Comstock Resources, Inc. (CRK) Q2 2012 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Second Quarter 2012 Comstock Resources, Inc. Earnings Conference Call. My name is Janeda, and I will 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 conference over to your host for today, Mr. Jay Allison, Chairman and CEO. Please proceed.

Thank you, Janeda. I like your tone. It's excellent to start the meeting off. Welcome to the Comstock Resources Second Quarter 2012 Financial and Operating Results Conference Call. You can view the slide presentation during or after this call by going to our website at www.comstockresources.com and clicking Presentations. There you'll find a presentation entitled Second Quarter 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 the new joint venture we have entered into on our Eagle Ford acreage, review our 2012 second quarter financial and operating results, as well as update the results of our 2012 Eagle Ford and Wolfbone drilling programs. Please refer to Slide 2 in our presentation and note that our discussion today will include forward-looking statements within the meaning of securities laws. While we believe the expectations and such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. Tab 3. Please refer to Page 3 of the presentation where we summarize our second quarter results. The financial results this quarter were impacted by the very low natural gas prices that we received for our production. The growing oil side of the company is helping mitigate the negative impact that the very weak natural gas prices were having on our financial results. For the second quarter, we reported revenues of $105 million, generated EBITDAX of $75 million and had operating cash flow of $61 million or $1.32 per share. We had a net loss of $10.3 million or $0.22 per share. We grew our production by 6% as compared to the second quarter of 2011. More importantly, we increased our oil production by 267% from our oil production in the second quarter of last year. Our 2012 drilling program is off to a strong start, especially in our newly acquired Wolfbone field in West Texas. Mark will report that some of the -- our most recent vertical wells are some of the best reported in the play to date. We drilled 39 successful wells, including 32 successful oil wells in our Eagle Ford and Wolfbone programs in the first half of the year. We're excited today to be able to announce a new partnership that we've formed with KKR. The joint venture places a $25,000 per acre value on the acreage position we have assembled and will allow us to accelerate drilling activity, while also bringing our CapEx down to be in line with our operating cash flow. If you'll flip to Slide 4, we'll summarize the new joint venture. We believe that KKR will be an ideal partner for us since they are an experienced participant in the early development of the Eagle Ford shale through their Hilcorp investment. The joint venture provides KKR an opportunity to participate, but does not obligate Comstock to drill wells in the future. KKR will have the right to participate for 1/3 of our working interest in wells drilled on our 28,000 net acres in exchange for $25,000 per acre for the net acreage being acquired. KKR earns 1/3 of our working interest in 80 acres for each well they participate in. In other words, they pay $667,000 for 26.7 net acres that we assign them, and they pay 1/3 of the well costs. The agreement will apply to wells spud on or subsequent to March 31, 2012, and we will retain all our other interest in wells spud prior to that date. KKR has committed to acquire acreage for the next 100 wells drilled on our Eagle Ford shale acreage and can continue to participate in additional wells drilled on the acreage for the same terms. Basically, we are guaranteed $67 million for the 2,167 net acres that the first 100 wells will earn, and they can continue to participate on the same terms until they have earned a 1/3 interest in all of our undeveloped acreage. This transaction will provide the capital necessary for us to accelerate drilling on this exciting oil play while still allowing us to have the capital to develop our Wolfbone properties in West Texas. I'll turn it over to Roland to review the financial results for this quarter in more detail. Roland?

