Comstock Resources, Inc.
Q4 2015 Earnings Call Transcript

Published: 24 Feb 2016

[Operator:]

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.

[M. Jay Allison:]

Again, thank you, Latoya. And I know it's a busy day for all those that are participating in the conference call. I want to thank you for choosing this conference call. Welcome to Comstock Resources fourth quarter 2015 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 will find a presentation titled fourth quarter 2015 results. I am Jay Allison, Chief Executive Officer of Comstock and with me to my right is Roland Burns, our President and Chief Financial Officer; to my left is Mack Good, our Chief Operating Officer. During this call, we will discuss our 2015 operating and financial results and our plan for 2016. As everyone on this call knows, this continues to be a very difficult environment with the continued weak oil and natural gas prices. But the good news is, and most of you know this, we continue to put up excellent results in our Haynesville shale program, as Mack will go over later in his presentation. If you go to slide two in the 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. 2015 summary. A summary of 2015 is outlined on slide three. Our realized oil price fell about 50% and our average realized natural gas price declined about 44% in 2015. The 20% increase we had in our gas production was not enough to overcome those low prices over oil and gas sales as they fell by 55% to $254 million. EBITDAX came in at a $150 million and cash flow from operations at $36 million. The positive results in 2015 continue to be the strong results we're achieving in our Haynesville program. Our 10 extended lateral wells in the Haynesville and Bossier shale that we drilled in 2015 were excellent with an average IP rate of 24 million per day per well. All wells are producing above our 14 Bcf to 16 Bcf type curve. Restarting our development program with the Haynesville has allowed us to increase our Haynesville gas production by 161% from our 2015 first quarter rate. We took several major steps in 2015 to improve our liquidity in this poor environment and we know we need to take more steps in 2016. In March, we completed a $700 million bond offering, which paid off our bank credit facility and added unquestionable liquidity to our balance sheet. It also removed covenant issues required by most, not all banks. They are difficult to comply with in the low commodity price environment they were in i.e. leverage ratios, covenants et cetera. In July, when oil prices rebounded somewhat, we sold our Burleson County oil properties for $115 million. This then allowed us to repurchase $130 million of our bonds for $43 million. We also retired another $40 million of our bonds in February. We have no debt maturities in 2019, and have total liquidity of $184 million. We have minimal obligations in 2016. It can adjust our drilling activities as needed this year based on what makes sense given current oil and natural gas prices. The actions taken within the last 12 months were all needed. Our focus in 2016 is continued to

[Roland O. Burns:]

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

[Mack D. Good:]

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

[M. Jay Allison:]

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.

[Operator:]

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

[Ronald E. Mills:]

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?

[Mack D. Good:]

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.

[Ronald E. Mills:]

Okay.

[M. Jay Allison:]

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.

[Ronald E. Mills:]

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?

[Mack D. Good:]

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

[M. Jay Allison:]

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

[Mack D. Good:]

Yes, but the vast majority were Haynesville.

[M. Jay Allison:]

Right.

[Mack D. Good:]

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...

[M. Jay Allison:]

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.

[Mack D. Good:]

Anyway, Ron, hope that answers your question?

[Ronald E. Mills:]

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?

[Roland O. Burns:]

That's a lot of questions in one question.

[M. Jay Allison:]

Ron, that's a good question too. Could you repeat it?

[Ronald E. Mills:]

Nope.

[Roland O. Burns:]

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.

[Ronald E. Mills:]

Great. All right, thank you so much.

[M. Jay Allison:]

Thank you, Ron.

[Operator:]

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

[Kim Marie Pacanovsky:]

Hi, good morning, everyone.

[M. Jay Allison:]

Hi, Kim.

[Kim Marie Pacanovsky:]

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?

[Roland O. Burns:]

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.

[M. Jay Allison:]

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

[Kim Marie Pacanovsky:]

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?

[Roland O. Burns:]

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.

[Kim Marie Pacanovsky:]

Okay, yes. Fair enough.

