Comstock Resources, Inc. (CRK) Q1 2015 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the First Quarter 2015 Comstock Resources' Earnings Conference Call. My name is Derek, and I'll be your operator for today. At this time, all participants are in a listen-only mode. We shall facilitate a question-and-answer session at the end of the conference. As a reminder, this conference is being recorded for replay purposes. I would now like to turn the conference over to the Chief Executive Officer, Mr. Jay Allison. You may proceed. M. Jay Allison - Chairman & Chief Executive Officer: Derek, thank you. Welcome to the Comstock Resources first quarter 2015 financial and operating results conference call everyone. 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 First Quarter 2015 Results. The highlight of this call really will not be the numbers we report today, you've seen those, but really the return of Mack Good as our Chief Operating Officer, and his overview of the company and our position. After 3.5 year break, Mack has returned to help us navigate through these difficult times with low commodity prices. I am Jay Allison, Chief Executive Officer of Comstock. And with me this morning in addition to Mack is Rowland Burns, our President and Chief Financial Officer. During this call, we will discuss our 2015 first quarter operating and financial results and our plan for the rest of this year. If you go to slide two, please turn to slide two 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 and such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. Slide three is a quick overview of the first quarter where we saw the rapid fall of both oil and gas prices. Without hedges in place, we felt the full brunt of the rapid decline in oil and gas prices in the first quarter as our realized oil price fell by 53% and our average realized natural gas price declined by 47%. The 11% increase in oil production was not enough to overcome the low prices of our oil and gas sales, fell by 53% to $67 million, EBITDAX came in at $40 million, and cash flow from operations $20 million or $0.43 per share. Our operations in the first quarter were focused on ramping up our oil drilling program and restarting our Haynesville shale program with improved completion designs. Our first two extended lateral wells in Haynesville were very successful as both had IP rates in excess of 20 million cubic feet per day as Mack will go over in detail in a few minutes. Our first rig frac in a producing Haynesville Shale well was also successful and was featured in Schlumberger's earning call. We expect to start growing our gas production again in the second quarter of this year. In March, we completed a $700 million bond offering, which paid off our bank credit facility and added liquidity to our balance sheet. Our goal was to establish a fortress balance sheet to weather this down cycle. We now have no debt maturities until 2019, and we have total liquidity of $279 million at the end of the first quarter. In order to safeguard our liquidity, we have significantly reduced our drilling expenditures for the remainder of 2015. I'll have Roland review the financial results with you in more detail. Roland? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: Thanks, Jay. On slide four, we recap our oil production growth. Our oil production averaged 11,500 barrels per day in the first quarter, an 11% increase over the first quarter of last year. With the rapid fall in oil prices, we shut down our oil drilling program in late December. We experienced some delays in completions planned for our East Texas Eagle Ford property in the first quarter, and we had excessive downtime for offset fracs and artificial lift installation in the quarter, which caused our oil production to decline from the fourth quarter rate of 12,400 barrels per day. With little drilling activity this year planned for our oil projects, we expect oil production to decline further. For all of 2015, we're expecting oil production to average between 9,500 to 10,500 barrels per day. Slide five shows our natural gas production, which continued to decline in the first quarter of 2015 and was down 25% from 2014's first quarter. Gas production in the first quarter averaged 91 million cubic feet per day. Our Haynesville production was down a little more than expected due to the delay in completing our first extended lateral well. In addition, we had to shut in some production in March while we completed our first two extended lateral Haynesville wells. We expect the Haynesville to start drilling again in the second quarter. For all of 2015, we expect our gas production will average 130 million to 155 million cubic feet per day. On slide six, we summarize the first quarter financial results. The 11% increase in oil production was not enough to offset the 25% decrease in our gas production in the quarter. This, combined with 53% lower oil prices and 47% lower gas prices, caused our revenues, cash flow and EBITDAX to decline. Revenues this quarter were down 53% to $67 million, EBITDAX was down to $40 million, and cash flow from operations declined to $20 million or $0.43 per share. Our lifting costs in the quarter were down 14% with the lower sales. However, our DD&A was up 3% due to an increase in our DD&A rate in the quarter. Starting next quarter, we'll see some benefit from our new Haynesville program, which will help lower the DD&A rate. Our G&A cost in the quarter were down 5% to about $8 million, and we also had two significant accounting charges in the quarter. We recorded a $41 million impairment on our unevaluated properties for our southern Burleson County acreage due to poor drilling results. We also had a charge of $1.8 million included in exploration expense for payments made to release one of our operated rigs and a charge of $3.7 million for the early retirement of our bank credit facility, which was offset in part by a $1 million gain on the repurchase of $2 million of our unsecured bonds. Including these charges, we had a $78.5 million loss or $1.71 per share. Excluding these items, we would have a net loss of $1.06 per share. On slide seven, we detail our capital expenditures in the first quarter. We spent $121 million on development and exploration activities, not including the $1.7 million we spent on acreage. We also spent an additional $1.8 million to release the operated rig before its contract term expired. In the quarter, we drilled five horizontal oil wells, or four net to our interest; two horizontal natural gas wells or two net to our interest. We also put four South Texas Eagle Ford wells and four East Texas Eagle Ford wells on production in the quarter. In March, we announced our plans to release another drilling rig and reduce our capital budgets to $248 million, which is detailed on slide eight. We estimate that we'll spend $238 million this year for drilling and completion activities, $95 million of that will be spent to drill 9 Haynesville shale extended lateral wells and another $23 million will be spent to refrac 14 of our producing Haynesville wells. We also budgeted $30 million to finish drilling four wells on our East Texas Eagle Ford shale acreage that were in process at year-end and we budgeted $50 million for completion cost of eight Eagle Ford shale wells that were drilled in 2014 but will be completed this year, and $40 million on facilities recompletions capital projects. The spending was heavily weighted to the first quarter with almost half of the budget being spent in the first quarter. Slide nine recaps our balance sheet at the end of the first quarter, which includes the $700 million bond offering we completed in March. We have $229 million of cash on hand and about $1.4 billion of total debt outstanding. Net debt represents 53% of our total book capitalization. We no longer have a bank facility that is limited to a borrowing base. We do have a new $50 million four-year bank commitment that is not subject to reduction based on a borrowing base redetermination. So, our total liquidity at March 31 was $279 million. We chose to do a larger bond offering due to definitions in our existing bond indentures, which made a second lien facility and a borrowing-based bank credit facility unworkable for us. This new structure removes any concerns over future reductions in borrowing capability for the company. Our first debt maturities do not come until 2019, giving us a long runway to survive this down cycle. I'll now hand it over to Mack Good, who we're very happy to have back at the helm of our operations during these difficult times.

