Comstock Resources, Inc. (CRK) Q4 2012 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2012 Comstock Resources, Inc. Earnings Conference Call. My name is Erica, and I'll be your operator 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 Jay Allison, President and CEO. Please proceed.

Thank you, Erica. And, everyone, welcome to the Comstock Resources Fourth Quarter and Annual 2012 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 Fourth Quarter 2012 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 2012 operating and financial results. Please refer to Slide 2 in our presentation and note that our discussions today will be including forward-looking statements within the meaning of securities laws. While we believe the expectations of such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. I know that there are probably 34 slides in the presentation. I'd like to give you kind of an overview right now from our perspective as far as the year and 2012 and 2013. And I know Roland and Mark will hit on some of the highlights and details in a moment, but just to kind of give you an overall view. Slide 3 summarizes the highlights of 2012. 2012, as well as 2013, are transition years for Comstock as we are changing the company from a 98% natural gas company to one with a more balance between oil and natural gas. We started 2012 with a partially proven Eagle Ford oil play and added the Permian properties in Reeves County as a new oil basin for us. In 2012, we saw natural gas prices decrease 36% from 2011, and our gas production dropped 9%. But then in 2012, we saw our oil production grow 175%, with the Eagle Ford becoming our main oil growth engine as we de-risked our acreage and brought in KKR as a JV partner. In 2013, the Eagle Ford will continue to be our largest oil growth engine, with a 3-rig dedicated program to focus drilling into better portions of our Eagle Ford acreage. In 2012, in West Texas, we drilled 46 gross vertical wells that have enabled us to de-risk portions of our 42,000 net acres, and we drilled our third horizontal well, the Gaucho State 15 #H, targeting the Wolfcamp A interval. The Gaucho has been fracture-stimulated now, with a 6,837-foot lateral in 18 stages and is expected to start flowing back later this afternoon. Comstock owns 100% working interest in the Gaucho well. This well will allow us to begin to evaluate the Wolfcamp A horizontal play, which offset operators have been very successful in developing. Mark Williams will go into more detail about this well and the offsetting wells later in this conference call. Concerning our 80,000 net acres in the Haynesville/Bossier play in East Texas and North Louisiana, where we have 6 Tcfe of upside, we have allocated $32 million in 2013 to drill 3.6 net wells versus the $107 million we spent in 2012. So in 2013, 94% of the net well drilled will be oil wells and 92% of our budget will be spent on oil projects. Also, I need to point out that a key component to Comstock in 2013 is to delever our balance sheet by bringing in a partner in our Permian drilling program later this year. We think a good partner will create a win-win situation in the Permian and allow us to delever our balance sheet and enable the Permian to be developed on a more consistent scale, incorporating both vertical and horizontal well programs. I will now turn it over to Roland and Mark to cover our financial and drilling results. Roland?

