Comstock Resources Inc (CRK) 2013 Q1 法說會逐字稿

Good day ladies and gentlemen and welcome to the first quarter 2013 Comstock Resources Inc. earnings conference call. At this time, all participants are in a listen only mode. Following the prepared remarks there will be a question-and=answer session.

(Operator Instructions).

I would now like to turn the presentation over to your host for today, Mr. Jay Allison, Chief Executive Officer. Please proceed.

Welcome to the Comstock Resources first quarter 2013 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 2013 Results.

I am 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 2013 first quarter operating and financial results and discuss our pending sale of our West Texas properties to Rosetta Resources. Please refer to slide two in our presentations and note that our discussion 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 of such expectations will prove to be correct.

If you go to Slide 3, it's the 2013 first quarter highlights, we'll summarize our first quarter results. The declining natural gas production results from pulling all of our rigs out of the Haynesville last March and the improving oil and gas prices defined our first quarter results. We had oil and gas sales including the gains from our hedging program, of $97 million for our continued operations. Our total EBITDAX was $81 million, and our total cash flow from operations was $62 million or $1.28 per share. We reported a net loss from continuing operations of $24.5 million, or $0.52 per share for the quarter.

Given the activity that is planned in south Texas and our Eagle Ford Shale program we are expecting another strong year of oil production growth. Oil made up 14% of our total production in the first quarter excluding our West Texas properties and is expected to average 20% this year. We expect that oil production from our Eagle Ford Shale properties will grow 28% to 34% over 2012 driven by our successful drilling program.

In the first quarter, we've drilled 11 successful Eagle Ford wells and completed 10 wells, which had an average per-well initial production rate of [854] (Company corrected after the conference call) barrels of oil equivalent per day. The 2013 completions have initial rates that are 32% higher than initial rates in 2012. We'll have a very strong balance sheet after the West Texas divestiture that we'll discuss today. We'll have over $800 million in pro forma liquidity and our pro forma net debt improves to 29% of our total capitalization.

Please refer to slide four now in our presentation where we summarize the pending sale of our West Texas properties. On March 15, we announced an agreement with Rosetta Resources to sell our properties in Reeves and Gaines County in West Texas for a sale price of $768 million, subject to customary purchase price adjustments and closing conditions. The sale will have an effective date of January 1, 2013 and is expected to close on May 14, 2013. The sale represents all of our assets in the Permian Basin, so we reflect these properties as discontinued operations in our financial results. Reserves related to these properties were 26.8 million barrels of oil equivalent and 1700 BOE per day of our 2012 production.

We intend to use the proceeds from the sale to primarily reduce debt and to improve our balance sheet. We expect to realize a gain of over $250 million on the transaction, which represents an outstanding return for our stockholders for the one year that we owned these properties. Despite the substantial gain from the sale, we expect the current tax liability for this year to be less than $2 million.

I will now turn it over to Roland Burns to provide the financial impact of this transaction and to review our first quarter results in more detail. Roland, it's yours.

Thanks, Jay. On Slide 5 in the presentation, we break out our West Texas properties from our 2012 results. The slide breaks out the 2012 results. You can see the impact of this transaction going forward on our numbers.

As Jay said, starting this quarter, we're reflecting the assets and the operating results of the West Texas properties as discontinued operations and we're excluding them from our continuing operations results. The properties we're selling represented 22% of our oil production at 1400 barrels per day in 2012, and less than 1% of our natural gas production at 2 million cubic feet of gas per day in 2012. These properties generated $47 million in revenues, or 11% of our 2012 revenues.

Oil as a percent of our total revenues, decreases to 47% without West Texas as compared to 52% with it. Our average oil price realization, before hedging, improves to $101.09 per barrel as compared to $96.95 per barrel.

Our average natural gas price realization decreases to $2.49 per Mcf, as compared to $2.52. Lifting cost per Mcfe produced, improves to $0.96 from $1.06. And DD&A per Mcfe improves to $3.77 as compared to $3.85.

$202 million of our $549 million in capital expenditures, last year, were spent on the Permian properties. And we sold 23% of our proved reserves in the transaction, including 52% of our oil reserves. 81% of the reserves that we sold were undeveloped, so after the sale, 75% of our total reserves are developed, as compared to 62% before the sale.

Now, looking at our first quarter 2013 results, on slide 6, we show our oil production by region, on a daily basis, and we showed for the last three years and for the first quarter of 2013. The West Texas oil production is shown in red on this chart and it's also combined with other production that we have sold in the past.

Total first quarter 2013 oil production increased to 6700 barrels per day and was 600 barrels per day higher in the fourth quarter last year. Half the increase was from the discontinued West Texas properties, being sold, which averaged 1900 barrels per day in the first quarter. The other half was from our Eagle Ford properties in South Texas, which increased to 4600 barrels per day.

In the fourth quarter last year, and the first two months of the first quarter this year, we had many of our Eagle Ford Shale wells shut in due to artificial lift installation, or for offset frac activity. We got all these wells back on production by the end of February. With the increasing -- with the increased drilling that's now planned for the Eagle Ford, in the second half this year, we expect our oil production from continuing operations to grow by approximately 28% to 34% over last year's pro forma continuing operations production. The total continuing operations oil production, we think, will average between around 2.3 million -- 2.4 million barrels in 2013.

Slide 7 shows our natural gas production on a daily basis. As expected, with limited drilling activity last year, our natural gas production declined by 9% to 177 million cubic feet per day as compared to the 195 million cubic feet per day in the fourth quarter of last year. Production from our Haynesville and Bossier wells, which is shown in dark blue on this chart declined to 124 million per day this quarter. Our remaining gas production rates remain the same as the fourth quarter.

Production from our Cotton Valley wells, shown in green average 25 million per day, our South Texas gas production, shown in light blue, was 20 million per day and other gas production, shown in purple, was 5 million per day. Then, we are divesting 3 million per day of our gas production, which is attributable to our West Texas properties. We expect our natural gas production related to the continuing operations to decline further this year, and to be approximately 57 Bcf to 61 Bcf, which would be a decrease of 25% to 30% from pro forma 2012 production from continuing operations.

Slide 8 shows our realized oil prices related to our continuing operations. Our price realizations in South Texas continue to be strong in the first quarter of 2013, as we realized $105.82 per barrel, up slightly from the $105.19 per barrel we realized in the first quarter of 2012.

With the significant Gulf Coast premium, we received in the first quarter, our realized priced average 112% of the average bench marked NYMEX WTI price. 89% of our oil production was hedged in the quarter at a NYMEX WTI price of $98.67. After our hedging program, our realized price improves to $111.19 per barrel, 9% higher than the after-hedging oil price we averaged in the first quarter 2012 of $102.06.

In Slide 9, we outlined our hedge position for the remainder of this year. We have a very attractive oil hedge program, which protects our [2013] (Company corrected after the conference call) drilling program. We have 5,778 barrels hedged per day for the second quarter at $98.69; 5556 barrels per day in the third quarter hedged at $98.72; and 6000 barrels per day hedged for the fourth quarter at $98.67 per barrel.

