Comstock Resources, Inc. (CRK) Q3 2015 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Comstock Resources Third Quarter Financial Results Conference Call. At this time, all participants are in a listen-only mode. Later, there will be a question-and-answer session and instructions will be follow at that time. As a reminder, today's call is being recorded. I would now like to turn the conference over to Jay Allison, Chairman and Chief Executive Officer. Sir, you may begin. M. Jay Allison - Chairman & Chief Executive Officer: Shannon, thank you. Welcome to the Comstock Resources third 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 presentations. There, you will find a presentation titled third 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 third quarter operating and financial results and our plan for the rest of this year. As all of you know, this continues to be a very difficult environment with the continued weak oil and natural gas prices. However, we continue to put up excellent results in our Haynesville shale program as Mack will go over later in this presentation. Our Haynesville results are proving to be both repeatable and predictable which is a mandate in this market. In fact, the Haynesville program is exceeding our expectations which is shown on slide 18, where at a $9 million drill and complete type-curve well for Haynesville well, at $2.50 gas yields a 33% rate of return and at a $3 gas yields a (1:48) 55% rate of return, which Mack will go over in his presentation. Please refer to slide two in our presentation; note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectation will prove to be correct. Now, our 2015 third quarter highlights. This slide, which is slide three, provides an overview for our third quarter where low oil and gas prices continued to negatively impact our financial results. Our realized oil price fell by 54% and our average realized natural gas price declined by 34% in the third quarter. The 40% increase we had in our gas production was not enough to overcome these low prices as our oil and gas sales fell by 54% (sic) [57%] to $62 million. EBITDAX came in at $36 million and cash flow from operations at $5 million or $0.10 per share. The positive news out of the quarter is the very strong results we're achieving in our Haynesville program. Our first eight extended lateral wells in the Haynesville were excellent, with an average IP rate of 24 million per day per well. The first eight wells are all producing above our 15.6 Bcf type curve. Restarting our development of the Haynesville has allowed us to increase our Haynesville gas production by 119% from our first quarter rate. We have taken several steps to improve our liquidity in this poor environment. In March of this year, 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. This allowed us to repurchase $101 million of our bonds for $38 million with no debt maturities until 2019 and have total liquidity currently of $214 million after repurchasing the bonds. We have no drilling obligations for 2016, so next year's drilling program will be based on what makes sense, given current oil and natural gas prices. Roland will now go over the financial results. Roland? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: Thanks, Jay. On slide four, we recap our oil production. Our oil production averaged 6,900 barrels per day in the third quarter, a 44% decrease from the third quarter of last year. The lower production level reflects the sale of our Burleson properties in July and shutting down our oil drilling program at the end of last year. With little drilling activity this year, we expect our oil production to decline further. In the last quarter this year, taking into account the sale of the East Texas Eagle Ford properties, we expect oil production to average between 5,200 barrels per day to 5,800 barrels per day. Slide five shows our natural gas production. With our new Haynesville wells starting to come online, our gas production grew 40% to 146 million cubic feet per day as compared to the third quarter of last year. Gas production was up 60% from the first quarter rate of 91 million cubic feet per day. We expect our Haynesville production to continue growing our total gas production numbers. In the last quarter this year, we estimate our gas production will average between 150 million cubic feet per day to 170 million cubic feet per day. Slide six shows our hedge position. We have 10 million per day hedged at $3.20 per Mcf. We hope to increase this position next year if we see a rally in gas prices. Slide seven shows our improving gas price realizations that we're getting from our Haynesville