Comstock Resources, Inc. (CRK) Q1 2013 Earnings Report, Transcript and Summary

Miles Jay Allison - Chairman, Chief Executive Officer and President Roland O. Burns - Chief Financial Officer, Principal Accounting Officer, Senior Vice President, Secretary, Treasurer and Director Mark A. Williams - Chief Operating Officer and Vice President of Operations

Brian M. Corales - Howard Weil Incorporated, Research Division Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division Leo P. Mariani - RBC Capital Markets, LLC, Research Division Rehan Rashid - FBR Capital Markets & Co., Research Division Jack N. Aydin - KeyBanc Capital Markets Inc., Research Division Kim M. Pacanovsky - MLV & Co LLC, Research Division Mark Lear - Crédit Suisse AG, Research Division Dan McSpirit - BMO Capital Markets U.S. Raymond J. Deacon - Brean Capital LLC, Research Division Sean Sneeden Daniel Katzenberg - Oppenheimer & Co. Inc., Research Division Michael Kelly - Global Hunter Securities, LLC, Research Division Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division Richard M. Tullis - Capital One Southcoast, Inc., Research Division Arvinder Saluja - Moody's Corporation, Research Division

Good day, ladies and gentlemen, and welcome to the First Quarter 2013 Comstock Resources, Inc. Earnings Conference Call. [Operator Instructions] I would now like to turn the presentation over to your host for today, Mr. Jay Allison, Chief Executive Officer. Please proceed.

Thank you, Stephanie. Welcome to the Comstock Resources First Quarter 2013 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 clicking Presentations. There, you'll find a presentation entitled First Quarter 2013 Results. I'm Jay Allison, President of Comstock. And with me this morning are Roland Burns, our Chief Financial Officer; and Mark Williams, our Chief Operating Officer. During this call, we will discuss our 2013 first quarter operating and financial results and discuss our pending sale of our West Texas properties to Rosetta Resources. 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. If you'd go to Slide 3, it's the 2013 first quarter highlights. I will summarize our first quarter results. The declining natural gas production results from pulling all of our rigs out of the Haynesville last March and the improving oil and gas prices defined our first quarter results. We had oil and gas sales, including the gains from our hedging program, of $97 million from our continued operations. Our total EBITDAX was $81 million and our total cash flow from operations were $62 million or $1.28 per share. We reported a net loss from continuing operations of $24.5 million or $0.52 per share for the quarter. Given the activity that is planned in South Texas in our Eagle Ford shale program, we are expecting another strong year of oil production growth. Oil made up 14% of our total production in the first quarter, excluding our West Texas properties, and it's expected to average 20% this year. We expect that oil production from our Eagle Ford shale properties will grow 28% to 34% over 2012, driven by our successful drilling program. In the first quarter, we drilled 11 successful Eagle Ford wells and completed 10 wells, which had an average per well initial production rate of 845 barrels of oil equivalent per day. The 2013 completions have initial rates that are 32% higher than initial rates in 2012. We'll have a very strong balance sheet after the West Texas divestiture that we'll discuss today. We will have over $800 million in pro forma liquidity, and our pro forma net debt improves to 29% of our total capitalization. Please refer to Slide 4 now in our presentation, where we summarize the pending sale of our West Texas properties. On March 15, we announced an agreement with Rosetta Resources to sell our properties in Reeves and Gaines County in West Texas for a sale price of $768 million, subject to customary purchase price adjustments and closing conditions. The sale will have an effective date of January 1, 2013, and is expected to close on May 14, 2013. The sale represents all of our assets in the Permian basin, so we will reflect these properties as discontinued operations in our financial results. 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 intend to use the proceeds from the sale to primarily reduce debt and to improve our balance sheet. We expect to realize a gain of over $250 million on 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 expect the current tax liability for this year to be less than $2 million. I will now turn it over to Roland Burns to provide the financial impact of this transaction and to review our first quarter results in more detail. Roland, it's yours.

