Comstock Resources Inc (CRK) 2013 Q3 法說會逐字稿

Good day ladies and gentlemen, and welcome to the third-quarter 2013 Comstock Resources earnings conference call. My name is Lisa and I will be your coordinator for today.

At this time all participants are in a listen-only mode. We will facilitate a question-and-answer session towards the end of this conference.

(Operator Instructions)

As a reminder this conference is being recorded for replay purposes. I would now like to turn the call over to your host, Mr. Jay Allison, Chief Executive Officer. Please proceed, sir.

Thank you, Lisa.

Before we start I've got about six or seven bullet points that I want to make sure that those are attending the conference, if they leave early, will get these bullet points pertaining to the quarter. As you all know, this is the first quarter that we've had where we have had that Permian divestiture behind us. With the proceeds from the Permian sale we have retired $735 million of debt, really in the last six months, so the question is what do we do with that. The bullet points are one--because of that we now have been able to double our Eagle Ford rig count. We went from three rigs to six rigs, as you know. And that allows our Eagle Ford oil production to grow to anywhere from 33% to 36% over that production of 2012.

The sale of the Permian also allowed us really to be 20% oil at the end of 2013 as far as production, and we should be 40% at the end of 2014 as far as oil production. It also allows Comstock to complete something like 15 additional net wells in the Eagle Ford versus our initial projections at the beginning of this year. We've added three more even in this quarter. It has allowed us to repurchase shares. We've repurchased 1.3% of our outstanding shares. And I think the other thing that it does -- we will spend $120 million to enter into two new oil basins, so the question is are we having some science experiment and the answer is quite frankly no.

We are not looking to enter into a science experiment that will dilute the strong return currently being seen in Eagle Ford, but rather invest in two areas, each of us we think has the potential to be another Eagle Ford. And we throw that $120 million out so you will know that we are not going to get in a financial strait. That's the amount of money that we are investing in the future in two new plays. And you also will note after the divestiture of the Permian, our bank credit facility should increase to $1 billion with $625 million initial borrowing base and our year end oil production should be greater that what we had projected as if we had kept the Permian. All those are great points that I did not want anyone to miss if they left the conference call early.

With that, welcome to Comstock Resources third quarter of 2013 financial and operating results conference call. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and clicking presentations. There you will find a presentation entitled Third Quarter 2013 Results. I am Jay Allison, Chief Executive Officer of Comstock. With me this morning are Roland Burns, our President and Chief Financial Officer; and Mark Williams, our Chief Operating Officer. During this call we will discuss our 2013 third quarter operating and financial results.

If you go to 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 the securities laws. But we believe the expectation as such statements to be reasonable, there can be no assurance that such expectations will prove to be correct.

Now slide 3. Our 2013 third quarter highlights summarizes our third-quarter results. Our third-quarter operating results were defined by continuing strong growth in our oil production and improved natural gas prices offset in part by declining natural gas production. Our oil and gas sales increased to $112 million in the third quarter, our total EBITAX was $82 million, and our total cash flow from operations was $63 million or $1.31 per share.

Our Eagle Ford drilling program is providing strong oil production growth this year. Our oil production increased 14% from the second quarter and is up 30% over last year's third quarter. Oil made up 22% of our total production in the third quarter alone. We expect oil production this year to grow 33% to 36% over 2012, as I stated earlier. The first three quarters of 2013 we drilled 47 successful Eagle Ford Wells and also completed 42 Wells which had an average well initial production rate of 797 barrels of oil equivalent per day. Our results in our Eagle Ford program have improved considerably since last year. Our 2013 completions had 30 day initial rates that are 25% higher than the 30 day rates in 2012, while at the same time our average well cost had decreased by 13% from 2012.

With a very strong balance sheet with the West Texas divestiture, which closed in the second quarter. The divestiture allowed us to retire $735 million of debt this year, including the October 15th redemption of our 2017 bonds. At the end of the third quarter our net debt has improved from 59% to only 35% of our total capitalization.

I will have Roland Burns report on the financial results for the quarter in more detail. Roland?

Thanks, Jay.

