Comstock Resources, Inc. (CRK) Q2 2015 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to Comstock Resources Second Quarter 2015 Financial Results Conference Call. At this time, all participants are in a listen-only mode. Later we will conduct a question-and-answer session and instructions will be given at that time. As a reminder, this conference call may be recorded. At this time, I would now like to hand the conference over to Mr. Jay Allison, Chairman and Chief Executive Officer. Sir, you may begin. M. Jay Allison - Chairman & Chief Executive Officer: Perfect, thank you, Saeed and welcome to the Comstock Resources second quarter 2015 financial and operating results conference call. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and downloading the quarterly results presentation. There, you will find a presentation titled second quarter 2015 results. I am Jay Allison, Chief Executive Officer of Comstock and 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 2015 second quarter operating and financial results and our plan for the rest of this year. This has been a tough environment for the sector and for us as well with a severe decline in oil prices. But the one major bright spot, the positive spot we have to share today with our stakeholders is the excellent results in our Haynesville shale program which Mack will review during this call. Please refer to slide 2 in our presentations 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 that such expectations will prove to be correct. If you will turn to slide 3 our 2015 Q2 highlights. This slide provides an overview that the second quarter where low oil and gas prices continue to negatively impact our financial results. Our realized oil price fell by 43% and our average realized natural gas price declined by 46% in the second quarter. The 10% increase we had in our gas production was not enough to overcome this low price as our oil and gas sales fell by 50% to $77 million, EBITDAX came in at $48 million and cash flow from operations at $15 million or $0.33 per share. Our operations on the first half of the year were focused on ramping up our oil drilling program and restarting our Haynesville shale program with our improved completion design. Our first five extended lateral wells in Haynesville were excellent with an average IP rate of 23 million per day per well. Our first two re-fracs of producing Haynesville shale wells were also successful and added bonus, which Mack will talk about in a moment, is the uplift seven producing wells got from the newly drilled wells where we had a 15 million a day gain in production. We are very pleased with the first five wells which were producing above our 15.6 Bcf type curve. We've taken several steps to both drive liquidity in this poor environment that we're in. In March, we completed a $700 million bond offering which paid off our bank credit facility and added liquidity to our balance sheet. In July, we sold our Burleson County properties for $115 million. We have no debt maturities until 2019, and have total liquidity pro forma for the sale of $283 million. In order to safeguard our liquidity, we have significantly reduced our drilling expenditures for the remainder of 2015. Please refer to slide 4 in our presentation where we summarize our recent sale of our East Texas Eagle Ford properties. On July 22, we completed the sale of our East Texas Eagle Ford operations to a private firm for $115 million. We sold these properties to enhance our liquidity after we decided they were non-core due to disappointing drilling results. We would have been required to drill two or three wells next year to retain all the leases in the oil window, proved reserves related to these properties were 3.9 million barrels of oil equivalent. We received good value for the undrilled acreage in the oil window in this transaction. These properties produced 267,000 barrels of oil and 649 Mcf of gas in the first six months of 2015. This represents about 9% of our total oil and 2% of our total gas production. We did realize a loss of $112 million on this transaction for this quarter. I'll now turn it over to Roland Burns to review the second quarter results in more detail. Roland? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: Thanks, Jay. On slide 5, we recap our oil production. Oil production averaged 10,200 barrels per day in the second quarter which was a 17% decrease from the second quarter of last year. With the rapid fall in oil prices, we shut down our oil drilling program in late December and with little drilling activity planned for this year in oil, we expect oil production to decline further. In the second half of the year, taking into account the sale of our East Texas Eagle Ford properties, we're expecting oil production to average between 7,000 and 8,000 barrels per day. Slide 6 shows our natural gas production. With our new Haynesville well starting to come online, our gas production grew 10% from 2014 second quarter to 122 million