operations. Last year, our all-in differential from Henry Hub was around $1 including wellhead gathering and treating cost of $0.45, which is usually reflected as part of our operating cost, and then regional transportation cost and basis differential from Henry Hub of about $0.55, which included firm transportation costs that were not being fully utilized. This year, with the growth that we've had in volumes, we've eliminated any unused firm transportation costs, and we're now averaging about $0.52. And recently, we have renegotiated certain field-gathering contracts, and will see our differential improve to $0.42 for next year. On slide eight, we summarize our third quarter financial results. We had a 40% increase in gas production offset by a 44% decrease in oil production in the quarter. Production overall was up 5%. This combined with 54% lower oil prices and 34% lower gas prices caused our revenues, cash flow, and EBITDAX to decline. Revenues this quarter were down 58% to $61 million, EBITDAX was down to $36 million, and cash flow declined to $5 million or $0.10 per share. On the cost side, in the quarter, our lifting costs were down 11% this quarter with lower production taxes and lower gathering cost. Our DD&A, or depreciation, depletion and amortization, was down 21% due to an improvement in our DD&A rate. Our DD&A rate in the quarter was $4.60 per Mcfe which improved 25% from the first quarter rate of $6.10 per Mcfe. After the large impairment charge that we took this quarter, we expect the DD&A rate to improve further to just under $3 per Mcfe. Our G&A costs were down this quarter by 29% to $5.7 million. And during this quarter, we took a large impairment on our producing properties in our unevaluated acreage, totaling $550 million. We also had unrealized hedging gains of $400,000 and a net gain on extinguishment of debt of $51.1 million. So, if you include all these unusual items, we had a $545 million loss or $11.81 per share this quarter. If you exclude those items, we had a net loss of $49 million or $1.06 per share. Slide nine summarizes the financial results for the first nine months of this year where we saw our oil production decrease by 18% and then gas production increase by 7% from 2004's levels. This combined with the 50% lower oil prices and 43% lower gas prices resulted in lower revenues, cash flow and EBITDAX. Revenues for the first nine months were down 54% to $205 million, EBITDAX was down to $124 million, and cash flow declined to $40 million or $0.86 per share. On the cost side, our lifting costs so far in 2015 are down 7% with the lower sales numbers and our DD&A in total was down about 8%. We saw G&A costs are down 20% to a total of $20.8 million. And again, we'll see improvements in all these cost numbers further into the fourth quarter and into 2016. For the first nine months of 2015, our total impairments for producing properties and unevaluated acreage totaled $617 million, and then we also had the loss of the sale of the Burleson properties that we recorded in the second quarter of $112 million. Other unusual items in the first nine months this year include unrealized hedging gains of $1.3 million, and then a net gain on the extinguishment of debt of $55.6 million. With all these items, our total net loss for the first nine months of the year was $759 million or $16.45 per share. If you exclude the unusual items, our net loss would have been $146 million or $3.16 per share. On slide 10, we've updated our capital expenditure budget for this year. And with some changes in the amount of refracs we're doing and then also adding the additional Haynesville well plus cost savings that Mack will go over in a minute in our drilling program, we've reduced our budget to about $236 million this year, down from the $248 million that we had in place last quarter. On slide 11, we recap our balance sheet at the end of the third quarter. We have $164 million of cash on hand and about $1.3 billion of total debt outstanding. Including the undrawn credit facility, our total liquidity is at $214 million at the end of the third quarter. As Jay mentioned, we retired $101 million in face amount of our bonds so far this year for total cash payments of $38 million, recognizing a gain of $63 million on these repurchases. We may continue to repurchase some of our debt this year at these attractive prices, but we'll balance that opportunity with maintaining adequate liquidity to get through this down cycle. Our first debt maturities do not come due until 2019, so we have a long runway to survive this cycle. I'll now hand it over to Mack for an update on our Haynesville drilling program.

