Comstock Resources Inc (CRK) 2013 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the second-quarter 2013 Comstock Resources, Incorporated earnings conference call. My name is Shaquana, and I will be your coordinator for today. At this time, all participants are in a listen-only mode. We will facilitate a question-and-answer session towards the end of this conference.

(Operator instructions)

I would now like to turn the presentation over to your host for today's call, Mr. Jay Allison, CEO of Comstock Resources. Please proceed, sir.

Thank you, Shaquana, and thanks for everyone that is participating in the conference call. Before we go over the 30 slides, I'd like to make an introduction. I know if you go back and you've been a long-time stakeholder of the Company, in 2010 Comstock produced very little oil. We were a pure natural gas company with the Haynesville being our marquee asset. Today that is a lot different.

Yes, we still own the 130,000-plus net acres in the Haynesville-Bossier, which is really inventoried until gas prices improve. But today we report the final results of the Permian acreage play, which we entered and exited really within a year, and how that event was a springboard for accelerating the other oil play that we're in, which is the Eagle Ford that we entered into beginning of 2010.

It is a rare occasion on a quarterly conference call that a company with an $816-million market cap, which is Comstock, can report on a quarterly call that it recognized a $231-million gain or $3.21 per share on the sale of an asset that it owned only for a year. But Comstock can report that news today.

That single event allowed Comstock to do several things. One, reduce net debt to capital from almost 60% to 33%. Two, provided Comstock with $764 million in liquidity. Three, it accelerated the Eagle Ford drilling program from a 42-gross-well program, which is what we had before the sale of the Permian, to a 72-gross-well Eagle Ford program. We added almost 30 gross wells as a result of the Permian sale. And finally, it allows our acquisitions group to focus again on the Eagle Ford and other oily plays in order to continue to create great wealth for the stakeholder, as it did with the sale of the Permian.

So with that, welcome to Comstock Resources second-quarter 2013 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 titled Second-Quarter 2013 results.

I am Jay Allison, Chief Executive Officer of Comstock. With me this morning are Roland Burns, our President and Chief Financial Officer, and Mark Williams, our Chief Operating Officer. During this call, we will discuss our 2013 second-quarter operating and financial results.

Slide 2 -- please refer to slide 2 in our presentations, and note that our discussions today will include forward-looking statements within the meaning of Securities laws. While we believe the expectations of such statements to be reasonable, there can be no assurance that such expectations will prove to be correct.

Our 2013 second-quarter highlights -- slide 3 summarizes our second-quarter results. The most significant item in the quarter is the recognition of a gain of $231 million, or $3.21 per share, from the sale of our west Texas properties, which was completed on May 14, 2013. Excluding the sale, our second-quarter operating results were defined by a strong growth in our oil production, and improved natural gas prices, offset in part by declining natural gas production. Our oil and gas sales, including gains from our hedging program, increased to $111 million in the second quarter. Our total EBITDAX was $89 million, and our total cash flow from operations was $67 million, or $1.43 per share.

Our Eagle Ford drilling program is providing strong oil production growth this year. Our oil production increased 26% from the first quarter, and is up 21% over last year's second quarter. Oil made up 19% of our total production in the second quarter, and is expected to average 20% this year. We expect our oil production this year to grow 28% to 34% over 2012.

In the first half of 2013, we drilled 25 successful Eagle Ford wells and also completed 25 wells which had an average per-well initial production rate of 796 barrels of oil equivalent per day. The 2013 completions have initial rates that are 23% higher than initial rates in 2012, while our drilling costs have decreased by 10%. We added three operated drilling rigs in June to bring our total rigs drilling to six, and plan to drill 47 more wells in the last half of this year. We have a very strong balance sheet after the west Texas divestiture. We have $764 million in liquidity, and our net debt decreased from 59% to 33% of our total capitalization.

Our west Texas divestiture, which is slide 4 -- please refer to slide 4 in our presentation, which summarizes the sale of our west Texas properties. On May 14, we completed the sale of our west Texas operations with Rosetta Resources, and received proceeds of $824 million, including reimbursements for capital expenditures incurred since January 1. We have reflected our west Texas properties as discontinued operations in our financial statements. Proved reserves related to these properties were 26.8 million barrels of oil equivalent and 1,700 BOE per day of our 2012 production. We realized a gain of $231 million in 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 estimate the current tax liability for this year will only be around $1 million.

I will now turn it over to Roland to review our second-quarter results in more detail. Roland?

Thanks Jay. Slide 5 shows our oil production from continuing operations by region on a daily basis for the last two years and the first two quarters of this year. This slide is a little different than the past because it is only reflecting continuing operations, and no longer reflects our discontinued west Texas operations.

Our oil production this quarter increased to 6,000 barrels per day, and was up 1,200 barrels per day, or 26%, over the first quarter of this year. Oil production this quarter was also 20% higher than the second quarter of 2012. Our Eagle Ford properties in south Texas averaged 5,800 barrels per day, as compared to 4,500 barrels per day in the first quarter. With increased drilling in the second half of this year, we expect our oil production from continuing operations to grow to approximately 2.3 to 2.4 million barrels in 2013, which is an increase of 28% to 34% over 2012.

Slide 6 shows our natural gas production from continuing operations, also on a daily basis. Our natural gas production declined by 10% to 156 million cubic feet per day, as compared to the 174 million per day we had in the first quarter. Production from our Haynesville and Bossier Wells, which is shown in dark blue on this slide, declined to 108 million per day this quarter.

Our remaining gas production only declined slightly as compared to the first quarter. Production from our Cotton Valley Wells, shown in green, averaged 24 million per day, and our south Texas gas production, shown in light blue, was 20 million per day. Other gas productions, shown in purple, was 4 million per day. We expect our natural gas production relating to our continuing operations to decline further this year to approximately 56 to 60 BCF, which is a decrease of 27% to 32% from 2012.

Slide 7 shows our realized oil prices relating to our continuing operations for the second quarter. Oil price realizations in south Texas continued to be strong in the second quarter of 2013, as we realized $100.06 per barrel, down slightly from the $101.79 per barrel we realized in the second quarter of 2012. With the Gulf Coast premium we received in the second quarter, our realized price averaged 107% of the average benchmark NYMEX WTI price. Recently, the premium of Gulf Coast crude to WTI has declined substantially with recent high WTI prices. Currently, we're receiving about $2 less than the WTI price in south Texas. 80% of our oil production was hedged in the quarter at a NYMEX WTI price of $98.69. After our hedging program, our realized price improved to $105.30 per barrel, 2% lower than the after-hedging oil price we averaged in the second quarter of 2012 of $107.71 per barrel.

