Comstock Resources Inc (CRK) 2012 Q3 法說會逐字稿

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 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.

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 and were not directly hit by super storm, Sandy, it is really kind of a somber morning. It's a strange morning. We've been doing this for 24 years and it's a strange morning not to have your stock trading.

As you know, Roland and I have spent a lot of time 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 for the super storm 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 will open it up with the third quarter 2012 results. If you'll 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 entitled Third Quarter 2012 Results. I am Jay Allison, President of Comstock. And with me this morning are Roland Burns, our Chief Financial Officer; and Mark Williams, our Chief Operating Officer.

During this call we will discuss our recent drilling results and review our 2012 third quarter financial results. Forward-looking statements that's on 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 expectations in 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 received for our production. The growing oil side of the company is helping mitigate the negative impact that the very 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 had operating cash flow of $71 million, or $1.47 per 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 revenues. We've had strong results in our 2012 drilling program which Mark will go over in a moment. We drilled 56 successful wells, including 49 successful oil wells in our Eagle Ford and Wolfbone programs.

The increasing 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 end of last year.

I'll now turn it over to Roland to cover the financial results in more detail. Roland.

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 7200 barrels per day as compared to third quarter of last year when we produce 2100 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 the 4600 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 one-third of our interest has slowed our oil growth this quarter and for the upcoming fourth quarter.

We're adding another rig to our Eagle Ford program in late November, which will bring us to three rigs by December. This initial activity allows 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 1900 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 are forecasting our oil production to grow by approximately 190% to 200% over last year's production with a total of 2.4 million to 2.5 million barrels in 2012. We expect again in 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% in the third quarter from last year to 220 million cubic feet of gas per day. The decrease is probably attributable to the 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 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 in our chart on slide 5, averaged 27 billion 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 remained the same at 7 million per day.

We are lowering our forecast for natural gas production for this year to approximately 81 Bcf to 82 Bcf which would represent a decrease of 9% to 11% from 2011's total production. Production has started -- our production has started to decline a little earlier than we originally anticipated, and will continue to decline until we restart our drilling program 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 the $87.55 per barrel in the third quarter of 2011. Our realized oil price averaged 105% of the average benchmark NYMEX WTI price due to the high differentials we are receiving for our Eagle Ford shale oil. Sixty-eight percent of our production was hedged in a 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 $0.17 more than our realized price in the third quarter of 2011.

Slide 7 shows our oil prices for the first nine months of this year. Our realized average oil price increased 8% in the first nine 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 during this period at a NYMEX WTI price of $99.43. Including the gains from the hedges, we realized $102.30 per barrel in the quarter which was 10% higher than what we realized in 2011.

On slide 8 we outlined our hedge program 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 $4.09 we realized in the second of -- or, the third quarter of 2011. Our realized gas price was 88% of the average NYMEX Henry Hub gas price for the quarter. Our average gas price for the first nine months of 2012 decreased 42% to $2.37 per Mcf as compared to $4.09 for the first three quarters of 2011. Our realized gas price is 92% of the average NYMEX Henry Hub gas price for the first nine 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 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 nine months of 2012, sales have increased 4% to $332 million as compared to $320 million for the first three 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 expiration expense, and other non-cash 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 nine 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. Operating cash flow for the first nine 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 outlined 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 nine 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 seen $0.16 per share for the same period in 2011.

The quarter and the year-to-date financial results for both periods include several unusual items. For the third quarter the reported results include a net loss in property sales of $2.8 million $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 had a $1.4 million impairment or $900,000 after tax or $0.02 per share relating to upcoming lease expirations. For the first nine months of 2012, those results include a net gain of $24.3 million or $15.8 million after tax or $0.34 per share on the property sales that we made. Gains of $26.6 million or $17.3 million after tax, or $0.37 per share on sales of our Stone Energy shares and $8 million in impairment, or $5.2 million after tax, or $0.11 per share. If you exclude all these items, we would have reported a net loss of about $0.50 per share this quarter and about $1.23 per share for the first nine months of this year.