Thanks, Jay. The first item I want to cover is the announcement we made yesterday to restate our financial results for the first 3 quarters of 2012. So if you refer to Slide 4. And while our oil hedging program has been a big economic success in 2012, we were required to change our accounting from hedge accounting to mark-to-market accounting. The net impact is that we have to include unrealized gain or loss related to the value of the oil hedge position in our income statement, instead of just an equity. As a result, we've recognized an unrealized loss of $10.2 million in the first quarter and unrealized gain of $34.8 million in the second quarter and an unrealized loss of $1.1 million in the third quarter. For the 9-month period, this accounting change has us reducing our loss after income taxes to $21.9 million as compared to the $29.4 million loss we previously reported. Even though the hedges were effective throughout all of 2012, our underlying documentation that designate the contracts as hedges were not completed in a timely manner. The technical requirements to use hedge accounting are unforgiving, and we failed to live up to them. We do want to apologize to our stockholders for any confusion this restatement has created. On Slide 5, we show our oil production on a daily basis by quarter. Our oil production in 2012 grew by 175%. In the fourth quarter, oil production fell to 6,100 barrels per day as compared to the third quarter, where we produced 7,200 barrels per day. The decrease is mostly due to the activity in our Eagle Ford Shale properties in South Texas, which is shown in light blue on this chart, which averaged 4,300 barrels per day as compared to the 5,000 barrels per day we had in the third quarter. There were several factors that contributed to the disappointing production rate in the quarter. A smaller number of net wells came online in the fourth quarter, and we had substantial shut-in time for offset frac activity. This was compounded by additional shut-ins for artificial lift installations. Our January and February production continues to be hampered by some of these issues, but we anticipate having a very strong March as we return all the wells to production plus having an additional 5.2 net wells coming on production in late February and March in the Eagle Ford. Our Wolfbone properties in West Texas averaged 1,600 barrels per day in the fourth quarter, down from the 1,900 barrels a day we had in the third. Limited completions in the quarter and artificial lift issues hampered production from this area in the quarter. Despite the slow start, we do expect our oil production to grow this year by approximately 40% to 60% over last year's production to total 3.2 million to 3.7 million barrels. Slide 6 shows our natural gas production on a daily basis. Our natural gas production declined by 9% in 2012 due to the 9 million a day of production we sold with our May property divestiture and the declines that we're experiencing from our Haynesville properties. In the fourth quarter, we averaged 195 million cubic feet per day as compared to the 220 million cubic feet per day that we had in the third quarter in the Haynesville for total production. But production from our Haynesville and Bossier wells in the quarter declined to 142 million per day, and the remaining gas production at the company has only showed modest declines in the quarter. Production from our Cotton Valley wells, which is shown in dark blue on the chart, averaged 25 million per day. And our South Texas gas production, shown in red, was 20 million per day. Other gas from our other regions, shown in purple, increased in the quarter to 8 million per day. We expect our natural gas production to decline further this year to approximately 59 to 62 -- 64 Bcf, a decrease of 22% to 28% from our 2012's total production. On Slide 7, we show that our average realized oil price in the fourth quarter of 2012 decreased to $92.46 per barrel as compared to the $100.18 per barrel in the fourth quarter of 2011. Our realized well net oil price in the quarter averaged 106% as the average NYMEX WTI price of $87.60 due to the premiums that we are receiving for our Eagle Ford Shale oil. 80% of our oil production was hedged in the quarter at a NYMEX WTI price of $99.53. So including our gains from the hedges, we realized $101.56 per barrel in the quarter, which was 1% higher than our realized oil prices in the fourth quarter of 2011. Slide 8 shows our oil prices for all of 2012. Our realized oil price increased 1% in 2012 to $96.95 per barrel as compared to the $95.73 per barrel in 2011 and had averaged 103% of the average benchmark NYMEX WTI price. 74% of our oil production was hedged in 2012 at a NYMEX price of $99.45. So including the gains from our hedges, we realized $101.18 per barrel in 2012, which was 6% higher than our realized prices in 2011. On Slide 9, we outline our hedge position. We have an attractive oil hedge position, which protects our 2013 drilling program, and we have 6,000 barrels of oil production hedged at $98.67 for all of 2013. Slide 10 covers our natural gas prices. Our average gas price of $3.05 decreased 10% this quarter as compared to the $3.40 price we realized in the fourth quarter of 2011. Our realized gas price was 90% of the average NYMEX Henry Hub gas price for the quarter. Our average gas price for all of 2012 decreased 36% to $2.52 per Mcf as compared to the $3.91 we averaged in 2011. Our realized gas prices was also 90% of the average NYMEX Henry Hub gas price for all of 2012. On Slide 11, we cover our oil and gas sales, including realized gains or losses from the hedges. Our total sales decreased by 2% to $112 million in the fourth quarter of 2012 as compared to the $114 million we had in 2011's fourth quarter. Oil made up 51% of our total sales in the fourth quarter as compared to only 31% in the fourth quarter of last year. In 2012, sales increased 2% to $442 million as compared to the $434 million of sales in 2011. Oil also accounted for 51% of total sales for all of 2012 as compared to only 18% of our total revenues in 2011. Our earnings before interest, taxes, depreciation, amortization and exploration expense and other non-cash expenses, or EBITDAX, decreased by 9% to $82 million from $90 million in 2011's fourth quarter, as shown on Slide 12. EBITDAX for all of 2012 has decreased 4% to $321 million from 2011's $336 million. Slide 13 covers our operating cash flow. Our operating cash flow for the quarter came in at $65 million, which was 18% lower than cash flow of $79 million in 2011's fourth quarter. Operating cash flow for 2012 was $261 million, a 12% decrease from 2011's operating cash flow of $298 million. On Slide 14, we outline our earnings. We reported a net loss of $78 million this quarter or $1.68 per share as compared to a net loss of $41 million or $0.89 per share in 2011's fourth quarter. For the full year, we reported a net loss of $100 million or $2.16 per share compared to a net loss of $33 million or $0.73 per share for 2011. The financial results in both 2011 and 2012 include several unusual items. In the fourth quarter, the reported net loss includes impairments on natural gas unevaluated leases and producing properties of $78.6 million or $51.1 million, aftertax, or $1.10 per share. We also had a $2 million unrealized loss from derivatives, $1.3 million, aftertax, or $0.03 per share. The 2012 annual net loss includes impairments of $86.7 million or $56.3 million, aftertax, or $1.21 per share; a gain of $26.6 million, $17.3 million, aftertax, or $0.37 per share on the sales of our Stone Energy shares; and a gain of $24.3 million, $15.8 million, aftertax, or $0.34 per share from our property sales; and also an $11.5 million unrealized gain from derivatives, which was $7.5 million, aftertax, or $0.16 per share. Excluding these items, we would've reported a net loss of $0.55 per share this quarter and $1.82 per share for 2012. On Slide 15, we show our lifting cost per Mcfe produced by quarter. Lifting costs for us are broken out into 3 components: production taxes, transportation and then other field-level operating costs. Our total lifting costs were $1.19 per Mcfe produced in the fourth quarter of 2012 as compared to the $0.77 rate that we had in the fourth quarter of 2011. Our production taxes were $0.15 per Mcfe, transportation averaged $0.27 in the fourth quarter and our field operating cost averaged $0.77 per Mcfe this quarter, which was higher than the 39% -- $0.39 rate that we had in the fourth quarter of 2011 and the $0.64 rate we had in the third quarter of 2012. The lower production in the quarter and the more expensive to lift oil production account for the higher rate. On Slide 16, we show our cash G&A per Mcfe produced by quarter, excluding stock-based compensation. Our general and administrative costs were $0.20 per Mcfe in the fourth quarter of 2012, which was the same rate that we had in the fourth quarter of 2011 and the same rate that we had in the third quarter of 2012. Our depreciation, depletion and amortization per Mcfe produced is shown on Slide 17. Our DD&A rate in the fourth quarter of 2012 averaged $4.55 per Mcfe as compared to our $3.07 rate in the fourth quarter of 2011 and the $4.10 rate we averaged in the third quarter. The low natural gas prices drove up our DD&A rate in 2012 due to the exclusion of most of our undeveloped natural gas projects from our proved reserves. Also, the higher finding cost of the oil projects is also driving this increase. We have a slide on our proved reserves and finding costs for 2012 on Page 18 of the presentation. Our proved reserves at the end of 2012 were estimated at 712 Bcfe compared to the 1.3 Tcfe that we had at the end of 2011. Our reserves are 67% natural gas and 33% oil as compared to the only 15% oil at the end of 2011. We operate 90% of our proved reserves, which went from being 46% developed at the end of 2011 to 62% developed at the end of 2012. Our successful drilling program in the Eagle Ford Shale in South Texas added 11.9 million barrels of oil and 7.5 Bcf of associated gas or 13.2 million barrels of oil equivalent to our proved reserves in 2012. The West Texas drilling program contributed 5.4 million barrels of oil and 9.5 Bcf of associated gas or 6.9 million barrels of oil equivalent to proved reserves in 2012, and the activity in the Haynesville Shale mainly in the first quarter of the year and our other regions added another 15 -- and another 14 Bcf of proved natural gas reserves into our reserves at the end of 2012. The very low SEC price that we had to use to estimate our proved reserves caused a large downward revision of 534 Bcf, as our undrilled natural gas projects are not economic at the $2.84 per Mcf price that we had to use. In 2012, we spent $490 million on exploration and development activities, and we spent another $35 million to acquire leases. The finding cost for 2012, excluding the exploratory acreage cost and the downward natural gas revisions, calculates at a $21.79 per BOE. Slide 19 recaps our balance sheet at the end of 2012. On December 31, we had $4 million in cash and $12 million in marketable securities on-hand. We also had $1.3 billion of total debt comprised of $884 million of our senior notes and $440 million outstanding under our bank credit facility. Our current borrowing basis of $570 million under the credit facility, leaving us $130 million in unused availability. Slide 20 breaks out our 2013 drilling budget. In 2012, we spent $490 million on our drilling activities. And this year, we expect to spend $420 million. Our new budget has us drilling 85 wells this year, 10 gas wells and 75 oil wells. $219 million will be spent on our Eagle Ford Shale program to drill 27.3 net wells, and $169 million will be spent on our Wolfbone properties to drill 8 Wolfcamp horizontals and 25 Wolfbone vertical wells. We've also budgeted $32 million for any required drilling to hold our acreage in the Haynesville Shale, and we plan to spend another $25 million to acquire acreage in 2013. I'll now turn it over to Mark to review our results from our drilling program.