Thanks, Jay. On Slide 5 in the presentation, we break out our West Texas properties from our 2012 results. This slide breaks out the 2012 results so you can see the impact of this transaction going forward on our numbers. And as Jay said, starting this quarter, we're reflecting the assets and the operating results of the West Texas properties as discontinued operations and we're excluding them from our continuing operations results. The properties we're selling represented 22% [ph] of our oil production at 1,400 barrels per day in 2012, and less than 1% of our natural gas production at 2 million cubic feet of gas per day in 2012. These properties generated $47 million in revenues or 11% of our 2012 revenues. Oil, as a percent of our total revenues, decreases to 47% without West Texas, as compared to 52% with it. Our average oil price realization before hedging improves to $101.09 per barrel as compared to $96.95 per barrel. Our average natural gas price realization decreases to $2.49 per Mcf as compared to $2.52. Lifting cost per Mcfe produced improves to $0.96 from $1.06. And DD&A per Mcfe improves to $3.77 as compared to $3.85. $202 million of our $549 million in capital expenditures last year were spent on the Permian properties, and we sold 23% of our proved reserves in the transaction, including 52% of our oil reserves. 81% of the reserves that we sold were undeveloped. So after the sale, 75% of our total reserves are developed as compared to 62% before the sale. Now looking at our first quarter 2013 results. On Slide 6, we show our oil production by region on a daily basis and we show it for the last 3 years and for the first quarter of 2013. The West Texas oil production is shown on red on this chart, and it's also combined with other production that we have sold in the past. Total first quarter 2013 oil production increased to 6,700 barrels per day and was 600 barrels per day higher than the fourth quarter last year. Half the increase was in the discontinued West Texas properties being sold, which averaged 1,900 barrels per day in the first quarter. The other half was from our Eagle Ford properties in South Texas, which increased to 4,600 barrels per day. In the fourth quarter last year and the first 2 months of the first quarter this year, we had many of our Eagle Ford Shale wells shut in due to artificial lift installation or for offset frac activity. We got all these wells back on production by the end of February. And with the increased drilling that's now planned for the Eagle Ford in the second half this year, we expect our oil production from continuing operations to grow by approximately 28% to 34% over last year's pro forma continuing operations production. The total continuing operations oil production, we think, will average between -- will be around 2.3 million barrels to 2.4 million barrels of oil in 2013. Slide 7 shows our natural gas production on a daily basis. As expected, with limited drilling activity, last year, our natural gas production declined by 9% to 177 million cubic feet per day, as compared to the 195 million cubic feet per day in the fourth quarter of last year. Production from our Haynesville and Bossier wells, which is shown in dark blue on this chart, declined to 124 million per day this quarter. Our remaining gas production rates remained the same as in the fourth quarter. Production from our Cotton Valley wells, shown in green, averaged 25 million per day. Our South Texas gas production, shown in light blue, was 20 million per day, and Other gas production, shown in purple, was 5 million per day. And then we are divesting 3 million per day of our gas production, which is attributable to our West Texas properties. We expect our natural gas production related to the continuing operations to decline further this year and to be approximately 57 Bcf to 61 Bcf, which will be a decrease of 25% to 30% from pro forma 2012 production from continuing operations. Slide 8 shows our realized oil prices related to our continuing operations. Our price realizations in South Texas continued to be strong in the first quarter of 2013, as we realized $105.82 per barrel, up slightly from $105.19 per barrel we realized in the first quarter of 2012. With the significant Gulf Coast premium we received in the first quarter, our realized price averaged 112% of the average benchmark NYMEX WTI price. 89% of our oil production was hedged in the quarter at a NYMEX WTI price of $98.67. So after our hedging program, our realized price improves to $111.19 per barrel, 9% higher than the after-hedging oil price we averaged in the first quarter of 2012 of $102.06. On Slide 9, we outline our hedge position for the remainder of this year. We have a very attractive oil hedge program which protects our 2003 (sic) drilling program. We have 5,778 barrels hedged per day for the second quarter at $98.69; 5,556 barrels per day in the third quarter hedged at $98.72; and 6,000 barrels per day hedged for the fourth quarter at $98.67 per barrel. Slide 10 shows our average gas price, which improved by 21% in the first quarter to $3.15 per Mcf, as compared to $2.61 in the first quarter of 2012. Our realized gas price was 94% of the average NYMEX Henry Hub gas price for the quarter. On Slide 11, we cover our oil and gas sales including the hedging gains or losses. Our decline in natural gas production was offset in part by improved oil and gas prices in the quarter, though sales related to our continuing operations decreased by 5% to $97 million in the first quarter, as compared to $102 million in 2012's first quarter. Our oil production made up 49% of our total sales, as compared to 43% in the first quarter of last year. Our earnings before interest, taxes, depreciation, amortization and exploration expense and other noncash expenses, or EBITDAX, increased by 3% to $81 million from $79 million in 2012's first quarter, as shown on Slide 12. $9 million of our EBITDAX in the first quarter was related to the discontinued West Texas operations, with $72 million attributable to our continuing operations. Slide 13 covers our operating cash flow. Our operating cash flow for the quarter came in at $62 million, a 10% decrease from cash flow of $67 million at 2012's first quarter. $6 million of our operating cash flow in the first quarter was related to the discontinued West Texas operations, with $56 million attributable to our continuing operations. On Slide 14, we outline our earnings. We reported a net loss of $24.5 million or $0.52 per share from our continuing operations, and a loss of $2.6 million or $0.06 per share from our discontinued West Texas operations, as compared to earnings of $1.4 million or $0.03 per share in 2012's first quarter. The first quarter financial results in both periods include several unusual items. We had gains from the sales of marketable securities in both quarters. In the first quarter of 2013, we had a gain of $7.9 million, or $5.1 million after tax, or $0.11 per share from the sale of our remaining position in Stone Energy, and we had a gain of $26.6 million, or $17.3 million after tax, or $0.37 per share in the first quarter of 2012 on the sale of 1.2 million shares of Stone. We had mark-to-market unrealized losses related to our oil derivatives of $8.8 million, or $5.7 million after tax, or $0.12 per share, in the first quarter of 2013, and $10.2 million or, $6.6 million after tax, or $0.14 per share, in the first quarter of 2012. Both quarters included some impairments on natural gas unevaluated leases in producing properties, $2.4 million, or $0.03 per share, in the first quarter of 2013 and about $1.3 million, or $0.02 per share, in the first quarter of 2012. We also have had a gain in 2012 of $6.7 million, $4.4 million after tax, or $0.09 per share, on property sales. Excluding these items, we would've reported a net loss from continuing operations of $0.48 per share this quarter and about $0.27 per share in 2012's first quarter. On Slide 15, we show our lifting cost per Mcfe produced by quarter related to our continuing operations. Lifting costs are comprised of 3 components on our income statement: production taxes, transportation costs and then other field-level operating costs. So our total lifting cost increased to $1.07 per Mcfe in the first quarter of 2013, as compared to $0.98 per Mcfe in the first quarter of 2012 and $1.02 per Mcfe in the fourth quarter of 2012. The increase is mainly due to the lower production we have this quarter and the fixed nature of much of the lifting cost. Production taxes were $0.12 per Mcfe this quarter. Our transportation cost averaged $0.23 in the first quarter, and then the field operating cost averaged $0.72 this quarter. On Slide 16, we show our cash G&A per Mcfe produced by quarter, excluding stock-based compensation. Our general administrative cost increased to $0.31 per Mcfe in the first quarter 2013 as compared to $0.21 per Mcfe in the first quarter of 2012. Our total level of G&A expense was roughly the same between the 2 periods, so the increase is solely attributable to the lower production volumes we have this quarter. Our depreciation, depletion and amortization per Mcfe produced is shown on Slide 17. Our DD&A rate in the first quarter averaged $4.66 per Mcfe, as compared to the $3.24 rate we had in the first quarter 2012 and the $4.43 we averaged in the fourth quarter of last year. The higher cost of the oil production and the write-down of undeveloped natural gas reserves last year, arising out of very low natural gas prices, are driving this increase. On Slide 19, we break out our 2013 drilling budget, which has been updated for the increased activity now planned for the Eagle Ford properties in the second half of this year. This year, we expect to spend $347 million on our continuing operations. The new budget has us drilling 82 wells this year: 10 gas wells and 72 oil wells. $312 million will be spent on the Eagle Ford shale program to drill 46.9 net wells. We've also budgeted $32 million for any required drilling to hold acres in the Haynesville shale. In addition to drilling expenditures, we plan to spend another $12 million on acres -- on acreage in 2013. We'll flip back to get back to -- we have skipped Slide 18. So let's cover Slide 18, which is an important one, where we detailed our capital expenditures relating to our continuing operations incurred this quarter. So capital expenditures on our discontinued operations after January 1 -- on our discontinued operations after January 1 are going to be reimbursed under the purchase of sale agreement, so they're excluded from this slide. But we did spend $58 million in the first quarter, as compared to $140 million we spent in 2012's first quarter on our continuing operations. The capital expenditures in South Texas, which is shown in red, relate to our Eagle Ford drilling program, and they decreased to $54 million this quarter as compared to $68 million we spent in last year's first quarter. Lower well cost and to promote that we're earning under our KKR joint venture account for the decrease. With low natural gas prices, our spending for our natural gas properties in North Louisiana declined to only $4 million this quarter, as compared to the $72 million we spent in the first quarter of 2012. Our capital expenditures related to our continuing operations this quarter line up pretty well with the $56 million that we generated in operating cash flow from our continuing operations. So now, we'll go ahead and go to Slide 20, which recaps our balance sheet at the end of the first quarter. And we also show our pro forma balance sheet for the West Texas divestiture which we expect to close in the second quarter. On March 31, we had $1.3 billion of total debt, which is comprised of about $885 million of senior notes and then $450 million outstanding under our buying credit facility. Our current borrowing base under the bank facility is $570 million, which leaves us about $120 million in availability. Pro forma for the West Texas divestiture will have $325 million of cash on the balance sheet and a note bank debt outstanding. Accordingly, our net debt will be reduced to $560 million and will fall to 29% of our total capitalization as compared to 59%, where it is today. I'll now turn it over to Mark to review our drilling results in the first quarter.

