Comstock Resources, Inc. (CRK) Q2 2013 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Second Quarter 2013 Comstock Resources Incorporated Earnings Conference Call. My name is Shaquanna, and I will be your coordinator for today. [Operator Instructions] I would now like to turn the presentation over to your host for today's call, Mr. Jay Allison, CEO of Comstock Resources. Please proceed, sir.

Thank you, Shaquanna, and thanks for everyone that's participating in the conference call. Before we go over the 30 slides, I'd like to kind of make an introduction. I know if you go back and you've been a longtime stakeholder of the company, in 2010, Comstock produced very little oil. We were a pure natural gas company, with the Haynesville being our marquee asset. Today, that is quite different. Yes, we still own 130,000-plus net acres in the Haynesville/Bossier, which is really inventories until gas prices improve. But, today, we report the final results of the Permian acreage play, which we entered and exited, really, within a year, and how that event was a springboard for accelerating the other oil play that we're in, which is the Eagle Ford, that we entered into beginning of 2010. It's a rare occasion, on a quarterly conference call, that a company with an $816 million market cap, which is Comstock, can report on a quarterly call that it recognized a $231 million gain or $3.21 per share on the sale of an asset that it owned only for a year. But Comstock can report that news today. That single event allowed Comstock to do several things: One, reduce net debt-to-capital by almost 60% to 33%; two, provided Comstock with $764 million in liquidity; three, it accelerated the Eagle Ford drilling program from a 42 gross well program, which is what we had before the sale of the Permian, to a 72 gross well Eagle Ford program. We added almost 30 gross wells as a result of the Permian sale. And, finally, it allows our acquisitions group to focus, again, on the Eagle Ford and other oily plays in order to continue to create great wealth for the stakeholder, as it did with the sale of the Permian. So, with that, welcome to Comstock Resources' Second Quarter 2013 Financial and Operating Results Conference Call. You can view the slide presentation during or after this call by going to our website at www.comstockresources.com and clicking Presentations. There, you'll find a presentation entitled Second Quarter 2013 Results. I am Jay Allison, Chief Executive Officer of Comstock. With me this morning are Roland Burns, our President and Chief Financial Officer; and Mark Williams, our Chief Operating Officer. During this call, we will discuss our 2013 second quarter operating and financial results. Slide 2. Please refer to Slide 2 in our presentations and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. Our 2013 second quarter highlights. Slide 3 summarizes our second quarter results. The most significant item in the quarter is the recognition of a gain of $231 million or $3.21 per share from the sale of our West Texas properties, which was completed on May 14, 2013. Excluding the sale, our second quarter operating results were defined by strong growth in our oil production and improved natural gas prices, offset in part by declining natural gas production. Our oil and gas sales, including gains from our hedging program, increased to $111 million in the second quarter. Our total EBITDAX was $89 million and our total cash flow from operations was $67 million or $1.43 per share. Our Eagle Ford drilling program is providing strong oil production growth this year. Our oil production increased 26% from the first quarter and is up 21% over last year's second quarter. Oil made up 19% of our total production in the second quarter and is expected to average 20% this year. We expect our oil production this year to grow 28% to 34% over 2012. In the first half of 2013, we drilled 25 successful Eagle Ford wells and also completed 25 wells, which had an average per well initial production rate of 796 barrels of oil equivalent per day. The 2013 completions have initial rates that are 23% higher than initial rates in 2012, while our drilling costs have decreased by 10%. We added 3 operated drilling rigs in June, to bring our total rigs drilling to 6, and plan to drill 47 more wells in the last half of this year. We have a very strong balance sheet after the West Texas divestiture. We have $764 million in liquidity and our net debt decreased from 59% to 33% of our total capitalization. Our West Texas divestiture, which is Slide 4. Please refer to Slide 4 in our presentation, which summarize the sale of our West Texas properties. On May 14, we completed the sale of our West Texas operations with Rosetta Resources and received proceeds of $824 million, including reimbursements for capital expenditures incurred since January 1. We reflected our West Texas properties as discontinued operations in our financial statements. Proved reserves related to these properties were 26.8 million barrels of oil equivalent and 1,700 BOE per day of our 2012 production. We realized a gain of $231 million from the transaction, which represents an outstanding return for our stockholders for the 1 year that we owned these properties. Despite the substantial gain from the sale, we estimate the current tax liability for this year will only be around $1 million. I will now turn it over to Roland to review our second quarter results in more detail. Roland?