Slide 10 shows our average gas price, which improved by 21% in the first quarter, to $3.15 per Mcf as compared to $2.61 in the first quarter of 2012. Our realized gas price was 94% of the average NYMEX henry hub gas price for the quarter.

On Slide 11 covers our oil gas sales including the hedging gains or losses. Our decline in natural gas production was offset in part by improved oil and gas prices in the quarter. So sales related to our continuing operations decreased by 5% to $97 million in the first quarter, as compared to $102 million in 2012's first quarter. Our oil production made up 49% of our total sales, as compared to 43% in the first quarter of last year.

Our earnings before interest, taxes, depreciation, amortization and expiration expense and other non-cash expenses, or EBITDAX, increased by 3% to $81 million from $79 million in 2012's first quarter as shown on slide 12. $9 million of or EBITDAX, in the first quarter, was related to the discontinued West Texas operations, with $72 million attributable to our continuing operations.

Slide 13 covers our operating cash flow. Our operating cash flow for the quarter came in at $62 million, a 10% decrease from cash flow of $67 million in 2012's first quarter. $6 million of our operating cash flow in the first quarter was related to the discontinued West Texas operations, with $56 million attributable to our continuing operations.

On Slide 14, we outline our earnings. We reported a net loss of $24.5 million or $0.52 per share, from our continuing operations and a loss of $2.6 million, or $0.06 per share from our discontinued West Texas operations, as compared to earnings of $1.4 million, or $0.03 per share in 2012's first quarter. The first-quarter financial results in both periods include several unusual items.

We had gains from the sales of marketable securities in both quarters. The first quarter of 2013 we had a gain of $7.9 million, or $5.1 million after tax, or $0.11 per share from the sale of our remaining position in Stone Energy and we had a gain of $26.6 million, or $17.3 million after tax, or $0.37 per share in the first quarter 2012 on the sale of 1.2 million shares of Stone. We had mark-to-market unrealized losses related to our oil derivatives of $8.8 million, or $5.7 million after tax, or $0.12 per share in the first quarter 2013, and $10.2 million, or $6.6 million after tax or $0.14 per share in the first quarter of 2012.

Both quarters included some impairments on natural gas, unevaluated leases and producing properties. $2.4 million, or $0.03 per share in the first quarter of 2013 and about $1.3 million, or $0.02 per share in the first quarter of 2012. We also had a gain in 2012 of $6.7 million, $4.4 million after tax, or $0.09 per share, on property sales. Excluding these items, we would've reported a net loss from continuing operations of $0.48 per share this quarter, and about $0.27 per share in 2012's first quarter.

On Slide 15, we show our lifting cost per Mcfe produced by quarter, related to our continuing operations. Lifting cost are comprised of three components on our income statement; production taxes, transportation costs and then other field level operating cost.

Our total lifting costs increased to $1.07 per Mcfe in the first quarter 2013, as compared to $0.98 per Mcfe in the first quarter 2012, and $1.02 per Mcfe in the fourth quarter 2012. The increase was mainly due to the lower production we had this quarter and the fixed nature of much of the lifting cost. Production taxes were $0.12 per Mcfe this quarter, our transportation cost averaged $0.23 in the first quarter and the field operating cost averaged $0.72 this quarter.

On Slide 16, we show our cash G&A per Mcfe produced by quarter excluding stock-based compensation. Our general administrative cost increased to $0.31 per Mcfe in the first quarter 2013, as compared to $0.21 per Mcfe in the first quarter 2012. Our total level of G&A expense was roughly the same between the two periods, so the increase is solely attributable to the lower production volumes we had this quarter.

Our depreciation, depletion and amortization per Mcfe produced is shown on slide 17. Our DD&A rate in the first quarter averaged $4.66 per Mcfe, as compared to the $3.24 rate we had the first quarter of 2012, and the $4.43 we averaged in the fourth quarter of last year. The higher cost of the oil production and the write-down of undeveloped natural gas reserves last year combined with a very low natural gas prices are driving this increase.

On Slide 19, we break out our 2013 drilling budget, which has been updated for the increased activity now planned for the Eagle Ford properties in the second half of this year. This year, we expect to spend $347 million on our continuing operations. The new budget has us drilling 82 wells this year, 10 gas wells and 72 oil wells. $312 million will be spent on the Eagle Ford shale program to drill 46.9 net wells.

We've also budgeted $32 million, or any required drilling to hold acres in the Haynesville Shale. In addition to drilling expenditures, we planned to spend another $12 million on acres -- on acreage in 2013.

We'll flip back, to go back, we skipped Slide 18, so let's go over Slide 18, which is an important one, where we detailed our capital expenditures relating to our continuing operations incurred this quarter. The capital expenditures on our discontinued operations, after January 1 -- on our discontinued operations after January 1, are going to be reimbursed under the purchase of sale agreement, so they're excluded from this slide. But we did spend $58 million in the first quarter, as compared to $140 million we spent in 2012's first quarter on our continuing operations.

The capital expenditures in South Texas, which is shown in red, relate to our Eagle Ford drilling program and they decreased to $54 million this quarter, as compared to $68 million we spent in last year's first quarter. Lower well cost and the promote that we're earning under our KKR joint venture account for the decrease.

With low natural gas prices, our spending for our natural gas properties in North Louisiana declined to only $4 million this quarter, as compared to the $72 million we spent in the first quarter of 2012. Our capital expenditures related to our continuing operations this quarter lineup pretty well with the $56 million that we generated in operating cash flow from our continuing operations.

Now, we'll go ahead and go to Slide 20, which recaps our balance sheet at the end of the first quarter and we also show a pro forma balance sheet for the West Texas divestiture, which we expect to close in the second quarter. On March 31, we had $1.3 billion of total debt, which is comprised of about $885 million of Senior Notes and then $450 million outstanding under our bank credit facility. Our current borrowing base, under the bank facility, is $570 million, which leaves us about $120 million in availability.

Pro forma for the West Texas divestiture will have $325 million of cash on the balance sheet and then no bank debt outstanding. Accordingly, our net debt will be reduced to $560 million and will fall to 29% of our total capitalization, as compared to 59% where it is today.

I'll now turn it over to Mark to review our drilling results in the first quarter.

On Slide 21, we cover our South Texas operations, where all of the activities are in our oil focused Eagle Ford Shale play which has identified resource potential of 78 million barrels of oil equivalent net to our interest. In the first quarter, we drilled 11 horizontal oil wells, or 7.2 net, and had three wells, or 2.3 net, drilling at March 31. We have completed 10, 6.4 net horizontal Eagle Ford shale wells including 6, 3.8 net wells that were drilled in 2012. The 10 Eagle Ford Shale wells that were completed had an average per well initial production rate of 854 barrels of oil equivalent per day.

Slide 22 and 23 show the results and locations of the 57 wells, which are currently producing Eagle Ford. We completed 10 more Eagle Ford Shale wells since our last update. They are wells numbered 48 through 57 on this list.

