Comstock Resources, Inc. (CRK) Q1 2012 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the First Quarter 2012 Comstock Resources, Inc. Earnings Conference Call. My name is Regina, and I will be your conference operator for today. [Operator Instructions] Today's event is being recorded for replay purposes. I would now like to turn the conference over to your host for today, Mr. Jay Allison, President and Chief Executive Officer. Please go ahead, Mr. Allison.

Thank you, Regina. I want to welcome everybody to the conference call. And I really kind of want to give you a preview and tell you that the 30 slides that we all worked on in detail, that they really are in great detail in order to give you a detailed breakdown of our Eagle Ford play, as well as the Permian play, that we're actively drilling now for oil, and to show you why we expect oil to grow by 200% over last year. That's the intent of the 30 slides that we're going to go over in detail. Welcome to the Comstock Resources First 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 First Quarter 2012 Results. I am Jay Allison, President of Comstock. And with me this morning is Roland Burns, our Chief Financial Officer; and Mark Williams, our VP of Operations. During this call, we will review our 2012 first quarter financial and operating results, as well as update the results of our 2012 drilling program. Please refer to Slide 2 in our presentations and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. Please refer to Page 3 of the presentation, where we summarize our first quarter results. Our growing oil side of the company is helping offset the negative impact that the very weak natural gas prices are having on our financial results. We reported revenues of $110 million, generated EBITDAX of $79 million and had operating cash flow of $67 million or $1.39 per share. Gains from our divestitures allowed us to make a profit this quarter of $6.9 million or $0.14 per share. This quarter had strong production growth as compared to the first quarter of 2011. More importantly, our oil production is growing. It's expected to increase 200% from our oil production last year. Our 2012 drilling program is off to a very good start, especially in our newly acquired Wolfbone field in West Texas. Mark will report that some of our recent vertical wells are some of the best reported in the play to date. We drilled 22 successful wells, including 15 successful oil wells in our Eagle Ford and Wolfbone programs in the first quarter. We continue to work on improving our balance sheet, which we used to give us an excellent inventory of oil projects to allow us to transition away from where we were a year ago, when 96% of our production was natural gas. I'll now turn it over to Roland Burns to review the financial results for this quarter in more detail. Roland?

