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Comstock Resources (NYSE:CRK)

Q3 2012 Earnings Call

October 30, 2012 10:30 am ET

Executives

Miles Jay Allison - Chairman, Chief Executive Officer and President

Roland O. Burns - Chief Financial Officer, Principal Accounting Officer, Senior Vice President, Secretary, Treasurer and Director

Mark A. Williams - Chief Operating Officer

Analysts

Brian M. Corales - Howard Weil Incorporated, Research Division

Cameron Horwitz - U.S. Capital Advisors LLC, Research Division

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Dan McSpirit - BMO Capital Markets Canada

Michael Kelly - Global Hunter Securities, LLC, Research Division

Raymond J. Deacon - Pritchard Capital Partners, LLC, Research Division

Operator

Good day, ladies and gentlemen, and welcome to the Q3 2012 Comstock Resources Inc. Earnings Conference Call. My name is Rachel and I will be your operator for today. [Operator Instructions] As a reminder, this call is being recorded for replay purposes. I now would like to turn the call over to Mr. Jay Allison, President and Chief Executive Officer. Please proceed, sir.

Miles Jay Allison

Thank you, Rachel. Before I start the third quarter results, I'd like to kind of have an opening comment from the company. For those of us who really don't live on the East Coast, we're not directly hit by Superstorm Sandy, it's is really kind of somber morning, it's a strange morning. We've been doing this for 24 years and it's a strange morning not have your stock trading. As you know, Ron and I has spent a lot of times, in the past 23 years, on the East Coast region, marketing the Comstock story. So it really feels like our second home. So please note that all of our prayers at Comstock this morning are for those impacted by Superstorm Sandy. The 7.8 million people without power, those directly in the storm's path. It's comforting to know that Americans are strong and that the impacted region will rebound in short order.

So with that, I'll open it up with the third quarter 2012 results. If you go to the slide presentation, welcome to the Comstock Resources Third Quarter 2012 Financial and Operating Results Conference Call. You can view the slide presentation during or after this call by going to our website at www.comstockresources.com and clicking presentations. There, you'll find a presentation titled Third Quarter 2012 Results. I'm Jay Allison, President of Comstock and with me this morning are Roland Burns, our Chief Financial Officer, and Mark Williams, our Chief Operating Officer.

During this call we will discuss our recent drilling results, review our 2012 third quarter financial results. Forward-looking statements, that's on Slide 2, please refer to Slide 2 in our presentation 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.

2012 third quarter highlights, if you'll refer to Page 3 of the presentation, will summarize our third quarter results. The financial results this quarter continue to be impacted by the very low natural gas prices that we receive for our production. The growing oil side of the company is helping mitigate the negative impact that the very weak natural gas prices are having on our financial results. For the third quarter, we reported revenues of $117 million, generated EBITDAX of $87 million and net operating cash flow of $71 million or $1.47 a share. We did have a net loss of $26 million or $0.56 per share. We were able to increase our oil production by 13 % from last quarter and 238% as compared to the third quarter of 2011. Oil comprised 16% of the third quarter production and 57% of the third quarter's revenues. We've had strong results in our 2012 drilling program, which Mark will go over in a moment. And we drilled 56 successful wells, including 49 successful oil wells in our Eagle Ford and Wolfbone programs. The increase in oil production and improving natural gas prices will have a positive impact on our future revenues and cash flow. Our cash flow is now able to cover most of our drilling expenditures and our bank borrowing base was increased to cover the one-year, $90 million advance our banks made to help us finance the Wolfbone acquisition at the end of last year. I'll now turn it over to Roland to cover of the financial results in more detail. Roland?

Roland O. Burns

Thanks, Jay. On Slide 4, we show our oil production on a daily basis by quarter. Our oil production this quarter grew by 238% to 7,200 barrels per day, as compared to the third quarter last year when we produced 2,100 barrels per day.

Our Eagle Ford shale properties in South Texas, shown in light blue on this chart, increased to 5,000 barrels per day and is our main engine for growth this year. We added 400 barrels per day in the Eagle Ford this quarter as compared to 4,600 barrels we averaged in the second quarter of this year.

The decrease in the rigs that we have drilling in our Eagle Ford program and the new joint venture, where KKR participates for 1/3 of our interest, has slowed our oil growth this quarter and for the upcoming fourth quarter.

We're adding another rig into our Eagle Ford program in late November, which will bring us to 3 rigs by December. This additional activity allows us to have strong production growth again in the region in the first quarter of next year.

Our Wolfbone properties in West Texas increased by 500 barrels this quarter to 1,900 barrels per day. We expect to see production from this region continue to increase each quarter as we go forward.

As we look to finish up this year, we're forecasting our oil production to grow approximately 190% to 200% of our last year's production to the total of 2.4 million to 2.5 million barrels in 2012. We expect to begin 2013 well-positioned to have another strong year of oil production growth.

Slide 5 shows our natural gas production on a daily basis. Our natural gas production decreased by 19% of the third quarter from last year to 220 million cubic feet of gas per day. The decrease is primarily attributable to 10 million a day of production that we sold with our May property divestitures, which closed in the second quarter, and declines from our Haynesville properties, which were at their peak production level in the third quarter of last year.

Production from our Haynesville and Bossier wells declined to 165 million per day this quarter. The remaining 25% of our gas production had only modest declines. Production from our Cotton Valley wells, which is shown in dark blue on our chart on Slide 5, averaged 27 million per day, and our South Texas gas production, which is shown in red, was 21 million cubic feet per day.

Our other gas production, shown in purple, remain the same, at 7 million per day.

We are lowering our forecast for natural gas production for this year to approximately 81 to 82 Bcf, which would represent a decrease of 9% to 11% from 2011's total production. Production has to start -- our production has started to decline a little earlier than we originally anticipated and will continue to decline until we restart our drilling program at in the Haynesville Shale.

On Slide 6, we show that our realized average oil price increased 11% in the third quarter of 2012 to $97.09 per barrel as compared to $87.55 per barrel in the third quarter of 2011.

Our realized oil price averaged 105% of the average benchmark NYMEX WTL price due to the high differentials we're receiving for our Eagle Ford shale oil. 68% of our production was hedged in the quarter at a NYMEX WTI price of $99.53. Including the gains from our hedges, we realized $102.08 per barrel in the quarter, which was 17% more than our realized price in the third quarter of 2011.

Slide 7 shows our oil prices for the first 9 months of this year. Our realized average oil price increased 8% in the first 9 months of 2012 to $99.63 per barrel as compared to $92.59 per barrel in 2011. Our realized oil price averaged 104% of the average benchmark NYMEX WTI price and 72% of our production was hedged in this period at the NYMEX WTI price of $99.43.