Thank you, Roland, and Happy Fat Tuesday to everyone. On Slide 21, we recap our activity in our East Texas/North Louisiana region. In the first quarter, we drilled 3 operated Haynesville wells, 2.5 net, before moving our 2 operated drilling rigs out of this region. We participated in another 4 non-operated wells, 0.7 [ph] net. We completed all of our operated Haynesville wells this year, and we still have 2 or 0.1 net of the non-operated wells -- Haynesville wells waiting to be completed. We will be able to exploit our 6 Tcfe of Haynesville and Bossier resource potential in the future when improved gas prices provide economics competitive with our oil projects. Slide 22, we cover our South Texas operations, where all of our activity has been in our oil-focused Eagle Ford Shale play. We still have 35,000 gross acres and 28,000 net acres in the oil window of the Eagle Ford Shale. Based on 80-acre spacing, we believe we have 277 horizontal locations, including the wells we have already drilled. We have excluded some of our Northern acreage and any acreage that we think is undrillable from this estimate. We estimate that our properties have 78 million barrels of oil equivalent potential. This year, we drilled 30 wells, 20.5 net to our interest, and the wells we drilled had an average initial production rate of 675 barrels of oil equivalent per day. Slide 23 and 24 show the results and locations of the 47 wells, which are currently producing. We completed 6 more Eagle Ford Shale wells since our last update. They are wells 42 to 47 on the list. The 47 Eagle Ford shale wells that were completed had an average per well initial production rate of 702 BOE per day. These wells are being produced under the company's restricted choke program, and the initial tests were obtained with a 14/64s to 16/64 choke. The 30 day per well production rate for these wells averaged 542 BOE per day, and the 90 day per well production rate averaged 461 BOE per day or 66% of the initial 24-hour test rate. The 6 new Eagle Ford wells reported on this quarter averaged 682 BOE per day with the Gloria Wheeler A #2H, the Gloria Wheeler B #2H and the Cutter Creek A #1H, all in McMullen County, having the highest initial production rates at 987, 872 and 765 BOE per day, respectively. At the end of the year, we had another 6 or 3.8 net Eagle Ford wells waiting on completion. Slide 24 shows the location of the 47 producing Eagle Ford wells. On Slide 25, we show how the cost of our Eagle Ford wells have come down considerably since we started drilling in August of 2010. The costs on this slide have been adjusted to standardize the lateral link up to 5,800 feet to make them comparable. The costs are based on actual costs for wells that we've completed and AFE costs for future wells. You can see that, in the beginning, these wells cost over $12 million, which included a lot of learning curve and science applied, and the cost have improved to just under $8 million recently. Faster drilling times and lower well stimulation cost account for much of the savings. Slide 26 shows the net Eagle Ford wells being put on production per month in 2012 and what is projected for 2013. Note the wide variation in net completions per month, which ranges from 0 all the way up to 6 net completions per month. This variation is due to multi-well pad drilling and subsequent multi-well stimulation operations. The large variation will result in a lot of lumpiness in our resulting Eagle Ford production curve in 2013. Production in the fourth quarter of 2012 was affected by the low number of completions in that quarter and Q1 of 2013 will also be adversely affected. Slide 27 shows the location of our planned 42 Eagle Ford wells in 2013. You can see the high concentration of planned wells in the McMullen County, where we have achieved the best results. And on this map, there are 40 dots, just for those of you that actually count, and there are 2 wells located in our DVR area to the East, and it made the map too small to read so we left that area off. But you'll also note that 38 of the 42 wells are in our high-quality McMullen area acreage. Slide 28 shows our West Texas region and the 89,000 gross and 54,000 net acres that we have there. Our activity this year has been focused on Reeves County and the properties we acquired from Eagle Oil & Gas at the end of 2011. The Reeves County acreage provides us over 900 vertical locations, targeting the Wolfbone with 178 million BOE of resource potential. We have a proven and successful vertical program on our acreage, but we think there's significant upside with horizontal development in the Avalon, the Bone Spring and the Wolfcamp formations on our Reeves County acreage. Recently, other operators in the area had -- have had strong results from horizontal Bone Spring and Wolfcamp wells for -- yes, around our acreage. Slide 29 shows our Reeves County acreage and highlights the latest 8 Wolfbone wells we reported on today. In 2012, we drilled 48 wells or 30.5 net wells. All of these were successful. Of the wells drilled in 2012, we completed 29 or 26.3 net operated wells in 2012. These wells had an average per well initial production rate of 356 barrels of oil equivalent per day. We also participated in 16 non-operated Wolfbone vertical wells, which had an average initial production rate of 369 barrels equivalent per day. The vertical wells were drilled to total depths of 11,250 to 12,786 feet and were completed with 5 to 11 frac stages. We had 3 wells, 1.0 net wells, awaiting completion at year end. Since our last update, we completed 8 additional wells in our Wolfbone field, which had an average initial production rate of 319 BOE per day. Our second horizontal well, the Dale Evans 196 #2H, targeting the middle Wolfcamp interval, was disappointing with an initial rate of 212 BOE per day. Slide 30 shows the 49 operated wells in our Wolfbone field, including the 8 we completed in the fourth quarter. The 49 wells had an average per well initial production rate of 322 BOE per day. The 30-day rate for the 48 wells that have produced for Wolfbone [ph] averaged 79% of their initial rate. Over a longer period of 90 days, the rates have averaged 61% of the initial rate. Slide 21 (sic) [ 31 ] shows the -- shows you the location of these 49 wells on our acreage. And as you can see, we have fully tested our acreage with vertical wells and feel we have de-risked the vertical program. Slide 32 shows Comstock's horizontal activity in Reeves County, along with horizontal activity by offset operators. Concho's horizontal wells, targeting the Wolfcamp A interval, have been very successful with the first 2 reporting 30-day IP rates as reported to the Railroad Commission of 758 BOE per day and 952 BOE per day, and those were the Rawhide and the Cowboy wells. Comstock's first horizontal well, the Monroe 35 #1H, targeting the Wolfcamp B interval, was moderately successful with a 24-hour IP rate of 653 BOE per day. We still have the Wolfcamp A and third Bone Spring to complete at a later date in this wellbore. Comstock's second horizontal well, the Dale Evans 196 #2H, targeting the middle Wolfcamp interval, was disappointing with a 24-hour IP rate of 212 BOE per day. We still have the Wolfcamp B, the Wolfcamp A and the third Bone Spring to complete in this wellbore at a later date. Comstock's third horizontal well, the Gaucho State 15 #1H, targeting the Wolfcamp A interval has been fracture-stimulated with 6,837-foot lateral and 18 frac stages. And you'll note they targeted the Wolfcamp A, which is the same interval as the successful Concho wellsoffsetting. The frac plugs have been drilled -- have been removed in this well, and we are preparing to start flowback later today. The lateral length of the Gaucho is significantly longer than previous Comstock and Concho wells, which ran -- they ran 3,500 to 4,000 or a little over 4,000 feet; and the Gaucho well is 6,837 feet. Comstock's fourth horizontal well is the Balmorhea 32-15 #1H, which will also target the Wolfcamp A interval with a planned lateral of over 7,000 feet. The vertical portion of this well is currently being drilled. Just to note, we own 100% of the Gaucho well, as well as 100% of the Dale Evans well. Slide 33 shows the primary oil targets on our acreage in Reeves County. Also shown are the potential completion types that we anticipate will be prospective. On the far right is a conventional vertical Wolfbone well, showing a primary 1,500 feet of completion interval from the third Bone Springs through the low -- through the middle Wolfcamp or lower Wolfcamp. In addition to that, we believe there are several horizontal targets in the Bone Spring and Wolfcamp shales that may significantly improve the economics of the play. Other operators in the area are actively pursuing horizontal opportunities in the Bone Spring and various benches in the Wolfcamp. Our Gaucho well is testing the Wolfcamp A, which has seen the most success by other operators in Reeves County. Our Monroe tested the Wolfcamp B, which has been moderately successful. And as I said before, the Dale Evans, which was not successful, tested the middle Wolfcamp shale. The horizontal aspect of this play is still emerging, so there is much science to be applied before it can be verified, but we are very excited to have such a prime position in this basin. And now, I'll turn it over to Jay.