Slide 8 shows our realized prices for the first six months of 2013, relating to the continuing operations. We realized $102.60 per barrel in the first six months of 2013, down slightly from the $103.44 per barrel we realized in the first half of 2012. This realized price was 109% of the average WTI price for this period. 85% of our production was hedged in the first six months of 2013 at a NYMEX WTI price of $98.69. So after our hedging program, our realized price improved to $107.89 per barrel, 3% higher than our after-hedging oil price we averaged in the first six months of 2012 of $104.97.

Slide 9 recaps our hedge position. We have an attractive oil hedge position, which protects the 2013 drilling program. We have 5,556 barrels per day hedged in the third quarter at $98.72, and about 6,000 barrels per day in the fourth quarter hedged at $98.67. We plan to hedge about 60% to 70% of our anticipated 2014 oil production.

Slide 10 shows our average gas price, which improved by 86% in the second quarter to $3.71 per MCF, as compared to $2 in the second quarter of 2012. Our realized gas price was 91% of the average NYMEX Henry Hub gas price for the quarter. Our average gas price improved by 48% in the first six months of 2013 to $3.42 per MCF, as compared to $2.31 in the first six months of 2012. Our realized gas price was 92% of the average NYMEX gas price for the first half of 2013.

On slide 11, we cover our oil and gas sales, including hedging. Our decline in natural gas production was offset by growth in our oil production and improved natural gas prices in the second quarter. Sales relating to our continuing operations increased by 19% to $111 million in the second quarter, as compared to $93 million in 2012 second quarter. Oil production made up 52% of total sales as compared to 53% in the second quarter of last year. Sales relating to our continuing operations increased by 6% to $208 million in the first six months of this year, as compared to $195 million in 2012's first six months. Oil production made up 51% of total sales, as compared to 48% in the first half of last year.

Our earnings before interest, taxes, depreciation, amortization and expiration expense, and other non-cash expenses, or EBITDAX, increased by 21% to $89 million from $73 million in 2012 second quarter, as shown on slide 12. $5 million of our EBITDAX in the second quarter was related to the discontinued west Texas operations, with $84 million attributable to our continuing operations. Our EBITDAX increased by 12% to $170 million from $152 million in 2012's first six months. $14 million of the EBITDAX in our first six months was related to discontinued west Texas operations, with $156 million attributable to our continuing operations.

Slide 13 covers our operating cash flow. Our operating cash flow for the quarter came in at $67 million, a 12% increase from cash flow of $60 million in 2012 second quarter. $1 million of our operating cash flow in the second quarter was related to discontinued west Texas operations, with $66 million attributable to our continuing operations. Our operating cash flow for the first six months was $129 million, a 2% increase from cash flow of $127 million in 2012's first six months. $7 million of our operating cash flow in the first six months was related to the discontinued west Texas operations, with $122 million attributable to our continuing operations.

On slide 14, we outline our earnings reported for the quarter and for the first half of the year. We reported net income of $130 million or $2.68 per share this quarter. $151 million or $3.13 per share related to our discontinued west Texas operations. Excluding discontinued operations, we had a net loss of $21.5 million or $0.45 per share.

We did have several items in the second-quarter results affecting the continuing operations net loss, including unrealized gains related to our oil hedges, and then impairments on unevaluated leases and producing properties. Excluding these items, we would have reported a net loss related to continuing operations of $0.32 per share, as compared to a recurring loss from continuing operations of $0.35 per share in 2012 second quarter.

For the first six months of 2013, net income was $103 million or $2.12 per share, as compared to net income of $9 million or $0.18 per share in 2012's first six months. Excluding the same unusual items, plus the gain we had on selling our marketable securities in the first quarter, we would've reported a net loss relating to continuing operations of $0.78 per share, as compared to our recurring loss from continuing operations of $0.62 per share for the same period in 2012.

On slide 15, we show our lifting cost per MCFE, produced by quarter, relating to our continuing operations. The lifting cost in this chart are comprised of three components -- production taxes, transportation and other field-level operating cost. Our total lifting cost increased $1.21 per MCFE in the second quarter of 2013, as compared to $0.90 in the second quarter of 2012 and $1.07 in the first quarter of 2013. The increase is mainly due to the lower natural gas volumes in the quarter and the fixed nature of much of the lifting cost. In addition, there were higher production taxes, which were relating to the stronger natural gas prices in the quarter. Production taxes in the quarter averaged $0.22 per MCFE, and our transportation cost averaged $0.25 per MCFE. Field operating costs in the quarter averaged $0.74 per MCFE this quarter.

On slide 16, we show our cash general-and-administrative expenses per MCFE produced by quarter, excluding stock-based compensation. Our G&A cost increased to $0.33 per MCFE in the second quarter of 2013, as compared to $0.23 per MCFE in the second quarter of 2012. G&A expenses per MCFE increased slightly over the first-quarter rate of $0.31. The increase is solely due to the lower production volumes on an MCFE basis this quarter.

Our depreciation, depletion and amortization per MCFE produced is shown on slide 17. Our DD&A rate in the second quarter averaged $4.87 per MCFE, as compared to our $3.54 rate in the second quarter of 2012 and the $4.60 that we averaged in the first quarter of this year. Again, the higher cost of our oil production, and then the write-down of undeveloped natural gas reserves that happened last year arising out of the very low natural gas prices, are cause of the higher rates in 2013.

On slide 18, we detail our capital expenditures relating to our continuing operations. Capital expenditures relating to our discontinued operations after January 1 were reimbursed to us as part of the sales price. We spent $133 million in the first six months of this year on our drilling program, as compared to the $240 million we spent in 2012's first six months. Capital expenditures for our south Texas region, shown in red, relate to our Eagle Ford drilling program, which decreased $120 million so far this year, as compared to the $144 million we spent in the first six months of last year. Lower well costs and then the promote that we're earning under the KKR joint venture account for the decrease. With low natural gas prices, our spending for our natural gas properties in north Louisiana declined only $13 million for the first six months of 2013, as compared to $96 million in the first half of 2012.

In total, our capital expenditures relating to our continuing operations of $133 million were funded primarily with $122 million that we generated from operating cash flow from our continuing operations. The funding gap of only about $11 million -- we only had a funding gap around $11 million for the first six months of 2013.