Thanks, Jay. Slide 5 shows our oil production from continuing operations by region on a daily basis for the last 2 years and the first 2 quarters of this year. And this slide is a little different than the past because it's only reflecting continuing operations and no longer reflects our discontinued West Texas operations. And our oil production this quarter increased to 6,000 barrels per day and was up 1,200 barrels per day or 26% over the first quarter of this year. Oil production this quarter was also 20% higher than the second quarter of 2012. Our Eagle Ford properties in South Texas averaged 5,800 barrels per day as compared to 4,500 barrels per day in the first quarter. With increased drilling in the second half of this year, we expect our oil production from continuing operations to grow at approximately 2.3 million to 2.4 million barrels in 2013, which is an increase of 28% to 34% over 2012. Slide 6 shows our natural gas production for continued operations, also on a daily basis. Our natural gas production declined by 10% to 156 million cubic feet per day as compared to the 174 million per day we had in the first quarter. Production from our Haynesville and Bossier wells, which is shown in dark blue on this slide, declined to 108 million per day this quarter. Our remaining gas production only declined slightly as compared to the first quarter. Production from our Cotton Valley wells, shown in green, averaged 24 million per day; and our South Texas gas production, shown in light blue, was 20 million per day. Other gas productions, shown in purple, was 4 million per day. We expect our natural gas production relating to our continuing operations to decline further this year to approximately 56 to 60 Bcf, which is a decrease of 27% to 32% from 2012. Slide 7 shows our realized oil prices relating to our continuing operations for the second quarter. Oil price realizations in South Texas continued to be strong in the second quarter of 2013, as we realized $100.06 per barrel, down slightly from the $101.79 per barrel we realized in the second quarter of 2012. With the Gulf Coast premium we received in the second quarter, our realized price averaged 107% of the average benchmark NYMEX WTI price. Recently, the premium Gulf Coast crude to WTI has declined substantially, with recent high WTI prices. Currently, we're receiving about $2 less than the WTI price in South Texas. 80% of our oil production was hedged in the quarter, at a NYMEX WTI price of $98.69. After our hedging program, our realized price improved to $105.30 per barrel, 2% lower than the after-hedging oil price we averaged in the second quarter of 2012 of $107.71 per barrel. Slide 8 shows our realized prices for the first 6 months of 2013 relating to the continuing operations. We realized $102.60 per barrel in the first 6 months of 2013, down slightly from the $103.44 per barrel we realized in the first half of 2012. This realized price was 109% of the average WTI price for this period. 85% of our production was hedged in the first 6 months of 2013 at a NYMEX WTI price of $98.69. So, after our hedging program, our realized price improved to $107.89 per barrel, 3% higher than our after oil -- after-hedging oil price we averaged in the first 6 months of 2012 of $104.97. Slide 9 recaps our hedge position. We have an attractive oil hedge position which protects the 2013 drilling program. We have 5,556 barrels per day hedged in the third quarter, at $98.72, and about 6,000 barrels per day in the fourth quarter hedged at $98.67. We plan to hedge about 60% to 70% of our anticipated 2014 oil production. Slide 10 shows our average gas price, which improved by 86% in the second quarter to $3.71 per Mcf as compared to $2 in the second quarter of 2012. Our realized gas price was 91% of average NYMEX Henry Hub gas price for the quarter. Our average gas price improved by 48% in the first 6 months of 2013 to $3.42 per Mcf, as compared to $2.31 in the first 6 months of 2012. Our realized gas price was 92% of the average NYMEX WTI gas price for the first half of 2013. On Slide 11, we cover oil and gas sales including hedging. Our decline in natural gas production was offset by growth in our oil production and improved natural gas price into the second quarter. Sales relating to our continuing operations increased by 19% to $111 million in the second quarter, as compared to $93 million in 2012 second quarter. Oil production made up 52% of total sales, as compared to 53% in the second quarter last year. Sales relating to our continuing operations increased by 6% to $208 million in the first 6 months of this year, as compared to $195 million in 2012's first 6 months. Oil production made up 51% of total sales as compared to 48% in the first half of last year. Our earnings before interest, taxes, depreciation, amortization and exploration expense, and other noncash expenses, or EBITDAX, increased by 21% to $89 million from $73 million in 2012 second quarter, as shown on Slide 12. $5 million of our EBITDAX in the second quarter was related to the discontinued West Texas operations, with $84 million attributable to our continuing operations. Our EBITDAX increased by 12% to $170 million from $152 million in 2012's first 6 months. $14 million of the EBITDAX in our first 6 months was related to discontinued West Texas operations, with $156 million attributable to our continuing operations. Slide 13 covers our operating cash flow. Our operating cash flow for the quarter came in at $67 million, a 12% increase from cash flow of $60 million in 2012 second quarter. $1 million of our operating cash flow in the second quarter was related to discontinued West Texas operations, with $66 million attributable to our continuing operations. Our operating cash flow for the first 6 months was $129 million, a 2% increase from cash flow of $127 million in 2012's first 6 months. $7 million of our operating cash flow in the first 6 months was related to the discontinued West Texas operations, with $122 million attributable to our continuing operations. On Slide 14, we outlined our earnings reported for the quarter and for the first half of the year. We reported net income of $130 million or $2.68 per share this quarter. $151 million or $3.13 per share related to our discontinued West Texas operations. Excluding discontinued operations, we had a net loss of $21.5 million or $0.45 per share. We did have several unusual items in the second quarter results affecting the continuing operations net loss, including unrealized gains related to our oil hedges and then impairments on unevaluated leases and producing properties. Excluding these items, we would've reported a net loss related to continuing operations of $0.32 per share as compared to a recurring loss from continuing operations of $0.35 per share in 2012's second quarter. For the first 6 months of 2013, net income was $103 million or $2.12 per share as compared to net income of $9 million or $0.18 per share in 2012's first 6 months. Excluding the same unusual items, plus the gain we had on selling our marketable securities in the first quarter, we would've reported a net loss relating to continuing operations of $0.78 per share as compared to a recurring loss from continued operations of $0.62 per share for the same period in 2012. On Slide 15, we show our lifting cost per Mcfe, produced by quarter, relating to our continuing operations. Lifting cost on this chart are comprised of 3 components: production taxes, transportation and other field level operating cost. Our total lifting cost increased to $1.21 per Mcfe in the second quarter of 2013 as compared to $0.90 in the second quarter of 2012, and $1.07 in the first quarter of 2013. The increase is mainly due to lower natural gas volumes in the quarter and the fixed nature of much of the lifting cost. In addition, there were higher production taxes, which are relating to the stronger natural gas prices in the quarter. Production taxes in the quarter averaged $0.22 per Mcfe and our transportation cost averaged $0.25 per Mcfe. Field operating cost in the quarter averaged $0.74 per Mcfe this quarter. On Slide 16, we show our cash, general and administrative expenses per Mcfe produced by quarter, excluding stock-based compensation. Our G&A cost increased to $0.33 per Mcfe in the second quarter of 2013 as compared to $0.23 per Mcfe in the second quarter of 2012. G&A expenses per Mcfe increased slightly over the first quarter rate of $0.31. The increase is solely due to the lower production volumes on an Mcfe basis this quarter. Our depreciation, depletion and amortization per Mcfe produced is shown on Slide 17. Our DD&A rate in the second quarter averaged $4.87 per Mcfe as compared to our $3.54 rate in the second quarter of 2012, and the $4.60 that we averaged in the first quarter of this year. The higher cost of our oil production and then the write-down of undeveloped natural gas reserves that happened last year, arising out of the very low natural gas prices, are causing the higher rates in 2013. On Slide 18, we detail our capital expenditures relating to our continuing operations. Capital expenditures relating to our discontinued operations after January 1 were reimbursed as part of the sales price. We spent $133 million in the first 6 months of this year on our drilling program as compared to the $240 million we spent in 2012's first 6 months. Capital expenditures for our South Texas region, shown in red, relate to our Eagle Ford drilling program, which decreased to $120 million so far this year, as compared to the $144 million we spent in the first 6 months of last year. Lower well cost and then to promote that we're earning under the KKR joint venture account for the decrease. With low natural gas prices our spending for our natural gas properties in North Louisiana declined only $13 million through the first 6 months of 2013 as compared to $96 million in the first half of 2012. So, in total, our capital expenditures relating to our continuing operations of $133 million were funded primarily with the $122 million that we generated from operating cash flow from our continuing operations. The funding gap, of only about $11 million -- we only had a funding gap of around $11 million for the first 6 months of 2013. Slide 19 breaks out our 2013 drilling budget related to our continuing operations. We still expect to spend, and budgeted, $347 million on our drilling program, with $312 million allocated to our Eagle Ford program and the remaining $32 million for any required drilling to hold our acreage in the Haynesville shale. In addition to the amount we're spending for drilling, we've budgeted to spend $12 million on acreage in 2013. Slide 20 recaps our balance sheet at the end of the second quarter, which reflects the closing of the West Texas sale. At the end of the quarter, we had $264 million of cash on hand and $883 million of total debt at June 30, bringing our net debt down to $619 million. We repaid the amount outstanding in our bank credit facility in May, which has a current borrowing base of $500 million, all of which is available. Our net debt is now 33% of our total capitalization, as compared to 59% at the end of the first quarter. As shown on Slide 21, on May 15, 2013, our Board of Directors declared our first dividend in the company's history. Stockholders received $0.125 dividend per share in the second quarter, reflecting the substantial improvement to our balance sheet. The dividend only cost the company about $6 million per quarter, and we expect to continue this dividend in the future. As we show on Slide 21, less than 1/3 of the 61 E&P companies that we survey pay a dividend. And of those 61 companies, we have the second-highest dividend yield of 3.2% at June 30. I'll now turn over to Mark to review our drilling results in the second quarter.

