Comstock Resources, Inc. (CRK) Q3 2013 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Third Quarter 2013 Comstock Resources Earnings Conference Call. My name is Lisa, and I will be your coordinator for today. [Operator Instructions] As a reminder, this conference is being recorded for replay purposes. I would now like to turn the call over to your host, Mr. Jay Allison, Chief Executive Officer. Please proceed, sir.

Thank you, Lisa. Before we start, I've got about 6 or 7 bullet points that I want to make sure that those that are attending the conference, if they leave early, they get these bullet points pertaining to the quarter. As you all know, this is the first quarter that we've had -- where we've had the Permian divestiture behind us. With the proceeds from the Permian sale, we have retired $735 million of debt, really, in the last 6 months. So the question is, what do we do with that? And the bullet points are, one, because of that, we've now been able to double our Eagle Ford rig count. We went from 3 rings to 6 rigs, as you know. And that allows our Eagle Ford oil production to grow anywhere from 33% to 36% over that production of 2012. The sale of the Permian also allowed us, really, to be 20% oil at the end of 2013 as far as production. And we should be 40% at the end of 2014 as far as oil production. It also allows Comstock to complete, I think, somewhere like 15 additional net wells in the Eagle Ford versus our initial projections at the beginning of this year. Now we've added 3 more even in this quarter. It has allowed us to repurchase some shares. We repurchased 1.3% of our outstanding shares. And I think the other thing that it does, we will spend $120 million to enter into 2 new oil basins. So the question is, are we having some science experiment? And the answer is, quite frankly, no. We're not looking to enter into a science experiment that will dilute to strong return currently being seen in the Eagle Ford but rather, invest in 2 areas, each of which we think have the potential to be another Eagle Ford. And we throw that $120 million out, so you'll know that we're not going to get in financial strait. That's the amount of money that we're investing in the future in 2 new plays. And you'll also note, after the divestiture of the Permian, our bank credit facility should increase to $1 billion, with $625 million initial borrowing base, and our year-end oil production should be greater than what we had projected as if we had kept the Permian. So all those are great points that I didn't want anyone to miss if they left the conference call early. So with that, welcome to the Comstock Resources' third 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 Third Quarter 2013 Results. I am Jay Allison, Chief Executive Officer of Comstock. And 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 third quarter operating and financial results. If you go to Slide 2, please refer to Slide 2 in our presentation and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. Now Slide 3, our 2013 third quarter highlights summarizes our third quarter results. Our third quarter operating results were defined by continuing strong growth in our oil production and the prudent natural gas prices offset, in part, by declining natural gas production. Our oil and gas sales increased to $112 million in the third quarter. Our total EBITDAX was $82 million, and our total cash flow from operations was $63 million or $1.31 per share. Our Eagle Ford drilling program is providing strong oil production growth this year. Our oil production increased 14% from the second quarter and is up 30% over last year's third quarter. Oil made up 22% of our total production in the third quarter alone. We expect our oil production this year to grow 33% to 36% over 2012, as I stated earlier. In the first 3 quarters of 2013, we drilled 47 successful Eagle Ford wells and also completed 42 wells, which had an average oil initial production rate of 793 barrels of oil equivalent per day. Our results in our Eagle Ford program have improved considerably since last year. Our 2013 completions had 30-day initial rates that are 25% higher than the 30-day rates in 2012. While at the same time, our average well cost had decreased by 13% from 2012. We have a very strong balance sheet off the West Texas divestiture which closed in the second quarter. The divestiture allowed us to retire $735 million of debt this year, including the October 15 redemption of our 2017 bonds. At the end of the third quarter, our net debt has improved from 59% to only 35% of our total capitalization. I'll have Roland Burns report on the financial results for the quarter in more detail. Roland?