Thanks, Roland. On Slide 21, 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 of oil equivalent net to our interest. In the first quarter, we drilled 11 horizontal oil wells, or 7.2 net, and had 3 wells, or 2.3 net, drilling at March 31. We have completed 10, 6.4 net, horizontal Eagle Ford shale wells, including 6, 3.8 net, wells that were drilled in 2012. The 10 Eagle Ford shale wells that were completed had an average per well initial production rate of 854 barrels of oil equivalent per day. Slides 22 and 23 show the results and locations of the 57 wells which are currently producing in the Eagle Ford. We completed 10 more Eagle Ford wells -- Eagle Ford shale wells since our last update. They are wells #48 through 57 on this list. The 57 Eagle Ford shale wells that were completed had an average per well initial production rate of 729 BOE per day. These wells are being produced under the company's restricted choke program, and the initial tests were obtained with a 14/64 to 16/64-inch choke. The 30-day per well production rate for these wells averaged 560 BOE per day, and the 90-day per well rate averaged 464 BOE per day or 68% of the initial 24-hour test. The 2013 completions have initial rates that are 32% higher than the initial rates in 2012. The 4 wells with the highest initial production rates were the Swenson A #1H, the Gloria Wheeler C #1H, the Gloria Wheeler A #3H and the Rancho Tres Hijos B #1H, all located in McMullen County. There you go. These wells are located in McMullen County and had an initial production rate of 1,222, 1,032, 978 and 968 BOE per day. As I said, Slide 23 shows the location of the 57 producing Eagle Ford wells. On Slide 24, we show how the cost of our Eagle Ford Shale wells have come down considerably since we started drilling in August of 2010. The costs in this slide have been adjusted to a standardized lateral length of 5,800 feet to make them comparable. The costs are based on actual cost for completed wells and AFE costs for future wells. You can see that in the beginning, these wells cost over $12 million, and that has significantly improved to just under $8 million. Faster drill times and lower well stimulation costs account for much of the savings. Slide 25 shows the location of our planned 72 Eagle Ford wells, reflecting an increase from our original plan with the pending West Texas sale. We plan to add an additional 3 operator rigs in the second half of the year. You can see the high concentration of planned wells in McMullen County, where we have achieved the best results. Slide 26 shows the net Eagle Ford wells being put on production per month in 2012, and what is projected for 2013, which reflects the addition of 3 new rigs in the second half of 2013. The monthly variation is due to multi-well pad drilling and subsequent multi-well stimulation operations, which result in the lumpiness of the result -- of the resulting Eagle Ford production curve in 2013. Production in the first quarter of this year was affected by low number of completions in that quarter. The second quarter Eagle Ford production will benefit from a high level of completions, while the third quarter will have a slower rate of increase due to lower activity in that quarter. The impact of the accelerated program will be seen in the fourth quarter of this year and the first quarter of next year. I'll now turn it over to Jay.

All right. Again, Thank you, Roland, and thank you, Mark. If everybody return to Slide 27, which is the 2013 outlook. On Slide 27, I'll summarize our outlook for the rest of the year. Even though natural gas prices are improving, as we all know, 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 have high returns on those projects. We expect the strong growth in our oil production will more than offset the natural gas production declines to allow us to have higher revenues and cash flow and be a much more profitable company in 2013. We expect oil to comprise 20% of 2013's production even after the sale of our Permian Basin properties. 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'll be able to ramp up our high-return Eagle Ford program and drill 72 wells by the end of the year. We continue to have one of the lowest overall cost structures in the industry. We'll have a very strong balance sheet after the West Texas divestiture closes on May 14. We will have over $800 million in pro forma liquidity, and our pro forma net debt improves to 29% of total capitalization from 59% at the end of the first quarter. And we see our 6-rig Eagle Ford drilling program being funded with our operating cash flow by the end of this year. For the rest of the call, we will take questions only from the research analysts who follow the stock. So Stephanie, we'll turn it back over to you.

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

Regarding the Eagle Ford, can you maybe talk about what you have been drilling on in terms of spacing and what you have tested or planned to test over the next, call it, 6 to 12 months?

Yes, Mark?

Yes. We're currently drilling -- you have to look at it a little bit different than acreage spacing because of the lateral lengths in the area and the shape of the acreage. So our current spacing pattern is about 500 feet. So that's how we're set up to drill, and really, that -- we're in development mode now and that's our goal, is to drill at this 500-foot spacing pattern. And we may do a little bit of testing. We have no firm plans at the moment to test the tighter spacing than that. That's really how we're established on our acreage at this time.

Okay. And when you add -- I guess, when you get to 6 rigs, almost everything -- or you have no HPP issues? Everything should be pad drilling?

Almost everything is. We will have a little bit of drilling on some of the northern acreage and then 1 acreage block to the West that has not been drilled on yet, that is still [indiscernible] to be drilling. But say, 90% of our drilling will be development drilling on pad sites.

Okay. And is there any other acreage? Are you all looking at other acreage in the Eagle Ford and around your areas? And I'll hang up and listen.

One thing that we were really not able to do because we were pretty cash-strapped before the divestiture of the Permian -- I mean, we weren't actively seeking any new acreage position. Even though I think we would have had some financial backing with our partner, I don't think we have "the headcount" to do that. So now yes, this has freed us up to take a look at that, and we have been taking looks at that. If you're the size company we are, it doesn't take many additional acres to have a pretty big impact. I'll tell you what we're not interested doing. We're not interested in buying hundreds of thousands of acreage in this goat pasture just to tell you we have a lot of extra acreage out there because we're not going to squander money like that.

Your next question comes from the line of Ron Mills with Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: A question just on the Eagle Ford program. You provide all the well results. And looking at Slide 25, am I counting the dots right in the sense that if you look at your 72-well program, it looks like about 60 of those 72 wells are going to be more in that central part of McMullen County, where you've had the stronger well results? Is that right? And then as you move forward as well, is that where you think the activity will remain concentrated?

Ron, yes. In fact, again, one of the things that we can do with a delevered balance sheet is we can double down on our rig count in the Eagle Ford, and we had de-risked the Eagle Ford by probably middle of last year. And what we wanted to do, and like we've shown on some of these slides, we want to reduce our cost and we want to increase our IP rates. And one way to do that is to drill more of your wells in McMullen. And so, yes, you're exactly right. And as far as Brian had asked a question earlier about whether the acreage is HPP, [ph] if you remember, in 2010 and '11, our total gross rig count or well count in Eagle Ford, was 17 wells in all of 2010 and '11. Last year, we drilled 30 gross wells. This year, because of the divestiture, again, we'll drill 72 gross wells in 2013. And Mark had talked about a little spottiness. Well, we had a lot of spottiness going on in the Eagle Ford program before we were able to add the fourth and fifth and sixth rig. In fact, and I looked at the numbers, in the third and fourth quarter, with this new business model, which again, I think Roland said we're pretty much going to fund this out of our free cash flow from continuing operations, that's our goal. I mean, if you look at the completions that we'll have added in the third and fourth quarter along with this new drilling program, it's almost 14 new net completed Eagle Ford wells. That's why we can take this production in Eagle Ford from this 40 -- 300, 400, or 500 barrels a day, hopefully we can exit it to 9,000-plus barrels a day and then we can do a lot better than that at the end of 2014, again, hopefully within our free cash flow from operations and, at the same time, have a completely undrawn credit line of $0.5 billion and $300 million in the bank. I mean, if you believe the old adage of "cash is king," we're going to be in pretty good shape for that. We're rambling, but we're pretty excited about where we are because if you've ever owned a share of stock, we haven't diluted you and issued any shares for over 8 years. We don't have any other the derivatives out there except for bonds and some hedges. So things are pretty good at Comstock. So go ahead, Ron. More questions? Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Yes. The question is as it relates to that $325 million cash position, to follow up a little bit on Brian's question about incremental acreage in and around your existing Eagle Ford, or I know you have some notes that become callable in October. And how do you -- at least, what's your framework, internally of how you evaluate the cost benefits of acreage acquisitions and/or debt reductions versus a potential stock buyback, if you view your shares as basically an acquisition opportunity as well?

