Comstock Resources Inc (CRK) 2014 Q2 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the second-quarter 2014 Comstock Resources' earnings conference call. My name is Glenn and I will be your Operator for today.

(Operator Instructions)

As a reminder, this conference is being recorded for replay purposes.

I would now like to turn the conference over to your host for today Mr. Jay Allison, CEO. Please proceed, sir.

Thank you, Glenn. Welcome to the Comstock Resources' second-quarter 2014 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 downloading the quarterly results presentation. There you'll find a presentation titled second-quarter 2014 results.

I am Jay Allison, Chief Executive Officer of Comstock, and 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 2014 second-quarter operating and financial results.

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

If you'll go over to slide 3, [I'll have some] opening comments before we go to slide 3. In the second quarter, our operations were smooth in all regions with the exception of the delay in the East Texas Eagle Ford Mach well completion which Mark Williams will expand upon in the operations update. Our South Texas Eagle Ford drilling program continued to perform as expected and even somewhat better since total costs continue to come down for drilling and completions.

We're extremely positive about our East Texas Eagle Ford region where we have 30,600 net acres in Burleson County. In fact we plan on moving a second rig into the area in the fourth quarter this year. Remember on April 2, about four months ago, we spudded our first well in our East Texas Eagle Ford region, the Henry well, which is being completed with a 30-day IP rate at 774 BOE per day.

We are completing the Mach well currently, had finished drilling the Flencher well, spudded the Curington A#1 well and have built locations for our fifth well, the Kovar well in our East Texas Eagle Ford region, all in about four months timeframe. We expect great results from this region.

In our TMS region, we have gone from 52,200 net acres in the first quarter to 60,600 net acres as of July. So 8,400 net acres added at low cost per acre. We have also built two locations in Wilkinson County and building a location in St. Helena Parish currently. As of this last weekend, we started moving a rig on location to spud the CRK Foster Creek well in Wilkinson County, our first TMS well that should be spudded by the middle of next week.

By this time next week we should have five rigs running. Three in the South Texas Eagle Ford region, one at our East Texas Eagle Ford region and one in the TMS. Things are on track and prove positive to Comstock as shown on slide 3.

Slide 3 lists some of the highlights of our second quarter. The 102% increase in our well production this quarter drove large increases in our revenues, EBITDAX and cash flow. Our oil and gas sales this quarter of $155.7 million were up 44% over 2013 second quarter.

EBITDAX this quarter of $121.3 million is 45% higher than 2013 second quarter, and our cash flow from operations grew 63% this quarter to $107.5 million or $2.29 per share. We reported net income excluding nonrecurring items of $5.9 million, or $0.12 per share for the quarter.

Our outlook calls for more oil production growth in the rest of the year. Oil made up 40% of our total production in the second quarter and is expected to continue to increase the rest of the year. We anticipate that oil production will grow 88% to 103% over 2013's production driven by our successful drilling program.

Since our last update, we drilled 21 successful Eagle Ford wells and put 19 new Eagle Ford shale wells on production. Our well costs keep coming down in our South Texas Eagle Ford program. 2014 well cost have averaged $6.9 million for the KKR promote which is 9% lower than last year.

We are very excited about recent development in our two new ventures, the East Texas Eagle Ford play and the TMS play. Our first well the Henry A#1 was very successful and initial production rate of 1,267 BOE per day. We continue to increase our acreage in the TMS and now have over 60,000 net acres. We'll spud our first well there at the beginning of next week. Now we'll let Roland review the financials results with you in more detail. Roland?

Thanks, Jay. On slide 4 we recap our oil production growth which is driving the growth. We've added revenues, cash flow and earnings this quarter. Our oil production increased to 12,200 barrels per day this quarter and was up 1,800 barrels per day, or 17% over our first-quarter rate. Oil production is 102% higher than the second quarter of 2013.