Slide 19 breaks out our 2013 drilling budget related to our continuing operations. We still expect to spend, and have budgeted, $347 million on our drilling program, with $312 million allocated to our Eagle Ford program and the remaining $32 million for any required drilling to hold our acreage in the Haynesville shale. In addition to the amount we're spending for drilling, we've budgeted to spend $12 million on acreage in 2013.

Slide 20 recaps our balance sheet at the end of the second quarter, which reflects the closing of the west Texas sale. At the end of the quarter, we had $264 million of cash on hand, and $883 million of total debt at June 30, bringing our net debt down to $619 million. We repaid the amount outstanding under our bank credit facility in May, which has a current borrowing base of $500 million, all of which [is] available. Our net debt is now 33% of our total capitalization, as compared to 59% at the end of the first quarter.

As shown on slide 21, on May 15, 2013, our Board of Directors declared our first dividend in the Company's history. Stockholders received $0.125 dividend per share in the second quarter, reflecting the substantial improvement to our balance sheet. The dividend only cost the Company about $6 million per quarter, and we expect to continue this dividend in the future. As we show on slide 21, less than one-third of the 61 E&P companies that we survey pay a dividend, and of those 61 companies, we had the second highest dividend yield of 3.2% at June 30.

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

Thank you, Roland, and good morning. On slide 22, we cover our south Texas operations, where all of the activity is in our oil-focused Eagle Ford shale play, which has identified resource potential of 78 million barrels of oil equivalent net to our interests. In the first six months of 2013, we drilled 25 horizontal wells, 15.2 net wells, and had 6 wells, or 3.7 net, drilling as of June 30. We have also completed 25, or 15.4 net wells -- horizontal Eagle Ford shale wells, including 6 -- 3.8 net -- wells that were drilled in 2012. The 25 Eagle Ford shale wells that were completed this year had an average per-well initial production rate of 796 barrels of oil equivalent per day.

Slides 23 and 24 show the results and locations of the 72 wells which are currently producing. We completed 15 more Eagle Ford shale wells since our last update. They are wells number 15 through 72 on this list. The 72 Eagle Ford shale wells that were completed had an average per-well initial production rate of 735 barrels of oil equivalent 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 583 BOE per day, and the 90-day per-well production rate averaged 484 BOE per day, or 66% of the initial 24-hour rate. The 2013 completions have initial rates that are 23% higher than the initial rates we obtained in 2012. The four wells with the highest initial production rates were the Forrest Wheeler C#1, the Swenson B#1, the Swenson A#1 and the Swenson B#2. These wells are all located in McMullen County, and had initial production rates of 1,337, 1,322, 1,222 and 1,143 BOE per day, respectively.

Slide 24 shows the location of the 72 producing Eagle Ford wells on our acreage. A well location marked in red indicates it was drilled this year, while the yellow locations were drilled between 2010 and 2012.

On slide 25, we show how the cost of our Eagle Ford wells have come down considerably since we started drilling in August 2010. In 2010, our first two wells averaged $11.4 million. Costs have fallen to an average of $8.1 million per well in the first half of this year. Faster drill times and lower well stimulation costs account for much of the savings.

We expect the average Eagle Ford well to cost $7.7 million in the second half of this year. On the far right, you can see the effect of the KKR promote on Comstock's realized well costs. The effective average well cost to Comstock on an [8H] basis improves to $6.7 million when you consider the promote.

On slide 26, we show the progression of lateral length over time in the Eagle Ford. Even though costs have come down considerably, the lateral length has increased almost 50% since our drilling program began in 2010. The average lateral length was 6,840 feet in 2013, as compared to only 4,595 feet in 2010. This increase is a function of our increased confidence in executing these longer laterals without complications, and our goal of maximizing our rate of return, as well as efficient utilization of our acreage.

On slide 27, we show the increase in proppant pumped since our program began in 2010. 50% of this increase is due to the increasing lateral length, if you keep the pounds per foot the same. We pumped 8.9 million pounds of proppant this year per well, as compared to 4.4 million pounds per well in 2010. And even considering lateral length, we have increased the amount of profit per lateral foot by 35% since we started in 2010.

Slide 28 shows the location of the 72 Eagle Ford wells that we have planned for 2013. We are currently operating six drilling rigs, and plan to maintain that number through the end of the year. You can see the high concentration of wells planned for McMullen County, where we have achieved the best results so far.

Slide 29 shows the net Eagle Ford wells being put on production per month so far in 2013, and what is projected for the rest of the year based on running a six-rig program. The monthly variation is due to multi-well pad drilling and subsequent multi-well stimulation operations, which creates lumpiness in our Eagle Ford production curve in 2013. Production in the first quarter was affected by the low number of completions in that quarter. Third- and fourth-quarter Eagle Ford production will benefit from the increased number of completions due to doubling the rig count. The large increase in completions in December is due to [4] four-well pads being drilled and then completed simultaneously. This activity will provide substantial momentum into the first quarter of 2014.

I'll now turn it back over to Jay.

Thanks, Mark. And again, thanks, Roland. If everyone would look on slide 30, it's the 2013 outlook. On slide 30, I'll summarize our outlook for the rest of the year. Even though natural gas prices are improving, 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 a high return on those projects.

We expect the strong growth in our oil production will more than offset the natural gas production declines we're facing to allow us to have higher revenues and cash flow, and be a much more profitable company in 2013 and 2014. We expect oil to comprise 20% of 2013's production, even after the sale of our Permian Basin properties, and will grow to 40% by the end of next year. 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 have ramped up our high-return Eagle Ford program, and will drill 72 wells by the end of the year.

We continue to have one of the lowest overall cost structures in the industry. We now have a very strong balance sheet after the west Texas divestiture, and we have $764 million in liquidity. And our net debt has improved to 33% of total capitalization from 59% at the end of the first quarter.

For the rest of the call, we'll take questions only from the research analysts who follow the stock. We will now open it up for questions.

(Operator instructions)

The first question comes from the line of Brian Corales representing Howard Weil. Please proceed.

Hello. Just a couple questions, mainly with the Eagle Ford. Good job with the longer laterals and more profit with lower cost. Is that mostly pad drilling? Can you maybe comment on what the main driver is there?

Brian, it's a combination of pad drilling and getting our days down. We've become more efficient drilling these wells and also the better contract that we received this year for frac services. Frac costs have come down. Some of the ancillary costs have come down -- coiled tubing, other things like that. So its a combination but the two big ones are drill times and our stimulation costs.

And Mark, how many wells can one rig drill a year?

Well, depending on whether that is pad drilling a not, about 14 or 15 a year on average.