Thanks a lot, Roland. It's good to be back. And I'll tell you what, if you work in the oil and gas business, you're never bored. That's for sure. What's made my return a lot easier is the opportunity to work with all of the many talented people here at Comstock and we have a great team here, and I'm really proud – pardon me – I'm really proud to be part of it. Since coming back to the company, diving into the things, the first thing that hit me was all the economic opportunities we have within our East Texas and North Louisiana region. And as everyone can see on slide 10, we have 69,000 net acres prospective for natural gas in both the Haynesville and Bossier shales. This slide also shows that the acreage has 6 Tcfe of total resource potential and that every bit of it is operated by Comstock. Maybe some of you have seen this slide before. Slide 10 demonstrates the magnitude of the resource. I think, this was a good slide the first time we showed it and it's even better now and I'll tell you why. It's better now because we are very confident that given our current drilling and completion strategies, we can take real advantage of economies of scale at the completion level. By doing this, we become much more efficient and cost-effective in gaining production from our shale gas assets. I know that in this first quarter, we have proved this to be true to ourselves and our partners. And in addition, we've also identified numerous Haynesville wells that are excellent candidates for refrac. So, during the first quarter, we implemented a refrac program that could add additional production and reserves from our 186 producing Haynesville and Bossier wells going forward. I know that many of you might wonder, why we would go back to the Haynesville in this low price environment. The reason is pretty simple. Last year, our technical team became convinced that the return profile of our typical Haynesville wells could be greatly improved by applying the newest drilling and completion technologies, specifically extended laterals and larger stimulation treatments, pumps across more stages and within certain pumping guidelines are very common in all the active shale plays today. And using this approach, our new Haynesville wells have 27% to 47% rate of returns at natural gas prices varying between $3 to $3.50 per Mcf. Refracs of our existing wells have a rate of return that vary between 40% to 69% at natural gas price deck $3 to $3.50. So, the Haynesville makes sense for us because we have an extensive inventory of drilling and recompletion opportunities that we can execute with positive economic benefit within a low price environment. As evidence of these opportunities, we've mapped over 700 Haynesville locations on our acreage including 91 with extended laterals. And in addition, we have 530-plus Bossier locations including 108 with extended laterals. And last, but not least, our refrac program has identified approximately 186 refrac candidates within our Haynesville and Bossier assets. And we consider it a real benefit that our Haynesville gas is located within a premium gas market close to the Henry Hub. Comstock, unlike many of the other Haynesville operators, is not burdened by expensive transportation obligations. So, because of this, we can take advantage of a market with excess capacity. Moving on to slide 12, you'll see the results of our first three Haynesville projects of this year. All three are in our Logansport field area in DeSoto Parish, Louisiana near the state line of Texas. And let me give you some of the numbers. We began the year by executing our first refrac of a Haynesville shale well during the first quarter of 2015. Following the refrac, the Pace 33 #1 well in DeSoto Parish, Louisiana, had an initial production rate of 4 million cubic feet per day, which was an eight-fold increase from its 0.5 million per day production rate before the refrac. We're currently producing this well at a stable rate of 3.5 million cubic feet per day. We also recently completed our first two new extended lateral wells using our new completion strategies and design. The Pyle 6-7 #1 was drilled to a total vertical depth of 11,183 feet with a 7,598-foot lateral. This well was tested with an initial production rate of 26 million cubic feet per day, which is a new company record for us. The second well, the Shahan 5-8, was drilled to a total vertical depth of 11,233 feet with a 7,421-foot lateral, and this well was tested at an initial rate of 22 million cubic feet per day. We have our third lateral well that's currently being completed. A fourth well waiting on completion and we're currently drilling our fifth extended lateral Haynesville well, and all of these wells are in DeSoto Parish. On slide 13, we have a comparison of how our new extended lateral well design compares to the most common design that we and everyone else was using about five years ago. And as with any business, there's nothing that improves results like the development of better technology coming together with more and better evaluated information. So based on current service costs, our new design cost is between $9.5 million to $10.5 million to drill and complete. Given all of our work and the results of our new wells, we expect that our extended lateral wells will have ultimate recoveries approaching between 14 Bcf to 16 Bcf. This compares to the 5.5 Bcf to 6 Bcf range that we previously obtained drilling and completing the shorter laterals with very similar D&C costs. So we expect an initial rate from our new wells in the Haynesville to average around 20 million cubic feet per day with the new design that we're fracking the wells with. Slide 14 shows the expected economics of the new Haynesville approach and the sensitivity to capital cost and gas price. The program should generate a 27% rate of return at an initial well cost of $11 million at a $3 NYMEX gas price. As the well cost is reduced to around $10 million, the program economics improve significantly, delivering a 35% rate of return at the same $3 gas price. And our goal is to do these jobs, these new Haynesville wells, at a $10 million D&C price. Now, move on from the Haynesville to our South Texas Eagle Ford acreage. Slide 15 shows this acreage. We currently have about 24,000 net acres in the South Texas Eagle Ford where we have drilled 196 wells. In the first quarter of 2015, we completed four wells, 2.2 net that were drilled last year. And these wells had an average production rate per well approaching 750 barrels of oil equivalent per day; 90% of this was oil. These will be the last wells we will drill and complete in this play until prices improve, but we'll be ready when they do. Our technical team has mapped an additional 105 locations left to drill, and we also think that many of our earlier wells are excellent candidates to be refracked, and we are working on a plan to execute some of these re-fracs starting in the second quarter of this year. Slide 16 shows the acreage we've accumulated in Burleson County targeting the Eagle Ford shale. We have 32,000 net acres in this play. Recent drilling results that include the Lewis wells show higher than expected GORs and this has caused us to remap the oil window in our southern Burleson County acreage. As a result, we now feel that 58% or 18,400 acres are prospective for oil development. We've written off the cost of the gassy southern acreage this quarter. The northern acreage looks very good where we drilled the William and Henry well. We consider the William well one of the best wells drilled to-date within the play. And we believe that our oil window acreage is prospective for about 125 future drilling locations. Slide 17 shows recent activity on our East Texas Eagle Ford acreage. We completed four wells, 3.8 net in the first quarter. Three of these wells, the Henry A2, A3 and A4 wells had an average per well initial production rate of 764 barrels of oil equivalent per day. 80% of it was oil. Our Lewis A1 had an initial rate of 101 barrels of oil and 2.9 million cubic feet of gas. There are four additional wells, our Henry B wells that are cleaning up after the respective frac treatments. Moving on to the TMS; on slide 18, we outline our current lease position there. Our ownership is now up to about 82,000 net acres and our technical staff has mapped most of it as highly prospective. A significant portion of our leasehold is offset by some of the best wells drilled in the play to-date. Obviously with the drop in oil prices, we suspended our leasing and drilling activity in this play. But we do intend to retain most of our acreage position for future development once oil prices improve. Importantly, I also want to point out that we are preparing to reenter the play by continuing to actively participate in the TMS Consortium Group that was formed to exchange drilling and completion information between operators in this play. Our goal is to be technically ready and up to date so we can reenter the play when the time is right. So that's it, from the Haynesville through the Eagle Ford and on to the TMS. And now going full circle, I'll hand the baton back to Jay. M. Jay Allison - Chairman & Chief Executive Officer: All right. Again, thank you, Mack. If everyone would please turn to slide 19, I'll summarize our plan for the rest of the year. With the rapid fall in oil prices, we decided to refocus on our largest assets, as Mack said, the Haynesville shale where improved completion technology has potentially improved the economics of the play. We have a vast resource there with over 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. The Haynesville program will deliver strong natural gas production growth in 2015, while our oil program is on hold in this low oil price environment. With the oil prices improving and well cost declining, we have a good inventory of projects to pursue, including 230 future operated Eagle Ford shale locations, and in addition to that 327 future operated TMS shale locations. We'll continue to maintain our low-cost structures. We have one of the lowest overall cost structures in the industry. And most importantly, we'll safeguard our balance sheet in 2015 with oil and gas price uncertainty and our lack of hedges. We entered the quarter with $279 million of liquidity and we have significantly reduced drilling activities to conserve this liquidity. So for the rest of this call, we'll take questions only from the research analysts, who follow the company. So, Derek, I'll turn it back to you.