Thanks, Jay. At Slide 5, we show our crude oil production on a daily basis for the last 3 years by quarter, including the first 2 quarters of this year. Our oil production this quarter grew 276 -- 267% to 6,400 barrels per day as compared to the second quarter last year when we produced only 1,700 barrels per day. Our Eagle Ford shale properties in South Texas, shown in light blue on this chart, increased to 4,600 barrels per day and is the main driver of our oil growth this year. We added about 500 barrels per day in the Eagle Ford this quarter, as compared to the 4,100 barrels we averaged in the first quarter of this year. Our Wolfbone properties in West Texas contributed 1,400 barrels per day to the average rate and is starting to become a major player in our oil growth this year. Looking ahead to the remainder of this year and with all the drilling activity starting in the second quarter focused on oil, we are forecasting our oil production to grow by approximately 200% over last year's production, to be around 2.4 million to 2.6 million barrels in 2012. And this is even after we did divest a 400 barrels per day on May 1 of this quarter. Slide 6 shows our natural gas production on a daily basis. Natural gas production declined by 5% this quarter from the second quarter of last year, to 241 million cubic feet per day, and was about 5 million a day less than our first quarter rate of 246 million per day. The decrease is primarily attributable to the production we sold with our May property divestiture and was up about 1 million a day if you look at the production on a pro forma basis, excluding the sold production, which we show on green on our production chart. Production from our Haynesville and Bossier shale wells came in at 180 million per day in the second quarter, and it accounts for 75% of our total gas production in the quarter. Our Haynesville production increased about 5 million a day from the first quarter rate. The remaining 25% of our gas production was pretty comparable to the levels we had in the first quarter. Production from our Cotton Valley wells, which is shown in dark blue, declined slightly to 28 million per day in the quarter, and our South Texas gas production, which is shown in red on the chart, remained the same at 23 million cubic feet per day. We're forecasting natural gas production this year to be approximately 84 Bcf to 85 Bcf, which would be a decrease of about 5% to 7% from last year's total gas production. The decrease this year is mostly due to the sale of 9 million cubic feet of gas per day that we sold and completed those sales on May 1 in this quarter. On Slide 7, we show our average realized oil price which decreased 2% in the second quarter of 2012 to $98.70 per barrel as compared to the $100 -- $101.02 per barrel that we had in the second quarter of 2011. Our realized price averaged 106% of the average benchmark NYMEX WTI price in the quarter due to the high differentials that we're seeing from our Eagle Ford shale wells. 77% of our production in the quarter was hedged at a NYMEX WTI price of $99.53. So if we include the gains from our hedging activity, we realized $103.37 per barrel for the quarter, which was 2% more than the prices we had in the second quarter of 2011. Slide 8 shows the oil prices for the first half of this year, and our realized oil price increased 6% in the first half of 2012 to $101.17 per barrel as compared to $95.89 per barrel in the same period in 2011. Our realized oil price averaged 103% of the average benchmark NYMEX WTI price. And 74% of our oil production for the first half of this year was hedged at a NYMEX WTI price of $99.37. So including the gains from the hedging, we realized $102.43 per barrel in the first 6 months, which was 7% higher than the realized prices we had for the same period in 2011. Slide 9, we outlined our hedge position for oil production, and we do have an attractive oil hedge position in place, which does protect our 2012 oil-focused drilling program. We have 5,000 barrels a day hedged at $99.53 for the WTI price for the rest of this year for the last 2 quarters, and then we have 3,000 barrels a day hedged at $100.33 per barrel for all of 2013. We do plan to continue to add to our 2013 positions as the year progresses. Slide 10 covers the natural gas prices. The last quarter where we had natural gas prices as low as the $2.03 that we realized this quarter was over 13 years ago, and it was in the first quarter of 1999. Our average gas price this quarter decreased 52% as compared to the $4.19 we had -- we've realized in the second quarter of 2011. Our realized gas price was 91% of the NYMEX Henry Hub gas price for the quarter. Our average gas price for the first 6 months of 2012 decreased 43% to $2.34 per Mcf as compared to the $4.08 that we realized in the first half of last year. Our realized price was 94% of the average NYMEX Henry Hub gas price for the first 6 months of 2012. On Slide 11, we cover our oil and gas sales. The 6% production growth we had this quarter and more importantly, the 267% growth in our oil production offset much, but not all, of the impact of the 52% decline in natural gas prices. As a result, our sales were about 7% less this quarter than they were in the second quarter of last year, at $105 million as compared to $112 million we had in the second quarter of 2011. Our oil sales now make up 58% of total sales this quarter as compared to making up only 14% of total sales in the second quarter of last year. For the first 6 months of 2012, sales have increased 7% to $215 million as compared to $200 million for the same period in 2011. Our oil accounted for 52% of our total sales in the first half of 2012 as compared to only 14% of our total sales in the first half of last year. Earnings before interest, taxes, depreciation, amortization and exploration expense and other noncash expenses, or EBITDAX, decreased by 14% to $75 million from the $87 million we had in the second quarter of 2011, which is all shown on Slide 12. EBITDAX for the first 6 months of 2012 has increased 1% to $154 million from 2011's $152 million. Slide 13 covers our operating cash flow. Our operating cash flow for the quarter came in at $61 million, which is 20% lower than cash flow of $77 million in 2011's second quarter. Our operating cash flow for the first half of this year was $128 million, a 4% decrease from the 2011's operating cash flow of $133 million. On Slide 14, we outlined our earnings. We reported a net loss of $10.3 million this quarter, or $0.22 per share, as compared to earnings of $3.9 million, or $0.08 per share, in 2011's second quarter. For the first 6 months of 2012, we reported a net loss of $3.4 million, or $0.07 per share, as compared to earnings of $6.4 million, or $0.13 per share, for the same period in 2011. The year-to-date financial results in both periods include several unusual items. For the second quarter, the reported net loss includes a gain of $20.3 million or $13.2 million after-tax or $0.28 per share that we realized on the sale of the properties we divested of in the quarter and a $5.3 million impairment or $3.4 million after-tax or $0.07 per share on certain natural gas properties that we impaired during the quarter. The first 6 months of 2012 included gains of $27.1 million or $17.6 million after-tax or $0.38 per share on the property sales. It also includes gains of $26.6 million, $17.3 million after-tax or $0.37 per share on sales of our Stone Energy shares, and then it also included $6.7 million in impairments or $4.4 million after-tax or $0.09 per share. Excluding all of these items, we would've reported a net loss of about $0.43 per share this quarter and $0.73 per share for the first 6 months of 2012. On Slide 15, we show our lifting cost per Mcfe produced by quarter. Lifting cost on this chart is comprised of 3 components: production taxes, transportation and then other field level operating costs. In the quarter, our total lifting costs came in at $0.97 per Mcfe as compared to $0.85 per Mcfe in the second quarter of 2011. However, our lifting cost did improve from the $1.03 per Mcfe produced that we averaged in the first quarter of this year. The increase year-over-year is mainly due to the higher cost of the oil production that are now making up a greater share of our production versus the very low cost of the Haynesville gas production that dominated last year's production. In the quarter, production taxes were $0.13 per Mcfe, transportation cost averaged $0.29 and the field operating cost averaged $0.55 this quarter as compared to the $0.51 rate we had in the second quarter of 2011. On Slide 16, we show our cash G&A expense produced by quarter, excluding stock-based compensation. Our general and administrative costs were up slightly to $0.22 per Mcfe produced in the second quarter as compared to the $0.21 per Mcfe we had in the second quarter of 2011 and in the first quarter of this year. Our depreciation, depletion and amortization per Mcfe produced is shown on Slide 17. Our DD&A rate in the second quarter averaged $3.59 per Mcfe as compared to the $3.12 rate we had in the second quarter of 2011 and the $3.24 rate we averaged in the first quarter of this year. The low natural gas prices, especially on the last 12-month basis, which is used to calculate reserves that we calculate DD&A on, drove up the DD&A rate this quarter. Because now the 12-month average SEC price is now low enough, the cost of the exclusion of a substantial amount of our undeveloped natural gas reserves from proved reserves. The increased rate is also slightly due to the higher cost of the oil production that we're now producing also. So as the 12-month average SEC price starts to improve, we can see it having those undeveloped reserves come back into the equation, and then sometime in the future, be able to drive the DD&A rates back down. On Slide 18, we detail our drilling expenditures. We spent $313 million on drilling and completing wells in the first 6 months of 2012, which happens to be the exact same amount we spent in the same period last year. We spent those dollars, we spent $93 million of those dollars in our East Texas, North Louisiana region; $140 million in our South Texas region; and then $80 million in our new West Texas region. To date in 2012, 70% of our joint expenditures have been spent drilling oil wells as compared to only 21% of our expenditures last year were for oil projects. On Slide 19, we break out our revised capital budget. After taking into account the new drilling venture with KKR and then after adding a third rig to our Eagle Ford program and then adding more horizontal wells to our West Texas program, which Mark will go over in more detail in a few minutes, we are adjusting our drilling budget for this year to $475 million. We now expect to drill 81 wells this year, 12 gas wells and 69 oil wells. Our spending this year has been very front-end loaded. And now with the joint venture in place, we expect our cash flow to actually exceed our drilling expenditures in the second half of this year. On Slide 20, we recap our balance sheet at the end of the second quarter. At the end of the quarter, on June 30, we had $4 million in cash and then $15 million in marketable securities on hand. We had $1.2 billion of total debt, comprised of about $883 million of our senior notes and then $340 million outstanding on our refined credit facility. After the bond offering that we completed in early June, our borrowing base is now at $569 million, with $229 million available. Our equity accounts were just over $1 billion, which is making our debt 54% of our total book capitalization. I'll now turn it over to Mark to kind of review our operating results in detail.

