high treating pressures.

We weren't hitting the completion efficiencies that we desired. So the bottom line is where I'm headed with this is, is that the initial performance that we've had the first 50 days down the Jordan exceeded our expectations considerably. The fact that it's producing with very little pressure draw down and very little decline was unexpected.

So I think it argues in favor of the fact that we got a tremendous completion on the well and we've got a very good Bossier test to evaluate going forward. I'm very hesitant to give out an EUR number for obvious reasons. It's a 50-day production interval that we're looking at.

So if I were to just extrapolate that flat line, it would obviously get an unreasonable result for an EUR. So we're going to give it two or three more months here before we generate an EUR, Ron..

Okay..

Ron, I did tell Mack that he disappointed me a little bit because this is a Jordan #1, I named it the Michael Jordan #1. I thought it'd be 23 MMcf a day well and it is only like 22 MMcf a day and change. So Mack fell a little short, Ron, I want you to know that..

I'm sure, Mack, appreciates that. And then, Mack, from a Bossier versus Haynesville, obviously, you drilled the Bossier down by the Parish line. That's where you had some of your better Bossier wells back when you were drilling in the play.

If you look at the distribution of the Bossier versus the Haynesville, do you think prospectivity up further north in DeSoto County or do you think each of the zones will be more localized in your two bigger acreage positions?.

Well, let me say, all the data that we have, Ron, indicates that the quality of the Bossier across our acreage position is very similar. There is no reason to believe at this point that we'd have a deterioration in quality as you move north.

Now obviously both with respect to the Haynesville and the Bossier, you can move too far north with respect to the Bossier and you can move too far south on the Haynesville as you well know, but right now all the mapping, all the data, the geological information we have, Ron, suggests that the key is the appropriate completion of an extra-long lateral in the Bossier.

It's not a deterioration of the Bossier quality that would cause (34:06) more the completion efficiency in a Bossier. So, a knock on wood, we got a great start on that..

And, Mack, I think, we've been involved in about 200 wells since 2008, is that right?.

Yes, but the vast majority were Haynesville..

Right..

So our restored confidence in the Bossier is really underpinned by the Jordan performance and the new completion and drilling frankly has a big, big contribution to this. It's a matter of getting a quality wellbore placed in the right spot and then completing that quality wellbore in the right away. So....

Yes, the beauty of the Bossier, as you know, you drill through Bossier when you drill to the Haynesville. So every Haynesville well we drill, we drill through the Bossier. So we've looked at this a little bit..

Anyway, Ron, hope that answers your question?.

No, for sure.

And then Roland, just can you expand a little bit on the comments from the last slide in terms of talk about potential asset sales, what are some of the likely candidates, maybe it's the conventional South Texas stuff or maybe you still have scattered acreage or additional debt-for-equity swaps and then you also talked about the potential venture.

Is that with industry partners? Is this with financial partners? And is anyone preferred or kind of any combination of all three? Are you agnostic between those?.

That's a lot of questions in one question..

Ron, that's a good question too.

Could you repeat it?.

Nope..

So basically, let's talk about the potential asset sales. We've identified certain properties that are non-core to the company. And I think what's core to the company is, obviously, the Haynesville and Bossier acreage. We think the Cotton Valley acreage is core also, even though we're not developing it right now.

And then our Eagle Ford and TMS acreage for future development. That's our core properties. So we have scattered properties that we don't see future development competing with our unconventional inventory.

And the most valuable of those properties is going to be the South Texas gas properties, very conventional deep gas and Wilcox and other plays down there. So that's definitely a property at fairly low decline, long property. So it's a kind of property that is easier to sell in this environment.

So for those properties, we're going to actively market and then potentially we have other scattered properties that also could be potential. But nothing that we consider core at all would we consider selling in this environment.

And then looking at the potential drilling joint venture, we're really talking with financial partners or financial investors more than industry partners as far as participating with us in a limited amount of our Haynesville program just for the couple – a year or so, while prices are low and capital scarce, because the returns are there to support it.

So, of course, gas prices, if they get weaker and weaker, that's maybe harder to do.

But given current kind of outlook for prices, there is interest there, there is return there and that's something we're considering that would be helpful to this year's program to kind of conserve and that could allow us to drill more wells versus the more minimum budget and help us conserve more cash..