Thank you, Mark, and again, Roland, earlier. If you look at the very last slide, the 2013 outlook, I mean, we are excited about the prospects for Comstock this year because we are able now to inventory our Haynesville gas region, and we'll spend our money this year developing our 2 Tier 1 oil basins, the Eagle Ford and the Permian, as Mark just reviewed. We expect the strong growth in our oil production will be more than offset -- will more than offset the low natural gas prices to allow us to have higher revenues and cash flow and be a much more profitable company in 2013. And we expect oil to comprise more than 25% of our 2013 production. 94% of the net wells that we will drill in 2013 will be oil wells and 92% of our budget will be spent on oil projects. Even though overall production this year is expected to decline, we do expect oil to grow by 40% to 60% over last year, which will grow our revenues and grow our cash flow. Our Eagle Ford shale program will be, again, our largest growth engine for this year, and we also see tremendous upside in future horizontal development in the emerging Wolfcamp shale based on recent activities in Reeves County, and hopefully, our own Gaucho well. And we continue to have one of the lowest overall cost structures industry, and we have adequate liquidity for our 2013 drilling plans. We expect operating cash flow to fund most of our planned drilling program and that the availability under our bank credit facility will increase with our oil reserve growth. We'll continue utilizing an oil price hedging strategy to protect our oil-focused drilling program. And as I stated earlier, a key component to Comstock in 2013 is to de-lever our balance sheet by bringing in a partner in our Permian drilling program later this year. We think a good partner will create a win-win situation in the Permian and allow us to de-lever our balance sheet, and enable the Permian to be developed on a more consistent scale, incorporating both the vertical and the horizontal well programs that Mark just described. So for the rest of the call, we'll take questions only from research analysts who follow the stock. Erika, I'll turn it back to you.