Thanks, Roland, and good morning, everyone. As Jay and Roland have told you, during the third quarter, we continued to focus on our high EUR and deliverability at Haynesville gas projects within our 68,000 net acreage position shown on slide 12. The projects results speak for themselves. All eight of our Haynesville wells have IPed about 20 million a day and are performing above our type curve expectation. So, we've not only continued to put 20 million a day IP rate wells into the pipeline with high EURs, but we also lowered what it cost to do it. I'll talk a little bit more about these lowered costs in a minute. Moving on to slide 13, you'll see the eight Haynesville wells that we've drilled and completed so far this year. The average completed lateral length of these eight wells is 7,280 feet and the average IP rate is about 24 million a day. Since our second quarter report, we drilled and completed three wells of 7,200 foot average completed lateral length on a 25 million a day average IP rate. Let me give you the specifics on these wells as quickly as I can. We drilled the Ramsey 7-18 #1 to an 11,127-foot total vertical depth and completed a 7,124-foot lateral that IPed at 23 million a day. After that, we drilled the Holmes 29-32 #1 to an 11,371-foot total vertical depth and completed a 7,101-foot lateral that IPed at 28 million a day. And finally, we drilled and completed the Gamble 4-33 #1 to an 11,520-foot total vertical depth and completed a 7,547-foot lateral that IPed at 24 million a day. The performance of all of these wells against our type curve is shown in the next slide. Slide 14 shows that all our new Haynesville wells are producing above the type curve. We showed this comparison in our second quarter report and the trend continues. So, just to state the obvious, the wells are better than expected. And then in addition to these better than type curve results from our new wells, we've also seen production and flowing pressure gains from the older offset wells. This benefit is shown in the next slide that plots the cumulative production gain from our offset wells. Slide 15 shows that we've gained over 9 million a day in production from our 15 offset wells that were shut in for the fracs of our new wells. And as you might expect, we've also seen a significant improvement in the wells' flowing pressure. We believe this is a direct result of the new well frac system re-pressurizing and reconnecting the old frac system network. Our refrac works from the wellbore out into the reservoir, obviously, but this is the exact opposite phase where the most distant parts of the offset wells fracture system is influenced by the fluid/proppant wave from the new well frac. We'll continue to monitor the offset well results in order to define the total incremental EUR benefit, but the daily production gain is a definite plus for our overall Haynesville project economics. As we mentioned in our second quarter report, as a result of this offset well performance benefit, we postponed our Haynesville refrac projects. Having said that, we continue to believe that both our Haynesville and our Eagle Ford wells would benefit from re-stimulation. But we'll wait for a better commodity price environment to pursue these projects. Moving on to slide 16, I want to talk a little bit about our lowered Haynesville drilling completion cost that I referred to earlier. And as you can see on the slide, it shows a steady decrease in our cost to drill and complete our 7,500-foot lateral horizontal Haynesville wells. We've gone from an $11.3 million drill and complete cost for our first well to a $9.6 million cost for our seventh well. We've done this by changing how we drill and steer our wells' lateral lengths through the targeted Haynesville section. This has allowed us to reduce our drilling time from about 30 days or so at the start of the year to about 23 days now. We've also negotiated with our service and material providers to gain additional cost savings. And as we roll off our rig contract in mid-November, any wells we drill going forward will obviously be at a much lower rig rate, and our goal is to achieve a $9 million D&C level for our subsequent 7,500-foot lateral length Haynesville wells. Slide 17 supports being able to reach this $9 million drill and complete cost goal since it shows just how much we have improved our drilling time curve. I talked about this earlier, but this graph really is a picture that is better than words. If you stare at the graph a little bit, you'll see that our first two 7,500-foot lateral wells took an average of about 33 days to drill. And if you jump to the seventh and eighth data points on this plot, you'll see that we took an average of 23 days to drill our last two 7,500-foot Haynesville wells. Not to confuse everybody but the very last point on the graph is our ninth well which is a 6,400-foot lateral well. So, I've excluded it from our 7,500-foot lateral well drill time average. But there's no doubt that we've drilled this ninth well below the longer lateral 23-day average, and we know that it would have been another confirming data point if we had drilled a longer wellbore in this case. But the bottom line here, from looking at all these drill time numbers is that we've obviously shaved at least 10 days off our drill times from the start of this year, and this obviously means big cost savings. So, we're confident we can reach the $9 million D&C goal given the 7,500-foot lateral length and our current completion design. Slide 18 is a graph that shows the rate of return economics for type curve Haynesville well at different gas prices on a flat gas assumption. A $9 million D&C type curve well at $2.50 per Mcf would yield around a 33% rate of return. Let's say the gas price went to $3, then that same well would yield an estimated 55% rate of return on the type curve. Obviously, these economics ignore the fact that all of our wells are at or above the type curve and the economics also ignore the benefit of the offset well production improvement that I talked about earlier. We'll continue to look at ways to even further improve these economic metrics. Those opportunities for improvement exist in the economies of scale that come with increasing our fracture treatment sizes, as well as drilling longer laterals than 7,500 feet. Well I guess that sums it up. So, I'll turn it back over to Jay. M. Jay Allison - Chairman & Chief Executive Officer: Mack, well done. Roland, thank you. Let me refer everyone to slide 19 where I will summarize our plan for the rest of this year. We're still on the same path that we presented in our last conference call. As our Haynesville program, as you can see, is exceeding our expectations, our achieved results are demonstrating that our improved completion design has substantially improved the economics of the play. And we have a vast resource with over 6 Tcf of reserve potential and over 1,200 mapped drilling locations in the Haynesville. And as Roland showed earlier, our net realizations in the Haynesville have improved substantially from last year, and will even be lower next year. We have a nice inventory of oil projects to pursue once oil prices improve and stabilize, including 105 future operated Eagle Ford shale locations and roughly 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 overheard cost wherever we can. We'll continue to safeguard our balance sheet, and with the recently closed sale of our East Texas Eagle Ford properties, we were able to retire over $100 million of debt and still have $214 million of liquidity. For the rest of the call, we'll take questions only from the research analysts who follow the company. Shannon, turn it back over to you.