Slide 4 shows our oil production related to our continued operations by region and on a daily basis for the last three years by quarter. Oil production this quarter increased to 6900 barrels per day and was up 900 barrels per day, or 14% over the second quarter this year. Oil production was also up 30% from the third quarter 2012. Our Eagle Ford properties in south Texas account for most of our oil production at 6600 barrels per day. We are looking for our oil production to average between 8300 and 9000 barrels per day in the fourth quarter. The wide range that we are providing for guidance in the fourth quarter is due to the very large amount of completions that are planned for December so the exact time of those will have a big impact on how we finish up the year.

Slide 5 shows our natural gas production from continuing operations on a daily basis. Our natural gas production declined by 5% to 148 million cubic feet per day, as compared to 156 million per day we produced in the second quarter. Production from our Haynesville Wells, which is shown in dark blue on the chart, declined by 5 million per day to 103 million per day this quarter. Production from our Cotton Valley Wells shown in green, average 20 million per day and our South Texas gas production shown in light blue, was also 20 million per day. Other gas production shown in purple, increased to 5 million per day. We expect our natural gas production to decline further in the fourth quarter to approximately 130 million to 140 million cubic feet per day.

Slide 6 shows our realized oil prices related to our continued operations for the third quarter. Oil price realizations in south Texas weakened in the third quarter as the NYMEX WTI contract outperformed the LLS Gulf Coast market indexes. We realized $104.83 per barrel for oil production as compared to $99.34 per barrel that we realized in the third quarter of 2012. With the Gulf Coast premiums failing to keep up with the WTI contract, our realized price averaged 99% of the average (inaudible) NYMEX WTI price. 79% of our oil production was hedged in the quarter at a NYMEX WTI price of $98.72. After considering losses from our hedging program, our realized price declined to $99.20 per barrel, or 7% lower than after-hedging oil price we averaged in the third quarter 2012, of $106.10.

Slide 7 shows our realized oil prices for the first 9 months of this year also related to our continuing operations. We realized $103.47 per barrel in the first 9 months of 2003, up 1% from $101.99 per barrel we realized in the first 9 months of 2012. Our realized price averaged 106% of the average WTI price for the periods. 83% of our production was hedged in the first three quarters of this year at a NYMEX WTI price of $98.69 per barrel. After our hedging program our realized price improved to $104.49 per barrel, 1% lower than our after-hedging oil price we averaged in the first 9 months of 2012 of $105.37.

On slide 8 we outline our hedge position. We have very attractive oil hedge position which protects the 2013 and 2014 drilling program. We have 6000 barrels per day hedged for the fourth quarter at $98.67 per barrel, and 5500 barrels per day for all of 2014 hedged at $96.31 per barrel. We plan to hedge about 60% to 70% of our 2014 production so we will continue to add some addtional oil hedges as this year progresses.

Slide 9 shows our average gas price which is improved by 37% of the third quarter to $3.33 per Mcf, as compared to $2.43 in the third quarter of 2012. However, natural gas prices this quarter fell about $0.38 from the prices we realized in the second quarter of 2013. Our average gas price improved by 44% in the first 9 months of 2013, to $3.39 per Mcf as compared to the $2.35 we realized in the same period of 2012. Our realized gas price is averaging 92% to 93% of the NYMEX [hindered] gas price so far in 2013.

On slide 10 we cover our oil and gas sales, including realized hedging gains or losses. Our decline in natural gas production was offset by growth in our oil production and improved natural gas prices in the third quarter. The sales relating to our continuing operations increased by 8% to $108 million in the third quarter, as compared to $100 million in 2012's third quarter. Oil production made up 58% of our total sales, as compared to 51% in the third quarter of last year. Sales relating to our continued operations increased by 7% to $316 million in the first nine months of this year, as compared to $296 million in 2012's first nine months. Oil production made up 53% of our total sales, as compared to 49% in 2012.

Our earnings before interest, taxes, depreciation, and amortization, and exploration expense, and other non-cash expenses or EBITDAX decreased by 5% to $82 million from the $86 million that we had in 2012's third quarter as we show on slide 11. $12 million of our EBITDAX for the third quarter of 2012 was related to our discontinued West Texas operations. And $74 million is attributable to our continuing operations so EBITDAX from continuing operations increased by 11% this quarter. Our EBITDAX increased by 6% to $52 million in the first 9 months of this year, from $238 million in 2012's first 9 months. EBITDAX from continuing operations only in the first 9 months was $238 million in 2013, and $212 million in 2012 for an increase of 12%.