Okay. And then looking at your inventory in the Eagle Ford, what are you all estimating now -- number of wells per section or spacing or whatever you want to talk towards?

We're averaging 65 to 80 acres per well, is kind of our average spacing. A lot of it is -- acreage is dependent on lateral length. So it varies. These long laterals use more acres, but the well spacing between wells stays the same.

Okay. And Jay maybe this is for you -- kind of a bigger picture as you go on for the next couple years. Can you add more acreage in the Eagle Ford? What is the pace of development? What is kind of the next step once you get towards developing the entire block that you all have currently?

Again, I think at the very beginning I mentioned in 2010, we had just entered the Eagle Ford. We got our 27,000 or 28,000 net acres at the same time with the Permian. We were 98% natural gas company, as you well know, because we've known you for a long time. And we did transition into two Tier 1 oil plays, and then we transitioned out of one with a tremendous profit. And we were in both of those plays -- we didn't have really the balance sheet to add acreage in Eagle Ford.

We would see acreage come, and I think there's a lot of fringe acreage on the market. We're not interested in that. We are now looking to add core Eagle Ford acreage. And as we drill a certain amount of wells in any given year, our corporate goal at a minimum is to replace that drilled acreage with new acreage that we have leased.

So we continue to add another year's worth of inventory at a minimum. I think the market will probably allow us to do that. There is lease expiration issues, there's mineral owners that are out there that we had visited with earlier that we couldn't do anything with. I think today that is one of the reasons that I opened it up to say the launching pad for us is to clean up our balance sheet and then really to dig down in the Eagle Ford and add to that position. You do not have to add a lot of acreage to replace a year's worth of drilling.

You add 6,000 or 7,000 acres that's important and you've replaced a year's worth of drilling. And I think if we continue to do that, at a minimum for several years, and gas prices do come back in the 450 range, take a number, then we have got a deep inventory of drilling in Tier 1 Haynesville. So, I think that's our plan. Our plan was not get a train wreck on our balance sheet. Our plan was not to dilute the shareholders by some type of strange financing or equity.

Our plan was to inventory the Haynesville and Bossier, at the same time unlock the value in the Eagle Ford, which we were not able to do when we owned the Permian asset. You noticed that we've gone from three rigs to six rigs and we did that instantly. We really accelerated that program probably six weeks earlier than we had predicted because of rig availability. And then I think you see our lumpiness, which is the next to the last chart.

It kind of goes away a starting in 2014, even with pad site drilling. I think you asked Mark a good question about the low cost, and that is, the fracking costs have come down materially but it's pad site drilling. But if you only have one or two rigs out there you can't create real wealth for the stock holders in that play because you can't bring in these economies of scale and reduce those costs.

So you have seen us, year after year after year, whether it's the sale of our Gulf properties to Stone in '08 or whether it's entering the Eagle Ford, which we are obviously correct on our acreage position, or the entrance in the Permian, which we were correct on, because Rosetta paid for that. We've never ever had an issue creating wealth by adding to acreage or adding to a new play, and we don't see that as a problem right now with the Company.

I think that's the single loudest cry that we hear from the public is, well what are you going to do after year three or so. If they been screaming like that in 2010, look what happens in 2010 and '11 and '12 and what we have done to create wealth on a per-share basis. That's why, today, to report that you had $231 million of profits in a year and $1 million of taxes, it's pretty phenomenal.

And I felt like we had cornered our acquisitions in new development departments so that we really could not continue to add that wealth. We were struggling with the development or fracking into the Permian and I don't think that was good for us. So I hope that, in a way, answers your question.

That was helpful. Thank you guys.

Your next question comes from the line of Marshall Carver representing Heikkinen Energy Advisors. Please proceed.

Yes, first on the well costs, you're guiding to $7.7 million wells in the back half of this year versus 8.1 for the first half. Where are you currently on well costs? Have you already gotten close to that $7.7 million, or where does that stand?

Yes, Marshall this is Mark. I believe we are basically at that number now and it's just that at the beginning of the year we still had some of those carryover costs with the higher stimulations in the first part of the year. So, I think we are really at that number and we should carry that through the year.

Okay, thank you. On the current production, do you have a current production rate you could give us? You had quite a number of completions in July and just wanted to see where that current production stands.

No, Marshall I don't have a current production number in front of me.

Okay. Do still think at least 9,000 barrels a day towards the end of the year is feasible? Would that be even higher now that you've got such a slug of December completions? What are your current thoughts on an exit rate?

I think that's pretty close to what our exit rate is projected to be. The December completions come on during the month and late in the month, so I don't know if they're going to have much impact on December production. They might have a little bit of an impact but probably more impact on January production than on December production.

Right.

Marshall, I think that with that large number of completions in December, the exit rate could be unusually high or impacted by that group depending on the exact day they come on. But for the quarter, I think, in our overall guidance, we feel like we're a little ahead of schedule and have an upward bias to our range right now and oil production. But the actual exit rate will be a real function of those 4 well pads. If they all come on before December 31, then we could probably have a higher exit than 9,000 barrels a day, but they all come on January 1 --

Sure.

And I think again, what the divestiture of the Permian has allowed us to do by the third or fourth quarter -- we'll have two fracking crews working, not just one. Periodically we'll have two. And I think 2014 -- a bogey out there is 14,000 barrels a day as an exit rate in 2014. I think if we keep with this program that's very achievable. Now, it goes back to a question asked earlier. We're so fluid here -- you can see in the Bossier we spent $13 million or $14 million this year and that's kind of all we have to spend in 2013 and probably the same will hold true in 2014.

We don't have to spend a lot of money in the Haynesville-Bossier to inventory this 6 TCFE of upside we think we have for resource. It's the same thing in the Eagle Ford.

Maybe we have to drill several wells in 2014 and in Eagle Ford, which are obligation wells, but we can control that whole program based upon where commodity prices are. I think that goes back to the slide that Roland read too. Our goal in 2014 is to hedge 60% to 70% of our oil production. So we'll be putting in this program in Eagle Ford in 2014, kind of at the end of the year, but if we want to have material growth in oil, I think we can.

You know the core area we're in, you know the cost, you know the balance sheet. Our CapEx almost equals our operating cash flow. So those things are good and now you have to go well, are you adding more acreage. And the answer is, I think we'll be able to do that in Eagle Ford. Time will tell, but that's where we are.

Thank you.

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

Yes, Mark, I was wondering if you could talk a little bit more about Atascosa County, the result from the NWR well and whether -- I know the location count doesn't include anything really for that part of Atascosa. Have your thoughts changed at all there?