The 57 Eagle Ford Shale wells that were completed had an average per well initial production rate of 729 BOE per day. These wells are being produced under the Company's restricted choke program and the initial tests were obtained with a 14/64 to 16/64-inch choke. The 30 day per well production rate for these wells, averaged 560 BOE per day and the 90 day per well rate averaged 464 BOE per day, or 68% of the initial 24 hour test.

The 2013 completions have [average] (Company corrected after the conference call) initial rates that are 32% higher than the initial rates in 2012. The four wells with the highest initial production rates were the Swenson A #1H, the Gloria Wheeler C #1H and the Gloria Wheeler A #3H and the Rancho Tres Hijos B #1H, all located in McMullen County. These wells were located in McMullen County and had an initial production rate of 1222, 1032, 978 and 968 BOEs per day. As I said, Slide 23 shows the location of the 57 producing Eagle Ford wells.

Slide 24, we show how the cost of our Eagle Ford Shale wells of come down considerably since we started drilling in August of 2010. The costs on this slide have been adjusted to a standardized lateral length of 5,800 feet to make them comparable. Costs are based on actual cost per completed wells and AFE costs for future wells.

You can see that in the beginning, these wells cost over $12 million. And that is significantly improved to just under $8 million. Faster drill times and lower well stimulation costs account for much of this savings.

Slide 25 shows the location of our planned 72 Eagle Ford wells, reflecting an increase from our original plan with the pending West Texas sale. We plan to add an additional three operated rigs in the second half of the year. You can see the high concentration of planned wells in McMullen County, where we have achieved our best results.

Slide 26 shows the net Eagle Ford wells being put on production per month in 2012 and what is projected for 2013, which reflects the addition of three new rigs in the second half of 2013. The monthly variation is due to multi-well pad drilling and subsequent multi-well stimulation operations, which result in lumpiness of the result -- of the resulting Eagle Ford production curve in 2013.

Production in the first quarter of this year was affected by the low number of completions in that quarter. The second quarter Eagle Ford production will benefit from a high-level of completions, while the third quarter will have a slower rate of increase due to lower activity in that quarter. The impact of the accelerated program will be seen in the fourth quarter of this year and the first quarter of next year.

I will now turn it over to Jay.

Again, thank you Roland and thank you Mark. If everybody would turn to Slide 27, which is the 2013 outlook. On Slide 27, I'll summarize our outlook for the rest of the year.

Even as natural gas prices are improving, as we all know, we will remain focused on increasing our oil production with our Eagle Ford Shale drilling program, which provides high returns on our investment. We will not start drilling natural gas wells until we can have high returns on those projects. We expect the strong growth in our oil production will more than offset the natural gas production declines, to allow us to have high revenues and cash flow and be a much more profitable company in 2013. We expect oil to comprise 20% of 2013's production, even after the sale of our Permian Basin properties.

93% of the net wells we'll drill in 2013 will be oil wells and 90% of our budget will be spent on oil projects. Post the West Texas sale, we'll be able to ramp up our high return Eagle Ford program and drill 72 wells by the end of the year. We continue to have one of the lowest overall cost structures in the industry.

We'll have a very strong balance sheet after West Texas divestiture closes on May the 14th. We will have over $800 million in pro forma liquidity, and our pro forma net debt improved 29% of total capitalization from 59% at the end of the first quarter. We see our six rig year drilling program being funded with operating cash flow by the end of this year.

For the rest of the call, will take questions only from the research analysts who follow the stock. Stephanie, we'll turn it back over to you.

(Operator Instructions). Your first question comes from the line of Brian Corales with Howard Weil. Please proceed.

Regarding the Eagle Ford, can you, maybe, talk about what you have been drilling on in terms of spacing? And what you have tested or planned to test over the next, call it 6 to 12 months?

Mark, yes, we are currently drilling -- you have to look at it little bit different than acreage spacing because of the lateral links in the area and the shape of acreage. Our current spacing pattern is about 500 feet. That's how we're set up to drill and, really, we're in development mode now and that's our goal, is to drill at this 500-foot spacing pattern. We may do a little bit of testing, we have no current plans at the moment to test a tighter spacing than that. That's really how we're established on our acreage at this time.

When you're add -- I guess when you get the six rigs, almost everything, you have no HBP issues, everything's going to be pad drilling?

Almost everything is. We'll have a little bit of drilling on some of the northern acreage and in one acreage block to the west that has not been drilled on yet that we are still drilling. 90% of our drilling will be development drilling on pad sites.

Is there any other acreage? Are you all looking at any other acreage around the Eagle Ford areas? I will hang up and listen.

I think, Brian, one thing that we were really not able to do, because we were pretty cash strapped before the divestiture of the Permian, I mean, we weren't actively seeking any new acreage position, even though I think we would've had some financial backing with our partner. I don't think we had the quote, the headcount to do that. Now, I guess this has freed us up to take a look at that and we have been taking looks at that. If you're the size company we are, it doesn't take many additional acres to have a pretty big impact. I'll tell you what we're not interested in doing, we're not interested in buying hundreds of thousands of acres of this goat pasture just to tell you we have a lot of extra acreage out there because we're not going to squander money like that.

Thanks.

Your next question comes from the line of Ron Mills with Johnson Rice. Please proceed.

A question just on the Eagle Ford program. You provide all the well results. Looking at Slide 25, my counting the dots right -- in a sense that if you look at your 72 well program, it looks like about 60 of those 72 wells are going to be more in that central part of McMullen County, where you've had the stronger well results; is that right? Then, as you move forward, as well, is that where you think the activity will remain concentrated?

Ron, yes. In fact, again, one of the things that we can do with the delevered balance sheet, is we can double down on our rig count in the Eagle Ford. We had de-risked the Eagle Ford by, probably, middle of last year. And what we want to do, and we've shown on some of the slides, we want to reduce our cost and we want to increase our IP rates. One way to do that is to drill more of your wells in McMullen. So, yes, you're exactly right.

As far as, Brian had asked a question earlier, about whether the acreage is HBP, if you remember, in 2010 and 2011, our total gross rig count or well count, in Eagle Ford, was 17 wells, in all of 2010 and 2011. Now, last year we drilled 30 gross wells. This year, because of the divestiture, again, we'll drill 72 gross wells in 2013.

Mark had talked about a little spottiness, well we had a lot of spottiness going on in the Eagle Ford program before we were able to add the fourth and fifth and six rig. In fact, I looked at the numbers. In the third and fourth quarter, with this new business model, which, again, Roland said we're pretty much going to fund this out of free cash flow from continuing operations, that's our goal. I mean, if you look at the completions that we'll have added in the third and fourth quarter, along with his new drilling program, it's almost 14 new net completed Eagle Ford wells.

That's why we can take this production in Eagle Ford from this [4,600] (Company corrected after the conference call) barrels a day, hopefully we can exit it to 9,000 plus barrels a day and we can do a lot better than that of the end of 2014. Again, hopefully within our free cash flow from operations. At the same time, have completely undrawn credit line of a $0.5 billion and $300 million in the bank. I mean, if you believe the old adage of cash is king, than we're going to be in pretty good shape for that. We're rambling, but were pretty excited about where we are because, if you've ever owned a share of stock, we haven't diluted you and issued you any shares for over eight years. We don't have any other derivatives out there, except for bonds and some hedges. So, it's -- things are pretty good at Comstock. So, go ahead, Ron, more questions?