Thanks, Jay. Slide 4 shows our oil production related to our continuing operations by region and on a daily basis for the last 3 years by quarter. Oil production this quarter increased to 6,900 barrels per day and was up 900 barrels per day or 14% over the second quarter of this year. The oil production was also up 30% from the third quarter of 2012. Our Eagle Ford properties in South Texas account for most of our oil production at 6,600 barrels per day. We're looking for our oil production to average between 8,300 and 9,000 barrels per day in the fourth quarter. The wide range that we're providing for guidance for this fourth quarter is due to the very large amount of completions that are planned for December, so the exact timing of those will have a big impact of how we finish up the year. Slide 5 shows our natural gas production from continuing operations on a daily basis. Our natural gas production declined by 5% to 148 million cubic feet per day as compared to the 156 million per day we produced in the second quarter. Production from our Haynesville and Bossier wells, which is shown in dark blue on the chart, declined by 5 million per day to 103 million per day this quarter. Production from our Cotton Valley well, shown in green, averaged 20 million per day. And our South Texas gas production, shown in light blue, was also 20 million per day. Other gas production, shown in purple, increased to 5 million per day. We expect our natural gas production to decline further in the fourth quarter to approximately 130 million to 140 million cubic feet per day. Slide 6 shows our realized oil prices related to our continuing operations for the third quarter. Oil price realizations in South Texas weakened in the third quarter as the NYMEX-WTI contract outperformed the LLS Gulf Coast market indexes. We realized $104.83 per barrel for our oil production as compared to $99.34 per barrel that we realized in the third quarter of 2012. With the Gulf Coast premiums failing to keep up with the WTI contract, our realized price averaged 99% of the average benchmark NYMEX-WTI price. 79% of our oil production was hedged in the quarter at a NYMEX-WTI price of $98.72. After considering losses from our hedging program, our realized price declined to $99.20 per barrel or 7% lower than the after hedging oil price we averaged in the third quarter of 2012 of $106.10. Slide 7 shows our realized oil prices for the first 9 months of this year also related to our continuing operations. We realized $103.47 per barrel in the first 9 months of 2003, up 1% from the $101.99 per barrel we realized in the first 9 months of 2012. Our realized price averaged 106% of the average WTI price for the period. 83% of our production was hedged in the first 3 quarters of this year at a NYMEX-WTI price of $98.69 per barrel. After our hedging program, our realized price improved to $104.49 per barrel, 1% lower than our after hedging oil price we averaged in the first 9 months of 2012 of $105.37. On Slide 8, we outlined our hedge position. We have a very attractive oil hedge position, which protects the 2013 and 2014 drilling program. We have 6,000 barrels per day hedged for the fourth quarter at $98.67 per barrel and 5,500 barrels per day for all of 2014 hedged at $96.31 per barrel. We plan to hedge about 60% to 70% of our 2014 production, so we'll continue to add some additional oil hedges as this year progresses. Slide 9 shows our average gas price, which has improved by 37% in the third quarter to $3.33 per mcf as compared to $2.43 in the third quarter of 2012. Our natural gas prices this quarter fell about $0.38 from the prices we realized in the second quarter of 2013. Our average gas price improved by 44% in the first 9 months of 2013 to $3.39 per mcf as compared to the $2.35 we realized in the same period in 2012. Our realized gas price is averaging 92% to 93% of the NYMEX-Henry Hub gas price so far in 2013. On Slide 10, we cover our oil and gas sales, including realized hedging gains or losses. Our decline in natural gas production was offset by growth in our oil production and improved natural gas prices in the third quarter. So sales relating to our continued operations increased by 8% to $108 million in the third quarter as compared to $100 million in 2012's third quarter. Oil production made up 58% of our total sales as compared to 51% in the third quarter of last year. Sales relating our continuing operations increased by 7% to $316 million in the first 9 months of this year as compared to $296 million in 2012's first 9 months. Oil production made up 53% of our total sales as compared to 49% in 2012. Our earnings before interest, taxes, depreciation and amortization and exploration expense and other noncash expenses, or EBITDAX, decreased by 5% to $82 million from the $86 million that we had in 2012's third quarter, as we show on Slide 11. $12 million of our EBITDAX in the third quarter of 2012 was related to our discontinued West Texas operation and $74 million is attributable to our continuing operations, so EBITDAX from continuing operations increased by 11% this quarter. Our EBITDAX increased by 6% to $252 million in the first 9 months of this year from $238 million in 2012's first 9 months. EBITDAX from continuing operations only in the first 9 months was $238 million in 2013 and $212 million in 2012 or an increase of 12%. Slide 12 covers our operating cash flow. Our operating cash flow for the quarter came in at $63 million, a 10% decrease from total cash flow of $70 million in 2012's third quarter. However, cash flow attributable to our continuing operations this quarter was 5% higher than the $60 million that we had in 2012's third quarter. Our operating cash flow in the first -- for the first 9 months was $192 million, 2% less than cash flow of $197 million in 2012's first 9 months. Continuing operation's cash flow of $185 million for the first 9 months of 2013 increased 6% over the same period in 2012. On Slide 13, we outline our earnings. We reported a net loss today of $24 million or $0.52 per share this quarter as compared to a net loss of $44 million from continuing operations or $0.95 per share in the third quarter of 2012. We have several unusual items in the third quarter results, including the unrealized losses related to our oil hedges, impairments on our unevaluated leases and a loss on property sales, which totaled $9 million. Excluding these items, we would've reported a net loss relating to continuing operations of $0.40 per share as compared to recurring net loss from continuing operations of $0.73 per share in 2012's third quarter. For the first 9 months of 2013, net income was $79 million or $1.63 per share as compared to a net loss of $22 million or $0.47 per share in 2012's first 9 months. Including that net income was a gain on the sale of our West Texas properties and their related results of $149 million or $3.08 per share. We had a net loss of $70 million or $1.45 per share related to our continuing operations. Excluding the same unusual items, plus the gain we had in selling our marketable securities in the first quarter, we would've reported a net loss relating to continuing operations of $1.14 per share as compared to the recurring loss from continuing operations of $1.35 per share for the same period in 2012. On Slide 14, we show our lifting cost per Mcfe produced by quarter related just to our continuing operations. Lifting cost in this chart are made up of production taxes, transportation and other field level operating costs. Our total lifting cost this quarter increased to $1.24 per Mcfe as compared to $0.96 per Mcfe in the third quarter of 2012 and $1.21 per Mcfe in the second quarter of 2013. This increase is mainly due to the lower natural gas volumes and the fixed nature of much of our lifting costs and higher production taxes related to the stronger gas prices. Production taxes this quarter were $0.24 per Mcfe and transportation averaged $0.26 in the third quarter. Field operating costs remained unchanged this quarter at $0.74 per Mcfe. On Slide 15, we show our cash G&A per Mcfe produced by quarter, excluding stock-based compensation. Our general and administrative costs increased to $0.29 per Mcfe this quarter as compared to the $0.21 per Mcfe we had in the third quarter of 2012, solely due to the lower production volumes we have in 2013. G&A expenses per Mcfe decreased from the second quarter rate of $0.33. Our depreciation, depletion and amortization per Mcfe produced is shown on Slide 16. Our DD&A rate in the third quarter averaged $4.93 per Mcfe as compared to the $3.99 rate we had in the third quarter of 2012 and the $4.87 we averaged in the second quarter of 2013. The higher cost of the oil production and a write-down of undeveloped natural gas reserves last year arising out of the very low natural gas prices are causing the increases. On Slide 17, we detail our capital expenditures related to our drilling operations. Capital expenditures from our discontinued operations after January 1 were reimbursed to us as part of the sales price are excluded from this slide. So far this year, we spent $234 million on our drilling program as compared to $266 million that we spent in 2012's first 9 months. Capital expenditures in South Texas, which are shown in red on this chart, relate to our Eagle Ford drilling program which increased to $215 million so far this year as compared to the $163 million we spent in last year's first 9 months. With low natural gas prices, our spending for our natural gas properties in North Louisiana declined to only $19 million so far this year as compared to the $103 million we spent in the same period in 2012. On Slide 18, we have an updated estimate of our 2013 drilling program in our capital budget. We are now expecting to spend about $345 million for our drilling activity this year, and we've also increased the number of net Eagle Ford wells being drilled to 49.6 as compared to 46.9 net wells in our prior budget. Offsetting the increase in the Eagle Ford, we're estimating we'll spend less on our natural gas fees in the Haynesville Shale. In addition to the drilling expenditures, we have budgeted $140 million to spend on acreage acquisitions, including the $120 million on the 2 new oil plays that Jay referred to earlier. The remaining $20 million are costs that we spent on our Eagle Ford acreage or capitalized interest or other acreage costs. Slide 19 recaps our balance sheet at the end of the third quarter. We had $228 million of cash on hand and $884 million of total debt at September 30, bringing our net debt down to about $656 million. Our net debt is now 35% of our total capitalization as compared to 59% at the end of the first quarter. On October 15, we used most of our cash and borrowed $100 million under our bank credit facility to redeem our 8 3/8% bonds due in 2017. We are currently completing a new $1 billion, 5-year bank credit facility that will have an initial borrowing base of $625 million, and we expect to close that in the next couple of weeks. Starting in June, we began paying a $0.125 dividend per quarter per share. The dividend cost the company around $6 million a quarter. As shown on Slide 20, only 1/3 of the 61 E&P companies we survey pay a dividend. And of those 61 companies, we have the second highest dividend yield at September 30 of 3.1%. In the third quarter, we also had some activity in our share repurchase plan, which we detail on Slide 21. We repurchased 1.3% of our outstanding shares or 631,096 shares for $9.2 million at an average of $14.63 per share. We still have over $90 million to authorize for share buybacks in the future. I'll now turn it over to Mark to review our drilling results in the third quarter.