Thank you, Roland, and good morning. On Slide 22, we cover our South Texas operations, where all of the activity is in our oil-focused Eagle Ford shale play, which has identified resource potential of 78 million barrels oil equivalent net to our interest. In the first 6 months of 2013, we drilled 25 horizontal wells, 15.2 net wells and had 6 wells, or 3.7 net, drilling as of June 30. We have also completed 25, or 15.4 net wells, horizontal Eagle Ford shale wells, including 6, 3.8 net, wells that were drilled in 2012. The 25 Eagle Ford shale wells that were completed this year had an average per-well initial production rate of 796 barrels of oil equivalent per day. Slides 23 and 24 show the results and locations of the 72 wells which are currently producing. We completed 15 more Eagle Ford shale wells since our last update. They are wells #15 through 72 on this list. The 72 Eagle Ford shale wells that were completed had an average per-well initial production rate of 735 barrels of oil equivalent per day. These wells are being produced under the company's restricted choke program, and the initial tests were obtained with a 14/64 inch to 16/64 inch of choke. The 30-day per-well production rate for these wells averaged 583 BOE per day and the 90-day per-well production rate averaged 484 BOE per day, or 66% of the initial 24-hour rate. The 2013 completions have initial rates that are 23% higher than the initial rates we obtained in 2012. The 4 wells with the highest initial production rates were the Forrest Wheeler C #1, the Swenson B #1, the Swenson A #1 and the Swenson B #2. These wells are all located in McMullen County and had initial production rates of 1,337; 1,352; 1,222; and 1,143 BOE per day, respectively. Slide 24 shows the location of the 72 producing Eagle Ford wells on our acreage. A well location marked in red indicates it was drilled this year, while the yellow locations were drilled between 2010 and 2012. On Slide 25, we show how the costs of our Eagle Ford wells have come down considerably since we started drilling in August 2010. In 2010, our first 2 wells averaged $11.4 million. Costs have fallen to an average of $8.1 million per well in the first half of this year. Faster drill times and lower well stimulation cost account for much of the savings. We expect the average Eagle Ford well to cost $7.7 million in the second half of this year. On the far right, you can see the effects that KKR promote on Comstock's realized well cost. The effective average well cost to Comstock, on a 8/8ths basis, improves to $6.7 million when you consider the promote. On Slide 26, we show the progression of lateral length, over time, in the Eagle Ford. Even though costs have come down considerably, the lateral length has increased almost 50% since our drilling program began in 2010. The average lateral length was 6,840 feet in 2013, as compared to only 4,595 feet in 2010. This increase is a function of our increased confidence in executing these longer laterals without complications and our goal of maximizing our rate of return, as well as efficient utilization of our acreage. On Slide 27, we show an increase in proppant pumped since our program began in 2010. Half of this increase is due to the increasing lateral length, if you keep the pounds per foot the same. We pumped 8.9 million pounds of proppant this year per well, as compared to 4.4 million pounds per well in 2010. And even considering lateral length, we have increased the amount of proppant per lateral foot by 35% since we started in 2010. Slide 28 shows the location of the 72 Eagle Ford wells that we have planned for 2013. We are currently operating 6 drilling rigs and plan to maintain that number through the end of the year. You can see the high concentration of wells planned for McMullen County, where we have achieved the best results so far. Slide 29 shows the net Eagle Ford wells being put on production per month so far in 2013 and what is projected for the rest of the year based on [indiscernible] rig program. The monthly variation is due to multi-well pad drilling and subsequent multi-well stimulation operations, which creates lumpiness in our Eagle Ford production curve in 2013. Production in the first quarter was affected by the low number of completions in that quarter. Third and fourth quarter Eagle Ford production will benefit from increased number of completions due to doubling the rig count. The large increase in completions in December is due to 4 4 well pads being drilled and then completed simultaneously. This activity will provide substantial momentum into the first quarter of 2014. I'll now turn it back over to Jay.

Thanks, Mark, and again, thanks, Roland. If everyone would look on Slide 30, it's the 2013 outlook. On Slide 30, I'll summarize our outlook for the rest of the year. Even though natural gas prices are improving, we will remain focused on increasing our oil production with our Eagle Ford shale drilling program, which provides high returns on our investment. We will not start drilling natural gas wells until we can have a high return on those projects. We expect the strong growth on our oil production will more than offset the natural gas production declines we are facing to allow us to have high revenues and cash flow, and be a much more profitable company in 2013 and 2014. We expect oil to comprise 20% of 2013's production, even after the sale of our Permian Basin properties, and will grow to 40% by the end of next year. 93% of the net wells we will drill in 2013 will be oil wells and 90% of our budget will be spent on oil projects. Post the West Texas sale, we have ramped up our high-return Eagle Ford program, and we'll drill 72 wells by the end of the year. We continue to have one of the lowest overall cost structures in the industry. We now have very strong balance sheet after the West Texas divestiture, and we have $764 million in liquidity, and our net debt has improved to 33% of total capitalization from 59% at the end of the first quarter. For the rest of the call, we'll take questions only from the research analysts who follow the stock. So we'll now open it up for questions.

[Operator Instructions] Your first question comes from the line of Brian Corales representing Howard Weil.

Just a couple of questions, mainly on the Eagle Ford. Good job with the longer laterals and more profit with lower cost. Is that mostly pad drilling? Can you maybe comment on what the main driver is there?

Brian, it's a combination of pad drilling, getting our days down. We did become more efficient in drilling these wells, and also the better contract that we received this year for frac services. Frac costs have come down, some of the ancillary costs have come down, coil tubing, other things like that. So it's a combination but the 2 big ones are drill times and our stimulation cost.

And Mark, how many wells can 1 rig drill a year?

Depending on whether it's pad drilling or not, but about 14 or 15 a year, on average.

Okay, okay. And then kind of looking at your inventory in the Eagle Ford, what are you all estimating now, the kind of number of wells per section or spacing? Whatever you want to talk towards.

We're averaging 65 to 80 acres per well, is kind of our average spacing. A lot of it -- acreage is dependent on lateral length, so it varies. These long laterals use more acres, but the well spacing between wells stays the same.

Okay. And, Jay, maybe this is for you. Kind of a big picture as you go on for the next couple of years. Can you add more acreage in the Eagle Ford? What is the pace of development? What kind of -- the next step once you kind of get towards developing the entire block that you'll have currently?