Including the gains from the hedges, we realized $102.30 per barrel on the quarter, which was 10% higher than what we realized in 2011.

For Slide 8, we outline our hedge programs for our oil production. We have a very attractive oil hedge position, which protects our drilling program for the rest of this year and for 2013. We have 5,000 barrels a day hedged at $99.53 for the fourth quarter of this year and for next year, we have 6,000 barrels hedged per day at $98.67 per barrel.

Slide 9 covers our natural gas prices. Our average gas price of $2.46 decreased 40% this quarter as compared to the $4.09 we realized in the second quarter of -- or the third quarter of 2011.

Our realized gas prices was 88% of the average NYMEX Henry Hub gas price for the quarter. Our average gas price for the first 9 months of 2012 decreased 42% to $2.37 per Mcf as compared to $4.09 for the first 3 quarters in 2011.

Our realized gas price was 92% of the average NYMEX Henry Hub gas price for the first 9 months of this year.

On Slide 10, we cover our oil and gas sales. Our oil production growth this quarter was able to offset much, but not all of the impact of the 40% decline in natural gas prices. As a result, our sales decreased by 2% to $117 million in the third quarter as compared to $119 million in 2011's third quarter.

Our oil production now makes up 57% of our total sales as compared to only 14% in the third quarter of last year. For the first 9 months of 2012, sales have increased 4% to $332 million as compared to $320 million for the first 3 quarters of 2011. Our oil accounted for 54% of our total sales so far in 2012, as compared to only 14% last year.

Our earnings before interest taxes, depreciation, amortization and exploration expense and other noncash expenses, or EBITDAX, decreased by 8% to $87 million from the $94 million that we had in 2011's third quarter, which is shown on Slide 11. EBITDAX for the first 9 months of 2012 has decreased 2% to $240 million from 2011's $246 million.

Slide 12 covers our operating cash flow. Our operating cash flow for the quarter came in at $71 million, which was 17% lower than cash flow of $86 million in 2011's third quarter. Our operating cash flow for first 9 months of 2012 was $199 million, 9% less than the 2011's operating cash flow of $219 million for the same period.

On Slide 13, we outline our earnings. We reported a net loss of $26 million for the quarter or $0.56 per share, as compared to earnings of $1.3 million or $0.03 per share in 2011's third quarter. For the first 9 months of this year, we reported a net loss of $29.4 million or $0.63 per share, compared to earnings of $7.7 million or $0.16 per share for the same period in 2011.

The quarter and the year-to-date financial results in both periods include several unusual items. For the third quarter, the reported results include a net loss on property sales of $2.8 million or $1.8 million after-tax or $0.04 per share, which is primarily related to the cost incurred in the formation of our Eagle Ford shale joint venture. We also have a $1.4 million impairment or $900,000 after-tax or $0.02 per share relating to upcoming lease expirations.

For the first 9 months of 2012, those results included a net gain of $24.3 million or $15.8 million after-tax or $0.34 per share on the property sale that we made. Gains of $26.6 million or $17.3 million after-tax or $0.37 per share on sale of our Stone Energy shares and $8 million of impairments, or $5.2 million after-tax or $0.11 per share.

If you exclude all these items, we would've reported a net loss of about $0.50 per share this quarter and about $1.23 per share for first 9 months of this year.

On Slide 14, we show our lifting cost per Mcfe produced by quarter. Our lifting cost is comprised of 3 different items: production taxes, transportation costs and other field level operating costs. Our total lifting cost this quarter were $1.06 per Mcfe as compared to $0.79 per Mcfe in the third quarter of 2011.

Our production taxes were $0.16 per Mcfe, the transportation averaged $0.26 per Mcfe and the field operating cost averaged $0.64 this quarter, which is higher than the $0.47 that we realized in the third quarter of 2011.

The lower gas production we had during the quarter and the more expensive oil production account for the higher rate that we had this quarter.

On Slide 15, we show our cash G&A per Mcfe produced by quarter, which excludes stock-based compensation. Our general administrative cost increased to $0.26 -- $0.20 per Mcfe produced in the third quarter of this year as compared to $0.18 per Mcfe in the third quarter of 2011. And that difference is mainly due just to the lower production level. Our G&A did improve this quarter from the $0.22 per Mcfe that we had in the second quarter this year.

Our depreciation, depletion and amortization per Mcfe produced, as shown on Slide 16, and our DD&A rate in the third quarter of 2012, averaged $4.10 per Mcfe as compared to $2.96 in the third quarter of 2011 and the $3.59 we averaged in the second quarter of this year. The low natural gas prices drove up our DD&A rate this quarter, as the 12-month average SEC price, which is used to calculate proved reserves, is down low enough to cause the exclusion of 434 Bcf of our undeveloped natural gas reserves from the proved reserves calculation.

The other factor that's contributing to the increase in the DD&A rate is the higher cost of our oil production, which is making up the greater percentage of our total production and revenues.

On Slide 17, we detail our drilling expenditures and we have spent $402 million so far this year on drilling and completing wells as compared to $443 million spent for the same period last year.

We spent $102 million in our East Texas/North Louisiana region, $161 million in our South Texas region and $139 million in our new West Texas region.

We also have spent, in addition to drilling wells, we spent $24 million on leasehold in the first 9 months of this year as compared to $53 million that we spent on the same period last year.

The South Texas expenditures on this chart are net of $24 million we received from our joint venture partner for participation in wells that were drilled starting in April of this year through July when the venture actually closed.

To date, in 2012, 75% of our drilling expenditures have been spent on drilling oil wells as compared to only 28% for the same period last year.

Slide 18 recaps our balance sheet at the end of the third quarter. On September 30, we had $3 million in cash and $15 million in marketable securities on hand, which represents our 600,000 shares of Stone Energy that we're still holding. We also had $1.2 billion of total debt which is comprised of about $884 million of our senior notes and $355 million outstanding under our revolving credit facilities.

Yesterday, our banks approved a borrowing base of $570 million, which is an increase of $75 million from our conforming borrowing base of $495 million. The growth in our conforming borrowing base allows us now to retire the nonconforming borrowing base which was $74 million that was due to expire on its own by December 31, 2012.

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

Mark A. Williams

Thanks, Roland. On Slide 19, we recap our activity in our East Texas/North Lousiana region so far this year. In the first quarter, we drilled 3 operated Haynesville wells, 2.5 net, before moving our 2 operated drilling rigs out of this region.

We participated in another 4 non-operated wells so far this year, and that's 0.7 net wells. In the third quarter, we completed the last of our operated Haynesville shale wells. We still have 3 non-operated Haynesville shale wells waiting to be completed.