[Operator Instructions] And our first question comes from the line of Leo Mariani with RBC.

Just a question around your comments about partnering in the Permian. Is that something you guys are pursuing extremely quickly here, you're getting after that right away? And should we expect that to be a very similar type of deal that we saw in the Eagle Ford in terms of structure?

Yes, this is Roland, Leo. Yes, on the question about looking for a partner in the Permian, it's something that we do want to -- we're going to start after we get the results from the 2 Wolfcamp A horizontal wells. So it's something that we like to kind of have identified a potential partner by the end of the second quarter. So that's kind of our goal, and it will be a similar process to the Eagle Ford. And as far as the actual structure, we're really hoping to how that will be structured. I think we would -- since we want to use it more to de-lever the balance sheet, it probably have to be structured differently. It would be more upfront funds. We have a lot invested in the Wolfbone properties. So I would see the structure in the Eagle Ford, which works right there, might not be ideal for this one if we're going to use it to de-lever the balance sheet.

Okay, that makes a lot of sense. And I guess, another question for you guys. In terms of the Gaucho well, sounds like you guys are going to know results in that pretty soon. Will we expect to -- you guys can expect to release those prior to first quarter earnings? Could we see an interim update with some results there?

Yes, this is Roland again, Leo. I think that we'll decide that kind of later on. I think, unfortunately, it would have been nice if the Gaucho could report results today because we, as a company like to give a comprehensive update to our drilling results every quarter versus picking wells to point out. But we understand the importance of the Gaucho and understand the importance of putting out something from the company versus having it leak out in the market. So I think that's something we'll evaluate once we actually even know what the well is going to do. And so the typical timeframe for the other 2 horizontals, it has taken about 2 to 3 weeks to establish an initial rate. So we're -- hopefully, today will just start the very first day of recovering some of the frac fluids that were injected in the well.

Yes, Leo, my comments to follow up with Roland, I mean I think we have too much debt. We do have to de-lever our balance sheet. We intentionally levered up the company in order to add the 2 oil basins, and we did bring in a perfect JV partner in the Eagle Ford. And of course, in the Eagle Ford, we didn't pay $332 million to enter the Eagle Ford. We base leased our acreage and then drilled it. I think we acted differently in the Permian. And now the Permian, we've had really good results vertically. I expect to have really good results horizontally with the Gaucho and the Balmorhea, which is at Wolfcamp A, which is our first horizontal Wolfcamp A. So I think with that, we will open the debt room, as Roland said, and -- but this JV will be structured differently than the Eagle Ford because we need to de-lever our balance sheet. And then I think as far as the press release on the Gaucho, I mean, we're listening to all of the stockholders and we'll act accordingly. So I hope that helps.

Could you address well costs on these horizontals you're doing in the Wolfcamp and also what you're seeing in the vertical Wolfbone well costs?

Yes, Mark will do that.

Yes [indiscernible] well cost on the horizontal Wolfcamp were -- our hefty cost is about $10 million right now. We still have some science involved and we drilled a 50% longer lateral or almost 50% longer on this one and a significantly larger frac job. So while our service costs have down, we've kind of evened that up with the additional lateral length and the additional frac-ing on this well. As far as vertical Wolfbone, our cost is coming down. I don't have real hard numbers, but I think our goal is to be around $4 million, and we are working toward that goal. I wouldn't say we're there yet, but we're getting much closer. And then in the Eagle Ford, you saw the curve. We're down around $8 million or a little bit less. We used $8.2 million in our budget because we have a lot of longer laterals and longer than the 5,800 feet. So we standardized that cost to be able to compare apples-to-apples across the field. But if you drill 7,000-foot laterals, the well is going to cost a little bit more. So that's kind of where we're at on that, and we've seen the significant stimulation cost reductions in the Eagle Ford, which has helped us come down on those costs.

Your next question comes from the line of Amir Arif of Stifel, Nicolaus. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Just a question about the Permian. The key question really is, can you just talk about the partnership that you're thinking about the Permian and how that ties into your oil production growth guidance that you've laid out? If you bring in a partner, would you accelerate activity to keep your net oil volume growth at 40 to 60? Or is this going to be more just straight balance sheet reduction?

Well, Amir, the -- our production growth goals this year are based on not bringing in a partner, so that's the program that's kind of budgeted for. I think as a goal of this company to de-lever, I think that bringing in a partner into the Permian would -- the big benefits would be we would have more activity there and hopefully spend less dollars there and have more activity. So I mean we can't really say what the -- since we don't know what the structure will look like, we don't know the impact, but the overall goal would be that we can actually have more production growth this year potentially if we have more capital available to add another rig to the Eagle Ford. That's one of the goals of doing a joint venture in the Permian, would be to accelerate activity in the Eagle Ford where we can immediately bring on more oil production if we could add another rig there, at the same time, de-lever the balance sheet. So right now though, the guidance that we're providing assumes that we're not -- we're going to stick with the plan as it is, which is to spend the money that we have budgeted. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. So just to summarize, is there a downside risk to that number with a partnership or upside risk to the net volumes for the oil side? I guess, it depends on the structure.