Well, again, I think my overall answer to that would be, when we had our conference call in February of 2013 and reported year end and the fourth quarter, we tell all the stakeholders that we had too much debt, and we realized that the industry is facing a capital intensity challenge. And we recognized that, And we told the stakeholders that we need to delever the company. Now I think it's very much a win-win for Rosetta and for Comstock because we had 2 Tier 1 oil plays, and they were really Tier 1 and they both needed a lot of capital. I mean the Permian needs a lot of capital and so does the Eagle Ford. And we, quite frankly, with our balance sheet, I don't think we were able to tender the capital that was needed in both of those regions because I think our leverage was too high. When you have too much leverage, you get kind of in the danger zone and you flirt with financial issues. It's not fun. And most of these companies don't come out of that unscathed. So by being able to monetize this for a fair price, I think what you see, to answer your question, I think these are the things that we can do now that we couldn't do before we had exited the Permian. We talked about -- that we've given the stakeholders a very large gain. It's an unbelievable return to our stockholders within a year. And we've gone from maybe a $570 million credit facility to $500 million. It's pretty unbelievable. I mean, that's $0.5 billion undrawn. And we have, as you mentioned, the $300-plus million cash in the bank. So what does that allow us to do now? Well, as Brian mentioned, we can look at the Eagle Ford now for some acreage, 1,000, 2,000, 3,000, 5,000, 10,000, whatever. And we can do that even with our partner, KKR, because we're kind of hand partners with them. So I think if we find something that has that [indiscernible] return, then we have the ability to do that because our technical team, they understand that area. I think we would be able to tender for our bonds in October if we so choose to do that. We couldn't do that before. And if we do that, that saves $22 million or so a year. Now I think we can add to our core area without diluting our stockholders. I think we've got a new business team here to develop new opportunities. It's the same group, but it's a new business team model. We couldn't exercise our internal strength with the financial balance sheet we had. And then again, you don't want to not talk about the Haynesville. I think it does let us re-evaluate our Haynesville/Bossier acreage and what type of internal rate of return we might get in the future. But the beauty of this, is this time last year gas was $2.04. Today, gas is like $4.40. And we're telling you as a company, we're not increasing our rig count in the Haynesville just because gas is even $4.50. But we're evaluating our opportunities now. So there's so many things that we can do now that we couldn't do, that we were constrained from doing. And again, Ron, I think that does include adding Eagle Ford acreage and adding the 3 rigs. And I think fundamentally, I think we will be a much better story as a delevered story. So Roland might want to comment on that a little bit.

No, I think you summarized it really well. I think the company will have a lot of options to redeploy some of the cash that will be on the balance sheet after the close. And the goal of the company is to maintain a much stronger balance sheet than we had after acquiring the West Texas assets. And as natural gas prices improve, that also improves the balance sheet, just with the natural gas prices almost doubling to where they were, especially in the second quarter last year. So there are a lot of options. And I think that we're going to close the transaction first and then present a lot of these options to our board and really be mindful of how can we create value if we're the stockholders and in the long run. And that's what we'll do with this balance sheet. We're not concerned about the lack of opportunity at the company because we've always had more opportunities to look at -- to either acquire properties or drill properties. That's never been a weakness of the company as you can look at our long history. And...

And as Roland said, I think one of the criticisms, is what's your depth of opportunities? And my answer to that, on one-on-ones because we've not been out touting this story, is well, if you look at who Comstock is, it was August of '08 that we monetized our Gulf of Mexico assets to Stone. And it was at the end of '07 that we started deepening wells in DeSoto Parish, whereby '08, '09, that's the heart of the Haynesville/Bossier play. And then it wasn't until the beginning of 2010 that we sent "our scouts" out to find more oil in South Texas. So through our G&G group, I mean, the 27,000, 28,000 net acres we have in the Eagle Ford, we started adding that in 2010, 2011. And look where the Eagle Ford is today. Then at the end of 2011, [indiscernible] , we announced that we're in the Permian and we'll be out in 2 weeks. I mean, as Roland said, we have never ever, ever had a shortage of opportunities that, quite frankly, have been good. And we've received a gift of a lot of cash, and we're going to be good stewards of that cash. We're going to create wealth for the stockholders on a per share basis. Period. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay, great. And then one last one. This is for you, Roland. On Slide -- I don't know what it is -- 5, where you have -- you tried to break out the financials in terms of the costs, unit costs and whatnot, x the divestiture. The pro forma column on the cost side, particularly on lifting cost, which is the biggest improvement, is that a good -- do you think those are good run rates in terms of your total lifting costs and overall cost structure? Or how should we think about the cost structure post asset sale in mid-May?

I think they're definitely a good indication of the different property mix. Obviously, the West Texas properties were not a large component of the numbers yet. But the other things you have to be mindful of is lifting cost is not a variable number. Only property [ph] production taxes and the transportation are pretty variable to production rates. So until we -- with some of the decline in production in the Haynesville, I mean, some of the lifting cost will still be there in less volumes to amortize it over. So I think that would be the only other trend that will happen a little bit. I think the absolute level of lifting cost we had this quarter on a dollar amount is very -- on a continuing operations basis is a good indication of what we expect for most of this year. And that number, on a unit basis, could look higher with the lower volumes that we can have from the gas area. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Did the first quarter include some higher cost associated with the artificial lift that may not be repeated in the second quarter? Or is that just incorrect?

There was a little bit of that in the first quarter. But then of course, with -- I think when you take into account some of the additional production we're putting on, I think that absolute level is kind of fairly indicative of what we could expect in the quarters in the future versus the -- probably increasing for a different reason and decreasing for the lack of those workovers. A lot of those workovers were probably in the discontinued operations' lifting cost.

Your next question comes from the line of Leo Mariani with RBC.

Jay, you made a comment that potentially, you get to get after gas a little bit now that you've got a much improved balance sheet. It didn't sound like that was really 2013. I guess Roland, you said obviously you guys will have a board meeting post to close in May. I'm just trying to get a sense of whether or not it's reasonable to expect to say gas was $4.50 or higher in 2014 for you guys to drill some gas wells?

I think what we do after the closing is we evaluate all of our opportunities. I mean, in the Eagle Ford right now, we'll probably get a 40% to 50% IRR. And unless it's competitive to the Eagle Ford, then I don't see us putting any meaningful number of rigs to drill natural gas. Most of that gas is HPP, and we've proven that. Because this year, if you look at the 10 wells that we'll participate in, maybe, but that's really kind of not accurate. I mean, that's a gross number. If you dig down in that number, it's like 3.2 net wells. And out of that, 2 of them are mandatory that we drill to hold acreage. The rest of that is a guess that we might receive an AFE as a non-operator. So, no. We're not -- even though we think natural gas fundamentals right now are looking better than oil, we're not interested in putting a lot of rigs or any rigs in drilling the Haynesville/Bossier. It's HPP. I think we should use our cash elsewhere right now. I do think if we have an industry partner that wants to accumulate some acres in Tier 1 Haynesville's, then we'd be interested in that. And guess what, there's 0 acreage like that for sale because they shouldn't be sold. It's too valuable. So no, I think, again, as Roland had mentioned earlier, once we close, we'll have a strategic board meeting and a management meeting, and we'll see where oil prices are, where gas prices are. We'll get from Mark what our well results look like. And again, in the Eagle Ford, there are 32% higher IP rates than they were last year. And we'll see what our new business opportunities are, and we'll put a budget together where we have a CapEx that's within our cash flow. And I think that's what you're going to see from us. It's going to be a much more predictable story with a lot less risk, with a lot more upside that is more predictable.