On slide 14, we show our lifting costs per MCFE produced by quarter. Our lifting costs are comprised of three different items, production taxes, transportation cost, and other field level operating cost. Our total lifting cost this quarter were $1.06 per MCFE as compared to $0.79 per MCFE in the third quarter 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 and administrative costs 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 the 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 of 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 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 cost 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 now making up a greater percentage of our total production and revenues.

On slide 17, we detailed our drilling expenditures. We have spent $402 million so far this year on drilling the 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 nine months of this year as compared to $53 million that we spent in 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 the 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 30th 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 bank credit facility.

Yesterday, our banks approved a new borrowing base for us 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 in its own by December 31, 2012.

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

Thanks, Roland.

On slide 19, we recap our activity in our East Texas, North Louisiana region so far this year. In the first quarter we drilled three operated Haynesville wells 2.5 net before moving our two operated drilling rigs out of the region. We participated in another four non-operated wells so far this year, that's 0.7 net wells. In the third quarter we completed the last of our operated Haynesville shale wells. We still have three non-operated Haynesville shale wells waiting to be completed. We will be able to exploit our 7 TCFE of Haynesville and Bossier resource potential in the future when improve 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 up side 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 -- 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 geo pressured. This is why we're 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 eight 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 one 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 production of which 79% is oil.

Of the eight new operated wells reported on in the third quarter, the Ponderosa Estate 25 1# and the Jesse James 4 2# each had an initial production rate of 511 BOE per day. We also participated in five 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 1#H targeting the Wolfcamp shale formation, and the results have been very positive with an initial production rate of 653 BOE per day. This well was completed with 15 frac stages over a 3627-foot lateral. Our second horizontal well targeting the Wolfcamp shale, the Dale Evans 196 2#H, has reached total depth at 14,584 feet with a 3428 foot drilled lateral, and is currently waiting to be completed.

Slide 23 shows the 41 operated wells in our Wolfbone field, including the eight 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 have 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 the 41 wells on our acreage. The wells with the highest IP rate so far have been in the area 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 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 five separate type curve areas that we use in this drilling program. After deducting royalties and interest that our new partner will earn in the growing venture, we estimate our properties we own 78 million barrels of oil equivalent of which over 80% is oil.

Slide 26 and 27 show the results and locations of the 41 wells which are currently producing. We completed six more Eagle Ford wells since our last update. They are the last wells on the list, wells number 36 and 41. The 41 Eagle Ford shale wells that were completed had an average per well initial production rate of 705 BOE per day. The six new Eagle Ford wells reported in this quarter average 816 BOE per day with the Swenson C 1#, the Hill A 3#, and the Hubbard 1#H in McMullen County having the highest rates at 1002, 829, and 786 BOE per day respectively.

These wells are being produced under the Company's restricted choke program and initial tests were obtained using a 14/64 to 16/64 inch choke. That 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 and $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.

Thank you, Mark.

If you'll go to the 2012 outlook 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 two 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. Ninety-three percent of the net wells we'll drill in 2012 will be oil wells and 78% of our budget will be spent on oil projects.

Even though overall production this year might not grow much after the divestitures we completed last quarter, we expect our oil production to grow close to 200% over last year. Our Eagle Ford shale program, which is becoming more prolific with Mark driving well costs down and to promote we get to 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 costs in this play and are working to create a successful horizontal program to drive up the rates of 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 in the fall and natural gas prices, the reduced leverage this year by completing asset divestitures which generated net proceeds of $183 million. We also completed a bond offering 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 forecasted drilling program. The new joint venture agreement we closed on in the third quarter of allows us to ramp up our drilling activity while at the same time reducing are spending level.

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

(Operator Instructions) Please stand by for your first question. Your first question comes from the line of Brian Corales of Howard Weil.

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

Mark.

Brian, as far as what we 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 have also changed how we pick our perforations, so we are 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 the 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 and I think that's driving the IP rates. I think overall EURs we're probably not going to see nearly as much of a difference east to west as we do on the early rates, but that's what we're seeing right now.

Is the product mix changing as you go east?

Not really. It's pretty -- with about 1800 standard cubic per barrel yield or GOR on both sides. Now, if you get way over on the west edge, it starts to go up. That's way out kind of on the western edge of our acreage. We are seeing the GORs climb to maybe 2,500 to 3,000.