And our first question will be coming from the line of Kim Pacanovsky, Imperial Capital. Please proceed.

Yeah. Hey. Good morning, everybody. Good morning and welcome back, Mack.

Thank you.

If you look at the vertical results around your Haynesville acreage and your previous mapping, what percent of the extended lateral locations do you think would be as high of quality as the two wells that you just drilled?

Well, that's a great question. A considerable percentage. I don't have an exact number for you, Kim. I mean, we're – the 90 or so laterals that – extended laterals that we mentioned is just targeting a specific part of the Haynesville acreage that we own. We have significant assets, as you know, to the South. We would like to see a little higher gas price before we start drilling an extended lateral in those areas. But we have absolutely – really good confidence that we can extend these concepts throughout our entire acreage.

Okay. So the 91 locations are based upon the current commodity scenario.

Right. We have...

Okay.

...dozens and dozens in increments of $0.10 to $0.25 per Mcf, higher stable gas price that we can go for at that time.

Got it. Okay. And then on the refracs versus the new drills, obviously the rate of return on the re-fracs is much higher. How do you look at weighting refracs versus new drills? Is the weighting more heavily here toward new drills because there's spottiness with the refracs or because of logistical issues. Because it takes a lot more refracs to equal the same tick up in production as a virgin well. How do you look at that?

Well, Kim. You just identified all of the reasons why we target the new wells preferentially to execute the refracs it's a more labor-intensive, work-intensive set-up to get these wells ready to refrac, to get partner approvals, et cetera. We have numerous candidates. We have AFE circulating. We also have the same identified candidate list in terms of numbers in our Eagle Ford play. So, I think, the important thing here is to keep our options open. We're going to do several refracs in Haynesville this year. And as you know, we've budgeted several in the Haynesville and we also have a handful that we like in the Eagle Ford as well.

Okay. Great. And then one last question, if you could just give us your thoughts on the Bossier?

Well, the Bossier is extensive throughout our acreage and it really develops more strongly on our Southern side of the acreage that we operate. We have drilled several using older completion techniques with laterals less than 4,500 feet. 5,000 feet I think is our longest lateral in the Bossier play that has extensive opportunities for us going forward.

Okay. Great. M. Jay Allison - Chairman & Chief Executive Officer: Kim, when you drill the Haynesville, remember, you drill to the Bossier, and if you look at DeSoto Parish, its extended laterals again you mentioned the 91 in the Haynesville, and as we come up with 108 extended laterals in the Bossier, that's your several hundred extended lateral wells right there.

Okay. And there's – and how many of those locations would actually overlap?

A bunch. M. Jay Allison - Chairman & Chief Executive Officer: Yeah, do you have map, percentage?

I mean, we have – again, we don't have a percentage. I don't have the map in front of us.

Okay.

But it's significant.

Okay. Great. Well thanks a lot, guys, and congrats on those excellent two wells.

Thank you, Kim.

Your next question will be from the line of Ron Mills, Johnson Rice. Ronald E. Mills - Johnson Rice & Co. LLC: Hey, Mack, just a clarification on one of Kim's last questions, the 91 Haynesville and 108 extended laterals in the Bossier, that's not limited by – I guess, let me ask it better. Is that limited by unitization rules or is that just identified in I guess the better part of the area. What's the limiting factor there? I suppose the total is 700.

So, the limiting factor – sure, Ron. The limiting factor is basically how we set up the units so far. We have a number of additional units that can set up that we haven't done so yet for extended lateral development especially on our southern acreage. M. Jay Allison - Chairman & Chief Executive Officer: And remember, Ron, the return on – we think the laterals that you drilled per section now, I think, EP is doing that. Chesapeake is doing that. It's probably 4% less than the return we get on the extended laterals. That's what our guess looks like. So, if you get a 35% rate of return for $10 million well, that's extended lateral. You maybe get a 30%, 31% rate of return of just the section well. Ronald E. Mills - Johnson Rice & Co. LLC: But the point is that... M. Jay Allison - Chairman & Chief Executive Officer: It's not what we're looking at. And as far as the answer, the – say the 200 locations we have right now that's really based just upon acreage. It's not quality. It's just based upon acreage because it's kind of hard to get contiguous acreage back to back to give the right to have extended laterals. Ronald E. Mills - Johnson Rice & Co. LLC: Okay. All right. And then also on the re-fracs in the Haynesville, I know you – I think you had talked in the past about $1.5 million to $2 million, and you just – today you gave us an idea of economics. But, one, is that what your refrac cost you? Two, you have 13 more refracs planned this year. When are they going to occur? And then, three, any commentary on EUR uplift versus the production uplift that you've highlighted so far?

Yes. So, our increment EUR – I'll answer the last question first – the EUR uplift is over 2 Bcf, between 2 Bcf to 2.5 Bcf. We feel like the cost structure on these refracs, we can get it down to between $1.5 million to $1.8 million. And in terms of timing, we have two that are on our to-go list right now. We're prioritizing, for obvious reasons, the use of our money. We have several other AFEs that are circulating to partners. I'm waiting for another couple of weeks here, Ron, to see if some of these other AFEs are approved. And if so, we'll be doing another refrac this month. Ronald E. Mills - Johnson Rice & Co. LLC: Okay. Great. And then on the Henry well, anything – the batch of Henry wells that you mentioned in the release today, the 764 BOE per day compared to the original – the rate on the original well of 1,200 BOE per day, was there any differences in the way they were completed or flow back managed or any comments on that?