Ray, we are still evaluating that well. It just came on production not long ago, and we're still interested to see how it performs. It is a long lateral, so we don't know how that is going to affect the decline curve on that well. So I guess the jury is still out on that acreage. Most of that acreage up there, we have said over and over that we have discounted it, that really we don't think it has much value, and we are still on the fence on that right now.

Okay, got it. And how about in terms of apples to apples comparisons in the second quarter versus the first quarter? I guess what it seemed to me was happening was you were drilling in areas that you knew would probably not be quite as prolific within McMullen.

Yet it seemed like the rates were a little higher than other wells you drilled in those areas. I'm just trying to get a handle on what -- I know some parts of McMullen are not as prolific. What are you seeing with the new artificial lift and new completion techniques in one area versus another?

Generally speaking, as you go from north to south on our acreage in McMullen County the IP rates go down when we go up north. So on the northern end you're looking at lower IP rates, and they improve when you get down to the Gloria Wheeler, the Swenson, the Forrest Wheeler acreage. The EURs don't change nearly as drastically as the IP rates, so the wells to the north, they're a little lower reservoir pressure. They tend to be flatter. They have a lower first year decline rate than the wells to the south.

So the performance is probably not quite as good on a rate of return basis, but not too dissimilar. So we've really been very pleased with almost all of our acreage, or I guess all of our acreage in McMullen County and then the acreage that flows over into LaSalle, as well. So I don't know if that answers your question but, that is kind of my impression.

That's a good answer. So the map that shows your '13 activity -- it looks like you're going to have one more Atascosa well this year. Is that right?

We have an obligation well that we have to spud up there in late 2013, so we will evaluate the NWR and determine whether we want to drill that well or not.

Got it. Thanks Mark.

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

Good morning guys, just a couple questions. Just a follow-on I think to raise a previous question. If you look at the 25 wells you drilled year-to-date and the 47 remaining wells, can you provide any kind of census to where your 47 wells are located? Are they more concentrated towards the southern part -- the Gloria Wheeler, Swenson area of McMullen county or are they spread across most of your box that you show on slide 24 in McMullen County.

Ron, this is Mark. I haven't broken it down exactly. But guessing, it's probably 60/40 from the south to the north, as far as remaining wells in McMullen County.

Okay, maybe this is one for you Jay. Your relationship with KKR from, not just a drilling carry standpoint on this acreage, but can you talk a little about how that relationship has progressed, what their appetite is in terms of potentially expanding acreage in the play and or -- private equity firms usually have a number of portfolio companies. Is that relationship also -- can it potentially benefit you in the sense that if they have any portfolio companies that have attractive acreage positions?

Yes, you know, I think if this were a classroom we'd probably get an A+ for relationship. And the reason is, they have come in and we have de-risked the Eagle Ford for the most part. They've been in and out of, I think, six different deals in the Eagle Ford, so they're very knowledgeable about the play. They come in in our acreage, and they can't cherry pick, so they are in all of it more or less.

And all of a sudden, our costs come down. These were $9 million, $10 million, $11 million wells several years ago, as you've seen and now they're $7.7 million. And all of a sudden production goes up 200 or 300 barrels or more per day as an IP rate. So if you are KKR and all of the sudden cost comes down and production goes up a lot and now all of a sudden we go from three rigs to six rigs and you're wanting to aggressively develop the Eagle Ford when oil is $100 plus dollars.

We're one of their best investments period. And they would like, I think, from our discussions, if we can duplicate this and add under Eagle Ford acreage, I think they would expect a phone call from us to be a partner. I have nothing but excellent news from our relationship with KKR period. And again, this time last year we didn't have that and I think it does give us a little more strength and we didn't have it last year.

Right. And Mark, from a well-designed completion standpoint, whether it be lateral length or proppents, you never stop learning, but do you think you're pretty well honed in on the best way to complete these wells? Are there any major variances in terms of how you complete them? The northern part versus the southern part?

As far as geographically Ron, no. We are doing pretty much the same thing in both areas. We do change the fluid design a little bit in the northern area. We try to pump less fluid just because it's lower pressure and it's harder to get the fluid back out, so I think we do tend to limit the fluid used in the north area.

We have been testing some different things in terms of pounds per lateral foot and cluster spacing and we're really just going through another round of that and waiting on results now. We need time to see how that impacted performance. But I think generally we've honed in on the design we like and we're going forward with that, generally.

All right I think that's all I have. Thank you, guys.

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

Thanks, guys. Good morning. Jay, in regards to new leasing efforts can you talk about what areas you are targeting specifically and maybe what acreage costs look like? I'm trying to estimate what the total acreage spend will be if you are successful in picking up the 6,000 to 7,000 acres in a year.

I really can't tell you where we're trying to lease other than if you look at a traditional geological map where the core of the Eagle Ford is. I think what you need to know is that we are not looking for some pricey acquisition. We're not looking for some pricey acreage. We are looking for some bolt on acreage in and around our core and all the way to the north.

As you know, we have been in "South Texas" for probably 15 years. The Eagle Ford was a new play for us in 2010. But we have got a lot of good will spread in the whole part of that country and our geologists have been very good at locating the right core acreage that we need. And I think we feel internally, Mike, that we have got a really good chance of delivering on our goal.

And our goal again is, however many acres that we would drill up in a given year, we want to add that many more acres as a minimum for inventory. We don't want depleted inventory year after year after year. We want to keep the same inventory that we have now and or add to that if we can. That is our corporate goal and I think we will be able to do that.

Okay. Would you be able to -- is there opportunity to add -- let's call it 2000 acre blocks that are bolt on to your core McMullen acreage at approximately 5,000 to 6,000 an acre. Does that sound reasonable?

Mike, if you have some of that you ought to shoot us an e-mail and we will talk about it. (laughter)

I'm sticking with research.

That's fringe acreage. Because we went in in 2010 and paid -- I think we had $4,000 in the whole program. And then you have seen some fringe acreage deals completed, we think, but we're not interested in that either. In other words, we're not interested in having a lot of acreage just to tell you have a lot of acreage. If we have acreage, then it should be all drill-able acreage and you should divide it by 65 or 80 acres and say we have added this many new locations. That's what we are looking for.

Okay and in regards your guidance an exit rate goals, correct me if I'm wrong here, but it sounds like the competencies there, that you are more towards the higher end of this year's oil production range barring anything extraordinary. I'm really interested in the factors that might cause you to come in either above or below that 2014 exit rate goal of the 14,000 a day on the oil side. If you could talk to that a little more I would appreciate it. Thanks.