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

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

Okay. That's very helpful. And this may be a dumb question, but looking at '13 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 your rigs back to the Haynesville with this small little running gap prices we've seen?

With oil prices where they are today, the marker is if you have a $5 natural gas price and at $5 we can get 30% plus rate of return in the Haynesville, we wouldn't look at bringing rigs back in the Haynesville unless you have a $5 handle on it.

That's kind of what we said corporately. So, as far as CapEx dollars in 2013 with commodity prices as they are today, we kind of pulled out $10 million for maintenance and that is if we have to drill a well or if we get an AFE or whatever. If you own 140,000 acres in the Haynesville and Bossier and 7 TCF both sides, 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.

Alright, guys. Thanks so much.

Thank you, Brian.

Thank you. Your next question comes from Cameron Horowitz of US Capital Advisors.

Good morning. Question for Mark. Mark, can you just tell us a little bit about maybe what you learn from them Monroe well as far as where you want to land your lateral, how to space your frac, et cetera, and are you doing anything differently because of that on the Dale Evans 11 well?

Cameron, this is Mark. We did not 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 Wolfcamp B. The Dale Evans is targeting the middle Wolfcamp. And then we've got two other wells scheduled to spud this year and they'll be targeting different intervals as well. So, our goal is 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 log properties and the rock properties in other areas and begin to define what our good targets are and we think there's multiple ones. We just need to figure out which one works the best in which area.

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

Cameron, that will be our goal is be to pull or form larger units everywhere possible to get our lateral length 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 length 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 reserves per dollars spend.

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?

Yes, the Monroe was a little over $9 million, the stimulation costs are coming down in West Texas the way they are in the Eagle Ford. So, I think our next job that we have coming up was substantially less, I think between $0.5 million and $1 million cheaper, so that's going to help a good bit. And we had to drill a few to kind of get our system down and improve our -- 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 is what our goal would be to get these wells drilled once we get just a little bit better at it.

Okay. Great. Thank you so much for the color.

Your next question comes from Leo Mariani of RBC.

Hi, guys. Just sticking with that Monroe well there, can you just give us the high carbon breakdowns in terms of oil, NGL gas on that well?

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

Yes, I think it started out at 78% and IP and then ended up about 82% at the 30 day on a composition basis.

I haven't seen the processing statement on NGLs yet, but that is the oil and gas breakdown.

Got you. Okay. That's helpful. In terms of well costs, 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?

Leo, on the Eagle Ford cost out there is probably going to run between $8 million and $8.5 million. Our lateral length on the wells we're drilling right now, some of them are fairly long and so the cost does increase with lateral length because you are 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 length. 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 are 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 more of a focused vertical program rather than having a program that really is able to bounce back and forth between the two. We really plan to separate them where we can focus on the vertical side, focus on our cost, and get that focus down with a target in the low 4's.

Okay. That's helpful color for sure. I guess in terms of your gas price, it looks like your differential's 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?

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. Some of it's 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. 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 contributed -- with those out of the picture, that contributes a little bit to lower average differential. And then as you are in the low gas prices, some of the -- a lot of the transportation costs aren't percentage based. They are fixed rates. So, with a low base gas price you're going to have a higher percentage differential because it's not a percentage based calculation. So, that and the volatility of gas prices, we had -- our production was kind of up and down during the quarter. It wasn't necessarily spread out over the three months very evenly, so I we think we have a little more production in the lower price months than higher price months. That part would not be recurring probably, but the other two would be recurring.

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?

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

Alright. That's really helpful. Thanks, guys.

One comment on the Eagle Ford, we've reduced costs probably a little less than $8 million right now, but as you increase the laterals, like Mark said, we are probably in the eight kind of zip code in that, but if we had to have wells that cost less than that we could, but it's all a factor of how long the lateral is, and 6,000 feet is a pretty good lateral. And then I think on the vertical Wolfbone, some of the offsetting operators are drilling just vertical wells for 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, any time 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 have been superior to offset operators. So, I think we are getting close there.

Alright. That's great color, guys.

Thank you our next question comes from the line of Ron Mills of Johnson Rice.

On the completion cost side I don't know, Jay or Mark, who is best to answer this, is 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 are the prime determinants behind the $400,000 or $500,000 of cost savings?