Our Eagle Ford properties in South Texas are driving almost all of this growth in oil production. For the first two quarters of 2014, we're expecting -- for the last two quarters of 2014, we're expecting our oil production to average between 12,500 to 14,400 barrels per day based on our current drilling and completion schedule. This would represent a year-to-year 88% to 103% growth over 2003's oil production.

Slide 5 shows our natural gas production which continues to decline and was down 29% from the second quarter of last year to 111 million cubic feet per day. With no natural gas directed drilling taking place this year, we expect our natural gas production to decline further in 2014 and to average approximately 98 million to 102 million cubic feet per day for the remaining six months of this year.

Slide 6 shows our realized oil prices this quarter. Oil price realizations in South Texas continue to improve in the second quarter of 2014 but were not as strong as they were in the second quarter of 2013. We realized $99.90 per barrel, down from $100.06 per barrel we realized in the second quarter of 2013. Our realized price averaged 97% of the average benchmark NYMEX WTI price.

57% of our oil production was hedged in the quarter at a NYMEX WTI price of $96.60. At our hedging program, our realized price decreased to $96.27 per barrel, 9% less than the after hedging oil price we averaged in the second quarter of 2013 of $105.30.

Slide 7 shows our realized oil prices for the first six months of 2014. We realized $98.39 per barrel in the first six months of 2014 down from the $102.60 per barrel we realized in the first half of 2013. Our realized prize was 98% of the average benchmark NYMEX WTI price. 57% of our oil production was hedged for this period at a price of $96.51 per barrel. After our hedging program, our realized decrease -- our realized price decreased to $95.78 per barrel, 11% less than the after hedging oil price we averaged in the first six months of 2013 of $107.89.

Slide 8 shows our current oil hedges for the remainder of 2014. We currently have 7,000 barrels per day hedged at $96.60. This represents around half of our projected 2014 production. We look to hedge our 2015 oil production when longer term oil prices approach the current levels.

Slide 9 shows our average gas price which improved by 19% in the second quarter to $4.42 per Mcf as compared to $3.71 in the second quarter of 2013. Our realized gas price was 94% of the average NYMEX Henry Hub gas price for the quarter. Our average gas price improved by 34% in the first six months of this year to $4.57 per Mcf as compared to $3.42 in the first six months of 2013. Our realized gas price was 95% of average NYMEX Henry Hub gas price for the first half of 2014.

On slide 10 we cover our oil and gas sales including the realized hedging gains or losses. The 102% increase in oil production and improved natural gas prices offset our lower natural gas production this quarter and drove our sales up 37% over the second quarter of 2013. Our sales increased $152 million this quarter compared to $111 million in last year's second quarter. Oil accounted for 71% of our total sales as compared to 52% in the second quarter of last year. Our sales increased to $292 million in the first six months this year compared to $208 million in last year's first six months.

Our earnings before interest, taxes, depreciation and amortization and expiration expense and other non-cash expenses, or EBITDAX, increased by 45% to $121 million from $84 million in 2013 second quarter as shown on slide 11. Our EBITDAX for the first six months this year increased by 48% to $232 million from $156 million in 2013's first six months. Cash flow increased significantly this quarter driven by the increase in oil and gas sales and lower interest cost.

On slide 12 you can see that our operating cash flow for the quarter came in at $108 million increasing 63% from cash flow of $66 million in 2013's second quarter. Cash flow per share this quarter of $2.29 per share was also up 63% from cash flow per share of $1.41 in the second quarter of 2013. Our operating cash flow for the first six months of 2014 came in at $205 million, increasing 68% from cash flow of $122 million in 2013's first six months. Cash flow per share for the first half of this year was $4.37 and was up 68% from the cash flow per share of $2.61 for the first half of 2013.

On slide 13 we outline our earnings. We reported net income of $1.9 million, or $0.04 per share this quarter as compared to a net loss from continuing operations of $21.5 million, or $0.45 per share in 2013's second quarter.

