Comstock Resources Inc (CRK) 2012 Q4 法說會逐字稿

Good day, ladies and gentlemen and welcome to the fourth quarter 2012 Comstock Resources Inc. earnings conference call. My name is Erica and I'll be your operator for today. At this time, all participants are in a listen-only mode. We will conduct a question-and-answer session towards the end of this conference.

(Operator Instructions)

As a reminder, this conference is being recorded for replay purposes. I would now like to turn the call over to Jay Allison, President and CEO. Please proceed.

Thank you, Erica and everyone, welcome to the Comstock Resources fourth quarter and annual 2012 financial and operating results conference call.

You can view a slide presentation during or after this call by going to our website at www.comstockresources.com, and clicking Presentations. There you will find a presentation entitled Fourth Quarter 2012 Results. I'm Jay Allison, President of Comstock, and with me this morning are Roland Burns, our Chief Financial Officer, and Mark Williams, our Chief Operating Officer. During this call, we will discuss our 2012 operating and financial results.

Please refer to slide 2 in our presentation and note that our discussions today will be including forward-looking statements within the meaning of securities laws. While we believe the expectations of such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. I know that there are probably 34 slides in the presentation. I'd like to give you an overview right now from our perspective as far as the years 2012 and 2013. I know Roland and Mark will hit on some of the highlights and details in a moment, but to give you an overall view. Slide 3 summarizes the highlights of 2012.

2012 as well as 2013 are transition years for Comstock, as we are changing the Company from a 98% natural gas Company to one with a more balance between oil and natural gas. We started 2012 with a partially proven Eagle Ford oil play and added the Permian properties in Reeves County as a new oil basin for us.

In 2012, we saw natural gas prices decrease 36% from 2011 and our gas production dropped 9%. But then in 2012, we saw our oil production grow 175% with the Eagle Ford becoming our main oil growth engine as we derisked our acreage and brought in KKR as a JV partner. In 2013, the Eagle Ford will continue to be our largest oil growth engine with a three-rig dedicated program to focus drilling on the better portions of our Eagle Ford acreage.

In 2012, in West Texas, we drilled 46 gross vertical wells that have enabled us to derisk portions of our 42,000 net acres. We drilled our third horizontal well, the Gaucho State 15 #1H targeting the Wolfcamp A interval. The Gaucho has been fracture-stimulated now with a 6,837-foot lateral in 18 stages and is expected to start flowing back later this afternoon. Comstock owns 100% working interest in the Gaucho well. This well will allow us to begin to evaluate the Wolfcamp A horizontal play which offset operators have been very successful in developing. Mark Williams will go into more detail about this well and the offsetting wells later in this conference call.

Concerning our 80,000 net acres in the Haynesville/Bossier play in East Texas and North Louisiana where we have 6 Tcf of upside, we have allocated $32 million in 2013 to drill 3.6 net wells versus the $107 million we spent in 2012. So in 2013, 94% of the net well drilled will be oil wells and 92% of our budget will be spent on oil projects.

I also need to point out that a key component to Comstock in 2013 is to delever our balance sheet by bringing in a partner in our Permian drilling program later this year. We think a good partner will create a win-win situation in the Permian and allow us to delever our balance sheet and enable the Permian to be developed on a more consistent scale incorporating both vertical and horizontal well programs.

I will now turn it over to Roland and Mark to cover our financial and drilling results. Roland?

Thanks, Jay.

The first item I wanted to cover is the announcement we made yesterday to restate our financial results for the first three quarters of 2012. So if you refer to slide 4, while our oil hedging program has been a big economic success in 2012, we were required to change our accounting from hedge accounting to mark-to-market accounting. The net impact is that we have to include unrealized gain or loss related to the value of the oil hedge position in our income statement instead of just in equity. As a result, we are recognizing an unrealized loss of $10.2 million in the first quarter and an unrealized gain of $34.8 million in the second quarter and an unrealized loss of $1.1 million in the third quarter.

For the nine-month period, this accounting change has us reducing our loss after income taxes to $21.9 million, as compared to the $29.4 million loss we previously reported. Even though the hedges were effective throughout all of 2012, our underlying documentation that designate the contracts as hedges were not completed in a timely manner. The technical requirements to use hedge accounting are unforgiving and we failed to live up to them. We do want to apologize to our stockholders for any confusion this restatement has created.

On slide 5, we show our oil production on a daily basis by quarter. Our oil production in 2012 grew by 175%. In the fourth quarter, oil production fell to 6,100 barrels per day as compared to the third quarter, where we produced 7,200 barrels per day. The decrease is mostly due to the activity in our Eagle Ford Shale properties in South Texas, which is shown in light blue on this chart, which averaged 4,300 barrels per day as compared to the 5,000 barrels per day we had in the third quarter.