Thank you. Our first question comes from Kim Pacanovsky with Imperial Capital. You may begin.

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

So, you have eight wells now under your belt, and I guess the results have been, I'd say, amazingly consistent. So, just looking at the entirety of your acreage in the 91 locations that you have identified that are capable of supporting an extended reach lateral, what's your expectation for that repeatability over the breadth of your acreage? M. Jay Allison - Chairman & Chief Executive Officer: I'd say all of them. All of our extended laterals lend themselves to high EUR and deliverability numbers. Kim, we've got about 45 to 50 in the Logansport proper. We've got the same number just to the east where the Haynesville is thicker, slightly lower porosity. So, the avenue to follow here is looking at a slightly larger frac in those areas where the porosity might be a little less than in the Logansport region. But we're still looking at anywhere from 14 Bcf to 16 Bcf. And like I mentioned in my presentation, we're also looking at 10,000-foot laterals, extended laterals, larger fracs to help us with the higher EURs. But we've got a significant inventory of high-deliverability EUR projects. That's the bottom line. Roland O. Burns - President, CFO, Secretary, Director & Senior VP: And, Kim, this is Roland. I would add, we are also working on several acreage exchanges with other operators. And so we expect to continue to increase that inventory where we can drill longer lateral wells.

Okay. Roland O. Burns - President, CFO, Secretary, Director & Senior VP: So, there's a lot in process. So, I think all the operators in the Haynesville like the longer lateral opportunity, so there's a lot of dialog of us kind of swapping acreage to give us all larger units.

Okay, great. Can you give us any idea of how many locations you are working on adding, I guess, in the nearer term? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: Well, we'll report that after we get some of them closed. M. Jay Allison - Chairman & Chief Executive Officer: Yeah.

Okay. Roland O. Burns - President, CFO, Secretary, Director & Senior VP: But it'll be substantial. Yeah. M. Jay Allison - Chairman & Chief Executive Officer: We do have a number but we shouldn't give it out yet.

Okay. And how are you incorporating offset uplifts in your IRRs? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: We're not.

So, that's total 100% upside on top of the IRRs you're showing? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: Yes, ma'am.

Okay. And then just quick one other thing, I don't know if I missed it, did you give an update on the short lateral well? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: Well, we're flowing it back and testing it right now.

Okay. Any comments on how it's looking? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: It's looking okay.

Okay, great. I'll pass the torch. Thank you. M. Jay Allison - Chairman & Chief Executive Officer: Kim, one other thing. We've just talked about the Haynesville but we still have all of the upside in the Bossier which our tenth well is an extended lateral Bossier well. So, that, again, it's a whole different chapter. But I think it's as valuable as the Haynesville chapter.

And I don't know if I'm – I guess I'm stalling the line here. When would we expect results from the 10,000-foot Bossier well? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: With the yearend results.

Yearend. Okay. Super. Thanks a lot, guys.

Thank you. Our next question comes from Brian Corales with Howard Weil. You may begin.

Hey, guys. Another question on the offsetting well improvement, are those direct offsets or are these – I guess, how far of a improvement are you all seeing when new wells are drilled?

It's a combination, Brian, of the direct offsets plus one offset past that. So, that the impact diminishes the further away, obviously, the further away you get from the new well fracked. But most of the wells are direct offsets. We've seen some slight influence on what we call indirect offsets, which is two spacings out.

And I'm assuming in slide 15, that's just showing one of the wells' improvement, is that pretty standard from what you've seen thus far?

Well, that's a cumulative plot showing the $9 million a day improvement over the – for all of the offset wells mentioned in the pile. So, it's not just one well. It's all of them. So, $9 million a day total.