Thanks, Jay. Starting with this presentation, we're going to talk about our oil and gas production separately, as the 50:1 relationship of gas prices to oil prices make an equivalent unit presentation, that we're so used to, meaningless to understanding the financial results, given the current situation we're in. So on Slide 4, we show our crude oil production on a daily basis for the last 3 years by quarter, including the first quarter of this year. And you can see this year is the first year we're really going to start showing growth in our oil production. Our production this quarter grew by 267% to 5,600 barrels per day as compared to the first quarter of last year when we produced only 1,500 barrels per day. Our Eagle Ford properties in South Texas, shown in light blue on this chart, increased to 4,100 barrels per day and will be the main driver of our oil growth this year. We had 1,000 barrels per day in the Eagle Ford this quarter as compared to the 3,100 barrels a day, we averaged in the fourth quarter. Our Wolfbone properties in West Texas contributed 800 barrels a day to the averagely -- average quarterly rate, and we expect that production for this area will grow substantially with the success we're now seeing with our recent Wolfbone wells. The West Texas production was a little light this quarter, due to transition issues we had to deal with, which were left over from the previous operator. Looking ahead to the remainder of this year, with all of our drilling activity focused on oil, we are forecasting our oil production to grow 190% to 210% over last year's production to a total of 2.4 million to 2.6 million barrels. This forecast is slightly higher than our previous outlook and is driven by the results we're seeing in our Eagle Ford wells, which have had lower declines than what we've originally expected. Slide 5 shows our natural gas production on a daily basis. Natural gas production grew by 17% over the first quarter last year to 246 million cubic feet per day, but was about 9 million per day less than the fourth quarter rate of 255 million per day. Production from our Haynesville and Bossier wells, which are shown in light blue on this chart, accounts for 71% of our total gas production. We completed many of the wells that we carried over from last year in the first quarter, but these wells were put on line fairly late in the quarter. We've also decided to restrict the production from the 10-well pad that came on in March to less than 5 million per well due to the very low prices that we're experiencing for our natural gas production. And then we've also had some minor delays in some pipeline hookups for some of the wells, so they'll come on later in the second quarter. The remaining 29% of our gas production was fairly comparable to the production rates we saw in the fourth quarter. Production from our Cotton Valley wells, which we show here in dark blue, remained at about 31 billion per day. And our South Texas gas production, which we show in red on this chart, also stayed the same, about 23 million per day, as the associated gas from the Eagle Ford program is offsetting declines from our mature South Texas gas properties. Other gas production, which is shown in purple, increased to 8 million per day as compared to the 7 million per day we had in the fourth quarter, and that's just in addition of the West Texas gas. We are divesting of 9 million per day of our gas production, which includes the conventional properties in both our South Texas and North Louisiana regions, and we're breaking that production out separately in green on this chart. After taking into account this divestiture, we expect our natural gas production to be flat to slightly down for the next couple of quarters, and then to show some more decline by the fourth quarter due to the lack of investment that we're making in the Haynesville. As a result, we've lowered our forecast for natural production -- natural gas production this year from an increase about 1% to 5% over the 2011 total gas production to a slight decrease of 2% to 6% from 2011's production rates. Oil prices continue to be very strong and provided us some relief from the very low natural gas prices. On Slide 6, we show that our realized average oil price increased 13% in the first quarter of 2012 to $102.93 per barrel as compared to $89.94 per barrel in the first quarter of 2011. 71% of our oil production was hedged in the quarter at a NYMEX-WTI price of $99.17. So if you exclude the losses from the hedges, that we actually realized $104.02 per barrel in the quarter, which is about -- which averaged about 101% of the average benchmark NYMEX-WTI price. Our Eagle Ford oil production is currently realizing a $9 premium to NYMEX, WTI. This premium was much less in January and February, and then we see it continue to be very volatile. On Slide 7, we outline our hedge position. We have 5,000 barrels a day hedged at $99.53 for the rest of this year, and then we presently have 3,000 barrels hedged at $100.33 for 2013. So we plan to continue to add to these positions as this year progresses. Slide 8 shows our average natural gas price, which decreased 34% in the first quarter to $2.63 per Mcf as compared to $3.96 in the first quarter of 2011. Our realized gas price was 96% of the average NYMEX Henry Hub gas price for the quarter. On Slide 9, we cover our oil and gas sales. Our 28% production growth and, more importantly, the 267% growth in oil production more than offset the 34% decline that we had at natural gas prices this quarter. As a result, our sales increased by 25% to $110 million in the first quarter as compared to $88 million in 2011's first quarter. Oil properties now make up 47% of our total sales as compared to only 14% in the first quarter of last year. Our earnings before interest, taxes, depreciation, amortization and exploration expense and other non-cash expenses, or EBITDAX, increased by 21% this quarter to $79 million from $65 million in 2011's first quarter, and this is shown on Slide 10. Slide 11 covers our operating cash flow. Our operating cash flow for the quarter came in at $67 million and grew 19% over cash flow of $56 million in 2011's first quarter. Slide 12. We outline our earnings. We reported net income of $6.9 million or $0.14 per share as compared to earnings of $2.4 million or $0.05 per share in 2011 first quarter. The first quarter financial results in both periods include several unusual items. We had significant gains from the sale of our marketable securities in both quarters. The first quarter of 2012 we had a gain of $26.6 million or $17.3 million after tax, which equates to $0.37 per share, and we also had -- and then in 2011 first quarter we had a gain on sale of marketable securities of $21.2 million, $13.8 million after tax or $0.30 per share. We also reported a gain in 2012 of $6.7 million, $4.4 million after tax or $0.09 per share on part of the oil and gas properties that we're divesting of this year. Part of the divestiture closed in February, and we expect to have an additional pretax gain of approximately $25 million in the second quarter from the balance of the property sale. The proceeds of $9.5 million from the February closing are reflected as restricted cash on our balance sheet, as they're part of a life-kind exchange that's allowing us to defer an almost $85 million tax gain that results from the oil and gas property divestitures we're making this year. This will be released as -- after we close on the balance of the divestitures, which we expect to happen today. Other unusual items in the numbers include impairments of $1.3 million or $0.9 million after tax or $0.02 per share taken this quarter on some of our leases, and then we had a similar impairment of $9.5 million or $6.1 million after tax or $0.13 per share in 2011's first quarter. The first quarter 2011 results also included a charge of $1.1 million or $0.7 million after tax or $0.02 per share, relating to the early redemption of our 2012 senior notes, which we redeemed 1 year early. Excluding these items, we would have reported a net loss of $0.30 per share this quarter and $0.10 per share in 2011's first quarter. On Slide 13 we show our lifting cost per Mcfe produced by quarter, and our lifting cost are broken out to -- into 3 components: production taxes, transportation and other field lever operating costs. Our total lifting cost increased to $1.03 per Mcfe in the first quarter of 2012 as compared to $0.90 per Mcfe in the first quarter of 2011 and then at the very low $0.77 per Mcfe we realized in the fourth quarter of 2011. The increase is mainly due to the higher cost of oil production versus the low-cost gas production in the Haynesville. The higher lifting costs are really a small price to pay for the significant revenue growth that the oil properties are providing for us. Production taxes this quarter were $0.14, and our transportation cost averaged $0.31 in this quarter. Field operating cost averaged $0.58 per Mcfe this quarter, and that was about same rate as we had in the first quarter 2011. On Slide 14,, we show our cash G&A per Mcfe produced by quarter, excluding stock-based compensation. Our general and administrative cost decreased to $0.21 per Mcfe in the first quarter of 2012 as compared to $0.26 per Mcfe in the first quarter of 2011. The rate was slightly higher than the $0.20 per Mcfe we had in the fourth quarter of last year. Our depreciation, depletion and amortization per Mcfe produced is shown on Slide 15. Our DD&A rate in the first quarter averaged $3.24 per Mcfe as compared to the $3.03 rate we had in the first quarter of 2011 and the $3.07 we averaged in the fourth quarter. The higher cost of the oil production and then the pressure on our natural gas reserves from the very low natural gas prices are driving this increase. On Slide 16, we detail our capital expenditures. We spent $178 million in the first quarter as compared to $158 million we spent on 2011's first quarter. We spent $72 million in our East Texas-North Louisiana region, $68 million in our South Texas region and then $38 million in our new West Texas region. With the activity in the Haynesville wrapping up for the most part in March, we do expect our CapEx level to be significantly lower in the upcoming quarters. And now looking on Slide 17, you can see that we still expect to spend $458 million in our drilling activity this year, despite that -- the high level of spending that you saw in the first quarter. Mostly, we're pretty much on track to maintain the same drilling budget that we presented earlier. This budget is based on the 6 operated rigs that we're currently running, 2 are in the Eagle Ford and then 4 are in the Delaware Basin in West Texas. Slide 18 recaps our balance sheet at the end of the first quarter, and then we also have a pro forma presentation, just taking into account of the property divestitures that we're completing today. At the end of the first quarter, we had $4 million in cash. We had a $9.5 million in restricted cash that I mentioned earlier, and then $17 million in marketable securities on hand. We have a total of $1.2 billion of total debt, which is comprised of about $600 million of our public borrowings and about $610 million outstanding under our bank's credit facility. Today, we're completing the property divestitures that we outlined back when we first told our stockholders about the new Wolfbone purchase. We estimate that we will receive net proceeds from these sales of $123 million after the normal purchase price adjustments and then selling cost, and that includes also the restricted cash that we'll all have available here with the expiration of the exchange trust. With the sales, the banks have adjusted our borrowing base down to $655 million to reflect the production that we're selling. On a pro forma basis, our bank debt would fall off to $487 million, applying the proceeds here to the -- our bank debt. Then our debt-to-total book capitalization, which is at 54% in the first quarter, would improve at a pro forma basis to 51%. Referring to Slide 19, we want to point out that we will continue to maintain a conservative financial profile this year, given the acquisition debt that we took on, and then the weak natural gas prices that we're experiencing. We have completed the asset sales or will complete them today, and we targeted a net generating proceeds of $123 million. We sold all but 600,000 of our stake in Stone Energy, which provided $38 million to help fund our drilling program this year, and then we'll continue to monetize that investment based on opportunities we have this year. We've also implemented a hedging strategy to protect us from declines in oil prices in the next 2 years, and we'll target to hedge 70% of our expected oil production. As I -- and as we showed recently, we'll maintain flexibility for what we spend on this year's drilling program. But with natural gas prices continuing to weaken in the first part of this year, we're not completely satisfied with the liquidity that we have, even after completing most of the divestitures that we targeted at the top end of our expectations. We will look to enhance liquidity and targeting to enhance it by another $100 million to $150 million this year, but we're not looking to do anything that will be dilutive to our existing stakeholders. The 2 things that we're considering to increase our liquidity are to term out some of the bank debt in the bond market, which would -- which could increase the availability we have under the credit facility. And then we're also looking at potentially bringing in a joint venture partner into one of our oil drilling programs. We're now in a position of having a very large inventory of high-return oil projects and we don't have the operating cash flow to develop in the timeframe that we think would maximize value for these projects. So we think either of these alternatives will be very additive to the overall value of the company in the long run. Mark would now give you an update on our operations and our drilling results.