Ron, this is Mark. It's both. The $400,000 or $500,000 is renegotiation of pricing, 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 new bill crews that showed up this year. So we have had indications of some additional price improvement at the end of the year.

And is the $400,000 to $500,000 what you think it 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?

That was our improvement from third quarter to fourth quarter.

And so you can see potentially more than 2013?

Yes, that's correct, Ron. I don't 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.

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

I would say that's more in the Eagle Ford just because the quantity of service in the Eagle Ford and I think that's going to happen in West Texas. We are 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 the Eagle Ford has with services yet.

Okay. Great. 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 that still the case and, B, it sounds like you will be at three rigs in Eagle Ford by year end. How do you look at the Permian in terms of anticipated activities/rig levels?

What we'll do in December, we have a Board meeting mid December. We will see where commodity prices kind of end up in December. Our goal is to have three rigs busy in Eagle Ford and again, as Mark had said or alluded to earlier, if we drill more in McMullen, we are going to hit these 900 to 1,100 barrel a day wells, higher IP wells and we can do that because we have a really great partner with KKR. So, we can put that third rig in and I think our costs go down and 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 will see in the first quarter 2013 it will all be working really perfectly, it should. So, a three-rig program in 2013 and again you've got maybe $10 million in 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 two different programs in the Permian. One is maybe have a rig or two that just drills horizontally and I think the rest of the rigs we'll drill vertically so, in a perfect world we'd like to see a four-rig program in the Permian. We'd like to have at least one of them drill horizontal wells, we'd like to have three of them drilling vertical wells hopefully at a cost around $3.5 million to $3.7 million to drill and complete and produce these wells.

Now, we're not there yet. So, we'll look in December and we'll see what our free cash flow from operations might be. We have a couple hundred million dollars available under our credit line and that's a big event because 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'll kind of see that looks like in December. And then we'll come up with this, quote, three- to four-rig program in the Permian. We'd like to have four and we'd like to have three in the Eagle Ford, but we'll make that call in December.

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

No. We're going to provide that when we come out with our budget instead of just trying to -- they are out numbers right now. Until we know our budget, we can't really tell you how much oil can grow.

Okay. And I guess lastly, the incremental two wells on the horizontal side in the Permian, are any of those added and it sounds like at least one of those will be targeting the 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 employee that information as you look to a longer lateral completion?

Yes, Ron. We're going to evaluate -- we have a lot of information to evaluate between now and then both on our wells and offset activity, so we'll incorporate all that and 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 see between now and next January or February.

Great. Okay, guys. Thank you.

Ron, on the horizontal, again, at the beginning of the year we thought we might drill one horizontal maybe and then now we're going to end up with three or four. We kind of forced the Monroe and somebody asked the question earlier, why didn't we drill a longer lateral? Well, the lease that we drilled on only allowed us to drill that 3600 foot lateral and it takes a lot of land work to unitize leases to allow you to drill longer laterals. So, in 2013 I think we'll be doing that and, as Mark said, you need to drill a 5400-foot or 6,000-foot lateral to optimize the reason you drill the horizontal well.

The other thing we did, if you remember when we closed this December of 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 three quarters and now we 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 had did some pretty good horizontal wells. Now, as we understand one's in the Wolfcamp B, one's in the A, et cetera. Ron, we're also -- we've got this other issue and that is when the leases are 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 at 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 months from now, like Mark said, we'll be on more the eastern side which, if you had your druthers right now, would 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 to put together a lease where we can drill 6,000 foot laterals. 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.

Thank you so much.

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

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

Hi, Dan, this is Roland. Yes, that's definitely one of the measures that we look at a lot when evaluating leverage. There's, of course, two factors. Having less debt and having more EBITDAX. I think we are going to be seeing improvements in our EBITDAX as we move away from the very low $2 type gas prices and become more -- and also have higher oil mix. So, we see that that leverage ratio is going to be improving just with the growth in cash flow and the growth in EBITDAX from the new oil production that's coming on, and just getting little bit improvement in gas prices. So, we think that's important. To reduce debt, we'd have to not invest in our oil properties and we're kind of saying well, let's not increase debt, but let's spend our cash flow on our high return projects and that will allow us to reduce leverage.