We'll be able to exploit our 7 Tcfe of Haynesville and Bossier resource potential in the future when improved gas prices provide economics competitive with our oil projects.

Slide 20 shows our West Texas region and the 91,000 gross and 57,000 net acres that we have. Our activity this year is focused on Reeves County and our Wolfbone Field. The Reeves County acreage provides us over 900 net vertical locations targeting the Wolfbone, which has 178 million BOE of resource potential. We have a proven and successful vertical program on our acreage, but we think there is significant upside with horizontal development in the Avalon, Bone Spring and Wolfcamp formations on our acreage.

Recent horizontal activity in the Bone Spring and Wolfcamp has been encouraging and we completed our first horizontal Wolfcamp well in the third quarter.

Slide 21 is a geologic model of what goes on and what's going on in Reeves County. You can see that our acreage is located at the deepest part of the basin and that much of our acreage has a very thick Wolfcamp section which is geopressured. This is why we are making some of the best vertical Wolfbone wells in the area. We plan to test several intervals within the Wolfcamp Shale to determine which benches will produce the best horizontal results.

Slide 22 shows our Reeves County acreage and highlights, the latest, 8 vertical Wolfbone wells we reported on today. So far in 2012, we have drilled 29 wells, 21.1 net. All of these wells were successful. Since closing on the acquisition of acreage in Reeves County, in West Texas, we have drilled and completed 20 operated vertical Wolfbone wells and 1 horizontal Wolfcamp shale well. The vertical wells were drilled to total depths of 11,250 to 12,786 feet and completed with 5 to 11 frac stages. These wells have an average per well initial production rate of 356 BOE per day, of which 79% is oil.

Of the 8 new operated wells reported on in the third quarter, the Ponderosa State 25 #1 and the Jesse James 4 #2 each had an initial production rate of 511 BOE per day. We also participated in 5 non-op Wolfbone vertical wells, which had an average initial production rate of 350 BOE per day.

We drilled our first horizontal well, the Monroe 35 #1H, targeting the Wolfcamp shale formation and the results have been very positive with an initial production rate of 653 BOE per day. This well is completed with 15 frac stages over a 3,627-foot lateral. Our second horizontal well, targeting the Wolfcamp Shale, the Dale Evans 196 #2H has reached total depth at 14,584 feet with a 3,428-foot drilled lateral and is currently waiting to be completed.

Slide 23 shows the 41 operated wells in our Wolfbone field, including the 8 we completed in the third quarter. The 41 wells had an average per well IP of 322 BOE per day. The 30-day rate for the 39 wells that are produced for that period, averaged 81% of their initial rate. Over a longer period of 90 days, the rates have averaged 64% of the initial rate.

Slide 24 shows you the location of those 41 wells on our acreage. The wells with the highest IP rates so far have been in the area of on the east, in the area of the Buffalo Bill, Jesse James and the Ponderosa wells. You can see that our first horizontal well is the Monroe, which is number 35 on the map.

On Slide 25, we cover our South Texas operations where all the activity is in our oil-focused Eagle Ford shale play. We have 35,000 gross acres and 28,000 net acres in the oil window of the Eagle Ford Shale. Based on 80-acre spacing, we believe we have 277 horizontal locations to drill, including the wells we have already drilled on our acreage. We have excluded some of the northern acreage and any acreage that we think is undrillable from this estimate. The average gross EUR is 500,000 barrels of oil equivalent for the 5 separate tight curve areas that we use in the drilling program. After deducting royalties and the interest that our new partner will earn in the joint venture, we estimate our properties will yield 78 million barrels of oil equivalent, of which over 80% is oil.

Slides 26 and 27 show the results and locations of the 41 wells, which are currently producing. We completed 6 more Eagle Ford wells since our last update. They are the last wells on the list, wells number 36 to 41. The 41 Eagle Ford shale wells that were completed, had average per-well initial production rate of 705 BOE per day. The 6 new Eagle Ford wells reported in this quarter averaged 816 BOE per day, with Swenson C #1, the Hill A #3 and a the Hubbard #1H in McMullen County, having the highest rates at 1,002, 829 and 786 BOE per day, respectively.

These wells being produced under the company's restricted shale program and initial tests were obtained using a 14/64" to 16/64"choke. The first 35 wells which had been producing for more than 90 days had an average initial production rate of 686 BOE per day. The 30-day, per-well production rate for these wells averaged 517 BOE per day and the 90-day rate averaged 448 BOE per day, which is 65% of the initial 24-hour test rate.

In addition to achieving consistent production performance, we are also reducing the cost we incurred in drilling to complete these wells. Starting in the fourth quarter, we expect to save between $400,000 to $500,000 per well based on lower pricing we are now receiving for our stimulation services.

Slide 27 shows the location of the 41 producing Eagle Ford wells on the previous slide. I will now turn it over to Jay.

Miles Jay Allison

Thank you, Mark. If you'll go to the 2012 outlook. In summary, I refer to Slide 28 in our presentation. Despite the very low natural gas prices we experienced this year, we are on track to meeting our goal of establishing 2 high-quality oil drilling programs which are transforming the company to a more balanced production mix and helping offset the low natural gas prices. We expect oil to comprise 15% to 18% of 2012's production, over 20% of production at the end of the year. 93% of the net wells that we'll drill in 2012 will be oil wells and 78% of our budget will be spent on oil projects. Even though our overall production this year might not grow much after the divestitures we completed last quarter, we expect our oil production to grow to close to 200% over last year.

Our Eagle Ford shale program, which is becoming more prolific with Mark driving well costs down and the promote we get from our KKR joint venture, is our largest growth engine this year. Our Wolfbone program in Reeves County continues to be a proven and profitable vertical drilling program. We have plans to reduce our well cost in this play and are working to create a successful horizontal program to drive up the rates returns in this area. We continue to have one of the lowest overall cost structures in the industry. We've completed several transactions this year to enhance our financial profile and liquidity post the Permian acquisition and the fall in natural gas prices. We reduced leverage this year by completing asset divestitures which generated net proceeds of $183 million. We also completed a bond offering on June 5 to free up over $200 million of our bank borrowing base. We will utilize the oil price hedging strategy to protect the acquisition and our oil forecast to drilling program. The new joint venture agreement we closed on the third quarter allows us to ramp up our drilling activity, while at the same term reducing our spending level.

So for the rest of the call, Rachel, I'd like to take questions only from the 19 or so research analysts that follow the stock. So I turn it over to you, Rachel, for questions.