Slide 12 covers our operating cash flow. Our operating cash flow for the quarter came in at $63 million, a 10% decrease from total cash flow $70 million from 2012's third quarter. However, cash flow attributable to our continued operations this quarter was 5% higher than the $60 million that we had in 2012's third quarter. Our operating cash flow for the first 9 months was $192 million, 2% less the cash flow of $197 million in 2012's first 9 months. Continuing operations cash flow of $185 million for the first 9 months of 2013 increased 6% over the same period in 2012.

On slide 13 we outline our earnings. We report a net loss today of $24 million or $0.52 per share this quarter, as compared to net loss of $44 million from continuing operations, or $0.95 per share in the third quarter of 2012. We had some unusual items in the third quarter results including unrealized losses relating to are oil hedges, impairments on our unevaluated leases, and a loss in property sales which total $9 million. Excluding these items, we would've reported a net loss relating to continued operations of $0.40 per share, as compared to recurring net loss of continuing operations of $0.73 per share in 2012's third quarter.

For the first 9 months of 2013 net income was $79 million or $1.63 per share, as compared to a net loss of $22 million or $0.47 per share in 2012's first 9 months. Including the net income with a gain on the sale of our West Texas properties and their related results of $149 million or $3.08 per share. We had a net loss of $70 million, or $1.45 per share related to our continuing operations. Excluding the same unusual items, plus the gain we had in selling our markable securities in the first quarter, we would've reported a net loss relating to continued operations of $1.14 per share as compared to the recurring loss of continuing operations of $1.35 per share for the same period in 2012.

On slide 14 we show our lifting cost per Mcfe produced by quarter related just to our continuing operations. Lifting cost in this chart are made up production taxes, transportation, and other field level operating cost. Our total lifting cost this quarter increased $1.24 per Mcfe, as compared to $0.96 per Mcfe in the third quarter 2012, and $1.21 per Mcfe in the second quarter of 2013. This increase is mainly due to the lower natural gas volumes and the fixed nature of much of our lifting cost and higher production taxes related to the stronger gas prices. Production taxes this quarter were $0.24 per Mcfe, and transportation averaged $0.26 in the third quarter. Field operating costs remained unchanged this quarter at $0.74 per Mcfe.

On slide 15 we show our cash G&A per Mcfe produced by quarter, excluding stock-based compensation. Our general and administrative cost increased to $0.29 per Mcfe this quarter, as compared to the $0.21 per Mcfe we had in the third quarter 2012, solely due to the lower production volumes we have in 2013. G&A expenses per Mcfe decreased from the second-quarter rate of $0.33. Our depreciation, depletion, and amortization per Mcfe produced is shown on slide 16. Our DD&A rate in the third quarter averaged $4.93 per Mcfe, as compared to the $3.99 rate we had in the third quarter of 2012, and the $4.87 we averaged in the second quarter of 2013. The higher cost of the oil production and the write-down of undeveloped natural gas reserves last year arising out of the very low natural gas prices are causing the increases.

On slide 17 we detail our capital expenditures related to our drilling operations. Capital expenditures from our discontinued operations after January 1st were reimbursed to us as part of the sales price are excluded from this slide. So far this year we spent $234 million on our drilling program as compared to $266 million that we spent in 2012's first 9 months. Capital expenditures in south Texas, which is shown in red on this chart, relate to our Eagle Ford drilling program, which increased to $215 million so far this year, as compared to $163 million we spent in last year's first 9 months. With low natural gas prices, our spending for our natural gas properties in North Louisiana declined to only $19 million so far this year, as compared to $103 million we spent in the same period of 2012.

On slide 18 we have an updated estimate of our 2013 drilling program and our capital budget. We are now expected to spend about $345 million for drilling activity this year and we've also increased the number of net Eagle Ford Wells being drilled to 49.6, as compared to 46.9 net Wells in our prior budget. Offsetting the increase in the Eagle Ford we are estimating that we'll spend less on our natural gas properties in theHaynesville Shale. In addition to the drilling expenditures we've budgeted $140 million to spend on acreage acquisitions, including the $120 million on the two new oil plays that Jay referred to earlier. The remaining $20 million are costs that we spent on our Eagle Ford acreage or capitalized interest or other acreage costs.