Okay. And so we can assume, I guess, the new wells you're going to put them on pad or on sections with existing wellbores?

Some will be and some won't be. It's a combination. The first several wells obviously that we drilled, it did include direct offsets because we were drilling in established units. But we have some other areas where we don't have those offsets but it's clearly (25:46) about 60% – 70%/30%, 70% with offsets, 30% without.

Okay. M. Jay Allison - Chairman & Chief Executive Officer: Yeah. And Brian, remember we have about 186 or so Haynesville wells. So, a lot of these wells will be drilled near existing wells.

Okay. And one more, I mean, as you look out to next year, I know you're probably still going through budgeting. What are your general thoughts I guess from where we sit today with the current commodity outlook? Can you just talk generally about direction for next year? M. Jay Allison - Chairman & Chief Executive Officer: Well, I think, as Kim Pacanovsky had asked, we're completing the short lateral, which is our ninth well. The tenth well is the extra long lateral in the Bossier. Our rig kind of goes away. Our rig, our existing rig goes away at the middle of this month, middle of November. So, right now, we'll mow that rig over, which is a HP rig, we'll move it over to a location, and we will not start drilling again until late January – mid-January. So, what we're going to do, we're going to see what our liquidity looks like. We're going to see what the oil prices look like, gas prices look like, see what our cost structure looks like, and then, as we said earlier Brian, we don't have any drilling obligations in 2016. So, we'll decide kind of in January what we need to do as far as our program to grow gas, and keep our liquidity. So, I think all E&P companies are in the box, it's a pretty good box to be in though when you don't have any drilling obligations and your cost to drill these kinds of wells will come down materially – well, with the new rig contract. So, we can have a rig busy. We can have no rigs. We can drill 3 wells, 10 wells. We'll decide that sometime in January.

Jay, that's very helpful. Thank you. M. Jay Allison - Chairman & Chief Executive Officer: Yeah.

Thank you. Our next question comes from Don Crist with Johnson Rice. You may begin. Don P. Crist - Johnson Rice & Co. LLC: Good morning, guys. Jay, just to drill down on what you said on your last conference call about your partner in the Eagle Ford might be willing to gain some assets either in the Haynesville or another basin. What does that market look like right now, and is their appetite just as strong as it was back then to add some acreage or maybe farm into yours? M. Jay Allison - Chairman & Chief Executive Officer: I would say yes. In fact, we've met with several different potential partners including KKR and that's our go-to partner. And just because commodity prices come down doesn't mean that the appetite is not there. In fact, there may be even greater appetite. I think the question we have to decide Don is what is best for Comstock and the shareholders, the bondholders. We've had some invitations to have other parties participate in the Haynesville drilling program. We don't know that that's in the best interests of the Comstock bondholder or stockholder. So all those things are choices, I think, that we have that we can make. But the good box that we're in, again, is we do have liquidity, $214 million. We don't have any borrowing base issues. We don't have real borrowing base. We've had exemplary results with Mack and the operations group, and the costs have come down. And even at a $2.50 gas price, I think the strip is $2.50 today, you could get a 33% rate of return. And that's before our cost come down some more with the new rig rate we'll have. So, you've known us forever and ever and ever. I mean, Roland is working hard, taking calls. I'm working hard. We're seeing what we need to do in 2016, not just survive but to grow. And we've done that all year long. And I think we've made some pretty good moves. And the key to Comstock is does the Haynesville work? And the answer is it does. And do we think the Bossier will work? And we think it will. And are we trading some more acreage to increase our footprint in the Haynesville? Yes, we're trying to do that too. So those are all good things. We've got great flexibility. And unlike the last down-cycle, we didn't have any built-in partners, but we do this time. So we'll see what we need to be doing to create some wealth for the shareholder. Hopefully that includes you, Don. Don P. Crist - Johnson Rice & Co. LLC: Thank you, Jay. All my other questions have been answered. So I'll turn it back. Thank you.

Thank you. Our next question comes from Gregg Brody with Bank of America. You may begin.

Good morning, guys.

Hi, Gregg.

You mentioned that you were able to renegotiate some of your gas contracts in the Haynesville. What is the – in terms of the negotiation, is it your market or are you in a better position or is there some swapping you're doing in terms of volumes for lower rate that's allowing you to get lower rates?