cubic feet per day. Gas production was up 35% from the first quarter rate of 91 million per day. We expect our Haynesville production to continue growing in the next two quarters. For all of 2015, we estimate our gas production will average between 125 million cubic feet per day to 150 million cubic feet per day. We recently added some natural gas hedges at $3.20 per Mcf starting in July for the next 12 months as detailed on slide 7. These hedges only cover 10 million per day of our gas production, but it represents a start to the hedge position we're seeking to build for 2016 to support our Haynesville drilling program next year. On slide 8, we summarize our second quarter financial results. We had a 10% increase in gas production offset by a 17% decrease in our oil production in the quarter. This combined with 45% lower oil prices and 46% lower gas prices caused our revenues, cash flow and EBITDAX to decline. Revenues this quarter were down 50% to $77 million, EBITDAX was down to $48 million, and cash flow was $15 million or $0.33 per share. Lifting costs in the quarter were up 6% with additional cost that we had to add artificial lift to our oil production. But our DD&A was down 4% due to improvement in our DD&A rate this quarter. Our DD&A rate in the quarter was $5.43 per Mcfe which improved 14% from the first quarter rate of $6.35. Our G&A cost were down 25% to this quarter to $7 million. During the second quarter, we incurred a loss from the sale of oil and gas properties of $112 million related to the East Texas Eagle Ford sale and we had impairments on oil and gas properties and unevaluated leases of $25 million. We also had unrealized hedging gains of $600,000 and a net gain on extinguishment of debt of $7.3 million. Including these charges, we had a $135 million loss or $2.93 per share this quarter. If you exclude these items, we had a net loss of $51 million or $1.11 per share. Slide 9 summarizes the financial results for the first half of this year. For the first half this year, oil production was down 4% and our gas production was down 9% from 2014. This combined with the 50% lower oil prices and 47% lower gas prices caused our – again caused our revenues, cash flow and EBITDAX to be lower. Revenues for the first six months were down 52% to $144 million, EBITDAX was $88 million, and cash flow was $35 million or $0.76 per share. Lifting costs for the first half of this year were down about 5% with the lower sales numbers and our DD&A rate was just down slightly. Our general and administrative costs decreased 16% in the first half of this year to a total of $15 million. And we had – the unusual items for the first six months we had the loss on the sale of $112 million. Total impairments of properties and unevaluated leases of $66 million and we had drilling rig termination fees we paid at $1.8 million. We also had an unrealized hedging gain of $600,000 and a net gain on extinguishment of debt of $4.5 million. Now with these charges, we had a $214 million loss or $4.64 per share for the first six months this year and without these items, we had a net loss of $100 million or $2.18 per share. On slide 10, we detail our capital expenditures so far this year. We spent $169 million on drilling and exploration activities excluding $7 million that we spend on acreage. Spending in the second quarter fell to $48 million as compared to the $129 million we spend in the first quarter. We expect spending to decline further in the second half of this year to a total of $68 million. As shown on slide 11, our budget remains unchanged for a total of $248 million to be spent on drilling and exploration and acreage acquisitions. As Mack will explain it and as we currently plan to do fewer refracs but may substitute another new well on our Haynesville program for the amounts budgeted for the refracs. Slide 12 recaps our balance sheet at the end of the second quarter. We had a $130 million of cash on hand and about $1.4 billion of total debt outstanding on June 30. The pro forma for the sale of the East Texas Eagle Ford assets in Burleson County, we would have cash of $233 million and on that basis our net debt would represent 56% of our total book capitalization. We no longer have a bank facility that's limited to burrowing base and we are not subject to any upcoming redeterminations for the next several years. We do have a four-year $50 million bank commitment. So our total liquidity pro forma for the sale is about $283 million. We have retired $16.8 million in face amount of our 9.5% bonds so far in the first six months of this year for a cash payment of $7.8 million and we recognized the gain of $9 million on these repurchases. We'll continue to repurchase some of our debt this year at attractive prices but will balance that opportunity with maintaining adequate liquidity to get through this down cycle. Our first debt maturities do not come due until 2019 giving us a long runaway to survive this cycle. I will now hand it over to Mack Good.