Thanks, Roland. On Slide 22, we cover our South Texas operations where all of our current activity is in our oil-focused Eagle Ford Shale play. At the end of the third quarter, we had 26,500 net acres reflecting the recent acquisition of 2,300 net acres and the exploration of a similar amount of acreage in Atascosa County. We are working on other bolt-on acreage acquisitions in our area. We estimate that we have 300 operated drilling locations with a total resource potential of 70 million barrels of oil equivalent net to our interest. Slide 23 shows the location of the 89 producing wells we have drilled on our acreage. In the first 3 quarters of 2013, we drilled 47 horizontal oil wells, 31.6 net, and had 11 wells or 8.3 net drilling at September 30 of this year. We have also completed 42 or 26.4 net horizontal Eagle Ford Shale wells, including 6 or 3.8 net wells drilled in 2012. The 42 Eagle Ford Shale wells that were completed this year had an average per well initial production rate of 793 barrels of oil equivalent per day. This rate is 22% higher than the average IP from 2012. Slide 24 shows the results of the 89 wells which are currently producing. We completed 17 more Eagle Ford wells since our last update. They are wells 73 through 89 on this list. The 89 Eagle Ford shale wells that were completed had an average per well initial production rate of 745 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 588 BOE per day and the 90-day per well rate averaged 492 BOE per day or 68% of the initial 24-hour rate. The 2013 completions have initial rates that are 22% higher than the initial rates in 2012 and have 30-day rates that are 25% higher. The 4 third-quarter wells with the highest initial rates were the Swenson C #4H, Forrest Wheeler D #1H and the Swenson #7H and #8H, which are all located in McMullen County. These wells had initial production rates in excess of 1,000 BOE per day. On Slide 25, we track the costs of our Eagle Ford wells which have decreased considerably since we started drilling in August 2010. In 2010, our first 2 wells averaged $11.4 million. Costs have been reduced to an average of $7.8 million per well in the first 9 months of this year. Faster drill times and lower well stimulation costs account for much of the savings. We expect to average Eagle Ford well to cost $7.6 million in the fourth quarter of this year. On the far right, you can see the effect of the KKR promote on Comstock's realized well costs. The effective average well cost to Comstock on an 8H basis improves to $6.6 million with the joint venture promote. On Slide 26, we show the progression of lateral length over time on our wells in the Eagle Ford. Even though costs have come down considerably, the lateral length has increased by 44% since our drilling program began. The average lateral length was 6,625 feet in 2013 as compared to 4,595 feet in 2010. This increase is a function of our increased confidence in executing longer laterals without complication and our goal of maximizing our rate of return as well as utilization of all of our acreage. On Slide 27, we show the increase in proppant pumped since our program began in 2010. Half of this increase is due to the increasing lateral length. We pumped 8.7 million pounds of proppant this year per well as compared to 4.4 million pounds per well in 2010. We have increased the amount of proppant per lateral foot by 35% since 2010. Slide 28 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 running the 6 rigs that we have in the 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. Our expected fourth quarter Eagle Ford production will benefit from the increased number of completions due to doubling the rig count this year. The large increase in completions in December is due to 4 4-well pads being drilled and then completed simultaneously. This activity will provide sustained momentum into the first quarter of 2014. I will now turn it over to Jay.