The question is, as it relates to that $325 million cash position, to follow up a little bit on Brian's question about incremental acreage in and around your existing Eagle Ford, or I know you have some notes that become callable in October. How do you -- at least what's your framework, internally, of how you evaluate the cost/benefits of acreage acquisitions and/or debt reductions versus, you know, a potential stock buyback, if you view your shares as basically an acquisition opportunity, as well.

Well, again, I think my overall answer to that would be, when we had our conference call in February 2013, and reported year-end and fourth quarter, we told all the stakeholders that we had too much debt. We realized that the industry is facing capital intensity challenge and we recognize that. We told the stakeholders that we need to delever the Company. I think it's very much a win-win for Rosetta and for Comstock, because we had two tier one oil plays and they were really tier one and they both needed a lot of capital. The Permian needs a lot of capital and so does the Eagle Ford.

We, quite frankly, with our balance sheet, I don't think we were able to tender the capital that was needed in both of those regions, because, I think our leverage was too high. You have too much leverage, you get kind of in a danger zone and you flirt with financial issues. It's not fun. Most of these companies don't come out of that unscathed.

So, by being able to monetize this for a fair price, I think what you see, to answer your question, I think these are the things that we can do now that we couldn't do before we had exited the Permian. You know, we talked about that we've given the stakeholders a very large gain. It's an unbelievable return to our stockholders within a year. And we've gone from maybe a $570 million credit facility to $500 million. That's pretty unbelievable. That's $0.5 billion undrawn and we have, as you mentioned, the $300 plus million cash in the bank.

So, what does that allow us to do now? Well, as Brian mentioned, we can look at the Eagle Ford, now, for some acres a 1000, 2000, 3000, 5000, 10,000, whatever. We can do that even with our partner KKR, because we're kind of in partners with them. I think if we find something that has that return and we have the ability to do that, because our technical team, they understand that area.

I think we would be able to tender for our bonds in October if we so choose to do that. We couldn't do that before. If we do that, that saves $22 million or so a year. I think we can add to our core area without diluting our stockholders. I think we've got a new business team here to develop new opportunities. It's the same group, but it's a new business team model. We couldn't exercise our internal strength with the financial balance sheet we had.

Then, again, you don't want to not talk about the Haynesville. I think it does let us reevaluate our Haynesville, Bossier acreage. What type of internal rate of return we might get in the future. But, the beauty of this, is this time last year, gas was $2.04 today gas is like $4.40.

We are telling you, as a company, we're not increasing our rig count in the Haynesville just because gas is even $4.50. But, we're evaluating opportunities, now. So, there's so many things that we can do now that we couldn't do that we were constrained from doing. Again, Ron, I think that does include adding Eagle Ford acreage and adding the three rigs. I think, fundamentally, I think we will be a much better story as a deleveraged story. So, Roland may want to comment on that a little bit.

I think you summarized it real well. I think the Company will have a lot of options to redeploy some of the cash that will be on the balance sheet after the close. And the goal of the Company is to maintain a much stronger balance sheet than we had after acquiring the West Texas assets. As natural gas prices improve, that also improved the balance sheet, just with the natural gas prices almost doubling to where they were, especially the second quarter last year.

There is a lot of options and I think that we are going to close the transaction first and then present a lot of these options to our board and really be mindful of how can we create value for the stockholders, and in the long-run, that's what we'll do with this balance sheet. Were not concerned about the lack of opportunity at the Company, because we've always had more opportunities to look at, either acquire properties or drill properties, that's never been a weakness of the Company, as you can look at our long history.

As Roland said, I think one of the criticisms is, what's your depth of opportunities? My answer to that, on one on ones, because we've not been out touting the story is; well if you look at who Comstock is, it was August of '08 that we monetized our Gulf of Mexico assets to Stone. It was at the end of '07, that we started deepening wells in DeSoto Parish. Well, by '08, '09, that's the heart of the Haynesville, Bossier play. And then it wasn't until the beginning of 2010 that we sent our scouts out to find more oil in South Texas.

So, through our G&G group, I mean the 27,000 - 28,000 acres we have in the Eagle Ford, we started adding that in 2010, 2011 and look where the Eagle Ford is today. At the end of 2011, I mean bunk, we announced that we're in the Permian and we'll be out in two weeks. As Roland said, we have never, ever, ever had a shortage of opportunities that, quite frankly, have been good and we've received a gift of a lot of cash and we are going to be good stewards of that cash. Were going to create wealth to the stockholders on a per-share basis, period.

Then, one last one just for you, Roland, on slide -- I don't know what it is, five, where you have -- you try to break out the financials in terms of cost, unit cost and whatnot. Ex- the divestiture. The pro forma column on the cost side, particularly on lifting, on lifting cost, which is the biggest improvement. Is that a good -- do you think those are good run rates, in terms of your total lifting costs? And, overall cost structure, or how should we think about the cost structure post asset sale in mid-May.

I think they're definitely a good indication with the different property mix. Obviously, the West Texas properties were not a large component of the numbers, yet. But, the other things you have to be mindful of is lifting costs is not a variable number, only probably production taxes, and transportation are pretty variable to production rate. Until we -- with some of the decline in production in the Haynesville, some of the lifting cost will still be there and less volumes to amortize it over. I think that would be the only other trends that will happen a little bit. I think the absolute level of lifting costs we have this quarter, on a dollar amount, is very -- on a continuing operations basis, is a good indication of what we expect for most of this year. That number, on a unit basis, could look higher with the lower volumes that we could have from the gas area.

Did the first quarter include some higher cost associated with artificial lift that may not be repeated in the second quarter, or is that just incorrect?

There were some -- a little bit of that in the first quarter but, of course, but, when you take into account some of the additional production we're putting on, I think that absolute level is clearly indicative of what we could expect in the quarters in the future. Versus-- probably increasing for a different reason and decreasing for lack of those workovers. A lot of those workovers are probably in the discontinued operations lifting cost.

I understand. Thank you.

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

Jay, you made a comment that, potentially, you get to get after gas a little bit now that you've got a much improved balance sheet. It didn't sound like that was really 2013. Roland, you said, obviously, you guys will have a board meeting post the close. I'm just trying to get a sense of whether or not it's reasonable to expect that, say gas was $4.50 or higher in 2014, that you guys would drill some gas wells.

I think what we do after the closing, is we evaluate all of our opportunities. In the Eagle Ford, right now, will probably did a 40% to 50% IRR. Unless it's competitive, to the Eagle Ford, then I don't see us putting any meaningful number of rigs to drill any natural gas. Most of that gas is HBP'd, and we've proven that. Because, this year, if you look at the 10 wells that we'll participate in, maybe, that's really kind of not accurate. I mean, that's a gross number. If you dig down in that number it's like 3.2 net wells. Out of that, two of them are mandatory that we drilled to hold acreage. The rest of that is a guess that we might receive an AFE as a non-operator.