Okay. I guess as a brief follow-up to that, you mentioned the 2 wells you have drilled this year hold acreage on a net basis. Just trying to get a sense of where that might go next year, will you also have some obligation wells to drill next year, and how many might that be?

Well, maybe got a couple more.

Yes, Leo, the 2 wells that we're drilling right now tie up that unit. And so it's HBP. And I'm not aware at the moment of anything we really have, obligation-wise, for next year. I think that was kind of the last one on the books for us.

What we might do is, if our reservoir group and G&G group and Mark all agree, and we want to test a longer lateral, or 2 or 3 or 4 of those type wells in the Haynesville/Bossier and see what the economics looks like, and what the IP rates are and what the RoR is, what our well costs are. We wouldn't consider that a "Haynesville/Bossier drilling program," we'd look at that more as an exploration type program to see if we can de-risk and add meaningful reserves and a lot lower cost to have a much higher RoR. But as far as a "Haynesville/Bossier Drilling Program," we're not really looking at that at all right now.

That's helpful color. And I guess, just jumping over to the Eagle Ford, you guys talked about pretty significant downtime on production in the field due to installing artificial lift and then just offset frac activity. It looks like that's been happening for the past couple of quarters. Is there any way you guys can give us like a ballpark quantification where that's hitting production by 15% or 20%? Or is there any way just to think about that? And then going forward, is that going to persist for the rest of the year? Would you expect that to be ironed out at some point? Whether that's this year or next?

This is Mark. I think it hit production in late Q4, early Q1 by maybe 20% to 25%. Almost all of that was resolved in February. It basically had everything back on -- around the end of February. So we were starting to get our production back full force in March, but we just didn't have many completions until March, and those didn't start selling until late March. So we just didn't see any effect of all those completions in the Q1 numbers. Q2 numbers should be much better. And we'll always have a little bit of ongoing downtime from offset frac-ing and from installation of artificial lift and just R&M, or repair and maintenance on these type of wells. But it will be much more manageable, I believe, going forward. More like 10%, which is kind of a normal number.

And what we've tried to do, if you go back to the February report that we put out and look at the Eagle Ford well completions, if you'll compare that to Slide 26, what we tried to do, to answer that question, is we try to put the well completions on a monthly basis. And you'll see that's what we add in the third and fourth quarter, another 13, 14 net wells to try to take out some of that lumpiness. You will still see it on this Slide 26, but if you go back to the February 2013 slide and you look at that one versus Slide 26, it's not nearly as lumpy. And the reason is, again, I think that the Permian and our Eagle Ford plays were materially undercapitalized. I think that's why Rosetta got a great property and I think we now have the cash to accelerate our Eagle Ford, and you see the results of that.

Your next question comes from the line of Rehan Rashid with FBR Capital Markets. Rehan Rashid - FBR Capital Markets & Co., Research Division: Sticking with Eagle Ford for one quick second. So the current well completion chart that you guys talk about, that incorporates the ramp to 6 rigs, correct?

Correct. Rehan Rashid - FBR Capital Markets & Co., Research Division: Got it. And we get to that, if you could remind me one more time, please, by the end of third quarter, by the end of fourth quarter, the 6-rig program?

Well, what you see is our goal is to add rig -- we have 3 rigs now, those results that we gave you. We exited 2012 with 3 rigs. So what you see on this, what we gave you as first quarter number, that's a 3-rig program that's kind of implemented. So now what you see, another rig in May, another rig in June, and hopefully, our sixth rig in July. That's our goal. And that's what the chart shows. So really, if you look at the chart, it's in the fourth quarter that you see what 2014 might look like if we have a 6-rig program, all of 2014, and it's pretty material oil production growth. Rehan Rashid - FBR Capital Markets & Co., Research Division: Absolutely.

We can give the stakeholders with a total 6-rig program in 2014. Now, Rehan, you have to put an asterisk by that because we were going to see what oil prices are, we're going to see what our cash flow looks like, we're going to see what the share prices are, we're going to see if the shares trade at a decent multiple. All these are things we're going to look at before we commit to the stakeholders and to the analysts, Rehan, what we're going to do in 2014. But I think that probably answers your question.

Yes, yes. And then a quick 1 or 2 more. As you have looked for these incremental rigs, directionally speaking, drilling, completion costs, any color on that?

Well, we have a slide that shows you we're down $10 million to like $7.7 million. And Mark, can you comment any more if it was here on that slide. What slide is that?

That's Slide 24. And you can see that those costs that really flattened out in the last 3, 4 months, and I believe that we're pretty stable. Our frac contract is stable until end of the year. I don't see those costs coming down anymore. The rigs we're picking up. Our plan to pick up will be very similar to the rigs we're running right now. And so that cost, that $7.7 million or so, is really the pad drilling, the current frac contract and the high-efficiency rigs. So I think that's about where we're at.

I think we have, what, the [indiscernible] campaign [ph] and Cactus, is that who we're using?

That's what we're using now.

Yes, right now. We're using 2 [indiscernible] campaign and 1 Cactus rig right now. Rehan Rashid - FBR Capital Markets & Co., Research Division: Perfect, perfect. And Mark, one more question. I missed the call, the beginning of the call. So did you go and talk about kind of down-spacing? Other folks talk about going as low as 40 acres in the Eagle Ford. You guys are around 80. Could you walk us through maybe some path towards, if not testing right now, when and kind of what data are we waiting for before we try it?

Right, Rehan. We're established right now. Our spacing pattern is 500 feet. So it's about 60 acres on a 4,500-foot lateral, and it's about 90 to 100 acres on a 9,000 or 10,000-foot lateral. So it's really based on width between wells and not acreage. So the 40-acre pattern may be shorter laterals in a more prolific part of the play. I don't think that's really feasible where we are. So we think we're at the right spacing, and we may look -- we're still monitoring everybody else. We're looking at our results. We may test a little bit, too. But right now, we're pretty well established on that 500-foot spacing. Rehan Rashid - FBR Capital Markets & Co., Research Division: Okay, got it. And one last one, I promise on this one. So what kind of recovery factors are implied in your resource potential that you detailed on Page 21?

We're probably in the 6% or 7% range, is where we're -- and it depends a little bit on the area you're at, but that's kind of the average recovery factor across our play. Rehan Rashid - FBR Capital Markets & Co., Research Division: Got it. And then what will, in your mind, what will it take to move it higher for yourself and maybe for the industry?

Well, tightened up -- tightened well spacing is the way to move that number significantly at this point, I mean, where you can put larger frac job, you can put tighter cluster spacing, which we are testing now. We've done some larger frac jobs, we've done some tighter cluster spacing to improve that incrementally, but those will be small changes. The biggest one would be in-field tighter well spacing, but it depends on what economics you're at now. If you're at 100% rate of return, you can down-space. If you're at 40% or 50% rate of return, you damage your rate of return too much by down-spacing, and so I think we're at the right spacing for our economics.