Unusual items in the second quarter results include a $5.8 million unrealized loss related to our oil hedges and a $300,000 impairment on our producing oil and gas properties. Excluding these items, would have reported net income of $0.12 per share as compared to a recurring loss from continuing operations of $0.32 per share in 2013's second quarter.

For the first six months of 2014, net income was $3.1 million or $0.06 per share as compared to a net loss of $46 million, or $0.95 per share in 2013's first six months. Unusual items in our year-to-date results include a $9.5 million unrealized loss related to our oil hedges and the impairment. Excluding these items, we would have reported net income of $0.19 per share as compared to recurring loss from continuing operations of $0.78 per share in 2013's first six months.

On slide 14 we show our lifting cost for Mcfe produced by quarter related to our continuing operations. Total lifting cost were $1.41 per Mcfe in the second quarter of 2014 as compared to $1.21 per Mcfe in the second quarter of 2013 but they also decrease from $1.47 rate we had in the first quarter of 2014. The higher lifting rates in 2014 are mainly due to the lower natural gas volumes that we produced and the fixed nature of much of our lifting cost, and also the higher cost of oil production including higher production taxes than we have on our oil sales.

Production taxes were $0.39 in the quarter and our transportation costs averaged $0.19 per Mcfe in the second quarter. Field operating cost improved to $0.83 this quarter as compared to the $0.90 rate we had in the first quarter of this year.

On slide 15 we show our cash G&A per Mcfe produced by quarter excluding stock-based compensation. Our general and administrative cost increased $0.41 per Mcfe in this quarter as compared to $0.33 in the second quarter of 2013 due to lower -- due mainly to the lower gas production volumes plus we had about $1 million of nonrecurring costs included in G&A this period.

Our depreciation, depletion and amortization per Mcfe produced is shown on slide 16. Our DD&A rate in the second quarter averaged $5.64 per Mcfe as compared to our $4.87 rate in the second quarter of 2013 and the $5.36 we averaged in the first quarter of this year. The higher rate is due to the oil production representing a higher percentage of the Company's total equivalent production.

On slide 17 we detail our capital expenditures relating to our continuing operations. We spent $308 million in the first six months of this year compared to $133 million that we spent in 2013's first six months related to our continuing operations. The $308 million in 2014 includes $50 million of lease acquisition cost primarily related to the acquisition of the additional 30% interest in our East Texas Eagle Ford shale acreage in Burleson County, Texas which was completed in the first quarter.

On slide 18 we outlined the components of our 2014 capital budget which remain unchanged from the first quarter. We're currently on track to stay within budget for our drilling and completion cost. We expect to spend about $510 million in 2014 on our development exploration projects and another $55 million for lease acquisition activity, which would include the first quarter acquisitions.

Slide 19 recaps our balance sheet at the end of the second quarter. We had $4 million of cash on hand and $975 million of total debt on June 30. Debt represented about 51% of our total book capitalization. Our borrowing base under our $1 billion bank credit facility is currently at $700 million giving us unused availability of $422 million -- $420 million. I'll now hand it over to Mark Williams to review our drilling results and operations.

Thank you, Roland. Slide 20 shows the location of the wells we have drilled in our Eagleville field in South Texas in the first six months of 2014 along with our 2013 drilled wells. We drilled 43 horizontal oil wells, 29.6 net in the first six months and had 2 wells or 1.6 net wells drilling at June 30. We have drilled 158 wells so far on our South Texas Eagle Ford acreage including 75 drilled in 2013 and 43 drilled so far this year. Our wells have had an average per well initial production rate of 728 barrels of oil equivalent per day. Our 30-day rates have averaged 79% of the 24-hour rate. And our 90-day rates have average 67% of the 24-hour rates.

Slide 21 compares our 2014 completions to our prior year completions. Our average 24-hour IP rates were lower this year at 685 BOE per day as compared to 780 BOE per day in 2013. Much of this was due to wells we drilled on our RTH lease which had short laterals due to our acreage configuration. Excluding these short lateral wells, our average 24-hour rates were much closer to 2013's average at 743 BOE per day.