If you continue to stay on Slide 28, the full impact of our 6-rig Eagle Ford drilling program really shows up in the fourth quarter of 2013, particularly in December. We expect to complete more Eagle Ford wells in December of 2013 than all of the third quarter of 2013, again, that's because you start seeing the full impact of our 6-rig Eagle Ford drilling program. If you go to Slide 29, our 2013 outlook. I'll summarize our outlook for the rest of the year. With continued weak natural gas prices, we have been 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 high returns on those projects. We expect the strong growth in our oil production will more than offset the natural gas production declines we are facing, allowing us to have higher revenues and cash flow and be a much more profitable company in 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. 96% of the net wells we'll drill in 2013 will be oil wells and 96% of our budget will be spent on oil projects. We're expanding our inventory of oil drilling locations by completing bolt-on acreage acquisitions around our Eagle Ford properties and by acquiring acreage in emerging oil plays. We continue to have one of the lowest overall cost structures in the industry. We now have a very strong balance sheet after the West Texas divestiture. We'll have over $0.5 billion in liquidity after the retirement of our 2017 bonds that we completed on October 15. For the rest of the call, we'll take questions only from research analysts who follow this talk. So Lisa, I'll turn it back to you.

[Operator Instructions] Your first question comes from the line of Ron Mills of Johnson Rice. Donald P. Crist - Johnson Rice & Company, L.L.C., Research Division: Actually, this is Don. Jay, in your new ventures, are you still focused on the 4-state area that you outlined in our conference of Louisiana, Mississippi, Texas and Oklahoma?

Yes. And the reason we gave you those areas are one, we -- Don, I think that the 2 or 3 things we needed to make clear when we sold the Permian is, one, we've got a great wealth creation group. And you say, "Well, where have they created great wealth?" It's Texas, Louisiana, Oklahoma and Mississippi. Those are the states that we've been very good in, and that's where our core people have been very good in. So we're staying within those states. We give you a budget. We're not going to spend $300 million, $400 million, $500 million chasing something. We're going to spend $120 million. And we've found the 2 areas that we really like, we're attempting to lease right now. And if anyone on the call ask if we're in a particular play, we won't comment on it because we've not publicized that we're in any new play other than the Eagle Ford. And then we have inventory at the Haynesville gas for future drilling when gas prices are anywhere from $4.30 to $4.50 or above. But we have located 2 basins that we really like. It's totally unanimous from the reservoir side, the operations side and the G&G side, the tease or kind of look-alike potential of the Eagle Ford in the future. Now maybe they will be, maybe they won't be, but there will -- we categorize as what the Eagle Ford might have looked like in the very first part of 2010. We're spending anywhere from $200 to $1,500 or so per acre. You can -- we've said that the goal is, in each of these plays, you're going to have a minimum of 20,000, 25,000 acres and maybe a maximum of 50,000 acres. And that's kind of your $120 million. We never said that we're going to be like Rip Van Winkle and go to sleep and not acquire acreage because we acquire acreage. When we got out of the Gulf, we went to the Haynesville, it worked. From the Haynesville, we go to the Eagle Ford, it worked. We go from Eagle Ford to the Permian, it obviously worked. And guess what? We're back working again. And we're telling you the dollars that we're going to deploy to do that and we're going to tell you that we're going to attempt to have a somewhat balanced budget in 2014. We'll talk about our budget in December, but we're not going to become reckless because we have money. But we're going to be accountable for all the shareholders. We're going to give them a dividend and we're going to buy shares back if we think the shares are "not behaving properly", at the same time, we'd love to invest in the future of the company, and it should be 2 new areas. So I hope, Don, that sets as good an answer as I can give you right now. Donald P. Crist - Johnson Rice & Company, L.L.C., Research Division: Absolutely, and I appreciate that. And looking into 2014, while I'm not looking for specifics, can you comment just broadly on staying within cash flow like you had talked before? I mean, with the new ventures, are you going to have a lot of time on these leases in order to evaluate and not spend a bunch of money right from the first day?

Well, the goal is to have 2 new core oil basins, 80-plus percent oil. It's to have the equivalent of primary leases, so the leases don't dictate that you have to have heavy drilling at all. And you can filter in these 2 plays throughout 2014 and you can do it within a reasonable budget. So our goal is to not materially outspend our free cash flow at all. I mean, we're going to try to stay within that ballpark. I think once we're able to announce what we're doing then, Don, we'll put our budget together and, believe me, we'll be accountable for the dollars that we'll spend and you'll never see us become reckless because we shouldn't become reckless. We fought really hard to reduce our debt the right way by being -- by creating a profit, and we did that in May of this year. So you can see that our borrowing base should materially increase. Our production should grow. We've got a hedging program for oil. So we're going to protect ourselves from the downside. We'd go from spending $103 million in the Haynesville to $19 million this year. Next year, it could be like $10 million. We don't really see any obligation wells in the Haynesville that we have to drill. We might just put a small budget in there just to have it there. But we're going to be a good, solid growth company with a good, strong balance sheet.

