Comstock Resources Inc (CRK) 2016 Q4 法說會逐字稿

Good day, ladies and gentlemen, thank you very much for standing by. Welcome to the Comstock Resources fourth-quarter 2016 earnings and operational update. (Operator Instructions). As a reminder, today's conference call is being recorded. I would now like to introduce your first speaker for today, Jay Allison, Chief Executive Officer. You have the floor.

All right, Andrew, thank you. A few comments before we start the formal presentation. First of all, thank you for listening to the Comstock report. I would like to tell you that 2015 and 2016 were tough years in the energy sector, as you know that are listening. I mean, action had to be taken to survive and then prosper for almost all energy companies. And as a Company, in the past two years Comstock has executed, in my opinion, well on all fronts giving our starting point.

In 2015 we focused on capital restructuring and protecting our liquidity and at the same time reducing our total debt. In those two years we reduced our total debt by $240 million, we monetized our East Texas Eaglebine and our South Texas conventional gas properties.

And then on November 8, which is not that many months ago, in 2016, we fully recapitalized Comstock and today Roland will report that we have $190 million of liquidity and a capital structure that works. And with a two to three rig Haynesville drilling program this year, which will be a predictable program, we should see a 40% production growth and the key is that it is funded primarily with operating cash flow in 2017.

The other thing we have done in the last two years is we focused on our core business activities, which was switching from oil to natural gas, but the natural gas is in the Haynesville. And then we focused on great geology because I think that drives everything. With our 700 operated locations in the Haynesville we see our rate of returns from anywhere from 50% to 70% with $2.50 gas and 70% to 100% with $3.00, depending upon the lateral length of the wells. They are repeatable, they are predictable.

And if you look of February 2015 when we started we had zero -- zero inventory of operated drill locations because we haven't drilled at that time an extended lateral location. Today we have the 700 operated locations in the Haynesville. We have come a long way in two years; it has been a rough two years. We are glad that today is the finale of 2016 and we can go forward with 2017 and we look forward to predictable growth in 2017.

With that I welcome everyone to the Comstock Resources fourth-quarter 2016 financial 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 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 2016 operating and financial results, but most importantly, we will review our outlook for 2017.

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 in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct.

Now our 2016 highlights. The highlights of 2016 are summarized on slide 3. 2016 was a difficult year where both oil and gas prices continued to drain the Company's liquidity. We protected our liquidity by limiting our spending and making other sacrifices like forgoing bonuses we had earned in 2015.

Despite the limited capital spending, our Haynesville Shale results continued to get stronger, as Mack Good will report in a moment. All of the wells we drilled in 2015 and 2016 continue to perform above their type curves. The performance of our Haynesville Shale wells drove the 47% growth. We had improvement in oil and natural gas reserves which replaced our 2016 production by 667%.

We were able to achieve an all-in finding cost of $0.14 per Mcfe in 2016. The successful debt exchange we completed in September allowed us to restart the drilling program in the fourth quarter. We plan to utilize three operated drilling rigs during this year to drill up to 22 Haynesville/Bossier wells. We anticipate that the 2017 drilling program will grow our natural gas production by 40%.

We recently announced a new Haynesville drilling joint venture which we can use to acquire additional acreage and to grow our inventory of drilling locations. The 2017 drilling program combined with improved oil and natural gas prices will result in substantial growth in our revenues, cash flow and EBITDAX in 2017.

We are able to invest again in the high return Haynesville program because of the step we took in 2016 to protect and enhance our liquidity. In 2015 to 2016 we retired $237 million of our senior notes generating annual interest savings of $21 million with total interest savings to maturity of $83 million.

Most importantly though, we completed the exchange with our senior note holders which reduce our annual cash interest burdens by $37 million and allows the Company to pay an additional $75 million in kind in the future. 98% of our bondholders participated in par for par exchange.

The future conversion of our second lien notes will delever the balance sheet and set us up to refinance our remaining debt at lower interest costs, which Roland can talk about in a moment. We have current liquidity of $191 million going into 2017 which is more than adequate to underpin our 2017 drilling program and operations.

Now I will turn it over to Roland to go over financial results. Roland.

Thanks, Jay. Slide 4 in the presentation shows our natural gas production since 2013. And despite having a limited drilling budget in 2016, we are still able to grow our natural gas production by 13% from 2015.

We put a rig to work in March of last year and we drilled three 7,500 foot horizontal lateral wells in our Haynesville program, but then we released that rig in July to conserve our liquidity. With the completion of the debt exchange that happened in September we started drilling again at the end of September and we added a second rig at the very end of October.

Our gas production averaged 133 million cubic feet per day in the fourth quarter and the decline in our gas production from the third quarter rate was due to -- partially due to the sale of 10 million a day relating to our South Texas natural gas properties. But most significantly it was due to the lack of drilling in the third quarter and the shut in of many of our largest producing Haynesville wells in November for 21 days. And they were shut in while we were conducting offset completion operations and doing other fieldwork.

But we are off to a good start this year as our January production averaged 150 million per day and we are bringing a lot of high-volume wells in this first quarter. So based on the drilling program and these new wells coming on, we do expect our gas production in 2017 will average between 200 million to 230 million cubic feet per day, and probably get close to those rates as we get to the middle of this year.

Slide 5 shows the hedge position that we put in place to try to lock in some of the high returns from the Haynesville Shale wells that we plan to drill in 2017. So right now we have 72 million of our projected 2017 gas hedged at $3.38 on a NYMEX basis.

Slide 6 shows the expected differentials for NYMEX that we expect to realize from our Haynesville Shale program. With firm transportation obligations which expire in 2017 and 2018 and the renegotiation of various gathering and treating contracts, we are expecting our differential to NYMEX to average $0.37 in 2017. Now this number includes both the gathering and treating cost, which is shown on red on the slide, which we include in operating cost. And then the average differential that you would see from a Henry Hub gas price to our realized gas price.

On slide 7 we summarize our oil production. Oil production averaged 3,200 barrels per day in the fourth quarter, showing continuing declines due to the lack of drilling since 2014 and the sale of our Burleson Eaglebine properties in 2015. With no drilling activity really budgeted for this year we do expect that oil production to decline further. We expect our oil production this year will average between 2,200 and 2,800 barrels per day.