On slide 22 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 $7.6 million per well in 2013. Faster drill times, lower well stimulation costs and more efficient field operations account for much of this savings. The wells drilled in recent years have had much longer laterals and larger stimulation treatments despite this lower cost.

In the first half of 2014, we reduced our average well cost to $6.9 million. Our joint venture further enhances our return as the effective average well cost in 2014 to Comstock on an eight-eights basis improves to $5.9 million when the KKR spud fee is considered.

On slide 23 we have our East Texas Eagle Ford acreage in Burleson County. We now have 30,600 net acres in this emerging play. Slide 24 shows recent activity in the vicinity of our East Texas Eagle Ford acreage. Our first well the Henry A#1 located in the center of our acreage had an initial production rate of 1,267 BOE per day. The well averaged 774 BOE per day for it's first 30 days of production.

We are completing a second well, the Mach A#1, which is taking longer than anticipated as we are making repairs to the casing which was damaged during that frac treatment. We recently finished drilling the third well, the Flencher A#1, which we drilled in 18.5 days. This is a substantial improvement over the first two wells. We have spud the fourth well, the Curington A#1, and as Jay said earlier, we have our fifth location built and ready.

On slide 25 we show our acreage in the emerging Tuscaloosa Marine shale play. We had 58,100 net acres at the end of the second quarter in what we believe is the most prospective part of this play. Including lease activity completed in July, we are now at 60,600 net acres. Our acreage is located in Wilkinson and Amite Counties in Mississippi and East Feliciana and St. Helena Parishes in Louisiana.

The next slide shows recent TMS wells including the very successful Goodrich Crosby well in Wilkinson County. Our first well which will be spud next week will be located just north of the Crosby well in Wilkinson County, Mississippi. I will now hand it back over to Jay.

Perfect. Again Roland, thank you, and Mark, thank you. If everybody would go to slide 27, I'll summarize our outlook for the rest of the year. This quarter's results showed continued progress as we transition to a more balanced Company by growing our oil operations. We continue to hold off on drilling natural gas wells until we can have returns on those projects that are competitive with our oil opportunities.

The strong growth in our oil production has more than offset the natural gas production declines that we are facing currently which is evidenced by our strong growth that we had in the quarter in revenues and cash flow. Oil made up 40% of our production this quarter and we expect that to continue to increase over the last half of this year. All of our operated wells we plan to drill this year will be oil wells. We are expanding our inventory of oil drilling locations by acquiring acreage into emerging oil plays.

And we're excited by the level of activity in both of these plays as offset operators have had successful wells near our acreage and we have now drilled our own successful well in the very middle of our new play in Burleson County. And we continue to have one of the lowest overall cost structures in the industry. Our natural gas properties in the Haynesville provide us substantial growth opportunities when natural gas prices improve. We have over 1000 undrilled locations on that acreage.

We continue to have a strong balance sheet to support our continued growth with $420 million of liquidity as Roland stated. For the rest of the call, we'll take questions only from research analysts who follow the stock. So Glenn, I'll turn it back over to you.

(Operator Instructions)

Your first question comes from the line of Brian Corales with Howard Weil.

Good morning, guys, and good quarter. Two questions on the East Texas Eagle Ford. One, we've seen the rig count pick up and we've seen a lot of good successful wells there. Is there a lot of acreage to be captured or is this all buying big packages now? And then two, Mark can you repeat what happened with the second well, I missed that?

I'll comment on the acreage. We pick up 200 or 300 acres, Brian, and again we look for acreage all the time as some of the companies do. Apache I think recently said their going to have 10 rigs busy there. That's a good thing for everybody. Halcon has three or four rigs. Clayton has two or three rigs. So it is busy. There's 15 or 20 plus rigs active in the area.