Well, again, I think at the very beginning, I mentioned that in 2010, we had just entered the Eagle Ford. We got our 27,000, 28,000 net acres at the same time with the Permian. I mean we were 98% natural gas company, as you well know, because we've been talking for a long time. And we did transition into 2 Tier 1 oil plays and we transitioned out of 1, with a tremendous profit. When we were in both of those plays, I mean, we didn't have, really, the balance sheet to add acreage in the Eagle Ford. I mean, we would see acreage come and there's -- I think there's a lot of fringe acreage on the market. We're not interested in that. I mean we are, now, looking to add kind of core Eagle Ford acreage. And as we drill a certain amount of wells in any given year, I mean our corporate goal, at a minimum, is to replace that drilled acreage with new acreage that we've leased, so we continue to add another year's worth of inventory at a minimum. I mean, I think the market will probably allow us to do that. There's lease expiration issues, there's mineral owners that are out there that with this, with earlier, we couldn't do anything with. I think, today, that's one of the reasons I kind of opened it up, to say the launching pad for us is to clean up our balance sheet and then really to dig down into Eagle Ford and add to that position, and you don't have to add a lot of acreage to replace a year's worth of drilling. I mean you add 6,000, 7,000 acres, that's important and you've replaced a year's worth of drilling. And I think if we continue to do that at a minimum for several years, and gas prices do come back in the $4.50 range, take a number, and we've got a deep inventory of drilling in Tier 1 Haynesville. So I think that's our plan. Our plan was not to get a train wreck on our balance sheet. Our plan was not to delude the shareholders by some type of strange financing or equity. Our plan was to inventory the Haynesville and Bossier, at the same time, unlock the bag in the Eagle Ford, which we were not able to do when we owned the Permian asset. You noticed that we've gone from 3 rigs to 6 rigs. And we did that instantly. We really accelerated that program probably 6 weeks earlier than we had predicted because of rig availability. And then I think you see our lumpiness, which is the next-to-the-last chart. It kind of goes away starting in 2014, even with pad-side drilling. I think you asked Mark a good question about the low cost. And that is the frac-ing cost have come down materially, but it's pad-side drilling. But if you only have 1 or 2 rigs out there, you can't create real wealth for the stockholders in that play, because you can't bring in these economies of scale and reduce those costs. So I mean, you've seen us year after year after year, whether it's the sale of our Gulf properties, to Stone in '08, or whether it's entering the Eagle Ford, which we're obviously correct on our acreage position, or the entrance in the Permian, which we were correct on because Rosetta paid for that. I mean we have never ever had an issue of creating wealth by adding to acreage or adding to a new play. And we don't see that as a problem, right now, with the company. I think that's the single loudest cry that we hear from the public is, well, what are you going to do after year 3 or so? Well, if they had been screaming like that in 2010, I mean look what happens in 2010, '11 and '12. And what we've done to create wealth on a per share basis. That's why, I mean, today, to report that you have $231 million of profits in a year and $1 million of taxes, it's pretty phenomenal. And I felt like we had cornered our acquisitions in new development departments so that we really couldn't continue to add that wealth. I mean, we were struggling with the development or our crack [ph] into the Permian, and I don't think that was good for us. So I hope that, in a way, answers your question.

Your next question comes from the line of Marshall Carver representing Heikkinen Energy Advisors.

Yes. First, on the well cost. You're guiding to $7.7 million wells in the back half of this year versus $8.1 million for the first half. Where are you currently on well cost? I mean have you already gotten close to that $7.7 million or where does that stand?

Yes, Marshall, this is Mark. I believe we are basically at that number now. And it's just that at the beginning of the year, we still had some of those carryover costs with the higher stimulations in the first part of the year. So I think we're really at that number and we should carry that through the year.

Okay. On the current production, do you have a current production rate you could give us? You had quite a number of completions in July and just wanted to see where that current production stands.

No, Marshall. I don't have a current production number in front of me.

Okay. Do you still think at least 9,000 barrels a day towards the end of the year is feasible or would that be even higher now that you've got such a slug of December completions? What are your current thoughts on an exit rate?

I think that's pretty close to what our exit rate is projected to be. The December completions come on during the month and late in the month. So I don't know if they are going to have much impact on December production. They all have a little bit of an impact, but probably more impact on January production than on December production.

Yes. Marshall, I think, with that large number of completions in December, yes, the exit rate could be unusually high or impacted by that group, depending on the exact day they come on. But for the quarter in, I think our overall guidance, we feel like we are a little ahead of schedule and have an upward bias to our range right now on oil production. But the actual exit rate will be a real function of that -- those 4 4 well pads. They all come on before December 31, and we can probably have them at a higher exit rate than 9,000 barrels a day. But they all come on January 1.

And I think, again, what the divestiture of the Permian has allowed us to do, by third, fourth quarter, we'll have 2 frac-ing crews working, not just 1. Periodically, we'll have 2. And I think 2014, I mean, again, kind of a buggy out there is 14,000 barrels a day is an exit rate 2014. I think if we keep with this program, that's very achievable. Now, it goes back to the question asked earlier. I mean, we're so fluid here you can see in the Haynesville/Bossier we spent $13 million, $14 million this year, and that's kind of all we have to spend in 2013. Probably the same will hold true in 2014. We don't have to spend a lot of money in the Haynesville/Bossier to inventory this 6 Tcfe of kind of upside we think we have for resource. See it's the same thing in the Eagle Ford. I mean, maybe, we have to drill several wells in 2014 and in Eagle Ford, which are obligation wells, but we can control that whole program based upon where commodity prices are. I think that goes back to slide the relevant rate [ph] too. Our goal in 2014 is to add 60% to 70% of our oil production. So we'll be putting in this program in Eagle Ford in 2014, kind of at the end of the year. But if we want to have material growth in oil, I think we can. You know the core area we're in, you know the cost, you know the balance sheet. I mean, our CapEx almost equals our operating cash flow. So those things are good and now you have to go, well, are you adding more acreage? And the answer is, I think we'll be able to do that in the Eagle Ford. Well, time will tell, but that's where we are.

Your next question comes from the line of Ray Deacon representing Brean Capital.

Mark, I was wondering if you could talk a little bit more about Atascosa County, the result from this NWR well and whether -- I know the location count doesn't include anything, really, for that part of Atascosa. Have your thoughts changed at all there?

Ray, we're still evaluating that. Well, it just came on production not long ago and we're still interested to see how it performs. It's a long lateral, so we don't know how that's going to affect the decline curve on that well. So [Audio Gap] So I guess jury's still out on that acreage. Most of that acreage up there, we have said over and over, that we've discounted, that really we don't think it has much value, and we're still kind of on the fence on that right now.