Thanks, Roland. On Slide 21, we recap our activity in our East Texas/North Louisiana region so far this year. In the first quarter, we drilled 3 operated Haynesville wells, 2.5 net, before we moved our 2 operated drilling rigs out of this region. We participated in another 4 non-operated wells, 0.7 net so far this year. We completed all but 1 of our operated Haynesville shale wells and still have 3 or 0.3 net non-operated Haynesville shale wells waiting to be completed. We will be able to exploit our 7 Tcfe of Haynesville and Bossier resource potential in the future when improved gas prices provide economics competitive with our oil projects. Slide 22 shows our West Texas region and the 91,000 gross and 50,000 net acres that we have. Our activity this year will be focused on Reeves County and the properties we acquired from Eagle Oil & Gas at the end of last year. The Reeves County acreage provides us over 900 net vertical locations targeting the Wolfbone and 178 million BOE of resource potential. We have a proven and successful vertical program on our acreage, but we think there is significant upside with horizontal development in the Avalon, Bone Spring and Wolfcamp formations on our Reeves County acreage. Recently, other operators in the area have had strong results from horizontal Bone Spring and Wolfcamp wells around our acreage. Slide 23 shows our Reeves County acreage and highlights the latest 8 vertical Wolfbone wells we reported on to date. So far in 2012, we have drilled 17 vertical wells, 14.2 net, all of these are successful. Since closing on the acquisition, we have drilled and completed 13 operated vertical Wolfbone wells. These wells were drilled to total depths between 11,370 and 12,786 feet, and completed with 5 to 11 frac stages. These wells have an average per well initial production rate of 374 BOE per day, of which it's about 78% oil. Our vertical Wolfbone wells continue to be some of the best vertical oil wells in the play. Of the 8 new wells reported on this quarter, 3 wells had initial production rates over 400 BOE per day, including the Pat Garrett 38 #1 at 489; the Buffalo Bill 9 #1 at 517; and the Trigger 40 #1 at 419 BOE per day. Slide 24 shows the 33 operated wells in our Wolfbone field, including the 8 we completed in the second quarter. The 33 wells had an average per well initial production rate of 311 BOE per day. The 30-day rate for the 31 wells that have produced that loan averaged 84% of their initial rate. And over a longer period of 90 days, the rates have averaged 67% of the initial rate. We will continue to monitor results and adjust the completion approach, but we are very encouraged that some of the most recent wells had impressive IP rates and are so far well above our average Wolfbone tight curve. Slide 25 shows you the location of these 33 wells from the previous slide. The 4 wells with the highest IP rates so far, the Dale Evans, the Pat Garrett, the Buffalo Bill and the Jessie James, are highlighted on this map. Slide 26 shows where we plan to drill for the remainder of this year. Our drilling program is targeted at holding leases, so we cannot just focus on drilling where we see the best results. We have 3 wells currently drilling shown as red stars. One of these, the Monroe 35 #1-H is our first horizontal well targeting the Wolfcamp formation. We are currently drilling the horizontal portion of this well. We are completing 3 wells, shown in red triangles on the map. We're also conducting a micro seismic frac study with 2 of these completions to test the effectiveness of our completions. The red dots show the locations that are currently in our drill schedule, which include our second Wolfcamp horizontal well, the Dale Evans 196 #2-H. You've seen this slide before, but Slide 27 shows where we think our program is headed, and it's really headed to horizontal development. This slide shows the various targets in the Reeves County. Also shown are the potential completion types that we anticipate will be prospective on our acreage, including vertical and horizontal completions. On the ledges of conventional vertical Wolfbone well, showing the primary 1,500 feet of completion interval in the Wolfbone and an additional 1,000 to 1,500 feet of completion potential in the upper Wolf -- in the upper Bone Spring. In addition to that, we believe there are several horizontal targets in the Bone Spring and Wolfcamp that may significantly improve the economics of the play. We have up to 4 horizontal Wolfcamp wells scheduled this year which will target the Wolfcamp shale. Other operators in the area are actively pursuing horizontal opportunities in the Bone Spring and various benches of the Wolfcamp. The horizontal aspects of this play is just emerging, so there is much science to be applied before it can be verified, but we are very excited with the initial results we've seen from other operators and to have such a prime position in this basin. Moving on to the South Texas region. On Slide 28, we cover our South Texas operations, where all the activity is on our oil-focused Eagle Ford shale play. We have 30,000 -- 35,000 gross acres and 28,000 net acres in the oil window of the Eagle Ford shale, and this has not changed from the previous quarter. Based on 80-acre spacing, we believe we have 277 horizontal locations, including the wells we've already drilled. We have excluded some of our northern acreage and any acreage that we think is un-drillable from this estimate. The average gross EUR is 500,000 barrels of oil equivalent for the 5 separate tight curve areas that we use in our program. After deducting royalties and the interest that our new partner will earn in the joint venture, we estimate our properties will yield 78 million BOE, of which over 80% is oil. Slides 29 and 30 show the results and locations of the 35 wells which are currently producing. We completed 8 more Eagle Ford shale wells since our last update, and they are listed as wells 28 through 35 in this chart. The 8 new wells had an average per well initial production rate of 635 BOE per day. These wells were primarily drilled in the company's northern acreage, in Atascosa, La Salle and McMullen counties, in order to meet primary term lease obligations. All of these wells are being produced under the company's restricted choke program. Longer-term results -- longer-term production results from the first 29 Eagle Ford shale wells, which have produced more than 90 days, have confirmed the benefit of our choke back program. Our first 35 wells had an initial rate of 686 BOE per day. The 30-day rate for the 31 wells that have produced that long have averaged 510 BOE per day which is 76% of their initial rate. And over a longer period of 90 days, the rates have averaged 68% of the initial rate. The restricted choke program also extends the time before artificial lift is needed. In the second half of this year, we plan to begin more development drilling, which will allow for additional cost efficiencies associated with multi-pad development, and we'll also be targeting our higher IP wells in the southern part of our acreage. Slide 30 shows the location of the 35 producing Eagle Ford wells that were listed on the previous slide. I'll now turn it over to Jay.