Some of the results hadn't been as good as others. So I think that to answer your question to get what we talked here on acreage, we ended up paying around $4,000 per acre. You're probably going to double, triple or quadruple that to pick up acreage now. From what we understand that's why we hadn't picked up acreage. But it's going to be a lot more expensive than what we picked up three or four months ago. So that's a good thing for the industry. And if we think we can drill on 100 acre spacing, we have 300 plus locations then we're going to be in good shape there. We do attempt to pick up more acreage but we're not willing to pay up materially for it at this moment.

In South Texas, again we've added a few acres there, not many. We'll probably have 100 drill sites at year end with the program that we're on. And we've not been able to pick up really any Tier 1 acreage there.

In the TMS, we did pick up a little over 8000 acres. $500 or so per acre where we're adding acreage and at the rate we're going there, we might get to our 80,000 net acre goal by year end. What we've told you and the public is hopefully we'll have 4,000 or 5000 net acres per quarter. But we're on a good glide path to get that acreage. So now go back to Mark on the -- is it Mach Williams or Mark Williams? We go back to Mark Williams on the Mach well.

Yes, Brian, it's Mark. What we did on that well is we fracked it, all the fracs went well. 17 stages about 9 million pounds. And then when we went into drill out the frac plugs with coiled tubing, we encountered a tight spot above the perforations. So we have analyzed that spot and it's a deformity in the casing that makes it too small for the mill to go through, so we have to go in and ream that out, get it big enough to get our equipment through so we can drill the frac plugs out and put the well on production. So that's what we have scheduled right now.

Okay, that was helpful. And then one final one and maybe for you Roland. I guess I would've thought we would have seen the gas production declines flatten a little bit, but it still seems to be pretty steep. Can you comment on that?

Well I think the gas -- we've said that gas is going to decline and I think it's within our expectations. There's absolutely no workovers or drilling or any operational support, so I think you're seeing the pure decline right now.

We're in the high 35%, 38% decline last year. Brian this year it looks like 25% to 30%. What you're really see here is purity. And a pure play like the Haynesville or any of the gas plays, if you don't have any recompletions or new wells, you can see a steep decline. And that's what we're -- we're the mirror image of that as Roland said.

And there's really no gas with our drilling programs coming from South Texas.

Yes, there's no supplemental gas. The great thing about our cores areas in South Texas and East Texas and the TMS they're all 85%, 90%, 96% oil.

Yes. And so if I look at 2015 versus 2014, would you expect another 20% to 25% decline without -- I know you haven't announced a budget, there's no more drilling, we -- would it be as low as 15% or would the declines be similar to what we're seeing this year that 25% or so?

Well we haven't really given guidance. So I don't really want to give guidance on gas without a budget and anything for 2015. But as the wells get older, the decline is going to soften as we're seeing right now.

Okay. (Multiple speakers)

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

Jay I think you mentioned the 80,000 acre TMS target in April to add $4,000 to $5,000 an acre, also the $500 cost. Where are you -- where have you been able to add those 8,000 or 9,000 acres since the end of the first quarter? Is it you're able to add any up in Wilkinson County or is more of it down in St. Helena and East Feliciana or any more color on where?

You can�t add that tough acreage anywhere near Wilkinson.

But we are going to add a lot in Wilkinson and filling in. But most of the acreage that has been fill-in acreage and so it is on the map. So the new map has been updated, but because it was pretty much maybe additional interest in acres that we didn't have 100% of the tracks or additional fill-in acreage, that's really been our goal is to -- so there's not any new areas at all. It is all contiguous acreage to what we owned before.

It's not a new big block of acreage, to get a big block of acreage in that core area where the activity is, you're going to pay up for that. We're not paying up for big blocks. Like our 33,000 net acres at Wilkinson, you don't find that type of acreage, we don't, available right now.