They were not completed appreciably different. We did manage the flow backs differently. We went very gradually to the average IP rate. We're a little more aggressive on the Henry A1 with the flow back. I think these wells – the other Henry wells would have done a 1,000 BEO per day, if we wanted to open them up much, but we decided not to do that. Ronald E. Mills - Johnson Rice & Co. LLC: Great. And then one last one, any – I know you've had legacy acreage in North Louisiana and you used to have a lot of Cotton Valley activity way back when. Any thoughts on prospectivity as the horizontal Cotton Valley in – coming from East Texas to North Louisiana heats up?

Absolutely. We've got – and I'm glad you asked that question because we've got a significant position as you know in the Cotton Valley. As a matter of fact, the production in the Cotton Valley is what held Haynesville and a lot of our acreage. So, we have it throughout the East Texas region and the West Louisiana, we've mapped numerous opportunities for horizontal drilling in the Cotton Valley, but it's HBP, Ron, so we're proceeding with the Haynesville program because of the high rate potential. Ronald E. Mills - Johnson Rice & Co. LLC: Okay. Great. Let me let someone else in. Thank you.

Yes, sir. Thanks, Ron.

Your next question comes from the line of David Amoss, IBERIA Capital.

Hey. Good morning, guys. M. Jay Allison - Chairman & Chief Executive Officer: Good morning.

Good morning.

I'm just trying to get a feel for the trajectory in LOE as you switch back to the Haynesville through this year. Can you just kind of give us your general thoughts about when that's going to dip and how much potentially?

Well, I'm looking at a nice little decrease in LOE not only because of the Haynesville rates. As you know, David, I'm sure you do, LOE per unit of production in natural gas play, dry gas play, it doesn't really need significant treatment to get it to market, it's pretty darn low. So, as we increase the rates, we'll be able to take advantage of economy of scales. I think, our LOE will go down by 10% or so, at a minimum. The other aspect of that is these are high-pressure, high-rate wells, they're not going to require compression. So that's another big advantage that we can take – get the benefit of, of course. Unlike some other situations where the wells fall off fairly quickly in terms of pressure and you need compression, these are totally different beasts. Roland O. Burns - President, CFO, Secretary, Director & Senior VP: And a couple of other cost factors on the Haynesville, the new wells are exempt from severance taxes for their first couple of years, so that will be a plus. And then our transportation rates to market, as a lot of our commitments are coming; some of them are expiring this year. We're going to – we're renegotiating some of them, and we have a lot of uncommitted gas now. So the transport rates are about a third of what they used to be. So, lots of positives as the new Haynesville gas comes in the numbers. Remember, none of it was in the first quarter, not one molecule. Those new wells came on in April. So, we'll see LOE improve and DD&A improve. So those are kind of the side effects from the Hayneville program. M. Jay Allison - Chairman & Chief Executive Officer: And we should be able to book some good reserves by year-end with all these wells being drilled.

Got it. Thanks. And then, Mack, another question on the Eagle Ford refrac. It sounds like you're going to have something planned for the second quarter. Does that mean you're actually going to go in and refrac a well in the second quarter? And then how many of those do you think you need before you get comfortable enough to add that to the program?

Well, David, that's – second quarter is our goal. That's for sure. We'd like to perform more than one Eagle Ford refrac in this quarter. In terms of the uplift, it'll – we have a number of models here, 20% rate of return, as you know, our hurdle rate for going forward with any project in this environment. And I always say, for today's conversation, that the preliminary economics that we've run significantly exceeds our hurdle rate. So, we're excited about the opportunity to go in refrac some of our older wells to get that uplift.

Got it. And then one last one, Jay. If you don't mind, just kind of relay out the decision matrix as you've seen the oil price come up, what are the commodity prices that would lead you to add rigs in various plays or move them around a little bit this year? M. Jay Allison - Chairman & Chief Executive Officer: I think, there's two answers to that. One, you have to tell me the commodity price for gas. And if we got a $3, $3.50 price right now, near-term gas is right at $2.90. So $3 gas price, $10 million drill and complete. If we get that down to $9.5 million, then you're looking at a 40%, 42% rate of return on gas, and you're going to add a lot of reserves. So if you look at that prospect and you say, well, what comparable oil price do I need to be competitive like that, then you got to start out with $65 oil and really go to $70-plus oil. Because we have – again, in the Eagle Ford, we've got 100 – we're thinking about 125 locations and another 105, so we have 230 locations. That's probably three years, four years' worth of drilling, I mean, particularly in the world that we live in today. So, we think we've a got a great inventory of Eagle Ford locations, and then at the same time, we do think Goodrich is de-risking the TMS. So we know we're right in the heart of the TMS. If they can continue to de-risk that for several years, we got another 300-plus locations there. And then you add that in to the 1,200 locations in the Haynesville, particularly the 200 extended laterals and we've got a really good kind of entrée of things that we can spend money on. And at the same time, we almost have $280 million of liquidity. And like Roland said, our CapEx budget this year, we almost spent half of that in the first 90 days, which is just not a good thing, but it's a fact and it's over, and now we're going to try to live within our cash flow. So, to answer that question, I have to – I've got no idea on the commodity prices. I like our oil upside. I like our gas upside. I like our realizations. I like our locations, and I like the fact that we haven't bought a big acreage position where you have to have four rigs or five rigs drilling to keep the acreage intact. In fact, the Haynesville HBP, South Texas HBP, we got to pay $3.5 million, I think, to keep our East Texas Eagle Ford totally intact, and I think, $7 million to the TMS, and we've budgeted that in our CapEx. So, I like our position. I don't like the fact that we have zero hedges. That's not a good thing; it's a bad thing. It showed up in the first quarter. But the one thing that did show up in the first quarter at the side of Mack is that what we thought we could do in the Haynesville work to mean, you can take a concept that the Chesapeake and others have said they've been participating in, then all of a sudden, we have our own wells, and like Mack said that probably one of the two best wells we've ever drilled for gas wells ever. And usually, your first well or two wells are not your best. So I think, the future is pretty good for Comstock. Hope that answers it.

It does. Thanks, guys, for all the commentary. Appreciate it.

Yes, sir.

The next question will be from the line of Brian Corales, Howard Weil.

Good morning, guys. M. Jay Allison - Chairman & Chief Executive Officer: Hi, Brian.