Thanks, Mark, and thank you, Roland. If everybody will turn to Slide 31, despite the 13-year low natural gas prices that Roland had mentioned earlier we experienced this quarter, we are having a successful year. The strong growth on our oil production has offset most of the impact of the low natural gas prices. We expect oil to comprise 15% to 18% of 2012 production and over 20% of production at the end of the year. 92% of the net wells we will drill in 2012 will be oil wells, and 78% of our budget will be spent on oil projects. Even though overall production this year may only grow about 5% after the divestitures we completed this quarter, we expect our oil production to grow by more than 200% over last year. Our Eagle Ford shale program will be our largest growth engine this year. The recently completed Permian acquisition gives us another oil growth engine, and we're in the middle of one of the hottest oil plays in the country and sitting on great acreage position. In addition to a proven and profitable vertical drilling program, we see tremendous upside in future horizontal development in the emerging Wolfcamp shale, and we're drilling our first horizontal Wolfcamp, as Mark mentioned, we're drilling it now and we plan to drill another 3 later this year. We continue to have one of the lowest overall cost structures in the industry. We've completed several transactions this year to enhance our financial profile and liquidity, post the Permian acquisition and the fall in natural gas prices. And we reduced leverage this year by completing asset divestitures, which generated net proceeds of $184 million. We also competed a bond offering on June 5 to free up over $200 million of our bank borrowing base. We'll utilize an oil price hedging strategy to protect the acquisition and our focused drilling program on oil. The new joint venture agreement we announced today with KKR will allow us to balance our operating cash flow and drilling expenditures and gives the company a strong financial partner to help us pursue other growth opportunities. For the rest of the call, we'll take questions only from research analysts who follow the stock. So we'll turn it back over to you, Janeda.

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

A question on the JV. The 100 wells, have those been predetermined? Like the locations, is it certain areas? Or are you all driving the boat on those locations of the first 100 wells?

No, Brian, this is Roland. The first 100 wells have not been predetermined, and that will be proposed by Comstock as we choose to proceed drilling. So, obviously, there's an idea of what this year's program looks like.

Right. Okay. And you currently have 2 wells -- I'm sorry, 2 rigs running in the Eagle Ford. I'm assuming -- is that going to be increased as you go into '13?

Brian, this is Mark. Right now, we have 1 and we have another one coming next week, which will make it 2 and then we have a third rig that is contracted for about December 1.

Okay, okay. And then one final question. The increase to 4 horizontal rigs in the Delaware, the first is targeting Wolfcamp. Are all 4 going to be targeting the Wolfcamp, or are you going to try to test other zones as well?

This is Mark again. They will all target Wolfcamp, but probably not all in the same bench of the Wolfcamp.

Your next question comes from the line of Kim Pacanovsky with MLV & Co. Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division: I'm just wondering if you have any thoughts on the Pearsall, what you're seeing in activity your monitoring and any plans to test it yourself?

Kim, this is Mark. We are monitoring it very closely and are cautiously optimistic about the results we see. We like some of the results, but it's just so early in the play. We do plan to drill a couple of our wells as pilot holes and get data and get good new vintage logs and core data across the Pearsall to better evaluate it. So that's really the extent of our plan this year. Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division: And so that would be a 2012 event later in the year?

Yes. Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division: Okay, great. And do you have any opportunity to add acreage in McMullen County and the Hill area where you've had such excellent results?

Kim, I believe most acreage is tied up by the real players out there right now, a lot of opportunity in the McMullen area at this time. Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division: Okay. And then switching over to the Wolfbone, what's controlling the number of stages that you're completing in those wells? And could you just remind me of what the range in costs are there?

Kim, as far as the range in cost, we're between $4.5 million and $5 million right now. We're still doing some experimenting with whether or not to drill some of the deeper part of the Wolfcamp, the what we call the red sand and the yellow sand. And so in some areas, we're drilling it, and that adds frac stages. In some areas, we're not drilling it. It kind of depends on the results we've seen in that area. And then every well is -- the perforations are picked with the detailed logs that we run and the correlations. So each well is a little bit unique in terms of how many different perforation clusters that we're applying, so then you pick your stages kind of based on how me perforation clusters. Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division: Okay, fair enough. And then a big picture question, maybe for Jay. You said that in the second half of this year, your cash flow will exceed your drilling CapEx. Next year, is the goal just to drill within cash flow? Or do you actually want to pay down debt?