Great. All right, thank you so much..

Thank you, Ron..

Thank you. The next question is from Kim Pacanovsky of Imperial Capital. Your line is open..

Hi, good morning, everyone..

Hi, Kim..

Hi. I have a question about hedging and I know and I've asked this in different ways before and I know you guys through your history and I've covered you for a long time, have been reticent to hedge.

And you're now getting returns of about you said 20% at $2 in the Haynesville and there have been multiple opportunities, I'd say, over the last six months, so layer in more hedges. And the best outcome you could have is that gas moves up $0.50 or so over the next year, and you capture that gain on your unhedged gas.

So I guess, my question is, how are you guys looking at the markets right now? When will you step in and put more hedges in and you give the equity investors some comfort on the returns?.

Well, Kim, we started putting in some hedges. I mean, the hedging this year – last year and this year has been like trying to catch a falling knife, and so it's been difficult for any of our targets to be met other than just some modest ones early on.

So to the extent that there is more stability and I think heading at the current prices don't help the company a lot in the overall picture, but to the extent that they get a little higher, and that's why it was the goal of ours to try to hedge the gas for this year, but not at the current price levels..

One thing we have done, Kim, if you look six months ago or so, it probably takes, and I have to go back and look at the numbers, but $3 gas will give you a 22% or 23% rate of return, now $2 gas we think can give you a 20% rate of return, $2.50 gas gives you a 30% rate of return.

So even though we hadn't (40:20) hedged, we've done something probably in the long-term more important and that is we've proven that the Haynesville and I think Bossier does work.

We've proven that it's repeatable, and like I said with Mack and the group we've reduced those costs so that even at a $2.00, $2.50 now, it's more likely that we could hedge. And I think another part of that question is you have to look at our total debt, it's about $1.1 billion net.

So, Kim, (40:50) we've reduced that debt so that even if we do hedge, it can support the entire company. That's how we looked at it because we have to say, well, will we drill three wells or nine wells, will we bring in a partner, will we have some asset sales, but we don't really know those things.

But we did start hedging a little last year, and we didn't think the market would fall off that quick and it did. But I want you to know we will hedge when we think that it's beneficial for the company, because, as you know, I mean even in this room you've got 3 million shares of stockholders. So we care about where the equity is..

Okay. And then looking at your two scenarios, I guess what was it, the three wells versus the nine wells.

What's your price point or your strip point where you kind of turn it off and say, okay, we're just going to lay the rig down and sit tight for a while?.

I think it's not a specific price. It's going to be a factor of all the – the situation of where the company sits in a couple of months. That's the way we've set it out. There is no long-term commitment. And so if we've entered into drilling joint venture, that could be a different answer.

So, yes, there is not a specific price we can give you on top of that..

Okay, yes. Fair enough..

But obviously if gas is below $1, we probably aren't going to be drilling anything. We'll probably shut it down that facility (42:21)..

I hope not. And then....

But we did want to have the locations built. As you know, it takes a long time to get the permits in some locations, and so that's why we say it's nine wells. I mean we drilled nine wells plus kind of a bonus well last year which is the Bossier, so....

We're not drilling in the month – in January and February, so this won't start until....

Yes..

So it's a shorter period there..

This will start in March..

Okay. And then just one question on the operational side.

How is the offset boost in production you've had when you frac your new long lateral wells, how is that holding up with the offset wells, the older wells?.

Extremely well. As we continue to add offsets through the ninth well, the tenth well, the Bossier, is solo, it doesn't have any offsets. But we've seen the same kind of profile over the last three quarters. So no surprises there whatsoever..

Okay, great. Thanks..

We present that on a slide there. You can see that and that's an up-to-date performance of the offset wells..

Okay..

Yeah. Slide 19, Kim..

Yes, thanks. Actually for some reason, I couldn't download the slides. But I'll try again. Thanks a lot, guys..

Sure..

Thank you, Kim..

Thank you. The next question is from Brian Corales of Howard Weil. Your line is open..

Hey, guys. And maybe more for Roland.

I mean, how does buying back your debt, are you all still able to do that one? And then I guess any kind of asset sales or kind of drilling carry could your CapEx budget be redirected to buying debt?.