Question on the refracking in the Eagle Ford. Can you maybe talk about what the current production rates are of what you plan to refrac and what do think it can ultimately go to?

Sure. The wells that we're currently targeting are wells that make anywhere from 50 to 150 barrels of oil per day. We think we can get to a 5 to 6 times uplift on those rates. Those wells that we're targeting are on artificial lift. They're older wells. So, of course, we would get the artificial lift on the side of the road and prep the well for refrac, and the well would be flowing after refrac for a significant period of time. Typically, it's about six months or so, and then reinstall the artificial lift that we've set on the side.

Okay. Helpful. And similar type cost to the Haynesville?

Yes, $1.5 million to $1.8 million.

Okay. And then more on the Haynesville, I think, if I remember correctly, you all used to restrict the chokes and kind of have a flatter production profile. Can you talk about – I think, those were just test rigs. Do you have anything longer term at the extended laterals, and how do you plan to produce the wells? Are you going to kind of go back to the restricted choke? And I can't remember if it's 10 million or 15 million a day flat for a while. What's the thoughts there?

Well, rather than talk about rates, we'll talk about pressure drawdown at the completion.

Okay.

We're looking at – and we monitor this very closely. We don't want to exceed a certain level of pressure drawdown across the completion. So, that drawdown is what dictates the flow rate. Now, these wells that we brought on, and I'm glad you asked the question because the flowing pressures are so significantly higher than we anticipated, that we're able to flow these wells at a significant rate without violating our pressure drawdown window. So, right now, these wells IP'd at – one IP'd at 26, the other 22, and we're flowing them at around at an 18 million to 19 million a day rate. And staying within our pressure drawdown window. So, these – the results are more than just about the rates. It's about how can you flow the wells without putting excessive pressure drawdown across the completion, and across the network of fractures that you've created, thereby increasing. If you did violate your window, and the reason why the window is important, is that you don't want to risk damaging the completion by putting too much pressure drawdown across it. So, we're pretty conservative right now about how we're approaching it. So we're – and we plan to remain so going forward with the wells that we're going to complete. We're going to let the pressure drawdown dictate the rate that we flow the wells. M. Jay Allison - Chairman & Chief Executive Officer: And Brian, I think, Mack said earlier that our third well is halfway completed, and we're waiting to complete the fourth, and we're drilling the fifth. So, the program seems to be really, really, really working.

No, very helpful. Thank you.

Yes, sir.

Your next question will be from the line of Leo Mariani, RBC.

Hey, guys. Just to follow-up on the Haynesville here. Trying to get a sense of what the well cost were on those first couple wells. And you guys indicated getting these well costs down to $9.5 million to $10 million. Just wanted to get a sense if that included some service cost reductions to get down to those levels?

Sure. Yeah. We're taking advantage of the service cost reductions. If you look at this time last year, the same wells would have cost us $14 million to $15 million, and now we're talking $11 million, and we're going to $10 million. Obviously, the real benefit of getting the 7,500-foot laterals in terms of cost is the economies of scale. The cheapest part of the well is that last 2,500 feet on the lateral that we drill. So that's a fairly minor cost adder, but you're getting a huge cost savings in terms of just the D&C cost, Leo, when you look at the fracs. The fracs now are one-third to 40% of what they were costing just a few months ago. So we think we can get the cost down into the $9.5 million, $10 million range. As far as the first two, we were very, very conservative going forward with our estimates, and the first two averaged, one was $10.8 million, and the other one was $11.2 million. So that's where we came up with $11 million.

Okay. That's helpful. And I guess in terms of those first two wells, can you just let us know when did those come on line? Did those make the first quarter at all? It sounds like maybe they didn't, were those kind of early second quarter?

No. They were for the second quarter. We brought them on in mid-April. I think, the beginning of the second week of April was well 1, and then well 2 was the third week of April. Back to your original question on cost, the other thing that's amazing is that the drilling times are coming down, and we're talking with a 7,500-foot lateral. So, if you go back to our 5,000-foot lateral wells – one of the wells that we drilled of the three that we have now – or four, pardon me, one of them, we set a record for drill time, and despite the fact that it added another 2,500 feet of lateral line. So that's a big plus as well in terms of the D&C cost, Leo.

Okay. That's helpful. And I guess just getting back to your acreage position of 69,000 net acres, I wanted to get a sense if you had any breakdown of that acreage position by the different parishes? I'm trying to get a sense of how much of that is in DeSoto Parish.

We can get that to you later. I don't have those numbers in front of me. But we have a significant acreage position at DeSoto. That's for sure.

All right. Thanks, guys.

Okay. Thank you.

Your next question will be coming from the line of Jeffrey Campbell, Tuohy Brothers Investment Research.

Good morning. M. Jay Allison - Chairman & Chief Executive Officer: Good morning.

I'll start out with a couple of Eagle Ford questions and then I'll return to the refracs which have been a pretty popular subject today. I was just wondering, did you have any 30-day rates from either the South or the East Texas Eagle Ford completions in the first quarter of 2015, and if numbers aren't handy, can you qualify if the results are meeting your expectations?

30-day IP rates are probably in the range of 400 barrels a day to 500 barrels a day. And yes, they are meeting our expectations.

Okay, great. With regard to the Lewis well, did that well have any mechanical issues or was it just not a strong well?

We drilled it in a high GOR area and that was one of the wells that further defined the gassy window in the play.

Okay. So that actually provided some of the data that informed the impairments that you discussed earlier on the call?

Yes, sir.

Okay, great. Thank you. And finally with regard to the refracs, are you initiating any new perforations in these or is this entirely about repumping existing perfs and fractures, and I'd like to add to that, will refracking in the Haynesville differ technically from refracking in the Eagle Ford?

The answer to your first question is yes and yes. I mean, we're going to – we have refrac candidates that don't require additional perforations and then we have some others that do. I'm talking specifically about the Eagle Ford. So, we have candidates teed up on both sides of the aisle with regard to that. The Haynesville refracs – is that – was that your other question on Haynesville refracs?

I was just asking, the second one was just is there anything that will really meaningfully differ technically, because the Haynesville is dry gas, and I'm assuming some of these wells you're going to refrac in Eagle Ford are wet, right?

Yes, sir.

I was just wondering, is there any notable technical differences in refracking one over the other?

Yes. One of the differences is the proppant selection. The other is the use of 100 mesh, and I'm talking about the Eagle Ford. The proppant selection for the Eagle Ford is different from the proppant that we pump in the Haynesville. In the Eagle Ford, we use 40/70 and 30/50. In the Haynesville, we do not. It's all 40/70. The frac fluid in the Eagle Ford is a gel hybrid system, and – whereas the frac fluid in the Haynesville is slick, no gel, whatsoever, in order to carry the proppant. So there are some significant technical differences and the pumping schedules vary as well. But the trick is to get as high a proppant placement per cluster arrangement and per stage in both plays in order to improve the fracture network so that you get the uplift that you're really looking for.