Well, our goal is to drill within cash flow as a minimum, and a better goal would be to pay down debt, so that's our priority. We want to stay within operating cash flow, but, Kim, 52%, 53% 54% net debt to cap is a little bit too high for us, we think. We think our reserves will qualify for that. In the older days, as you know, it used to be 60%, and today it's more like maybe in the 40s. So I think we should reduce that, but we do not plan to incur debt in 2013 by drilling or completing wells. The other thing we are looking, Kim, you asked about the Pearsall, we do think that maybe 82% of our acreage is in the Pearsall fairway. So as Mark said, we may or may not drill a well this year in the Pearsall, but we've taken a hard look at it. I know Cabot and Cheyenne and others are in the play. And so if we need to drill a well there, we can. That's a good question, thank you.

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

Just real quick on your first horizontal Wolfcamp well there, what is the AFE on that well?

Leo, this is Mark. Our initial AFE is 9.5 million, and that's pretty well in line when we started our Eagle Ford program and we did kind of the full experimentation, so we're pretty much in line with that.

Okay, and how many frac stages did you guys plan? And how long is that lateral?

It's about a 4,000-foot lateral or a little bit more, and it'll probably be 10 to 15 stages. We haven't designed the frac on it yet.

Okay. And when should we expect to see results of that?

Probably with the third quarter conference call because the it's the 1st of September completion, and by the we get all of our data, we're probably looking at 1st of October or later.

Yes, really, Leo, what really happened is we'll file a report with the railroad commission and you'll pick it up and you'll know the results, I mean, before we have the conference call. That's the real world.

Okay, I got you. I guess your oil price seemed particularly high in the second quarter if I just looked at on an unhedged basis. I think it was about $5 above WTI, differential improved from the prior quarter, just any kind of color around that?

Yes, Leo, this is Roland. That's all the Eagle Ford, and the Eagle Ford participates more in the Gulf Coast-type market, and that's really a function of the wider basis that we saw between WTI and Brent, which is where the Gulf Coast is more influenced by. So we have pretty wide differentials again now, so it's fairly volatile. We saw it improve from the first quarter, but it's whatever Brent versus WTI are doing, we get to participate in some of that premium in the Eagle Ford.

Okay. And I guess just last question, I know it was kind of a small number, but if I look at the way you all give some production detail on your earnings release, your other oil production was up a fair bit this quarter versus prior quarters. Are you guys potentially involved in any kind of new play or maybe there was new oil well that you guys haven't talked about yet?

Yes, Leo, there was a well where we were non-operating -- non-operator in, in South Louisiana, that reached a payout status, and we had a pretty good oil accrual on that well, and that bumped that number up a little bit.

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

Wolfbone looks strong and getting stronger. I was just hoping you could quantify the percentage improvement you've made in the IP rates since you've actually taken over that acreage and applied the new, the new completion technique to those vertical wells.

Remember, our starting goal was 200 barrels a day average for 30 days, and then Mark can go over what's happened since the first 3 wells. I mean, we've improved greatly.

Yes, I think, if I recall, I don't have the numbers in front of me, but I think the first wells were -- the first group of wells was about 280 BOE per day. And now we're up over 370 on the last group of wells. So we're looking at maybe 30% to 40% improvement in performance, and we're still fine-tuning.

Okay, that's great...

Mike, as we've said, if you drill to the kind of the west, I mean, that's not a great vertical play. We think it's a really good horizontal play. And we drill these wells north, south, east and west. If you go east or you go kind of southeast or northeast, we're at the better wells. So we blended all that in, so we're giving you a number that's not skewed toward the better part of the play. We're giving you a number that's encompasses the entire footprint of that 44,000 net acres.

Got it, okay. And you did mention that you -- and the results seem to really to confirm this, that you are ahead of the tight curve right now. Would you be willing or when would you be willing to actually go out there and revise that tight curve part?

When we say year end, we always look at reserves at year end, so we're looking at a year end, but they should go up, not down.

Got it, okay. And then moving over to the JV, I was just hoping to get a little bit more color on the mechanics of this. It looks like KKR is on the hook to pay you essentially an acreage fee for each well drilled in -- to the tune of around $667,000 per well. I was wondering if you can confirm my math on that. And also just kind of what pace do you expect to see here once you get the full, the second and third rig up and running, and how many gross wells could you drill in 2013?

We started going through this JV process back in January, and we had several proposals from some quality partners. And what we were really looking for was more of an oil and gas partner, not really a financial partner, but more of an oil and gas type partner that your preference would be that they've been in the area before, because what they can do is they can stamp approval on the 28,000 net acres that we have, and say, "I've been in and out of this area before, I like it, I like your program." We didn't, Mike, we didn't want to be locked in by a big prepayment upfront that would cause us to drill wells over the next 3 or 4 or 5 years if oil prices went south. So we wanted a win-win. We're, as you know, we want total flexibility. Our goal this year was to transition to oil from dry gas, and yet at the same time, keep our 7 Tcfe of upside, our resource upside in the Haynesville/Bossier. So what KKR did is they came in. They're very strong financially, they looked at all of our acreage and we came up with a program that said, "Well, we want to decide where the wells will be drilled." Like someone had asked the question earlier, have the 100 locations been agreed upon? No, because as we drill these wells, Comstock as the operator wants the right to say, "Here's where we want to drill the next 10, 20, 30 wells, whatever." And we want flexibility, and we'll drill some of these on PUD sites. We should have efficiencies and scale. We should have lower cost, because of the PUD sites. We should be able to drill more of the southeastern parts in some of these wells. So with the KKR deal, we said, well, like Roland said, we've got the 28,000 net acres. But if you net that, you net-net-net out acres that we think are not very profitable right now and you net out acres that we drilled on, we have 277 locations. We really have about 350 locations. Maybe we drill 350, but maybe we only drilled 20, 30, 100 or 277. So what we've done with KKR, we said, look, it has to be a win-win. We want to decide where to drill and how to complete. You can add some input, but that's not the intent. The intent is for us to be the operator and you'd be a passive working interest on it really. So they're going to pay for 26.7 acres. They're going to pay us $667,000, so a 100-well program out of the 28,000 net acres, what do they get? They get 2,167 acres and they pay $67 million for that. So what does that do for us? It gives us total flexibility. We're not obligated to drill a bunch of wells been that shouldn't be drilled. They provided capital for us to be more efficient so we can accelerate the Eagle Ford. And at the same time, what it does, it allows us to have capital to develop, which you just mentioned, the Wolfcamp or the Wolfbone properties in the Permian, which we think have 178 million barrels of upside. So this is a great program. It's a little different than being strapped in and tied up during good times and bad times for prices. We don't want to do that, and we chose not to do that. And I think this JV is a win-win for everybody, which is kind of unusual. Somebody's usually a big loser. This is not structured like that at all.