Slide 19 recaps our balance sheet at the end of the third quarter. We had $228 million for cash on hand and $884 million in total debt at September 30th, bringing our net debt down to $656 million. Our net debt is now 35% of our total capitalization, as compared to 59% at the end of the first quarter. On October 15 we used most of our cash and borrowed $100 million under our credit facility to redeem our 8.375 bonds due in 2017. We are currently completing a new $1 billion 5-year credit facility that would have an initial borrowing base of $625 million. We expect to close that in the next couple of weeks.

Starting in June we began paying a $0.125 dividend per quarter per share. The dividend cost the Company around $6 million a quarter. As shown on slide 20, only a third of the 61 E&P companies we survey pay a dividend and of those 61 companies we have the second highest dividend yield at September 30th of 3.1%. In the third quarter we also had some activity in our share repurchase plan which we detail on slide 21. We repurchased 1.3% of our outstanding shares, or 631,096 shares for $9.2 million at an average of $14.63 per share. We still have over $90 million authorized per-share buybacks in the future.

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

Thanks, Roland.

On slide 22 we cover our South Texas operations where all of our current activity is in our oil focused Eagle Ford shale play. At the end of the third quarter we had 26,500 net acres reflecting the recent acquisition of 2300 net acres, and the expiration of a similar amount of acreage in Atascosa County. We are working on other bolt-on acreage acquisitions in our area. We estimate that we have 300 operating drilling locations with a total resource potential of 70 million barrels of oil equivalent net to our interest.

Slide 23 shows the location of the 89 producing Wells we have drilled in our acreage. In the first three quarters of 2013 we drilled 47 horizontal oil wells, 31.6 net and had 11 Wells, or 8.3 net drilling at December 30 of this year. We have also completed 42 or 26.4 net horizontal Eagle Ford shale Wells, including 6 or 3.8 net wells drilled in 2012. The 42 Eagle Ford shale Wells that were completed this year had an average per well initial production rate of 793 barrels of oil equivalent per day. This rate is 22% higher than the average IP from 2012.

Slide 24 shows the results of the 89 Wells which are currently producing. We completed 17 more Eagle Ford wells since our last update. They are Wells 73 through 89 on this list. The 89 Eagle Ford shale Wells that were completed had an average per well initial production rate of 745 BOE per day. These Wells are being produced under the Company's restricted show program and the initial tests were obtained with a 14/64th to a 16/64th choke. The 30 day per well production rate for these wells averaged 588 BOE per day, and the 90 day per oil rate averaged 492 BOE per day, or 68% of the initial 24 hour rate. The 2013 completions have initial rates that are 22% higher than the initial rates in 2012, and have 30 day rates that are 25% higher.

The four 3rd-quarter Wells with the highest initial rates were the Swenson C#4 H, Forrest Wheeler D#1H, and the Swenson #7H and #8H, which are all located in [McMullen] County. These Wells had initial production rates in excess of 1000 BOE per day.

On slide 25 we track the cost of our Eagle Ford Wells which have decreased considerably since we started drilling in August 2010. In 2010 our first two Wells averaged $11.4 million. Costs have been reduced to an average of $7.8 million per well in the first 9 months of this year. Faster drill times and lower well stimulation costs account for much of the savings. We expect the average Eagle Ford Well to cost $7.6 million in the fourth quarter of this year. On the far right you can see the effect of the KKR promote on Comstock's realized well costs. The effective average well cost to Comstock on #8H basis improves to $6.6 million with the joint venture promote.

On slide 26 we show the progression of lateral length over time on our Wells in the Eagle Ford. Even though costs have come down considerably, the lateral length has increased by 44% since our drilling program began. The average lateral length was 6625 feet in 2013, as compared to 4595 in 2010. This increase is a function of our increased confidence in executing longer lateral's without complication and our goal of maximizing our rate of return, as well as utilization of all of our acreage.

On slide 27 we show the increase in proppant pumped since our program began in 2010. Half of this increase is due to the increasing lateral length. We pumped $8.7 million pounds of profit this year per well, as compared to 4.4 million pounds per well in 2010. We have increased the amount of proppant per lateral foot by 35% since 2010.