So, no. We're not -- even though we think natural gas fundamentals, right now, are looking a little better than oil, we are not interested in putting a lot of rigs or any rigs and drilling the Haynesville, Bossier. It's HBP'd. I think we should move the cash elsewhere right now. I do think if we have an industry partner that wants to accumulate some acreage in tier one Haynesville, than we'd be interested in that. And guess what, there's zero acreage like that for sale, because it shouldn't be sold. It's too valuable.

So, no, I think, again, as Roland had mentioned earlier, once we close, we'll have a strategic board meeting and a management meeting and we'll see where oil prices are, where gas prices are. We'll get from Mark what our well results look like. And, again, in Eagle Ford, they're 32% higher IP rates than they were last year and we'll see what our new business opportunities are. We'll put a budget together where we have a CapEx that's within our cash flow. I think that's what you're going to see from us. It's going to be a much more predictable story with a lot less risk, with a lot more upside, that is more predictable.

I guess as a brief follow-up to that. You mentioned the two wells you have to drill this year. The whole acreage on a net basis. Just trying to get a sense of where that might go next year. Would you also have some obligation wells to drill next year? How many might that be?

Maybe a couple more.

Leo, the two wells that we're drilling right now tie up that unit. It's HBP'd and I'm not aware at the moment of anything we really have obligation-wise for next year. I think that was kind of the last one on the books for us.

Now, you know, what we might do, is -- if our reservoir group and G&G group and Mark all agree, and we want to test a longer lateral, or two or three or four of those type of wells in the Haynesville, Bossier, and see what the economics look like and what the IP rates are and what IRR is and what our well costs are, we wouldn't consider that quote, a Haynesville, Bossier, drilling program. Would look at that more as an exploration type program to see if we can de-risk and have meaningful reserves at a lot lower cost to have a much higher IRR. As far as a quote, a Haynesville, Bossier, drilling program, we're not looking at that at all right now.

All right. That's helpful color. I guess just jumping over to the Eagle Ford, you guys talked about placing risk in downtime on production, in the field, due to a stalling artificial lift and then just offset frac activity. It looks like that's been happening for the past couple quarters. Is there any way you guys can give us a ballpark quantification where that's hitting production by 15% or 20%, is there any way just to think about that? Then, going forward, is that going to persist for the rest of the year, or would you expect that to be ironed out at some point? Whether that's this year or next?

Ron, this is Mark. I think it hit production in late Q4, early Q1 by, maybe, 20% to 25%. Almost all of that was resolved in February. It basically had everything back on around the end of February. So, we were starting to get our production back full force in March, but we just didn't have many completions until March and those didn't start selling until late March. You didn't see any effect of all those completions in the Q1 numbers. Q2 numbers should be much better and will always have a little bit of ongoing downtime from offset fracking and from installation of artificial lift and just R&M, repair and maintenance on these type of wells. But, it will be much more manageable, I believe, going forward. More like 10%, which is a normal number.

What we've tried to do, if you'll go back to the February report, that we put out, and look up the Eagle Ford well completions, if you'll compare that to Slide 26, what we tried to do to answer that question, is we tried to put the well completions on a monthly basis.

You'll see that's what we had in third and fourth quarter another 13, 14 net wells to try to take out some of that lumpiness. You'll still see it on this Slide 26, but if you go back to the February 2013 slide, and you look at that one versus Slide 26, it's not nearly as lumpy. The reason is, again, I think that the Permian and our Eagle Ford plays were materially under capitalized. That's why Rosetta got a great property and, I think, we would now have the cash to accelerate our Eagle Ford and you see the results of that.

All right. Thanks guys, that's very helpful.

Your next question comes from the line of Rehan Rashid and with FBR Capital Markets. Please proceed.

Sticking with Eagle Ford for one quick second, so, the current well completion chart that you guys talk about that incorporates the ramp to six rigs, correct?

Correct.

Got it. We get to that, if you could remind me one more time, please, by the end of third quarter? By the end of fourth quarter? The six rig program.

What you see is, our goal is to add a rig -- we have three rigs now. The results that we gave you -- we exited 2012 with three rigs. So, what you see on this -- what we give you is first-quarter numbers, that's a three rig program. It's kind of implemented. Now, what you see another rig in May, another rig in June and hopefully, our sixth rig in July. That's our goal. That's what the chart shows. If you look at the chart, it's in the fourth quarter that you see what 2014 might look like, if we have a six rig program, all of 2014. It's pretty material oil production growth. The stakeholders with a total six rig program in 2014.

Now, going on, you have to put an asterisk by that, because we're going to see where oil prices are, we're going to see what our cash flow looks like, we're going to see what the share prices are, we're going to see if the shares trade at a decent multiple. All of these are things we are going to look at before we commit to the stakeholders and to the analysts, Rehan, what we're going to do in 2014. I think that probably answers your question.

Yes. Yes. A quick one or two more. As you look for these incremental rigs, directionally speaking, bidding, completion cost any color on that?

We have a slide that shows you -- $10 million to like $7.7 million. Mark can comment anymore if he wants to on that slide, what slide is that?

That's Slide 24, Rehan. You can see those costs have really flattened out in the last three, four months. I believe that we're pretty stable. Our frac contact is stable through the end of the year. I don't see those costs coming down anymore. The rigs we're picking up, or plan to pick up, will be similar to the rigs we are running right now. That cost, that $7.7 million or so, is really the pad drilling, the current frac contract and the high-efficiency rates. I think that's about where we're at.

I think we have, what, Helmerich & Payne, and Cactus, is that who we're using?

That's who we're using now.

Yes, right now. We're using two Helmerich & Payne, one Cactus rig right now.

Perfect. Mark, one more question. I missed the beginning of the call. Did you talk about any kind of downspacing? Other folks talk about going as low as 40 acres in the Eagle Ford. You guys are on 80. Could you walk us through, maybe, some path towards, if not testing right now, when and what data are we waiting for before we try it?

Right, Rehan. We're established right now. Our spacing pattern is 500 feet, so it's about 60 acres on a 4,500-foot lateral and it's about 90 to 100 acres on a 9,000 or 10,000-foot lateral. It's really based on width between wells and not acreage.

The 40-acre pattern maybe shorter laterals and more prolific part of the play. I don't think that's really feasible where we are. We think we are at the right spacing and we may look -- and we're still monitoring everybody else. We're looking at our results. We may test a little bit, too. But right now, we're pretty well established on that 500-foot spacing.

One last one, I promise, on this one. What kind of recovery factor is implied in your resource potential that you detail on page 21?

We are probably in the 6% or 7% range. It depends a little bit on the area you're at, but that's kind of the average recovery factor across our play.

Got it. And then, what will, in your mind, what will it take to move it higher for yourselves and maybe for the industry?

