Comstock Resources Inc (CRK) 2015 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the Comstock Resources fourth-quarter 2015 financial results conference call. (Operator Instructions). As a reminder, this conference call is being recorded.

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

Thank you, Latoya, and I know it is a busy day for all of those that are participating on 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 entitled 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, and 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 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 of the presentation, and note that our discussion 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 by 44% in 2015. The 20% increase we had in our gas production was not enough to overcome those low prices of our oil and gas sales as they fell by 55% to $254 million.

EBITDAX came in at $150 million and cash flow from operations at $36 million. The positive results in 2015 continue to be the strong results we are achieving in our Haynesville program. Our ten 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 to 16 BCF type curve. Restarting our development program in 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 if not all banks that are difficult to comply with in the low commodity price environment that we are in, i.e., leverage ratios, covenants, etc.

In July when oil prices rebounded somewhat, we sold our Burleson County oil properties for $115 million. This then allowed us to repurchased $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 and 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 has continued to one, be frugal in our spending; two, protect our balance sheet; three, keep a flexible budget. Our Helmerich and Payne rig is contracted to drill three wells at a $10,000 a day rate lower than it was last year.

Four, to continue to reduce debt levels as we did the last nine months. We recognize as the management and the Company of the 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 have drilled and completed probably the best 10 wells in a row in our corporate history in the Haynesville Bossier. They have reduced costs, they have proven that the play is repeatable and predictable. We have added valuable drilling locations this year at no cost and could deliver a rate of return at 30% at $2.50 gas and 20% rate of return at $2 gas.

And our last well drilled in 2015 that was completed in 2016, the Jordan-1 well may be the single best Bossier well ever drilled in the region. Mack has a comment on that later. We have 350 Haynesville locations from 4500 foot to 10,000 foot laterals and we have 286 Bossier locations from 4500 foot to 10,000 foot laterals. That is quite an inventory starting from where we were this exact day last year with no -- that is no extended lateral Haynesville or Bossier wells completed. Plus you will see on slide 20 if our Haynesville staggered lateral well potential is viable which we think it is, we could potentially add another 83 extended Haynesville lateral locations.

Make no doubt about it, we are 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 have 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 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 production averaged 5400 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 in late December of 2014.

With little drilling activity planned for this year we do expect our oil to decline further. We expect oil production in 2016 will approximate between 4200 and 4500 barrels per day.

Slide six shows our hedge position. We still have only 10 million of our natural gas production hedged this year at $3.20 per MCF. At the extent that there are better prices available later this year, we would 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 them, their overall differentials are well over $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 EBITDAX 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% and 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 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 you 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. 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. 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 of 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 program. $105.3 million was spent in the East Texas, North Louisiana region to drill nine Haynesville wells and one Bossier Shale well. We also refracked 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 outlined our proved reserve estimates at the end of 2015. We grew our proved reserve 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 a reserve report fell to $46.88 per barrel compared to $92.55 in 2014 for oil and $2.34 per Mcf compared to $3.96 in 2014 for natural gas.

In the year, we also divested of 27 Bcfe which represented the sale of our East Texas Eagle Ford properties. The reserve additions in 2015 came almost exclusively from our Haynesville program. 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. 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 can obtain that by dividing be 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 are 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, $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 was, 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 will 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.

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 of our 2015 drilling program confirm that a Comstock Haynesville well completion targeting a horizontal length between 7500 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 7500 foot to 10,000 foot lateral horizontal wells for future development. And our review of the way the 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 7500 feet and 10,000 feet.

And we believe that our new Jordan well's 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 from the well 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 of others who are less well located might have to suffer.