Slide 28 shows the net Eagle Ford wells being put on production per month so far in 2013 and what is projected for the rest of the year based on running the six rigs that we have in the program. The monthly variation is due to multi well pad drilling and subsequent multi well stimulation operations which creates lumpiness in our Eagle Ford production curve in 2013. Our expected fourth-quarter Eagle Ford production will benefit from the increased number of completions due to doubling the rig count this year. The large increase in completions in December is due to four 4-well pads being drilled and then completed simultaneously. This activity will provide sustained momentum into the first quarter of 2014.

I will now turn it over to Jay.

If you continue to stay on slide 28 the full impact of our six rig Eagle Ford drilling program really shows up in the fourth quarter of 2013, particularly in December. We expect to complete more Eagle Ford Wells in December of 2013 than all of the third quarter of 2013. Again, that's because you start seeing the full impact of our six rig Eagle Ford drilling program.

If you go to slide 29, our 2013 outlook, I'll summarize our outlook for the rest of the year. With continued weak natural gas prices, we've been focused on increasing our oil production with our Eagle Ford shale drilling program which provides high returns on our investment. We will not start drilling natural gas wells until we can have a high returns on those projects. We expect the strong growth in our oil production will more than offset the natural gas production declines we're facing, allowing us to have higher revenues and cash flow, and being a much more profitable company in 2014. We expect oil to comprise 20% of 2013's production even after the sale of our Permian Basin properties and will grow to 40% by the end of next year. 96% of the net wells we'll drill in 2013 will be oil wells, and 96% of our budget will be spent on oil projects.

We are expanding our inventory of oil drilling locations by completing bolt-on acreage acquisitions around our Eagle Ford properties, and by acquiring acreage in emerging oil plays. We continue to have one of the lowest overall cost structures in the industry. We now have a very strong balance sheet after the West Texas divestiture. We'll have $0.5 billion in liquidity at the retirement of our 2017 bonds that we completed on October the 15th.

For the rest of the call we will take questions only from research analysts who follow the stock. So Lisa I turn it back to you.

(Operator Instructions )

Ron Mills, Johnson Rice

Good morning, this is actually Don. Jay, on your new ventures are you still focused on the four state area that you outlined at our conference of Louisiana, Mississippi, Texas and Oklahoma?

Yes. And the reason we gave you those areas are one, Don, I think the two or three things that we needed to make clear were when we sold Permian is one, we've got a great wealth-creation group and you say where have they created great wealth? It's Texas, Louisiana, Oklahoma, and Mississippi. Those are the states that we've been very good in and that's where our people have been very good in. So we're staying within those states. We will give you a budget.

We're not going to spend $300 million, $400 million, $500 million chasing something, we're going to spend $120 million and we found the two areas that we really like. We are attempting to lease right now and if anyone on the call asks if we are in a particular play we won't comment on it because we're not publicized that we're in any new play other than the Eagle Ford, and that we have inventoried the Haynesville gas for future drilling when gas prices are anywhere from $4.30 to $4.50 or above. But we have located two basins that we really like. It's totally unanimous from the reservoir side, the operation side and the G&G side that these are kind of look-alike potential of the Eagle Ford. In the future and maybe they will be, maybe they won't be but what we categorize is what the Eagle Ford might've looked like in the very first part of 2010. We're spending anywhere from $200 to $1500 or so per acre and you can -- we said that the goal is in each of these plays we are going to have a minimum of 20,000 or 25,000 acres, and maybe a maximum of 50,000 acres and that's kind of your $120 million.

We never said that we are going to be like Rip van Winkle and go to sleep and not acquire acreage because we acquire acreage. When we got out of the Gulf, we went out to the Haynesville, it worked. We went out from the Haynesville we go to the Eagle Ford, it worked. We go from the Eagle Ford to the Permian, it obviously worked. And guess what? We are back working again. We're telling you the dollars that we are going to deploy too, and we're going to tell you that we are going to attempt a have a somewhat balanced budget in2014.

We talk about our budget in December but we are not going to become reckless because we have money but we're going to be accountable for all of the shareholders. We are going to give them a dividend, we are going to buy shares back if we think the shares are behaving improperly. At the same time we'll invest in the future of the Company and it should be two new areas. So I hope, Don, that's as good an answer I can give you right now.