Well, I think that, yes, we still can buy it and still that's part of our strategy is maybe to use a variety of resources we have at hand like we saw with the stock for debt exchange that we did. So, yes, that's going to be a big strategy. As far as the CapEx, again, I think that's why we have such a wide range on the CapEx. It's very flexible.

None of it is we're obligated to do. We could even not drill the three wells and pay a small fee on to release the rig. So lots of flexibility there. And then we recognize that the return in buying the bonds back is by far the highest return available in the company.

So it's just a way of using whatever resources we have to accomplish that and that is our major goal I think in this market. We've proven up. Last year our major goal was to prove up what we thought the Haynesville could be and I think we've done that and then we've done it in spades.

And that's provided opportunities for – without that there wouldn't be investors that would want to participate in that because of the performance we put on the board. But now the performance demonstrated, it's really do the economics justify drilling the well, do we want some level of production and then we kind of hold off.

So there are lots of options we have to try to get through in what looks like it's setting up to be a very, very difficult turbulent year for the sector..

And on those kind of drilling partnerships, is that something just to get through 2016 or is this going to be something on a bigger scale that could be you have a partner now longer-term, what's your thought?.

Our thought in approaching that has been that we wanted it fairly limited, because we – and I think that's the real goal. It's limited to a small part of our inventory..

Ron, I think the answer to that though is that, what we're seeing from a potential JV partner is that they like the quality of our assets. So if you wanted to be much bigger, you could, but again you've got go (46:46) company right now and that's our building inventory that's proven and predictable. So I think that's an option we will have..

But it's also to the extent that we can get that in place and that relationship in place, it will be a great vehicle if we have other opportunities like the exchange we did, any kind of other acreage opportunities and what we think is areas that will deliver similar results. I mean we'll have a vehicle to be able to capitalize on those opportunities.

That's been stuff that we've been working on also for the last eight months is getting partners in to help us take advantage of any acquisition opportunities in the plays where we're good operationally..

Thank you..

Thank you, Brian..

Thank you. The next question is from the Phillips Johnston of Capital One. Your line is now open..

Hey, guys. Thanks. Congrats on the Haynesville results. My question is on your reserve adds in the play.

What was the average EUR booking per well for the long laterals for both your PDP locations as well as the 35 PUD locations that you guys added?.

For our proved reserve bookings, I think we're probably averaging around, especially for the undrilled wells, around 12 Bcf, and then we have an additional probable reserves that takes us up to our full type curve.

So we're getting pretty comfortable to where we think a lot of that probable part of the type curve is going to move into proved, and hopefully, as these wells get to be a year old and more that we'll see that the 2016 end of the year is more at our full type curve or even better (48:44)..

Okay.

And then how about the 10 PDP wells that you booked, or eight or nine or 10 whatever it was, was that closer to 15 MMcf (48:52)?.

No. I think it's similar. They're going to be all different based on their exact performance. But I would say if you were to average them out, it would be something similar, maybe slightly higher than the PUDs....

Okay..

...just because they're drilled. But yes and I think we have – just like they were much more conservatively booked the year before, so we had a pretty large upward revision. So we would hope to be able to have a similar type of upward revision, and feel like the wells today are on that track with where they are producing above our total type curve..

Okay. Makes sense. And then just to follow up on Ron and Brian's questions about the potential JV.

Can you talk about what the preferred structure is that you guys might pursue? I mean, would it be more of a traditional upfront cash plus a drilling carrier or do you think it would look something more like what your existing joint venture with KKR is in the Eagle Ford?.

I think there are some options to structure it different ways, and if you kind of change one aspect of it, it changes another one.

And I think, that's really for us to – I know we're just in the process of working through all that to figure out what we think is the best structure, which could include cash up front, which obviously very helpful in this environment or wanting to have a bigger interest in the well later.

So, all that's really to be determined and so we're a little early on the process, but maybe by the next reporting day, we can have something really firmed up..

Yeah, and Phillip, I can tell you that who we're dealing with, I mean they're very quality long-term players that you'd be pleased if we would do business with. I think that's a key too..

Sounds good guys. Thanks..

Thank you..

Thank you. The next question is from Chris Stevens of KeyBanc. Your line is open..

