Comstock Resources Inc (CRK) 2016 Q3 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the third-quarter 2016 Comstock Resource (sic), Inc. earnings conference call. (Operator Instructions) As a reminder, today's program is being recorded.

I would now like to introduce your host for today's program, Jay Allison, CEO. Please go ahead, sir.

All right. Thank you, Jonathan. I like your tone. Welcome to the Comstock Resources third-quarter 2016 financial and operating results conference call. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and downloading the quarterly results presentation. There you'll find a presentation entitled third-quarter 2016 results.

I am Jay Allison, Chief Executive Officer of Comstock. With me is Roland Burns, our President and Chief Financial Officer, and Mack Good, our Chief Operating Officer. During this call, we will discuss our third-quarter operating and financial results and also the successful debt exchange we just completed in September.

Please refer to slide 2 in our presentation and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations of such statements to be reasonable, there can be no assurance if such expectations will prove to be correct.

2016 third-quarter highlights. Some of the highlights of our third quarter are summarized on slide 3. On September 6, we completed the debt exchange transaction we launched on August 1. 98% of our bond holders participated in this par-for-par exchange.

The primary impact of the exchange was to free up our operating cash to invest in our very successful high-return Haynesville Shale drilling program. This will allow us to grow our natural gas production revenues and cash flow in a substantial way in 2017.

The exchange reduced our annual cash interest burden by $37 million and allows us to pay an additional $75 million in kind at any time. The future conversion of the new second lien notes will delever the balance sheet and open the door to refinancing our remaining debt at lower rates.

At a special meeting of our stockholders that we just concluded moments ago, our stockholders approved the transaction allowing the future conversion of the second lien notes. The main reason we were successful with the debt exchange is the quality of our Haynesville/Bossier assets. All of the new wells continued to perform above the 14 to 16 BCF type curve, which Mack will go over in a moment. As Mack will cover in more detail, increased proppant loading in our next series of wells is expected to raise our EURs by 20% and IRRs by 28%.

Even after the exchange offer, we are very, very mindful of continuing to protect our liquidity and improve our balance sheet. We have current liquidity of $152 million, and the pending asset sale will add to that, as Roland will discuss in a moment. Most importantly, our 2017 drilling program will be primarily funded with operating cash flow and we are building our 2017 hedge position to protect that cash flow.

On slide 4, we detail the debt exchange and the terms of the new notes. In the exchange, we did not ask our bond holders to forgive our debt by giving us a discount. We did ask for some relief from the high-interest burden we had to give us adequate cash flow to invest in our proven high-return drilling program.

They agreed to our plan and have given the Company a path to rebuilding our cash flow and reserve base so we can service the debt and grow the value of the Company for all of our stakeholders. The new second lien notes are convertible into common stock at a ratio of 81.2 shares per $1,000. The conversion is mandatory when the share price reaches $12.32.

Now that the framework is in place, all that is left is for us to perform. We are highly confident in Mack and his team's ability to deliver great results and are very excited about the future.

Roland will now go over the financial results for the quarter.

Thanks, Jay. Slide 5 shows our natural gas production. And despite having limited capital available for drilling this year, we are expecting to grow our natural gas production by anywhere from 10% to 15% over 2015.

We did put a rig to work in March of this year, and we drilled 3 7,500 foot horizontal lateral wells. But we released that rig in July in order to conserve our liquidity. With the completion of the debt exchange, we are starting drilling again. And in late September put a rig to work, and then we added a second rig late last week.

For this quarter, our gas production averaged 153 million cubic feet per day, which was 4% higher than the third quarter of last year. 10 million cubic feet per day of our third-quarter production is related to our South Texas gas properties that we are selling.

With the drilling program we announced today, we expect our natural gas production in 2017 will average between 200 to 230 million cubic feet per day after taking into account the divestiture of the South Texas properties.

Slides 6 shows our hedge position. We have 35 million cubic feet per day hedged for next year at $3.27 per MCF. That's about a third of the position we would like to put in place for our 2017 drilling program.

On slide 7, we summarize our oil production. Our oil production averaged 3,500 barrels per day in the third quarter, which was a 50% decrease from the third quarter of last year. That large decline is due to the sale of our Burleson properties in July of last year and then also shutting down our oil drilling program at the end of 2014.

With little drilling activity this year or planned for next year, we expect oil production to decline further. And in 2017, we think our oil production will average between 2,200 and 2,800 barrels per day.