Absolutely. And I appreciate that. And look into 2014, while I'm not looking for specifics can you comment just broadly on staying within cash flow like you talked before? With the new ventures are you going to have a lot of time on these leases in order to evaluate and not spend a bunch of money right from the first day?

The goal is to add two new core oil basins, 80%-plus oil, it's to have the equivalent of primary leases, so that the leases don't dictate that you have to have heavy drilling at all, and you can filter in these two plays throughout 2014. And you can do it within a reasonable budget. So our goal is to not materially outspend our free cash flow at all. We work and try and stay within that ballpark. I think once we are able to announce what we're doing, then Don, we will put the budget together and believe me we will be accountable for the dollars we will spend and you will never see us become reckless because we shouldn't become reckless. We fought really hard to reduce our debt the right way by being--by creating a profit, and we did that in May of this year.

So you can see that our borrowing base should materially increase. Our production should grow. We've got a hedging program for oil so we're going to protect ourself from the downside. We go from spending $103 million in the Haynesville, to $19 million this year. Next year it could be like $10 million. We don't really see any obligation wells in Haynesville that we have to drill. We may just put a small budget in there just to have it there, but we are going to be a good, solid growth company with a good, strong balance sheet.

Okay. Jay, I appreciate it. I'll get back in the queue.

Thank you, Don.

Ray Deacon, Brean Capital

Good morning. I have a question for Mark. I was wondering--I didn't hear you talk about the oil gas mix on the wells in McMullen, the Swenson in the Forrest Wheeler Wells, is it gassier as you go south? I'm assuming yes?

Yes. We are between 80% and 90% oil on all of our wells. GOR if not very high and even in McMullen County, so we are probably still over 80% on those wells.

Okay. Great. And I was wondering can you give me a sense of what the EURs were on the two Haynesville Wells you drilled this year? And kind of what your plans are looking like into 2014 there?

As far as 2014, we don't have any Haynesville Wells planned. We have a small budget that we will probably include in our 2014 budget just for non-op and anything that comes up that might be an obligation, but we don't have anything planned to drill in 2014. I don't have a specific EUR numbers on those two wells. They are probably in the six range something in there.

Okay, got it. And then maybe just one last quick one. In terms of the acquisition, would you be looking to have a partner on that or would you want to stay 100%?

I think what we do on that, Ray, we'd see what our obligation might be and then if there is an increased amount of acreage that we could possibly acquire, if we have a partner. I think the goal is to have a financially sound balance sheet and CapEx budget, at the same time drill several wells in 2014 in each of these areas to prove up the areas along with other operators that are in the areas. And then if we can add more acreage and it makes sense to bring a partner and I think we'd look at that. I think we have the potential to bring one in. So in the past you didn't know if we could bring one because historically we never have, but I did think our relationship with KKR and/or others and our performance at the drill bit in the areas that we've been in would allow us to do that. So I think that's just a financial decision where we don't plan on getting over levered at all. If we need a partner to take a little bigger bite out of the apple then maybe we'll do that. But we are not telling you that we will. We're telling you that if we had to we would.

Okay, got it. Thanks, Jay.

Mike Kelly, Global Hunter Securities.

Thanks. Jay, your recent strategy in Eagle Ford. Just curious if this is changed now that you have $120 million slated to go outside the Eagle Ford into new basins. I think the original plan is 6,000 to 7,000 a year being added and just kind of core of bolt-on deals.

I think the answer is we're continuing, like we added the 2,300 acres in the Eagle Ford in the last quarter, we are continuing to add Eagle Ford acreage. And we've got the more acreage in the queue right now. But I think we've got like a $20 million, we give you kind of a $20 million budget for that and that's the 3,000 to 6,000 acres or so. So that is still what we are doing but you can't always rely upon the fact that you can get that amount of acres annually. We think we have a pretty good shot this year and we are already have some more acreage reported into next quarter.

However, you still have to rely upon your big growth engine, which is our G&G group to find new areas, like they did in the Permian, like they did in Eagle Ford. I think, Mike, the difference is we said that was a $50 million to $100 million investment and now we've changed that. We said well we really know now it's between $100 million and $120 million in these 2 new areas, if what we are attempting to do we are successful in doing. So we thought it's fair for the shareholders and you, as analysts et cetera to know what we're doing with the dollars and to know that we are trying to create wealth in two other regions that are similar looking to what the Eagle Ford looked like at the beginning of 2010. Which goes back to Don's question earlier, if you remember when we marketed with you, when we went into Eagle Ford, we put a rig in July of 2010, we didn't put a second rig until June 2011 so we let our outcome dictate the number of wells that we drilled in the Eagle Ford. And along with success from the other operators in these two new areas that we are attempting to acquire acreage in, that is the same strategy.