And Mike, I would add that the 100 wells is just the minimum that they have committed to definitely do, but the expectation is that they will participate in the full development of this field, and we will continue to earn the $25,000 per net acre all the way through every well drilled and that's the expectation. If Comstock wants to drill those wells, there's no reason why we wouldn't assume that they would want to continue to participate.

And Mike, that number is $230 million to maybe $250 million. I mean it's a big number.

Yes. The acreage number is, if it all gets developed, it's $233 million. The $67 million is just the part that there's a commitment there so we can plan for the next year or so. Really, probably 2 years, that 100 wells is probably something we'll develop in about 2 years, probably from that March 31 start date.

So it gives us efficiencies and flexibility in that Tier 1 oil play. It also gives us efficiencies and flexibility in the Permian. And quite frankly, 2 or 3 years from now, who knows if gas is $5, this JV structure gives you the flexibility to drill some gas wells instead of being locked in to drill oil wells. It may or may not be economic, depending upon the price.

Your 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 just quickly on the JV first. Can you break out the allocation of the roughly $58 million number you had in the CapEx disclosures around the JV? How is that going to be, I guess, allocated between, let's say, future drilling capital for KKR versus a carry on acreage?

Michael, we don't really have that exact number in front of us, but basically, that number represents, if you look at our budget we're going to incur, we think that's going to be the part that's attributable to them, either to purchase acreage or to pay for their share of drilling costs through December 31, so it's basically a way to come up with our exact budget. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Okay. I guess maybe I'll come at it -- one different angle is how much of that $58 million do you know is allocated to the kind of makeup payment for the second quarter?

For those wells, there are -- we did spud a -- since March 31, I think there is about 11 wells that have been drilled or even at least spudded by now in various states of being completed. So none of those wells were producing in the second quarter. Only 4 of those wells have IP results. I think the last 4 on our chart are the 4 that would be in the deal, which all came on production in July. So... Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: That's like 1/3 interest in 11 wells and you [ph] carry on 11 wells and then whatever the remainder is, is for the rest of the year?

Right, yes. And basically, all the wells are in the budget. And then the part that we think is going to get billed out, including those 11 wells, is that $58 million, plus any acreage costs attributable to any wells that actually gets spud this year. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Okay, that helps. And then I guess last one on the JV, is KKR at all limited in its ability to, let's say, assign this agreement to a sponsor entity, so another private company? Or do they have to keep this in house at KKR, like straight to KKR?

We probably don't want to comment on real details like that on the agreement.

Right. That won't impact us, so we rather not comment on that. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Fair enough. I guess switching to the Permian program, obviously, getting some increased confidence on the horizontal program given offset results. Can you talk to the other -- you mentioned the first horizontal spud in September maybe results by the third quarter call, what's the kind of timing, I guess, on the other 3 horizontal wells? I'm assuming are those just going to be really be 2013 impacts?

Michael, this is Mark. The second well is scheduled to spud August 4. We should have results and some impact from it later in the year. And then the other wells are in October through December. So they really won't impact production. We may get results by the end of the year conference call, probably be kind of what we'll be looking for there. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: Okay, but may tailwind into 2013. I guess the only last one on my end is, you spent or you talked to the 30% to 40% improvement in kind of initial rates. Would you expect or is there any reason not to expect the uptick in EUR on the verticals to be similar order of magnitude? Or how should we think about that?

Yes, Michael, I would not expect 30 -- and in fact, I went to do the calculation while I was sitting here and it was a 35% increase from the 18 producing wells when we took over in the last 8. So that's the increase in IP rate. I do not expect the EUR increase that much. I do expect maybe in the 20% range, but some of it is just that high initial rate flush production that you get out of this these fracs, and so I do expect a good increase, but not 35%.

Your next question comes from the line of Ron Mills with Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: A couple of questions. On the joint venture, is that only -- does that only cover the Eagle Ford to the extent you have 82% of your acreage do you think is in the Pearsall fairway? Does that include Pearsall rights or just Eagle Ford?

It includes any rights on that acreage, so the obligation, though, to drill -- the obligation to participate wells is for an Eagle Ford well, though, so they could -- if we drill the Pearsall well, they could choose to be in it, they could choose not to, because it's not something that's been evaluated. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And on the CapEx, your new CapEx budget of kind of in the $475 million versus the $313 million that you spent in the first half would imply plus or minus an $80 million run rate the second half of the year. How does that coincide with your plan to add a third rig in the Eagle Ford? I think Mark said in December. And as we look ahead to next year, if you enter with 4 rigs in the Permian and 3 in the Eagle Ford, is your quarterly run rate still looking -- do you think it will still be $80 million, $85 million, or do you think it would be something higher than that?