Okay, got it. And I guess, how about in terms of kind of apples-to-apples comparisons in the second quarter versus the first quarter? I guess, what it seemed to me was happening was you were drilling in areas that you knew would probably not be equate as prolific within McMullen, yet it seemed like the rates were a little higher than the other wells you drilled in those areas. I guess -- I'm just trying to get a handle on what -- I know some parts of McMullen are not as prolific. And I guess what are you seeing with the new artificial lift and new completion techniques kind of in one area versus another?

Right. Generally speaking, as you go from north to south on our acreage in McMullen County, the IP rates go down, then they go up. So on the northern end, you're looking at lower IP rates, and they improve when you get down to the Gloria Wheeler, the Swenson, the Forrest Wheeler acreage. The EURs don't change nearly as drastically as the IP rates, so that the wells to the north, they're a little lower reservoir pressure. They tend to be flatter. They have a lower decline rate, first year decline rate than the wells to the south. And so the performance on -- is probably not quite as good on a rate of return basis, but not too dissimilar. So we've really been very pleased with almost all of our acreage, or I guess all of our acreage in McMullen County. And then the acreage account flows over into La Salle as well. So I don't know if that answers your question, but that's kind of my impression.

Yes. No, That's a good answer. And I guess just to make sure, so the map, it shows your '13 activity. Well, it looks like you're going to have one more Atascosa well this year, is that right or...

We have a well, an obligation well, that we have to spud up there in late 2013. So we'll evaluate the NWR, too, and determine whether we want to drill that well or not.

Your next question comes from the line of Ron Mills representing Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: A couple of questions, just a follow-on, I think, to Ray's previous question. If you look at the 25 wells you drilled year-to-date and the 47 remaining wells, you have any kind of -- can you provide any kind of sense as to where your 47 wells are located? Are they going to -- are they more concentrated towards the southern part, the Gloria Wheeler, Swenson area of McMullen County? Or are they spread across most of your box that you show on Slide 24 in McMullen County?

Ron, this is Mark. I haven't broken it down exactly but if I were to guess, it's probably 60-40 on the -- for the staff to the north, as far as remaining wells in McMullen County. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And maybe this is one for you, Jay. Just your relationship with KKR, from -- not just a drilling carry standpoint on this acreage, but can you talk about a little bit how that relationship has progressed? What their appetite is, in terms of potentially expanding acreage in the play, and/or private equity firms usually have a number of portfolio companies. Is that relationship also -- can it potentially benefit you, in the sense that if they have any portfolio of companies that have attractive acreage positions?

I think if this were a classroom, we'd probably get like an A plus for relationship. And the reason is, I mean, they come in and we have de-risked the Eagle Ford for the most part, and they've been in and out, I think, of 6 different deals in the Eagle Ford, so they're very knowledgeable about the play. They come in, in our acreage and they can't cherry pick, so they're in all of it, more or less. And all of a sudden, our costs come down. I mean, these were $9 million, $10 million, $11 million wells over years ago, as you've seen. And now they're $7.7 million. And all of a sudden, production goes up, 200, 300 barrels or more per day as an IP rate. So if you're KKR and all of a sudden costs come down and production goes up a lot, and now all of a sudden, we go from 3 rigs to 6 rigs and you're wanting to aggressively develop Eagle Ford when oil is $100-plus, man, we're like the -- one of their best investments, period. I mean I would -- and they would, I think, from our discussions, I mean if we can duplicate this in -- and add under Eagle Ford acreage, I think they would expect a phone call from us to be their partner. So I have nothing but excellent news from our relationship with KKR, period. And again, this time last year, we didn't have that. I think it does give us a little more strength. We didn't have it last year. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Right. And then, Mark, from a well-design standpoint, a completion-design standpoint, whether it be lateral length or proppants, you never stop learning. But do you think you're pretty well honed in on the best way to complete these wells? And are there any major variances in terms of how you complete them, the northern part versus the southern part?

As far as geographically, Ron, no. We're doing pretty much the same thing in both areas. We did change the fluid design a little bit in the north area. We tried to pump less fluid just because it's lower pressure and it's hard to get the fluid back out. So I think we do tend to limit the fluid used in the north area. We have been testing some different things in terms of pounds per lateral foot and cluster spacing, and we really just kind of going through another round of that, and we're waiting on -- obviously, waiting on results now. We need timed to see how that impacted performance. But I think, generally, we've honed in on the design we like, and we're going forward with that generally.

Your next question comes from the line of Mike Kelly representing Global Hunter Securities.

Jay, in regards to the leasing efforts, can you talk about what areas you're targeting, specifically? And then what acreage costs look like? Really, I'm trying to estimate what the total acreage spend will be if you're successful in picking up the 6,000 to 7,000 acres in a year.

I really can't tell you where we're trying to lease, other than if you look at a traditional geological map where the kind of the core of the Eagle Ford areas -- I mean, I think what you need to know is that we're not looking for some pricey acquisition. We're not looking for some pricey acreage. I mean we're looking for some bolt-on acreage in and around our core and/or all the way to the north. We've, as you know, we've been in "South Texas" for probably 15 years. The Eagle Ford was a new play for us in 2010, but we've got a lot of good wells spread in the whole part of the country and our geologists have been very good at kind of locating the right core acreage that we need. We got -- and I think we feel, internally, Mike, that we've got a really good chance of delivering on our goal. And our goal, again, is however many acres that we would drill up in a given year, we want to add that many more acres as a minimum for inventory. We don't want a depleted inventory year after year after year. We want to keep the same inventory that we have now and/or add to that if we can. That's our corporate goal, and I think we'll be able to do that.

Okay. Would you be able to -- is there an opportunity to add, let's call it, 2,000-acre blocks that are bolt onto your core McMullen acreage at roughly 5,000 to 6,000 an acre? Does that sound reasonable?

Mike, if you have some of that, you ought to shoot us an e-mail, and we'll talk about that.

[indiscernible]

[indiscernible] fringe acreage. Because we went in 2010 and paid -- I think we had $4,000 in the whole program. And then -- I mean you have seen some fringe acreage deals completed, we think. But we're not interested in that either. In other words, we're not interested in having a lot of acreage just to tell you we have a lot of acreage. I mean, if we had acreage, then it should be all drillable acreage and you should divide it by 65 or 80 acres and say we've added this many new locations. That's what we're looking for.

Okay. And then in regards to your guidance and exit rate goals, correct me if I'm wrong here, but it sounds like the confidence is there that you're more toward the higher end of this year's oil production range barring anything extraordinary. I'm really interested in the factors that might cause you to come in above or below that 2014 exit rate goal of the 14,000 a day on the oil side. If you could talk to that a little bit more, I'd appreciate it.

Well, I take one, then I'll turn it over to Mark. And we have to put a CapEx program together for 2014, which is again a 6-rig program, whatever, in order to hit that 14,000 net barrels production in 2014. We've not advertised that, that's what we're going to do. We said that with oil prices where they are and gas prices where they are, we're going to stay the course right now. But we do have flexibility to change that. Now I'll turn it over to Mark.