I think one, and then I will turn it over to Mark. We have to put a CapEx program together for 2014 which is a six rig program, whatever, in order to hit that 14,000 net barrels production in 2014. We've not advertised that that is what we're going to do. We've said that with oil prices where they are and gas prices where they are we are going to stay the course right now. But we do have flexibility to change that. I will turn it over to Mark.

Yes, Mike, it's Mark. I think that's basically it. We don't have an approved budget yet to -- we've don't projections and what-ifs. We don't have our approved budget for '14 that goes that far or that makes that exit rate. I think we can make that number or come very close to it or be a little above it or somewhere in that vicinity if we run the six rigs through next year. I feel comfortable with that. We've got the inventory to do it.

We've built the what-if program that shows us that and I think timing of the completions can affect that a little bit. If we drilled a bunch of four well pad wells all in a row and ended up pushing it off until late December next year or January, just like we're doing this year, then it did kind of affect your exit rate slightly. But that is the only thing that I would say, other than going a different direction if gas prices improve, or if we get into another play that requires us to use some of our cash flow for that play rather than this one then that would affect those numbers.

Right. There is nothing within the Eagle Ford boundary that would cause us to not hit those numbers in our opinion. The acreage is there, the rigs are there, the frac crews are there. It would just be if we changed that business plan.

Okay. Thank you, guys.

Your next question comes from the line of John Freeman representing Raymond James. Please proceed.

Good morning, guys. You talked about the flexibility with the budget next year. Can you give me a rough idea of when the various rigs would be scheduled to roll off the contracts?

Jonah, this is Mark. Most of our rigs are under six-month contracts. So they roll off, we have rigs rolling off every couple of months. We have two rigs that are long-term contracts that are 2015 expirations. But the other four are all short-term rigs so we have a lot of flexibility on that.

Okay, great. Mark, you have spoken pretty consistently in the past about you feel like the 500 foot spacing pattern is pretty well established and so then really the only consideration is how long the lateral length is. I'm curious - obviously your lateral links have been going up this year. What is the longest lateral that you all have tried? And when do you think we will have a better idea of whether the -- let's say a longer lateral, call it a 9,000 foot on a 90 acre spacing is appropriate or maybe more what you are doing close to 78 or 80 acres is appropriate?

Jonah, you are correct on the 500 foot. We have been consistent about that and we're staying with that program of keeping wells about 500 feet apart. Give or take our acreage sometimes of your acreage is shaped a certain way, maybe ended 470 feet or 530 feet apart or something like that. As far as longest well, I think that NWR #2 in Atascosa County is our longest completion to date.

It's about 10,200 feet. We've had several more very close to that, around 10,000 or just a little under and really it depends -- sorry about that it's John, not Jonah. Really, we are trying to utilize our acreage. We maybe drilling one unit up that are all 6,000 footers, because that's the way it spaces out because we don't think we can drill 12,000 footers, or the unit is just that long.

And another place we're drilling 9,000 or 9,500 footers because of the shape of the acreage. We are trying to use every acre effectively, and that really is what drives lateral length as much as anything. We know that we need at least 4,000 feet in the south and probably 5,000 or 5,500 feet in the north to be economic, to make our numbers. Anything above that is just utilizing acreage efficiently.

Great. Thanks, guys. That's all I've got.

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

Thank you, folks. Good morning. If I could maybe ask a more theoretical question here. Do you look at the Eagle Ford and maybe oil assets in general as a bridge to a higher natural gas price environment where returns at the field level could be better and operations maybe more scalable? In answering that question can you speak to the natural gas price? The Haynesville and Bossier are competitive on returns with your McMullen County Eagle Ford?

Let me tell you what we try to do. We try to create wealth on a per-share basis and about 45 minutes ago we told you for this quarter, each shareholder got $3.21 per share of a gain of the $231 million of profits we made in the year. So if you take the denominator as what you can do to create wealth on a per-share basis, we just created $3.21 per share and in 2010 we were a 98% natural gas company.

Second of all, we're not going to rupture ourself with a balance sheet that is stretched all over to investment banking heaven. We are not going to do that. We're not going to put ourself off the ledge. So I think what we had to do was we had to come in and find some oil plays. We found two major oil plays, obviously. One we got out of and the second one we kept. And we kept it because I think you are exactly right.

I think not many companies our size have been able to bridge themselves with oil right now, that they control, with an unbelievable partner like KKR with years of drilling that is pretty predictable -- as some of the questions have been asked about predictability. So now you get to the value of Haynesville. We have 1200, 1300, 1400, 1600 locations or whatever. When you get somewhere in the $4.50, $5 gas price depends upon what these wells might cost.

And we have looked at, theoretically, do you drill section, section and a half wells in the core area of Haynesville, what kind of return would we get? I think when you get into $4.30 price to $4.50 price, and it's not just a flash in the plan, a day price, but it's a 12-month strip type price.

Then I think some of the prospects that we have in the core, not all of that 130,000 net acres, but the core acreage in the Haynesville, I think some of that would be competitive in the Eagle Ford. So we don't advertise, again, we make a bold statement that where gas prices are, we're not accelerating our drilling program. But you can just believe in the years to come that with demand increasing and rig count kind of down and production pretty flat overall for natural gas on a daily basis, that the commodity will swing around and be $4.50, $5 commodity -- maybe more.

We cannot run the company based upon that program in two years, but you can certainly run the company based upon the inventorying and the golden egg for the future. I think that's what we have done.

I appreciate that.

Maybe little stronger than they are today but we're certainly pleased where prices are today versus the $1.90 a year ago. So, I think if we're talking just theoretical -- and I think we have always communicated that to you and everybody else about what our corporate plan is.

I appreciate that answer, Jay. On the subject of shareholder value, how do you view acquisitions or how do acquisitions compare to buy back stock in terms of creating wealth for shareholders?

I don't think you spend money buying back shares, if it causes you to give up a good acquisition, and/or if it causes you not to add meaningful core acreage in the Eagle Ford, then I think you shouldn't be buying your shares back. But I think, again, our credit line, we had a borrowing base of $570 million when we owned the Permian. After we sold the Permian our borrowing base was reduced to $500 million.

We only lost $70 million in our whole borrowing base and that was an $824 million event. So, I think we became much stronger and we needed to become much stronger. So it is unusual, again. You have got a company -- if you look today look on the ticker we're probably $800 million in market capital, we have $760 million odd of liquidity, and we're gas rich and we're now starting to be oil-rich. Because by the end of 2014 we think 40% of our production will be from oil.

