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

Don P. Crist - Johnson Rice & Co. LLC.

Good day, ladies and gentlemen, and welcome to the Comstock Resources First Quarter 2016 Conference Call. At this time, all participants are in a listen-only mode. Later, we will conduct a question-and-answer session and instructions will be given at that time. As a reminder, this conference is being recorded.

I would now like to introduce your host for today's conference, Mr. Jay Allison, Chief Executive Officer. Sir, you may begin..

Chelsea, thank you. Welcome to Comstock Resources' First 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 First Quarter 2016 Results.

I am Jay Allison, Chief Executive Officer of Comstock, and with me is Roland Burns, our President and Chief Financial Officer; Mack Good, our Chief Operating Officer. During this call, we will discuss our first quarter operating and financial results.

This continues to be a very difficult environment, as you all know, with the continued weak oil and natural gas prices. Our Haynesville shale program continues to deliver great results, but we do need higher natural gas prices to get the company back on track.

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

If you turn to slide three, a summary of our first quarter is outlined on slide three. Oil and gas prices continue to be weak. Our realized oil price fell by 40% and our average realized natural gas price declined by 25% in the first quarter as compared to 2015.

Our production was up 13% from the first quarter of 2015, but that was not enough to overcome the low prices of our oil and gas sales, as they fell by 44% to $37 million. EBITDAX came in at $15 million but was not high enough to cover our interest expense this quarter of $30 million. Our Haynesville drilling program continues to get better.

The 10 wells drilled in 2015 are performing above our 14 Bcf to 16 Bcf type curve. And our first well in 2016 had an IP rate of 23 million cubic feet a day and added an additional 5 million cubic feet per day from offset wells. As a result, our Haynesville production is up 144% over first quarter of 2015.

And also, we were able to bring our drilling costs down with this well coming in at $8.2 million. We're very focused on improving our balance sheet. We've retired $104 million in long-term debt so far in 2016, which saves us $8.4 million in annual interest payments and $27.2 million in total interest.

We have total liquidity of $139 million and expect to add to that with our pending asset sale. We have minimal drilling obligations in 2016 and no debt maturities before 2019. Roland will now go over the financial results.

Roland?.

Thanks, Jay. Slide four shows our natural gas production. Our Haynesville shale drilling program is driving the growth that we expect for this year. We started drilling again in March, so we expect gas production to increase again in the second quarter with three new wells coming online.

Our gas production averaged 152 million cubic feet per day in the first quarter, which was 67% higher than the first quarter of 2015. 10 million cubic feet per day of our production in the first quarter is from our South Texas gas properties that we plan to divest of this year.

We expect our natural gas production this year will average between 145 million cubic feet per day to 160 million cubic feet per day after the divestitures. On slide five we summarize our oil production. Our oil production averaged 4,600 barrels per day in the first quarter, a 60% decrease from the first quarter last year.

The production decline is due to the sale of our Burleson County properties in July of last year and shutting down the oil drilling program in our South Texas Eagle Ford at the end of 2014. With little drilling activity this year, we expect oil production to decline further.

We expect our oil production in 2016 will approximate between 4,000 barrels per day and 4,300 barrels per day. In slide six we show our hedge position, which hasn't changed. We have 10 million Btu per day of our gas production hedged at $3.20 per Mcf. We hope to be able to try to hedge 2017 as gas prices continue to improve in the longer term.

On slide seven we summarize the first quarter financial results. We had a 69% increase in gas production, offset by a 60% decrease in oil production in the quarter. But overall, production was up 13% on an equivalent unit basis. Lower oil and gas prices more than offset that production increase. Oil prices fell by 40% and gas prices were 25% lower.

Oil and gas sales this quarter were down 44% to $37 million, and EBITDAX was down to $15 million. We did see significant improvement on the cost side. Lifting costs in the quarter were down 12% with lower production taxes and gathering costs. And our G&A costs were down 30% in the quarter.

Our DD&A was down 58%, due to an improvement in the DD&A rate for the quarter. Our DD&A rate in the quarter was $2.36 per Mcfe, which improved 63% from the 2015 first quarter rate of $6.35 per Mcfe.

During the quarter, we had an impairment primarily related to assets that we are currently selling and due to some TMS acreage that will expire totaling $31 million. We also had a gain on the extinguishment of debt of $33 million. Including these items, we had a $57 million loss or $1.14 per share in the quarter.