Question-and-Answer Session

Operator

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

Brian M. Corales - Howard Weil Incorporated, Research Division

Just starting on the Wolfbone, what have you all changed since you first started drilling and what are you seeing geologically as you go east to see some of those higher production rates?

Mark A. Williams

Brian, as far as what we had changed, we increased our frac size in our completions. We have tested and -- either verified or eliminated a couple of the deeper zones where we had drilled to them and tested them and now we're not drilling to them. And we've also changed how we pick our perforation, so we're much more focused using the technology that we have in picking perforations rather than just picking them evenly. And we think that's giving us a substantial improvement in performance. And as you go east, you get a little deeper into the basin. And I think the pressures we're seeing, that the pressures are a little bit higher on the east side of the field than they are on the west. I think that's driving the IP rates. I think overall EUR, we're probably not going to see us nearly much of the difference, east to west as we do on the early rates, but that's what we're seeing right now.

Brian M. Corales - Howard Weil Incorporated, Research Division

Is the product mix changing as you go east?

Mark A. Williams

Not really. It's pretty similar, with about 1,800 standard cubic feet per barrel yield on her GOR on both sides. Now if you get well over on the west edge, it starts to go up. But that's way out, kind of on the western edge of our acreage we're seeing that GORs climb maybe to 2,500 to 3,000.

Brian M. Corales - Howard Weil Incorporated, Research Division

And then just one other question. Just looking at kind of your Haynesville program, I mean you pretty much stopped drilling there. What kind of declines are you all thinking for '13, just from Haynesville?

Roland O. Burns

Brian, this is Roland. I think that, overall in 2013, we were kind of planning on a 25% decline in our gas production, but no drilling activity at all. I guess I'll mitigate that. That implies -- with Haynesville at 75% of our production so it's creating most of that gains. So it has probably closer to 30% since it's the major declining area. Our other production, the other 25%, we haven't drilled on for quite some time and it's much more a lesser decline as you can see in this quarter.

Brian M. Corales - Howard Weil Incorporated, Research Division

Okay. That's very helpful. And just -- this may be a dumb question, but looking at '13, and I know you all haven't set a budget, but we can assume that the rig count you have is going to be -- you're not going to bring any rigs back to the Haynesville with this smaller running gas prices we've seen?

Miles Jay Allison

Well, what we've seen is you have [indiscernible] oil prices where they are today, the kind of the marker is if you have a $5 natural gas price, $5 we can get 30 plus percent to rate of return in the Haynesville. I mean we wouldn't look at bringing rigs back in the Haynesville unless you have like a $5 handle on it. That's kind of what we've said corporately. So as far as CapEx dollars in 2013, with a commodity prices as they are today, we kind of pulled out $10 million from maintenance and that is -- we have to drill a well or if we get than AFE or whatever. So if you own 140,000 acres in the Haynesville, Bossier, and 7 Tcfe of upside, you'll have to spend a little bit somewhere. So instead of spending the $102 million or $106 million we spent this year, it will be more like $10 million and the rest of our operating cash flow will go toward out of the Eagle Ford or the Permian.

Operator

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

Cameron Horwitz - U.S. Capital Advisors LLC, Research Division

A question for Mark. Mark, can you just tell us a little bit about maybe what you learned from the Monroe well, as far as where you want to land your lateral, how you space your fracs, et cetera? Are you doing anything differently because of that on the Dale Evans well?

Mark A. Williams

Cameron, this is Mark. We didn't change our strategy because of the Monroe well, but the Dale Evans is targeting a different interval because in that area, the Middle Wolfcamp looks better than the Wolfcamp B. Our first well is in the Wolfcamp B, the Dale Evans is targeting in the middle Wolfcamp. And then we got two other wells scheduled to spud this year and they will be targeting different intervals as well. So our goal is really to test the various intervals, test which interval we think looks good in an area, try to learn from that, see how it performs, apply that to the logged properties and the rock properties in the other areas and begin to define what our good targets are. And we think there's multiple ones, which we need to figure out which ones work best in which area.

Cameron Horwitz - U.S. Capital Advisors LLC, Research Division

Okay. That's helpful. And then just in terms of the lateral link, are you just governed by the lease lines right now and are you thinking about maybe extending those in some of the areas where you can?

Mark A. Williams

Cameron, that will be our goal, it'll be to pool or form larger units everywhere possible to get our lateral linked up to be more comparable to our Eagle Ford, which is around 6,000 feet. And that's what we think is kind of an optimum link to both drill and complete without getting into maybe some of the mechanical issues that you get in with the ultra-long laterals, but still you can maximize your dollars or your to reserves per dollars spent.

Cameron Horwitz - U.S. Capital Advisors LLC, Research Division

Okay. And then just along that line, can you just give us a little color on the well cost. I guess Monroe, you were a little over $9 million. Where do you see that trending over time?

Mark A. Williams

Yes. The Monroe was a little over $9 million. The frac simulation costs are coming down in West Texas, the way that they are in the Eagle Ford. So I think our next job that we have coming up' were substantially less. I guess between $0.5 million and $1 million cheaper, so that will help a good bit and we have to drill a few to the kind of get our system down and improve our -- we get up the learning curve on these things. So after a few, I think we're going to be somewhere between $8.5 million and $9 million, probably, it's what our goal would be to get these wells drilled, once we get a little bit better at it.

Operator

Your next question comes from Leo Mariani of RBC.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Just sticking with that Monroe well there, can you just give us the kind of hydrocarbon breakdowns in terms of oil, NGL gas on that well?

Mark A. Williams

As far as oil, it's about 75% oil -- 75% to 80% oil.

Roland O. Burns

Yes, I think it started out at 78% in the IP and then ended up about 82% with a 30-day just on a composition basis. But yes, I haven't seen a processing statement on the NGLs yet, but that is the oil and gas breakdown.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Got you. Okay, that's helpful. In terms of well cost, just trying to get a sense of what you think the Eagle Ford well costs are going to be. In the fourth quarter, you talked about them coming down pretty significantly. Can you just put a number on that. And then additionally, what are these vertical Wolfbone wells costing you all?

Mark A. Williams

Mariani -- or Leo, on the Eagle Ford, our cost out there is probably going to run between $8.5 million -- $8 million and $8.5 million. Our lateral lengths on the wells that we're drilling right now, some of them are fairly long. And so the cost does increase with lateral length because you're just adding frac stages, you're adding some drilling time, but mainly, you're adding frac stages. And so that cost is variable, depending on your lateral lengths. So -- but on an equivalent basis, we said our cost is going to be probably $0.5 million cheaper than it was in the second quarter, and then we expect to get some additional savings next year with some pricing and also some pad drilling that we're planning to do, which will provide some pretty good savings. Vertical Wolfbone, we're still in that $4.5 million to $5 million range, and our goal next year is to really work on that to get a more of a focused vertical program rather than having a program that really is able to bounce back and forth between the 2. We really plan to separate them where we can focus on the vertical side, focus on our cost and get that cost down with a target in the low 4s.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay, that's helpful color, for sure. I guess in terms of your gas price, it looks like your differential has widened a fair bit in the third quarter '12. Can you just kind of walk us through any color you have on that? And should we expect that differential to kind of persist into 4Q or early next year?