Thanks Roland. And good morning, everybody. As you and Jay have already indicated today, we're currently focusing on executing our Haynesville high deliverability gas projects and I think that our first and second quarter results confirm that our new drilling and completion approach is the right one. It's definitely providing both repeatable and predictable results. Slide 13 shows locations of 69,000 net acres in Haynesville and Bossier Shales. It also shows that we have nine new Haynesville wells planned for the year along with 14 refracs, I'll talk more about the refracs in a minute. During the first quarter of this year, as everybody knows, we completed our previously drilled Eagle Ford oil projects and we quickly move toward executing the first of our extra long lateral Haynesville gas well projects. Slide 14 summarizes why we're focused on Haynesville. As part of this effort, we significantly changed the previous completion design strategy that we and everybody else had commonly used in the past on the shorter lateral length Haynesville wells. We did this so we could better place more profit per foot at lateral length, better stimulate the reservoir and improve gas recovery rates and EURs. In fact, we announce the results from our first two wells in the first quarter confirming that we were on to something. Both of these first quarter wells had a lateral length over 7,400 feet long and then an initial production rate over 20 million a day. As evidence of the many opportunities we have in Haynesville, we've mapped 704 Haynesville locations on our acreage including 91 with extended laterals. In addition, we have 532 Bossier locations including 108 with extended laterals. And last but not least, we have also prioritized 186 refrac candidates within our Haynesville and Bossier assets. As of today, we have drilled and completed five horizontal Haynesville shale wells this year using our new design as shown on slide 15. Each have lateral lengths of at least 7,400 feet and each received a 30-stage fracture treatment using a total of over 20 million pounds of propane and each of this new wells have delivered over 20 million a day in initial production rates. Our current total drilling and completion costs for our extended lateral Haynesville wells is around $10 million and we believe that we are going to be able to lower this to $9.5 million in the very near future. During the second quarter, we continued our Haynesville success by completing three additional wells in the DeSoto Parish, Louisiana and within our Logansport field area as shown on slide 16. Just like our first two wells in the first quarter these three well also have lateral lengths over 7,400 foot long and IP rates over 20 million a day. Just to summarize, thanks for everybody, I'll quickly give you the stats on these three wells we completed in the second quarter. We drilled the Boggess 5-8 #1 well to a vertical depth of 11,306 feet for the 7,430-foot lateral and tested at an IP rate of 21 million a day. After that we drilled the Horn 8-17 #2 well to a vertical depth of 11,216 feet for the 7,400 foot lateral and it also tested with an IP of 21 million a day. Our third well, the Harrison 30-19 #1 well was drilled to a vertical depth of 11,405 feet for the 7,437 foot lateral and it tested with an IP rate of 24 million a day. During the second quarter we also continued to investigate the refrac potential within our Haynesville well inventory. We performed our secondary frac by retreating the Bagley A #4 using around 4 million pounds of proppant and diverter material to restimulate the well and this well IPed at 3 million a day which was a six fold increase over its production before the refract. We will continue to monitor this well's performance in order to gain an estimate of the incremental EUR benefit on the well. On slide 17, we plot our 15.6 Bcf type curve for our extended lateral Haynesville shale wells. As you can see, all of our wells are producing above this type curve. So, we're obviously very pleased with the results. Not reflected in the EURs assigned to the new wells is the increased production and pressure increase seven offset wells near our first four new Haynesville gas wells. The offset well production currently amounts to an additional 15 million a day. So far each offset wells production profile is following its original decline but at a much higher rate and pressure. We will continue to monitor the offset well production in order to evaluate the long-term EUR benefits to each well. We will also see if wells near our fifth well are positively impacted and we expect them to be. As for refracs, the efforts by numerous operators and service providers to refrac wells above the Haynesville and Eagle Ford this year is definitely providing a slow but steady improvement in both refrac candidate selection methods and refrac treatment designs. We believe that a large number of our wells in both our Haynesville and Eagle Ford plays will benefit from a refrac. But given the prevailing low oil prices and the fact that we're seeing significant offset Haynesville well production boost from our new completions, we've decided to postpone our refrac projects. As a result of postponing our refrac program, we have the option to use the amount budgeted for these projects to drill an additional well, as Roland mentioned earlier. And with that, I'll turn it back over to Jay. M. Jay Allison - Chairman & Chief Executive Officer: Mack, thank you, Roland, thank you. If you were to go slide 18, our plan for 2015, I will summarize our plan for the rest of the year. We're still on the exact same path that we presented with our last conference call as our Haynesville program is exceeding our expectations as Mack just showed you. Our achieved results are demonstrating that our improved completion design has substantially improved the economics of the Haynesville play. We have a vast resource play in the Haynesville with our 6 Tcf of reserve potential and over 1,200 mapped drilling locations. The play is near the Gulf Coast market which offers premium price realizations compared to other regions in the country and unlike most Haynesville operators we are not burdened by expensive above market gathering and firm transportation obligations. We've a good inventory of all oil projects, to pursue once oil prices improve and stabilize including 105 future operated Eagle Ford shale locations and 327 future operated Tuscaloosa Marine Shale locations. We'll continue to maintain a low cost structure as we have one of the lowest overall cost structures in the industry and are working to lower our drilling and overhead cost wherever we can. We will continue to safeguard our balance sheet and with the recent closed shale of our East Texas Eagle Ford properties we have $283 million of liquidity and have significantly reduced our spending for the rest of the year to conserve this liquidity. For the rest of the call, we'll take questions only from the research analysts, who follow the company. Saeed, I'll turn it back over to you.