Hey, morning guys. Just looking at the presentation, looks like most of your wells are outperforming the type curve at this point.

Any color you can provide on what your type curve assumes for first-year production? And then what these wells are actually tracking at this point over the first year?.

Well, each well, like Roland said earlier, is a little different although they are all the above the type curve. Our type curve starts off at about 22 million a day or so with a hyperbolic decline. As you can see, first year's production, I mean we're reaching 2 Bcf in the first year across the board on average, but that's an average.

So, to get more specific information about that, we'd have to dive into the details obviously, but that's kind of an average well (52:06)..

Okay.

And any idea on the incremental reserves you're adding at this point for some of the offset well impact of refrac?.

The short answer is no just because we've chosen to be real conservative just like Roland mentioned earlier about how we booked our reserves on our new wells. We wanted to firm up those EUR projections so we could add reserves later rather than have a downward correction.

So we've chosen not to assign an incremental benefit at this point just because the time that we think we need to look at this on a well-by-well basis..

Okay.

And just lastly, how much production is associated with some of the other non-core asset sales that you were discussing earlier in the conventional gas assets?.

Well, there's multiple answers to that depending on what area you're talking about – anywhere from one package might have 5 million a day or 3 million a day on a smaller level up to say 10 million a day to 13 million a day, depending on the – the way the property package is built and those are net numbers, so it varies..

So, I guess in aggregate, roughly 10 million to 15 million a day of production?.

Yeah. Something like that. And then – the overall metrics of each area changes, as you know – LOE and the operational complexity, et cetera, so..

All right. Thanks a lot..

Yeah..

Thank you. The next question is from Dan Guffey of Stifel. Your line is open..

Morning, guys. You mentioned completion differences, Bossier versus Haynesville. Wondering if you can talk about the differences and then if you saw any cost differences in the overall well..

Yeah. I had talked a little bit about it. The key to completing both the Haynesville and the Bossier is to get enough rates and profit placed per cluster. And the Haynesville is all slickwater on the fracs, the Bossier is not just because it's a different type of formation.

So, you have to gel up just a little bit on real light gel loading, so that's what we are saying, say 15 pound per gallon gel loading, something like that. The stages are smaller in the Bossier than in the Haynesville. The Haynesville is more brittle, it fractures much more easily.

So, in order to get the same rate per cluster in a proper place in the Bossier, the stages that you're treating have to get smaller. So that means more stages, more stages means more costs. And this was our first well, so a number of those things had to be learned as we went.

As I mentioned earlier in my presentation that we – when we first started the completion of the Jordan well, for example, we realized very quickly we were not going to be able to pump the fracture treatment with slickwater, we had to go to a gel system.

We also realized very quickly we had to target smaller intervals in order to get the kind of rate and profit placement we wanted and that was going to cause us to increase the number of stages by – from 30 to say 38 or so. So, plus we had some mechanical issues in the completion process. We had to change out a frac vendor.

That was an issue that cost us a little more money. So we think we can get the Bossier completed for about $10 million or so after we solve these other issues that we ran into. Obviously we learned a lot on the Jordan drilling and completion. So, the shorter answer is, yeah, there are some differences for sure.

And we think we've learned what those differences are. And we can improve on it from there..

Okay. Great. I guess on a third of that having kind of the inefficient frac is kind of how you're looking at it.

Do you think you could have higher productivity should – if the entire well would have been completed as the last two-thirds were and how much rate or performance do you think the well suffered because of the first third, that was completed with the slickwater?.

Well, I can't answer how much better it would have been if we hadn't run into these issues and et cetera, I know it would be better. The magnitude of the problem that was caused by the first several stages and its impact on overall well performance, I couldn't quantify that for you.

But in general, yeah, I think everybody on the team certainly believes that once – if we have fracked every stage as we fracked the last 25 stages or 30 stages in the well, we would have a better performing well, there's no question about that.

Now, the well right now is performing awfully well, it's a (57:46) performer for us, so we're really interested to continue to monitor the performance, pressure drawdown in the – the right amount of well over time.

Because right now, I'm not kidding you, the things are flat and we've seen very little drawdown on pressure and that is highly unusual for Bossier well, matter of fact, I haven't seen it, period. So....