Depends on the structure and depends on whether they participate in the current producing wells. The Eagle Ford that was structured where they did not. So there's a lot of ifs. But if there would be any type of downside, it would be very temporary because I think in the long run, it would allow us to accelerate activity as a company. And the quicker that we add a rig in the Eagle Ford, we can make up a whole lot of oil production that may go to a partner in the Permian. Amir Arif - Stifel, Nicolaus & Co., Inc., Research Division: Okay. And then just a follow-up question on your Gaines County acreage, if you can just give us an update on what your plans are for that.

Right now, our activity, Amir, is focused in the Reeves County acreage, so we are kind evaluating our Gaines County acreage to determine how best to go and proceed with testing that, and we really don't have a plan that we want to talk about yet. So we do know that we need to get it evaluated, and that's kind of in the works.

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

I was just hoping you could clarify what you think the biggest driver is and the difference in the performance you've seen in your horizontal Wolfcamp wells versus what you've seen in the offset Concho wells. Is it just as simple as they're targeting the Wolfcamp A with their laterals or is there some other notable difference in how they're completing producing these wells?

Mike, this is Mark. The completions are similar, not significantly different by any means, and the lateral lengths are similar. So I do believe it's just the rock is acting different in the middle Wolfcamp, in the Wolfcamp B, versus that Wolfcamp A section. So that's kind of the simple answer, and we'll be able to verify that with the Gaucho well and then following up with that with our Balmorhea well, which will be in the Wolfcamp A as well. So that's what we believe right now, that it's just the rock quality in the areas where we drilled our wells. We do believe that, that middle Wolfcamp has some significant potential over to the East. It does look better over to the East. And at some point in the future, we want to test that. But we're going to focus this year on the Wolfcamp A because that's where we've seen the most success.

Got it. And Roland, a question for you. I was just hoping that -- you gave oil guidance, reiterated it at 40% to 60% growth in 2013, but was hoping for some help on Q1. How does that progression look on the oil side in the Eagle Ford and in the Permian?

Yes, Mike, in the Eagle Ford, yes, we still have some of the issues that kind of flagged the fourth quarter, especially in the month of January and part of February. But we do expect to see our total company production oil grow from the fourth quarter levels, but probably not quite back to where we were in the third quarter of last year. I think that March will be real strong, but it's going to be diluted a little bit by January and part of February because we still had shut-ins and not many new wells coming on yet, so -- well, Mike, I think our biggest production from quarter to quarter just based on how the Eagle Ford, which is the biggest driver, is stacked up, the second quarter growth over the first quarter will be our most dramatic growth quarter-to-quarter just based on today's schedule. Because there, you'll have the benefit of coming and starting the quarter with really hot production month and having some good completions. And then we see kind of fairly consistent growth from the second to the third to the third to the fourth despite the spottiness in the completions, the way that it kind of matches in the different quarters. So really, a big uplift by the second quarter and then some moderate growth in the third and fourth. The wildcard in the production forecast is how does the horizontal Wolfcamps, how do they come in, because we're up -- we're being conservative in what we expect from them. And so they have the ability to allow us to have higher expectations for oil, but we need to see the results of those 2 wells.

I think to be accountable, I mean, to the stockholder, we -- 2 things. One, we put Slide 26 in, which shows you the completions per month for the Eagle Ford. We thought that visual was very important. And then I have asked Mark to kind of give an update on fourth quarter production versus where we are today. And really, the location of the Eagle Ford wells that we drilled and the completion times, I think that's big because, again, the Permian will be pretty consistent, I think, from here on out. But really, the driver of the predictable well is the Eagle Ford. I mean we hit a huge well in the Gaucho and the Balmorhea, then all bets are off to the upside because it will be really good in the Permian. But we're still kind of going through that dance. We've got some really good vertical wells that are very predictable in the Permian. But right now, in our model, the real driver of our oil is the Eagle Ford. So I'll let Mark kind of give you his COO view of that.

All right. This is Mark. I'll run through both areas real quick and just kind of give you a list of things. In the Eagle Ford, several factors affected our Q4 and early Q1 production, and we've already spoken about most these, but I'll hit them again. As shown on Slide 26, a very small number of wells came online since last October, and this continues really through this month. And then in late February and March, we just have a big ramp-up of completion activity. This is mainly due to the pad drilling that we're executing, which defers our completions until after all the pads are drilled and then you move in those frac crews and you frac the whole -- all the wells on the pads. So everything just takes longer, it defers that activity. The second factor is that 2 of our last 4 wells that we've completed are in Atascosa County. That was the Mesquite well and the DVR well. And that's where IP rates are significantly lower than in our prime McMullen County acreage. These are lease obligation wells. They hold a significant amount of acreage, so we felt they were valuable to drill even though they're not our Tier 1 acreage. Third, we had several wells shut in for extended periods and mainly in December for offset frac-ing either by us or by other operators across the leased line from us. And lastly, we had numerous operational issues beginning in early to mid-December and continuing until just about now. And these were mainly due with new wells loading up and artificial lift-related issues that we've had to work through. We still had 5 wells down this morning, and all of which -- all but one of which should be returned to production in the next few days. We have one well shut in because we have a drilling rig on the pad drilling another well. So we can't get it on until we get that drilling rig done. Now the Wolfbone, the primary factors affecting production have been operational and then the results of our horizontal program. Similar to the Eagle Ford, we were kind of hit with a rash and mechanical issues in Q4 that carried over into Q1 of this year. Almost all of these were artificial lift-related. We've made changes to our chemical program and to our equipment design that should significantly improve performance. But those changes have to kind of work their way through the system. And as you repair wells, you make the changes and then they may become less problematic in the future. We have reduced the number of nonproducing wells from a high of 16 to 11 currently. And we should have several of these return to service this week. And regarding our horizontal program, the effect of the Dale Evans #2 to production was pretty significant. Not only did the well underperform even our average vertical wells, but it occupied a drilling rig for 75 days, a time period in which we probably could've drilled 3 vertical wells. So for the foreseeable future, our horizontal program will be focused on the Wolfcamp A, where the results offsetting us have been significantly better. And we'll monitor our results and carefully tread forward this year.