Thanks, Roland. On Slide 20, we recap our activity in our East Texas-North Louisiana region for the first quarter. We drilled 7 wells or 3.4 net wells in this region, including 5 or 3 net Haynesville-Bossier horizontal wells and 2 or 0.4 net Cotton Valley wells. All of these wells were successful. The 2 Cotton Valley wells were nonoperated wells located in one of the properties that we are divesting today. We moved our 2 operated drilling rigs out of this region during the first quarter, so any remaining wells drilled this year will be nonoperated. We completed 10 gross and 10 net of our operated Haynesville or Bossier shale wells in the first quarter, and we have 5 wells waiting to be completed. Much of the new production came online in March, and we have -- and we limited the production of these wells in response to low gas prices. With minimal lease expirations occurring this year, we've been able to move much of our drilling budget to profitable oil projects without jeopardizing our 82,000 net acre position in the Haynesville. We will be able to exploit our 7.3 Tcfe of Haynesville and Bossier resource potential in the future when gas -- when improved gas prices provide economics competitive with our oil projects. Slide 21 shows our West Texas region and the 90,000 gross and 56,000 net acres that we have in that region. This consists of 13,000 net acres in Gaines County and 43,000 net acres in Reeves County. Our activity this year will be focused on Reeves County and the properties we acquired from Eagle Oil & Gas at the end of the year. With budget dollars this year being in high demand, we will wait until next year to test some of the ideas we have for our Gaines County acreage. The Reeves County acreage provides us over 900 vertical locations targeting the Wolfbone section, which has 178 million BOE of resource potential. We have a proven successful vertical program on our acreage, but we think there is significant upside with horizontal development in the Avalon, Bone Spring's and Wolfcamp formations on our Reeves County acreage. Slide 22 shows our Reeves County acreage and the activity we had in the first quarter. Since we closed on the acquisition, we have drilled 8 vertical wells, 5.7 net vertical wells, all of them were successful. We have completed 7 operated Wolfbone vertical wells since we closed the acquisition on December 29. These wells, which we see on the map, were drilled to a total depths of 11,477 to 12,170 feet, and they were completed with 5 to 9 frac stages. The 7 wells had an average per well initial production rate of 347 BOE per day, and 80% of that was oil, not rich gas or superrich gas but oil. Our first 3 wells, the Paladin, the City of Pecos and the Monroe, averaged 262 BOE per day. After that, we changed our completion approach and had improved results with the last 4 wells, the Dale Evans, the Jessie James, the Lone Ranger and the Pistola, which averaged 410 BOE per day. The Jessie James well, which had an initial production rate of 539 BOE per day is one of the top vertical wells in the Wolfbone play. As you can see, the Pistola is the weakest of the group at 193 BOE per day, but it's located at the very southern edge of our acreage. We think this area will be prospective for horizontal development, so we want to maintain our acreage position in this area. We also participated in the completion of 3 nonoperated Wolfbone wells, just east of the Jessie James, which averaged 322 BOE per day. One other thing to note on this map is that the different colored dots outside of our acreage represent recent horizontal permits by the various offset operators, including Clayton Williams, Concho, BHP, Cimarex and others. And we'll talk just a bit about the horizontal in a little bit. Slide 23 shows 25 operated wells in our Wolfbone field, including the 7 we completed in the first quarter. The 25 wells had an average per well initial production rate of 297 BOE per day. The 30-day rate for those 25 wells was 233 BOE per day, which was 89% of the initial rate. Over a longer period of 90 days, the rates averaged 75% of the initial rate. We will continue to monitor results and adjust our completion approach to improve our results. But we are very encouraged that some of the most recent wells have had impressive IP rates and are so far well above our average Wolfbone type curve. Slide 24 shows you the location of the 25 producing wells that are listed on the previous slide. Slide 25 shows what we plan to drill for the remainder of 2012. Our drilling program is targeted at holding leases, so we can't just focus on drilling around where we are getting the best results. We have 3 wells currently drilling, shown as the red stars on the map, and we are in process of moving the fourth rig to a new location. We are currently competing 4 wells, which are shown as the red triangles on the map. The red dots show the locations that are currently in our drill schedule for 2012. We are planning to spud our first horizontal Wolfcamp well in June, and we're currently evaluating several potential wells in our drill schedule to convert from vertical to horizontal. If the horizontal results are encouraging, and we expect them to be, we will be poised to convert additional vertical wells to horizontal going forward. Slide 26, which we've shown you all before, shows where we think our program is heading to with horizontal development. This slide shows the various potential oil targets in our -- on our Reeves County acreage. Also shown are the potential completion types that we anticipate will be prospective on our acreage. On the left is our 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 Bone Spring, which includes the Avalon. 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 one horizontal well scheduled this year, and as illustrated on Slide 22, other operators in the area are actively pursuing horizontal opportunities in the Bone Spring and Wolfcamp, in our same area. The horizontal aspect of this play is just emerging, so there's much science to be applied before it can be verified, but we are very excited to have such a prime position in this very hot basin. On Slide 27, we cover our South Texas operations, where all the activity is in our oil-focused Eagle Ford Shale play. We have 35,000 gross acres and 28,000 net acres in the oil window of the Eagle Ford Shale. Based on a detailed study of our acreage, we believe we have 260 horizontal locations, including the wells we have already drilled, that will yield 80 million BOE equivalent -- of BOE, of which over 80% is oil. We have excluded 5,500 of our northern acreage from the resource potential estimate, as it is not economic at the current price. The average gross EUR is 500,000 barrels of oil equivalent for the 5 separate type curves that we use in this program to evaluate our acreage. Slides 28 and 29 show the results and the locations of the 27 wells that are currently producing on our Eagle Ford acreage. We completed 8 more Eagle Ford Shale wells since our last update. They are shown at the bottom of the list. Starting with the short well. The 8 wells had an average per well initial production rate of 498 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 our primary term lease obligations. All of these wells are being produced under the company's restricted choke program. Longer-term production results from the first 19 Eagle Ford Shale wells have confirmed the benefits of this program. Our first 19 wells, which have been producing for more than 90 days, have an average initial production rate of 782 BOE per day. The 30-day per well production rate for these wells averaged 584 BOE per day, and the 90-day production rate averaged 514 BOE per day or 68% of the initial rate. The restricted choke program also extends the time before artificial lift is needed. If you compare our results to similar data published by some of the other operators in the Eagle Ford and public data that's available, I think you'll find that our extended time results are very strong. Later this year, we plan to begin development drilling, which will allow for cost efficiencies associated with multi-pad -- multi-well pad development. As I said before, Slide 29 shows the location of the 27 producing wells that were listed on the previous slide. As you can see, we have now tested all of our acreage. Now I'll turn it back over to Jay.