There were several factors that contributed to the disappointing production rate in the quarter. A smaller number of net wells came online in the fourth quarter and we had substantial shut-in time for offset frac activity. This was compounded by additional shut-ins for artificial lift installations. Our January and February production continues to be hampered by some of these issues, but we anticipate having a very strong March as we will returned all the wells to production, plus have an additional 5.2 net wells coming on production in late February and March in the Eagle Ford.

Our Wolfbone properties in West Texas averaged 1,600 barrels per day in the fourth quarter, down from the 1,900 barrels a day we had in the third. Limited completions in the quarter and artificial lift issues hampered production from this area in the quarter. Despite the slow start, we do expect our oil production to grow this year by approximately 40% to 60% over last year's production to total 3.2 million to 3.7 million barrels.

Slide 6 shows our natural gas production on a daily basis. Our natural gas production declined by 9% in 2012 due to the 9 million a day of production we sold with our May property divestiture and the declines that we're experiencing from our Haynesville properties. In the fourth quarter, we averaged 195 million cubic feet per day, as compared to the 220 million cubic feet per day that we had in the third quarter.

Production from our Haynesville and Bossier wells in the quarter declined to 142 million per day and the remaining gas production that the Company has only showed modest declines in the quarter. Production from our Cotton Valley wells, which is shown in dark blue on the chart, averaged 25 million per day and our South Texas gas production, shown in red, was 20 million per day. Other gas from our other regions, shown in purple, increased in the quarter to 8 million per day. We expect our natural gas production to decline further this year to approximately 59 Bcf to 62 -- 64 Bcf, a decrease of 22% to 28% from our 2012 total production.

On slide 7, we show that our average realized oil price in the fourth quarter of 2012 decreased to $92.46 per barrel as compared to the $100.18 per barrel in the fourth quarter of 2011. Our realized wellhead oil price in the quarter averaged 106% of the average NYMEX WTI price of $87.60, due to the premiums that we were receiving for our Eagle Ford Shale oil. 80% of our oil production was hedged in the quarter at a NYMEX WTI price of $99.53. So including our gains from the hedges, we realized $101.56 per barrel in the quarter, which was 1% higher than our realized oil prices in the fourth quarter of 2011.

Slide 8 shows our oil prices for all of 2012. Our realized oil price increased 1% in 2012 to $96.95 per barrel as compared to the $95.73 per barrel in 2011 and it averaged 103% of the average benchmarked NYMEX WTI price. 74% of our oil production was hedged in 2012 at a NYMEX price of $99.45. So including the gains from our hedges, we realized $101.18 per barrel in 2012, which was 6% higher than our realized prices in 2011.

On slide 9, we outlined our hedge position. We have an attractive oil hedge position which protects our 2013 drilling program. We have 6,000 barrels of oil production hedged at $98.67 for all of 2013.

Slide 10 covers our natural gas prices. Our average gas price of $3.05 decreased 10% this quarter as compared to $3.40 price we realized in the fourth quarter of 2011. Our realized gas price was 90% of the average NYMEX Henry Hub gas price for the quarter. Our average gas price for all of 2012 decreased 36% to $2.52 per Mcf as compared to the $3.91 we averaged in 2011. Our realized gas price was also 90% of the average NYMEX Henry Hub gas price for all of 2012.

On slide 11, we cover our oil and gas sales, including realized gains or losses from the hedges. Our total sales decreased by 2% to $112 million in the fourth quarter of 2012 as compared to the $114 million we had in 2011's fourth quarter. Oil made up 51% of our total sales in the fourth quarter as compared to only 31% in the fourth quarter of last year. In 2012, sales increased 2% to $442 million as compared to the $434 million of sales in 2011. Oil also accounted for 51% of total sales for all of 2012 as compared to only 18% of our total revenues in 2011.

Our earnings before interest, taxes, depreciation, amortization and exploration expense, and other non-cash expenses, or EBITDAX, decreased by 9% to $82 million from $90 million in 2011's fourth quarter as shown on slide 12. EBITDAX for all of 2012 has decreased 4% to $321 million from 2011's $336 million.

Slide 13 covers our operating cash flow. Our operating cash flow for the quarter came in at $65 million, which was 18% lower than cash flow of $79 million in 2011's fourth quarter. Operating cash flow for 2012 was $261 million, a 12% decrease from 2011's operating cash flow of $298 million.

On slide 14, we outline our earnings. We reported a net loss of $78 million this quarter, or $1.68 per share, as compared to a net loss of $41 million, or $0.89 per share, in 2011's fourth quarter. For the full year, we reported a net loss of $100 million, or $2.16 per share, compared to a net loss of $33 million, or $0.73 per share, for 2011.