If you look in our budgets in the Eagle Ford, it's 27 net wells. 22 of the 27 are in McMullen, kind of like Mark said. And then you go to the Permian, I mean, we had 27 net wells in the Permian also. 20 of those were vertical wells, and they're going to be really configured toward the Tier 1 portion that we de-risked, and then the 7 -- there are 7 net horizontal wells. And instead of drilling a Monroe well or a Dale Evans type well, the 7 wells that we will drill in 2013 will be, one is the Gaucho, and so Wolfcamp A; the second one is a Balmorhea, that's a Wolfcamp A. We don't plan on drilling any of the horizontal wells in the Permian till we know the outcome of the Gaucho and then the Balmorhea. And then our goal is to kind of offset those wells and we'll kind of inch out from those core wells in our development program for horizontal wells in 2013. So it's going to be a lot more predictable, and I think that's what we need to do for this year. I hope that's a long, long answer, but I think everybody deserves that answer.

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

Quick question for Mark here. Mark, can you talk just a little bit about the well design on the Gaucho State well? At 60- or 100-foot lateral, 18 stages, so about 375 feet per stage. Seems a little bit wide. Can you just talk about why didn't you do a little bit more frac intensity in terms of the number of stages on that well?

Cameron, this is Mark. That's very similar to both our Haynesville and our Eagle Ford designs. In fact, in the Eagle Ford, we typically catch about 400 feet or a little bit over 400 feet per stage. We use 9 clusters per stage, and we limit the number of perforations so that we get about 2 barrels a minute per perforation. Here, we use 7 perforation clusters per stage instead of 9. And so we're a little bit more conservative here than we are in the Eagle Ford, where we've proven to our ourselves that, that design works. And so I would say we're a little more conservative here. Obviously, the less clusters you catch and the tighter the spacing, the more expensive the completion. So we feel like we've balanced out here in this completion pretty well. And if can we prove through some logging and analysis that we can add a cluster or 2 at each stage in the future, we'll probably do that. But for now, we're probably going to stick with this design.

The next question comes from the line of Michael Hall with Robert W. Baird. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: I guess, I wanted to dig in a little bit on the cost structure side of the equation. Cost structure on the lifting side propped up in the fourth quarter, just curious on the outlook for that as you work through '13, as you bring company volumes back on, should we expect that to come back down or just probably how should we think about that?

Sure, Micheal, this is Roland. If you look at the, today, the lifting cost just by the regions, I think you will see some improvement in the South Texas region, just a modest improvement with the higher volumes because there's still a fixed cost structure there. But again, we will be adding some dollars to the overall lifting cost as we put more wells in our official lift and the other type costs that goes along with that. So that the lifting cost rate in the fourth quarter was like $1.93 per Mcfe even though it still had an Mcfe basis. And we see that declining slightly as we look ahead to 2013 with the better volumes. I think there'll be a more dramatic improvement in the West Texas area, the same way where we had a repair cost also in the quarter and had a $4.11 per Mcfe-type lifting total all-in rate, including gathering and production taxes. We see a big improvement to that rate with the volumes coming up in that area. But then as a company-wide, obviously, in the gas -- where the gas production is, other than the production taxes and gathering costs, which are fairly proportional to the production levels, we'll see higher rates, lifting rates in the Haynesville/Bossier just because of the volume declines, and the rest of the costs there are fairly fixed. And so company-wide, I don't -- I think that we will have those 2 factors kind of working together. And then so as far as the overall lifting rate, which was $1.19 in the fourth quarter, I think the numbers, we'll see a little higher lifting rates consolidated for all of the regions as we go into 2013. We see it at a level starting kind of where it was the fourth quarter to all-in kind of lifting rates approaching $1.40 or something by the end of the year, just as the mix of oil is higher versus the gas and just the lower gas volumes and the fixed cost. So kind of a complicated answer, but that's kind of what we'll see overall. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: That's helpful. And then, I guess, also on a kind of corporate level, I think you, in the past, alluded to reaching closer towards a kind of cash flow neutrality in back half of '13, I guess. Where is your head on that? And excluding any impacts of a potential JV, we'll see that occurring in '13 or is that being pushed back at this point?

No, Michael, we see us getting very close to that in the second half of '13 with the oil mix. Of course, a lot of it depends on overall -- especially the gas, what's the gas commodity price is and are we closer to the $4, are we closer to the $3. It's a big variable there. But -- and I think we've also been fairly conservative in the estimate of cost as you can see from our budget. So I think we're still under this year's plan without the JV, bring those 2 rigs close to each other in the second half of 2013 with a modest overspend in the first half given where current natural gas prices are at in the market. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Okay. And so those are -- those comments are based on basically strip pricing today? Is that...