So, we will make an additional investment of $100 million to $120 million in these two areas. We will filter in these wells throughout 2014. We will not become reckless. Hopefully we will add great inventory of oil locations in each of those two areas by the middle to latter part of 2014, by a little bit of our own drilling by a lot of other operators drilling. So no, it's basically the exact same footprint. We're going to continue to add Eagle Ford acreage when we can find it. We're not quick to bank everything on doing that, even though we've been successful this last quarter and acquiring acreage and it's not a lot of money in Eagle Ford. Does that answer that?

Yes it does. Two quick follow up's on that front. So, if I took the $20 million that you have allocated to the Eagle Ford lease hold CapEx, and just divided by the midpoint of that 3,000 to 6,000 that implies you're paying about a little over $4000 in acre. I just want to confirm that is what you're doing this at. And then just the timing on the leasehold pickups in these two other basins, you do have it in the 2013 budget. Do you expect to be--how much do you expect to actually get signed by the end of the year?

Well the $4000 is a good number give or take $400 or $500, that's a good number. And then I think the reason we stick that $120 million in 2013 is because there's a great chance that will happen in 2013. We don't want to surprise anybody year-end also we see that we spent $100 million to $120 million when we told the market it's between $50 million and $100 million we said it's going to be down into next year and you don't know when those opportunities come around. But they're here so we're kind of giving you a heads up that there is a chance that that might happen this year.

All right, thank you.

Which, Mike would be good because that we can factor that in for our budget in 2014.

Rehan Rashid, FBR Capital Markets

Good morning, Jay. My favorite question is downspacing in Eagle Ford. Looks like you are carrying 80 acre spacing, any updated thoughts on that please?

There's not a big Mark up on that and he won't budge on me, but I'll let him answer that.

We are always evaluating it but based on our information, our reserves, and recoveries we don't think that downspacing is really an opportunity that we will pursue in Eagle Ford at this time. We think we are at the right spacing and we think as you get much tighter you really diminish your net present value on the properties by going down.

Okay. Any incremental changes to well design from here, more stages, more tighter cluster spacing anything on that front?

We are testing several right now. We are testing both of those really, tighter cluster spacing and fracking less clusters per stage. And we will do those tests over the next couple months and kind of see what kind of impact we get. And move forward with the revised design if we do see enough benefit for that additional cost.

Okay. On the Haynesville front, last time Jay, we talked you guys had mentioned some kind of incremental work on longer laterals, any kind of update on that front from permitting, to science work standpoint?

And we think in the core for the Permian if we extend the lateral to 7.5 we could probably have a drilling program in the $4.30 price range. However, Rehan, I think with the success we've had in Eagle Ford and hopefully the potential purchase in leases in two new key core areas within this oil basin, we will de-risk part of that in 2014 and then we will see where gas prices go. And we tried (multiple voices) the Company up to say--look we've got 6 Tcfe. We think there is resource potential in Haynesville. I guess at a $4.30 price we could probably start some of the infill for section to have drilling, laterals. But really if you are at a $4.50 to $5 price, that's when you can have a dedicated program and you can hedge and you can ( technical difficulties ) your Haynesville better.

So we are, that's why we are enclosing we said don't think that we have to drill any Haynesville wells because we don't. Can we in the future? Absolutely. And the beauty of that is, unlike 2012 we spent $103 million holding acreage and completing wells in the Haynesville. This year we spent $19 million, that's a lot of extra money we can spend on oil run now and that's what we're doing. And that's what we should be doing.

One quick one. The share buyback with capital allocation priority changing into 2014 with more acreage, does that share buyback take a backseat from this point on?

No, not at all. I think that's what we try to advertise. Here is the amount of money we've invested, we will invest, or hope to invest in acreage in the future. We do hope to have two new oil regions and we will filter in whatever budget we will have in two regions in 2014 budget if we can close those by year end. But at the same time we are totally committed to a dividend which is a 3% yield. At the same time we are committed to share buybacks if the shares do what we call misbehave. So we bought 1.3% of the shares back and we can do that and you can see our borrowing base should go up to that $1 billion or $625 million available. So we are getting stronger financially and the reason is we divested ourselves of the Permian properties. It unlocked our great strength and we are using those now. You are just now starting to see it.