The financial results in both 2011 and 2012 include several unusual items. In the fourth quarter, the reported net loss includes impairments on natural gas unevaluated leases, and producing properties of $78.6 million, or $51.1 million after tax, or $1.10 per share. We also had a $2 million unrealized loss from derivatives, $1.3 million after tax, or $0.03 per share.

The 2012 annual net loss includes impairments of $86.7 million, or $56.3 million after tax, or $1.21 per share; a gain of $26.6 million, $17.3 million after tax, or $0.37 per share, on the sales of our Stone Energy shares; and a gain of $24.3 million, $15.8 million after tax, or $0.34 per share, from our property sales; and also $11.5 million unrealized gain from derivatives, which was $7.5 million after tax, or $0.16 per share. Excluding these items, we would have reported a net loss of $0.55 per share this quarter and $1.82 per share for 2012.

On slide 15, we show our lifting costs per Mcfe produced by quarter. Lifting costs for us are broken down into three components, production taxes, transportation, and other field level operating costs. Our total lifting costs were $1.19 per Mcfe produced in the fourth quarter of 2012 as compared to the $0.77 rate that we had in the fourth quarter of 2011. Our production taxes were $0.15 per Mcfe, transportation averaged $0.27 in the fourth quarter and our field operating cost averaged $0.77 per Mcfe this quarter, which was higher than the $0.39 rate that we had in the fourth quarter of 2011 and the $0.64 rate we had in the third quarter of 2012. The lower production in the quarter and the more expensive to lift oil production account for the higher rate.

On slide 16, we show our cash G&A per Mcfe produced by quarter excluding stock-based compensation. Our general and administrative costs were $0.20 per Mcfe in the fourth quarter 2012, which was the same rate that we had in the fourth quarter of 2011, and the same rate that we had in the third quarter of 2012.

Our depreciation depletion and amortization per Mcfe produced is shown on slide 17. Our DD&A rate in the fourth quarter of 2012 averaged $4.55 per Mcfe as compared to our $3.07 rate in the fourth quarter of 2011, and the $4.10 rate we averaged in the third quarter. The low natural gas prices drove up our DD&A rate in 2012 due to the exclusion of most of our undeveloped natural gas projects from our proved reserves. Also, the higher finding costs of the oil projects is also driving this increase.

We have a slide on our proved reserves and finding costs for 2012 on page 18 of the presentation. Our proved reserves at the end of 2012 were estimated at 712 Bcfe compared to the 1.3 Tcfe that we had at the end of 2011. Our reserves are 67% natural gas and 33% oil, as compared to being only 15% oil at the end of 2011. We operate 90% of our proved reserves, which went from being 46% developed at the end of 2011 to 62% developed at the end of 2012.

Our successful drilling program in the Eagle Ford Shale in South Texas added 11.9 million barrels of oil, and 7.5 Bcf of associated gas, or 13.2 million barrels of oil equivalent to our proved reserves in 2012. The West Texas drilling program contributed 5.4 million barrels of oil and 9.5 Bcf of associated gas, or 6.9 million barrels of oil equivalent to proved reserves in 2012. The activity in the Haynesville Shale mainly in the first quarter of the year and our other regions added another 14 Bcf of proved natural gas reserves to our reserves at the end of 2012.

The very low SEC price that we had to use to estimate our proved reserves caused a large downward revision of 534 Bcf as our undrilled natural gas projects are not economic at the $2.84 per Mcf price that we had to use.

In 2012, we spent $490 million on exploration of development activities and we spent another $35 million to acquire leases. The finding costs for 2012 excluding the exploratory acreage costs and the downward natural gas revisions calculates at a $21.79 per BOE.

Slide 19 recaps our balance sheet at the end of 2012. On December 31, we had $4 million in cash and $12 million in marketable securities on hand. We also had $1.3 billion of total debt comprised of $884 million of our senior notes and $440 million outstanding under our bank credit facility. Our current borrowing base is $570 million under the credit facility, leaving us $130 million in unused availability.

Slide 20 breaks out our 2013 drilling budget. In 2012, we spent $490 million on our drilling activities and this year we expect to spend $420 million. Our new budget has us drilling 85 wells this year, 10 gas wells and 75 oil wells. $219 million will be spent on our Eagle Ford Shale program to drill 27.3 net wells, And $169 million will be spent on our Wolfbone properties to drill eight Wolfcamp horizontals and 25 Wolfbone vertical wells. We've also budgeted $32 million for any required drilling to hold our acreage in the Haynesville Shale, and we plan to spend another $25 million to acquire acreage in 2013.

I'll now turn it over to Mark to review our results from our drilling program.

Thank you, Roland, and Happy Fat Tuesday to everyone.