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

I had a question for Mack (sic) [Mark]. I was wondering -- I didn't hear you talk about the oil/gas mix on the wells in McMullen, the Swenson and the Forrest Wheeler wells. Was it -- is it gas here as you go south? I'm assuming yes.

Yes. Our -- we're between 80% and 90% oil on all of our wells. Our GOR is not very high even in McMullen County, so we're probably still over 80% on those wells.

Okay, great. And I was wondering, have you -- can you give me a sense of what the EUR is for on the 2 Haynesville wells you drilled this year and kind of what your plans are looking like into '14 there?

As far as '14, we don't have any Haynesville wells planned. We have a small budget that we'll probably include in our 2014 budget just for non-op and anything that comes up that might be an obligation, but we don't have anything planned to drill in 2014. I don't have the specific EUR numbers on those 2 wells. They're probably in the 6 range, something in there.

Okay. Got it, got it. And maybe just one last quick one. In terms of the acquisition, would you be looking to have a partner on that or would you want to stay 100%?

I think what we do on that, Ray, we see what our obligation might be, and then if there's an increased amount of acreage that we could possibly acquire, if we had a partner, I think the goal is to be -- have a financially-sound balance sheet and CapEx budget, at the same time, drill several wells in 2014 in each of these areas to prove up the areas along with other operators that are in the areas. And then if we can add more acreage and it makes sense to bring a partner in, I think we'd look at that. I think we have the potential to bring one in. So in the past, you didn't know if we could bring one in because historically we never have. But I do think our relationship with KKR and/or others and our performance at the drill bit in the areas that we've been in would allow us to do that. So I think that's just a financial decision where we don't plan on getting over-levered at all. If we need a partner to take a little bigger bite out of the apple, then maybe we'd do that. But we're not telling you that we will. We're telling you that if we had to, we would.

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

Jay, your recent strategy in the Eagle Ford, just curious if this has changed now that you have $120 million slated to go outside the Eagle Ford into -- to new basins. I think the original plan was 6,000 or 7,000 a year being added in just kind of core bolt-on deals.

I think the answer is we're continuing -- like we added the 2,300 acres in the Eagle Ford in the last quarter, but we're continuing to add Eagle Ford acreage. I mean, we've got some more acreage in the queue right now. But I think we've got like a $20 million -- we gave you kind of a $20 million budget for that, and that's the 3,000 to 6,000 acres or so. So that is still what we're doing. But you can't always rely upon the fact that you can get that amount of acres annually. Now we think we have a pretty good shot this year and we already have some more acreage that we'll probably report at the end of next quarter. However, you still have to rely upon your big growth engine because -- which is our G&G group, to find new areas like they did in the Permian, like they did in Eagle Ford. But I think, Mike, the difference is, we said that it was a $50 million to $100 million investment, and now we've changed that. We said, "Well, we really know now it's between $100 million and $120 million in these 2 new areas, if what we're attempting to do, we're successful in doing." So we thought it's fair for the shareholders and you as an analyst, et cetera, to know what we were doing with the dollars and to know that we're trying to create wealth in 2 other regions that are similarly looking to what the Eagle Ford looked like at the beginning of 2010. Which goes back to Don's question earlier. If you remember, when we market with you, when we went into Eagle Ford, we put a rig, and in July of 2010, we didn't put a second rig in until January of 2011. So we let our outcome dictate the number of wells that we drilled in the Eagle Ford and along with the success from the other operators. And these 2 new areas that we're attempting to acquire acreage in, that is our same strategy. So we'll make an initial investment of $100 million to $120 million in these 2 areas. We'll filter in these wells throughout 2014. We'll not become reckless. Hopefully, we'll add great inventory of oil locations in each of those 2 areas by the middle to latter part of 2014 by a little bit of our own drilling and maybe a lot of other operators' drilling. So, no. It's basically the exact same footprint. We're going to continue to add Eagle Ford acreage where we can find it. We're not going to bank everything on doing that even though we've been successful this last quarter in acquiring acreage and not a lot of money in the Eagle Ford. Does that answer that, Mike?