Thank you, Mark, and thank you, Roland. If everybody go to the final page, Page 30. I mean, despite the dismal outlook for natural gas prices after a very warm winter, I mean, we are excited about the prospects for Comstock this year, and we expect the strong growth in our oil production 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 2012. And we expect oil to comprise 15% to 18% of our 2012 production and over 20% production at the end of this year. 92% of the net wells we'll drill in 2012 will be oil wells, and 77% of our budget will be spent on oil projects. Even though overall production this year may only grow by 5%, this year, after divestitures, we expect oil to grow by 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 profitable vertical drilling program, we see tremendous upside in future horizontal development in the emerging Wolfcamp shale. We continue to have one of the lowest overall cost structures in the industry. We plan on maintaining a conservative financial profile to improve our liquidity post the Permian acquisition. We are reducing leverage this year with the asset divestitures that, as of today, will be completed, and we will utilize an oil price hedging strategy to protect the acquisition and our oil-focused drilling program. As Roland have stated earlier, we're committed to further improving our liquidity to allow us to weather the natural gas price storm that we're all caught up in. For the rest of the call, we will take questions only from the research analysts who follow the stock. Regina, I'll turn it over to you.

[Operator Instructions] And gentlemen, your first question today comes from the line of Brian Corales with Howard Weil.