Moving on to slide 16, we will break out some of the Haynesville metrics for you for our extended lateral wells. I won't go over every number in the slide but I would 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 7500 foot lateral and about $11.5 million for a 10,000 foot lateral. We are confident that our IP rates for those wells will be over 20 million a day for the 7500 and over 30 million a day for the 10,000 foot horizontal completion and the EURs would vary between 15 to 20 Bcf respectively, 15 for the 7500 footer, 20 Bcf plus for the 10,000 footer. We are 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 will see a map showing the approximate locations and IP rates for our two refracked wells along with the 10 wells we have 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 7280 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 Carraway 20-29 targeted a shorter 5950 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 7430 foot lateral length and it IP-ed at 22 million a day. I will 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 2015 to finish the year's drilling program. Just to mention this, we also highlight on the map that we have 3637 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 is 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 from each 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 is 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 is definitely in the top three. The well has been producing for about 50 days and it is following a different production profile that our Haynesville wells follow. And keep in mind that I 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 with very little decline and we expect it to cross the Haynesville type curve in about two to three weeks and produce above the Haynesville type curve at that point.

After we get additional information on the well production history, etc., we will build a Bossier type curve that will be supported by well performance and evaluate the wells EUR. Let's just say we like what we see so far and we like it a lot.

An 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 improve the offset well production performance by a total of 10 million a day. And as we have said before, we think this kind of impact is due to a new well fracture treatment reopening and re-pressurizing an older offset well fracture network. We have been monitoring this impact since the beginning of our program and it is obviously an additional benefit to our overall Haynesville economics.

One easy way to look at this is since the average benefit 10 million a day divided by 10 wells is 1 million a day for our 10 2015 wells. You could simply add this one 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 concept. And I know most of you again if not all of you are probably familiar with it. Basically this is a concept that has been successfully applied by some operators in the Eagle Ford and it is one that we believe applies to our future Haynesville development. Since the Haynesville is about 150 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 the potential to give us an additional 83 horizontal Haynesville locations with lateral lengths between 7500 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 is the slide 20 that I mentioned earlier. Before I have some closing comments, it is 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 as a COO. I mean he had 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 25, 26 years and all of the financial levers we have, Roland controls them. You don't get a better proven executive than Roland.

So and the results, when you are in an environment like we are 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 is what we have given you.

We will go to slide 21 where I will 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 economics of the play. 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 costs wherever we can.

We substantially reduced our overhead in 2015. And we elected -- we elected to forego 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 the last three quarters.

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

(Operator Instructions). Ron Mills, Johnson Rice.

Good morning. A quick question for Mack. If you look at the Bossier versus the Haynesville, I know it is 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 of that color? And then as we get more data see how this well is 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 7500 foot Bossier horizontal well nor had we tried to complete it with the new approach that 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 getting the kind of completion efficiencies that we desired.

So the bottom line is where I'm headed with this is that the initial performance that we have had the first 50 days or so in the Jordan exceeded our expectations considerably. The fact that it is producing with very little pressure drawdown 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 is a 50-day production interval that we are looking at so if I were to just extrapolate that flat line, it would get obviously get an unreasonable result for an EUR so we are going to give it two or three more months here before we generate an EUR on it.

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

I am sure Mack appreciates that. And then Mack, from a Bossier versus Haynesville, obviously you drilled the Bossier down by the Parish line, that is 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, all of 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 would have a deterioration in quality as you move north. 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 all know. But right now all of the mapping, all of 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 is not a deterioration of the Bossier quality that would cause (multiple speakers) more the completion efficiency in the Bossier. So knock on wood, we've got a great start on that.

And Mack, I think we have been involved in about 200 wells since 2008. Isn't that right?

Yes, but the vast majority were Haynesville. Our restored confidence in the Bossier is really underpinned by the Jordan performance and then the new completion and drilling frankly has a big, big contribution to this. It is a matter of getting a quality wellbore placed in the right spot and then completing that quality wellbore in the right way.

The beauty of the Bossier as you know is you drill through the Bossier when you drill to the Haynesville. So every Haynesville we have drilled we have drilled through the Bossier. So we have looked at this a little bit.

Anyway, Ron, I hope that answers your question.

For sure. And 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 is the conventional South Texas stuff or maybe you still have scattered acreage or additional debt for equity swaps? And then you also talk about a potential venture. Is that with industry partners, is this with financial partners and do you have, is any one preferred or in a combination of all three, are you agnostic between those?

That is a lot of questions in one question.

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

Nope.

So basically let's talk about the potential asset sales. We have identified certain properties that are non-core to the Company and I think what is core to the Company is obviously the Haynesville and Bossier acreage. We think the Cotton Valley acreage is core also even though we are not developing it right now. And then our Eagle Ford and TMS acreage all for future development. That is 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 is definitely a property at fairly low decline, long life property.