Well, tightened well spacing is the way to move that number significantly, at this point. We could put in a larger frac job, you can put tighter cluster spacing, which we are testing now. We've done some larger frac jobs, we've done some tighter cluster spacing to improve that incrementally. Those will be small changes. The biggest one would be infill and tighter well spacing. It depends on what economics you're at now. If you are at 100% rate of return, you can down space. If you're at 40% or 50% rate of return, you damage your rate of return too much by downspacing. I think we're at the right spacing for our economics.

Okay.

Rehan, one thing, if you want to really and truly -- all jokes aside, if you want to figure out how to do something, you get an Aggie to do it. Because they have great engineers, they really do. Mark is an Aggie, and I'm telling you, he's been here 17 years. If there's a way that you can increase recovery factor or downspacing, and it makes sense -- you have to trust that we will do it.

Perfect. Roland, on the October -- the bonds we talked about. They're callable in October? Is that kind of the rough timeframe?

That's correct. One of our issues, was callable on, I think, October 15. Given it's eight and five-eighths effective rate, given that coupon, it's a real big savings for next year's interest expense. That's something we'll be looking at pretty hard. We'll want to exercise that opportunity.

It's callable at what part?

It's like 104. It's the first call date. If we decide to wait, obviously the call price goes down every year.

All right. Thank you so much.

Your next question comes from the line of Kim Pacanovsky, with MLV & Co. You may proceed.

Back to page 21 in the presentation, I mean, obviously, you've high graded your acreage, you're concentrating McMullen, as you spoke about. What are your plans for La Salle, which really isn't on the agenda for this year? Also, as you look at the gross EUR's on this slide of 500 MBOE, how does that very through your acreage?

Yes, Kim, this is Mark. The Western acreage in La Salle is a much newer lease. So, a much later lease term than the acreage in McMullen County. We plan on starting that program in early 2014 and that will be a development area for us then. Timing wise, it just isn't necessary to develop that La Salle acreage now. The results are very similar to our -- the results around it that we've seen from other operators is very similar to some of our McMullen County acreage, so we do expect it to be very much in the middle of the pack, as far as acreage goes for us. We're just not required to start developing it yet, at this time.

Okay.

Then, your other question I believe was about EUR's?

Yes.

Basically, you can just go from south to north and your EUR is higher than that number to the south then it dwindles to a lower number than that as you go north into Atascosa County. It basically follows the -- basically follows the depth curve or the GOR curve, for the most part.

Then, back to Leo's question about the number of wells that will be off-line each quarter. Can you just -- just for modeling purposes, let us know what production is running right now? I know that everything that was off in the first quarter is back on. How many wells are now -- how many new wells are off now, if any? Or, how many net wells for the quarter?

For Q1?

For the Eagle Ford?

Kim, I don't have that number. We've gotten almost everything back on in late February and then we've got three or four wells shut in right now for offset fracking--

Okay. That's what I wanted to know.

It's just a constant process. We are using, in our internal work, we are using about 10% average for down time in the field. It was probably double that in December and January when we had our operational issues and we had a lot of wells shut in for fracking, kind of an unusual number. We got that back in the 10% seems to be managing very well.

The wells we have now, waiting to be completed in Eagle Ford?

We had three, as of a few days ago, I believe, is what I had on the list.

Three waiting completion? And current production today? Would you give that number?

Are you talking about in the Eagle Ford?

Yes.

In the Eagle Ford, I don't have the exact number, but it's between 5000 and 6000 barrels a day, net.

Okay. That's great. And, any thoughts or observations on the Pearsall?

No. We are continuing to monitor the results. We've got Pearsall potential under most of our acreage. And we drilled a pilot hole and got some log data. We traded that for some other log data. We are not in a hurry to test that concept. We're letting Cabot and some of the operators test it and we'll see if the results warrant any capital in the future.

Thanks a lot, guys.

Your next question comes from the line of Mark Lear with Credit Suisse. Please proceed.

Jay, you brought up the KKR deal earlier in the Q&A. Just wanted to get a sense for whether those guys have elect to -- for the next, I guess, basket of 100 wells and, some of the impact -- maybe some of the infill drilling might have on that agreement as I know they have to pay on, what is it, like a per well or per acreage basis. How does that -- infill drilling might impact that, I guess, upfront payment per well.

Mark, this is Roland. The KKR has been participating in all the wells and they still haven't -- they're required to do the first 100. I don't think, obviously, we haven't drilled 100 yet, but, the returns are very high. We expect that all our projections and our reserve estimates, we assume they're going to participate in the full development of the field. I think they'll -- if you look at some of their materials, and the funds that own it, it's performing very well for them. They do pay -- they pay as, basically, $667,000 to participate in a well, which is equivalent to the $25,000 per acre for the one third of the 80 acre partition unit that they earn. That's going to continue through the full development of the field. The other promote will be paid all the way to the end, pretty much, unless we decide to down space to a much tighter spacing.

Mark, they're pleased, because if you're a high partner, and KKR is, all of a sudden we're the operator and then you have to write a check to have a right to participate in a well, then the costs come down, as we've shown in the slides. Production goes up and you know oil's $90 plus a barrel, you're extremely pleased with the agreement. They are and so are we. I think, like Roland said, our economics are based upon them participating in all those wells.

But as you infill space, it's still the $666,000 per well? So that would enhance --

What the agreement is --

Based on 80 acres -- (multiple speakers) That's generally what the plan is. Either it could be slightly less. To the extent that we have 60 acres spacing in and they wouldn't have to pay as much because they have less acres. Basically, if you look at the whole plan, that's a good number to use.

Then, that six rig run rate would also depend on them electing the additional 100 wells, or if it goes in 100 well tranches, or when do they have to tell you, when they want to --

There's not 100 well traunches. They're committed to do 100 wells upfront. Obviously, after that, they can participate or if they choose not to participate they will be happy to own 100% of it. It's a high-return project.

Okay.

Unless the returns are low, they're going to participate. If the returns are low, we'd probably want to move our capital somewhere else. I just don't see a case where that's going to be an issue.

Okay. Thanks, guys.

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

Considering leasehold acquisitions, what's the going rate for Eagle Ford Shale and Haynesville Shale leasehold these days.

Dan, this is Mark. We've really seen very, very few in either play. There's really not a going rate. I mean, the last deal we heard about in the Eagle Ford was, pretty far from us, and it was about $30,000 an acre. We don't really have a good baseline there in either play, really.

A lot of that depends upon where. There's a lot of goat pasture out there. You buy it and put a Billy goat out there and the most expensive thing is the Billy goat. It's not worth much. You see those out there all the time. There's some acreage that you only pay for PDP wells. We're looking for acreage that our geologist would want us to buy. And, we started looking at that. We don't know that we will get any. But, I think that where we were not looking for any earlier, we are looking for some. Again, I think, Dan, we bought $2 billion or so in assets, $2.1 billion, it doesn't take a lot of extra acreage to add a lot of value to a company like Comstock. We have 48 million shares fully diluted out there. I think what we're telling you, is that if we find some, that we like and we announce it, then should be good. We do, I think, have a partner that will participate with us, which is KKR.