On slide 8, we summarize our third-quarter financial results. We had a 4% increase in gas production, which was offset by that 50% decrease in oil production in the quarter. On an equivalent basis, production was down 7%.

We also saw oil prices were 4% lower, and then natural gas prices were actually improved by 4%. But overall, oil and gas sales in the quarter were down 18% to $50 million, and our EBITDAX came in at $30 million.

We continue to see significant improvement on the cost side. Lifting costs in the quarter were down 22%, with lower production taxes and lower gathering costs. Our G&A costs were down 26% in the quarter, and our DD&A was down 53% due to improvement in our amortization rate. The amortization rate in the quarter was $2.33 per Mcfe, which improved from the 2015 third-quarter rate of $4.58.

We did report a loss of $28.5 million today on the quarter, which was $2.32 a share, but there were lots of noise in the quarter. We had some unusual items, including a $76.5 million impairment of our Tuscaloosa Marine shale acreage, which we have decided to totally write off in this quarter.

As we have seen oil prices continue to linger at these low levels, we just do not see the Company being able to drill on this acreage. And the Company doesn't have real plans to try to maintain this acreage position by spending more capital on it.

So the decision was made to go ahead and write this off, although we will continue to own these leases. And if there was a miraculous turnaround in oil, we could get some value out of them. We also had a loss on the pending property sale of $13.2 million in the quarter.

These unusual items were offset by a gain on the extinguishment of debt of $100.5 million. That related to the exchange offer. If you exclude these items and other nonrecurring items, we would've had a net loss of about $40.1 million or $3.27 per share.

On slide 9, we summarize the financial results for the first 9 months of this year. For that period, we have seen gas production increase by 26%, while oil production decreased by 58%. Production on an equivalent unit basis was down just 1%.

But both oil and gas prices were significantly lower than 2015. The oil prices fell by 25% and gas prices were 12% lower. So that resulted in our oil and gas sales being down 37% to $129 million. EBITDAX was down to $64 million, but on the positive side, our costs were also lower. Our lifting costs in the quarter for the 9 months were down 20%, G&A costs were down 26%, and the DD&A was down 57%.

For the first nine months of 2016, we also had the unusual items, including an impairment -- the impairment of mainly the Tuscaloosa Marine Shale acreage of $108.8 million, the loss on the property sale of $14.1 million, and then a total gain from debt extinguishment of $190.1 million. So if you include all these items, we reported a $80.2 million loss or $7.13 per share. If you exclude these items and other nonrecurring items, it would've been a larger net loss of $142.3 million or $12.65 per share.

Looking at slide 10, we announced our capital expenditure budget for the last quarter of this year and for next year. And you can see we outline all the detail on the slide.

Under the current drilling program that we have proposed, we expect to drill 5 additional wells or 3.7 net wells in the fourth quarter and then 21 horizontal Haynesville/Bossier wells or 17.1 net wells in 2017. And we drilled 3 or 2.8 net wells earlier this year. Two of the Haynesville wells that are planned for the fourth quarter will be non-operated.

The capital expenditures for this drilling program are currently estimated to be $20.9 million in the fourth quarter, which would bring our total spending to $57.5 million for this year. For 2017, the drilling program will cost $142.9 million, which we believe will primarily be funded with our operating cash flow.

Slide 11 shows our balance sheet at the end of the third quarter. And after the completion of the debt exchange, we had $27 million of cash on hand and a $1.163 billion of total debt outstanding based on its face amount.

Including our undrawn credit facility and available pay-in-kind interest of our first lien bonds, our total liquidity to work with is $152 million. But after the pending divestiture closes, our liquidity will improve to $179 million.

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

Okay. Roland. Thanks. Well, I will start off just like I usually do in these conference calls and talk a little bit about our Haynesville and Bossier acreage positions. You can see on slide 12 that we have 67,000 net acres, and they are more important than they have ever been to us.

As usual, the map shows our acreage position in both plays, and that's basically the same map that you have been shown before. The area highlighted in blue on the map is our acreage position and we're looking to add some more blue to that map. We are looking at several different arrangements that will increase our position in both plays, but the details on that will have to wait.

I can also tell you that after drilling 10 wells in 2015 and 3 wells so far in the first 9 months of -- or the first few months of 2016, we have restarted our drilling program in the Haynesville. Currently, we are running two rigs and we are completing one well.