So it is the kind of property that is easier to sell in this environment. So those properties we are 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 or we would consider selling in this environment.

And then looking at the potential drilling joint venture, we are really talking with financial partners or financial investors more than industry partners as far as participating with us. And a limited amount of our Haynesville program just for a year or so while prices are low and capital scarce because the returns are there to support it. Of course, gas prices if they get weaker and weaker that may be harder to do but given the current kind of outlook prices, there is interest there, there is return there and that is something we are considering that would be helpful to this year's program to kind of conserve and that could allow was to drill more wells versus the more minimum budget and help us conserve more cash.

Great. All right. Thank you so much.

Kim Pacanovsky, Imperial Capital.

I have a question about hedging and I know and I have 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 are now getting returns of about -- you said 20% at $2 in the Haynesville and there have been multiple opportunities over the last six months to 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 give the equity investors some comfort on the returns?

We started putting in some hedges. I mean hedging this year, last year and this year has been like trying to catch a falling knife and so it has been difficult for any of our targets to be met other than just some modest ones early on. So to the extent there is more stability and I think hedging 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 is why it was a goal of ours to try to hedge the gas for this year but not at the current price levels.

One thing we have done if you look six months ago or so, it would probably take -- and I'd have to go back and look at the numbers -- $3 gas would give you a 22% or 23% rate of return. Now $2 gas we think can give you a 20% rate of return and $2.50 gas gives you a 30% rate of return. So even though we haven't hedge, we have done something probably in the long-term more important and that is we have proven that the Haynesville and I think Bossier does work, we have proven that it is repeatable. And like I said with Mack and the group, we have reduced those costs so that even at a $2, $2.50 now, it is more likely that we could hedge. And I think another part of that question is you have to look at our total debt, it is about $1.1 billion net. So can we reduce that debt so that even if we do hedge it can support the entire company?

I mean you've got to -- that is how we look at it because we have to say will we drill three wells or nine wells? Will we bring in a partner? Will we have some asset sales? 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 is beneficial to 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. Then looking at your two scenarios I guess what was it -- the three wells versus the nine? Where do you, what is 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 is not a specific price, it is going to be a factor of all the -- the situation of where the Company sits in a couple of months. That is the way we have set it up. There is a long-term commitments and so if we have entered into a 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 (multiple speakers).

Fair enough.

Obviously of gas is below $1, we probably aren't going to be drilling anything. We will probably shut it down then (multiple speakers).

I hope not.

Although we do want to have the locations built, as you know it takes a long time to get the permits on some locations. And so that is why we say it is nine wells. We drilled 9 plus kind of a bonus well last year which is the Bossier.

And we are not drilling in the month of January and February so this won't start until March. So it is a shorter period.

This will start in March.

Okay. And then just one question on the operational side. How is the offset boost in production you have 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 have seen the same kind of profile over the last three quarters so no surprises there whatsoever.

And, Kim, we present that on a slide there. You can see that and that is an up to date performance of the offset wells.

Slide 19, Kim.

Yes, thanks. For some reason I couldn't download the slides but I will try again. Thanks a lot, guys.

Brian Corales, Howard Weil.

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?

I think that we still can buy it and still that is 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 is going to be a big strategy.

As far as the CapEx, yes, I think that is why we have such a wide range on the CapEx. It is very flexible. None of it is we are obligated to do. We could even not drill the three wells and pay a small fee to release the rig, so lots of flexibility there. And we recognize that the return in buying the bonds back is by far the highest return available to the Company. So it is just a way of using whatever resources we have to accomplish that.

That is our major goal, I think, in this market. We have proven up -- last year our major goal was to prove up what we thought the Haynesville could be, and I think we have done that, and that we have done it in spades. And that has 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 is really economics. The economics justify drilling the well. People 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 what looks like is 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 is your thought?

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

Ron, I think the answer to that, though, is what we are seeing from a potential JV partner is that they like the quality of our assets. So if you wanted it to be much bigger, you could. But again, you've got to go towards the value of the Company right now, and it is our drilling inventory that is proven and predictable. So I think that is an option we will have.