Perfect. Thank you.

Amir Arif, Stifel.

Just a question, can you give us a sense of how much of the $120 million you've spent so far?

No, we cannot comment on that.

None at the end of the third quarter.

But good chance most of it should be done by year end. Is that fair? Based on your previous comments?

I think we would like for it to be spent. Whether it happens or not I don't know.

Okay. And then just a quick question on the Eagle Ford production growth. Just given the completions that you showed in that one chart with most of them coming in December, even at the low end of your 8.3 to 9 range, that's implying 20% sequential growth. You guys are comfortable with that based on the completions that were happening in 3Q?

Yes. This is Roland. A lot of that was achieved with the activity in the third quarter, not really based on the December activity. So achieving the high end of the range would have those contribute some. With those being pushed toward the very end of the year that's why we have kind of a larger range that we would like to have for the fourth quarter because of the timing of--do we get a month of production out of a lot of those, do we get a half a month, do we get a day. So that accounts for the range. But we are very comfortable that we could be in that range given the levels of production we have now.

Okay, sounds good. And final question on Haynesville. If you didn't do any drilling next year what kind of decline rates would that field have, 15% to 20% would be a fair number? Or would it still be higher than that?

I think that I know we are looking at our total gas production to decline by 15% to 18% next year, so that Haynesville is probably a little large of the component would be a little larger than that, probably the 25% range.

The company wide 15% to 18% is a good number.

That's what we're looking at with no investment in gas at all next year, so we think that's kind of the floor.

Okay, sounds good. Thanks.

Marshal Carver, Heikkenin Energy Advisors.

Yes, the down tick in the 3P reserves in the presentation from 78 million BOE to 70 million BOE, what -- did you condense some locations or are you assuming smaller wells there? What drove that change from 2Q to 3Q?

Marshall what we did is with that some of the acreage has expired and that's out of our acreage count and most of that we did have locations on. And then we added some new acres and that's really just a more refined calculation of putting-- we do have 300 operated, engineered locations on our acreage that we feel like will all be developed and we just kind of put those in the real proper EUR categories. We think is a very fair number and a much more precise number than before. I think it's just much more precision. There is some of our acreage that has, that's not been put in and operated even yet that probably we have potential for, but we are going to kind of wait and add that when we get those put into a unit. I think it's really just more precision of the numbers than anything else.

Okay. In terms of the two new areas. Is it a bunch of small packages with sort of organic leasing or is there a few key packages you're looking for. I'm wondering if you'd likely have an announcement or would it just be when you're numbers come out, you will reveal the positions.

I think we have an obligation if we spend that amount of money between now and year end then we'll put a Press Release about it because I think that's a fair thing to do to the market.

And Marshall, I think you got a look at the rest of the year and things could be different before the fourth quarter update, which obviously won't come until next year, we will finalize our bank facility so that should be pretty imminent coming out. We will report on our capital budget after approval by our board in early December. Those two are things that are planned on and then I think that if we are able to complete significant leasing in these two areas in the fourth quarter, which we think is probable, then we would probably report on that also. I think those are the three announcements we can say that are probably going to come before the end of the year.

Okay. Thank you.

Rehan Rashid, FBR Capital Markets.

On the inventory for Eagle Ford, is that a remaining inventory? Is that the total?

Right now that would be the total. I guess you are talking about acreage?

Okay. Yes. Thank you.

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

Again, I think this is the first quarter that we've had -- it's pretty much a clean quarter after the divestiture and you can see hopefully the direction that we are focused. We are focused on telling you what our bank facility looks like. We're telling you what the results are from the six rig in Eagle Ford and what they should look like in October, November, December this year. And then being accountable to you for the entrance into two new oil regions that we think we'll be successful in entering. And if we are successful we will put a Press Release out on that will be accountable to how we would develop those regions in 2014 and beyond. So again we always are appreciative of your time and thanks for the conference call.

Ladies and gentlemen, this concludes today's presentation. You may now disconnect. Have a great day.