So that's the new news. What is old and new at the same time is something that's been on the map -- slide 12 -- for a long time, but I don't think it's been given the significant attention that it deserves. It has -- that something is our belief that the Haynesville and the Bossier acreage has 6 TCF of resource potential.

It's been on this map for several quarters, but now it carries a lot of additional support. That support comes from the fact that every well we have drilled since 2015 has had a greater than 20 million per day IP rate and an average recovery approaching 15.6 BCF. But we think we can do better than that. So we have decided to make some improvements, and I will tell you what I mean on the next slide.

During our last conference call, we summarized our Haynesville Shale drilling program for you, and this summary is shown on slide 13. We talked about how longer laterals and bigger and better completions gave us better results. And that certainly has been the case.

We ran the numbers back then and found that a flat gas price between $2.50 and $3 per MCF would get rates of return varying between 50% and 80% for the various lateral lengths we drill in the Haynesville. But those results were then, and this is now.

And what we're telling you now is that our expectation is better than that. We think we can increase these rates of return by around 20% across the board by changing our future well completion design to include more proppant and smaller frac stages.

Our plan is to increase the completion frac intensity by pumping more proppant per foot of lateral length and decreasing the target stage length that receives that proppant. I will tell you more about this in greater detail later.

Besides providing a significant improvement in our well economics, our expectation is that this improved recovery will also create tremendous additional value in our remaining drilling inventory. Our drilling inventory is also shown on slide 13. And as I previously mentioned, we are planning to add to this inventory through various arrangements. We'll give you greater detail on that when we complete those arrangements.

Moving on to slide 14, we show the location of the various wells we've drilled so far. And to date, we have drilled and completed 12 Haynesville wells with an average IP rate of 23.7 million a day and 1 Bossier well with an IP rate of 22 million a day. The average lateral length completion of all these wells averaged about 7,200 feet at an average proppant loading of around 2,800 pounds per foot, and included a stage length of about 250 feet.

Our new completion design will increase the proppant loading to around 3,800 pounds per foot and target a stage length of about 150 feet. Obviously, our new design should create greater fracture complexity around the well bore, with better proppant support and a larger number of flow entry points from the reservoir. All of these changes should provide a much better bang for the buck, and as I mentioned before, the economics improve quite a bit.

So we move on to slide 15. And I know it's getting pretty busy, but it continues to tell a great story. It shows that all of our wells are continuing to produce as expected against the type curve. Only one well was slightly below that type curve, and that's because after we ran production tubing, we decided to hold some additional back pressure on it so we could evaluate its performance using this technique.

It used to be called the choke back technique. We have found mixed results using this strategy on some of our wells with the old-style completion, but this particular well was the lesser of all of our new wells, so we wanted to see if holding back pressure on a new completion would have a positive effect. We're also holding some additional back pressure on the best of our Haynesville wells for the same reason.

Why would we do this to the lowest and highest production profile wells of our new group? We think it's prudent to test the effect of additional back pressure on these two wells that represent the lower and upper bounds of our performance category on the existing Haynesville completion so we can make the best or optimum choice for producing our wells in the future. The time to do that is after the wells are producing through tubing and so that's exactly what we're doing.

So let me go back to a topic that I brought up earlier: the one about our new completion design and the better economics. Slide 16 will give you some more information about all that. It shows the comparison between our original drilling and completion design versus the new design that we put on the board.

You can see that by going with more proppant and smaller frac stages, we expect an EUR recovery improvement from our old 2.07 BCF per 1,000 foot of lateral length to an improved 2.48 BCF per 1,000 feet of lateral length.

Even though I hate to use the word old to describe our original completion results, since they also yield excellent results, there is no doubt that going with the higher-intensity frac design is the way to go. We simply get more of the reservoir fractured, effectively propped, and contributing to production by going with this redesign. It is simple as that, but it takes a lot of very talented people to execute it.

In an earlier slide on slide 12, I talked about the 6 TCF resource potential, and I want to sidetrack just a minute to talk a little bit about that. I don't feel in the past it's been given enough attention in that the 6 TCF doesn't take very long to say, but it's a huge resource potential that we believe exists throughout our acreage positions.

If you divide the 6 TCF by the 700 or so locations that we believe we have in our drilling inventory, that gives you an EUR recovery on a per-well basis of around 8.6 BCF. And if you look at the tables provided in slide 16, you'll see that a 4,500-foot lateral gives you an EUR using the old completion of 9 BCF, whereas the new completion design that we are advocating, we expect an 11-plus BCF EUR.