These are kind of field transportation contracts, gathering contracts that were put in place back when the Haynesville started up. And we had legacy contracts that are still in place now that are attractively priced, so we don't have an interest in renegotiating those. But we have one that was kind of higher than those. And a lot of our Haynesville production has dual connections and so I think that what we really have is some ability to have some competition. And that one particular contract that we showed in our chart is improving the numbers next year was expiring next year, and we asked them to look at renegotiating that early, and they were gracious enough to do that, and basically saying, we have other ways to go with it next year. So I think they want to keep the volumes, plus given our new drilling I think that's attractive to them, too, seeing volume growth. I think the combination of being an active operator with new volumes and having competition is what allowed us to kind of renegotiate some of those gathering contracts. So I think there are some other contracts that run out and that's kind of what the chart shows, some other firm transportation contracts that we could renew cheap. But generally, we're pretty much close to pretty market rate for what the market will bear for moving our Haynesville gas, so in a good position.

Did you have to commit to additional volumes or extend the term of the contract for a longer period of time or is it...?

Yes, we definitely extended the term from what would have expired early next year for this particular – this is only part of our Haynesville. Part of it goes to other companies as far as gathering. So this part we elected to extend that at a market rate that we like, but we didn't obligate ourselves to any firm volumes. So this will just be a acreage dedication.

Got it. And then you mentioned you were looking at swapping some acreage positions. Is there an opportunity to add acreage on your own in any of the areas that you have existing assets?

Yes. We think the area that we've been working hard is obviously the Haynesville, especially around our acreage footprint where we're drilling these wells. So, yes, we think there are some opportunities to add some acreage and there are definitely opportunities to trade acreage with other operators. And so I think we'll get some of those done in, hopefully, the fourth quarter, which would just add to our inventory of extended lateral opportunities and makes everybody's acreage more valuable when they have it more blocked up.

And then switching to the refrac program, I think you said that's on hold for the rest of the year and indefinitely. Previously, there were some issues with getting some of your other owners to commit to refrac wells. Did you see any progress on that front? I mean, where it could actually move forward if prices did improve? M. Jay Allison - Chairman & Chief Executive Officer: Well, we haven't (35:01) pursued it aggressively on the refrac side just simply because we were basically getting the re-performance (35:13) from the offset wells to our new Haynesville fracs. But I anticipate there would be a lot of difficulty gaining partner approval on refracs on a standalone basis going forward in this market. But we didn't pursue it aggressively just simply because we were getting the great results on the offset performance boost.

Got it. And the last question for you. You mentioned you could still reduce debt. I believe you still have another $12 million of RP capacity from the banks. But then you also mentioned you're going to manage liquidity prudently. How do you think about balancing those two things, buying back debt and prudently managing liquidity? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: Well, I think, yes, there's great opportunities to retire the debt at discounts, which reduces interest carry. So I think that they're kind of intertwined, those two goals. And so we had a pretty active open-market repurchase program kind of through the end of the quarter, which we typically once we get to the end of the quarter, we kind of black out purchases just because of the waiting for results to be reported. So we'll evaluate when we want to come back into that market and then also evaluate other ways to maybe do something much larger to retire some of that debt as other companies are doing with other transactions. So we're kind of evaluating what's the best answer but that opportunity – while our prices are low to significantly reduce the total debt and the total interest burden of the company, it obviously is out there and we hope to be able to take advantage of that to improve our liquidity overall. We have a lot of tools to work with. So we'll just decide how we want to approach that, including the open-market plan, which we could resume at any time.

Yes. And the $38 million we spent, got rid of $101 million of bonds we had and saved $10 million a year in interest expense. Roland O. Burns - President, CFO, Secretary, Director & Senior VP: Yes. We retired one-seventh of all our unsecured notes with that program.

No, I would agree. I think that's good use of cash. I guess you kind of hinted at potential exchanges. Is there any sort of exchange that would potentially include equity as sort of a convert structure or something like that, or are you still thinking on issuing any equity in any form? Roland O. Burns - President, CFO, Secretary, Director & Senior VP: I don't think we take anything off the table at all. But we have no particular transaction in mind. I think that's something we'll just continue to look at what's going on in the market and look at potential opportunities and talk to our partners, our big partners and see if we see something that we think helps all our stakeholders. We want to improve the value of the stockholders and the bondholders, and that will be our approach. And our approach isn't to be coercive to any of those groups. And that's why we like the open-market approach. And so, again, we'll continue to evaluate those opportunities and kind of compare those to what the Haynesville offers in drilling, and then kind of the key is what type of commodity prices do we have next year and how defensive will we be with our spending.