If you exclude these items and some other non-recurring items, we had a net loss of $51 million or $1.03 per share. We've revised our capital expenditure budget, which is shown on slide eight, for the cost savings that we are now seeing in our Haynesville drilling program.

We commenced drilling in March with our very first 2016 new well in the quarter. The rig we're currently running now can drill about nine extended lateral wells this year. But we'll reevaluate where we stand with natural gas prices and our overall liquidity after we finish drilling the first three wells and may hold off drilling additional wells.

If we suspend the drilling after three wells, our total capital expenditures will be around $36 million. If we continue drilling throughout all of 2006, our total expenditures should be about $81 million.

And so our final capital expenditures could be anywhere within that range depending on the level of activity that we maintain after the first three wells. In the first quarter, we only spent $8.9 million on capital expenditures. Slide nine shows our balance sheet at the end of the first quarter.

We ended the quarter with $89 million of cash on hand and $1.230 billion of total debt outstanding. Including our undrawn credit facility, our total liquidity is around $139 million. In February, we retired $40 million of our senior notes by exchanging common stock for the bonds.

And in April and May, subsequent to the quarter, we've retired an additional $64 million of our senior notes for $3.5 million in cash and shares of common stock valued at $5.7 million. Pro forma for our senior note repurchases, our total debt is $1.166 billion.

We plan to continue to pursue strategies for retiring the bonds and reducing our interest expense. To-date, we've retired $234 million of our senior notes for $46 million in cash and 12.2 million shares of common stock.

These repurchases have generated annual interest savings for the company of $20.3 million with total interest savings to maturity of $81.9 million. I'll now hand it over to Mack Good for an update on the Haynesville drilling program..

Thank you, sir. Good morning, everybody. If you flip over to slide 10, you'll see our Cotton Valley, Haynesville and Bossier acreage outlines in Texas and Louisiana. As you know, we began drilling and completing significantly longer and better Haynesville wells during the first quarter of 2015.

And I think most, if not all of you, also know by now that our 2015 drilling program was extremely successful. All of our wells were high IP rate completions and confirm that our new completion design was the way to go.

Anyway, after drilling our 10th 2015 program well last year, we stacked our rig on the location where we planned to drill the first of our 2016 program wells. As planned, we resumed drilling with this rig during the first quarter of this year, and we will drill between three and nine wells this year using the same rig.

And no one should be surprised by the fact that we will try to use the same strategy that we did last year. We will make an effort to stack the rig after drilling our third 2016 program well, while we evaluate prevailing market conditions.

We'll resume drilling whenever we believe the market will support the resumption of drilling additional Haynesville or Bossier horizontal wells.

And if you move over to slide 11, you'll see that the current cost of services that Comstock has for a 7,500-foot horizontal Haynesville well completion can now deliver a rate of return between 24% to 48% at a gas price between $2 and $2.50 per Mcf.

As the slide also shows, we have a significant inventory of both Haynesville and Bossier horizontal wells for future development.

The way our Haynesville and Bossier acreage is laid out will allow us to drill at least 386 extended lateral Haynesville locations and 322 extended lateral Bossier wells, having horizontal lengths between 4,500 feet and 10,000 feet. The Bossier is worth an additional comment here after I've just talked about our Bossier drilling inventory.

You might remember that, during our last conference call, we mentioned that our last well of 2015 was the Jordan #1 and that it was an enhanced Bossier completion that was performing very much like our new Haynesville completions. After three more months of production history since that call, I can definitely tell you that nothing's changed.

Our Bossier well has a different production profile than our Haynesville type curve, but it's important to point out that it's currently producing above our Haynesville type curve with very little pressure drawdown after about 120 days of production.

There's no doubt in our minds that we have one of the best Bossier performers in the play and that our extended lateral drilling and enhanced completion ideas for the Bossier will allow us to repeat this success going forward.

One last thing I want to say about all of our gas production and drilling inventory is the same point we made during our last call, and that's to restate a simple fact that our acreage is close to the Henry Hub and that obviously means we won't have to suffer the long-haul transportation costs that others who are less fortunate might.