Roland O. Burns

Leo, this is Roland. Yes, I think on the gas price, there are several things at work there on the differentials, weakening from where they were. Yes, part of it -- some of it is -- NGL prices are getting weaker. We reflect our NGL revenues as part of our gas stream and have always included that in our gas price realization, but that is not a big part of the company. It's probably around 2% of our revenues. But those are getting weaker, so that hurts the differential a little bit. We have sold our biggest component of NGL properties we're divested of in May. So that contribute a little -- with those out of the picture, that contributes a little bit to a lower average differential. And then enter in the low gas prices, I mean, some of the -- a lot of the transportation costs are percentage base. They're fixed rates. So with a low base gas price, you're going to have a higher percentage of differentials because it's not a percentage base calculation. So that and the volatility of gas prices, we have -- our production was kind of up and down during the quarter. It wasn't necessarily spread out over the 3 months very evenly, so I think we have a little more production in the lower price months than the higher price months. That part would not be reoccurring, probably, but the other 2 would be reoccurring.

Leo P. Mariani - RBC Capital Markets, LLC, Research Division

Okay, that's very helpful color. So on the lines of transportation expense, I know you guys break that out separately as well. I take it that some of it is still kind of reflected in your gas price as well?

Roland O. Burns

Right. The part that's reflected in our gas price is, yes, basically, wherever we sell the gas at. So that's how you properly show that. So if our Haynesville gas and some of the gas that we transport the longest away from the wellhead to certain other delivery points to get better -- because of the big volumes, so that's reflected -- that's a big part of our transportation costs, that's part of lifting costs. And those costs you see are going to be pretty bearable and are going to be -- they came down with a lower gas production in the Haynesville. Most of our oil, there's not too much transportation costs associated with our oil because most of them is sold at the wellhead. So that's going to be reflected in the netbacks we get in our oil prices.

Miles Jay Allison

One comment on the Eagle Ford. We have reduced cost probably a little less than $8 million right now, but as you increase the laterals, like Mark said, and we're probably in the $8 million kind of ZIP code in that. But if we had to have wells that cost less, then we could. But it's all a factor of how long the lateral is, and 6,000 feet is just a pretty good lateral. And I think on the vertical Wolfbone, some of the offsetting operators are drilling just the vertical wells for a little less than $4 million, drilling and completing. So I think our goal in 2013 is to have a vertical program and try to drill and complete those wells for a little less than $4 million. We're seeing costs coming down there, and like Mark said, anytime you enter a new area, it takes a little while to kind of crack the code there, and we've done it in every area that we've been in. And, of course, as you know, our IP rates have been excellent. They've been superior to offset operators. So I think we're getting close there.

Operator

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

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

On the completion cost side, I don't know, Jay or Mark, who's best to answer this, is this -- the lower completion cost, is that a function of renegotiating pricing already with your service providers or is that something to be on the come in 2013? What's -- what are the prime determinants behind those $400,000 to $500,000 of cost savings?

Mark A. Williams

Ron, this is Mark. It's both. The $400,000 to $500,000 is renegotiation of pricing, but there's -- but also, our contract runs out at the end of the year. And we do expect the market is somewhat oversaturated now in the Eagle Ford with all the crews that have come there from -- both from the gas plays and all the newbuild crews that showed up this year. So we have had indications of some additional price improvement at the end of the year.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

And that -- is the $400,000 to $500,000, what you think, can improve fourth quarter versus third or is the $400,000 to $500,000 inclusive of what you think the new pricing will be once that contract expires at year-end?

Mark A. Williams

That was our improvement from third quarter to fourth quarter.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

And so you could see potentially more in 2013?

Mark A. Williams

Yes, that's correct, Ron. I don't see expect it to be that big of a change based on the pricing that we've seen so far, but I do still expect a fairly substantial improvement. And we're also seeing other services get more competitive and prices come down. So when you get an improvement across the board, it really does impact the bottom line.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

And is that primarily in the Eagle Ford or is that across both the Eagle Ford and the Permian at this point?

Mark A. Williams

I would say that's more in the Eagle Ford just because the quantity of service in the Eagle Ford. I think that's going to happen in West Texas. We're getting calls from new vendors every day out there. So I think that will happen, but West Texas hasn't become saturated to the point that Eagle Ford has with services yet.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay, great. And then I think Brian had asked a little bit about 2013. When you look at 2013, Jay, you've been pretty vocal on prior conference calls about funding your budget out of cash flows. A, is still that the case? And b, it sounds like you'll be at 3 rigs in the Eagle Ford by year-end. How do you look at the Permian in terms of anticipated activity/rig levels?

Miles Jay Allison

Yes, I think we'll do in December. We have a board meeting kind of mid-December. We'll see where commodity prices kind of end up in December. Our goal is to have 3 rigs busy in the Eagle Ford, and again, as Mark had said or related to earlier, if we drilled more in McMullen, we're going to hit these 900, 1,000, 1,100-barrel-a-day wells or higher IP rate wells. And we can do that because we have really great partner with KKR. So we can put that third rig in. And I think our cost go down, our production profile goes up. Again, there's a transition in this next quarter because KKR does have a third of the new wells that are drilled. But then you'll see in the first quarter 2013, I mean, it will all be working really perfectly, it should. So a 3-rig program in 2013, and again, you've got maybe $10 million of maintenance for dry gas. So the rest of your free cash flow, we want to put it right now in the Permian. And as Mark said, there's 2 different programs in the Permian. One is maybe have a rig or a rig or 2 that just drills horizontally, and I think the rest of the rigs will drill vertically. So in a perfect world, we like to see a 4-rig program in the Permian. We'd like to have at least one of them drill horizontal wells, when you have to like to have 3 of them drilling vertical wells, hopefully at a cost of around $3.5 million, $3.7 million to drill and complete and produce these wells. Now we're not there yet. So we'll look in December. We'll see what our free cash flow from operations might be. You see we have a couple of hundred million dollars available under our credit line, and that's a big event because, I mean, we just went through the very worst cycle in the last 13 years for gas prices. So we want to keep that $200 million available. We really want to stay within our free cash flow. We kind of see what that looks like in December, and then we'll come up with this "3- to 4-rig program" in the Permian. And we like to have 4 and we like to have 3 in the Eagle Ford, but we'll make that call in December.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

And I think Roland had mentioned, just primarily as a function of the almost no activity in the Haynesville, the gas volumes next year can drop kind of up to 25%. Any expectation in terms of how the oil volumes can continue to grow? Are we talking about a 70% or 80%? I'm just trying to get a sense as to the overall production mix and/or what the profile looks like in '13.