Yes, Mike, it's Mark. I think that's basically it. We don't have an approved budget yet to -- we've done projections and what-ifs. We don't have an approved budget for '14 that goes that far, that makes that exit rate. I think we can make that number or come very close to it or be a little above it, somewhere in that vicinity, if we run the 6 rigs through next year. I feel comfortable with that. We've got the inventory to do it. We built a what-if program that shows us that. And I think timing of the completions can affect that a little bit, if we drilled a bunch of 4-well pad wells all in a row and we ended up pushing that off until late December next year or January, just like we're doing this year, then it could affect your exit rate slightly. But that really is the only thing that I would say other than going a different direction, if gas prices improve or we get into another play that requires us to use some of our cash flow for that play rather than this one, then that would affect those numbers.

Right. There's nothing within the Eagle Ford kind of boundary that would cause us not to hit those numbers, in our opinion. I mean the acreage is there, the rigs are there, the frac crews are there. It would just be if we change that business plan.

Your next question comes from the line of John Freeman representing Raymond James. John Freeman - Raymond James & Associates, Inc., Research Division: You talked about the flexibility with the budget next year. Can you just kind of give me, in rough idea, kind of when the various rigs would be scheduled to roll off the contracts?

John, this is Mark. We have -- most of our rigs are under 6-month contracts, so they roll off every -- we have rigs rolling off every couple of months. We have 2 rigs that are long-term contracts, that are 2015 expirations. But the other 4 are all short-term rigs, and so we have a lot of flexibility on that. John Freeman - Raymond James & Associates, Inc., Research Division: Okay, great. And then, Mark, you've spoken pretty consistently in the past about your -- you feel like the 500-foot spacing pattern is pretty well established. And so then the really only consideration is how long the lateral length is. I'm curious -- I mean obviously, your lateral lengths have been going up here this year. What's the longest lateral that you all have tried? And when do you think we'll have a better idea on whether the, let's say, a longer lateral, call it, like a 9,000-foot or a 90-acre spacing is appropriate or maybe more of what you're doing closer to 78 or 80 acres is appropriate?

Joan, you're correct on the 500-foot. We've been consistent about that and we're staying with that program of keeping the wells about 500 feet apart. Give or take our acreage. Sometimes if your acreage is shaped a certain way, maybe end up 470 feet or 530 feet apart, something like that. As far as longest well, I think that NWR #2 in Atascosa County is our longest completion to date. It's about 10,200 feet. We've had several more kind of very close to that, around 10,000 or it hits a little under. And really it depends -- sorry about that, it's John, not Joan. I'm indiscernible]. So really, we're trying to utilize our acreage. And so we may be drilling one unit up that are all 6,000-footers because that's the way it spaces out, because we don't think we can drill 12,000-footers or the unit is just that long. In another place we're drilling 9,000 or 9,500 footer because of the shape of the acreage. So we're trying to use every acre effectively, and that really is what drives lateral length, as much as anything. We know that we need at least 4,000 feet in the south and probably 5,000 or 5,500 feet in the north to be economic, to make our numbers. So anything above that is just utilizing acreage efficiently.

Your next question comes from the line of Dan McSpirit representing BMO Capital Markets.

If I could maybe ask a more theoretical question here. Do you look at the Eagle Ford and maybe oil assets in general as you bridge to a higher natural gas price environment where returns at the field level could be better and operations may be more scalable? And in answering that question, can you speak to the natural gas price, the Haynesville and Bossier are competitive on returns with your McMullen County Eagle Ford?

We have -- I think, Dan, if you want -- let me tell you what we're trying to do. We're trying to create wealth on a per share basis. And about 45 minutes ago, we told you for this quarter, each shareholder got $3.21 per share of a gain at the $231 million profits we made in a year. So if you take the denominator as what can you do to create wealth on a per share basis, we just created $3.21 per share. And in 2010, we are a 98% natural gas company. Second of all, I'm not going to rupture ourself with a balance sheet that's stretched all over to investment banking heaven. We're not going to do that. We're not going to put ourself off the ledge. So I think what we had to do is we had to come in and find some oil plays. We found 2 major oil plays, obviously. One we got out of; and the second one, we kept. And we kept it because I think you're exactly right. I think not many companies our size have been able to bridge themselves with oil right now to take control with an unbelievable partner like KKR. With years of drilling, that's pretty predictable, as some of the questions had been asked about predictability. So now you get to the value of Haynesville. We have 1,200, 1,300, 1,400, 1,600 locations or whatever. When you get somewhere in the $4.55 gas price, depends upon what these wells might cost. And we'd looked at, theoretically, do you drill section, section-and-a-half wells in the core area of Haynesville? What kind of return would we get? And I think when you get in the $4.30 price to $4.50 price, and it's not just a flash in the pan, a day price, but it's a 12-month stripped out price, then I think that some of the prospects that we have in the core, not all of that 130,000-plus net acres, but the core acreage in the Haynesville, I think some of that would be competitive in the Eagle Ford. So we don't advertise. Again, we make a bold statement that where gas prices are, we're not accelerating our drilling program. But we just believe in the years to come that, with demand increasing and the rig count kind of down and production pretty flat overall for natural gas on a daily basis, that the commodity will swing around and be a $4.55 commodity, maybe more. You can't run the company based upon that program in 2 years, but you can certainly run the company based upon the inventory-ing the golden egg for the future. And I think that's what we've done. We thought [indiscernible] a little stronger than they are today, but we're certainly pleased where prices are today versus the $1.90 a year ago. So I think if you're talking just theoretical, that's -- and I think we've always communicated that to you and everybody else about what our corporate plan is.

Well, I appreciate that answer, Jay. And on the subject of shareholder value, how do you view acquisitions? Or how do acquisitions compare to buying back stock in terms of creating wealth for shareholders?

Well, I don't think you spend money buying back shares. If it causes you to give up a good acquisition and/or if it causes you not to add meaningful core acreage in Eagle Ford, I think then you shouldn't be buying your shares back. But I think with the -- well, again, our credit line, we had a borrowing base of $570 million when we owned the Permian. I mean after we sold the Permian, our borrowing base was reduced to $500 million. We only lost $70 million in our whole borrowing base, and that was an $824 million event. So I think we became much stronger. We needed to become much stronger. So it's unusual, again. You've got a company -- I mean, you look today, you look on the little ticker, we're probably $800 million in market cap. We have $760-some-odd million of liquidity. And we're gas-rich, and we're oil -- now starting to be oil-rich. Because by the end of 2014, we think 40% of our production will be from oil. So I think what we try to communicate with the shareholders, who own this company, we're not -- we'll take risks, but we'll not be reckless in anything we do. We're inventorying the Haynesville/Bossier. People call all the time, why don't you put some rigs into drilling? And we don't need to. We've demonstrated we don't need to. At the same time, and again in 2010 and '11 and '12, we didn't have hardly any oil. We've been in and out of material oil. And it's almost laughable within our organization to think that we can't add acreage between now and year end, or now and the end of 2014 in the core area, being the Eagle Ford or another core area because, Dan, we always have, we'll always have. So that might be a fear of the public. It's definitely not a fear of management or the board. So that's how we look at all that.