Thank you. Our first question comes from Kim Pacanovsky from Imperial Capital. Your line is open please go ahead.

Yeah. Hey, good morning everyone. M. Jay Allison - Chairman & Chief Executive Officer: Good morning, Kim.

It was a bold move to return to the Haynesville and I know there were a lot of doubters out there but you are starting to see dividends now. So congratulations on that. I just wanted to talk about the uplifted offset wells. If they do indeed continue to behave with the normal decline, and just so you assume maybe the credit of one offset per virgin well, what would the IIRs look like at – I'm sure you've modeled this out at – pick a $10 million cost and a $3 gas price, how does that improve the IIR of the new drill well?

Kim, if you just look at the production boost from the seven wells and assume what you just mentioned we're looking at a – at a $10 million cost, we're looking at around – at $2.50 gas, looking about a 30% rate of return and at $3 gas close to 48%. So, and that's at a $2.50 rate.

Okay, great. Not too shabby. And are your IIRs fully loaded?

Yes.

Yes. Okay, good. And then on the cash, the cash actually dropped more than I had anticipated this quarter. And I missed Roland what you said about what was spent on repurchasing the bonds, but can you just go through that and also if there's been a change on the payables? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: Yes, Kim. The question on the change in cash, I think this quarter is when we saw a pretty significant change in working capital and as we went from a much larger 4 rig to 5 rig drilling program to a 1 rig program there's a big, big change in the kind of the accrued cost related to that program, which we saw almost all of that happen this quarter. So, that was about $57 million of working capital turnaround which is most of the $60 million we kind of expected with the change in the capital program. So, I think this quarter saw most of that velocity in spending kind of run through on the cash balance. We did spend, as you point out, a few dollars on repurchasing some bonds also in the quarter, but the biggest change...

What was that amount, Roland? What was the amount repurchased – or the amount you spent actually? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: That we spent? We spent about $7 million in the second quarter of cash...

Okay. Roland O. Burns - President, CFO, Secretary, Director & Senior VP: ...to retire about $16 million of bonds.

Okay, great. And I'm just going to sneak one more in. As you start to move East in your acreage, what are the expectations for how these wells will behave as you move further East in acreage?

We anticipate the same level of performance Kim. There's no reason based on the geological mapping that we have to believe they would perform otherwise.

Great, all right. That's all I have.

Thank you, ma'am.

Thank you. And our next question comes from Don Crist from Johnson Rice. Your line is open. Please go ahead. Don P. Crist - Johnson Rice & Co. LLC: Good morning, guys. How are you? M. Jay Allison - Chairman & Chief Executive Officer: Hi, Don. Don P. Crist - Johnson Rice & Co. LLC: I'll just start on the bond repurchases; what is your appetite going forward? I mean, I know you have $233 million pro forma and you want to keep some liquidity going into 2016 but what is your appetite given that your bonds are trading pretty low right now to repurchase more of those? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: Yeah, that's a good question and that's a balancing act that we have to do. It's a great opportunity to retire debt at the – where the bonds are trading for. Of course, the bonds are hard to get. So, it's not easy to execute on because it's very small volume in the bonds. But with the sale, we think we can get a little more aggressive on that, but we'll have to balance that. We're trying to target to end the year with – our goal is to end the year with $200 million of liquidity, or mostly $200 million of cash. So we are kind of – as the year progresses decide how much of the sales proceeds we can use toward retiring additional bonds. Don P. Crist - Johnson Rice & Co. LLC: Okay. Roland O. Burns - President, CFO, Secretary, Director & Senior VP: (24:05) but again, also target to keep good liquidity at the end of the year. Don P. Crist - Johnson Rice & Co. LLC: Right. And just to touch on the refrac program, I mean it's been an excellent program but I know you've run into some challenges with working interest partners, et cetera, trying to come up with capital to fund that program on their part. But looking towards 2016, would you – given the current environment and where it is and commodity prices if they – assuming they stay where they're at today, could you drop your operated rig and go to a refrac program solely to conserve capital and further protect your balance sheet?