And Rehan, one thing. If you want to really and truly know -- decide if you want to figure out how to do something, you get an Aggie to do it because they have great engineers, something they really do. Mark is an Aggie, and I'm telling you, he's a big [indiscernible], he's been here 17 years, and if there's a way you can increase recovery factor or down space it and it makes sense, you have to trust that we will do it. Rehan Rashid - FBR Capital Markets & Co., Research Division: Perfect. And Roland, on the October, the bonds we talked about, their callable in October, is that kind of the rough timeframe?

That's correct. We have one of our issues was probably on, I think, October 15. And given that it's 8 5/8 effective rate, given that coupon, it's a real big savings to next year, it's interest expense. So that's something that we'll be looking at pretty hard if we want to exercise that opportunity. Rehan Rashid - FBR Capital Markets & Co., Research Division: And then it's callable at what Revpar?

I think it's like 104. It's the first call date, and then, if we decide to wait, obviously, the call price goes down every year.

Your next question comes from the line of Kim Pacanovsky with MLV and Co. Kim M. Pacanovsky - MLV & Co LLC, Research Division: Back to Page 21 in the presentation. I mean, obviously, you've high-graded your acreage, you're concentrating in McMullen as you spoke about. What are your plans for La Salle, which really isn't on the agenda for this year? And also, as you look at the gross EURs on this slide of 500 MBOE, how does that vary through your acreage?

Kim, this is Mark. The western acreage in La Salle is a much newer lease, so a much later lease term than the acreage in McMullen County. So we plan on starting that program in early 2014, and that will be a development area for us, then. It just isn't -- timing wise, it is unnecessary to develop that La Salle acreage now. The results are very similar to our -- the results around it that we've seen from other operators is very similar to some of our McMullen County acreage. So we do expect it to be very much in the middle of the package, as far as acreage goes for us. It is -- we're just not required to start developing it yet at this time. And then the other question, I believe, was about EURs. And basically, you can just go from south to north, and your EUR is higher than that number to the south and then it dwindles to a lower number than that. As you go north into Atascosa County, and so that basically follows the debt curve or the GOR curve for the most part. Kim M. Pacanovsky - MLV & Co LLC, Research Division: Okay. And then back to Leo's question about the number of wells that will be offline each quarter, can you just -- just for modeling purposes, let us know what production is running right now? And I know that everything that was off in the first quarter is back on, but how many wells are now -- how many new wells are off now, if any? Or how many net wells for the quarter?

For Q1?

For the Eagle Ford?

Kim, I don't have that number. We got almost everything back on in late February, and then we've got 3 or 4 wells shut in right now for offset frac-ing that we'll drill right through there. Kim M. Pacanovsky - MLV & Co LLC, Research Division: Okay, that's what I wanted to know.

This then becomes a process. We're using -- in our internal work, we're using about 10% average for downtime in the field. It was probably double that in December and January when we had our operational issues and we had a lot of wells shut in for frac-ing, kind of an unusual number. But we got that back, and the 10% seems to be matching very well.

And how many wells do we have now waiting to be completed in Eagle Ford?

We had 3 as of a few days ago, I believe, that's what I had on the list.

Yes. Kim M. Pacanovsky - MLV & Co LLC, Research Division: 3 waiting on completion? And current production today, would you give that number?

In the Eagle -- you're talking about in the Eagle Ford? Kim M. Pacanovsky - MLV & Co LLC, Research Division: Yes.

In the Eagle Ford, it's between -- I don't have an exact number, but it's between 5,000 and 6,000 barrels a day net in the Eagle Ford. Kim M. Pacanovsky - MLV & Co LLC, Research Division: That's great. And any thoughts or observations on the Pearsall?

I know we continue to monitor the results. We've got Pearsall potential under most of our acreage, and we drilled that pilot hole and got some log data. We've traded that for some other log data. We are not in a hurry to test that concept. We're letting Cabot and some of the other operators test it and we'll see if the results warrant any capital in the future.

Your next question comes from the line of Mark Lear with Crédit Suisse. Mark Lear - Crédit Suisse AG, Research Division: Jay, you brought up the KKR deal earlier in the Q&A. And just wanted to get a sense for whether those guys had elected for the next basket of 100 wells. And I guess, some of the --- the impact, maybe, some of the infill drilling might have on that agreement is I know they have to pay on a like a per well or a per acreage basis. How does that infill drilling might impact that, I guess, upfront payment per well?

Well, Mark, this is Roland. KKR has been participating in all the wells. And they still haven't -- they're required to do the first 100. I don't think we -- obviously, we haven't drilled 100 yet. So -- but the returns are very high. So we expect in all our projections and in our reserve estimates, we assume they're going to participate in the full development of the field. And I think they'll -- if you look at some of their materials and the funds that own it, I mean it's performing very well for them. And they do pay on, they pay us, basically, $667,000 to participate in a well, which is equivalent to the $25,000 per acre, for the 1/3 of that 80-acre exploration. So that's going continue through the full development of the field, and yes, the per month will be paid all the way to the end pretty much, unless we decide to down-space to much tighter spacing.

Well, Mark, and they're pleased because if you're our partner, and KKR is, all of a sudden, we're the operator and you have to provide a check to get -- have a right to participate in the well, and the costs come down, as we've shown in the slides and production goes up. And oil is $90-plus a barrel. I mean, you're extremely pleased with the agreement. And they are, and so are we. So I think, like Roland said, our economics are based upon them participating in all of those wells. Mark Lear - Crédit Suisse AG, Research Division: Right. So -- but as you infill space, it's still the $666,000 per well? So I guess I wouldn't handle...

With the agreement...

It's based on the 80 acres.

Yes, 80 acres.

And generally, that's what the wells are -- I mean, that's generally what the plan is. Now and if it's -- either, it can be slightly less to the extent that they have 60-acre spacing, and they wouldn't have to pay as much as they have less acres. Basically, if you look at the whole plan, that's a good number to use. Mark Lear - Crédit Suisse AG, Research Division: Okay. And then the that 6-rig run rate would also depend on them. I guess, electing the additional 100 wells are -- if it goes in 100 well tranches, when do they have to tell you or when they...

There's not 100 well tranches. They're committed to do 100 wells upfront, because obviously, we don't want to -- and after that, they can participate. Or if they choose not to participate, then we'll be happy to own 100%. It's a high-return project. That's just not -- unless the returns are low, they're going to participate. And if the returns are low, we probably want to move our capital somewhere else. I just don't see a case where that's going to be an issue.

The next question comes from the line of Dan McSpirit with BMO Capital Market.

In considering leasehold acquisitions, what's the going rate for Eagle Ford shale and Haynesville shale leasehold these days?

Dan, this is Mark. We've really seen very, very few deals in either play. There's really not a going rate. I mean we -- the last deal we heard about in the Eagle Ford was pretty far from us, and it was about $30,000 an acre. So they don't really have a good baseline there in either play, really.

Well, a lot of that depends upon where. I mean there's a lot of goat pastures out there, and you buy them. When they barely go out there, the most expensive thing is a billy goat. It's not worth much. You see those out there all the time. I mean, there's some acreage that you only pay for PDP wells. I mean we're looking for acreage that our geologists would want us to buy. And we start looking at that. We don't know if we'll get any. But I think, where we were not looking for any earlier, we are looking for something. And again, I think, Dan, we bought $2 billion or so in assets, $2.1 billion. It doesn't take a lot of -- it takes a lot of value to a company like Comstock where we have 48 million shares fully diluted out there. So I think what we're telling you is that if we find some that we like when we announce it, then it should be good. And when we do, I think, have a partner who participate with us, which is KKR.