Turning to slide 12, you'll see 10 red dots scattered throughout the blue acreage outline that illustrate the general locations of our 10 2015 extended horizontal lateral program wells. The first nine of our 2015 wells were Haynesville completions and our final one, as I mentioned earlier, was the Bossier completion.

The red hatched area shows our bolt-on acreage that we added via our acreage trade with EOG. You can easily see where we've drilled our Jordan #1 Bossier test on this map if you just look for the southernmost red dot. This Bossier well IP'ed at 22 million cubic feet a day and is one of the best Bossier completions to-date in the play.

Finally, just to complete for you our 2015 project list, the yellow dots show the locations of our two 2015 Haynesville re-frac projects. The blue well location label shows the location of the Ramsey 4-9 #1, which is our first 7,500-foot horizontal Haynesville well of 2016.

Last week, we IP'ed this well at 23.2 million cubic feet a day, and the well is performing as expected and it falls right in line with all of our other 2015 Haynesville wells. The average IP rate for our nine 2015 Haynesville completions was 23.4 million cubic feet a day, so the Ramsey IP obviously is right where we thought it would be.

We're currently completing our second 2016 Haynesville well right now and we'll report on that well during our next conference call. You can see on the next slide that all 10 of our 2015 program wells are producing at or above our Haynesville type curve.

And if you squint hard enough, you'll be able to see that the Jordan #1 well's Bossier completion started out producing below the type curve, but that it is now and has been for the last 70 days or so producing well above it.

Obviously, and not surprisingly, the Jordan well's Bossier completion is following a different production decline profile than our Haynesville completions.

And as I mentioned before, we just need a little more production history to establish and confirm that production profile so we can build a new Bossier type curve and an EUR expectation level for different lateral length completions.

So right now, suffice it to say that all of our completions are following a production profile that meets or exceeds our expectations.

I know that slide 14 has been presented before, but we're presenting it again since it shows the baseline cost and performance metrics for each type of horizontal Haynesville wells that we have in our drilling inventory.

The big difference in the current version of this, not in all previous versions that we have shown, is that it shows a significant reduction in our drilling and completion costs for each Haynesville completion lateral length.

For example, we can now drill and complete a 7,500-foot lateral Haynesville well for $8.5 million rather than the $9.5 million that we've listed before. In fact, our most recent Haynesville completion, the Ramsey 4-9, is estimated to have a drilling and completion cost of $8.2 million.

Anyway, the $1 million reduction that we have gained here is a direct result of a lower drilling rig day rate, a faster drill time to TD, resulting from an upgraded drilling rig configuration, and lower frac costs.

The lower overall D&C cost structure has allowed us to achieve better project economics, and slides 15 to 16 will demonstrate this for you. So let's go to slide 15. Slide 15 shows the ROR that can be achieved at different flat gas price levels for our various Haynesville horizontal wells.

Since you have already seen that all of our wells are at or above our type curve, we think this graph paints the current economic floor for our projects. As you can tell from the graph, our 7,500-foot and 10,000-foot Haynesville lateral completion RORs are about the same at all gas prices.

At a $2 per Mcf flat gas price deck, the 7,500-foot completion has a 24% ROR, while the 10,000-foot completion has just under a 26% ROR. The reason for this is pretty simple. We're being very conservative estimating the future cost of our first 10,000-foot horizontal Haynesville wells, since we have not yet drilled and completed one yet.

Even though we've lowered our 7,500-foot D&C costs from $9.5 million to $8.5 million, or about a 10.5% reduction, we're currently projecting a 6% cost reduction for our first 10,000-foot lateral completion. Still, I'm confident that we will be able to drive the costs down as we gain experience executing our 10,000-foot lateral projects.

I'll point to the cost reduction history we've achieved for our 7,500-foot laterals as the reason that I'm confident. Slide 16 is the same kind of graph as shown in slide 15, but it shows how the NPV at 10% discount changes with gas price.

At a $2 flat gas price deck, the NPV is about $3 million for the 7,500-foot lateral completion versus a little over $4 million for the 10,000-foot completion. If the gas price deck is moved to $3 per Mcf, these projects will generate $10.3 million and $13.9 million NPV 10 respectively.

After all I've just said about the 7,500-foot and 10,000-foot Haynesville completions, you might wonder why I didn't say anything about the 4,500-footers. I wanted to focus on the project types that are in our current program.