On slide 8 we summarized the fourth-quarter financial results. The 22% production decline resulted from the limited drilling in 2016 offset much of the benefit of improved oil and gas natural prices as compared to the fourth quarter of 2015. Oil prices were up by 27% and natural gas prices were up by 41%.

The net result was our oil and gas sales for the quarter were only up slightly to 1% to $48.5 million and EBITDAX was up a similar percentage to $27.2 million. But most importantly our operating cash flow of $9.2 million was substantially improved from the cash flow deficit we had of $3.3 million in the fourth quarter of 2015.

We have continued to experience significant improvements on the cost side. Our lifting costs this quarter were down 33% with lower production taxes and lower gathering costs. And our DD&A was down 51% due to improvement in our DD&A rate.

Our G&A costs were up this quarter in comparison to the very, very low number we had in the fourth quarter of 2015 as the Company returned to normal compensation practices and, unlike 2015, is paying performance bonuses again. As Jay mentioned in his opening comments, the bonuses were earned but given back to the Company which created the very low number in the fourth quarter of 2015.

For the quarter we reported a net loss of $54.9 million or $4.48 per share. But there were still a lot of unusual items in the quarter, including some impairments for a loss in divestitures of $3 million and unrealized mark-to-market on the hedge position we have in place for 2017 of $6 million. And some losses related to the debt exchange we completed in September of $11 million. If you exclude these items and other nonrecurring items the net loss would have been about $32 million or $2.58 per share for the fourth quarter.

Slide 9 summarizes the 2016 financial results. There you see our overall gas production was up by 13%, but oil production was a decrease by 55%. Overall production was about 6% lower in 2016 than 2015 due to the very, very limited drilling activity we had in 2016.

Oil prices were also lower in 2016; they had fallen by 17% while the gas prices were fairly consistent between the two years. But overall, because of the lower oil production, oil and gas sales were down 30% to $178 million and our EBITDAX was down to $91 million. Again you saw the costs were much lower in 2016; lifting costs were down 23% and our DD&A, depreciation, depletion and amortization, was down 56%.

In 2016, lots of noise in the loss we reported, $126 million of impairments or losses on the sales. That same unrealized mark-to-market lost on hedges, which totaled about $8 million for the year. And then we had the large gain that was recorded on the debt exchange and the other retirement of debt of $177 million. So, excluding these items we would have had a net loss of about $14.61 per share or $171 million.

Slide 10 in our presentation shows the very positive direction our producing costs have trended since we have shifted toward drilling our low-cost Haynesville Shale natural gas oriented properties versus the higher cost oil projects that really made up most of our activity in 2014. So you know, operating cost for 2016 averaged $1.10 per Mcfe produced as compared to $1.48 back in 2014.

A lot of that reduction is due to lower production tax. Some of that relates to the much lower oil and gas prices that were realized, but there is also, with the mix of more production from the Haynesville wells -- a lot of the wells are exempt from production taxes their first two years. So that was a huge part of the savings and we expect to kind of see that continue into 2017.

But field level costs, which were also down, they averaged $0.76 in 2016 as compared to $0.92 in 2014. That is -- part of that is due to the volumes in the Haynesville have very little hard field level costs associated with them. And then we have made efforts to reduce our operating cost in our oil properties in 2017.

We have seen a dramatic reduction in DD&A per Mcfe produced, which has come down to average $2.26 per Mcfe as compared to $5.74 in 2014. This improvement -- a lot of it is due to the very, very low finding cost of the Haynesville Shale wells that were drilled in 2015 and 2016 which are now making a big part of our production. But also it is in part due to the significant asset write-downs we took on our oil properties back in 2015 to help lower their cost also.

But looking ahead to 2017, we expect to show further improvements to our producing cost and expect our total lifting cost to actually be under $1.00 for 2017 and that our DD&A expense per Mcfe to be under $2.00. And again, this is more just the shift of the high volumes coming from the Haynesville which come with the lowest cost.

Slide 11 summarizes the proved reserves at the end of 2016. We were able to grow our proved reserves from 625 Bcfe to 916 Bcfe at the end of 2016 and that was done through a combination of drilling and the strong performance from the new Haynesville wells that we drilled in 2015 and 2016. And it is also due in part to the improvements to our liquidity which allows us to have expanded drilling plans in the future.

The SEC prices that were used to determine proved reserves were no help at all. They were actually lower than they were in 2015 given the backward looking nature of that calculation. And oil fell -- the oil prices used for the reserves net to the Company's realization were $37.62 per barrel as compared to $46.88 per barrel in 2015 and gas was $2.29 per Mcfe, just a little bit less than the $2.34 used in the 2015 reserve estimates.

So these lower prices caused a very small downward revision of 16 Bcfe from the 2015 reserves. And then you also -- we divested of 60 Bcfe in 2016, but the additions far outweighed the reductions to the reserves this year. And then the reserve additions, which almost exclusively come from the Haynesville program, were very strong coming in at 429 Bcfe.

We added 285 Bcf of new reserves from the drilling program and also due to the expansion of the future drilling plans for 2017 in the future, and that was made possible by the improvements to our corporate liquidity. But in addition to that though we experienced 144 Bcfe in upward revisions primarily due to the really strong performance that the wells that we drilled in 2015 demonstrated throughout 2016.

We were also conservative in using -- in recording the reserves back in 2015 as our new completion design didn't have the long history that it has now.

At the end of 2015 our proved reserves included only 30.3 net proved undeveloped locations related to our Haynesville Shale properties. The 2016 proved reserves include 51.9 net proved undeveloped locations and that's simply reflecting the increased drilling budget that we put in place for 2017 versus what we were looking forward at the end of 2015.

But with the large inventory of over 700 operated drilling locations there is plenty more undeveloped locations to include in the future to drive really good proved reserve growth further. The substantial growth that our reserves experienced in this rare combination with a very, very, very limited capital spending in 2016 did create some unbelievable all-in finding costs of being only $0.14 per Mcfe.