Roland O. Burns

We're going to provide that when we come out with our budget runs. Instead of just trying to throw out numbers right now. But until we know our budget, we can't really say how much oil can grow.

Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division

Okay. And then I guess lastly, the incremental 2 wells in -- on the horizontal side in the Permian, are any of those added? And it sounds like at least one of those will be targeting a 6,000-foot lateral. Mark, is there anything -- or if it's on a 6,000-foot lateral, what are you contemplating in terms of frac intervals? Or are you going to wait to see how the Dale Evans comes in and employ that information this year as you look to a longer lateral completion?

Mark A. Williams

Yes, Ron, we're going to buy -- we've got a lot of information to evaluate between now and then, both on our wells and the offset activity. So we'll incorporate all of that and then determine how we want to space our perforation clusters and how much profit we want to pump, kind of based on all the results we're seeing between now and next January, February.

Miles Jay Allison

Yes, Ron, on the horizontal, again, at the beginning of the year, we thought we might drill 1 horizontal, maybe, and then now we're going to end up with 3 or 4. And we kind of forced the Monroe, and somebody asked a question earlier, why didn't we drill a longer lateral? Well, the lease that we drilled on have only allowed us to drill that 3,600-foot lateral. It takes a lot of land work to unitize leases to allow you to drill longer lateral. So in 2013, I think we'll be doing that. As Mark said, you need to drill a 5,400-foot or 6,000-foot lateral to optimize the reason you drill a horizontal well. The other thing we did, if you remember, when we closed this December 2011, we had 600, 700, 800 leases. We have a ton of leases, and we kind of arranged them and said, "Well, we need to drill wells to hold leases." It wasn't really about geology; it's about holding leases. So we've done that to the first 3 quarters. And now we've kind of forced in the Monroe well because we go to Mark and say, "Can't we drill a horizontal?" Because some of the offset operators to the East side did some pretty good horizontal wells. Now, as we understand, one's in the Wolfcamp B, one's in the A, et cetera, et cetera. But Ron, we're also -- we've got this other issue, and that is, when the lease is in their primary term, you traditionally hold 100 feet below the deepest-producing formation. So as long as the lease is active and alive, you don't have the depth limit, but once you quit drilling, you cease drilling, you do have a depth limit on most of these leases. So our program in 2012 was to drill these wells to the Wolfcamp and Wolfbone wells and hold the lower portions of that acreage. So we blended in this horizontal program with the original goal of holding as much of the leases as we can. So again, as we end up in December, a couple of months from now, like Mark said, we'll be on more the Eastern side, which if you had your druthers right now, we'd rather be on the Eastern side. Not that the Middle or the Western is not as good, but we've got results on the Eastern side. So we've been able, I think, to put together a lease where we can have -- we can drill 6,000-foot lateral. So we would expect that well to be a pretty good well. So that's kind of the reasoning behind the actions that you might want to know.

Operator

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

Dan McSpirit - BMO Capital Markets Canada

Can you give us an idea on your comfort level on leverage, at least maybe as measured by debt-to-EBITDA? I asked in an effort to get a hint on what that leverage stat could look like, say, at the end of next year, at the end of 2013.

Roland O. Burns

Dan, this is Roland. Yes, that's definitely one of the measures that we look at a lot when evaluating leverage, and there's, of course, 2 factors on movement, having less debt and having more EBITDAX. And I think that we are going to be seeing improvements in our EBITDAX as we move away from this -- the very low $2-type gas prices and become more -- and also have a higher oil mix. So we see that, that leverage ratio is going to be improving, just with the growth in cash, cash flow and the growth in EBITDAX from the new oil production that's coming on and just getting a little bit of improvement in gas prices. So we think that, that's important to reduce debt. We'd have to not invest in our oil property. So we're kind of saying, "Well, let's not increase debt, but let's spend our cash flow on our high-return projects that will allow us to reduce leverage." So -- and we like to -- we definitely want to improve it through 2013, but we don't see doing anything -- we don't have to do anything drastic to improve, such as slashing our capital budget, so much that we can't grow our oil production or doing any type of very dilutive offering. I think as gas prices improve to the extent of a better longer-term outlook for gas, we have some divestiture opportunities there in conventional gas that I think that's kind of what we would look to bring down the overall debt levels of the company. But we're patient. We definitely want to do that early, we want to get full value for those longer-term, low-decline gas assets that we have in the company.

Dan McSpirit - BMO Capital Markets Canada

Okay. And on the subject of divestiture candidates, is any of the Haynesville Shale or Bossier Shale prospective leasehold candidate for?

Roland O. Burns

We don't view that as a divestiture candidate at all. We think that's our -- that some of our -- that's our really good gas assets, and we want to be a balanced company, not just an oil company. And so that's the area that we plan to grow our gas production end in the future, in the right price environment. So we're guarding our prime Haynesville acres. Now if there's some fringed acreage, we might let some of that go over time if it's not operated, but generally want hang on to our core Haynesville, not looking to divest of that or the other production that's there with, the Cotton, because I think we want to keep all rights and sell Cotton Valley or other formations in that area.