Well, I think we have that option, that's certainly the case. We have so many refract candidates that offers that opportunity up but on the other hand with one rig, several offsets that are positively impacted by the completion, so in effect you get that free benefit from a refrac. So, again, I think it will be a mixture of taking advantage of the opportunities in front of us rather than all of one and none of the other. Don P. Crist - Johnson Rice & Co. LLC: Okay. M. Jay Allison - Chairman & Chief Executive Officer: Don, we look – the four wells, Mack, talked about or you have seven offset wells that have a 15 million net production increase I mean that's almost like a free well. Our IP rates come in at 20 plus million, little north of that and we pull them back so there is 15.5 Bcf type curve, it's almost like after that fourth well with those seven offset wells being materially impacted, you get a free well which goes back to Kim's economics. So, we didn't know that going into first quarter, we really didn't put going into the second quarter and as we compared our results with some other operators in the area, you found out that those results are real. So, we go into a 2016 budget, we'll factor that in too. The problem with the refracs which we're big proponents of refracs both in the Haynesville and our South Texas Eagle Ford is that when oil and/or gas prices are lower. It's a little hard to do that because the (26:30) from the non-operators is dried up and it's really hard to get consensus. So, it's not an issue whether they work. We're two out of two. I think some other companies in the Haynesville area reported they've had great success. So, it's not a question of success, I think they work better if prices are little higher just because you can get the consents from the non-operators.

Just to add something real quick to what Jay just mentioned, we're not solely focused on the Haynesville refrac program, we also have opportunities in the Eagle Ford and of course, low oil prices the economics are not quite as appealing as we would like them to be. So once we get a little help in the marketplace, you will see us in the Eagle Ford doing some refracs. Don P. Crist - Johnson Rice & Co. LLC: Okay. And one more if I could sneak it in? Can you tell me what your current AFEs are on your most recent refrac and the new drill wells right now in Haynesville?

Yeah. Refrac AFEs are around $2 million in the Haynesville and the drilling compete on our 7500 foot laterals is around $10 million and we anticipate being able to move that down toward the $9.5 million range in toward the end of our program this year. Don P. Crist - Johnson Rice & Co. LLC: All right. Thank you. That's all I've got. Thanks. M. Jay Allison - Chairman & Chief Executive Officer: Thank you, Don.

Thank you. [Operator Instruction] Our next question comes from Gregg Brody from Bank of America. Your line is open. Please go ahead.

Good afternoon, guys. Nice work on the Haynesville wells. I was curious, you've laid out there's 90 prospective extended laterals in DeSoto. What's the – how many of those do you think you've de-risked with the five wells you've drilled and how do we – how do you expect to de-risk the remaining over the next year or two? And maybe you can talk about the Bossier wells as well if you're going to go after those?

Well, we haven't completed our planning for FY 2016 because of the variables involved but certainly we have a number of opportunities there in Y2015. We're currently drilling our sixth well, we'll be on our seventh well by the end of the month. We have a short lateral Haynesville well planned for the ninth well and as mentioned, we have an optional 10th well that we're considering we can drill either a short lateral, long lateral Haynesville well or look at a long lateral Bossier well. So, we're evaluating those cases. Back to Y2016, right now we're looking at the same kind of program in Y2016 perhaps pared down a little bit but we haven't firmed anything up.

Do you think is there a way to quantify what you've de-risked?

Well, a lot of the de-risking and you're talking about the extra long lateral Haynesville wells?

Yeah, I think that sort of the 90 you've listed there and then on the Bossier you have 108, right?

A number of the – the Haynesville largely been de-risked by the short lateral wells we've previously drilled. We have significant geological mapping, significant hard data from wells that have already been completed. So going into the program in Y2015 of the extra long lateral program, we were extremely confident that we were going to see the type curve achievements that we've seen and, in fact, as shown earlier, we're exceeding those expectations. So largely, just to be real quick with the answer, we've derisked the Haynesville previously and now we're taking advantage of the technological enhancements from drilling the longer lateral and completion techniques.

That's helpful. And then just coming back to the bond buybacks, could you remind us what the governor is for you? What's the limitation today on buying back bonds and did you get any amendments from your bank lenders to do up to a certain amount? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: Yes, Gregg. The limiter is probably in our new credit facility as the common bank facility has limitations on lots of transactions that you just get permission for and including the sales, so we obviously got permission to complete the Burleson divestiture in the bank with a bank amendment and we also increased the amount that we can spend on debt retirement of any type to $50 million.