Slide 12 recaps the capital spending in 2016 and then what we are expecting for 2017. Again, we spent only $59.5 million in 2016 as we focused on preserving the liquidity and limited the activity and were -- and for several months we really had no drilling rigs running. But we did drill 13 wells, which was [7.9] wells net to our interest and had a fair amount of activity going on at the end of the year.

Now a lot of the wells that we drilled -- obviously the wells we drilled in the fourth quarter are the ones that we plan to complete and bring online in the first quarter of this year. So our plans are still to drill 20 or 15.5 net additional Haynesville Shale wells this year primarily using the two operated rigs that are dedicated to the program.

We also, as we will talk about a little bit more in a few minutes, have a drilling joint venture with USG and we will have -- we will run a third rig for that program but we'll have about a 25% participation in those wells. So overall we are expecting the Haynesville Shale program to cost about $143 million.

We also have another $7 million just for other routine drilling expenditures kind of budgeted. And then we've tentatively budgeted another $17.6 million for 2, or 1.7 net, additional Bossier Shale wells that may be drilled later -- late in the year. And we will make that decision kind of based on how we see the year progressing with the high volatility in natural gas prices and where our cash flow is.

But we are really attracted to drill these wells, as Mack will tell you in a few minutes, because of the really incredible performance of the [Jordan] well we drilled in 2015. It is really compelling to come back and drill another well there. And we think that would further prove up the very extensive inventory we have of Bossier Shale wells, especially in the southern part of the Haynesville play.

Slide 13 shows our balance sheet at the end of the year. So we ended the year, we had $66 million of cash on our balance sheet and still the $1.173 billion of total debt outstanding. So if you include the undrawn credit facility that we have, and the feature that we have that we don't plan to use this year where we can pay in kind the interest on our first lien bonds, we have kind of $191 million of total liquidity that kind of backstops our plans for 2017. And our goal is to continue to have that liquidity available through most of this year.

We did have -- we have had some of the second lien bonds convert to equity. I think a little less than 3 million converted before the end of the year, but we have had another 9.2 million convert in early 2017. So those are convertible at the option of the holder at any time. But would mandatorily convert if we can achieve a $12.32 price for 15 days.

And we did show -- we talk a little bit about that of the second lien bonds on slide 14 and really the impact they have on the balance sheet. I mean the -- given the nature that the interest is all paid in kind in these bonds, we expect fully to convert to equity. They are not a big influence on our cash flow or our drilling plan, but they have the -- they do cause our balance sheet to show a lot of leverage.

And so if you look at kind of what we are -- if you look at our leverage ratio, and we kind of use a $3.00 NYMEX gas price -- we actually have some good hedges protecting some of our production [in excess] to that price. But if you look at that we are still about 5.9 times with a [leverage] ratio, which is not an attractive leverage ratio in our sector.

But post conversion, which again would happen if we can achieve the stock price required for that, the leverage ratio improves almost overnight to 3.6 times with just this $3.00 NYMEX gas price. And stronger gas prices would even get it possibly below 3 times.

So looking ahead to 2018, our goal really is to get our leverage ratio back to 2.5 times. And we hope to do that by achieving the conversion in 2017 at some point. But then also growing our EBITDAX further with the high return drilling program which we think can generate that growth. So now I will hand it back over to Mack Good to give us an update on our drilling program.

Thanks, Roland, and good morning to everybody out there. I will start off as I usually do in the other conference calls with the first slide is familiar to most of you. That is slide 15 that shows our 67,000 net acres in the Haynesville Bossier.

But what it doesn't show is where we are looking for additional acreage to add to our holdings. As an example of what we have been doing and are doing, in January of this year we announced our JV partnership with USG and that will give us an exposure to an additional 3,300 net acres in the Haynesville.

We plan to start drilling out there on this acreage block sometime in the second quarter of this year and we will be drilling 10,000 foot laterals in the Haynesville. We will operate these JV wells, as Roland mentioned earlier, with 25 working interest. The net revenue interests are attractive, net lease position out there, so we will have well over 20% [NRI] in all of those wells.

And we are working on various other arrangements and some of them are quite close to being finalized. That will increase our acreage count and improve our drilling and inventory by several 10,000 foot lateral locations. And also increase obviously our tremendous reserve potential in the Haynesville. And we will talk about all of these arrangements of course once we get them finalized.

Also given the improvements we've made in our completion strategy our Haynesville reserve expectations per well on our acreage have grown. And so, that 6 Tcf of reserve potential that we refer to in the right-hand corner of slide 15 continues to be supported by the strong results that we have seen from our extended reach Haynesville drilling program.

And these wells that we have drilled suggest that we should be able to gain recoverable reserves approaching 2.5 Bcf per 1,000 feet of completed lateral using an improved completion design that I call Gen 2. Gen 1 is the completion to sign that we applied in 2015 and 2016. Given our history of improvement I think -- I know we can improve above the 2.5 Bcf per 1,000 feet going forward as we continue to optimize our completion designs.

Anyway, moving on to the next slide, I will give you a little more information about all of this. Slide 16 is showing the location of numerous wells that we have drilled. We have summarized some of the Haynesville Shale drilling program results for you in our last conference call. And this -- slide 16 continues the discussion.

In the past we talked a lot about how longer laterals with better completions gave us significantly better economics under a variety of market conditions. And although this continues to be true, our expectation is that we should be able to do better. We think that everything else being equal we can increase our previous rates of return by at least 20% across the board by changing our well completion designed to include, simply put, more proppant per foot and going to smaller frac stages and cluster spacing.

In fact, we've completed three wells using this new design and we are in the process of completing three additional wells that within two to three weeks will be flowing to sales. These six wells will give us a pretty decent starter kit for evaluating the benefits of our new design. All six of these wells that I mentioned have varying lateral lengths.

Two of the first three wells we have already brought to sales, the Claybrook and the Halsey have lateral lengths that are slightly less than 4,500 feet. But both gave IP rates above 20 million a day. Tremendous results. The third well, the Pace 5-8 had a lateral approaching 7,500 feet long and its IP rate was approximately 25 million a day.