Just looking at the 4,500-foot design gives you an EUR that is in excess of the 8.6 average BCF per well it would take to get to the 6 TCF potential. That's why we feel confident that we do have that resource potential and it is simply a matter of accessing it via the drill bit.

So having talked about the 6 TCF, let's move onto the next two slides that will show how this new completion should pay off. Slide 17 has a graph that shows how the ROR changes at different gas prices for different horizontal lateral lengths using our old completion design versus our new design.

We ran the numbers for our various lateral length horizontal completions using our new design and we found that at $2 per MCF, our RORs varied from 23% for a 4,500-foot lateral to around 35% for our 7,500-foot lateral at $2 per MCF. At this lower gas price, our 10,000-foot lateral was about the same as the 7,500-foot lateral.

And as you would guess from these numbers, we are staying pretty conservative with our forecast for the 10,000-foot lateral. We want to drill 1 and we want to complete 1.

But as you move into the $3 per MCF gas price level, the RORs jump dramatically for all of the different lateral lengths. You can see that the 4,500-foot laterals yields almost an 80% ROR, while the 7,500 footer and the 10,000-foot lateral both give over 100% RORs.

So by pumping about 36% more proppant per foot, our correlations indicate that we will get a 20% greater EUR and around a 20% greater ROR for an additional investment ranging from $200,000 to $500,000 depending upon the lateral length.

The next slide covers the NPV numbers. It's the same type of slide on slide 18. It compares the NPV economics for the old versus our new design. No surprise here: the new design gives you more value.

For example, at a $2.50 flat gas price, the old 7,500-foot design gave a $7 million NPV versus a $9 million NPV for the new design. In every NPV case, the new design yields superior results.

Not to leave marketing out of the discussion, on slide 19, you get a quick visual on the breakout of our current and future anticipated gas transport and basis versus gathering and treating costs going from the well head to a Henry Hub market price. Right now, our all-in costs average around $0.44 per MCF. But as you can see, we expect this total cost to fall to $0.37 in 2017 and even further in the years after that.

Currently, we are selling a majority of our Haynesville gas at Henry Hub minus $0.08 to $0.12 and then paying our gatherer about $0.32 to cover the rest of the costs. We have about 40 million a day in firm transport obligations, and that brings the total weighted average differential up to Henry Hub minus $0.44, as shown in the graph. This firm transport will expire in 2017 and with the renegotiation of various contracts by our world-class marketing group here at Comstock.

During the year, we expect to bring the differential down to $0.37 in 2017 and to $0.34 in 2018. Based on public information, we think these numbers are outstanding and compare very favorably to other operators in the region.

Finally, on slide 20, provide a reminder that we do have an excellent acreage position in the Eagle Ford shale play that we have had parked for the last two years or so for obvious reasons. Even though it has been parked, it doesn't mean we haven't been working on it. We have several ideas that we think will generate substantial value once the oil price improves to the upper $50 per barrel level.

We have 26,000 gross, 19,000 net acres in the play. We've identified 83 future drilling locations within our acreage position. We also have additional opportunities to test the staggered and stacked lateral concept. And we are confident that we can generate acceptable returns using this technique once the oil price recovers. No one should be surprised that we have specific plans in place to drill in the Eagle Ford once the oil price does recover.

So as you might've guessed from everything I've said so far, we are focused on creating value in our Haynesville and Bossier assets. And we think we are not only doing that, but we're finding additional ways to improve our results. That will always be the name of the game here at Comstock.

And with that, I'll hand it back over to Jay.

If you would turn to slide 21, I think the two things that are important. One: in order to get to this slide, we had to firm up our balance sheet. We had to have a successful recap, which literally happened about an hour ago. And I give thanks to Roland and his group for doing that. So you firm up your balance sheet.

And then the second thing you have to have, you have to have a core asset that you could focus on that's real. So I thank Mack and his group for really -- as he said, telling a really great story, which is a result of what our talented group focusing on the Haynesville and Bossier.

So with a firm balance sheet and a focus on core assets, we will go to slide 21. Let me refer you to slide 21, where I will cover our outlook for 2017.

Our high-return Haynesville Shale assets will provide us the means to achieve strong growth in 2017. Our enhanced completion design has transformed the Haynesville Shale into North America's highest-return natural gas basins, and our acreage position gives us over 700 operating locations.