Can you talk about -- obviously, you changed the completion on the Wolfbone wells. Can you tell what you did a little bit differently? And then also, I noticed that it's mostly Wolfcamp and not a lot of completions in the Bone Spring's. Could you add additional completions there?

Brian, this is Mark. First, on our completion approach, our first 2 wells, it's a very thick section. There's a lot of complexity of the lithology, the different formations within this section from the third Bone Spring's down to the Wolfcamp. So our first 2 completions, we took the approach that we were just going to space our perforations out somewhat evenly and expect the frac jobs to grow up and down and contact all the reservoir rock. And the results weren't as we liked. So we've changed our approach to really target the rock that gives up the best oil, and we did that by running some fairly advanced logs and did a lot of log analysis and we tied that to production logs that Eagle had run and determine where the oil is coming from and why it's coming from there, and then we adjusted our completion approach, our perforating strategy, mainly to that data. We've also enlarged our frac job on one of the wells, and that appears to be giving us better result also. So it's going to be a combination going forward of changing our frac strategy and our perforating strategy. On the other question about the Wolfbone, typically, in here, and we've done it and other operators are doing it, too, the initial completion is the third Bone Spring down through the Wolfcamp, because that's more of a geo-pressured section. It has higher reservoir pressure. And then later you can come in and recomplete into the upper Bone Spring, the first and second Bone Spring, and the Avalon, and several operators have done some of those with pretty good result. There are still some more complexity there, some things to learn. But yet on all of our acreage, the upper Bone Spring is prospective.

Okay, that's helpful. And then getting to -- Roland, I think you talked a little bit about the JV or potential JV in the Eagle Ford. Can you just -- I don't know, just the thought process between terming out debt versus JV being part of the Eagle Ford, and how much? Are you looking for a certain amount of capital? What do you -- what's the thoughts there?

Brian, this is Roland. We look at wanting to improve liquidity a little more as opposed to really slashing the CapEx some more, just because we're having so much success in adding the oil in the 2 programs. So I think the terming out some of the bank debt makes a lot of sense to add just to liquidity. It doesn't really reduce leverage. But I think the other thing we looked at is that as the -- with the success that Mark's having with the Wolfbone and then when he goes horizontal, we're going to have quite a bit of demand for drilling dollars just this year, next year and in the future. And then the 2 programs, since we have such a large interest, especially in the Eagle Ford, that it might make sense to sell a small part of that to a partner. We'd still want to operate. It'd still be very large program for us and to use that to help just bring in some equity-type dollars to actually delever the company. So that's why we've looked at that as an option, and I think both of them are great options. We could do a combination of both or one of the other, but it's something that we'll look to do relatively soon. We've been working on it quite a bit. That's why I want to just bring it up in the conference call and say that we don't have details for either one. But it's not that we spent a lot of time this first 4 months working on -- especially watching the other natural gas prices erode.

Well, Brian, I think my comment is the stockholders are used to a delevered company, but they're also used to a $4 or $5 gas price. So once you have a $1.92 gas price, even though the 12-month strip is almost $3, I mean, we had to either probably lose a lot of our borrowing base because the bank new price deck or we had to go and morph into an oil-based company and inventory our natural gas, which Mark said we've got 7.3 Tcfe of upside, we think, in our Haynesville/Bossier, which we'd spend maybe $15 million, $20 million on from here on out till we decide to drill there again. So we did have a core area in the Eagle Ford, and it was good. We have 211 or so locations. But we felt like, internally, we had to have another Tier 1 oil basin, which was a Permian, and this turned out to be probably better than we thought it would in the timeframe that we've owned it. So if you look at the most mature area that we could probably find a very compatible JV partner, it is in the Eagle Ford. So we would reduce our position little bit. And with the JV partner, we would probably accelerate some of that drilling based upon a carry, and I think that would be a win-win for everybody. And we would delever the company, which -- management is used to a company that's a little less levered than we are today. So of I hope that answers your question.

Yes, that was good. And just maybe a follow on to that. I mean, you all mentioned relatively soon. So I mean, should we be looking at the next month, 2 months, 3 months for kind of you ought to make a decision and to move forward? Is that kind of the thought?

The one thing, Brian, you assumed we are not is reckless. I mean, you -- we did take risks, but we don't ever want to be reckless. And when we announced that we would buy the Eagle Oil & Gas properties in the Permian basin, we said that, one, we would have an aggressive hedging program, which we have at about 2.8 million barrels hedged. Second thing we said that we thought that we could monetize anywhere from $100 million to $130 million of our existing properties, which that number, as Roland said earlier, has $128 million. And we want to have our borrowing base redetermined more sooner than later. We did that, really, February. We put that press release out March 6. And then Roland reported that our new bank case with the sale that we should close today, it gave you that number. So even back in November, December, one of the things internally that we thought about was having a potential partner in the Eagle Ford. So we have been working on that. All of January, all of February, all of March and through today, May 1. So that is well underway. So when that happens or if it happens, I don't know. It could happen in the next month. It may be a quarter. We're not going to do something that would diminish the value that we have on a per-share basis. But we are telling you that we're not comfortable with the liquidity that we have, even though that we think our cash flow from operations this year will go ahead and cover our drilling budget, and we reinforced that $458 million of CapEx. We still think that we need to have some liquidity. Nobody's forcing that on us. It's just, I think, something that management and the board would like, and I think the stockholders would like that. So we're pursuing that now.