So to be brief we are seeing IPs and initial performance profiles that meet our expectations and as we move forward will be able to evaluate the future benefits of our new design on each well's longer-term production. We will be looking at just how each well's production profile compares to our existing type curve along with how each well's performance might compare to the other legacy producers in the immediate area.

There is no question that comparing the well's performance against the type curve is useful, so let's take a quick look about how things are going so far by looking at slide 17. Slide 17 is a little different then you have seen in the past, but it is still at the same type curve metric that we use with the 7,500 foot lateral well for standard comparison purposes.

And what we have done is we have averaged nine of our wells into a single representative curve so we can clear it up a little bit. That gives you a better picture of how the other wells are performing against our 7,500 type curve measuring stick. Obviously the nine well average curve is well above the type curve and that speaks for itself.

You can also see that our one Bossier well, as Roland mentioned earlier, the Jordan, continues to impress. It is well above the type curve. In order to better define and measure well performance we are in the process of building a 4,500 foot lateral type curve that will be based on the future performance from our new wells that have this lateral length. But right now we are throwing everything up against our standard 7,500 foot type curve just to keep it simple for discussion purposes.

This slide will obviously get some additional members before our next conference call since we anticipate in another three weeks or so we will have three additional wells flowing to sales, two of which will have lateral lengths approaching 7,500 feet long while one will be a 5,000 foot length completion. All three will be Haynesville wells of course.

Taken altogether, it is obvious that we are evaluating the performance of wells having different lateral lengths in our portfolio and we are doing that for two basic reasons. One is that we have numerous drill ready and highly economic 4.5K lateral opportunities to go along with significant number of larger length laterals. And the other reason is that we can drill, complete and connect these shorter lateral wells to sales (technical difficulty) and very fast.

This way we can build a significant production wedge using an economic approach that utilizes a combination of high-performance Haynesville wells having various lateral length completions.

Let me go back to an earlier topic, the one about our new completion design and what we expect from it. So slide 18 will give you a little more information about this. What it shows is a simple comparison between our original, or Gen 1, completion design versus our new design, or Gen 2, over a three frac stage section.

In an effort to keep things straight I am calling it Gen 1 for the old design and Gen 2 for the new design. Gen 1 design worked just fine, there was nothing wrong with it but we thought we could improve it. You saw how Gen 1 worked in the previous slide, marking well performance against the type curve.

Each frac stage in Gen 1 was about 250 feet long and had five perforation clusters, the clusters being spaced about 50 feet apart. And we pumped 2,800 pounds of proppant per foot. So each stage got about 700,000 pounds of proppant. In Gen 2 our effort is to gain more of what the reservoir guys call effective stimulated reservoir volume.

And as you can see in the slide, the Gen 2 fracs stage length shrinks to about 150 feet and the clusters are closer together. Now they are only 30 feet apart. And we are pumping 3,800 pounds of proppant per foot. So each stage is getting about 570,000 pounds of proppant pushed into a targeted shale thickness of about 150 feet.

So just looking at things in these terms, the Gen 1 frac pumps at 2,800 pounds per foot would have only pushed about 420,000 or 440,000 pounds into that same 150 foot target thickness and have fewer take points or clusters across that 150 feet.

So what does all this stuff mean? Well first, if we look at a 7,500 foot Haynesville lateral it means that a Gen 1 completion would get a total of 21 million pounds of proppant while a Gen 2 completion is going to get 28.5 million pounds of proppant. It will also mean that the proppant in Gen 1 would be distributed across 150 perforation clusters while the Gen 2 proppant is going to have a lot more take points connected to the reservoir with 250 perforation clusters.

So Gen 2 gets more proppant and more reservoir take points and all of our correlations plus a little common sense tells us that we should get a significant improvement in that stimulated reservoir volume I mentioned earlier. The greater the stimulated reservoir volume the better the well performance, the EUR and the economics.

You all have your correlations and we have ours and ours suggest that a 36% increase in proppant coupled with a 67% increase in the number of take points connected to the reservoir should deliver a 20% increase in EUR. What is the best combination? Meaning what is the best frac stage length and pounds per proppant pumped and cluster spacing?

We don't have the answer yet, neither does anybody else. But we are working on it and we suspect that the right answer will depend on where the well is located in the play and the proximity and the history of the production in the immediate area.

I will just say this to some up this part of the presentation here. I believe we are getting pretty close to knowing the optimum completion code for our area of the Haynesville. I think we are very close.

Moving on to the next slide is another example of just how things can improve with better technology and being diligent about things. The bar graph on slide 19 shows that since 2010 we have reduced our average spuds to rig release time window by 13 days, incredible.

Even though very few of the wells we drilled in 2010 had horizontal laterals beyond 5,000 feet, that is no longer the case. Most of the wells we have drilled since we began our new program in 2015 have lateral lengths greater than 7,000 feet.

So the bar graph you see -- the other paragraph you see on the right side of slide 19, is an effort to give you an apples-to-apples comparison of just how much we reduced our drill time per 1,000 feet of horizontal section drilled in the Haynesville since 2010. This gives you a pretty clear picture of the fact that we can now drill a little over twice as fast as we did just six years or so ago.

We are now drilling an average of just over 1,000 feet of horizontal Haynesville section per day when it used to take us about two days, a little over two days to drill that same distance. This improvement is due to the combination of several things: better bits, better mud motors, better hole [planning], better steering. But the most important thing of all is the first class drilling group here at Comstock and out in the field that has a lot of experience in applying all of these things. This all translates to the bottom line cost savings and better well economics.

Slide 20 is just a quick summary of our year 2017 drilling program as it sets up. And as you can see, we plan to spud -- drill 22 wells, 15 of them will have 7,500 feet or greater lateral lengths, six of the 15 wells with lateral lengths greater than 7,500 are going to be at the 10-K or 10,000 foot lateral length.

The table and the slide also gives you some variety of information that includes our current D&C costs, IP rates, production profile metrics and EURs for each well length category. This information sets up the well economic forecasts that we will go over in the next two slides.