On slide 21, we recap our activity in our East Texas and North Louisiana region. In the first quarter, we drilled three operated Haynesville wells, 2.5 net, before moving our two operated drilling rigs out of this region. We participated in another four non-operated wells, 0.7 net. We completed all of our operated Haynesville wells this year and we still have two, or 0.1 net, of the non-operated wells Haynesville wells waiting to be completed. We will be able to exploit our 6 Tcfe of Haynesville and Bossier resource potential in the future when improved gas prices provide economics competitive with our oil projects.

Slide 22, we cover our South Texas operations for all of our activity has been in our oil-focused Eagle Ford Shale play. We still have 35,000 gross acres and 28,000 net acres in the oil window of the Eagle Ford Shale. Based on 80-acre spacing, we believe we have 277 horizontal locations including the wells we have already drilled. We have excluded some of our northern acreage and any acreage that we think is undrillable from this estimate. We estimate that our properties have 78 million barrels of oil equivalent potential. This year we drilled 30 wells, 20.5 net to our interest and the wells we drilled had an average initial production rate of 675 barrels of oil equivalent per day.

Slide 23 and 24 show the results and locations of the 47 wells which are currently producing. We completed six more Eagle Ford Shale wells since our last update. They are wells 42 to 47 on the list. The 47 Eagle Ford Shale wells that were completed had an average per well initial production rate of 702 BOE per day. These wells are being produced under the Company's restricted choke program and the initial tests were obtained with a 14/64 inch to 16/64 inch choke. The 30-day per well production rate for these wells averaged 542 BOE per day and the 90-day per well production rate averaged 461 BOE per day, or 66% of the initial 24-hour test rate.

The six new Eagle Ford wells reported on this quarter averaged 682 BOE per day, with the Gloria Wheeler A number 2H, the Gloria Wheeler B number 2H, and the Cutter Creek A number 1H, all in McMullen County, having the highest initial production rates at 987 BOE, 872 BOE, and 765 BOE per day, respectively. At the end of the year, we had another six, or 3.8 net Eagle Ford wells waiting on completion. Slide 24 shows the location of the 47 producing Eagle Ford wells.

On slide 25, we show how the costs of our Eagle Ford wells have come down considerably since we started drilling in August of 2010. The costs on this slide have been adjusted to standardize the lateral length up to 5,800 feet to make them comparable. The costs are based on actual costs for wells that we have completed and AFE cost for future wells. You can see that in the beginning these wells cost over $12 million, which included a lot of learning curve and science applied, and the costs have improved to just under $8 million recently. Faster drilling times and lower well stimulation costs account for much of this savings.

Slide 26 shows the net Eagle Ford wells being put on production per month in 2012 and what is projected for 2013. Note the wide variation in net completions per month which ranges from zero all the way up to six net completions per month. This variation is due to multi-well pad drilling and subsequent multi-well stimulation operations. The large variation will result in a lot of lumpiness in our resulting Eagle Ford production curve in 2013. Production in the fourth quarter of 2012 was affected by the low number of completions in that quarter, and Q1 of 2013 will also be adversely affected.

Slide 27 shows the location of our planned 42 Eagle Ford wells in 2013. You can see the high concentration of planned wells in McMullen County where we have achieved the best results. On this map, there are 40 dots, it's for those of you that actually count, and there are two wells located in our DVR area to the East, and it made the map too small to read so we left that area off. But you'll also note that 38 of the 42 wells are in our high-quality McMullen area acreage.

Slide 28 shows our West Texas region and the 89,000 gross and 54,000 net acres that we have there. Our activity this year has been focused on Reeves County and the properties we acquired from Eagle Oil & Gas at the end of 2011. The Reeves County acreage provides us over 900 vertical locations targeting the Wolfbone with 178 million BOE of resource potential.

We have a proven and successful vertical program on our acreage but we think there is significant upside with horizontal development in the Avalon, the Bone Spring and the Wolfcamp formations on our Reeves County acreage. Recently, other operators in the area have had strong results from horizontal Bone Spring and Wolfcamp wells around our acreage.

Slide 29 shows our Reeves County acreage and highlights the latest eight Wolfbone wells we reported on today. In 2012, we drilled 48 wells, or 30.5 net wells. All of these were successful. Of the wells drilled in 2012, we completed 29, or 26.3 net operated wells in 2012. These wells had an average per well initial production rate of 356 barrels of oil equivalent per day. We also participated in 16 non-operated Wolfbone vertical wells, which had an average initial production rate of 369 barrels equivalent per day.

The vertical wells were drilled at total depths of 11,250 feet to 12,786 feet and were completed with 5 to 11 frac stages. We had three wells, or 1.0 net wells, awaiting completion at year end. Since our last update, we completed eight additional wells in our Wolfbone field which had an average initial production rate of 319 BOE per day. Our second horizontal well, the Dale Evans 196 number 2H, targeting the Middle Wolfcamp interval, was disappointing with an initial rate of 212 BOE per day.