As a follow-up, let me ask -- yesterday we read Southwestern acquired more dry gas properties, a move that may suggest a bottoming of natural gas asset value. Do you believe natural gas asset values have bottomed? Where does acquiring more Haynesville and Bossier perspective leasehold rank among the options you are considering today?

Well, again, I commented. I think natural gas fundamentals right now, of course they're -- we think they're probably better than oil. Oil is $90, $95 and natural gas has gone from $2.04 a year ago to $4.40 or $4.50 this time. I think what you're seeing, is you're seeing companies be realistic about all the acreage that they've leased. That Southwestern deal, they bought 162,000 acres, whatever it was, maybe 2 million cubic feet of gas per day for $90 million-something. $500 an acre, they're really just buying production and a little bit for the leases. I think that there's going to be a tier one, two, and three in all these major plays, whether it's the Haynesville, the Bossier, the Barnett, the Marcellus, you can call it super rich, or whatever, but there's going to be a tier one, two, three.

I don't think you're going to have the frothiness that we had in '08, '09, '10, where people made big bets on leases and you had to drill them and all of a sudden you have a recession. You have a lot of foreign JV partners. I don't think we want that. When gas gets back in the $5 plus range, that some of the true tier one acreage will be very valuable.

I think you're starting to see a little shift toward that, although the rig count, if you look at the rig count, it's kind of interesting. You do your research. The rig count is at a 14-year low right now in April 2013. If you go back a year ago, natural gas in 2012 on the month of April was at a 14-year low. It took the rigs another year to hit that number. Now, this month, in 2013, gas is at a two-year high. I think you're seeing a tide turn, but I don't think you're seeing any craziness out there and I don't think you'll see it.

The rig counts with natural gas rigs went down last week by 13, 14 rigs, whatever. I think that's what, we're kind of the barometer out there. We are saying, we've got a tier one dry gas play in the Haynesville, Bossier. It goes from zero production to 7 billion a day in four years. We're still not putting any rigs in there just to drill wells. Because, we base it -- our capital dollars we spend we base it upon whatever the IRR will be. And right now, we have better places to put those dollars.

I appreciate the answers. Thank you.

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

I was wondering if you could talk a little bit more about the quality of the Eagle Ford acreage and some of the variation and EURs between north and south and whether the returns you're talking about are applicable to the portfolio, or just to parts of the assets?

Ray, this is Mark. We've talked a lot about our northern acreage being a lower rate of return and that's why we haven't focused the drilling up there, yet. We are drilling a well in the (inaudible) acreage at the time and those rate of returns are probably in the 20% to 30% range. Where as, as you work your way to the south, you're increasing to 40% to 50% to 60% rate of returns. The numbers we're talking about our average numbers across the whole portfolio and not just the stuff that's focused on the south end.

Okay. Got you.

I think, Ray, the luxury of this divestiture, again, in the Permian, it allows us to drill wells, the majority of these wells in McMullen, where in the past we had to kind of scatter them. We did have several wells we needed to drill the hold acreage.

In terms of -- you know, Mark, in terms of high grading the gas assets in the Haynesville, if you were to look at a batch, at the number of acres that work at $4.50 to $5, could you say what that is now?

Ray, we're working that problem, but we don't have answers to put out for public at this time. So, I'm really not going to get into that.

If you were to keep six rigs going in the Eagle Ford, can you talk about where you might get to on the production side on oil, by the end of next year?

I think Jay alluded to that a little earlier. He said, at the end of this year, we're in the 9,000 barrel a day range and at the end of next year, with a six rig program, of that's what we do, we are probably on the 14,000 barrel a day range. Something in that range.

That's great. Thank you.

Your next question comes from the line of Sean Sneeden with Oppenheimer. Please proceed.

Most of my questions were answered, but, Roland, just a question for you on the balance sheet. How do you think about leverage going forward? It sounds like you felt a little uncomfortable when you were looking at the leverage north of, say, 3.5 times. Would it be fair to say that you guys are thinking about trying to keep it under three times going forward?

Sean, I think that we definitely were a little uncomfortable with the leverage being where it is now, which is a little over four times. Some of that's caused by the low natural gas prices last year. Some of that corrects in a $4 plus world. Some of it's just the level of debt we were carrying. Then, the capital expenditure level versus cash flow. We were uncomfortable with that.

When we look at, going forward, our goal is to -- it's probably to be below, definitely below 3.5 times, three times is probably an okay level for us. Obviously, below three, that's a great level. We really want to be in the upper tier, as far as leverage of companies and I think staying below -- the very low threes to the high twos, as far as leverage ratio is where we want to be as a company. I think this transaction, immediately does put us into that new ballpark.

I would agree. Then, related, just given the rise in the forward gas curve. How do you guys think about adding hedges on the gas side at all?

We have been looking at the forward gas curve and it's amazingly flat, too. Even going out three, maybe four years, you almost get the same kind of price. It's an extremely flat curve. I think that we kind of see that potential hedging and of natural gas, natural gas production, a kind of go hand-in-hand with when we think the returns are adequate to start drilling again. I think the two will probably come together.

If we get to a level where we can get returns of 20%, 25% on capital spent. I think we might look -- if we look to put a program out there, we probably look to protect the new gas with a hedge. I don't see us with a real strong balance sheet we have, seeing a lot of need to try to lock in below those return levels. Just to lock in a certain level of cash flow. We want to be able to be competitive when gas prices do come back and not be locked into being very low return by having hedges in place.

A strong balance sheet will give us the ability to wait until the right time to start gas development again, versus prematurely jumping in now because that's the only thing we have to do.

Then, just one last question, on the balance sheet. Your most recent note, the 9.5, can you remind me, is there any mechanism that you guys have, in order to take those out earlier, to save on the interest expense?

Well, the only thing that comes -- a conventional -- we do have the equity claw-back kind of, as we did an equity offering we could retire some of those proceeds. Those are notes. And we don't really need to do an equity offering. Right now, those notes are going to be out there and we'll be able to take the second most expensive notes out, if we want to, in October. But, obviously, if you -- you could try to buy those in the open market, they are trading at very, very high premiums, as they should.

And, Jay, just one clarification. I think you mentioned you might entertain selling a stake of your Haynesville acreage? Just so I understand, are you planning to run a formal process there, or were you just throwing that out as an example of what you might do.

Number one, I never said we would sell anything, period. We are not selling anything. Asset sales is not a part of our story, period. If you heard that, and I said that, then I apologize and I didn't say it, though.

I think, Jay may have been commenting on -- if to the extent that we might want to acquire some future gas acres, that might be something we would do with a partner, but, as far as selling any existing assets, right now, we are not focused on that at all.

Right. We would not entertain that at all. In fact, I think, Sean, that's a great strength we have. We didn't have to liquidate a tier one gas play, or part of it, to fund other tier one regions that we had. No, asset sale is not part of our story at all. In two weeks, we'll have completed that. I think we want to inventory that, as Dan and Ray and Mark had mentioned earlier. When the fundamental gas price gets competitive to the Eagle Ford, then I think you'll see us have a Haynesville, Bossier drilling program. But we're not nearly there right now.