If you look at the budget, it does -- we do incorporate all these newest assumptions, adding the rigs when they're scheduled to come in the third rig. The third rig is not there for a long period of time this year. So next year, we'd be looking at a little larger Eagle Ford program in total, because it would be more indicative of a 3 -- I think this year's budget for the Eagle Ford is more or less a 2-rig program, and we've had periods where we had -- that we'll have 3. We've had a couple -- a month or so where we had 1, and so slightly over 2. For next year, we would see a little larger Eagle Ford program. Of course, the joint venture will cover 1/3 of that cost. The -- so I mean, next year, on the -- part of what's of course going to happen as you could tell is that some of the dollars we have reported in capital expenditures in the second quarter are actually going to be rebilled to the joint venture. So some of the costs in the first part of the year that are already been incurred, we're going to reimbursed for. And -- but if you do look at the net effect to us for the second half of the year, we will be in that -- that number's, like you said, running at an average rate of less than $100 million, that's $80 million to $100 million, taking all that into account. Next year's program, we would see -- we really haven't set that yet, so we're going to kind of see how the horizontals work in the Wolfbone and kind of see what the CapEx looks for that program. The Eagle Ford, we're kind of want to start out with a 3-rig program, and if we can afford it, we'd like to move that up to a 4-rig program. So a lot of it is still to be determined based on the outlook for oil prices. Are we able to lock in oil prices as we go forward for next year? We've got about half of that done as we can get high prices that really helps. And then, what are gas prices? Because we still produce a lot of gas, and a little bit of increase in gas prices adds a lot of cash flow. So there's a lot of variables, but we've got all the tools to balance that, and so we'll set the program's pace based on what cash flow is going to be. But the second half of the year, given the commodity price outlook that's out there right now, we should be very balanced in the second 6 months of this year. First 6 months of this year, we outspent our cash flow, but we did sell a lot of assets. And if you combine that, we really funded most of that overspend with proceeds from asset sales.

And a lot of that went to the Haynesville, remember, which we have 0 rigs running in the Haynesville.

Right. It's 2 different chapters, so I think it'll be a different looking program. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: The JV in the Eagle Ford covers the undeveloped acreage, what I mean by that is, any wells spud are only getting spud after March 31. So of your 28,000 acres, how much remains to be -- is remaining as undeveloped that they can earn that 1/3 interest in?

That's a good question. There are 31 producing wells that they will not have an interest in. And those 31 producing wells would have somewhere around 2,400 acres that are attributable to them. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. So it's off of your 28,000 net acres, it's really -- they have the right to participate in for 1/3 of 25.6?

Right. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: All right. And then 2 last short ones, on the production side, you -- your oil production remains unchanged from your prior guidance. Implicit in that, is there some kind of oil production guidance increase? Because I'm assuming your new guidance takes into account the 33% interest that KKR would participate in for the future wells? And if so, is that just driven by well performance in both the Eagle Ford and Permian?

Well, there's a combination of a lot of factors at play which gave us unchanged outlook for our oil production. Some of the wells that we were -- that originally were in our production forecast, they'll own 1/3 interest of that production. Some of those wells start producing in the third quarter and in the fourth quarter. But then we've also had, we're having really good performance in Wolfbone, so that's been a positive. And as far as picking it up in performance, longer-term performance of the Eagle Ford wells themselves. So that and a little bit of additional work by getting that, although it won't add a lot to production this year, but the timing of when we were able to drill some wells got -- we were able to move those up a little bit. And so all that combined got us very close to those same numbers. But the stage is set for probably better growth for next year, because we will have extra work done and so we start next year -- we would have a better oil price outlook than we might have otherwise if we just stayed with our current program. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Great. And then, Mark, the last one is for you. On the horizontal Wolfcamp, you talked about the initial cost. When you start looking at it from a program return standpoint, what do you think your horizontal wells in the Permian can cost? And what kind of EURs would you expect from the Wolfcamp, and at what point do you think you would think about either testing the Bone Spring or the Avalon, probably more the Bone Spring because it's more oily?

Well, Ron, that's a whole conference call by itself, all those questions. I would say cost-wise, we probably will move our cost in the Eagle Ford from initial time to the full development down at least $1 million with just development of your strategy plus the operational efficiencies of multi-pad drilling. So eventually, I would expect our cost in the Wolfbone to be similar in the $8 million to $8.5 million range once we get into full development mode. There is one Wolfcamp producer in the field and it's produced for 2 months, so I'm not going to venture and put out a number on EUR yet. I mean, we expect it to be significant, but we have to get out and prove that number. So really, I'm not going to go down that road. As far as Bone Spring, we think some of our acreage has good Bone Spring potential in the third Bone, and we do like the log characteristics of the upper very much, but there's just been very little testing so far, so we're too early to put any numbers on that.

Ron, we do like what we've seen and what the offset operators have shown us well enough to not only drill 1 or 2 or 3, but 4 this year. So that's a good indicator. We're out of whack, we like what we see, it should be good. So you can choose which one.

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

Just in the Wolfbone, can you just talk a little bit about kind of what you've learned from the work you've done in the vertical wells when it comes to how you're completing the horizontal wells and kind of what zones you're thinking about landing in and just kind of how confident are you out of the gate in terms of those completions?

Yes, this is Mark. Well, I'll answer the last one first, we're very confident. Based on our vertical results, we're very confident that we're going to get very encouraging results. We're targeting zones that produce the most oil based on our production log analysis of our vertical wells and also have the right log characteristics and the right lateral extent to be able to land a horizontal and drill 4,000 or 5,000 feet. So that's kind of how we're picking them, and we're really -- it will be different in each area of the field and we have multiple good targets in some of the fields. So we're going to do a little testing of different Wolfcamp benches, primarily kind of in the upper and middle Wolfcamp to start with. But we've got some lower Wolfcamp that looks very good. And then between us and that stuff that Concho is doing and Clayton Williams and other operators, I think a lot of data will be available to analyze over the next 6 to 12 months.

Okay, great, that's helpful. And then just lastly, in the Gaines County acreage, what's the game plan there? Any potential to monetize that acreage, or what's the outlook?

No, no potential right now unless whoever bought that deal from Noble the other day wants to come and give us the same thing for ours then we'll be happy to talk to them. Our goal would be to test it next year at some point. And evaluate it in and then go forward.