Slide 30 shows the 49 operated wells in our Wolfbone Field, including the 8 we completed in the fourth quarter. The 49 wells had an average per well initial production rate of 322 BOE per day. The 30-day rate for the 48 wells that have produced for that long averaged 79% of their initial rate. Over a longer period of 90 days, the rates have averaged 61% of the initial rate.

Slide 21 shows you the location of these 49 wells on our acreage. As you can see, we have fully tested our acreage with vertical wells and feel we have derisked the vertical program.

Slide 32 shows Comstock's horizontal activity in Reeves County, along with horizontal activity by offset operators. Concho's horizontal wells, targeting the Wolfcamp A interval, have been very successful with the first two reporting 30-day IP rates as reported to the Railroad Commission of 758 BOE per day and 952 BOE per day. And those were the Rawhide and the Cowboy wells.

Comstock's first horizontal well, the Monroe 35 #1H, targeting the Wolfcamp B interval, was moderately successful with a 24-hour IP rate of 653 BOE per day. We still have the Wolfcamp A and third Bone Spring to complete at a later date in this wellbore. Comstock's second horizontal well, the Dale Evans 196 number 2H, targeting the Middle Wolfcamp Interval, was disappointing, with a 24-hour IP rate of 212 BOE per day. We still have the Wolfcamp B, the Wolfcamp A and the third Bone Spring to complete in this wellbore at a later date.

Comstock's third horizontal well, the Gaucho State 15 #1H, targeting the Wolfcamp A interval, has been fracture-stimulated with a 6,837-foot lateral and 18 frac stages. You'll note that targeted the Wolfcamp A, which is the same interval as the successful Concho wells offsetting it. The frac plugs have been drilled have been removed in this well and we are preparing to start flow back later today. The lateral length of the Gaucho is significantly longer than previous Comstock and Concho wells which ran -- they ran 3,500 to 4,000 feet, or a little over 4,000 feet and the Gaucho well is 6,837 feet.

Comstock's fourth horizontal well is the Balmorhea 32-15 #1H which will also target the Wolfcamp A interval with a planned lateral of over 7,000 feet. The vertical portion of this well is currently being drilled. Now just to note, we own 100% of the Gaucho well, as well as 100% of the Dale Evans well.

Slide 33 shows the primary oil targets on our acreage in Reeves County. Also shown are the potential completion types that we anticipate will be prospective. On the far right is a conventional vertical Wolfbone well, showing the primary 1,500 feet of completion interval from the Third Bone Spring through the Middle Wolfcamp or Lower Wolfcamp. In addition to that, we believe there are several horizontal targets in the Bone Spring and Wolfcamp shales that may significantly improve the economics of the play.

Other operators in the area are actively pursuing horizontal opportunities in the Bone Spring and various benches in the Wolfcamp. Our Gaucho well is testing the Wolfcamp A which has seen the most success by other operators in Reeves County. Our Monroe tested the Wolfcamp B, which has been moderately successful, and as I said before, the Dale Evans, which was not successful, tested the Middle Wolfcamp Shale. The horizontal aspect of this play is still emerging, so there is much science to be applied before it can be verified. But we are very excited to have such a prime position in this basin.

Now I'll turn it over to Jay.

Thank you, Mark, and again, Roland, earlier.

If you look at the very last slide, the 2013 outlook, we are excited about the prospects for Comstock this year because we are able now to inventory our Haynesville gas region. We'll spend our money this year developing our two tier one oil basins, the Eagle Ford and the Permian, as Mark just reviewed. We expect the strong growth in our oil production will be more than offset the low natural gas prices to allow us to have higher revenues and cash flow and be a much more profitable Company in 2013. We expect oil to comprise more than 25% of our 2013 production.

94% of the net wells that we will drill in 2013 will be oil wells, and 92% of our budget will be spent on oil projects. Even though overall production this year is expected to decline, we do expect oil to grow by 40% to 60% over last year, which will grow our revenues and grow our cash flow. Our Eagle Ford Shale program will be, again, our largest growth engine for this year. We also see tremendous upside in future horizontal development in the emerging Wolfcamp Shale based on recent activities in Reeves County and hopefully, our own Gaucho well.

We'll continue to have one of the lowest overall cost structures in the industry, and we have adequate liquidity for our 2013 drilling plans. We expect operating cash flow to fund most of our planned drilling program and that the availability under our bank credit facility will increase with our oil reserve growth.

We'll continue utilizing an oil price hedging strategy to protect our oil-focused drilling program. As I stated earlier, a key component to Comstock in 2013 is to delever our balance sheet by bringing in a partner in our Permian drilling program later this year. We think a good partner will create a win-win situation in the Permian and allow us to delever our balance sheet and enable the Permian to be developed on a more consistent scale, incorporating both the vertical and the horizontal well programs that Mark just described.