But there is no doubt that a 4,500-foot Haynesville lateral completion continues to be economic even if the gas price deck falls to $2. You can see that the value jumps for this completion length at $2.50 when the ROR jumps to over 30% and the NPV is $2.8 million.

I guess I should say that we enjoy the luxury of having a significant inventory of these projects waiting for us. Well, that pretty much covers my side of things. So I'll send it back to Jay before I wear out my vocal here..

Roland and Mack, again, as always, thank you. If everyone would look at slide 17, that's our plan for 2016. Kind of as a synopsis, after Thanksgiving in 2014, Comstock flipped the page and really began a new business plan, a new chapter. In the first quarter of 2015, we began drilling and completing extended lateral Haynesville wells.

As Mack said, all 11 of our wells have been successful, including our extended lateral Bossier well. We currently have 348 operated extended lateral Haynesville/Bossier locations.

On our acreage, they can deliver a rate of return between 24% to 48% at a gas price between $2 and $2.50 per Mcf, which is where the gas market is today, including the 12-month strip today at $2.68.

In addition, we have 350 Haynesville/Bossier horizontal locations, as Mack said, that are 4,500 foot laterals that will yield a 30% rate of return at a $2.50 gas price. Mack Good and his staff have delivered operation perfection thus far.

They have de-risked our Haynesville and Bossier drilling inventory by delivering repeatable and predictable results. On the financial side, in the first quarter of 2016, we only spent $8.9 million drilling and completing wells, leaving us with total liquidity, as Roland said, of $139 million currently.

We hope the proceeds from the sale of certain of our non-core gas properties that we are marketing today will help fund the drilling program this year. We are also working with several investors that we've known for years. They could provide new capital to help fund our drilling activities and help improve our balance sheet.

We will continue to attempt to reduce our long-term debt with more repurchases and exchanges. In fact, during the past 16 months, Roland has done an excellent job retiring $234 million of our senior notes, generating annual interest savings of over $20 million with total interest savings to maturity of almost $82 million.

What that really means, in a short sentence, it means that we have retired one-third of all of our unsecured bonds in the past 16 months. We continue to improve every aspect of our business from drilling and completion efficiencies to EURs per well.

You see we have a Tier 1 acreage position and a Tier 1 gas field that yields phenomenal returns even in the current market that we operate in.

Our goal to each one of you, whether you're a bondholder, a debt holder, an equity owner, is to keep you informed of the details of where we are and a glimpse of where we are headed in this tough oil and gas market. We thank you for listening thus far.

I'll turn it back over to Chelsea for questions really from the research analysts who follow the company.

Chelsea?.

Thank you. And our first question comes from the line of Don Crist with Johnson Rice. Your line is now open..

Good morning.

Jay, you touched on it briefly on slide three, but can you give us any details on the asset sale process, like when we should assume an announcement on that and the discussions ongoing on the JV that you talked about on the last call?.

Yeah. I mean, my comments, Roland can add to it, the same group that delivered the buyer for our East Texas Eagle Ford acreage is in charge of selling it. Our conventional gas in South Texas that we've probably owned for 20 years is probably 10,000 acres. It's 11 million Btu a day production....

10 million Btu..

10 million Btu a day production. We've had a data room – I can tell you that there's 60-plus parties that have signed CAs that are interested in looking. We've had the data room completely full of people. We think it's a very marketable property because it's very predictable. We haven't spent hardly any money in the last 10-plus years on it.

So it does have a lot of upside. I think we'll start getting results back for what the offers might be at the end of this month, and then we would close it shortly thereafter. On the price ranges, fortunately gas prices have gone up during the marketing process.

So the price ranges kind of vary, but we think we should get a fair offer for that as we did when we sold our other properties in July of last year. Then on the JV area, we've looked at maybe JV-ing the Haynesville/Bossier. We've had some very, very interested parties that we've known for a while and some new faces.

If you, Don, look at the results, it's pretty easy to figure out why you'd like to JV the area. Particularly as Mack said, where it's located, we don't have the firm transportation issues. We've got hundreds and hundreds and hundreds and hundreds of locations. We don't have to drill any wells.

What we're trying to do, though, is to maximize value for the stakeholders and decide should we do a JV, if so what size and how accretive is it to Comstock today, not a year from now but today, again because our total focus is on our liquidity. So Roland might want to add to that.