Okay. Okay, and as a follow-up, let me ask, yesterday, we read Southwestern will acquire more dry gas properties, a move that many suggest the bottoming of natural gas asset value. Do you believe natural asset values had bottomed? And where does acquiring more Haynesville and Bossier perspectively sold rank among the options you're considering today?

Well, again, I'd comment. I think natural gas fundamentals right now are -- of course, I wouldn't think they're probably better than oil. I mean oil is $90, $95 and natural gases are going from $204 a year ago to $40 or $50. I think what you're seeing is you're seeing companies be realistic about all the acreage that they've leased, I mean, the Southwestern Delaware bought 162,000 acres or whatever it was, maybe 2 million cubic feet of gas per day for $90-something million. I mean, so $500 an acre, they're really just buying production and paying a little bit for the leases. I think that there's going to be a Tier 1, 2 and 3 in all these major plays, whether it's the Haynesville, the Bossier, the Barnett, the Marcellus. You can call it super rich or whatever, but there's going to be a Tier 1, 2, 3, I don't think you're going to have a fault in this that we had in '08, '09, '10 where people make big bets on leases, and you had to drill them also and you have a recession. When you have a lot of foreign JV partners, I don't think -- when gas gets back in the $5-plus range, some of the true Tier 1 acreage will be very valuable. And I think we're starting to see a little shift toward that. Although the rig count, if you look at -- the rig count, it's kind of interesting if you do your research, but the rig count is at a 14-year low right now in April 2013. But if you go back a year ago, natural gas in 2012 in the month of April was at a 14-year low. It took the rigs another year to hit that number. But now, this month in 2013, I mean, gas is at a 2-year high. So I think you're seeing a tight turn, but I don't think you're seeing any craziness out there, and I don't think you'll see it. I mean, the rig count from natural gas rigs went down last week by 13, 14 rigs or whatever. And I think that's where we're kind of the barometer out there, we're saying we've got a Tier 1 dry gas play in Haynesville/Bossier, and that goes from 0 production to, what, $7 billion a day in like 4 years. So we're still not putting any rigs in there to drill our wells because we base it -- the capital dollars that we spend, we'll base it upon whatever RoR would be, and right now, we have better places to put those dollars.

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

I was wondering if you could talk a little bit more about the quality of the Eagle Ford acreage and maybe some of the variation in the EURs between North and South, and whether the returns you're talking about are kind of applicable to the portfolio, or just kind of parts of the asset, I guess.

Ray, this is Mark. We've talked a lot about our Northern acreage being lower rate of return. And that's why we haven't focused the drilling up there yet. We are drilling a well in the Atascosa acreage at this time. And those rate of returns are probably in the 20% to 30% range, whereas, as you work your way to the South, you're increasing to 40% to 50% to 60% rate of returns. So the numbers we're talking about are average numbers across the whole portfolio and not just the stuff that's focused on the South end.

I think we have the luxury of this divestiture, again, the Permian. It allows us to drill wells, majority of these wells, in McMullen, where in the past, we had to kind of scatter them because we did have several parts we needed to drill to hold acreage.

Right. Got it. And I guess in terms of -- Mark, in terms of hydrating the gas assets on the Haynesville, what -- if you were looking at kind of a batch -- a number of acres that would work at $4.50 to $5, could you say what that is now?

Ray, we're working that problem, but we don't have the answers to put out the public at this time. So I'm really not going to get into that.

Okay, got it, great. And I guess, if you were to keep 6 rigs going in the Eagle Ford, can you talk about kind of where you might get to on the production side and oil by the end of next year?

Yes, I think Jay alluded to that a little earlier. He said we were -- into this year, we're in the 9,000 barrel a day range. And in the next year, with the 6-rig program, if that's what we do, we're probably in the 14,000-barrel a day range, something in that range.

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

Most of my questions were answered, but Roland, just kind of a question for you on the balance sheet. How do you think about leverage going forward? It sounds like you felt a little uncomfortable when you were looking at the leverage north of, say, 3.5x. Would it be fair to say that you guys are thinking about trying to keep it under 3x going forward?

Well, Sean, I think we definitely were a little uncomfortable with the leverage being where it is now, which is a little over 4x, and so that -- some of that's caused by the low natural gas prices last year, so some of that, it corrects in a $4-plus world. But some of it is just the level of debt we were carrying, and then the capital expenditure level versus cash flow. So we were uncomfortable with that. But I think that when we look at -- going forward, our goal is to -- is probably to be below -- definitely below 3.5x, probably 3x, it's probably an okay level for us. Obviously, below 3x, that's a great level. So we really want to be in the upper tier as far as leverage of companies, and I think, staying below -- in the very low 3s to the high 2s, as far as the leverage ratio, is where we want to be as a company. And I think this transaction, kind of immediately does put it us into that new ballpark.

Right. I would agree. And then -- related, just kind of keeping the bias in the forward gas curve, how do you guys think about adding hedges on the gas side at all?

We have been looking at the forward gas curve, and it's amazingly flat, too. I mean, I think even going out even 3, maybe 4 years, you almost get the same kind of price, it's an extremely flat curve. I think that we kind of see the potential hedging of natural gas -- or natural gas production kind of go hand-in-hand when we think the returns are adequate to start drilling again. So I think the 2 will kind of probably come together if we kind of -- we get to a level where we can get returns of 20%, 25% on capital spend. I think we might look -- if we look to put a program out there, we'll probably look to protect that new gas with a hedge. I don't see us, with the real strong balance sheet we have, seeing a lot of need to try to lock in below those return levels just to lock in a certain level of cash flow. Because you have -- I think we want to be able to be competitive when gas prices do come back and not be locked in to be in a very low return by having hedges in place. So a strong balance sheet will give us the ability to wait until the right time to start gas development again, versus prematurely jumping in now because that's the only thing we have to do. Daniel Katzenberg - Oppenheimer & Co. Inc., Research Division: Sure. And then just kind of one last question on the balance sheet. Your most recent notes, that 9.5% -- remind me, is there any sort of mechanism that you guys have in order to take those out earlier just to save on the interest expense?

Well, the only thing that comes unconventional, we do have the equity clawback kind of as we did an equity offering, we could retire some of those proceeds. I mean those are notes. And -- but we don't really need to do an equity offering. So right now, those notes will probably out there and we'll be able to take the second most expensive notes out if we want to, in October. But obviously, you could try to buy those in the open market, but they're trading at very, very high premiums as they should. Daniel Katzenberg - Oppenheimer & Co. Inc., Research Division: And Jay, just kind of one clarification. I think you mentioned you might entertain selling a stake of your Haynesville acreage. Just so I understand, are you planning to run a formal process there? Or are you just kind of throwing that out as an example of what you might do with the asset?

Well, number one, I never said we'd sell anything. Period. We're not selling anything. Asset sales is not a part of our story, period. So if you heard that, and I said that, then I apologize. And I didn't say it, though.

I think Jay may have been commenting on -- if to the extent that we might want to acquire some future gas acres, that might be something we would do with a partner. But as far as selling any existing assets, right now, we're not focused on that at all.

Right. And we would not entertain that at all. In fact, I think, Sean, that's a great strength we have, and then we didn't have to liquidate a Tier 1 gas play or part of it to fund other Tier 1 regions that we have. Asset sale is not part of our story at all. In 2 weeks, we'll have completed that. I think we want an inventory that, there's kind of Dan and Ray, Mark had mentioned earlier, and when the fundamental gas price gets competitive for the Eagle Ford, then I think you'll see us have a Haynesville/Bossier drilling program, but we're not nearly there right now. Daniel Katzenberg - Oppenheimer & Co. Inc., Research Division: I apologize, I may have heard your previous...