Next year, we expect our natural gas production to grow by around 40%, driven by a 22-well drilling program funded primarily with operating cash flow. In combination with an improving natural gas market, we hope, our EBITDAX and cash flow are expected to increase significantly. Our already low-cost structure is expected to improve with our new low-cost Haynesville Shale production.

Our producing costs per Mcfe in 2017 are expected to decrease by $0.20 per Mcfe, which is 14% lower than this year. Our balance sheet and liquidity continue to improve.

During the downcycle, we retired $237 million of our senior notes, generating annual interest savings of $21 million with total interest savings to maturity of $83 million. The recently completed debt exchange reduces our annual cash interest burden by $37 million and allows us to pay an additional $75 million in kind if we choose to. The future conversion of our second lien notes now possible with a successful shareholder vote earlier today will delever our balance sheet.

For the rest of the call, I will now take questions only from analysts who follow the Company. So Jonathan, turn it over you.

(Operator Instructions) Ron Mills, Johnson Rice.

Mack, on slides 17 and 18, can you walk through just some of the differences on those economics versus the PV? And are you assuming the same shape of the curve to drive a similar IRR, but a much higher PV for the 10,000-foot laterals?

Yes. Ron, what we've done is we have assumed no change in the profile of the type curve. We just lower the IP that we feel is representative of a given lateral length based on all our correlation work and the data that we have evaluated, which is several hundred wells. So anyway, the bottom line is the profile of the type curve remains the same. It basically follows the same shape, just that it starts off at a different IP rate.

And if you look at the different gas price assumptions here, that's a flat gas price for the life of the well applied to the type curve for that given lateral length. And one thing that I like to point out is as you can see from the slide that compares the actual well performance to the type curve, almost all of our wells have been producing above that type curve. So we think we are providing a fairly conservative forecast on the production for the different lateral lengths.

As far as the 10,000 versus the 7,500-foot lateral length, we have assumed a pretty conservative ratio based on the data analysis that we've done -- the ratio between the 10,000-foot IP rate and the 7,500-foot IP rate. So we have lowered the expectation basically to parallel the economic results for the 7,500 footer, although there's an expectation yet to be confirmed through actual well performance. The 10,000 footer will provide better economics than the 7,500 footer.

Being able to take advantage of the acreage configuration that we have out there is really important to us. We're certainly going to drill a number of 10,000-foot laterals during 2017 to confirm this concept. But anyway, in a nutshell, the assumptions that we built to provide the economics are fairly conservative, in our opinion.

Okay. And then am I correct in thinking all your wells so far have been 7,500 feet? So you alluded to my next question. If you look out at your wells next year, how do you envision the split being between the 7,500-foot and the 10,000-foot laterals?

We've got a variety of lateral lengths scheduled to be drilled. We've got 5 or 6 of our wells that are going to be targeting between 4,500-foot and 6,000-foot lateral lengths. We have about the same number between 6,000 and 8,000. So we've -- and then of course, we have several wells that we are scheduled to drill between 8,000- and 10,000-foot lateral lengths.

One of the wells that we've drilled of the 13 that we mentioned was -- had a lateral length of about 5,600 feet. And it's the Caraway well that is producing well above the type curve and it's -- and that type curve, by the way, is for a 7,500-foot lateral length. And here we have a shorter lateral length well producing above the 7,500-foot type curve at the 2,000-pound-per-foot proppant loading.

So again, it's a conservative approach to providing production guidance not only to ourselves, but to you all as well. So we are targeting the shorter lateral length split for increased proppant loading so we can assess the improvements that we certainly expect based on a comparison against the 7,500-foot type curve.

And then lastly, look at your inventory. You have a lot of 4,500-foot laterals. I know you just -- within the past few months had swapped some acreage. You talked about expanding your positioning.

Can you provide a little bit more color in terms of whether they are additional exchanges or leasing or acquisitions? And are those designed to increase to shift some of those 4,500-foot laterals into the longer lateral categories? Thanks.

Ron, you have cited all of the options that we are looking at. And certainly, you have 4,500-foot lateral opportunities that provide significant value, but other companies have those opportunities as well. I mean, 4,500-foot lateral opportunities.

If we can trade or make other arrangements whereby we can trade one of our 4,500-foot lateral section opportunities for one of theirs and they can stack ours and we can stack theirs to another section and get a 10,000 footer or a 7,500 footer or stack three sections, now you're talking two 7,500-foot cross unit laterals, one north theoretically and one south. That's a win-win for both parties.