Miles Jay Allison

I think, Dan, you asked a really good question. If you go back, and you follow the company forever, but June, this time last year, when we had this third quarter conference call, it was only June of last year that we put a second rig into drilling the Eagle Ford. So this time last year, we were saying, "Well, we've got a second rig drilling the Eagle Ford." I mean, it was almost a nonevent. Well, one of our goals was, we were the reason -- we were a really great natural gas company in '08 because we were -- in the Haynesville/Bossier, we were 98% natural gas unhedged, off to great things until you have a recession and a glut, and those are facts. So then what happens? We specifically said -- and we haven't issued equity in 8 years. We said we really want to add 2 core oil fields, significant oil fields that give us significant exposure. We're already in South Texas, and we had started spending some money on the Eagle Ford acreage. So we ended up with a 28,000 net acres. We base-leased most of that, have 100% ownership. And after we drilled those 35 wells and de-risked it, I mean, we brought KKR in, which is a great partner for the 25,000 horizontal acre. So that was one of the goals. Now you don't know if you can accomplish a goal or not. It all depends upon the quality of the basin that you're in. So that -- you put a checkmark by that, that has really, really worked, and we needed it to work. We didn't get caught up in a lot of these background noise and have frange [ph] acreage or Tier 2 and 3 acreage. Now the other thing we decided to do in 2011 was to add the Permian. Now we didn't intend to add the Permian like the big acquisition in Reeves County. Our business model was to add it like we added the Eagle Ford. It was have 2 or 3 land grids go out. We went to Gaines County. If you'll notice, like in July of this last year, you look at all the counties in the state of Texas, Gaines County was the fourth largest producer of oil of any county in the state of Texas. So we go to Gaines County, we look at overpressured area and then knock, knock, knock, an opportunity comes along in Reeves County and we said, "Well, significant oil exposure, 178 million barrels. It's been de-risked, 37 wells drilled, big footprint, 44,000 net acres, and we had worked hard to have the borrowing base where we could write a check." We didn't have to have production payments or preferreds or converts or any of the other kind of financial instruments. But then we did choose to lever up the company, and we did that and we went from 30-something percent net debt to cap to 54%, 55% net debt to cap. But what we told you we would do, we did. We had $184 million of divestitures, either Stone shares or Double A or Sligo or some of the other properties, and then we hedged our oil, which we got pretty aggressive on that, 60% to 70% of oils hedged for this year-end and next year. And then we pulled in our budget even though it seemed to be out of control in the first quarter. We thought we'd pull it in, and that's when we went to 1 rig in the Eagle Ford. I mean, we pulled it in. We didn't have a second rig until KKR came in. So I'd give you a little background on that because what our goal is, like Roland said, we were 96% gas and 4% oil this time last year. Now, if you fast forward it by year-end, hopefully, our production is 80% gas, 20% oil, with 57% of our revenues from oil. But then you go to 2013 in the 2 basins that we were in right now, the Eagle Ford and the Permian, I mean, we could be 30% oil plus. And then by 2014, we're where we want to be, and that is about 60% gas and 40% oil. And then you ask about the divestitures. I think the mid-continent, maybe South Texas, and acreage that's not quote in the Eagle Ford kind of footprint, I think those would be candidates when gas prices were higher. But I think one of our holy grails of the whole company, which is not valuable today, is the Haynesville/Bossier. I mean, you go 1,600, 1,700 wells in 3 years from 0 production to 7 Bcf in the Haynesville, it caused a glut. I mean, it took the Barnett 12 years and 15,000 wells. So we're not interested in selling any of the Haynesville/Bossier. We want to keep that, and that's kind of our third leg of the program. It's 2 big oil projects. And then an inventory done, I think that's the key word, inventory at Haynesville. Fortunately, we didn't have to sell down or we didn't have to -- we didn't have a partner there that caused us to drill wells in Haynesville that we shouldn't be drilling, and we didn't have to dilute ourselves by issuing equity. And we're one of the fortunate companies that could transition to oil exposure without diluting the shareholders. So we plan in 2013 to stay within whatever our operating cash flow is. And if we have to have some divestitures along the way, we'll do that. So I just want to give you a sense of comfort of what we're trying to do.

Dan McSpirit - BMO Capital Markets Canada

Yes, that's very helpful. I appreciate the context and texture, indeed. Jay, you did -- you mentioned Gaines County. What should we expect in terms of exploration drilling activity -- exploratory drilling activity in 2013 in Gaines County?

Miles Jay Allison

We, again -- we've got 20,000 gross acres, 13,000 net acres. We really like the county. We chose it from every county in the Permian basin. We've got $500 an acre in it. The leases are 3-, 4-year leases. We would like to drill and we're probably budget to drill 1 or 2 wells, and Mark would like to drill more of it at least 1 or 2 in Gaines County. They'd be vertical. But if we're right there, Dan, I mean, we've been right in these new areas most of the time. If we're right there in a very prolific county that produces a lot of oil, I mean, that's upside that we don't have a lot of money in, a lot of equity built in there. So Mark, you might want to comment more on that, the top well you would drill?

Mark A. Williams

Yes, that's exactly right. Our goal would be to drill 1 or 2 vertical wells in there, essentially pilot holes to gather as much information as we can, we would probably set pipe and test some intervals and see what we get mix -- oil gas mix, what type of capacity to produce those zones have and then have them set up where we could reenter them at a later time and drill horizontal laterals out of those vertical wellbores. So that would be our goal for this coming year and depends on availability of capital, how aggressive we are in trying to get up and test that acreage.

Miles Jay Allison

Well, that even goes back, Dan, to like the Pearsall. We didn't -- nobody asked about it, but probably 82% of our acreage in the Eagle Ford area has perspective Pearsall under it now. Are we planning on drilling any of those? Intentionally, no. Are we going to want to core 1 or 2 of the Eagle Ford wells that we're drilling? Yes. So if the Pearsall turns out to be good, which seems like there's a well or 2 that looks pretty good. Then we've got a lot of upside there, which is definitely not in the numbers at all. So it's core regions, Haynesville/Bossier's core, Tier 1 area, the Eagle Ford definitely is a Tier 1 area and the Permian is definitely a Tier 1 area. So we've -- through our operations group and our reservoir group and our G&G group, we've been able to add those core areas without diluting anybody.

Dan McSpirit - BMO Capital Markets Canada

Okay, good. And one last one for me, sticking with West Texas. The Ponderosa and Jessie James wells, the latest 2 wells -- vertical wells to the Wolfbone are certainly overproducing wells, not unlike the first Jessie James well, I guess, and the Buffalo Bill well. What of your acreage in that part of the play -- what percentage is perspective for what you believe to be these overproducing vertical wells?

Mark A. Williams

On a net basis, probably 30% of our acreage on the East side would be that type of acreage, Ron, something like that. I haven't added all up to see exactly, but I think that's about right.

Operator

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

Michael Kelly - Global Hunter Securities, LLC, Research Division

As you moved to drill the longer laterals in the Wolfcamp and you go to 6,000 feet in your horizontals there. Just curious, what are your expectations on a 30-day rate? What would you be happy with seeing there?

Mark A. Williams

Mike, it's Mark. It's very early for us to put a hanging number on this well. I think they're going to -- we're still testing zones. Generally speaking, you don't get a linear improvement in IP. When you drill longer laterals, it's something less than that. Just mechanically, that's the way it works. But I do believe you get a proportionate improvement in EUR. If you drill 8,000-foot laterals instead of 4,000, you double the EUR, but you don't double the IP rate. So I think it's way too early for us to hang a number on. It's going to vary a lot over the field and by reservoir as well.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Okay. And if you mark-to-market current service costs, what's the fair D&C on those longer lateral wells?