So let's move over to slide 21 showing our rate of return forecast cases that are run at different flat gas prices, apply to the production we expect from each different Haynesville lateral length well we drill. And as you can see, at a $2.50 flat gas price our RORs range from 48% for our 4,500 foot Haynesville well to around 70% for the horizontal wells drilled to 7,500 feet and beyond. As you can also see, the RORs jump by about 30 points if you apply $3.00 per Mcf flat gas price to the EUR profiles.

All of these forecasts are based on our 3,800 per foot Gen 2 completion design I talked about earlier. And you can see that both the 7,500 foot and 10,000 foot lateral well economics are pretty similar to each other. And that is simply because we continue to be very conservative with our 10,000 foot performance projection and production profile.

We will build a new forecast for this 10,000 foot well type just as we are going to do with the 4,500 foot well type once we get some production history to confirm the shape of those type wells' production profiles.

The next slide -- over on slide 22 is the same type of graph that you saw before except it shows how the NPV changes for each well category at different flat gas prices. Again, (technical difficulty) at the $2.50 flat gas price our NPVs range from $4.6 million for a 4,500 foot HV well to $12.6 million for a 10,000 foot Haynesville horizontal well.

The 7,500 foot well has a $9.5 billion NPV at the same $2.50 gas price. And just as with our RORs, if you use a $3.00 per Mcf gas price the NPV jumps by several million dollars for each well category. The bottom line is that, as shown on slides 21 and 22, our economics are very, very good.

Earlier while I was talking about our acreage position I briefly mentioned that we had announced our JV with USG that focuses on 10-K extended reach Haynesville wells. Slide 23 shows the general location of this acreage in Caddo Parish Louisiana. We plan to spud the first well in the second quarter of this year; we'll operate, as I mentioned, at a 25% working interest level going forward. This JV is a first for us and we know that both parties certainly look forward to a continuing relationship that holds considerable promise for future expansion.

Stepping away from the Haynesville for a bit, even though it is our favorite topic, obviously, slide 24 shows our 19,000 net acre position in the Eagle Ford Shale oil play. While we have concentrated on our Haynesville program, 11 Eagle Ford operators in our general area have drilled and completed numerous wells on tighter spacing.

Some of these same wells also successfully tested the stack/stagger concept that I know you are all familiar with. Several wells around our leasehold area have been drilled on spacing ranging from 165 to 330 feet and production from these wells have been extremely encouraging to us.

In fact, Comstock recently participated in two 10-K lateral Eagle Ford wells drilled by another operator in our immediate area on a spacing approaching 300 feet. One of these wells IP'd at 1,639 barrels of oil per day while the other well IP at 1,826 barrels of oil per day.

Since Comstock's standard well spacing in the Eagle Ford currently is between 650 to 700 feet on average, we believe that we have a stage that is set up for our return to the Eagle Ford at the appropriate time to drill on tighter spacing. And while targeting these infill opportunities we would also want to springboard off certain other results we have seen from several other operators in the area to test our stack/stagger locations.

The next slide will give you a little clearer picture of what I am talking about when I am talking about stack/stagger. And that's slide 25 and it shows that most of our drilled Eagle Ford wells targeted the lower section of the Eagle Ford and were spaced about 650 to 750 feet apart from each other.

This particular well spacing obviously allows us to target future wells in the upper section of the Eagle Ford using a tighter spacing of 300 feet or so. And doing this will allow us to access what we believe to be a largely if not totally untapped portion of the upper Eagle Ford shale section.

We also believe that we can significantly improve our future Eagle Ford Well EURs going forward by using the improved completion strategy that -- drilling on tighter spacing and targeting the upper Eagle Ford section in various parts of our acreage position.

I can assure you that over the last several months we have been preparing a development action plan that will provide various options for drilling these types of wells in the Eagle Ford and has significant potential throughout the area of our leasehold. We have been amassing quite a bit of data and we are pretty close to having it all packaged up and evaluated. But things look very, very clear at this point to us that it is a tremendous opportunity for Comstock at the right time.

Our reservoir and geological groups estimate that the number of additional locations that this could add to our inventory could be well over 250 locations, which is more than the total number of Eagle Ford wells we have drilled to date, it is an amazing statistic.

So as Comstock moves through the rest of 2017 we have several things in our operational plan going for us. Obviously we have got a lot of diversity and flexibility in our Haynesville extended reach drilling program. We will be drilling several wells from two well pads, drilling wells with horizontal sections ranging between 4,500 feet all the way to 10,000 feet in length. And we will be starting a new JV with a very strong partner in USG targeting a drilling program that is full of 10,000 foot lateral wells.

And on top of all of that we have what we believe to be a significant oil recovery drilling program waiting to be started in our Eagle Ford acreage position. It is just a matter of time before that happens. And finally, we have some of the best professionals in the business to get the job done. I know one thing for sure, there is nothing wrong with our picture. So with that I will get out of the way and give this thing over to Jay.

All right, Mack, excellent. Roland, excellent. I would like to conclude kind of the formal presentation with -- and you can look at site 26 and read that on your own. But nobody knows where oil and gas prices will settle in 2017, nobody. But here are the things that we do know about Comstock and there are 10 or 11 of them.

One, we do have a world-class natural gas asset in the Haynesville. We kind of start proving that up because there are several private E&P companies backed by private equity that have made multibillion-dollar bets recently. And you have got several public E&P companies that have reported stellar well results. Well, I think we kicked this off in February 2015. It is a world-class natural gas asset.

Two, two years ago, even a year ago, we had no hedges for gas. Today we have hedged 50% of our current production and probably 30% plus of our 2017 projected production to $3.38.

Three, like Mack just said, our EURs are up 20% on our Gen 2 frac program in the Haynesville. And our Gen 1 EURs were stellar and they are getting better.

Four, we have 700 operated Haynesville locations and they are growing. We are adding acreage. I mean we added 3,200, 3,300 acres last year when we had no money.

Fifth, we do have $191 million of liquidity, as Roland mentioned.

Sixth, 40% production growth funded primarily with operating cash flow.

Seven, 50% to 70% rate of return in the Haynesville when gas is $2.50 or a 70% to 90% return at $3.00 depending upon the lateral lengths, as Mack went through.