But also to the extent 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 other kind of acreage opportunities in what we think is the areas that will deliver similar results. We will have a vehicle to be able to capitalize on those opportunities. That is something we have 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 are very good operationally.

Thank you.

Phillips Johnston, Capital One.

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 are probably averaging around -- especially for the undrilled wells around 12 Bcf. And then we have an additional probable reserve that takes us up to our full type curve. But we are 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 will see that the 2016 end of the year is more at our full type curve or even better.

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?

No, I think it is similar. They are going to be all different based on their exact performance. But I would say if you were to average the amount, it would be something similar, maybe slightly higher than the PUDs just because they are drilled.

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 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? Would it be more of a traditional upfront cash plus a drilling carry 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 is really for us -- I know we are just in the process of working through all of that to figure out what we think is the best structure which could include cash up front, which obviously would be very helpful in this environment or wanting to have a bigger interest in the well later. So all that is really to be determined and it is a little early on the process but maybe by the next reporting date, we can have something really firmed up.

Phillips, I can tell you who we are dealing with. I mean they are very quality long-term players that you would be pleased if we would do business with. I think that is a key too.

Sounds good, guys. Thanks.

Chris Stevens, KeyBanc.

Good morning, guys. Just looking at the presentation, it 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 above the type curve. And 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 are reaching 2 Bcf in the first year across the board on average. But that is an average so to get more specific information about that, we would have to dive into the details obviously but that is kind of an average look.

Okay. And any idea on the incremental reserves that you are adding at this point for some of the offset well impact, the free frac?

The short answer is no just because we have 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 have 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, the conventional gas assets?

Well it is multiple answers to that depending on what area you are talking about anywhere from one package might have 5 million a day or 3 million a day on a smaller level up to 10 million a day to 13 million a day depending on 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?

Something like that and the overall metrics of each area of change as you know, LOE and the operational complexity, etc.

All right. Thanks a lot.

Dan Guffey, Stifel.

Good morning, guys. You mentioned completion differences, Bossier versus Haynesville. I'm wondering if you can talk about the differences and then if you saw any cost differences in the overall well?

Yes, I can talk a little bit about it. The key to completing both the Haynesville and the Bossier is to get enough rate and proppant placed per cluster and the Haynesville is all slick water on the fracs; the Bossier is not just because it is a different type of formation. So you have to gel up just a little bit on real light gel loading so that is the first thing, say 15 pounds 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 and the proppant placed in the Bossier, the stages that you are treating have to get smaller so that means more stages, more stages means more cost. 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 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 slick water. We had to go to a gelled system. We also realized very quickly we had to target smaller interval in order to get the kind of rate and proppant placement we wanted and that was going to cause us to increase the number of stages from 30 to say 38 or 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 have learned a lot on the Jordan drilling and completion.

So the shorter answer is yes, there are some differences for sure and we think we have 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 are looking at it. Do you think you could have higher productivity should the entire well would have been completed as the last two-thirds were and how much rate or performance you think the well suffered because of the first third that was completed with the slick water?

Well, I can't answer how much better it would have been if we had run into these issues, etc. 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 in general, yes, I think everybody on the team certainly believes that if we had fracked every stage as we fracked the last 25 or 30 stages in the well, we would have a better performing well, there is no question about that.

Now the well right now is performing awfully well. It is a performer for us so we are really interested to continue to monitor the performance pressure draw down and the rate on the well over time because right now I'm not kidding you, the thing is flat and we have seen very little draw down on pressure and that is highly unusual for a Bossier well. As a matter of fact, I haven't seen it period.

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

We can't answer that. We have got a lot of analytical work that is being done, calculating bottom [hole] pressure draw down versus surface pressure draw down versus rate, transient analysis, etc. We have not reached an out of boundary on the reservoir at 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 will start to see that.

So I guess really this being the first well, the first 7500 footer, the first high-tech completion design that we put on a he 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? 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 had never infill drilled a well so I think that is still the case. Mack might want to add on that.

A little bit less because we sold some acreage in Atascosa County but I think we are in the 85 range for locations.