So yes, we are looking at all the above that you cited. But certainly, the combination that I mentioned of trading section for section is appealing to a number of different groups that we've been talking to. We just have to work out the proper swaps.

Great. Thank you.

Jeffrey Campbell, Tuohy Brothers.

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

Well, we don't really want to discuss specific targets in our hedging strategy. But you see a third of the positions in place now and we would like to really add triple that to get kind of the level of 60% or so of the production level.

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

Yes, we would want that number to be very small. I think that -- yes, we are targeting -- we are hoping to bring the CapEx and cash flow into alignment. If we don't, it'll just be because gas prices are lower than our forecast. And we haven't got as many hedges out as we wanted, but we think that's going to be not a very large number. Maybe $10 million, $20 million.

We really want to keep the level of liquidity that we will end the year with kind of out in place. And we don't expect to use the pay-in-kind provision on the first lien notes. We are expecting to not use that and not incur that additional debt.

Okay. And then last question I want to ask, and I'm actually referring to your corporate presentation rather than the one for the quarter. It's I believe slide 14, where you give an illustration of the staggered lateral potential in the Haynesville.

I was just wondering if you have any -- have a time in mind when you are going to begin to test that upper/lower stack concept. And also if you could add some color on how this approach will increase your extended lateral locations?

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

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

Well, if you use that -- look at that illustration, you'll see that the spacing between the wells are such that you can -- using the staggered concept, you can add an additional two locations per section if you're talking about 4,500-foot laterals. If you are talking about 7,500 footers, you're talking the same addition. So number of staggered laterals is what I'm talking about.

So the idea being that the well spacing can be narrowed by targeting the lower intervals in the staggered lateral versus where most of our current laterals are placed, and that would be in the Upper Haynesville.

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

Yes, sir.

Okay, great. Thank you. I appreciate it.

Sean Sneeden, Oppenheimer.

Thank you for taking the question. Roland, maybe as a follow-up to one of your answers there, but on the 10s, can you just maybe just discuss a little bit more about how we should think about -- or how you guys are thinking about paying PIK versus cash as you go forward? What would you need to see in order to PIK those bonds versus pay cash?

Well, yes, we don't -- we want to plan not to. So I guess it's there to kind of underpin the overall liquidity of the Company. But that is not at all -- we want to delever the balance sheet, so we don't want to add that -- add back additional debt to repay. So we are really planning, and we said that all along, not to use that provision. But right now, based on even where gas prices are now, we don't believe we will need to.

Okay, that's helpful. You guys had highlighted the potential conversion of the second liens to help you expedite your deleveraging process. What is your ultimate goal or how are you guys thinking about deleveraging the balance sheet? Any kind of targets you guys are thinking about as you are putting out some 2017 guidance in that sense?

Yes, that's -- it's really the path that we have the roadmap we have to getting the balance sheet back in great shape is -- the next step is the conversion of the second lien bonds. And I think when that happens, it really -- it puts the balance sheet -- it puts our overall borrowing ability back to where we can potentially refinance our first lien bonds to something at a lower rate.

So I think step one is we believe that step needs to happen first -- that conversion happen. And then it really opens the door to further improving the balance sheet and getting -- at least getting our debt down to a much lower cost than it is now.

Okay, that's helpful. Thank you very much.

David Epstein, Cowen.

I wanted to get a sense of the additional cost of the added proppant and the new design. I know for, say, a 7,500-foot lateral that you guys are showing like $8.5 million. And I think in the past before you showed this new well design, you were showing costs anywhere from I think $8.1 million to $8.5 million over time depending on the presentation. Maybe just get a sense of what the additional costs are. Maybe very little?

Yes, the additional costs is between $200,000 to $500,000, depending on the lateral length. And that includes all of the different aspects of the completion, which would obviously include the proppant.

What we've done is, as most operators that have a volume of work, we have packaged that work to the various vendors so we could take advantage of volume discounting. So the bottom line is the additional proppant costs through the discounting of the volume work is negligible.

Overall, we have looked at the additional cost of -- obviously with a 7,500-foot lateral, the older completion design -- the one we used last year -- we had about 30 frac stages over a 250-foot stage length. Into a 7,500 footer gives you about 30 stages. Now we're talking about 50 stages that are smaller, 150-foot length, but they will pump faster.

So the amount of time we are estimating -- the additional time it will take to frack the new completion design is probably an additional two days or so, if everything goes well. And normally it does. So hopefully that answers your question on costs. The bottom line there is volume discounting to keep your costs as low as possible, obviously.