Eight, major repair to our balance sheet that started in February 2015. It kind of culminated in November 2016 with another major step taken when our second lien notes convert to $450 million of equity, as Roland mentioned.

Nine, possible drilling locations, as Mack had mentioned, that we could add in the Haynesville with the staggered well success that other companies I think are seeing.

Ten, and Mack mentioned this in the last part of his presentation, South Texas Eagle Ford. We don't talk about it a lot, but we have drilled 190 extended lateral wells in South Texas Eagle Ford. We drilled those on 700 foot locations from well to well. Well, it looks like the stacked/staggered locations could add another 250 drill sites to our inventory of 80 plus existing locations that we have.

So this 330 locations is in our site. We might have that many locations in our South Texas Eagle Ford. And then you kind of throw in a bonus with the JV in the Haynesville with USG which Roland mentioned. That is a Tier 1 partner, it brings capital that complements our operation skills in the Haynesville.

So you say, why the Haynesville and why Comstock? Well, one, we have had success. Our successful program -- we had 10 successful wells in 2015, we have had eight successful wells in 2016. We have the lack of the burden of the legacy transportation burdens that a lot of the peers might have. We don't have that. That is why we are profitable, that is why we can have these rates of return.

Location of our Tier 1 acreage, we proved that up through our drilling program and the location of the Haynesville itself in Louisiana near several intrastate pipelines, potential export facilities, industrial consumers, near Sabine Pass for LNG exports, and near pipelines that are materially underutilized. All those things are positive, tremendous balance and tremendous future for Comstock.

So, Andrew, with that I will open it up to take questions only from the analysts who follow the Company.

(Operator Instructions). Ron Mills, Johnson Rice.

Question on the Eagle Ford maybe for Mack. Obviously really good results on those stagger/stack wells and an increased inventory. Given the liquidity position and the outlook of becoming free cash flow positive in the early part of next year, at least on our model, what would make you want to revisit and maybe start drilling again to add a little bit of oil exposure and reverse that decline?

Well, Ron, all we need is to get certain things to happen that we plan to make happen in the Haynesville to build our production wedge, get our production targets in sight. Roland mentioned earlier about the last two wells in our program are the Bossier wells. That also -- and I didn't give a whole lot of attention to that in my talk. But the Bossier is a completely wide open opportunity for Comstock.

We just need to make sure that we are in a great capital position. If we are at the end of the year, I guarantee you if oil is in the $55 to $60 range the opportunity to add to our oil production is just right in front of us. We would certainly be eager to take that next step and get out there and drill a few wells.

We have already got an action plan built for that. We know exactly where we want to go. We know exactly what we want to do once we get there. It is finding the right time in terms of the financial situation to do that. And so, I am hopeful that at the end of the year, Ron, and the first part of next year we will have that opportunity to get out there. Roland may have something he wants to add to that picture. But that is kind of the way I see it.

No, I think Mack summarized it pretty well. It is a great opportunity. I think as we go through this year we will continue to see our gas and oil perform in relation to each other. And we continue to evaluate that.

I mean we think even with the gas falling off some the returns in the Haynesville are probably still trumping everything and that is where we want to build to meet our production goals, build up our cash flow with the Haynesville production. And then over time we would look to revive the Eagle Ford and put value back in that asset which has been neglected since 2014 really (multiple speakers).

So the timing is really up to us. It is held by production leases, so we just need to see when does it fit into the Company's capital program the best. And most likely it would not be before 2018 that we really start drilling.

And, Ron, you have seen the reports the last two weeks. I mean the peer operators that offset our acreage, I mean they have materially de-risked a lot of the Eagle Ford that we own by the stack/staggered success. So we continue to look at that.

And then, again, our cost structure is so much less in the Haynesville. We have to consider that when we go back to the oil play in the South Texas Eagle Ford. And then we -- again, we committed to our equity owners and our bondholders, which are incredible people. I mean to have a 98% vote for the secured and unsecured bondholders and a 90% plus vote from the equity owners that we could round up to vote to support the plan. We committed to keep our balance sheet as pristine as we can. So a lot of the decision will be based upon that.

And then along the same lines, Mack, any update or in terms of maybe just an update on timing? I know you participated in three stagger/stack wells also in the Haynesville testing tighter spacing, which I think can increase your inventory by about 20%. Where does that stagger/stack test stand in terms of potential timing of a new [slow]?

Well, the initial results are very encouraging, Ron. They are still flowing the wells back. And so, we haven't completed our evaluation of those yet. So it is going to wait two or three weeks for that to happen. But right now I can tell you that it is exactly fitting our model. There has been no surprise, we are very encouraged by the results that we have seen so far.

But I want to wait until the wells get tested to final IP and then we build a curve on those things. But that stack/stagger opportunities in the Haynesville, you are exactly right, that is an opportunity for Comstock to add additional locations.

And the operator that drilled those wells had two that were high in the Haynesville section and one that was low in the Haynesville section. And so, all three of those wells are performing exactly what we anticipated so far. But give it another two or three weeks and we will have some harder data for you, Ron.

And then just to go back to Eagle Ford, I failed to ask this. The results that you are having there, I know you are using more intense completion designs now than when you last drilled. Can you just refresh our memory of kind of what you were expecting in that area, how these wells are versus what you would have expected with the new completion designs? Because I just can't recall your Eagle Ford type curve.

Well we sure haven't talked about it in a long time. But basically what Comstock did and most other operators did back in 2012 -- starting in 2011 through 2014, was to use the 30/50 and even 40/70 proppants, lots of gel in the fluids that were pumped. And so, the EURs on average in our area was around 40,000 barrels per 1,000 feet of completed lateral length and that is kind of an average.

I can give you more specific ranges later, but on an average that is kind of what we EUR'd our wells using this completion approach, again Eagle Ford Gen 1. Eagle Ford Gen 2 is going to be totally different. A lot of things have changed, the 11 operators that I referred to earlier, certain considerable number of things have changed in the completion strategies.