So, I think what we tried to communicate with the shareholders who own this Company, we will take risks, we will not be reckless in anything we do. We are inventorying the Haynesville Bossier. People call all the time and want you to put some rigs into drilling and we don't need to. We've demonstrated we don't need to. At the same time, again, in 2010 and '11 and '12 we didn't have hardly any oil.

We have been in and out of material oil, and it is almost laughable within our organization to think that we can't add acreage between now and year-end or now and the end of 2014 in the core area being the Eagle Ford or another core area, because we always have. So that may be a fear of the public, but it is definitely not a fear of management or the board. So that's how we look at all that.

I understand. And one last one for me, if I may, just for modeling purposes here. Can you estimate for me or express for me the decline rate on natural gas production on the underlying natural gas production and how that might change over the next one to two years? Again, just for modeling purposes.

We said it may be a size 32% this year in Haynesville Bossier. Again, we added a couple of wells which we had to drill and I think next year will probably be 15% or 18% in the Haynesville Bossier.

For total company, yes.

Yes, total company. That's probably the number that you use.

Much appreciated. Thank you again.

Your next question comes from Cameron Horwitz representing U.S. Capital Advisors. Please proceed.

Hello guys. Good morning. Mark, following up on what was asked earlier -- maybe I'll ask it a different way. If you take the geography out of the equation, can you kind of quantify what performance improvement, if any, you are seeing maybe on a lateral foot basis as you have run these more intensive fracture stimulations?

I don't have that in front of me, and it's really an ongoing process. I don't know that we have enough data to give you real definitive number yet. We are still evaluating what we get out of longer laterals and what we get out of the tighter cluster spacing, the more pounds per foot. I really just don't have that number here.

Okay. I guess with some of the improvements in well costs at least, what are you guys internally estimating from a rate of return perspective for the go forward Eagle Ford inventory?

Cameron, this is Roland. With the wells that are obviously with the venture, we think the greater return to Comstock is approaching 50% for the investment for the drilling capital spent. Obviously, it's going to vary which part of the section you are in. But it is very strong for the overall program.

Okay, I appreciate that.

(Inaudible) those returns in our other areas right now especially on the gas side. That is where the capital is going to be focused.

Sure. And lastly Mark, can you just remind us looking at the map here on that Y-Bar leasehold that you have there. What the expectations for this acreage, given it looks like the only major block you haven't drilled a well on yet?

Yes, but there has been a lot of drilling around it and the performance of that has been very, very similar to our acreage just to the east, our Carlson and Hubbard acreage. But we really expect it to perform like that. It just had a lot more term on those leases. They were leases and we have a lot more term and we were able to put it into the schedule a little bit later. That will be a big focus in our 2014 program.

Okay. Thanks a lot. I appreciate it.

Thank you.

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

Good morning and thank you for taking the questions. Maybe as a follow-up to one of the previous questions. With the sale of the Permian, because as you outlined Roland, you have $264 million of cash in the balance sheet. Could you maybe discuss what you might look to use that cash for over time? And I know you have talked about a potential re-fi of the 8.375% senior notes which become callable in October? Or maybe could you just prioritize again what you think you might want to use that cash for?

Sure, Sean. I think that the top priority right now -- we plan to, kind of depending on what the interest rate environment looks like in the overall liquidity market looks like at that when we can actually issue the call. But calling the bonds, the 8.375% bonds, which are callable on October 15 is kind of what we are right now considering something we would do.

I don't think that we really plan to refinance those at this time or issue new bonds because we'd like to re-balance our debt between the lower cost bank debt and the bonds. So that is at the top of our agenda. Of course we have other -- we have an authorization for the stock buyback to the extent that we want to buy shares back also. And then the other priority with us would obviously be any type of acreage opportunities that would be real attractive.

Okay, got you. And then just broadly speaking, can you discuss about how you think about balancing, paying and or growing the dividend with liquidity and leverage. Are there any particular targets you're looking to maintain? For instance are you planning to spend cash flow or anything like that? That would be helpful.

Sure. The dividend payment, the dividend is about $6 million a quarter, so we reviewed the level as a very good level for the Company given today's environment where commodity prices are. So, we're not really targeting a particular yield at all. The average yield for our space for the dividend payers is 1%, so the 3% yield's more of a function of the lower stock price right now than anything else.

But definitely the dividend is something that we do not want it to cause us to spend less on the drilling program, or get in the way of acreage acquisitions, or increase the leverage to a point that is not optimal for the Company, and we feel like right now it fits in very well. Our goal is for 2014 to have a capital program that is fully funded with operating cash flow and we think that that's what this fixed rate program would appear to be, based on commodity prices and, as we put our hedges in place.

Before we approve that capital budget we'll have more certainty to that. So we think the dividend fits well with all those objectives. So again, we don't have a lot of shares outstanding, so I think when people look at the dividend, it's not a very costly item to our cash flow compared to many other companies with a lot of shares outstanding.

Sure. That make sense. And then just one last one from me. I think you mentioned your target hedging on the oil side for next year. But you didn't mention anything for gas. Are you guys still planning to be largely unhedged, just given where we are before the curve?

Yes, I think we would look to add gas hedges when we look to drill gas again. So I think that right now the forward curve doesn't support drilling for next year or this year as far as we're concerned. So, yes we would not see to hedge that either.

Okay great. Thank you very much.

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

Thanks and good morning guys. Just a quick question on the Permian sale and the low tax impact of it. Is that going to change your 100% deferred tax rate for the foreseeable future for the next year or so?

It really has no impact. We had given a couple of years of low gas prices and a couple of years of high drilling and a lot of dollars spent on drilling programs. We had generated both NOLs and IDC that we didn't use that were able to shield that very large gain that we made on the Permian sell. We still have some of those attributes remaining, but really the deferral of most of the current taxes is really a function of our drilling expenditures, and as long as we are primarily spending our cash flow for drilling, we will be able to defer most of the current taxes and continue to push those out.

Okay and then for Eagle Ford -- can just quantify how much acreage has been added relative to total acreage? And when the acreage expirations would start to come in terms of when you will have to either decide to let it go or drill it?