That was great color. I appreciate it. Thank you.

You bet.

Your next question will be from the line of Dan McSpirit, BMO Capital.

Thank you and good morning. Just... M. Jay Allison - Chairman & Chief Executive Officer: Good morning, Dan.

Good morning. If I could revisit a few – with a few more questions on the refracs in the Haynesville shale. First of all, I just want to confirm that you stated you get as much as a 2.5 Bcf uplift for a drill and complete cost of anywhere from $1.5 million to $1.8 million. Is that correct?

Yes.

Okay. And so if I consider that, I come up with an implied F&D cost of somewhere in the neighborhood of about $0.70 an Mcfe versus something closer to say $0.60 on a new well, do you look at it the same way? I'm just trying to reconcile how capital should be going or why capital should be going to a refrac versus a new well?

Well, just a real quick response. I mean, we're talking about numbers that varied by $0.10 on a per unit basis. So, we've done one refrac and that was the result of our refrac. We were quite pleased with it. It compares favorably to other successes on refracs in the Haynesville. We certainly know that as we do more of these jobs, Dan, we're going to get better and better at it. We think the metrics are going improve right along with it. In terms of comparing it to a new well, with the refrac, obviously, you're pumping a job across the completion that's already received a frac. And so, you're using diverters in order to ensure that you open up the clusters, the stages that have been previously fracked. You know all of this I'm sure in your coverage of this whole business. So, the diverter placement and the pumping schedule is something that is evolving. And we've met with all of the service companies and going through the databases that they have and looking at different ways to improve the efficiencies of the refrac. So the bottom line for me is if for $1.5 million to $1.8 million or so I can get a 2.5 Bcf uplift incremental, and that's on just our first well, it's worth considering doing a few more in order to really identify how we can improve the process and get even better economics. Our new wells speak for themselves, I think.

Great. That's helpful, very helpful. I appreciate that. And if I could follow-up on the same subject of refracs, appreciating that you have limited number of wells here and with very limited production history, but do you see the shape of the decline curve or the first year decline rate being much different than that observed on a new well?

Well, it's a little early to tell. Give me about three months, Dan, and I'll be able to give you a much better answer. But right now, they seem very similar. Obviously, the rates on the refracs are much lower, so it's hard to compare a $20 million a day well to a $3.5 million a day well, but in terms of decline that we've got less than 60 days of history on. But right now, I can tell you that our type curve and all the modeling that's been done on both of those type of projects, we're right on type curves. So, no issues here.

Okay. Great. And what is the base decline rate of the company today and where do you see it, say, at the end of this year, or even the end of 2016 based on how capital is being allocated today? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: Hey, Dan. This is Roland. Yeah, the base decline in our oil is steeper because of the new – so many new oils and the transition to artificial lift for many of the oil wells happens this year. And so, when we make that transition and finish it, it'd be a lower decline. So, I think, we've always said that overall decline based on kind of a year-on-year basis is somewhere in the 30% to 40%. And gas is probably 18% kind of without the new Haynesville program. But as we add the new wells, I guess that will change. That decline rate will probably increase as these big new wells kind of take over a large percentage of the gas production.

Okay. Great. And a couple more, if I could squeeze them in. What is the cost to retain the 82,000 net acres in the TMS, and could you sketch for us the lease expiry schedule on that leasehold? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: This year, the cost for extensions is about $7 million, $7.5 million which we've budgeted in our budget. The rest of our budget is to do some extensions in our Burleson area. So that would retain the acreage. There's a few – if we can operate a unit in the TMS, I don't think we're going to make any great attempt to keep that acreage. There's a lot of units that we can operate in the TMS. So, a lot of them have extensions that can, over the next two years to three years, that can kick in. And so mostly that's how we're doing is using automatic extenders.

Okay. Great. Last one from me. And then beyond preserving liquidity, what do you see to be the way out in this low commodity price environment? For example, should an acquisition be contemplated where the balance sheet is maybe over-equitized in the process or is it just best to wait it out for higher prices? M. Jay Allison - Chairman & Chief Executive Officer: Well, we think we've got good assets. I mean, we need it to change the economic valuation in Haynesville, which I think the – and that's a key objective for this year, but I think the best answer for Comstock is to wait it out. I mean, there's – we got – we don't need new assets and we need a little bit higher commodity prices and there's a lot of other options the company can look at if we want to bring in partners as we proved up the quality of the assets. And – but with that, we put enough liquidity, we have it in place to wait it out. I think that's the best answer versus doing something that's very – not going to get an instant fix in this environment. And if we got one, it'd be very painful to the existing holders, so we would rather wait it out and then look to continue to improve the cost structure, improve the economics of the wells, build reserves in the Haynesville, our biggest asset, and look for opportunities to bring in capital, maybe do some non-core project assets sales. So just a variety of things, but an instant fix would be more commodity prices coming back up, and putting in some protective hedges for next year. Those are our goals for next year.

Got it. Thanks again for taking my questions. M. Jay Allison - Chairman & Chief Executive Officer: Thanks, Dan.

Your next question will be from the line of Gregg Brody, Bank of America Merrill Lynch.

Good morning, guys. M. Jay Allison - Chairman & Chief Executive Officer: Good morning.

Just some questions on the bond buyback. So, it was bought back a small amount, just $2 million. What's – is there a strategy to that that we should think about going forward? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: Gregg, there's not a specific strategy. I mean, they're an incredible investment opportunity, but we have to weigh that against preserving liquidity. And so as we look at – I think that this – we would like to be able to do more of that, but only have kind of a modest amounts that – we're budgeted for that without bringing in some – new sources of capital without using our existing liquidity. But again, maybe a strategy might if we have some non-core assets we can get a really good price for, that could provide some capital to – that would let us to retire that debt at a big discount like those are – it's obviously a compelling opportunity that we look at ways to take advantage of the best we can.

Do you have anything that you're actively marketing right now that you could sell that would help you to generate proceeds or something like that? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: We're not actively marketing any properties because of the commodity price outlook. We don't know if it's ideal time. But we are dealing with quite a bit of inquiries from – inbound inquiries on different properties and obviously looking at potential – to the extent they throw out a number that we think is good. So, I think, it's a possibility, but we're not actively pursuing an aggressive strategy until we kind of see some transactions clear the market and kind of get a good idea of what they can clear it at.

What's your understanding of your limitation as to what you can buy back in terms of bonds with respect to the new... Roland O. Burns - President, CFO, Secretary, Director & Senior VP: Yeah. There's a limited amount especially under the new credit facility we have. I think that number is like $5 million.