I don't know if we can add much more to that, Roland, that we should talk about..

I think that we're working in those areas, but we of course don't have anything definitive to share today on those processes. I would think that toward the end of the second quarter we would hope to wrap up the sales process with an executed agreement..

Okay. And one for Mack, if I could.

The upgrades that were done to the rig, how did that impact your well cost? And what I'm driving at is how much of those savings are forecast to stay in place from an efficiency standpoint once commodity prices rebound and we could get some price escalation on the cost side?.

Well, that's why we listed $8.5 million rather than $8.2 million for our 7,500-foot lateral D&C. To answer your question specifically, we did upgrade the rig, the rig pumps. We went to a larger drill stream. We increased the mud motor on the drilling assembly.

And as a consequence of making those changes, we can drill faster, so our drill times have come down. And as you know, time is money in the oil patch when you're drilling. So about half of our savings that we've realized are from the upgraded drilling operation that we have, and the other half is as a result of lower frac costs.

And so we do expect, once the commodity prices rebound, that there will be a slow escalation of service costs. But certainly, the drill time reductions and the completion strategy that we have now where we're able to frac three to four stages a day whereas when we first started we were fracking two stages a day.

So that saved us a substantial amount of money. Those efficiencies will stay in place. So I guess to specifically answer your question, we do expect some price creep, cost creep upward, but it will be a slow process because of the efficiencies that we've baked into our game plan here..

I think the other thing Mack and his group and LaRae and the Land group has been doing, if you come to the Comstock office, I mean nobody is like Eeyore. I mean, everybody is working. We're all growing.

In fact, if you look at the trade that we've reported in the last quarter where we exchanged acreage in our South Texas Eagle Ford for some Haynesville acreage, I mean we added 33% of the lateral locations. We added 39 locations total. So we're adding to our drilling locations, and we're doing that as we speak today.

We're trying to have acreage exchanges. And the great thing about that is, when you do that, it's a win-win for offset operators. They have more acreage with the longer extended laterals that are drillable and so do we. So we're aggressively working on that and continue to add locations.

I think my only comment is when Mack and the group were completing the Bossier we didn't use the same completion technique in the Bossier as we did the Haynesville. So if you're a newcomer out there and you're trying to do Bossier wells, it's going to take a little while to learn how to do that.

I mean, we have been dead-on perfect so far, knock on wood, for both our Bossier well and the Haynesville program. So those are all good things. In a market that you're in today, even though our balance sheet is stretched, we know that and that's why Roland has been working really hard to help cure that, you have to have Tier 1 properties.

I mean, if you don't have a Tier 1 property, the battle is pretty hard because you end up with inferior properties even if you have an unstrained balance sheet. We've got a Tier 1 property. We've had it for a long time. Again, Mack, in his early days in 2008, drilled 135 4,500-foot Haynesville wells. We've been doing it a long time.

We kept the acreage, it's held. And I think as a plus, we do have the 83 locations in our South Texas Eagle Ford when oil prices come back a little bit. So it's a pretty good blend. The only thing that's outstanding that's harsh is the leverage we have and that's the interest expense.

And we've been trying to handle that a little per quarter as you see, but we have been doing that, so..

I appreciate the answers. I'll turn it back to you, Jay..

Thank you. That does conclude today's question-and-answer session. I would now like to hand the call back to Mr. Jay Allison for closing remarks..

Again, I think the report that Mack gave and Roland gave, the goal is to tell you the details. It should tell you where we are and the choppy market that we're in, and it should tell you where we're trying to go.

And I think Don asked a great question, that is we're continuing to work our way out of the valley, we are, as all the big companies are, and we're working on our balance sheet. We've got a lot of allies there, and Roland has done a pretty good job in de-levering the company with the tools that we have. And we still have quite a bit of liquidity.

We didn't buy big properties that we had to keep rigs drilling. We don't have wells that we have to drill and not complete just to hold acreage. So even though the facts are – they're straining, I think we've managed them the best that we can to provide value creation the best we could in the market that we're in.

And everyone listening needs to know that we're all on our A game and we're working hard to make this work. It's a tough market. We've been through this for 30 years. We'll get through it. So thank you. Thank you, Chelsea..

Thank you. Ladies and gentlemen, thank you for participating in today's conference. This does conclude the program and you may all disconnect. Everyone have a great day..