So, we definitely want to improve it through 2013, but we don't have to do anything drastic to improve it such as slashing our capital budget so much that we can't grow our oil production or do 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 that's kind of what we would look to, to bring down the overall debt levels of the Company. We are patient. We don't 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.

Okay. And on the subject of the divestiture candidates, is any of the Haynesville shale or Bossier shale perspectively sold?

No. We don't view that as a divestiture candidate at all. We think that's 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 in, in the future in the right price environment. So, we are guarding our prime Haynesville acres. Now, if there's some fringe acreage, we might let some of that go over time if it's not operated, but in general we want to hang on to our core Haynesville. Not looking to divest that or the other production that's there with it because we want to keep all rights and not sell our Cotton Valley or other formations in that area.

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 the third quarter conference call it was only June of last year that we put a second rig in to drilling the Eagle Ford. So, this time last year we were saying, well, we've got second rig drilling in the Eagle Ford. I mean, it was almost a non-event. Well, one of our goals was we were -- the reason we were a really great natural gas company in '08 is because we were in the Haynesville Bossier, we were 98% natural gas unhedged, all the great things until you have a recession and a glut and those are facts. So, then what happens?

We specifically said we haven't issued equity in eight years. We said we really want to add two core oil fields, significant oil fields that give us significant exposure. We're already in South Texas and we started spending some money on the Eagle Ford acreage. So, we ended up with 28,000 net acres. We basically leased most of that, have 100% ownership and after we drill those 35 wells and de-risk it, we brought KKR in which is a great partner for the $25,000 an acre. So, that was one of the goals and 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. You can 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 this background noise and having fringe acreage or tier two and three 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, two or three land groups go out. We went to Gaines County. If you'll notice 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 and looked at all the pressured areas and then knock, knock, knock an opportunity comes along in Reeves County and we said, well, significant oil exposure 178 million barrels, it has 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 did not 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 net debt to cap to 54% to 55% net debt to cap, but what we told you we would do we did. We had $184 million divestitures, either Stone shares or AA or [slygo] or some of the other properties. And then we hedged our oil which we got pretty aggressive on that, 60% to 70% of oil is hedges for this year and next year, and then we pulled in our budget even though it seemed to be out of control in the first quarter, we told you we would pull it in and that's when we went to one rig in the Eagle Ford.

We pulled it in and we didn't add a second rig until KKR came in. So, I gave 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 revenues from oil. But then you go to 2013 and the two basins that we were in right now, the Eagle Ford and the Permian, we could be 30% oil plus and then by 2014 we are 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 is not, quote, in the Eagle Ford kind of footprint, I think those will be candidates when gas prices are higher. But I think one of our holy grails of the whole Company, which is not valuable today, is the Haynesville Bossier. You go 1600, 1700 wells in, in three years from zero production to 7 BCF in the Haynesville it caused a glut. 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 two big oil projects and then inventory, and I think that's a key word, inventory at Haynesville.

Fortunately, we didn't have to sell down or we didn't have a partner there to cause us to drill wells in the Haynesville that we shouldn't be drilling. And we didn't have to delude ourselves by issuing equity. We're one of the fortunate companies that could transition to oil exposure without deluding 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 will do that. So, I just want to give you a sense of comfort of what we are trying to do.

That's very helpful and 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?

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 Permian basin. We've got $500 an acre in it. The leases are three-, four-year leases. We would like to drill and we're probably budgeted to drill one or two wells and Mark would like to drill more, but at least one or two in Gaines County. They would be vertical, but if we're right there, Dan, we've been riding these new areas most of the time. If we are right there in a very prolific county that produces a lot of oil, that is upside that we don't have a lot of money, a lot of equity built in there. So, Mark, you may want to comment more on the type of well you would drill.

Yes, that's exactly right. Our goal would be to drill one or two 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, oil gas mix, what type of capacity to produce those zones have, and then have them set up where we could re-enter them at a later time and throw horizontal laterals out of those vertical well boards. 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.

That even goes back, Dan, to the Pearsall. 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 core one or two 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 two 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 or Bossier's core tier one area, the Eagle Ford definitely is a tier one area and the Permian is definitely a tier one area. So, through our operations group and reservoir group and our G&G group we've been able to add those core areas without deluding anybody.