I don't have a count in front of me of that acreage that is still under primary term. It is probably 2,000 or 3000 acres still under primary term. The acreage on the east side is all HBP. The Lucas, the DVR, the Mesquite Wells, they held all that acreage. So really, it is a pretty small acreage block that is remaining in terms of any decision-making. And that really goes out later this year and probably into '14. Actually, we have an obligation well to drill I think in November or December, and that is a decision point. So, we will decide then what we want to do with that acreage.

Okay. And the $12 million that you lay out for leasehold costs this year, is that specifically for Haynesville, or is that also in the Eagle Ford, or is that also new acreage and new plays?

That is an overall budget, Amir which includes capitalized interest. I think we won't have a lot of capitalized interests for the second half of the year given that a lot of our unevaluated, we sold a lot of our unevaluated acreage to Rosetta, and then also the Eagle Ford is quickly becoming fairly evaluated. So, I think we only had like $5 million of that number so far in the first six months of the year.

We look at lease acquisition opportunities on a case-by-case basis versus setting a big program and a number. So that would handle all of the normal recurring things that you have such as free capitalized interest or other kinds of renewals that we had planned to do. But it would not encompass a very large acreage purchase that we have not specifically identified.

Okay and were those renewals in Eagle Ford, are is it mostly just in the Haynesville?

There are a few places we might have a very inexpensive renewal. But you can tell it is a pretty small dollar amount so they are not very material in either play.

Okay. And just a final question. I know you guys mentioned that you feel the market is overly concerned about the inventory and you guys have always been able to create opportunities. What inventory level in terms of your six rig drilling program would you feel that you need to get something done? Is it once to get down to a year or year and a half or two years?

We'd always like to have a three-year program. That's kind of the comfort zone. A couple of years we don't have a hiccup, one year is a little taxing. Puts a little more pressure on you. But I think if we had a strong three-year drilling program that would be really good.

Okay sounds good. Thank you.

You have a question from the line of Ron Mills representing Johnson Rice. Please proceed.

One last real quick one. I'm assuming, Mark or Jay, from a lease expiration standpoint, not really from comp stocks, but where are we in the lifecycle of the Eagle Ford leases in terms of industry primary term coming up on expirations? Is that one of the primary sources here of bolt on opportunities? Or, am I too early in that assumption?

No, Ron we believe that is a part of it. There's a lot of acreage that was picked up anywhere from 2007 to 2010 that is coming up. Some of it has extension rights, some of it doesn't. We think companies are just going to struggle to getting some of their smaller acreage blocks and some of that will become available.

Okay, perfect. Thank you.

Thank you Ron.

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

Quick question, guys on CapEx for the year. So the 1.6 wells that -- in the Haynesville -- that were supposed to be drilled, operated by others. Is that going to get drilled by year-end? And then I have a quick follow up.

Yes, Rehan, this is Roland. Right now we have not had any outside operated proposals for the Haynesville and I don't believe that we have any in hand. So it's a possibility that it doesn't get spent. We did drill the two operated wells and then we completed those very, very early -- July. So it is a possibility we spend no more money in the Haynesville but there could be some proposals that we think are worthy to participate in come later.

Okay. And then going back to the acreage and inventory discussion. On the Eagle Ford, should we think about any kind of particular exit level in terms of adds by year-end, soon thereafter, in terms of kind of what you're been working through?

As far as acreage?

Yes.

Our goal is, like Jay said, to add 5,000 to 6000 acres. Whether or not we accomplish that by year end or not is a question. But I think we will make progress toward that.

Presumably these are infill acreages right around where you operate?

Right, I think they were talking about numbers, the smaller acreage acquisitions, they need to be right around where we operate in order to be useful to us. If they're going to be pretty far out of our operating area, but in an area that we like in the Eagle Ford, if they're going to tend to have to be a little larger to make more sense and be more contiguous so you can get a lot of drilling locations on it.

Those type of purchases would be more expensive typically. The larger the acreage tract in an area that is proven then the more value it has and conversely the smaller the acreage track, even in a good area may have less value just because it can't be used by as many operators.

Good and I continue to hear from you guys a strict discipline around what you will spend money on and what parameters that will have to bring to the table, right? And then that is something we should continue to expect for the next several quarters -- let the market come to you rather than chase anything?

Absolutely. Definitely. A lot of feedback we've gotten back from other investors in the industry and especially the private equity commercial banks etc., is they feel like the industry in general has the opposite problem. They have way too much inventory, way too many things that need to be drilled and just on the whole. They feel like those opportunities will be there. So we plan to be very disciplined.

We have a very good year if we just stick to what we own today and run the six rig program and oil prices are supportive of that, we have a very, very good year next year. So we don't want to mess that up by jumping off into another area that may not be able to produce the same results. And we want to be very disciplined and find the right opportunities. But we do see overall in the long run, that we want to add more oil opportunities to the Company.

We just exited a very large one that probably, before that, we would say we don't want to add anymore, because we have so much on our plate. But, just months ago, that changed. So, we are open to those kind of ideas, but we don't want to stress the balance sheet. Nor do we want to create a lot of obligations for things that have to get drilled immediately or generate lower returns than what we can make now in the Eagle Ford.

So we're very disciplined and patient, but we think those opportunities will obviously come, they always do. And then we'll add as we march down the next three years we will definitely add additional oil opportunities to keep us more balanced. We don't want to go back to 98% gas in the long run. But the Company wants flexibility to respond to the different challenges the industry throws our way.

I apologize for this theoretical question, but along the same line, the sense that you guys were saying was there were very few underutilized operating platforms in the public capital markets as an E&P company. If a private equity wants to come to you and say hey let me back into your public platform these set of assets, what would you demand in return and how would you shape something like that? Again, it's theoretical, I understand, but all addressed to the same basic concern and question of the marketplace?

Well, we would obviously want to see an immediate value that makes that a worthwhile proposal to us, not only just for whatever part of capital it uses or takes, but also what part of our time and efforts that our operations group and other groups would have to spend on it. So we would just have to evaluate that opportunity.

But we do think, like I said earlier, that there are, in general, there is a lot of inventory, a lot of projects out there that need a lot more capital than the companies that have them have. So I think we are sitting in a good position with the real strong balance sheet. And we'll see how that all plays out.

Okay. Thank you so much.

I would now like to turn the call back over to Mr. Jay Allison for closing remarks.

Well, again, we are always thankful that you participated in the conference call and that you're either an analyst or a stockholder that are interested in the story. And I think the questions that were asked were excellent questions and hopefully we have given you some clarity on what the business plan is and we have been accountable for our entrance and our exit to the Permian and what we are attempting to do in the Eagle Ford, as well as larger. So thanks for your time.

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