Remember, we had, say, $500 an acre in it, and we'd accumulated 20,000 gross, about 12,000 net acres. And we think it's very prospective but we didn't have it in our budget in 2012. So like Mark said, we'll budget to drill a well or 2 in probably 2013. And remember back to the Delaware Basin in Reeves County? The one reason that we like this when we looked at it in the fourth quarter of 2011 was, it was overpressured, and we've been in an overpressure basin in the Haynesville/Bossier. So when you look at that, we expected the wells to produce a little better than what had historically been the numbers. And so far we've been right on that. But it's attributable to the location where we are in the county.

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

Just turning to the balance sheet and looking at the ratios of debt to cap and long-term debt to EBITDA, for example, is there an internal goal or what might those ratios look like at, say, at the end of this year, at the end of next year, based on your own internal models and assumptions? And included in those assumptions -- are asset monetizations included in those assumptions?

Dan, this is Roland. I think a couple of things are happening, and of course, if you would tell us what the gas price will be, we can answer that question easily. But as the oil becomes a bigger percentage of the revenues, it's improving those ratios just, especially the coverage ratios, pretty dramatically as it takes over more of the production. Better gas prices make a dramatic difference, and we do plan to, of course, monetize the rest of our marketable securities, and so that's definitely in the works. And we'll evaluate monetizing maybe some other conventional assets, probably with a better natural gas kind of curve out there. But in the long run, those are definitely things that we plan to do, plan to work on the balance sheet. I think as gas prices improve from this very low level they're at now, we look dramatically different.

Dan, we do have 2, 3 areas that we could monetize properties in, Dan, but not at a $3, $3.20 gas price. We'd look at those. Our 3 big areas that are Tier 1 areas are the Haynesville/Bossier is one, and then the Eagle Ford is 2, and the Permian is 3, not in any particular order. But everything else would be "prospects" to be sold.

Got it. And what price deck are you assuming in your plan to be cash flow neutral in the back half of this year?

We just look at the current NYMEX prices, if they stay where they are. If they improve, that will be a plus.

And can you remind me what percentage of your leasehold in South Texas and now West Texas is held by production?

A large percentage in South Texas, because the Eagle Ford -- the drilling obligation to the Eagle Ford, we've done a lot of it this year.

Well, and we showed you that. We only have 1 rig drilling in Eagle Ford right now. So like Roland said, I don't know what percent of it is, but majority of it is.

Yes. There's a -- it's a very complicated answer because there are different leases with some continuous drilling, but it's not a -- it's an area that we have a lot of latitude, not to invest less in next year for just lease retention. Our biggest lease retention issues are in the West Texas area where they have a lot of leases still to earn. That's why we're still drilling a lot of vertical wells, because it's the most efficient way to earn those leases.

Okay, got it. And then one last one if I may, you speak to spacing units of 80 acres in the JV press release. Is that considered optimal? What's the plan to test down-spacing here, maybe over the balance of this year and certainly in 2013?

Dan, this is Mark. Well, the 80 acres for us is a 500-foot between well spacing. We really look at it more as between wells than acreage, although that's what it averages out is 80 acres. But we believe that the optimal distance is -- based on the micro seismic we've done, all the work that we've seen published from all the other operators, we think that 500 feet is pretty optimal at this point. We have 2 wells that we're frac-ing soon that will test that spacing pattern and 2 additional wells planned a little bit later in the year to -- as further test of that spacing pattern. But we're really moving forward with that development plan at this time. And then obviously, we will test an increased density on top of that once we get that data. But it just doesn't do any good to test an increased density when you don't now know these are going to act.

Your next question comes from the line of John Selser with Iberia Capital Partners.

I apologize if you've already touched on this. But the horizontal locations in Reeves County, you've identified the first 2, and there's been some pretty good activity overall in the Eastern part, would that be where the -- you say the third well would go?

It's Mark. We're working on several potential locations and there's a lot of land work that we're doing and analysis, so I really don't want to say where the other 2 are going to be at this time. But we like, we do like that East area, I'll say that.

And this concludes the Q&A session for today's call. I would now like to turn the call back over to Mr. Jay Allison for any closing remarks.

All right, again, thank you for participating in the conference call. We've worked really hard to put together a win-win JV to create wealth on the shareholder base. We want flexibility. Again, we've tried to demonstrate that we are transitioning to oil from dry gas, and at the same time, not giving up any of our 7 Tcfe of resource potential in the Haynesville/Bossier. I think that the agreement that we've structured is unusual. It may take a day or 2 to digest it, because it's not a cookie-cutter model, which I think it's a better model. It's a custom model for what we need, because it does give us flexibility, as Mark mentioned, to be more efficient in the Eagle Ford. And at the same time, I mean, if the Eagle Ford is good as we all think it is, I mean we'll receive anywhere from $67 million to $230 million and promote with KKR the right way, because it will be based upon successful wells that we drilled. It also gives us flexibility on the Permian, probably 1/2 of the questions were asked about the Permian. And we do -- well you can feel our excitement about the horizontal wells that we'll be drilling in the Permian. And at the same time, we don't want to give up the strength we have in our natural gas field. That's probably the single most prolific dry gas field in North America is the Haynesville. So we don't want to get rid of that. We want to keep it inventoried. At some point in time, natural gas will come back. And then we had several questions asked about financial flexibility. We have $230 million undrawn on our bank line. The one reason that we went with a kind of a KKR is that we didn't really want to sell existing production, and we didn't want to sell our reserves that were predeveloped producing which would cause another redetermination of our borrowing base. We didn't see why we should do that. We presented to the world that we want to keep our oil production and grow it, which we have, and we want to add to the Eagle Ford drilling program, which we did. And we want to do that with the proper flexibility, which, hopefully, you see that we've demonstrated. So we'll continue to honor what we said we'd do and create wealth on a per share basis. And again, thank you for participating in the conference call.

Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may now disconnect. Have a great day.