That's very helpful. I appreciate the time, guys. Thank you. Roland O. Burns - President, CFO, Secretary, Director & Senior VP: Thank you.

Thank you. Our next question is from Kim Pacanovsky with Imperial Capital. You may begin.

Yes. Hey, guys, just a couple of quick follow-ups. First, what is the rig rate for the rig you have right now versus what you might expect to get it at at current market or to renew at at current market? M. Jay Allison - Chairman & Chief Executive Officer: Well, rigs that were put under contract two years ago were for a Flex3 rig we were going anywhere from $25,000 to $30,000 day rate. Ours is about $27,500, kind of in the middle.

Okay. M. Jay Allison - Chairman & Chief Executive Officer: And the new rig rates, again, range depending on what kind of rig, what kind of crew, what kind of operator, et cetera, anywhere from $15,000 to $19,500. And we're still negotiating that. So, I don't want to give numbers out on that, but...

Sure, okay. M. Jay Allison - Chairman & Chief Executive Officer: That's kind of the range.

Okay, great. And then if I look at your slide 17 when you went through your improvements in drilling days going from like 35 days and 31 days for the first two wells, then to 22 days. I'm just very curious what did you do so right on the third well that you drilled it in 24 days?

Well, a lot of people have asked that question. And the short answer is sometimes everything just goes perfectly. That was an anomalous – obviously from the first few wells that one stands out. So, I mean, the question is legitimate, what did we do. We didn't do anything different.

Okay.

We just got a really great result, and I don't think we could do that again if we went back – very often, if we went back to what we were doing when we drilled that well. Going forward, we improve our chances tremendously by making the changes that I mentioned: where we land our lateral, how much of a tolerance window we get to navigate the trajectory of the lateral, that kind of stuff. We went to a bigger pump and bigger mud motor gave us higher velocity, cleaning rates on the drilling side. So the bottom line, Kim, is we feel like we found a better mousetrap to give us more consistent drilling results and faster drill times. M. Jay Allison - Chairman & Chief Executive Officer: And Kim, what Mack is telling me, the drilling engineers, they've given a little more room in where the lateral is because we've got 100 feet to 150 feet of thickness, there's a little more wiggle room. So you're not likely to make a mistake if you get a little more wiggle room. And I think Mack started doing that the last four, five wells. And that has helped our drilling time materially. That...

That's right. Basically, we've become more tolerant on the navigational side with no issues – obvious to everyone, there's been no issues on the performance side. So it's a real cost saver that's for sure.

Is it safe to assume that when you venture into the regions where the Haynesville is thicker you could potentially remove additional drilling days just because you can widen that window even more?

Well, we're starting to squeeze the margins on the savings.

Okay.

We don't want to widen the window to the point where we have what's called porpoising lateral.

Right. right.

So basically a rollercoaster ride when you try to land your casing, your production casing. So we want to stay reasonable with that tolerance window, Kim.

Okay, great. M. Jay Allison - Chairman & Chief Executive Officer: We do think that with the thick of the pay (43:08) the more locations we're going to have, which is a whole new thought and we'll report on that maybe in the fourth quarter.

All right. Thanks, guys. M. Jay Allison - Chairman & Chief Executive Officer: Thank you.

Thank you. This concludes the Q&A session. I'd like to turn the call back over to Mr. Allison for closing remarks. M. Jay Allison - Chairman & Chief Executive Officer: Sure. Again, so there were a lot of companies reporting today. If you stayed with us for the 43 minutes, we're very thankful. And as Roland has said, as Mack has said, we're trying to asses everything in an ugly commodity market in order to continue really to create well for the bondholder, the equity owner, everybody. And we're making those decisions daily. We do have really good liquidity. We've had exemplary results in the Haynesville. Hopefully, we can show those same results in the Bossier. And we don't have any drilling requirements in 2016. So we'll finish wells 9 and 10, we'll report on those, see if we can get our costs down a little more, and then give you what our program will look like some time at January of 2016. Thank you for your time.