Obviously higher proppant loadings by some operators, other operators have gone a different route with different staging and different fluid systems. We have looked at all of that stuff. We have a favorite that we think yields the best results. And by that I mean 70,000 barrels or so per 1,000 feet of lateral is kind of an estimated target for us to go back out into the tighter spacing and stack/stagger opportunities in the Eagle Ford.

We think that is certainly achievable given all the data that we have seen. So, we have a particular approach that we want to take and that is -- but I don't want to give you any more detail than that right now.

Great, thank you for all the comments.

Ray Deacon, Coker Palmer.

Mack, I was going to ask you about the Claybrook well and the Pace James well, just what you are seeing with the higher sand loadings in terms of pressure drawdowns and expected declines and whether potentially the 18.5 Bcf type curve might turn out to be conservative with using more sand?

That is a great question, Ray. It is pretty early in the game for me to give you a definitive comment on it. I can tell you that the initial performance of the wells, it is awfully early. I mean the James Pace has only been on for about 2.5 months. The Claybrook about 45, 50 days. And of course the Claybrook being a 4,500 footer, the James Pace being a 7,500 footer, they were both drilled in a different environment, meaning offset wells around them. So there was the depletion shadow, if you will, in fact influence.

So right now the pressure drawdown is kind of in our expectation window. We haven't seen any excessive pressure drawdown as a result. We are pretty pleased right now that we are on target with the kind of production profile that we anticipated.

But really we need six months in order to get firm data given the fact that one well was a 4,500 footer, and the other well was a 7,500 footer. And those were our first two 3,800 pounds per foot jobs and given the different settings that those wells were drilled in.

So, I can tell you right now we are very pleased with results and it is meeting our expectations, but we need about another six months of hard data -- production data to firm up things.

That is great. Thanks, Mack. And I guess where are you targeting with the JV acreage to -- will you stick in Caddo Parish with that and how big could it get? And I guess I was also wondering if Roland could kind of quantify the potential interest savings with the debt exchange and refinancing your other debt? Thanks.

Real quick, on our JV acreage, the 3,700 acres, the 10,000 foot laterals that we plan to drill, it will accommodate at least 20 10,000 foot laterals up there. And again, it does have the opportunity for expansion. And that work is going on right now. And it is in a variety of locations. So I don't want to really comment any more than that, Ray, about it, but it does have room to grow.

Got it, thanks. And I guess, Roland, just how much potentially, once you got the conversion done between the PIK and cost savings on refinancing the secured debt, could you improve interest expense?

Sure, Ray. Well, just the interest that is paid on the second lien notes is paid in kind, just the actual interest is around $9.5 million a quarter. And then there is this additional almost $10 million a quarter of really phantom interest that results from those bonds being recorded at $0.80 on the dollar when they first were issued just under the accounting rules. And in a $100 million gain being created and then the amortization of a discount back.

So that is dashed those are just accounting numbers that just show up as non-cash. So that is another $10 million. So a lot of interest will leave the income statement just with the conversion. And none of it is paid in cash. But then the cash interest the Company really has is related to its secured debt which is closer to $70 million on an annual basis. And we could pay in kind but don't budget to this year.

That -- the opportunities are there post conversion to look to refinance that at lower effective rates. So we would have to see where the markets are at the time. But that is a 10% type rate and for secure debt and for unsecured debt the markets today, when the balance sheet is stronger, should be substantial savings there in the future.

And that would be at the step two that we would hope to achieve to get the balance sheet back to completely healthy and getting the leverage ratio at our targets. But we think we are on the path to do that. We have all the tools to work with and it will take us time for Mack to get all this production on line. And that is what 2017 is all about. Can't have (technical difficulty).

Well, and another comment to kind of follow up on Mack, and he stated this earlier. But if you give us another three weeks, and maybe four at the most, we will have three additional wells flowing to sales and that is Gen 2 completed wells. I think a couple are 7,500 feet and another one is 5,000 foot. So we have drilled them and completed them, we are flowing them back. So again, we'll know that in another four to six weeks.

And then we will have consistency in 2017 that we didn't have an 2016. As Roland said, we did -- this time last year we had no rigs drilling. We started in March with a rig, we drilled three wells, laid it down until we could recap the Company which was September. Put a rig in September drilling and then one in November. So it was choppy last year. I mean that is why the year-end results were choppy, that is why we are looking forward to 2017 and the performance that we will deliver.

You have done an amazing job in the past year; it looks a lot better. Thanks.

Chris Stevens, KeyBanc.

I appreciate the comprehensive update here. If I could just follow up on the Eagle Ford a little bit. You mentioned you have an action plan ready for when you want to go back out there and start drilling. Can you just maybe give a little bit more color on exactly what it is that you will be testing out there?

Are you going to go into an area where the lower -- part of the lower Eagle Ford has already been fully developed and are you going to drill just a bunch of wells directly -- or I guess stagger/stacked above that? Is it going to be a single well, a few wells? Are they going to be I guess 660 feet apart or so? Just any color you can provide there?

Sure, I can give you a little bit. One is of course we'll be on tighter spacing. We'll be 300 feet or so away from adjacent wells. The other is that, yes, it will be a stack/stagger location and we'll also test, just like the operator that I mentioned in my discussion earlier, did with the two wells they drilled. It will be just an infill drilling opportunity, not a stack opportunity.

So we would like to test both options. And we have a variety of areas that we can do that in that we think hold tremendous potential. So the first thing we are going to do is look at where we have the best data set to guide us. When I say data set I mean the operators in the area, where have they drilled these kinds of wells? What were the results that they got? How does their geology compare to our geology? And then we will go forward.

But what I would like to do, and of course there is a lot of moving parts to this. But what I would like to do is to test in three different areas, the infill drilling opportunity versus the stack/stagger opportunity. We think we have both and so we would like to confirm that by drilling wells. We would like to take advantage of drilling two well pads for obvious reasons, cost efficiencies and economy of scale.

But as Roland mentioned earlier, that depends upon us making our Haynesville targets. We've got great economics in the Haynesville, so. But we know where we're going to go, we know what we are going to do when we get there. And so, giving you any additional detail would be like laying our total plan in front of you right now. And we are not quite at that point but we are getting pretty close.