[Roland O. Burns:]

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

[Kim Marie Pacanovsky:]

I hope not. And then...

[M. Jay Allison:]

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...

[Roland O. Burns:]

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

[M. Jay Allison:]

Yes.

[Roland O. Burns:]

So it's a shorter period there.

[M. Jay Allison:]

This will start in March.

[Kim Marie Pacanovsky:]

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?

[Mack D. Good:]

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.

[Kim Marie Pacanovsky:]

Okay, great. Thanks.

[Roland O. Burns:]

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

[Kim Marie Pacanovsky:]

Okay.

[Mack D. Good:]

Yeah. Slide 19, Kim.

[Kim Marie Pacanovsky:]

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

[Mack D. Good:]

Sure.

[M. Jay Allison:]

Thank you, Kim.

[Operator:]

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

[Brian Michael Corales:]

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?

[Roland O. Burns:]

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.

[Brian Michael Corales:]

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?

[Roland O. Burns:]

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.

[M. Jay Allison:]

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

[Roland O. Burns:]

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.

[Brian Michael Corales:]

Thank you.

[M. Jay Allison:]

Thank you, Brian.

[Operator:]

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

[Phillips Johnston:]

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?

[Mack D. Good:]

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

[Phillips Johnston:]

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

[Roland O. Burns:]

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...

[Phillips Johnston:]

Okay.

[Roland O. Burns:]

...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.

[Phillips Johnston:]

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?

[Roland O. Burns:]

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.

[Roland O. Burns:]

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.

[Phillips Johnston:]

Sounds good guys. Thanks.

[Roland O. Burns:]

Thank you.

[Operator:]

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

[Chris S. Stevens:]

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?

[Mack D. Good:]

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

[Chris S. Stevens:]

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

[Mack D. Good:]

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.

[Chris S. Stevens:]

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?

[Mack D. Good:]

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.

[Chris S. Stevens:]

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

[Mack D. Good:]

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

[Chris S. Stevens:]

All right. Thanks a lot.

[Mack D. Good:]

Yeah.

[Operator:]

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

[Daniel Guffey:]

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.

[Mack D. Good:]

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.

[Daniel Guffey:]

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?

[Mack D. Good:]

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

[Daniel Guffey:]

Okay. Great.

[Mack D. Good:]

So far so good.

[Daniel Guffey:]

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

[Mack D. Good:]

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.

[Daniel Guffey:]

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?

[M. Jay Allison:]

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.

[Roland O. Burns:]

I think it's a little bit less as we sold some acreage (59

[Mack D. Good:]

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.

[Daniel Guffey:]

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?

[Roland O. Burns:]

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.

[Daniel Guffey:]

Okay. Thanks for all the detail guys.

[Roland O. Burns:]

Thank you.

[Operator:]

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

[Ronald E. Mills:]

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?

[Roland O. Burns:]

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.

[Ronald E. Mills:]

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

[Mack D. Good:]

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.

[Ronald E. Mills:]

Great. Thank you.

[M. Jay Allison:]

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.

[Mack D. Good:]

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

[Ronald E. Mills:]

I was going to say I'm not sure what to (1

[Mack D. Good:]

We're both getting older.

[Ronald E. Mills:]

(1

[M. Jay Allison:]

Yeah.

[Ronald E. Mills:]

Thank you.

[Mack D. Good:]

Yes, sir.

[Operator:]

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

[Michael Douglas Breard:]

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

[Roland O. Burns:]

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.

[Michael Douglas Breard:]

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?

[Roland O. Burns:]

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

[M. Jay Allison:]

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.

[Michael Douglas Breard:]

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?

[Roland O. Burns:]

Yeah. Certainly get them excited.

[Michael Douglas Breard:]

Okay.

[Roland O. Burns:]

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.

[Michael Douglas Breard:]

Okay. Thank you very much.

[M. Jay Allison:]

Thank you, Mike.

[Operator:]

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

[M. Jay Allison:]

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.

[Operator:]

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