Yes, it does. Two quick follow-ups on that front. So if I took the $20 million that you have allocated to the Eagle Ford, leasehold CapEx and just divide it by the midpoint of that 3,000 to 6,000, that implies you're paying about a little over $4,000 in acreage, just wanted to confirm if that's what you're doing this at. And then just the timing on the leasehold pickups in these 2 other basins. You do have it in the 2013 budget. Do you expect to be -- how much do you expect to actually get signed by the end of the year?

Well, the $4,000 is a good number. I think, give or take $400 or $500, that's a good number. And then I think the reason we stick that $120 million in 2013 is because there's a great chance that, that will happen in 2013. And we don't want to surprise everybody at year-end and all of a sudden they see that we spent $100 million to $120 million when we've told the market it's between $50 million and $100 million. We said it'll be between now and the next year and you don't know when those opportunities come around, but they're here. So we're kind of giving you a heads-up that, that is -- there is a chance that, that might happen this year which, Mike, could be good because then we could factor that into our budget in 2014.

Your next question comes from the line of Rehan Rashid with FBR Capital Markets. Rehan Rashid - FBR Capital Markets & Co., Research Division: My favorite question, downspacing in the Eagle Ford, it looks like you're still carrying 80-acre spacing, any updated thoughts on that, please?

It's time to beat Mark up on that, and he won't budge on me, but I'll let him answer.

Rehan, we're always evaluating it, but based on our information, our reserves and recoveries, we don't think that downspacing is really an opportunity that we will pursue in the Eagle Ford at this time. We think we're at the right spacing and we think, as you get much tighter, you really diminish your net present value on the properties by going down. Rehan Rashid - FBR Capital Markets & Co., Research Division: Okay. Any incremental changes to well design from here, more stages, more tighter cost of spacing, anything on that front?

We're testing several right now. We're testing both of those, really tighter cluster spacing and frac-ing less clusters per stage. And we'll do those tests over the next couple of months and kind of see what kind of impact we get and then move forward with a revised design, if we do see enough benefit for that additional cost. Rehan Rashid - FBR Capital Markets & Co., Research Division: Okay. On the Haynesville front, last time, Jay and Roland, we talked -- you guys had mentioned some kind of incremental work on longer lat curls, any kind of update on that front from a permitting to /science work standpoint?

Well, we think in the core of the Permian, if we kind of extend the laterals to 6.5, we could probably have a drilling program in the $4.30 price range. However, Rehan, I think with the success we've had in the Eagle Ford and, hopefully, the potential purchasing of leases in 2 new key core areas within this oil basin, we'll de-risk part of that in 2014. And then we'll see, Rehan, where gas prices go. We're trying to [indiscernible] the company up to say -- look, we've got 60 cfe, we think there's resource potential in the Haynesville. I guess at a $4.30 price, we could probably start some of the infield for 6.5 drilling laterals. But we're really in a period of a $4.50 to $5.00 price, that's when you can have a dedicated program when you can hedge and you can really develop your Haynesville better. So we're -- that's why, kind of in closing, we say we don't think that we have to drill any Haynesville wells because we don't. Now can we introduce it? Absolutely. And the beauty of that is, kind of like 2012, we spent $103 million holding acreage and completing wells in the Haynesville. This year, we spent $19 million. I mean, that's a lot of extra money we can spend on oil right now. And that's what we're doing because that's what we should be doing. Rehan Rashid - FBR Capital Markets & Co., Research Division: And one quick one, the share buyback, with maybe capital allocation priorities changing into '14 with more acreage, is that -- does that share buyback take a backseat from this point on?

No, not at all. I think we -- that's what we try to advertise, "Here is the amount of money we've invested, we will invest or hope to invest in acreage in the future." We do hope to have 2 new oil regions, and we'll filter in whatever budget we'll have in those 2 regions in a 2014 budget, if we can close those by year-end. But at the same time, we're totally committed to a dividend, which is at 3% yield. At the same time, we're committed to share buybacks if the shares, what we call, misbehaved. So we bought 1.3% of the shares back, and we can do that. You can see our borrowing base should go up to that $1 billion, with $625 million available. So I mean, we're getting stronger financially. And the reason is we divested our sales of the Permian properties. It unlocked our great strength and we're using those now. You're just now starting to see it.