Okay. Great..

So far so good..

On that drawdown and based on the pressure data, when do you guys expect the well to go into decline?.

We can't answer that. We've got a lot of analytical work that's being done, looking – calculating viable pressure drawdown versus surface pressure drawdown versus rate, rate transient analysis et cetera. We have not reached an outer boundary on the reservoir in 50 days, didn't expect to.

So, until we get to some sort of boundary condition where the pressure will start to decline, we can't answer any questions about when we'll start to see that.

So I guess that really, this being the first well, the first 7,500 footer, the first hi-tech completion design that we put on a Bossier well, we have the same questions that you do as far as when the well will start to see a decline, but 50 days, not seeing much of a decline whatsoever is pretty impressive..

Okay, thanks.

Switching gears to the Eagle Ford, I guess can you guys talk about the depth and quality of any remaining inventory? And then at what price would you guys be inclined to either, one, add a rig back; or two, look at it as a divestiture candidate?.

I think we had 105 or so locations at the end of last year. And then we had not infill drilled, we drilled on 80s. We'd never infill drilled a well. So I think that's still the case. Mack might want to add on that..

I think it's a little bit less as we sold some acreage (59:45). But I think we're in the 85 range for locations..

And we're also looking at the staggered lateral concept, as I mentioned earlier. So we have a number of drillable locations in Eagleville on the inventory.

And the quality varies depending upon what area we're talking about – if you're talking about an area to the West of our extreme west of our acreage holdings versus one that's in the core which we consider to be at McMullen County.

So that's kind of a long-winded answer to your question and maybe doesn't give you the kind of information you're looking for because I can't give you numbers on that right now as far as the number of locations we have in each of those different areas. But we have that in house and waiting on better oil prices obviously..

Okay. Great.

And then I guess lastly from me, can you guys discuss LOE and G&A trends? Obviously, you guys deferred any bonuses this year, but can you talk kind of how, one, on G&A throughout the year, what your expectations are for 2016 and then on LOE, as you become gassier, should we assume the LOE is going to continue to drop?.

No, I think that's – especially on a per-unit basis, the – obviously the production taxes and the gathering costs are very much variable costs, kind of going along with sales. The lifting cost number is relatively fixed and more volumes would drive it down to the gas side.

We're not adding a lot of fixed new costs when we put on a new Haynesville well. So, I would say – I would look at it more from that standpoint that a lot of that cost is fixed, the lifting cost is relatively fixed number. And as we increase the volumes, you'll see the rates go down other than for the transportation and the production taxes.

G&A, I think that I would say that that's going to track more quarterly – quarter would be more like $5 million a quarter, in that range for total G&A, including – some of that's stock-based G&A, more than this – this quarter was lower than a normal quarter because of the election to forgo bonuses..

Okay. Thanks for all the detail guys..

Thank you..

Thank you. And the next question is from Ron Mills of Johnson Rice. Your line is open..

Two quick ones. One, you mentioned TMS as one of the areas you wouldn't look to sell.

Can you talk about the acreage position there and in your requirements if any – I know you would – you were talking to landowners about extensions, renewals, what's an update there?.

Yeah. On the TMS acreage, we're obviously holding that for long-term oil price recoveries. And we only have one producing well, so there's not a lot of – there's – mostly it's acreage and most of the acreage is term.

Our core acreage, which is the – around the original Crosby wells and the wells – the one well we drilled, is the part that we consider the most core part. And we did extend that out where there's no drilling required or any kind of delay rentals required for the next two years.

So we would have to revisit it in really 2018 and decide what we want to do with it then. Some of the other acreage that makes up our total TMS block, there are various leases, some of those will expire over the course of several years.

But we would see that that'd be very inexpensive to renew or to re-lease right now, there's really not any activity to speak of in the play..

Okay. And then lastly, Mack, on the upper versus lower Haynesville, you talk about 200 feet of thickness and you don't think you're necessarily draining the full 200 feet.

What are some of the challenges or maybe not in terms of the way you've already laid out wells when you come back and if you drilled a staggered upper or lower Eagle Ford to go with the upper, any challenges with pressure depletion, et cetera, or as your well layout (1:04:38) protect you from some of that?.