So you (31:40) $50 million. Roland O. Burns - President, CFO, Secretary, Director & Senior VP: If we looked at other type of transactions, we simply would go to the banks and ask permissions, but that's kind of where we are right now.

And that's $50 million of total spending or face value? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: No. Of total spending.

And your second lien bonds don't restrict that in any way? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: No, that's – yeah, they obviously don't restrict buying themselves back, yeah.

Great. Thank you for the clarification. I am going to hop off.

Thank you.

Thank you. Our next question comes from Chris Stevens from KeyBanc. Your line is up. Please go ahead.

Hey, guys. Great job out there in the Haynesville, I was hoping you guys could maybe quantify some of the efficiency gains that you are seeing out there. What was the spud to TD on the latest well? How does that compare to the first well? And then as we get into 2016, how many wells do you think you could drill at the one-rig program?

You wanted to know what the TD on the last well that we drilled, is that right? M. Jay Allison - Chairman & Chief Executive Officer: The drilling time?

The drilling time.

Yeah, the drilling times.

Okay, I am sorry. I misheard your question. We've been seeing – right now, we are pretty efficient. We are seeing the spud to spud in 33 days, 34 days. Meaning, spud one well, drill it to the 7,500 foot or so lateral TD, rig down – set casing rig down, move to the next location, and about 34 days is the interval. So we've pretty much got it down at this point. And the second part of your question was what?

Just how many wells do you think you could drill in 2016 with the one-rig program?

About 10 wells. One rig could drill 10 wells to 11 wells.

Okay. And, I guess, when your rig comes off the contract, I guess, how much do you expect to save on your well cost and is that already factored in, I guess, at this point on the $9.5 million, is that what will get you there?

No. Actually that isn't factored in in the $9.5 million. What we're looking at there is some savings on type and a little bit more savings on the frac side of the cost equation. The rig rolls off contract in mid November and the savings on subsequent wells based on current rig rates is around $250,000 to $300,000 a well.

Okay. And, I guess, are you trying any other differences in the completion of the design out in the Haynesville, are you trying to increase the amount of proppants or anything like that?

Well, the first five wells that we've completed, we've stayed with the program because we wanted to really measure the impact of our design, we didn't want to deviate too much from it. Now we're considering – right now, it's 3,000 pounds proppant per foot of lateral length, which is pretty high, but we have talked about increasing the proppant loading just a little bit to see if there's an impact there. We've talked about a possibility of drilling a 10,000 foot lateral in certain cases. That's probably a next year project when we dive into that. We like the fluid system that we're pumping. We like the overall completion strategy of about 250 feet per stage with the five clusters, you heard all this before. We think we're getting the right kind of proppant loading and the right kind of stimulation on the reservoir along that 7,500 foot lateral length. So we don't want to deviate too much. It's the old saw, if it's not broke, don't try to fix it. We're doing real well with the program we've got now, but that does not mean we won't make some changes as we get a little more information coming at us.

All right. Yeah, the well results had been good so far.

Yeah, sure.

If I could just add one more in here? The transportation expense out in the Haynesville, I guess, what's the cost on the incremental volumes at this point and, I guess, what's good to use on a go forward basis? Thanks. Roland O. Burns - President, CFO, Secretary, Director & Senior VP: Yeah. We are in the process of finalizing some new – and actually maybe terminating early some transportation arrangements, but they are not 100% final yet. But we are hoping to have a lot of that in place by the fourth quarter. But generally, we are targeting transportation costs in the neighborhood of $0.15 to $0.20 versus our historical $0.35 that we have incurred. One thing, we've always had enough volume, so we haven't had to pay for unused transportation because of the way we structured our deals. But as they expire, the market is really low now, it's really a buyer's market for gathering and transportation services in the Haynesville, so we're able to take advantage of that to lower our cost structure. So think about that, given if we're successful in getting some of those in place earlier, we can kind of see those rates maybe show up in the fourth quarter.

Okay. Thank you.

Thank you. We have a follow-up question from Kim Pacanovsky from Imperial Capital. Your line is open. Please go ahead.

Yeah. Hi, again. Just wondering if you have any information on Chesapeake's 10,000 foot lateral well. I wasn't on the call this morning, so I was just wondering if you have any update on that. And also if you could tell us where that location is?

Kim, I don't have any information about it and the specific location of the 10,000 foot lateral is to our east, but I can't tell you specifically how far to the east.