[Operator Instructions] Your next question is from the line of Kim Pacanovsky with MLV. Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division: Can you just walk us through some of the assumptions that you've made in your 178 million barrel estimate for the Permian?

Yes. Kim, this is Mark. Our -- it was based on our net vertical wells. And I believe a 200 -- basically, a 200,000 BOE type curve. Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division: Okay. And is that 200,000 BOE just the Wolfcamp and the third Bone Spring, or is there the secondary section of Bone Spring in that?

That is -- Kim, that is a -- that is the third Bone through the Wolfcamp. The section that's been completed so far, all the historical data we used to build our type curve. Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division: Okay. So there's a lot of upside to that number then?

We believe there is, both on -- in the upper section and in the horizontal development. We believe there's significant upside to that number. Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division: Okay, terrific. And just -- if you could just give me the old number that you had for percent oil growth? You were at 190% to 210% now, and what was the old number?

As far as the percent or growth? Kim M. Pacanovsky - McNicoll, Lewis & Vlak LLC, Research Division: Yes, you said you increased your percent growth year-over-year to 190% to 210%.

It's actually 200% before. And I think that we're -- depending on the results, if a lot of that wells in the Wolfbone can be like Jessie James, then we can raise our numbers. So we’re really encouraged, but it's only a few wells. So I think that there's some upside to our oil forecast. We just aren't ready to stretch it out too much.

And I think the market, Kim, should hold us accountable for spudding a well and -- in a premier part of the Permian in June. I mean, Mark is working at least on that one, and you need to have another one right behind that. So we're going to start that program in June. If that turns out really well and we hit a really nice oil, which we -- hopefully, we expect that, then some of those numbers might change, too, to the positive.

And the next question is from the line of John Selser with Iberia Capital.

You touched on this already, but I was hoping you might expand on it a little bit. If you were to term out some of your bank debt, would you create some spare capacity in your bank line? I mean, I guess the question is that, as you term it out, that it won't be a dollar-per-dollar reduction in the borrowing base. Will it?

No, John, this is Roland. That's correct. Our facility, basically, would have -- it's about a $0.25 reduction for every $1 of new subordinated debt that we would put on. So that's a kind of a built-in feature. So it would create quite a bit of availability if we do that. Now it is not going to -- we recognize that doesn't reduce the overall leverage of the company because it's still debt, and it would have a higher cost than our bank debt.

Right. And just one more real quick on the -- if you x the Haynesville spending out of the first quarter, it still looks like you're about $100 million on a run rate. If you proceed like that through the next 3 quarters, and then your closer to $500 million, if my LSU math is correct. How -- why do you feel still that you're going to be smaller in the $458 million range?

John, this is Mark. We have a couple of rigs in our schedule. We have less rigs in a couple of months, I think in 2 or 3 of the months later in the year, which reduces the capital in those months. So it's not just a flat capital program from here out. I think our third quarter is going to be less than our second and our fourth, if I recall. It's -- we're staying at 2 rigs, on average, in Eagle Ford, but we have some rigs that are expiring and some that are coming. And the timing of them just doesn't match up perfectly, so it kind of goes 2 rigs, 3 rigs, 1 rig, 2 rigs is the kind of how it looks.

And I think the other thing, John, to point out is that the first quarter had a lot of completion activity, from both the Haynesville, which -- but also even in the Eagle Ford, because we were using the same crew. So there was a lot of wells that were built up in the Eagle Ford that we did a lot of completion work in March, and you saw those wells on our charts that came on in March and April. So there's -- it has an unusual amount of completion activity as the backlog in both plays, it was pretty much cleaned out in the first quarter. So that's -- and that's -- with the Eagle Ford and the Haynesville, completion cost on wells is the huge dollar item, and it gets incurred very quickly because they do the work in a week.

And you also have some motion with the final settlement of Eagle Oil & Gas in the first quarter numbers, because remember, there were 800 leases we had to get our hands around.

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

Just continue to drill down into the cost side. Can you give us what your current Wolfbone costs are? Have those gone up at all with the new completion technique? And what are your current Eagle Ford costs right now?

Leo, this is Mark. Using the same frac size that we started with, we're still -- we're right at $4.5 million. In fact, a couple of our wells look like they're going to be a little bit less than that, maybe in the $4.1 million, $4.2 million range. The new frac design that we had pumped on one of the wells, the Lone Ranger's 192 well, that does add some costs. So that pushes us up in the -- into the upper 4s, probably between $4.8 million and $5 million. But we're still tweaking that job size and some of the other things, and we're also still improving our drilling process. So we think we'll be able to work that back down into the $4 million or $5 million range. On the Eagle Ford, our kind of our goal -- our expectation before was to be at around $8.5 million. And then once we went to pad drilling, it would push that number down to maybe $8 million. But our last 5 wells have averaged about $8 million, and our last 10 wells have averaged somewhere around $8.1 million. And we're not doing much pad drilling yet. So I think we're seeing some of the improvement in both our drilling curves, our completion efficiency and in some of the pressure on service costs, just across-the-board in South Texas, to help that. And when we get into full development mode, based on these numbers, we could be in the low to mid-7s.

Okay. And I guess in the Eagle Ford, you talked about, early this year, having to drill some areas to the north, where the results kind of weren't as good as historically. When do you expect to transition further to the south on your acreage position? Is that happening now, or is that second half of the year?