Your next question comes from the line of Amir Arif with Stifel. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Just a question, can you give us a sense of how much of the $120 million you've spent so far?

No, we can't comment on that.

None as of the -- into the third quarter.

Yes. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Yes, good. But a good chance that most of it should be done by year-end, is that fair based on your previous comments?

I think we'd like it for it to be spent. Now whether that happens or not, I don't know. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay, okay. And then just a quick question on the Eagle Ford production growth. I mean, just given the completions that you showed in that one chart, with most of them coming in December, even at the low end of your 8.3 to 9 range, that's implying 20% sequential growth. Are you -- you guys are comfortable with that based on the completions that were happening in 3Q?

Yes. This is Roland, Amir. Yes, we -- yes, a lot of that was achieved with the activity in third quarter, not really based on the December activities. So achieving the high end of the range with what-have-those contribute some, but with those being pushed toward the very end of the year, that's why we have kind of a larger range that we'd like to have for the fourth quarter because of the timing of -- do we get a month to production out of a lot of those? Do we get a half a month? Do we get a day? So that's -- accounts for the range. But we're very comfortable that we can be in that range, given the levels of production we're at now. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay, that sounds good. And just a final question on the Haynesville. I mean, if you didn't do any drilling next year, what kind of decline rates would that field have, 15% to 20% would be a fair number, or would it still be higher than that?

Well, I think -- I know that we're looking at our total gas production to decline by around 15% to 18% next year, so the Haynesville is probably a little -- as a component, would be a little larger than that, probably in the 25% range would be my guess. But company-wide, that 15% to 18% is a good number. That's what we're looking at, with no investment in gas at all next year, so we can take that kind of a floor.

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

Yes. The downtick in the 3P reserves in the presentation from 78 million BOE to 70 million BOE, what was -- did you condense some locations? Are you assuming smaller wells there? What drove that change from 2Q to 3Q?

Well, Marshall, what we did is with the -- some of the acreage has expired and that's out of our acreage count. And most of that, that we didn't have locations on. And then we added some new acres, and that's really just a more refined calculation of putting -- we do have 300 operated, engineered locations on our acreage that we feel like are -- will all be developed. And then we just kind of put those in their real proper EUR category, so we think it's a very fair number, a much more precise number than before. So I think it's just much more precision. And there is some of our acreage that has a -- that's not been put in an operated unit yet, that probably we have potential for, but we're going to kind of wait and add that when we kind of get those put into a unit. So I think it's really just more precision on the numbers than anything else.

Okay. And in terms of the 2 new areas, is it a bunch of small packages, some sort of organic leasing or is there some -- a few key -- a couple of key packages you're looking for? I'm wondering if we're going to -- you would likely have an announcement or would it just be when your numbers come out, you can reveal those positions?

I think that if we can -- I think we have an obligation. If we spend that amount of money between now and year-end, then we'll put a press release on about it because I think that's a fair thing to do to the markets.

And Marshall, I think if you kind of look at the rest of the year, things could be different. But before the fourth quarter update, which obviously won't come until next year, we see -- of course, we'll finalize our bank facility, so that should be pretty imminent coming out. We'll report in our capital budget after approval by our board in early December. But those 2 are things that are planned on. And then I think that if we are able to complete significant leasings in these 2 areas in the fourth quarter, which we think is probable, we'll probably report on that also. So I think those are the 3 kind of announcements we could say that are probably going to come before the end of the year.

Your next question is a follow-up from the line of Rehan Rashid from FBR Capital Markets. Rehan Rashid - FBR Capital Markets & Co., Research Division: Yes, real quick. On the inventory for Eagle Ford, is that the remaining inventory? Is that the total?

No, Rehan, that would be the total [indiscernible] on that acreage.

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

Again, I think this is the first quarter that we've had that is pretty much a clean quarter after the divestiture. And you can see, hopefully, the direction that we're focused. We're focused on telling you what our bank facility looks like, telling you what the results are from the 6-rig program, of what is -- in the Eagle Ford or what they should look like in October, November, December of this year. And then being accountable to you for the entrance in the 2 new oil regions that we think we'll be successful in entering. And if we are successful, we will put a press release out on that and we'll be accountable to how we would develop those regions in 2014 and beyond. So again, we're always appreciative of your time, and thanks for the conference call.

Ladies and gentlemen, this concludes today's presentation. You may now disconnect. Have a great day.