Right, those are based on the strip pricing today. So we always -- in all our planning, we use strip pricing. So every time we want to look at it, we just run them again versus taking a view on -- a different view on the market. So I think what the idea of really achieving debt reduction and really de-levering the balance sheet is what we want to accomplish by bringing a partner into the Permian. And so that's a big focus of this year's goal, as well as developing the 2 big oil plays.

Well, and like Roland said, if you talk at maybe the game changer in the Permian for the horizontal, the Wolfcamp A, I mean in the model, we get horizontal wells just a slight increase from the vertical wells that we know what their average IP rate is. So we bump that up a little bit, but we don't give it a high number. So if these wells come in at a high number, then that's a game changer, too, as you know.

Your next question comes from the line of Mario Barraza with Tuohy Brothers.

Jay, I just want to follow up on your comments about, in the Delaware Basin. You mentioned you're going to be targeting the Tier 1 acreage. How would you rank, now that you've delineated on a vertical basis, the acreage on a tier side, Tier 1? Is there a few tiers, say, Tier 1, Tier 2, Tier 3? And how does that break out percentage-wise?

Well, I think when I say Tier 1, when we look at our drilling program in 2013, we're going to focus if we can, again, some of this is lease obligation-driven, we're going to focus our vertical wells near offset wells maybe on different leases. We've had 300-, 400-, 500-barrel a day IP rate wells. We're going to try to do that and then we'll try to stay away from the areas where vertically, we put our 180-, 190-, 200-type barrel a day wells. And you can see that on one of the charts that we've handed out. I mean that's our goal, if we can do that. I mean, there might be some straggler wells that we need to drill in order to hold the lease blocks, but that's not something we're going to try to focus on. Mark might want to comment some more on that, but that's how I look at.

That's exactly what we're going to try to do. We still haven't determined that some of the fringe acreage isn't valuable for horizontal drilling. So until we determine that, one way or the other, where we can, we're going to hold the large acreage blocks. But we're going to do that with a minimum number of wells and minimum cost, and really try to focus to build our production more than anything.

Okay. And then just a clarification point, Jay, earlier in the call, you said that your footprint now is 42,000 net acres. Is that correct or is it the 44,000 still?

We started out a year and 2 months ago at 44,000. Then we traded some acreage. We bought a little acreage. We sold a little acreage. And so the net, I think the net is like 41,500 acres to 42,000 net acres. That's the number.

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

I think most of my questions have been touched on. I just wanted to check on the time when those horizontal Haynesville wells will be coming online.

Well, the Gaucho well, the [indiscernible] should be...

No, the Horizontal Haynesville well, did you say?

Yes, that's correct.

I believe we have those scheduled -- we have a rig scheduled to come in, in, I'm thinking it's the first or second week of March. And they're 2 wells on the same pads. We're just going to go ahead and drill them both at the same time, so they're probably May or June, probably May or June as far as IP rates on those 2. And those are lease obligation wells under a lease we took and we [indiscernible] up a while back. And we were obligated to drill 4 wells, and we drilled 2 of them last year and these will be the other 2 remaining wells. And then as far as all the other wells in the well count, those are just non-placeholders assuming that some of the partners would propose wells. We just don't -- we haven't -- don't have any proposed at this time. We don't know if anybody's going to propose any to us or not.

Okay. And then, I guess, a quick question on CapEx. You see kind of level spending throughout the year. I heard you talking about being close to cash flow neutral in the second half. Does that assume kind of level CapEx numbers throughout the year?

That's correct, Richard. We think the -- that given -- yes, the rig count will stay very consistent through the year. So other than the Haynesville, where we might -- that activity will bring the rig count of a one-off activity. So in the end, we'll make a run at trying to extend that or push that out. But it may not be successful, so it's budgeted. So that's the only activity that would be kind of, in one particular quarter, which sounds like it could be more in the second quarter. But the rest of it will be fairly leveled out. Some of the completions may stack up heavier in one quarter than another.

That's all the time we have for today's Q&A session. I would now turn the call back over to Jay Allison for any closing remarks.

Yes, thank you, Erica. And again, our goal this conference call is to get, quite frankly, 2012 behind us and it's to continue to transition this company, I mean, away from this 98% natural gas platform we had, which at that time, several years ago, that was a good platform, today, it's a horrible platform. And in order to change the platform, we did have to add 2 Tier 1 oil basins. I think we're exactly where we need to be. I think our performance is a little lumpy. We're very disappointed in the fourth quarter results. I think that's part of just transitioning to become an oil company. And that's a little bit of the lumpiness in the Eagle Ford, which, again, is the driver. We did have a disappointing Dale Evans well and that did hurt production, and we're not going to do that again in 2013. We're going to kind of hunker down, drill these Wolfcamp A wells, which is out of the Gaucho, the Balmorhea or some others maybe. And it will -- the Permian is a very hot area right now. We've had phone calls asking what they could do with us in the Permian for prospective partners. So that's a good thing. It's a good thing to be in a nice hot area where I think 20% of all the oil produced in the United States comes from the Permian, and that's for a reason, and we're right in the middle of it. So we're very, very pleased. And we were at a conference last week and we were in New York a couple of weeks ago, and our goal was, and we didn't know this, and Mark moved up this completion date on the Gaucho because really, the Gaucho initially wasn't scheduled to be completed until today. But we did move that up and we did have the 18-stage frac, and like he said, we should start flowing that well back today. And that's a great thing, so we at least don't have that hanging out there. And we just need to see the rock quality of the Wolfcamp A that we drilled in. And again, as Mark said, it's between 2 good offset wells that some other companies own. So we'll see what happens, and I hope that we've given full accountability of 2012, and particularly, where we're going in 2013. It's a privilege to work here, and we try to do the right thing and we try to be accountable. So anyhow, thank you.

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