Okay. And then just a follow-up on the G&A. What are some of the reasons for the large improvement in the G&A expense? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: Kim, this is Roland here. I think it's mostly lower personnel cost. I mean, we're continuing to trim staffing and have pretty much – obviously have a hiring freeze and...

Yeah. What's the year-over-year employee count, Roland? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: I think overall we're down, I think in total in the neighborhood of eight to nine people.

Okay. Roland O. Burns - President, CFO, Secretary, Director & Senior VP: And we'll continue to evaluate our staffing. I think, as we go forward with the smaller CapEx program, we might see additional reductions there. Definitely, as we have retirements and other attrition, we're not replacing that. So I think depending on the environment and what type of program we run, but we're targeting to continue to see G&A be reduced. M. Jay Allison - Chairman & Chief Executive Officer: We had 130 employees, 135 employees at the beginning. Roland O. Burns - President, CFO, Secretary, Director & Senior VP: Right. M. Jay Allison - Chairman & Chief Executive Officer: And we probably have 120-plus employees. We're probably down... Roland O. Burns - President, CFO, Secretary, Director & Senior VP: Yeah, we're down about 10 people. M. Jay Allison - Chairman & Chief Executive Officer: Yeah. That's about right, which...

Okay. M. Jay Allison - Chairman & Chief Executive Officer: ...if you think as a percentage wise it's a lot, and we're continuing to look at that.

Okay, great. That's all I have. Thanks, guys. M. Jay Allison - Chairman & Chief Executive Officer: Thank you.

Thank you. Our next question comes from Gregg Brody from Bank of America. Your line is open. Please go ahead.

Hey, guys. Just a couple of follow-ups, if you don't mind. Just on sort of the side fracking that's taking place, what are you looking for to understand how that may impact the well over time and are there any analogies that you can think of that you can explain to us that will help us understand what to expect in terms of their sort of risk to the well performing differently than you would think?

Well, I can tell you what we've seen. What we've seen is that every well that we've jut in prior to the frac that we pumped on the new Haynesville extra long lateral well, with that exception, every well offset to that new well has benefited from the frac, depending on the distance away from the new well. And you have to keep in mind that every well that we're talking about has a horizontal lateral and so the lateral length of the offset well is shorter than the lateral length of the new well. So there's overlap, meaning, only part of the old offset well lateral is covered within the frac envelope of the extra long lateral length. Does that make any sense?

Yes.

Okay. So, when we frac the new well, only part of the old well is subject to the impact of the new frac, and again, depending on distance. So, we've been able to pretty accurately predict now after the fifth well – we've been pretty accurate in being able to predict which wells are going to be impacted the most and we've developed ranges internal to Comstock – ranges of expectation on the boosted production per offset well. And so far, as I mentioned earlier in my presentation, the offset wells are producing above their original declines at higher rates and higher pressures. So, we continue to monitor the overall performance profile of those offset wells to determine just how they're going to extrapolate out over time. But, right now, it's a very, very low risk opportunity to get additional production from the offset wells. Now the further away, the offset well is from the new frac, the less the impact, obviously it make sense. And what we think is happening is, we're re-pressurizing the reservoir with the new frac. We're also reconnecting the old fracture system in the offset wells and that's what, simply put, is giving the old well the opportunity to benefit.

And then when you mentioned the returns that you were talking about, you said $10 million per well. Was that, were you effectively saying, drilling on extended lateral, I've added this range of side frack production on and that's the return you're coming up with or is it (43:07)

Well, what the assumption was that we're getting 15 million a day of preproduction basically without cost. So, if you add that back into the five wells, you get the additional benefit. The other way that we look at it, we haven't added that in a specific way. We've kept that on the side because we want to evaluate, totally evaluate the – or better evaluate the boosted production before we make an assignment, an allocated assignment of the offset well production to the new well EURs. But, obviously, we're getting additional production, it's been over 100 days on some of the offset wells. The performance appears to be holding steady. So, obviously, we're getting that economic benefit, but until we get a little more production data, we don't want to assign the economic benefit over to the new wells. Not to add anyone.

All right. And your – the cost guidance that you have in your presentation for the year, I think it's $145 million for lifting cost. Does that assume the benefits of these sidetracks or is there a potential upside to lowering that number as a result of that?

There's potential to lower the number, that's for sure. It just depends on the level of the impact.

Got it. And is any of that reflected in this number today or is it versus not?

I don't believe so.

All right. Thank you very much for the explanation. It's good to hear your voice back.

Yes, sir. Thank you. We appreciate it.