And we are also looking at the staggered lateral concept as I mentioned earlier so we have a number of drillable locations in Eagleville in the inventory and the quality varies depending upon what area we are talking about. If you are talking about an area to the west, extreme west of our acreage holdings versus one that is in the core which we consider to be in Mullen County. So that is kind of a long-winded answer to your question and maybe doesn't give you the kind of information you are 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, then I guess lastly for 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?

I think especially on a per unit basis, obviously the production taxes and the gathering costs are very much variable costs and kind of going along with sales. The lifting cost number is relatively fixed and more volumes will drive it down to the gas side. We are not adding a lot of fixed new costs when we put on a new Haynesville well.

So I would look at it more from that standpoint that a lot of that cost is fixed, the lifting cost is a relatively fixed number and if we increase the volume, you will see the rates go down other than for the transportation and the production taxes.

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

Thank you for the detail, guys.

Ron Mills, Johnson Rice.

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 where I know you were talking to landowners about extensions, renewals. What is an update there?

On the TMS acreage, we are obviously holding that for a long-term oil price recovery and we only have one producing well so there is not a lot of -- mostly it is acreage and most of the acreage is term. Our core acreage which is around the original Crosby wells and the one well we drilled, the part that we considered the most core part and we did extend that out where there is 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 wanted 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 they would be very inexpensive to renew or to release right now because there is really not any activity to speak of in the play.

Okay. Lastly, Mack, on the upper versus lower Haynesville, you talk about 200 feet of thickness and you don't think you are necessarily draining the full 200 feet. What are some of the challenges or maybe not in terms of the way you have already laid out wells when you come back and if you had drilled a staggered upper or lower Eagle Ford to go with the upper? Any challenges with pressure depletion, etc., or does your well layout protect you from some of that?

We are 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 depletion is -- that is the basically the foundation of the idea is that you have no depletion in the lower from the upper completion because the frac doesn't extend into the lower section.

So you have not captured those reserves, you are only effectively completing the other fracture network, the upper section of the Haynesville so that is 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 is significant depletion of the lower section by the upper section being completed.

Great, thank you.

Ron, do you realize 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 upper and lower is the Haynesville and then the Bossier. I mean it was eight years ago that you asked about that. Now we've got an upper and lower Haynesville but then we do have a Bossier so that is kind of interesting.

What that means, Ron, is we are both getting older.

I was going to say I am not sure what to take from that.

We are both getting older.

Mike Breard, Hodges Capital.

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

No not really. It is not a proved developed producing well because it was completed in January. And so it is not reflected as part of those wells and we really didn't -- given there are limited runway for adding undeveloped locations, we obviously chose to just put them in 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 completed in 2016 and we only had 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 our 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 to enter into a drilling venture and drilled wells, would they 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 -- yes, we would definitely want to drill some more wells in the Bossier for sure and that would be one advantage of the -- of doing a drilling joint venture would give us extra opportunities to test the 10,000 foot laterals, to test and do more Bossier and to potentially even test the staggered laterals. That is one of the benefits that would give us the capital to move the rest of those (technical difficulty) but evidence -- actual results on the table that those are working.

Mike, that is one reason we upgraded, Mack did, the H&P rig to be able to do that, to drill the 10,000 foot laterals.

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

It would certainly get them excited.

Okay.

We will continue to progress that way. But again I think we have really looked at this year, it is a challenging year, we know that, the commodity prices have just been -- we are kind of in the worst-case scenario, worse than the worst-case scenario that anybody envisioned. And it is going to be a stormy year but we think we have prepared the Company as best we could last year for it and we are going to be proactive as we always have been in taking on problems and issues and to get through 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 of that, all of the adversity of what was going on, I think we accomplished a lot on the operational side and took our largest asset and showed 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.

There are no further questions in queue at this time. I will turn the call back over for closing remarks.

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 Roland said to guide all of us through this oil and gas landmine year. We do what we do. We always give you our best, we will always keep our integrity, we will always be transparent and always commit to you the stock and bond owner, to deliver our best with the set of facts and the set of assets that we have which is what you would expect us to do. As a group and me personally, it is 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.