It's probably second half of the year. We got both rigs running, I think, in our -- in kind of that same area, our Hubbard lease, which is near the Carlson, and then we'll move back down. We'll drill some wells on the Hill lease and the Gloria Wheeler lease, which is in the southern area. So it really starts, probably, June or so. But I guess we have a difference of opinion. I think the results are still very good in that middle section. It fits our type curves. The EURs are not much lower than in the south. The IP rates are little lower, but we still are very pleased with the results in that middle section of our acreage.

Yes. Leo, that's one reason we gave that very, very detailed chart on the Eagle Ford. We're always asked what's your 30-, 60-, 90-day rates and what's your decline rates. So you couldn't get any more detail than that chart. In the same way, in the Permian, we gave you a detailed chart there.

Your next question comes from the line of Michael Hall with Robert W. Baird. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: First for me, up in West Texas. You've kind of alluded to some transmission issues you were looking through. I was wondering if you could add a little color around that and just give us some -- the outlook for just kind of midstream environment as you see it and the -- how you progress.

Yes. Michael, this is Mark. We didn't -- other than just taking an extra week or 2 to get a gas line laid, we don't have any transmission or transportation issues in West Texas. We did when we took over the field. There were lot of wells that were still on primary production and hadn't been converted to artificial lift yet. As is typical with an operator who is in the sell process, they -- when they know they're going to sell, they quit spending capital and doing things, and it just takes you a little while to kind of catch up. And so really, it's been more just the mechanical aspect of the field the first 3 or 4 months.

Yes. I think the comment was transition issues not transmission.

There you go. Michael A. Hall - Robert W. Baird & Co. Incorporated, Research Division: My apologies. I guess for my follow-up then, just kind of in the Eagle Ford. Looking at the completions in the first quarter, it looks like -- or I should say in 2012, it looks like only a couple went off and actually produced during the first quarter, yet you had a nice big bump in oil volumes, first quarter versus fourth quarter '11. Any read-through on the type curve? I mean, how are you holding up relative to expectations on your type curve? And I guess how is that looking versus what you thought?

We -- this is Mark. We've adjusted our type curve a little bit upward a couple of times since we started this program, and we still are very comfortable with our results that we're at or above the type curves on average. We're trying to be somewhat conservative with our bookings and our projections because we don't want to undershoot, so yes, very comfortable with that. Part of that, you're talking about the first quarter production being strong, we had several wells completed in December. I think we had 4 completed in December of last year. So most of that production really hit the first quarter.

Your next question comes from the line of Ron Mills with Johnson Rice. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Just one follow-up on, I think, John Selser's question earlier. Relative to your CapEx budget, is it fair to assume in terms of carryover cap -- or completions, you ended up spending somewhere in kind of that $85 million to $90 million range, which is -- which then is how you kind of push yourselves down closer to the $9 million run rate over the rest of the year? Is that the right way to look at your CapEx?

Yes. Ron, this is Roland. Yes, that's -- a lot of that work get -- did get done in the first quarter, lot of the Eagle Ford carryover and the Haynesville, and so that's definitely a big part of it. That's a big component of that. But like Mark said, there's a few -- there's a couple of months later on in the year we aren't running as many rigs. I think that was a -- just going to the pad development is -- it can be -- it can really -- as we were doing that in the Haynesville, that can really kind of cost the CapEx to get -- really get concentrated in a particular month. And we kind of actually start to do that in late, in the second half of 2012 in the Eagle Ford, as we're going to -- things start to go to a little bit of pad development, We'll actually not be completing some of those wells until we can get them all drilled. So I think that's probably why the fourth quarter CapEx maybe one of lightest quarters of the year, because you're -- some of that's going to be pushed into 2013. So it's just timing. We have a detailed budget based on the rigs, the cost of the rigs. Then the timing of completions is really critical to how it fits in a quarter or a year. It's because -- not so much maybe on the Wolfbone. But when you're talking about the Haynesville and the Eagle Ford, the completion cost, as I said, it's a very big, large part of the budget, and it happens in a very quick period of time when you have to do the work.

Yes, we could have 5 or 6 or more Eagle Ford rigs drilled and being completed at December '12 going into '13, and that's what Roland was talking about. So what we're trying to do is adjust it to have more production in December versus pushing it out into January, February. So we'd beat Mark up on that all the time. But that's your timing issue, Ron, with the CapEx. That's why it gets a little light in the fourth quarter. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay. And, Mark, can you -- I think you mentioned that you're now excluding about 5,500 acres from the northern part of your position. Is that 5,500 net acres or gross acres in terms of your resource potential? And is that what drove your EURs in the Eagle Ford from the 400,000-barrel range to the 500,000-barrel range as you high grade, or you just give a little bit more color behind that comment?

Ron, you're correct that it's -- it was 5,500 net acres, and it's right up in the -- in and around our Jupe well, which just isn't economic right now at these prices. Although we -- if we get our cost driven down into that $7 million to $7.5 million range, we'll reevaluate that and we might be able to pull that acreage back into the mix. So yes, it -- when you take that acreage out, your average recovery per remaining well goes up. That's part of the reason we went from 400,000 to 500,000, and part of it is an adjustment of the type curves because of the performance we've seen. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: And you -- but that allows then to remain at that plus or minus 100-acre spacing?