No. I'm glad you brought that up because if somebody else heard it, then we'll clarify that. That's a great sentence.

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

I was hoping you could talk a little bit more about the opportunities that you see in front of you. First, if you can just give us a -- your thoughts on your location count in the Central McMullen acreage where you've been knocking out these great wells and just talk, maybe in general terms, about your running room there. And second, interested to hear if you'd be adding acreage organically or leasing outside of Eagle Ford under some sort of program that might be classified as new ventures type of program.

Well, Mike, this is Mark. As far as the Eagle Ford goes, you can see the map on Page 25. The acreage in the -- and we need to get this labeled in the future, just so a little easier to talk about. The acreage, kind of farthest to the Southeast is our house track, our [indiscernible]. That is pretty well developed after 2013. The rest of the acreage -- and acreage is just kind of the Northeastern corner of McMullen county, is pretty well developed after 2013. We have a lot of locations left in our Forrest Wheeler area, which is the southernmost acreage. And then the RT, Rancho Tres Hijos area,which is that really rectangular block, south of the name, McMullen. We have a lot of development room there. And so those will develop in 2014. And then we'll concentrate more in our 4 corners area, which is all the acreage kind of in the corner of the 4 counties. We have a lot of locations, probably 50 to 70 locations, just guessing here, in that area that we will develop. And then we'll just continue working our way west and north as long as gas prices allow us to maintain the returns that we want, we'll continue to develop the acreage west and north from there.

And then I think as far as adding, I mean, opportunity is there, and we can add acreage that we think gives us the proper rate of return in our core areas, we would do that. And as far as the new areas, I mean, we do have a business development team. I mean, they're the ones that had us deepen the Haynesville/Bossier back in third and fourth quarter of '07. They're the ones that led us into the Eagle Ford, and led us into Permian. But you will not see us making a purchase of a producing property. I mean, if we enter a new area, it will be kind of like how we entered the Eagle Ford and how we were entering Gaines County. I mean, Rosetta got a good property in Gaines County and that we would have a land group for 2 or 3 leasing acreage and that would be very inexpensive acreage and we would drill our way to prove it up. So we don't plan to spend any real money on that areas.

Okay. And real quick. 6-rig Eagle Ford program, what's the ballpark number for a quarterly CapEx under that scenario?

I think the -- when the 6 rigs are fully running, it's probably about $100 million, in that neighborhood based on the KKR participating in the program.

That's about what I had, too, here. About $100 million to $110 million a quarter.

Your next question comes from the line of Amir Arif with Stifel. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Just one quick question. When we think about realized pricing in the Eagle Ford, should we be thinking about a discount to LLS or a premium to WTI in terms of the way you've structured yourself?

Well, I guess, it's priced off of LLS. And that it's not priced off of WTI. So as most of the oil production in the Eagle Ford for most producers is all LLS price, because that's where the oils actually go into that market. So the relationship between WTI is just -- and Eagle Ford oil, is really just a function of the relationship between LLS and WTI. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: And Roland, what kind of a discount should I be thinking out of LLS?

I think that historically, we have been averaging -- if you take the difference between WTI and LLS, we've been capturing about half of that premium, net back to us. And I think as some new transportation arrangements are coming into place where we can go to more pipelines, we see that improving. But those are still on the works, they haven't been finalized. But where we're located at McMullen is kind of the heart of the Eagle Ford and there are some new oil pipelines that even are crossing some of our leases. So we expect to stop trucking in the future and delivering the pipelines, which will create a bigger premium for us and reduce some of the transportation costs. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. So if LLS is coming down relative to WTI, you still think your realized prices can go up with the new pipeline options, is that what you're saying?

Well I think the overall transportation cost will go -- will be reduced. Our index based price will tie in with LSS. We'd capture more of that premium with better transportation.

Your next question comes from the line of Richard Tullis with Capital One Southcoast.

Just a couple of questions on the Eagle Ford completions in 1Q. Mark, how do those compare to, say, what you did in 4Q, lateral length completion stages, et cetera?

Richard, the lateral lengths, I don't have the exact number before me, but they've been a little bit longer. In the first quarter, we've got on some leases that had -- we had some long laterals planned. And so we're probably, on average, maybe 200 or 300 feet longer. Our number of stages is really -- relates to lateral length. So on the longer wells, if you're 300 feet longer, you'll probably average 1 more -- have 1 more stage in there. So where we were average at about 15 stages, those wells might have been averaging 16 to 17 stages.

Okay. So that's really the....

We're still doing a little bit of experimenting also with cluster spacing and frac size, so we're testing that on a few wells as well.

So I guess the completions in 1Q were 15%, 20% better IPs on 30-day and 24-hour rate versus 4Q. Do you think it's mainly a function of the longer lateral or there's other factors in there as well? On the McMullen -- McMullen wells.

Right, right. Some of that's lateral length. And some of it is just location. The Gloria Wheeler, obviously, by the numbers, is the best acreage block we have and then we had a number of completions in there. So some of them may be location, but some of it's also lateral length and maybe frac size. We really don't have enough data to get some definitive answers on that yet.

Okay. Remind us again, what's the net acreage split by county for McMullen and La Salle?

I don't have that in front of me, to tell you the truth.

Yes, call us back later.

I don't have an updated report on that.

Okay. And then lastly, I know you had mentioned, I guess briefly, that your JV partner may look to participate in additional acreage acquisition in the Eagle Ford. I mean, have they given you an indication there? Will it be just participate and to the promote on the wells? Would it be pay part of the cost toward acreage acquisition?

That would have to be structured, Richard. We can offer that. Unless it's very tightly adjacent, I think there might be some -- to our acres where they might have some rights, we don't even have an AMI. So it would be something we would just structure and offer as we saw fit.

Okay. They haven't really given you any indication on that deal?

No. We don't present a deal and there's no reason to give an indication for something we haven't presented.

The final questions will come from the line of Jack Aydin with Keybanc.

All my questions were answered, save your time.

Jack, you've got to ask 1.

Well, if you want me to ask you, it's basically I'm worried about the inventory. How are you going to address it? Because if you're running 6 rigs in 2014, you're going to run through that inventory, and I know you've got the cash and everything, I want to see a little -- to get a little more color, how you're going to add to that inventory.

Jack, have we ever not had something to do with -- we've known you for -- you're 27 years old now, are you, Jack?

18 years old.

Yes, okay. Don't worry about our lack of inventory, if that's what you perceive us having. We would never have a problem with finding a place to spend money and making money. So we addressed that early on.

Ladies and gentlemen, that concludes the question-and-answer session. I will turn the call back to Jay Allison for closing remarks. Please proceed.

Again, I would like -- this is a long conference call. It's like 1.5 hours or so, which is unusual. As always, and we know most of you, we try to put in a good days work to create the value on a per share basis. I think the divestiture in the Permian is a win-win for Rosetta and for us. I think they're going to do wonderful there and I think we're going to do wonderful with accelerating the Eagle Ford. But we do guard our money carefully because it's not ours, it's yours. And we're trying to create a valuable stock. So we thank you for staying with the conference call for 1.5 hours and believing in us. That's it, Stephanie.

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