I think the Eagle Ford, the unique opportunity there too is that we have made big investments in infrastructure, electricity, we have excellent facilities there. And so, this is a huge -- and production is much lower than it was back in its prime. It is a great opportunity to add a lot of new production and not have to make any of those investments for infrastructure that were already made back in 2013 and 2014. So I think it is going to be some compelling economics based on where oil prices are.

That is a great point, Roland.

Right, so that is definitely helpful information there. And I guess based on your newer sort of EUR expectations and in a $55 to $60 environment, how do you expect those returns to compare to the Haynesville at this point?

Well, quite well.

No, the Eagle Ford versus the Haynesville.

Oh, the Eagle Ford versus the Haynesville?

Yes, that is what he is saying.

Oh, well, the Haynesville is just knocking it out of the park. I mean, 70% rate of returns, give me a $3.00 price and we are over 100% rate of return with a 10,000 foot lateral. I mean it is just hard to compare the Haynesville to anything in my known universe. So the Haynesville is -- it is just hard to beat.

Okay, yes, that is what I sort of assumed. So just given the size of the opportunity set in the Haynesville, it would probably be difficult to put much capital to work out in the Eagle Ford. Is that an accurate statement? And I guess would the thought be that maybe you monetize it to accelerate some of the value of the Haynesville?

Well, I think on the Eagle Ford it is -- whether or not you deploy all your capital there to bring it all forward is a question to look at for the future. And again, it is what is the relationship between oil and gas? They are both very volatile. But I think for us, we want to prove up its value. We think it is very much an underappreciated asset that the Company owns now and the play in general. And we think it is going to get better.

And in the long run for the Company like the idea of having a diversified opportunity set not just oil, not just gas. So it gives us a very unique low-cost oil opportunity versus having to start a brand-new oil play that would come with a lot of other exploratory risk, infrastructure issues, etc., that we would do to have to add that in the future.

But, yes, so I think right now our idea is to get the property value more appreciated and it might take a little capital at least to demonstrate its potential is much more important than cutting -- trying to cut, sell it and just taking some capital into an asset that we already know has great returns.

Yes and that acreage is held by production. I mean 90% of it you don't have to drill the hole. So we are not going to lose it, it continues to be de-risked by other operators. And at the same time we really think we know what type rate of return we are going to have in our Haynesville and it is predictable, repeatable, we are focused there. And we have got a big partner there. So I think that's where we came up with this tremendous balance both on oil and gas and tremendous future.

Great, thanks so much.

Mike Breard, Hodges Capital.

Chesapeake has reported some excellent wells in Caddo County. How close is that to your joint venture acreage in Caddo?

It is about 8 miles to the southeast, Mike.

Okay. And then also on the JV, you said you are going to bring in a rig in the second quarter. Would that be -- do you have something, a rig in mind already or would it be early in the second quarter or late in the second quarter? Do you have any details on that yet?

Mike, we do have the rig under contract and we plan to move it into the area in late April into the Caddo JV area, that is our current plan.

Okay. Is there any chance you might drill a well on your own acreage and watch?

Yes, sir. Actually our plan is exactly that, to bring in the new rig, drill a well on our acreage. It will be probably around a 5,000 foot lateral test. And then after we finish with our well we will move it north to the Caddo area and start drilling our JV wells, 10,000 foot lateral wells.

Okay. And then also there has been some good Cotton Valley wells in Texas [near your] acreage. Do you think possibly you might be non-operating on some of that or that you might drill some of your own Cotton Valley wells?

No, we have a lot of Cotton Valley experience, as you know, Mike, and we certainly haven't let that fall off the radar either. But the rates of return that we calculate on a Cotton Valley horizontal are far less than the opportunities in the Haynesville, so that would be down the road for us.

Okay. Is there any chance you might sell that acreage to some of the active Cotton Valley drillers?

Heck, no. We like it, we want to keep it. It is HBP, Mike, so we are -- it is in inventory and it is an opportunity for later.

I think the key point though is -- Mike, you did bring up some important -- we do have that acreage. And years and years and years and years ago we had Hosston, Travis Peak, (inaudible) Cotton Valley. And the question is would we sell it and spend most of our money in the shallow waters in the Gulf of Mexico? And we said, no. And what happens below the Cotton Valley is the Haynesville.

So, I think that is -- why Mack is an old East Texas guy, he won't sell anything and I agree with him. So you never know where that next golden egg will come from and maybe it is Cotton Valley. So that is a very good point.

Okay. All right, thank you very much.

Thank you. That is all the questioners that we have in the queue at this time. So I would like to turn the call back over to management for closing comments.

Sure, thank you, Andrew. Again, I just want to stress that we are very appreciative of the 98% vote from the secured and the second lien holders and the 90% plus vote from the equity owners that we could round up to vote. It is an extreme vote of confidence in management when no one was forced to vote in favor of the recap proposal, no one. And it was clearly represented and it was based upon the results of the Haynesville.

I think we had to prove it up and I think we had to have good behavior, our entire corporate life as a management group, in order to have the support that we have out there. Again, we are appreciative of it, we will never abuse it and we will tell you the truth good or bad. When you ask Mack a question or Roland a question for me a question we will tell you what the answer is.

And we do take big actions. When things were looking bad after Thanksgiving of 2014 we told everybody we made changes, big changes. And as a result of that I think we have the call we have today. And the big changes have brought I think a really bright future to the Company.

If you look at natural gas, it was April a year ago, if you look at the five-year average gas in storage we were 60% above that. And today we are only 7% above that, that is pretty good. Even though we hadn't had a really bad winter we are still -- the numbers look good.

Even though gas has pulled back $1.00 or so in the last several days we're still very profitable. As Mack said, a $2.50 gas price, a $3.00 gas price, we get a 50% to 70% to 100% rate of return. And unlike last year we are going into this summer with a hedged portfolio too. So world-class gas asset with world-class bondholders and equity owners, we are thankful. Thank you for listening to the conference call.

Ladies and gentlemen, thank you again for your participation in today's conference. This now concludes the program and you may now disconnect at this time. Everyone have a great day.