I apologize. I might have heard your previous --

I'm glad you brought that up. Because, somebody else heard that, and we will clarify that. That's a great sentence. Thank you.

Great. Thanks guys.

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

I was hoping you could talk a little bit more about the opportunities that you see in front of you. First, if you could just give us the thoughts on your location count, and this central McMullen acreage where you've been knocking out these great wells. And just talk in general terms about your running room there. Second, I'm interested to hear if you'd be adding acreage organically, or leasing outside of the Eagle Ford under some program that might be classified as a new ventures type of program.

Yes, Mike, this is Mark. As far as the Eagle Ford goes, you can see the map on page 25. The acreage -- and we need to get this labeled in the future, just so it's a little easier to talk about, the acreage farthest to the southeast is our house track, our Gloria Wheeler, Swensen lease. That is pretty well developed after 2013.

The rest of the acreage, and acreage on the northeastern corner of McMullen County is pretty well developed after 2013. We have a lot of locations left in our Forrest Wheeler area, which is the southernmost acreage. The Rancho Tres Hijos area, which is that really rectangular block, south of main McMullen, we have a lot of development room there. And so those we'll develop in 2014. Then, we'll concentrate more in our four-corners area, which is all the acreage in the corner of the four counties.

We have a lot of locations, probably 50 to 70 locations, just guessing here, in that area that we will develop and then we'll just continue working our way west and north, as long as gas prices allow, and allow us to maintain the returns that we want. We'll continue to develop the acreage west and north of there.

As far as padding, the opportunity is there and we can add acreage that we think gives us the proper rate of return in our core areas, we would do that. As far as new areas, we do have a business development team. They're the ones that had us deep in the Haynesville, Bossier back in third and fourth quarter of 2007. They're the ones that led us into the Eagle Ford, led us into Permian.

You will not see us making a purchase of a producing property. I mean, if we enter a new area, it will be kind of like how we entered the Eagle Ford and how we were entering Gaines County. I mean, Rosetta got a good property in Gaines County and we have a land group or two or three leasing acreage and that would be very inexpensive acreage. We would drill our way to prove it up. We don't plan to spend any real money on new areas.

Real quick, six rig Eagle Ford program, what's the ballpark number for quarterly CapEx?

I think when the six rigs are fully running, it's probably about $100 million, in that neighborhood. Based on that -- participating in the program.

That's about what I have, too, here. About 100 to $110 million a quarter.

Your next question comes from the line of Amir Arif, with Stifel. Please proceed.

Just one quick question. When we think about realized pricing in the Eagle Ford, should we be thinking about a discount LLS, or a premium to WTI in terms of how you've structured yourselves?

Well, I guess, it's price off of LLS. It's not priced off of WTI. As most of the oil production in the Eagle Ford, for most producers, is all LLS price because that's where the oil's actually going to that market. The relationship between WTI is just -- Eagle Ford oil is really just a function of the relationship between LLS and WTI.

Roland, what kind of a discount should I be thinking of off of LLS?

I think that -- historically, we have been averaging, if you take the difference between WTI and LLS, we've been capturing about half of that premium, in netback to us. I think as some new transportation arrangements are coming into place where we can go to more pipelines, we'd see that improving. But, those are still in the works. They haven't been finalized. Where we're located in McMullen, is kind of the heart of the Eagle Ford and there are some new oil pipelines even crossings some of our leases. We expect to stop trucking in the future and filling the pipelines, which will create a bigger premium and reduce some of the transportation cost.

If LLS is coming down relative to WTI, you still think your realized price can go up with the new pipeline options; is that what you're saying?

I think the overall transportation costs will go -- will be reduced. But, our index-based price will tie in with LLS. We'll just capture more of that premium with better transportation.

Sounds good. Thank you.

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

Just a couple questions on the Eagle Ford completions in 1Q. Mark, how do those compare to, say, what you did in 4Q? Lateral line completion stages, et cetera.

Richard, the lateral lengths, I don't have the exact number in front of me, but they've been a little bit longer in the first quarter. We've gotten on some leases that we had some long laterals planned. We're, on average, maybe 200 or 300 feet longer. Our number of stages really relates to lateral links. The longer wells, if you're 300 feet longer, you probably have one more stage in there. Where we were averaging about 15 stages, those might've been averaging 16 to 17 stages.

Okay, that's really --

We're still doing a little experimenting, also, with cluster spacing and frac size. We're testing that on a few wells, as well.

I guess the completions in 1Q were 15%, 20% that are IP on 30-day and 24-hour rate versus 4Q. Do think it's mainly a function of the longer lateral, or there's other factors in there, as well?

(multiple speakers). On the McMullen wells.

Some of that's lateral length. Some of it's just location. The Gloria Wheeler, obviously, by the numbers, is the best acreage block we have and we had a number of completions in there. Some of it may be location, but some of it's also lateral length and maybe frac size. We really don't have enough data to get some definitive answers on that, yet.

Remind us again, what's the net acreage split by county for McMullen and La Salle?

I don't have than in front of me, to tell you the truth.

Okay.

Call us back later.

We might. No, I don't have an updated report on that.

Lastly, I know you had mentioned, briefly, that your JV partner may look to participate in additional acreage acquisition in the Eagle Ford. Have they given you any indication there? Would it be just participate in the promote on the wells? Would it be paid part of the cost toward acreage acquisition?

That would have to be structured, Richard, with them. We could offer that. Unless it's a very tightly adjacent, I think there might be some -- to our acres where they might have some rights, we generally don't have an AMI. It would be something we do structure and offer as we saw fit.

They haven't really given you any indication on that?

We would present a deal, there's no reason to give an indication for something we haven't presented.

Okay. That's all for me, thanks, guys.

The final question will come from the line of Jack Aydin, with KeyBanc. Please proceed.

Thank you. All my questions were answered. Save your time.

Jack, you've got to ask one.

Well, if you want me to ask you, it's basically, I'm worried about the inventory, how you're going to address -- because if you're running six rigs in 2014, you're going to run through that inventory and I know you've got the cash and everything. I want to get a little more color how you are going to have that inventory.

Jack, have we ever not had not something to do? We've known you for -- you're 27 -years-old, now? How old are you, Jack?

18 years old. (laughter.)

Don't worry about our lack of inventory. If that's what you perceive us having. We've never had a problem with finding a place to spend money and making money. We addressed that early on.

Okay. Thank you.

Thank you. As always, Jack.

Ladies and gentlemen, that concludes the question and answer session. I will turn the call back over to Mr. Jay Allison for closing remarks. Please proceed.

Again, I would like -- this is a long conference call. It's like an hour and a half or so, which is unusual.

As always, and I know most of you, we try to put in a good day's work to create value on a per-share basis. I think the divestiture in the Permian is a win-win for Rosetta and for us. I think they're going to be wonderful there and I think we will do wonderful with accelerating Eagle Ford. But, we do guard our money carefully, because it's not ours, it's yours. We are trying to create a valuable stock. We thank you for staying with the conference call for an hour and a half and believing in us. That's it, Stephanie.

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