So, for the rest of the call, we'll take questions only from research analysts who follow the stock. Erica? Turn it back to you.

(Operator Instructions)

Leo Mariani, RBC.

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

This is Roland, Leo. On the question about looking for partner in the Permian, it's something that we do want to -- we're going to start after we get the results from the two Wolfcamp A horizontal wells. So it's something that we'd like to have identified a potential partner by the end of the second quarter. So that's our goal. It will be a similar process to the Eagle Ford. As far as the actual structure, we're really open to how that will be structured.

I think we would -- since we want to use it more to delever the balance sheet, it would probably have to be structured differently. It would be more up-front funds. We have a lot invested in the Wolfbone properties. So I would see the structure in the Eagle Ford, which works right there, might not be ideal for this one if we're going to use it to delever the balance sheet.

Okay. That makes a lot of sense. Another question for you guys, in terms of the Gaucho well, it sounds like you guys are going to know results on that pretty soon. Do we expect to -- are you guys going to expect to release those prior to first quarter earnings? Could we see an interim update with some results there?

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

Leo, my comments to follow-up with Roland, I think we have too much debt. We do have to delever our balance sheet. We intentionally levered up the Company in order to add the two oil basins. We did bring in a perfect JV partner in the Eagle Ford. And of course, in Eagle Ford, we didn't pay $332 million to enter the Eagle Ford. We base leased our acreage and then drilled it. I think we acted differently in the Permian and now the Permian, we've had really good results vertically.

I expect to have really good results horizontally with the Gaucho and the Balmorhea, which is a Wolfcamp A, which is our first horizontal Wolfcamp A. So I think with that, we will open the data room, as Roland said, but this JV will be structured differently than the Eagle Ford because we need to delever our balance sheet. And then I think as far as the press release on the Gaucho, we're listening to all the stockholders and we'll act accordingly. So I hope that helps.

That's very helpful. Just lastly, could you address well costs on these horizontals you're doing in the Wolfcamp and also what you're seeing in the vertical Wolfbone well costs?

Yes. Mark will do that.

Yes, more on the -- as well costs on the horizontal Wolfcamp were -- our cost is about $10 million right now. We still have some science involved and we drilled a 50% longer lateral, or almost 50% longer on this one and a significantly larger frac job, so while our service costs have come down, we've eaten that up with the additional lateral length and the additional fracing on this well. As far as vertical Wolfbone, our cost is coming down. I don't have real hard numbers but I think our goal is to be around $4 million. We are working toward that goal. I wouldn't say we're there yet but we're getting much closer.

And then in the Eagle Ford, you saw the curve, we're down around $8 million or a little bit less. We used $8.2 million in our budget because we have a lot of longer lateral's in that -- longer than the 5,800 feet. So that -- we standardized that cost to be able to compare apples to apples across the field. But if you drill 7,000-foot lateral's, the wells are going to cost a little bit more so that's where we're at on that. We've seen the significant stimulation cost reductions in the Eagle Ford which has helped us come down on those costs.

Amir Arif, Stifel Nicolaus.

Just a question on the -- about the Permian. The key question really is, can you just talk about the partnership that you're thinking about the Permian and how that ties into your oil production growth guidance that you've laid out? If you bring in a partner, would you accelerate activity to keep you net oil volume growth at 40% to 60%, or is this going to be more just straight balance sheet reduction?

Well, Amir, the -- our production growth goals this year are based on not bringing in a partner. So that's the program that's budgeted for. I think as a goal, this Company to delever, I think that bringing in a partner into the Permian would -- the big benefit is we would have more activity there, and hopefully spend less dollars there and have more activity. So we can't really say what -- since we don't know what the structure would look like, we don't know the impact, but the overall goal would be that we could actually have more production growth this year, potentially if we have more capital available to add another rig to the Eagle Ford. That's one of the goals of doing a joint venture in the Permian would be to accelerate activity in the Eagle Ford where we could immediately bring on more oil production if we could add another rig there. At the same time, delever the balance sheet so we're -- so right now though the guidance that we're providing assumes that we're not -- we're going to stick with the plan as it is, which is to spend the money that we have budgeted.

Okay. Just to summarize, is there downside risk to that number with a partnership or upside risk to the net volumes with the oil side? I guess it depends on the structure.

Depends on the structure and depends on whether they participate and the current producing wells, the Eagle Ford, that was a structure where they did not, so there's a lot of if's, but if there would be any type of downside, it would be very temporary because I think in the long run, it would allow us to accelerate activity as the Company and -- the quicker that we add like a rig to the Eagle Ford, we can make up a whole lot of oil production that may go to a partner in the Permian.

Okay. Just a follow-up question on your Gaines County acreage, if you can just give us an update on what your plans are for that?