Mark A. Williams

Probably adding around 500 feet -- $500 per foot of lateral, just in the stimulation and additional drilling cost. That's kind of what we've used in our Eagle Ford program. So every 1,000 foot of additional lateral, you'll probably add something in the 500 -- $400,000 to $500,000 range.

Michael Kelly - Global Hunter Securities, LLC, Research Division

Okay. Great. And then it seems like you talked about 2013's program, just kind of an initial glance at it, and that you'd favor still drilling with vertical -- vertical rates versus horizontal. Do you think that's ultimately how this acreage of this play shapes up for you? It's primarily a vertical play or would success in your initial wells here, you think you could be -- could shift and go to -- you drill more from a horizontal perspective?

Miles Jay Allison

I think we bought it for a vertical play, and I think that probably 80% of our acreage, you should drill it vertically. Now can you drill it horizontally also? The answer is yes. There's probably 20% of the play we think that only should be drilled horizontally, but I think if you go back to all these plays, the Eagle Ford or the Haynesville/Bossier, all these horizontal plays, it takes several years to kind of crack the code horizontally. I think that the offset operator to the East, I mean, they drilled 145 vertical wells and drilled any horizontal, and their economics seem excellent. You do have some horizontal wells in that area but probably less than a dozen offsetting our acreage. Now to the North, the New Mexico coming down. I mean, you got a lot of horizontal wells. But I think where we are specifically, there hasn't been a whole lot of activity horizontally. So what we don't want to do is we don't want to spend a lot of money for R&D when offset operators have maybe horizontal programs. We drill to find out what's successful and not and have maybe 1 rig drilling horizontals and the other 3 rigs drilling verticals. And a lot of that, just like Mark said, is what is your EUR and what's your drilling cost. And I think our costs are going to come down. You fast forward it a year from now, I think our cost is going to come down materially and vertically and I think horizontally. And if you look at the Eagle Ford, some of our initial Eagle Ford and even Haynesville/Bossier wells, they were $10 million, $11 million, $12 million, $13 million and today could probably drill a horizontal Haynesville well for somewhere in the $7 millions and complete it. In the Eagle Ford, if we had to drill and complete those wells for $7.5 million to $8 million, we'd probably do that. A lot of that depends upon the length of your lateral. So the costs are coming down. And kind of like the drilling time, it used to take us a couple of months to drill a Haynesville well. You can drill one of those in 15 days now. I know some of the operators in the Permian are saying that they reduced their drilling times about 40%. I think we'll be doing that, too. So a lot of that is just the nature of the new area. But I think costs will come down. I think we'll have a good handle on the EUR and the IRR, and I think they're going to be good. And they will compete against each other, being the Eagle Ford and the Permian, and once gas prices are $5, they will compete against the Haynesville. And the great thing about Compstock, we don't have any venture in place that forces us to spend money in a certain region, and we don't have a bank forcing us to hedge anything either, which tells you that we've got pretty good liquidity and pretty good financial positioning.

Operator

Your next question comes from the line of Ray Deacon of Pritchard Capital.

Raymond J. Deacon - Pritchard Capital Partners, LLC, Research Division

Mark, I had a question about the IP rates in the Eagle Ford. Do you think given where you're going to be drilling for the next couple of quarters, that the rates this quarter looked representative or...

Mark A. Williams

I think, Ray, I think they're going to creep up because we're going to be focused more on our South acreage in the fourth quarter and in the first quarter than we are -- than we were in the third quarter. So I think that average rate of 816, I don't think it will move significantly higher, but I do think it will move a little bit higher.

Raymond J. Deacon - Pritchard Capital Partners, LLC, Research Division

Okay. Got it. All right. And in terms of the Permian, have there been any transactions recently that give you more confidence about what you paid for Eagle? And have there been any recent horizontals you guys have heard of in any of the zones, Wolfcamp or other zones?

Mark A. Williams

Well, there's a package of properties, Ray, on the East side that is packaged to be sold by RBC, and we think it's Tier 1 acreage. Well, we looked at it. I mean, it's excellent acreage. It's roughly 50%. What is available is for sale, which includes operations. Bids were due the 17th of this month and we'll find out. We're -- we'll find out what happens with that property. It's pretty exciting because if it sells, it will be a pretty good marker for us because we paid $332 million in December of 2011, and I think the expectations for that property are a lot greater than that. So we'll find out, but we think it's Tier 1 acreage and it should sell for a mint. That's all vertical, that's roughly 145 vertical wells and I think the upside horizontally is to be discovered. It hadn't been unlocked yet. We're in some of those wells, and those are good wells. I mean, they're getting 600-, 700-barrel-a-day vertical wells. So it looks pretty good.

Raymond J. Deacon - Pritchard Capital Partners, LLC, Research Division

Got it. All right. I just want to make sure I understood the production decline. Roland, you said previously, you were looking at gas to decline, completed the wells you've drilled. So now, you're saying you got a little lower number in '12, so maybe it's more like 20%. Is that fair?

Roland O. Burns

I'm not sure what the reference to the 20% is, but...

Raymond J. Deacon - Pritchard Capital Partners, LLC, Research Division

Oh, well, I guess just how much decline year-over-year would you expect in '13.

Roland O. Burns

Oh, we still said 25% was our expected gas decline from our property base.

Operator

There are no further questions. I'd now like to turn the call over to Mr. Jay Allison for closing remarks.

Miles Jay Allison

Rachel, I wish I had your accent, but you could tell I'm not from New Jersey or from London. I'm from Texas. So anyhow, again, we've had a long conference call. It's 1.5 hours, I apologize for that. Hopefully, you've asked all the questions, have plenty of time to do that, and hopefully, we presented the story that we're not diluting anybody. We do have significant oil exposure both in Eagle Ford and the Permian. We think our cost structure will come down and our recovery rates will go up. We think we have tremendous upside of the 78 million barrels in Eagle Ford and over 178 million barrels in the Permian. There is divestiture that's contiguous to our acreage in the Permian. That will be exciting. I mean, we will drill several other horizontal wells, and I think they'll only get better. We do have scale in areas that we're in and I think that's important. So our gross stool is pretty stable, the Eagle Ford, Permian and then the inventory at Haynesville. Financial positioning, I think, is excellent. We are very fortunate to have the banks that we have to support us. Divestitures, I think that we do have hundreds of millions of dollars of divestitures in the future at a higher gas price but not today. And as far as the employees at Comstock, I don't think we've ever had a better group ever. So we're here to serve and we'll tell you the way it is.

So with that, thank you for listening in and being a stockholder. Thank you.

Operator

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

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