That is correct. Yes, we do feel there's additional potential on a tighter well spacing also, but we just haven't gotten out and proving that yet, so we don't want to add those numbers. Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division: Okay, great. And, Roland, just on the LOE. It was up. You -- and talked about it being related to oil production. As your oil continues to grow as a percentage of your overall production stream, I've been modeling continued unit cost growth in both LOE and production taxes. Is that the right way to look at it, or any outlook in terms of range of potential cost increases as your oil production increases?

Ron, definitely, the production taxes -- a lot of the gas production at Haynesville has an exempt rate. So as -- it really distorts the production tax rate that we had last year. We had such a very low rate because of the big growth in the Haynesville production. Of course, now no oil production has any exempt rate. And so as oil becomes a bigger percent, the actual average production tax percent of sales, we see that increasing from the 3.3% level to, depends on how fast oil grows, but to getting closer to 4%, kind of average to 4.5% maybe, before it really gets to big share of the revenue. So that's definitely one component that's pretty predictable, and it can be kind of calculated. On gathering costs, part of our lifting, is very much tied to the gas production. So it's very variable, and you'll see it just track whatever the gas production is because that's where we transport the gas a fairly -- a long distance in order to realize the strong gas prices, the net that we get in the Haynesville. Within the fixed lifting cost, we -- of course, we added the new properties as part of our fixed lifting costs in the first quarter, the oil properties. Yes, they're just generally cost more to produce in general -- especially when they got artificial lift. So yes, the trend would be that we really can't realize $0.77 per Mcfe if we want to convert our revenue stream to oil. It's just impossible. So we see that the cost we had this quarter is probably a good proxy for where it'll be the next couple of quarters and then maybe increase it a little bit more as the production tax rates are higher

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

These 90-day rates in the Eagle Ford wells are definite positive, very strong. I was hoping you could give me your decline assumptions between month 1 and month 13?

Mike, this is Mark. I think our -- yes, type curves vary a little bit, but I think the decline is about 70% on average. So your -- that's your 1 year decline from day 1 to day 366 is about 70% on the type curves.

Okay. I mean, these 90-day rates, it seems like you're outperforming that to-date. Is that a fair assumption?

We think we are a little bit. We're just not ready to adjust our type curves and our modeling yet.

Okay. And we've seen some pretty attractive JVs done in the Eagle Ford and some asset sales there. And now with a 500,000-barrel EUR pegged to your acreage here, do you think you could garner up to 20,000 maybe, 30,000 an acre type price for any sale or JV done there?

I think our goal is to whoever the JV partner might be, I mean, is to not trick them into doing a good or bad deal, but to show him what we've done and that we've derisked this acreage and come up with something for the deal. Now we'll see what the going JV agreements are, and then based upon what we've done and our acreage -- and again, a great thing about Comstock, I mean, the wells we'll drill this year, which is 24 gross well, there's 22 net. So we have almost 100% ownership of each of these wells. So even though we may sell down a little bit, I think we're in the best possible position to, one, add a little liquidity here and maybe even accelerate the Eagle Ford and get a very nice partner with a fair price for both of us.

Gentlemen, your final question tonight comes from the line of Jack Aydin with KeyBanc.

Most of the questions were answered, but is there anything different -- you did anything different in Jessie James well than the other wells that you got such good results?

Well, that's the outlaw name. We're going to name them all outlaw names.

Well, Jack, this is Mark. We got almost as good a result in the Dale Evans and the Lone Ranger, and I really think the Lone Ranger may end up being the best of those 3. We did a bigger frac job on it, a lot more fluid. It's a little slower to clean up, but it looks really strong. I just didn't have a 30-day rate to give you yet, but it looks very good. But I think on all 3 of those, we used the same completion approach of trying to pick the right places to put the perforations. And that's still a learning process. It's a very complex section. And my first impression was you just go in there and kind of shotgun approach, perf and frac and you'll be fine, but it didn't work that way. And so we're still learning. I think we'll get better as we go. So this is kind of our first run at applying the new science to the completions.

My follow-up question, on the Eagle Ford, you're using 100-acre spacing. The industry using 65-acre spacing. Now when do you think you might decide to go to the 65-acre spacing?

Jack, we're working on that right now. This is Mark. And we're -- we are -- the 2 Hill wells we're going to drill later are, I think, 65-acre spacing wells. We're going to drill those and test them and make sure that we're satisfied with the results. And then we adjust our spacing a little bit, depending on whether we're drilling due north/south or we're drilling more perpendicular to the frac direction. And so our spacing does vary a little bit. Ultimately, it's going to be a little smaller than 100, but we're just using 100 right now to be conservative.

Ladies and gentlemen, this does conclude the question-and-answer portion of our event. Gentlemen, would you like to make some closing remarks?

Yes, Regina. Again, those that are still on the call, it's been 1 hour and 20 minutes. We started out that we acknowledge that we are in a dismal natural gas market. But let me tell you what our goal was, we hope that the detailed slides and our comments gave great transparency to everyone, as we're -- we currently are, as a company, in transition and, really, we're trying to go the remainder of the year. We've told you we're not deluding anybody with equity issuances. We would like to raise little more liquidity, maybe to the bond market or partnering one of our oil plays. But we're trying to be totally transparent because you, as a stockholder, trust that we'll implement what we tell you to do. And if we can't, then we'll tell you why on a 90-day basis. So again, thanks for enduring 1 hour and 24 minute call. We do appreciate it. Thank you.

Ladies and gentlemen, thank you so much for your participation today. This does conclude the presentation, and you may now disconnect. Have a great day.