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

Mike Kelly, Global Hunter Securities.

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

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

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

Mike, in the Eagle Ford, we still have some of the issues that plagued the fourth quarter, especially in the month of January and part of February. But we do expect to see our total Company production will grow from the fourth quarter levels but probably not quite back to where we were in the third quarter of last year. I think that March will be real strong but it's going to be diluted a little bit by January and part of February that were -- we still had shut-ins and not many new wells coming on yet. So --

I think our biggest production from quarter to quarter based on how the Eagle Ford, which is the biggest driver, has stacked up, the second quarter growth over the first quarter will be our most dramatic growth, quarter to quarter, just based on today's schedule. Because there, you'll have the benefit of starting the quarter with really high production month and then having some good completions. Then we see fairly consistent growth from the second to the third, to the third to the fourth, despite the spottiness in the completions the way that it matches in the different quarters. So really, a big uplift up on second quarter, and then some moderate growth in the third and fourth. The wild card in the production forecast is, how does the horizontal Wolfcamps -- how do they come in? Because we're being conservative in what we expect from them and so they have the ability to allow us to have higher expectations for oil, but we need to see the results of those two wells.

Okay. Thank you, guys.

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

This is Mark. I'll run through both areas real quick and just give you a list of things. In the Eagle Ford, several factors affected our Q4 and early Q1 production. We've already spoken about most of these, but I'll hit them again. As shown on slide 26, a very small number of wells came online since last October, and this continues really through this month. And then in late February and March, we just have a big ramp-up of completion activity. This is mainly due to the pad drilling that we are executing which defers our completions until after all the paths are drilled and then you move in with the frac crews and you frac the whole -- all the wells on the pad, so everything just takes longer, it defers that activity.

The second factor is that two of our last four wells that we completed are in Atascosa County that was the Mesquite well and the DVR well. That's where IP rates are significantly lower than in our prime McMullen County acreage. These were lease obligation wells. They hold a significant amount of acreage so we felt they were valuable to drill even though they're not in our tier one acreage. Third, we had several wells shut-in for extended periods and mainly in December for offset fracing, either by us or by other operators across the lease line from us. And lastly, we had numerous operational issues beginning in the -- in about early to mid-December and continuing until just about now. These were mainly due with wells, new wells loading up and artificial lift-related issues that we've had to work through. We still had five wells down this morning, all of which, all but one of which should be returned to production in the next few days. We have one well shut-in because we have a drilling rig on the pad drilling another well so we can't get it on until we get that drilling rig done.

Now, on the Wolfbone, the primary factors affecting production have been operational and then the results of our horizontal program. Similar to Eagle Ford, we were hit with a rash of mechanical issues in Q4 that have carried over into Q1 of this year. Almost all of these are artificial lift-related. We've made changes to our chemical program and to our equipment design that should significantly improve performance but those changes have to work their way through the system. As you repair wells, you make the changes and then they become less problematic in the future. So we have reduced the number of non-producing wells from a high of 16 to 11 currently and we should have several of these returned to service this week.

In regarding our horizontal program, the effect of the Dale Evans #2 to production was pretty significant. Not only did the well under-perform even our average vertical wells, but it occupied a drilling rig for 75 days, a time period in which we probably could have drilled three vertical wells. So for the foreseeable future, our horizontal program will be focused on the Wolfcamp A, where the results offsetting us have been significantly better. We'll monitor our results and carefully tread forward this year.

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

Cameron Horwitz, US Capital Advisors.

Quick question for Mark here. Mark, can you talk just a little bit about the well design on the Gaucho State well? 60, 100-foot lateral, 18 stages, that's about 3.75 feet per stage. It seems a little bit wide. Why -- can you just talk about why didn't you do a little bit more fracing intensity in terms of the number of stages on that well?

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

Michael Hall, Robert W. Baird.

I want to dig in a little bit on the cost structure side of the equation. Cost structure on the lifting side popped up in the fourth quarter. Just curious on the outlook for that as you work through '13 as you bring some of these volumes back on. Should we expect that to come back down or just broadly, how should we think about that?

Sure Michael, this is Roland. If you look at the lifting costs just by the regions, I think you will see some improvement in the South Texas region, just a modest improvement with the higher volumes because there's still a fixed cost structure there. But again, we will be adding some dollars to the overall lifting costs as we put more wells on artificial lift and the other type costs that goes along with that. So the lifting cost rate in the fourth quarter was like $1.93 per Mcfe even though it's still oil having Mcfe basis. We see that declining slightly as we look ahead to 2013 with the better volumes. I think there will be a more dramatic improvement in West Texas area the same way where we had repair costs in the quarter and had a $4.11 per Mcfe lifting total all-in rate including gathering and production taxes. We see a big improvement to that rate with the volumes coming up in that area.