Thanks, guys.

Thank you. Our next question comes from Chris Stevens from KeyBanc. Your line is open. Please go ahead.

Hey. Thanks for letting me follow-up here. Obviously, the opportunity in the Haynesville, the resource is very large out there, I was hoping maybe you could just quantify a little bit the opportunity in the Cotton Valley out there on that acreage and I know is that something you could monetize while keeping the Haynesville rates?

Well, we like the Cotton Valley a lot. Obviously, a number of wells were drilled through the Cotton Valley completed in the Cotton Valley and held at production. They gave us the Haynesville – held the leases, pardon me, that gave us the opportunity to access the Haynesville. But in terms of drilling horizontal wells, that's an in-house assessment that's ongoing right now. Given the current market environment and are trying to be very careful with our liquidity, and we haven't posited a Cotton Valley opportunity. We feel like the bigger returns is on the Haynesville extra long lateral wells that we're drilling. So, but to try to answer your question, we believe there's significant Cotton Valley opportunity within our Haynesville area holdings that we can access later. As far as divesting them, that's always a continuing evaluation depending on a lot of different factors. But certainly one of the, just as an operator, I don't particularly like the idea of having someone on top of me while I am out trying to drive wells through the Haynesville of 7,500 foot, 10,000 foot lateral lengths. We like the Cotton Valley where it's held by production, so to sell that while we are taking advantage of Haynesville is down on my list, but I've learned never to say never.

Okay. M. Jay Allison - Chairman & Chief Executive Officer: I think the answer is, we do have 20 plus million a day of Cotton Valley gas. We have Hosston and Travis Peak in Cotton Valley, we think it's very valuable. It's very marketable. We have request all the time, companies wanting...

That's right. M. Jay Allison - Chairman & Chief Executive Officer: ...to buy it and we've perpetually said no. And we do have about 20 million a day of gas in South Texas, which is very valuable also and we've got the TMS as upside, and then of course we've got a very good inventory slate in our South Texas Eagle Ford. And as you know, we drilled those wells on 80s and South Texas Eagle Ford, a lot of the operators were drilling those wells on 40s, we haven't done that either. So, there is a lot of upside plus you can add the 1200 locations in Haynesville/Bossier. So, even though the world of energy is pretty terrible, particularly if you are a microcap, small cap E&P company, we're riding the wave as strong as we can.

Okay. And I guess just thinking about your borrowing base, as you go and you're developing this economic resource in the Haynesville, how do we think about the growth and what your borrowing base could be through next year? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: Well, Chris, we don't have a borrowing base at all, so I mean we don't have that type of facility in place. But I think over time, we can put one of those in place. So, I think as you grow the reserves into next years' environment and that may be something we'd look to do, to do some refinancings of our other debt. M. Jay Allison - Chairman & Chief Executive Officer: But, again, we always said if you remember in 2012, we had about 500 Bcf of Haynesville reserves that were on the books that there were future reserves that we were drilled based upon the drilling program. When natural gas hit $1.90 in May of 2012, of course at the end of 2012, we took them off. We didn't lose any of the acreage. So as Mack is de-risking the extended lateral Haynesville today and then just a normal lateral well than Haynesville and then maybe a Bossier well, I do think we have some pretty meaningful reserves and we can add back on the books at a materially different economic cost. So, those are all good things.

All right. I appreciate the time guys. M. Jay Allison - Chairman & Chief Executive Officer: Yes sir, thank you.

Thank you. Showing no further questions at this time. I would like to hand the conference back over to Mr. Allison for closing remarks. M. Jay Allison - Chairman & Chief Executive Officer: Thank you, Saeed. And, again, there is a lot of competitive companies today that you get to listen to. So, all the listeners there I thank you for listening and to be supportive of Comstock and asking really good questions. Again, I think the extended lateral Haynesville results have exceeded our type curve, we're pleased to report that. Our Haynesville refracs are really working. The balance sheet is as strong as it's been all year long. We do have excellent natural gas inventory in the Haynesville with 1,200 locations in Haynesville/Bossier. And as someone had asked, we also have Cotton Valley assets. We have deep gas in South Texas. And in the future when oil prices comes up, we've got a very good inventory of oil projects and our South Texas Eagle Ford. And then no one mentioned it, but in the future we do have the TMS that we've held, we've got 81,000 or 82,000 acres there. So, with that I thank you for your time and again, we'll give you our best day's work every day. Thank you.