Very good. One last one for me. Sticking with West Texas. The Ponderosa and Jesse James wells, the latest two wells, vertical wells to the Wolfbone are certainly over producing wells, not unlike the first Jesse 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 over producing vertical wells?

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 it all up to see exactly, but I think that's about right.

Very good. Thanks again.

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

As you move to drill the longer laterals in the Wolfcamp, 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?

Mike, it's Mark. I think it's very early for us to hang a number on these wells. We're still testing zones. Generally speaking, you don't get that 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 an 8,000 foot lateral 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. It's going to vary a lot over the field and by reservoir as well.

Okay. And if you mark to market current service cost, what is a fair D&C on those longer lateral wells?

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

Okay. Great. It seems like you talked about 2013's program, just initial glance at it and that you favor still drilling vertical rigs versus horizontal. Do you think that is ultimately how this acreage or this place shapes up for you, it's primarily a vertical play or with success in your initial wells here, do you think it could shift and be drilled more from a horizontal perspective?

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. But there is probably 20% of the play we think that only should be drilled horizontally. 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 crack the code horizontally. I think that the offset operator to the east, they drilled 145 vertical wells, they hadn't 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, New Mexico, coming down you've got a lot of horizontal wells, but I think where we are specifically there haven't been a whole lot of activity horizontally. So, what we don't want to do is we don't want to spend a whole lot of money for R&D when offset operators have maybe horizontal programs. We'd rather find out what's successful and not and have maybe one rig drilling horizontals and the other three rigs drilling verticals. And a lot of that is, like Mark said, what is your EUR and what is your drilling cost? I think our costs are going to come down. You fast-forward it a year from now, I think our costs are going to come down materially vertically and I think horizontally if you look at the Eagle Ford, some of our initial Eagle Ford and Haynesville Bossier wells, they were $10 million, $11 million, $12 million, $13 million and today you could probably drill the horizontal Haynesville well for somewhere in the $7 million and complete it, and in the Eagle Ford if we had to drill and complete those wells for $7.5 million to $8 million, we probably do that. A lot of that depends on 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 months to drill a Haynesville well. 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 time by 40%. I think we will be doing that, too. So, a lot of that is just the nature of the new area.

I think costs will come down. I think we will have a good handle on the EUR and the IRR and I think they're going to be good, and they'll compete against each other being the Eagle Ford and the Permian and then once gas prices are five, they'll compete against the Haynesville. And the great thing about Comstock, 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.

Alright. Thanks for the color, guys.

Thank you.

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

Yes. I'm sorry. Can you hear me? Yes, 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 quarters, that the rates this quarter look representative?

Ray, I think they're going to creep up because we are going to be focused more on our south acreage in the fourth quarter and in the first quarter than we were in the third quarter. 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.

Got it. 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?

There's a package of properties right on the east side that is packaged to be sold by RBC. We think it's tier one acreage. We looked at it. 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 will 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 will find out, but we think it's tier one acreage and it should sell for a mint.

Got it. Great.

That's all vertical. That's roughly 145 vertical wells. And I think the up side horizontally is to be discovered. It hadn't been unlocked to get.

Got it.

We are in some of the wells and those are good wells. I mean, they are hitting 600 to 700 barrels a day vertical wells. So, it looks pretty good.

Got it. 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?

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

Well, how much decline year-over-year would you expect in '13?

We still said 25% was our expected gas decline from our property base.

Okay. Got it. Great. Thank you.

Thanks, Ray.

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

Rachel, I wish I had your accent, but you can tell I'm not from New Jersey or from London. I'm from Texas. So, anyhow. Again, we've had a lot along conference call, it's an hour and a half. I apologize for that. Hopefully you've asked all the questions, had plenty of time to do that, and hopefully we presented the story that we are deluding anybody. We do have significant oil exposure both in the 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 a divestiture that is contiguous to our acreage in the Permian, that will be exciting. We will drill several other horizontal wells and I think they will only get better. We do have scale in the areas that we are in and I think that's important.

So, our growth still is pretty stable with the Eagle Ford Permian and 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 divestiture 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 are here to serve and we will tell you the way it is. So, with that, thank you for listening in and being a stockholder. Thank you.

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