But then as the Company-wide, obviously, in the gas -- where the gas production is, other than the production taxes and gathering costs which are fairly proportional to the production levels, we'll see higher rates, lifting rates in the Haynesville/Bossier area just because of the volume declines and the rest of the costs there are fairly fixed. So Company-wide, I don't -- I think that we will have those two factors working together. And then so as far as the overall lifting rate which was $1.19 in the fourth quarter, I think the numbers, we'll see a little higher lifting rates consolidated for all the regions as we go into 2013. We see it at a level starting where it was in the fourth quarter to all-in lifting rates of approaching $1.40 or something by the end of the year just as the mix of oil is higher versus the gas and just the lower gas volumes and the fixed costs. So a complicated answer but that's what we'll see overall.

That's helpful. Thank you. And then also on a corporate level, I think in the past, you alluded to reaching closer towards a cash flow neutrality in the back half of '13. Where's your head on that excluding any impacts of a potential JV? So you'll see that occurring in '13 or is that being pushed back at this point?

No, Michael, we see us getting very close to that and like in the second half of '13 with the oil mix. Of course, a lot of it depends on the overall -- especially the gas, what's the gas commodity prices and are we closer to the $4 or are we closer to the $3 is a big variable there. But that -- and I think we've also been fairly conservative in the estimate of costs, as you can see from our budget. So I think we're still under this year's plan without the JV, bringing those two very close to each other in the second half of 2013 with a modest overspend in the first half given where current natural gas prices are at in the market.

Okay. So those comments are based on basically strip pricing today? Is that --

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

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

Yes. Certainly. I appreciate the color, guys. Thank you.

Mario Barraza, Tuohy Brothers.

Jay, I just wanted to follow-up on your comments about in the Delaware Basin for -- you mentioned you're going to be targeting the tier one acreage. How would you rank now that you've delineated on a vertical basis the acreage on a tier side, tier one? Is there a few tiers, say tier one, tier two, tier three, and how does that break out percentage-wise?

Well, I think when I say tier one, when we look at our drilling program in 2013, we're going to focus, if we can -- and again, some of this is lease obligation driven. We're going to focus our vertical wells near offset wells maybe on different leases, where we've had 300, 400, 500 barrel a day IP rate wells, we're going to try to do that. Then we'll try to stay away from the areas where, vertically, we picked our 180, 190, 200-type barrel a day wells. You can see that on one of the charts that we've handed out. I mean, that's our goal, if we can do that. There may be some straggler wells that we need to drill in order to hold big lease blocks but that's not what we're going to try to focus on.

Mark may want to comment some more on that but that's how I look at that.

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

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

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

Okay. No, that's all I had. Looking forward to hearing some info on the Gaucho.

Yes, me too.

Richard Tullis, Capital One Southcoast.

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

Well, the Gaucho well this afternoon should be --

The horizontal Haynesville well did you say?

That's correct.

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

Okay. A quick question on CapEx, you see level spending throughout the year now that you're talking about being close to cash flow neutral in the second half. Does that assume level CapEx numbers throughout the year?

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

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

Thank you, Erica. Again, our goal in this conference call is to get, quite frankly, 2012 behind us. It's to continue to transition this Company away from this 98% natural gas platform we had, which at that time, several years ago, that it was a good platform. Today, it's a horrible platform. In order to change the platform, we did have to add two tier one oil basins. I think we are exactly where we need to be. I think our performance is a little lumpy. We're very disappointed in the fourth quarter results. I think that's part of just transitioning to becoming an oil Company. That's a little bit of the lumpiness in the Eagle Ford, which, again, is the driver.

We did have a disappointing Dale Evans well and that did hurt production. We are not going to do that again in 2013. We're going to hunker down and drill these Wolfcamp A wells which is out of the Gaucho, the Balmorhea or some others maybe and then we'll -- the Permian is a very hot area right now. We've had phone calls asking what they could do with us in the Permian for prospective partners, so that's a good thing. It's a good thing to be in a nice, hot area where I think 20% of all the oil produced in the United States come from the Permian and that's for a reason and we're right in the middle of it. So we're very, very pleased. We were at a conference last week and we were in New York a couple weeks ago and our goal was -- we didn't know this, and Mark moved up this completion date on the Gaucho because really, the Gaucho initially wasn't scheduled to be completed until today, but we did move that up. We did have the 18 stage fraced, and like he said, we should start flowing that well back today. That's a great thing so we at least don't have that hanging out there.

Now we just need to see the rock quality of the Wolfcamp A that we drilled in and again, as Mark said, it's between two good offset wells that some other companies own. So we'll see what happens. I hope that we have given full accountability of 2012 and particularly where we're going in 2013. It's a privilege to work here and we try to do the right thing and we try to be accountable. So anyhow, thank you.

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