Got it. And then you mentioned living within cash flows, your goal. Could you tell us what your current production is today, and if you are, in fact, living within cash flow? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: I don't – we don't have the current production rate right now with all the new stuff coming on. But it's obviously big uplift to gas since none of those new gas projects were on in the first quarter from where we were in the – where we were earlier in the first quarter. As far as cash flow, I don't want – I think we're still slightly not within cash flow yet, not at the current commodity prices. I think that is a key since our shift to gas. I think, getting gas up to over $3, then we get pretty close. M. Jay Allison - Chairman & Chief Executive Officer: Yeah. That's our corporate goal.

And your realizations were a little bit different than historical. Is what you had last quarter what we should think about for the rest of the year, or is there something... Roland O. Burns - President, CFO, Secretary, Director & Senior VP: No. I think they have improved a lot. I think, last – first quarter was – one, the timing of production was given there were such rapid changes of prices in the quarter, it's a very strange quarter as far as realizations because production was at level throughout the quarter for either oil or gas. And you had a rapid change in prices. But as – I think, we'll see in crude realizations especially in the Haynesville where we're going to have better marketing arrangements with the new gas. Again, none of that was in the first quarter.

Got you. So, is it – the sort of – so to go back to historical levels of sort of 95% of NYMEX makes sense, and then take it back to pretty much 99% of crude oil WTI is the right way to think about it? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: Yeah. I think, when you look at differentials, and this is for the whole industry, not just us, I mean, using percentages is not the best way because a lot of embedded transportation cost and differentials are fixed. So, when you have low prices, it tends to – those become a bigger percentage. So I think that's also just kind of the relative nature of where we are at low prices. But those very few – I mean, very few of our transportation marketing arrangements are percentage-based. They're just actual deducts for hauling oil or transporting gas that are fixed in nature. So the percentages...

Got it. Roland O. Burns - President, CFO, Secretary, Director & Senior VP: ...will be different. Yeah.

But the improvement in oil prices, you're seeing some improvement? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: Yes.

I got it. And then just...

The best way to look at it is to take a number historically, and then I think you'll be a lot closer, not a percentage.

And just two quick ones for you. You mentioned lack of hedging. Are there any thoughts to maybe lock in some hedges on crude here with the move in oil prices?

Yeah. Obviously, the moves are getting us close to our targets for oil. I mean, it's probably going to be – I think our – for this year, the horse is probably out of the barn as far as getting good hedges in. But definitely, we're very – we've got targets that we like on both the oil and gas, and we'd like to have a hedge position that works for us for next year, but patient in putting it in place because often very low prices aren't going to be helpful at all. But definitely crude has made the biggest move to getting to the targets.

And then one last clarification. You laid out very nicely the opportunity in the Haynesville and the Bossier, but your – the Bossier opportunity, the 108 wells, is there a chance you get to that this year at all? And maybe just one other, just the refrac opportunity. It sounds like you have second-half-weighted, is there a split between Haynesville and Eagle Ford that we should think about?

I think on the Bossier, yeah, I think given a limited amount of projects that we have in the budget, I don't see the Bossier – trying to do a Bossier well this year. If we do it, it might be late in the year. And on refracs, the mix is kind of – I think a lot of it will be up to logistics partner approval. And then the first kind of seeing how the first Eagle Ford refrac comes together. The one factor in refrac is if we do have a partner, it takes a 100% approval because it's an existing producing well. And then we've got other considerations. If we're doing a refrac of a Haynesville well, we have a one well holding the section, and that's the only well that's still in the section. We may kind of be very cautious about wanting to refrac it, just to not to have to create a drilling obligation. So there's a lot of – so it's really a – there's a lot of potential candidates, but there's a lot of considerations to when you pull the trigger. And their timing is less predictable than the new wells. But again, things were getting a little ahead of schedule on the new wells and they're the biggest driver of our production numbers.

I appreciate all the color, guys. Thank you for the time.

Thanks, Gregg. M. Jay Allison - Chairman & Chief Executive Officer: Thank you.

We have a follow-up question from the line of Ron Mills, Johnson Rice. Ronald E. Mills - Johnson Rice & Co. LLC: Just real quick. Mack, on the 186 producing wells in the Haynesville, you said you have 186 potential refrac. Is that – I mean, all your producing wells there, were there any potential limitations on some producing wells? And I guess the same question on the Eagle Ford.

Yeah. Ron, that 186 basically suggest that every well that we have in the play is deserving of an evaluation, so – for refrac, so it is a candidate. And I think I mentioned earlier in the call that we're prioritizing and we're well into that whole process of which wells are immediate candidates for project execution, part of the criteria is obviously partner approval, but there are many other criteria that we use, how under-stimulated was the original completion on a Haynesville well, et cetera. And the same criteria is applicable to the Eagle Ford as well with one exception that we feel like getting partner approval in our Eagle Ford opportunities would be far less cumbersome a process. So I think the question earlier was what's the split between our Eagle Ford and Haynesville refrac candidate list. We're starting to build a robust candidate list on both sides of that question. And so I like having the option of being able to execute either/or. But right now, it appears that our executable Eagle Ford refrac list is ahead of where I thought it would be at this point. So that's why I'm pretty optimistic that we can get some of these jobs executed in the second quarter. Ronald E. Mills - Johnson Rice & Co. LLC: Okay. Good. And then secondly, Roland, for you, just production trajectory here, it sounds like at least between now and year-end oil should continue to decline – should it – can decline pretty ratably over the remainder of the year. And then on gas, I know you obviously expect it to average almost 50% higher than it did for the first quarter. I guess the same question there or how does that trajectory build? Because at some point, is it more of a second half growth, or does that growth on the gas side start here in the second quarter? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: No, it starts in the second quarter, luckily, with the big – with the – as long as Mack keeps producing those wells at the good rates. And there we do have 100% interest in those two first wells, so that's good. The – on the oil, I think, the – there's a little bit steeper decline that really starts in the third quarter. We do have some new stuff coming on to soften the second quarter, but definitely some decline will start there, but then maybe be a little bit higher decline rate going from second to third. And then a lot depends on how the artificial lift program goes as we put a lot of that work gets finished in the third quarter. Ronald E. Mills - Johnson Rice & Co. LLC: And then when you do the refracs, particularly when you start thinking about – you have the offset frac activity. Was the offset frac activity more in the Haynesville, or was it the Eagle Ford that impacted the first quarter?

It was the Haynesville, Ron. Ronald E. Mills - Johnson Rice & Co. LLC: Okay.