Yes, I understand. And one last one for me, if I may, just for modeling purposes here. Can you estimate for me or express for me the decline rate on natural gas production on the underlying natural gas production, and how that might change over the next, say, 1 to 2 years? Again, just for modeling purposes.

We said it may be as high as 32% this year in the Haynesville/Bossier. Again, we added a couple of wells, which we had to drill. And I think next year probably '15, '18 in the Haynesville/Bossier, just probably --

For total company, yes.

Yes, total company. That's probably the number that you use.

Your next question comes from the line of Cameron Horwitz, representing U.S. Capital Advisors.

Mark, following up on what was asked earlier, maybe I'll ask it a different way. If you kind of -- if you take the geography out of the equation, can you kind of quantify what performance improvement, if any, you're seeing? Maybe on a lateral foot basis, as you've run these more intensive tracks or stimulations?

I don't have that in front of me and we really kind of -- it's an ongoing process. I don't know if we have enough data to give you a real definitive number yet. We're still kind of evaluating what we get out of the longer laterals, what we get out of the tighter cluster spacing, the more pound per foot. I really just don't have that number here.

Okay. So I guess with some of the improvements in the well cost, at least, what are you guys internally estimating from a rate of return perspective, for the go forward for Eagle Ford inventory?

Cameron, this is Roland. With wells that are obviously with the venture, we think the rate of return to Comstock is approaching 50% for the investment -- for the drilling capital spend. Obviously it's going to vary which part of the section you're in, but it's very strong and -- for the overall program. So we really can't match those returns in our other areas right now, especially on the gas side. That's where the capital is being focused.

Sure. And then just lastly, Mark, can you just remind us, just looking at the map here on that Y-bar leasehold that you have there, what the expectations for this acreage, just given it looks like the only major block you haven't drilled a well on yet?

There have been a lot of drilling around it and the performance of that has been very, very similar to our acreage just to the East, our Carlson and Hubbard acreage. So we really expected it to perform like that. It just that it had a lot more term on those leases, they were a lot newer releases. So we have a lot more term and we were able to put it into schedule a little bit later. That will be a big focus in our 2014 program.

Your next question comes from the line of Sean Sneeden, representing Oppenheimer.

Maybe as a follow-up to one of the previous questions, with the sale of the Permian, you guys, as you outlined, Roland, you have $264 million of cash in the balance sheet. Could you maybe discuss what you might look to use that cash for over time? I know you talked about a potential refi of the 8 3/8% senior notes, which become callable in October. Or, maybe, could you just prioritize, again, kind of what you think you might want to use that cash for?

Sure, Sean. The -- I think the top priority right now, we plan to -- kind of depending on what the interest rate environment looks like and the overall liquidity market looks like at that time, when we can actually issue the call, but calling the bonds, the 8 3/8% bonds, which are callable on October 15, is kind of what we're, right now, considering -- something we would do now that's more -- I don't think that we really plan to refinance those at this time or issue new bonds because we like to kind of rebalance our debt between the lower cost bank debt and the bonds. So that is top of our agenda. Of course, we have other -- we have an authorization for the stock buyback, to the extent that we want to buy shares back also. And then the other priority would obviously be any type of acreage opportunities that we feel real attractive.

Okay, got you. And then just kind of broadly speaking, can you discuss about how you think about balancing, paying and/or growing the dividend with liquidity and leverage. Are there any particular targets you are looking to maintain? For instance, are you planning to spend within cash flow or anything like that? That would be helpful.

Sure. On the dividend payment, the dividend is about $6 million a quarter. So we view the level as a pretty good level for the company, given today's environment where commodity prices are. So we're not really targeting a particular yield at all. The average yield for our space for the dividend payers is 1%, so the 3% yield is more of a function of lower stock price right now than anything else. But definitely, the dividend is something that we do not want it to -- call this to spend less on the drilling program or get in the way of acreage acquisitions or increase the leverage to a point that's not optimal for the company. And we feel like, right now, it fits in very well. Our goal is for 2014 to have a capital program that's fully funded with operating cash flow. And we think that that's kind of what the 6-rig program would appear to be based on commodity prices. And as we put our hedges in place, before we approve that capital budget, we'll have more certainty to that. So we think the dividend fits well with all those objectives. So again, we don't have a lot of shares outstanding so -- when people give a dividend. It's not a very costly item to our cash flow, compared to many other companies with a lot of shares outstanding.

Sure, that makes sense. And then just one last one for me. But -- I mean, I think you mentioned your target hedging on the oil side for next year, but you didn't mention anything for gas. Are you guys still playing to be largely unhedged, just kind of given where we are before curve?

Yes, I think that we would look to add gas hedges when we look to drill gas again. So I think that right now, the forward curve doesn't support drilling for next year or this year, as far as we're concerned. So yes, we wouldn't see to hedge that either.

Your next question comes from the line of Amir Arif, representing Stifel. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Just a quick question on the -- with the Permian sale and the low tax impact of it, is that going to change your 100% deferred tax rate for the foreseeable future for the next year or so?

This is Roland. Amir, that's a -- it really has no impact. What we had given the couple of years of low gas prices and a couple of years of high drilling -- a lot of dollars spent on drilling programs, we had generated both NOLs and IDC that we didn't use that we're able to shield that very large gain that we made on the Permian sale. We still have some of those attributes remaining. But I mean, really, the deferral of most of the current taxes is really a function of our drilling expenditures and as long as we're primarily spending our cash flow for drilling. We'll be able to defer most of the current taxes that continue to push those out. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay, okay. And then for Eagle Ford, can you just quantify how much acreage is in Atascosa relative to your total acreage? And when acreage explorations would start to come in terms of when you will have to either decide to let it go or drill it?

Amir, I don't have a count in front of me of that acreage that's still under primary term. It's probably 2,000 or 3,000 acres that's still under primary term. The acreage on the east side is all HBP, the Lucas, the DVR, the Mesquite wells, they held all that acreage. So really, it's pretty small acreage block that's remaining in terms of any decision making. And that really goes out later this year and into -- probably into '14. Actually, we have an obligation well to drill, I think, in November or December. That's a decision point. So we'll decide then whether -- what we want to do with that acreage. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. And the $12 million that you lay out for leasehold cost this year, is that specifically for Haynesville? Or is that also in the Eagle Ford? Or is that also new acreage and new plays?