We're fortunate in that our legacy Haynesville wells were landed in the upper part of the Haynesville section. And so that leaves the lower half to two-thirds of the Haynesville section open for the staggered lateral drilling opportunities.

And the depletion is – that's the basically the foundation of the ideas that you have no depletion in the lower from the upper completion because the frac doesn't extend into the lower section. So, you've not captured those reserves. You're only effectively completing the other fracture network, the upper section of the Haynesville.

So, that's the basic principle of the staggered lateral concept. So, we feel pretty good about that. If we drilled a 10,000 foot lateral, obviously we need a little more room to move with that upper landing area.

But the same thing applies to the staggered lateral concept, we still don't believe that there's significant depletion of the lower section by the upper section being completed..

Great. Thank you..

Hi, Ron, do you realized that it was eight years ago that you asked Mack the question on upper and lower, except it was upper and lower was – Mack came back and said, well, upper and lower is the Haynesville and then the Bossier.

I mean it was eight years ago that you asked about that, and now we've got an upper and lower Haynesville, but then we do have a Bossier. So that's kind of interesting..

What that means Ron is we're both getting older..

I was going to say I'm not sure what to (1:06:33)..

We're both getting older..

(1:06:35) Mack..

Yeah..

Thank you..

Yes, sir..

Thank you. And the last question is from Mike Breard of Hodges Capital. Your line is open..

Yes.

On the Bossier well, was that completed soon enough to have any impact at all on the year-end reserves?.

No, not really. I mean, there is – it's not a proved developed producing well because it was completed in January. And so it's not reflected – as part of those wells. And we really didn't – given our limited runway for adding undeveloped locations, we obviously chose to just put them in the more – the Haynesville is much easier.

So it really didn't have any, like you said, it didn't really have any impact on the reserves because that completed in 2016 and we only had a limited available slots for undeveloped wells under the SEC kind of rules.

But we do think prospectively, it did a whole lot to get us excited about the large Toledo Bend North acreage, and again, we want to monitor its performance, but it did a lot here to give us a lot of confidence in the Bossier locations..

So if you were enter into a joint venture and drill wells, would that be primarily Haynesville or could you include some Bossier on that and potentially show a pretty good reserve increase?.

I think that we would want to – yeah, we would definitely – we definitely want to drill some more wells in the Bossier for sure. And that'd be one advantage of doing a drilling joint venture will give us extra opportunities to test the 10,000 foot laterals to test – do more Bossier and to potentially even test the staggered laterals.

So I mean, that's one of the benefits it would give us the capital to move the rest of those (1:08:46) ideas, put evidence X results on the table that those are working. So that's....

Mike, that's one reason we upgraded the – Mack did the HP rig to be able to do that, to drill the 10,000 foot laterals..

And then also of course if you tell your vendors are going to drill nine wells instead of three wells, they might cut your prices a little more?.

Yeah. Certainly get them excited..

Okay..

And so – yeah. We will compete and progress that way, but again, I think we really to look at this year. it's going to be – it's a challenging year, we know that, the commodity prices have just been. We're kind of in the worst case scenario, worse than the worst case scenario that anybody had envisioned.

And it's going to be a stormy year, but I think we prepared the company as best we could last year for it and we're going to be proactive, as we always have been, in taking on problems and issues and to get to this year and to be better at the other end of the year, just like I think 2015 was a challenging year.

But in all that – all the adversity of what was going on, I think we accomplished a lot on the operational side and took our largest asset and showed that it had a lot more value than people thought it had by drilling these new completion style wells in the Haynesville and Bossier..

Okay. Thank you very much..

Thank you, Mike..

Thank you. And there are no further questions in queue at this time. I'll turn the call back over for closing remarks..

Okay. Thank you Latoya. Again, make no doubt about it. We will work hard every day collectively as a company to make the best decisions possible, as Ronald said, to get all of us through this oil and gas land mine year. What we do, we always give you our best. We'll always keep our integrity.

We'll always be transparent and always commit to you the stockholder and bondholder to deliver our best with the set of facts and the set of assets that we have, which is what you expect us to do. As a group and me personally, it's a privilege to serve you. So, again, thank you for your time this morning..

Thank you. Ladies and gentlemen, this concludes today's conference. You may now disconnect. Good day..