Yeah. We shut in some of our wells to accommodate the refrac – or the frac scheduling, and as well as the refrac that we did, we shut in a couple of wells there, but primarily the shut-ins were due to the new well fracs that we were conducting. Roland O. Burns - President, CFO, Secretary, Director & Senior VP: Yeah. Most of the – in oil side, a lot of it was the artificial lift installation...

Right. Roland O. Burns - President, CFO, Secretary, Director & Senior VP: ...and the disruptive they are to production. Ronald E. Mills - Johnson Rice & Co. LLC: Okay. Great. All right. Thanks for the clarifications.

You bet.

We have another follow-up question coming from the line of Kim Pacanovsky, Imperial Capital.

Yeah. Hey, again. I'm just wondering when those Haynesville wells came back on line, if you saw any uplift from those wells like Chesapeake has been talking about?

Yeah, Kim, we did and that's a great question. I'm glad you asked that one, too. We had offset wells to each of our first two that we shut in, and they were shut in approximately 2.5 weeks. And when we brought them back on, the production levels were 3 times to 4 times higher than they were prior to shut in. So there was very little doubt that we did get some re-pressurization due to the frac on the new wells. So that was an added benefit for sure. Now, we're evaluating the durability of that uplift. And so we can't really make a prediction in terms of incremental EUR benefit, that sort of thing. But right now, it's been about 2.5 weeks, 3 weeks, and they're still producing an elevated rate. So that's definitely a benefit.

Great. And can you just give us an idea of what those rates were before and after?

Sure. Before, one well was 1 million a day and now it's 3.5 million a day. Another well was 750,000 a day, and it's about 2.8 million a day now. Those are the two that I remember.

Great. Okay.

A couple of others that fall in the same category.

Great. Thanks a lot.

You bet.

The next question will be from the line of Chris Stevens, KeyBanc.

Hey, guys. Good morning. Just a quick follow-up on the refracs, how long do you guys expect the well – your first refrac to kind of stick around the 3.5 million a day, and what are the modeling assumptions for first year cumulative production on the 2 Bcf to 2.5 Bcf EUR?

Well, right now, it's 3.5 million a day, and the pressure is staying up there around 2,600 pounds, 2,700 pounds. So, we feel like line pressures – goes into a high line pressure system, around 800 pounds. So, we feel like this high rate is going to stay with us for a significant period of time. The percentage of EUR in the first year is probably around 25% to 30%. So, we've got at least 750 million, 700 million in the first year. So, the benefit of the refrac is pretty significant. And we like the contribution for relatively low cost, the economics, as we've mentioned, are definitely positive.

All right. Okay. And can you just remind us how much proppant did you guys use in your first two enhanced completion design in the Haynesville, and are you guys going to test maybe anything else out there to try to further optimize the wells? Are you going to stick with this current design right now?

I think in the design approach that we're taking, Chris, it's more is better in terms of proppant placement. To answer your question, we pumped about 23 million pounds of total proppant in each well, 40/70 sand, along with 100 mesh. So we're looking at the – and the first, that's we pumped 30 stages. 27 stages, 28 stages went at below gradient. So, in other words, we feel like we could place more proppant. And so we're looking at probably the fourth well we'll try placing a little more proppant per stage. The proppant loading is about 750,000 pounds per stage. We may bump that a little bit, 800,000 pounds or so, 850,000 perhaps pounds per stage. So that's the kind of parameters we're looking at. Certainly, the whole goal here, as everybody knows, is to create the most complex interconnected fracture system along that 7,500-foot lateral that we can, so the more proppant/fluid that we pump per stage, the better.

Great. Thank you.

Yes, sir. M. Jay Allison - Chairman & Chief Executive Officer: Thank you, Chris.

Your next question will be from the line of Dan Guffey, Stifel. Daniel D. Guffey - Stifel, Nicolaus & Co., Inc.: Thanks, guys. Appreciate all the color today. Just a quick one on hedges, you guys had talked about having targets for oil and gas prices, for layering in some hedges in 2016, care to share what prices those are? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: No, we don't really want to share that publicly. Daniel D. Guffey - Stifel, Nicolaus & Co., Inc.: Okay. Yeah. Makes sense. And then secondly, you guys mentioned you're not actively marketing any assets, but you have had some inquiries, I'm wondering if any of those inquiries are from financial partners on future Haynesville development like what you've had from KKR in South Texas. Roland O. Burns - President, CFO, Secretary, Director & Senior VP: Primarily, they've – we've been there with other operators that have been interested in specific properties. And some of them, we said, no, we're not sellers, but some of them, we said, well, you can give us a number, if we could – especially where we saw those properties being non-core to see what the market would be. So – but I think as the year progresses and we've had some dialog in the past about private equity or other type passive kind of participants in a joint venture with some of the properties. And I think that – as we establish the economics, especially of the Haynesville/Bossier program, and we have a vast resource there, that may be something we entertain toward the second half of the year, especially if we see stronger gas price curve. M. Jay Allison - Chairman & Chief Executive Officer: Dan, I would say that we've not been calling anyone to find a partner, but we've had both private equity and other companies call us to ask if we would partner on some of the properties. And so we've received those phone calls. Same thing, we've had incoming calls on some of the oilfields that we own, and we said, well, maybe you can take a look at them. We don't really think that in the market we're in, somebody is going to pay fair value. So, I don't think you should get your expectations up. But again, we've received a lot of incoming calls which probably is an indication that they like our South Texas Eagle Ford because we haven't infield drilled any wells there. We've got 80-acre and 100-acre spacing. We've got – we think an exemplary refracking program; same thing with our East Texas Eagle Ford. We've written off maybe 40% of that. So we have completely decided that the Southern part is too gassy. We've got better gas, which is the Haynesville, but we like our position in our northern acreage. And then I think the Haynesville kind of speaks for itself. So it's a good position, and I think we can hold on to our liquidity. And in the second quarter, gas prices and oil prices are a lot better than they were in the first quarter. Daniel D. Guffey - Stifel, Nicolaus & Co., Inc.: Okay. Well, great, I appreciate all the good color there, I guess.

Thank you. M. Jay Allison - Chairman & Chief Executive Officer: All right. Derek, again, thank you for hosting the conference call. And some quarters are better than others and this was not a good one, not only for us, but it's a hard time to be in the E&P business. And our goal in the first quarter was to give you some results, be clear about that and then also guide you to what we think we can do in the second quarter, third quarter and fourth quarter of 2015 with the market is as it is. I thought one of the really good questions was where will you allocate your money, and the answer to that was it depends upon where the commodity price is because we do have a really good inventory of oil and gas projects in the future. And again, I'm very pleased that Mack is back as the COO to help guide the company as he did from 1987 to 2011. So anyhow, thank you for your time. I know, it's an hour or so. Thank you.