That's an overall budget, Amir, for -- which includes capitalized interest. So -- but I think we won't have a lot of capitalized interest for the second half of the year, given that a lot of our unevaluated -- we sold a lot of our unevaluated acreage to Rosetta and then also the Eagle Ford is quickly becoming fairly evaluated. So I think we only have like $5 million of that number. So far, the first 6 months of the year. So it's really -- we'll really look at lease acquisition opportunities on a case-by-case basis versus setting that on a permanent number. That would handle all of the more recurring things that you have, such as free capitalized interest or just other kind of renewals that we had planned to do, but wouldn't encompass a very large acreage purchase that we haven't specifically identified. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. Well, Roland, are those renewals in Eagle Ford or is it mostly just in the Haynesville? Before you go over the [indiscernible]...

I mean, there's just 2 places where you might have a very inexpensive renewal. But in total it's a pretty small dollar amount, so they're not very material on either play. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. And then just a final question. I know you guys mentioned that you feel the market's overly concerned about the inventory and you guys have always been able to create opportunities. What inventory level, in terms of your 6-rig drilling program, would you feel that you need to get something done? Is it once you get down to 1 year, 1.5 years, 2 years?

We always like to have a 3-year program. I mean that's kind of the comfort zone. A couple of years, we don't have a hiccup on, 1 year, it's a little taxing. It puts a little more pressure on you. But I think if we had a strong 3-year drilling program, that would be really good.

You have a question from the line of Ron Mills, representing Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: One last real quick 1. I'm assuming, Mark or Jay, from a, at least exploration standpoint, not really through Comstock's, but where are we in the life cycle of Eagle Ford leases in terms of industry primary term coming up on explorations? Is that one of the primary sources here of bolt-on opportunities? Or am I too early in that assumption?

No, Ron, we believe that's part of it. There's a lot of acreage that was picked up anywhere from 2007 to 2010 that is coming up. Some of it has extension rights, some of it doesn't. We think companies are just going to struggle to getting to some of their smaller acreage blocks and some of that will come available.

Your next question comes from the line of Rehan Rashid representing FBR Capital Markets. Rehan Rashid - FBR Capital Markets & Co., Research Division: Quick question, guys, on CapEx for the year. So the 1.6 wells that -- in the Haynesville that were supposed to be drilled or operated by others, is that going to get drilled by year end? And then I have a quick follow-up.

Yes, Rehan, this is Roland. Right now, we haven't had any outside operator proposals in the Haynesville, and that I don't believe we have any in hand. So it's a possibility that it doesn't get spent. We did drill the 2 operated wells and then we completed those very, very early July. So it's a possibility we spend no more money in the Haynesville, but there could be some proposals that we think are worthy to participate in come later. Rehan Rashid - FBR Capital Markets & Co., Research Division: Okay, okay. And then going back to the kind of acreage inventory kind of discussion. So on the Eagle Ford, should we think about any kind of particular exit level in terms of ads by year end, soon thereafter? In terms of kind of what you've been working through?

As far as acreage? Rehan Rashid - FBR Capital Markets & Co., Research Division: Yes.

Our goal is to, like Jay said, to add 5,000 to 6,000 acres. Now whether or not we accomplish that by year end or not is the question. But I think we'll make progress towards that. Rehan Rashid - FBR Capital Markets & Co., Research Division: And presumably, these are in-fill acreages right around where you operate?

Right. I think you were talking about the numbers -- the smaller acreage acquisitions, they need to be right around where we operate in order to be useful to us. If they're going to be pretty far out of our operating area, but then an area we like in the Eagle Ford, they're going to tend to have to be a little larger to make more sense and be more contiguous so you can get a lot of drilling locations on it. Those type of purchases would be on the high -- would be more expensive, typically. The larger the acreage track in an area that's proven, the more value it has. And conversely, the smaller the acreage track, even in a good area, may have less value just because it can't be used by as many operators. Rehan Rashid - FBR Capital Markets & Co., Research Division: Got it. And I continue to hear from you guys the strict discipline around kind of what you will spend money on and kind of what parameters that will have to bring to the table, right? And then that's something we should continue to expect toward the next several quarters, let the market comes to you rather than chase anything?

Absolutely.

Definitely. I know we've -- a lot of feedback we've gotten back from other investors in the industry, especially the private equity and the commercial banks, et cetera, is they feel like the -- that the industry in general, has the opposite problem. They have way too much inventory, way too many things that need to be drilled and -- just on the whole. And they feel like that those opportunities would be there. So our -- we plan to be very disciplined. We have a very good year. If we just stick to what we own today and run the 6-rig program and oil prices are supportive of that, we have a very, very good year next year. So we don't want to mess that up by jumping off on to another area that may not be able to produce the same results. So we're going to be very disciplined in finding the right opportunities. But we do see, overall, in the long run, that we want to add more oil opportunities for the company. We just exited a very large 1 that probably, before that, we would say we don't want to add anymore because we have so much on our plate. But just months ago, that changed. So we're open to those kind of ideas, but we're not -- we don't want to stress the balance sheet, nor do we want to create a lot of obligations for things that have to get drilled immediately or generate lower returns than what we can make now in the Eagle Ford. So we're very, very disciplined, but -- and patient. But we think those opportunities will obviously come, they always do. And then we'll add, as we get -- as we barge down the next 3 years, we will definitely have additional oil opportunities to keep us more balanced. We don't want to go back to 98% gas in the long run. In the company, we do want flexibility to respond to the different challenges the industry throws our way. Rehan Rashid - FBR Capital Markets & Co., Research Division: I apologize for this theoretical question, but along the same line. So like kind of essentially what you guys were saying, that there are very few underutilized operating platforms in the public capital markets such as an E&P company, if a private equity wants to come to you and say, "Hey, let me back into your public platform these set of assets." What would you demand in return? And how will you kind of shape something like that? Again, it's theoretical, I understand. But all addresses the same kind of basic concern and questions the marketplace?

Well I think I've had -- we would obviously want to see the immediate value that makes that a worthwhile proposal to us, not only just for whatever part of our capital it uses or takes, but also what part of our time and efforts there that our operations group and other group would have to spend on it. So I guess we would just have to evaluate that opportunity with specifics. But we do think, like I said earlier, that there are, in general, there are a lot of inventory, a lot of projects out there that need a lot more capital than the companies that have them have. And so I think we're sitting in a good position with a real strong balance sheet. We'll see how that all plays out.

I would now like to turn the call back over to Mr. Jay Allison for closing remarks.

Again, we are always thankful that you participated in the conference call and that you're either an analyst or stockholder are interested in the story and I think the questions that were asked were excellent questions. And hopefully, we've given you some clarity on what the business plan is and we've been accountable for our entrance and our exit to the Permian and what we're attempting to do in the Eagle Ford, as well as in [indiscernible]. So, thanks for your time.

Thank you for your participation in today's conference. This concludes the presentation. You may now disconnect and have a great day.