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

That's right.

So you will know that.

Okay, great. And the $0.20 per Mcfe costs that you're talking about the next year. That is full year 2017 versus full year 2016 as opposed to like exit to exit? And that is oil and gas? As far as the LOE improvement?

Right. That is full year to full year on an Mcfe basis, right. Yes. The total Company cost structure. It will be predominantly gas next year, obviously.

Right. Thank you.

Chris Stevens, KeyBanc.

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

Sure. The Jordan continues to produce at a production profile that is now above the type curve. If you go back to slide 15, it's that black line amidst all the other colorful lines. That's the Jordan.

We do have every intention of drilling some Bossier wells in the latter part of the year. And our current plan is to drill 1 7,500 footer. And if everything is working as planned, we also have on the board a 10,000-foot lateral length Bossier well.

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

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

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

Well, that's a longer explanation. But in short, it is based on data, then analysis from several hundreds of wells where we tracked the -- for different lateral links, the amount of proppant that was pumped. And then look at the EUR forecast for those wells. So if you look at proppant loading per foot, proppant loading per cluster, proppant loading total over the length of the lateral length, you can develop correlations that suggest certain EURs.

And then if you look at our performance last year, the correlations worked quite well. Because we anticipated -- and that's represented by the type curve of 15.5 to 15.6 BCF EUR for our Haynesville completions, given the proppant loading and the 7,500-foot lateral length. So we have confirmation there that the correlations are valid.

So the basis is that bin analysis, data analysis that I referred to earlier. And then the 7,500 footers, then the shorter lateral length that I mentioned earlier, the Caraway confirmed -- more than confirmed. It verified that our correlations were quite good.

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

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

Okay, got it. Thank you, guys.

(Operator Instructions) Mike Breard, Hodges Capital.

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

Yes, Mike. We are quite pleased by that, and it certainly has been a great benefit. But we have not touted nor have we worked into the economics on any of our forecasts. So I appreciate you bringing that up. We will have that same opportunity in 2017.

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

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

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

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

Okay. And that's with no extra costs?

No, sir.

Okay, thank you.

It's a freebie.

Ray Deacon, Coker Palmer.

Mack, I was wondering if I could ask what your completion schedule looks like in 4Q and 1Q of net wells and what kind of lateral lengths?

Well, we are drilling two now. We've got one that's going to start completion here in about five or six days. We should be in completion mode on an additional three wells before the end of the year.

Lateral length -- the first well we drilled was about an 8,000-foot lateral length. We have a couple of 4,500 footers that are being drilled. One is a 7,000 footer. So we're going to be quite busy during the fourth quarter, that's for sure.

That's great. So first quarter, that will look great. That's good. And I was wondering with some -- could you just talk about how your marketing and gathering work and pipeline capacity. And I guess your cash costs slide, that does not include transportation, right? Or it does? No, it does include the --

No, it does. It shows all of that. Yes, we show -- some of that cost is reflected in the gas price differential. And then some of it is in our lifting cost and we call that -- it's in a line item called gathering cost. So it's in all-in cost from the wellhead to the market.

Got it, got it. Great. Thank you.

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

All right, Jonathan. Thank you. As Mack kind of had a theme going here that then and the now, I like the now better than the then. And I look at the now and I just kind of took some notes on it. We have no hedges; now we've got a third kind of our hedge goal completed. We didn't know what 2017 drilling program would look like. Now you know what it looks like. Our goal is to not incur any additional debt.

You know that we've taken greater steps toward firming up the 6 plus TCF of reserves. 700-plus locations. You've heard from Mack: we have materially improved the economics on our Haynesville/Bossier program. It's not by reading somebody else's press release.

A couple hours ago, we really finalized our recap. It's complete. And as the question was asked, the Bossier, the Jordan well, it continues to look exemplary. And then I've got, and Mike Breard asked this, and we do have some gas. When we complete these wells, we got 13, 14, 15 day-to-day of quote other gas from -- as a result of just the wells we have been completing.

So those are all good things. It's a tough market. We'll see what Old Man Winter does for us. And I think we are on the right path. It took a really great effort from Mack and Roland and the Board, and the shareholders and the, again, bond holders, whether you were secured or unsecured, in order for us to have a day like today. And everyone at Comstock is thankful for each one of you. So go out and vote. Jonathan, that's it.

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