From eye balling the maps last night, it looked like more of it was down on Louisiana side than the Mississippi side and --

That's correct in the -- for the first six months and then maybe next -- you'll see more in Wilkinson in the third quarter because we just closed some there.

Okay. And it sounds like the rig is moving on to location, so you'll spud next week. When you look at your -- the location you're building down in Louisiana, is there -- are there any offset results near the location you're building down in Louisiana that we can look to as we look forward even past your first TMS well?

Yes this is Mark. I guess it'd be about halfway between the Goodrich Blades well and that recent Beech Grove well. Neither one of them are real close. It's just south and it's just a little bit south of the Encana Anderson wells. So I think there will be more activity and more results over the next quarter or two in that area then there have been so far. But those are the nearest ones right now.

And is the plan still to drill two or three wells this year or the fact that the rigs moving in a little bit late does that limit how many wells you'll end up drilling?

We plan to keep that rig busy, with the first two wells in Wilkinson and then move to Louisiana. And then really our goal is to continue to keep it busy in 2015.

I think we'll have two TDed by the end of the year, so our third will be drilling at the end of the year. That's how it's budgeted right now or projected.

Great. And then Mark over in the Eagle Ford, thanks for the description on the Mach well. But looking at where the Curington is and the Flencher, it looks like a lot of your activity is really more focused in your oil window. Any color in terms of where the fifth and sixth locations are being built? I guess trying to get direction in terms of how far to the south and east do you think you'll test by the end of the year or is this year really focused more in the oil side?

We're really just testing our acreage all the way across, so if you look on the map the fifth dot a little further to the east, just east of the Henry is the Kovar, that would be our fifth well. And then we've got two or three other locations working at least one of which would be south of that and I'm not sure which -- it depends which one will have title done and units formed and locations built in time. So we're a little bit flexible after that fifth one right now. But we do plan to test all of our acreage pretty methodically and see -- make sure we know what to expect over the whole acreage position.

And as the two rigs that you'll be going to, is that a thought of taking another one out of the South Texas Eagle Ford and moving into East Texas Eagle Ford, so you stay at five rigs? And if so, is that the kind of activity level that you think you may -- that you think this field supports or do you think there's future acceleration opportunity as we look to 2015?

No, this is Mark. I think we'll continue to accelerate this play as we go forward and prove it up and get -- really get it set up for full field development which we're not set up for yet. But yes we're planning on staying at five. We're moving a rig from South Texas to this play in the fourth quarter. And that would be our goal would be to -- well we don't have a budget for 2015 but our goal would be to accelerate this play as we're ready to.

Yes, right now it's a five rig program for out of East Texas or South Texas Eagle Ford. But it's a five rig Eagle Ford program.

Okay. I thought it was four there and one in the TMS.

Four right (multiple speakers).

Yes, but we'll end up -- what we're looking for now is we've got three rigs right now in South Texas and one of course in East Texas. We'll move one rig from South Texas to East Texas. But then I think as 2015 progresses, we will probably add another rig. That wouldn't happen until 2015 though.

Okay, perfect.

We will be plenty busy in the TMS.

Okay, great. Thank you.

Your next question comes from the line of Mike Schmitz with Ladenburg.

Thanks, congrats on a good quarter. Jay I think you mentioned with success you could have more than 300 locations in the East Texas Eagle Ford. Could you remind us how many locations you have left in the South Texas Eagle Ford? And following up on the last question, how do you see the South Texas Eagle Ford program in 2015 and 2016 relative to this year from a magnitude standpoint?

Yes, with the program that we have this year, which is roughly 45 net wells in South Texas, we'd have about 100 locations left in South Texas. And if you look at the 30,600 net acres we have in East Texas Eagle Ford call it on 100 acre spacing, it's about 300 locations.

What our goal really is we visited the second with Ron on that earlier, our goal is to have this four to five rig program in our Eagle Ford play. Right now we have three rigs in South Texas and again we have a rig in East Texas, we have a four rig program. We might end up with a five rig program sometime in 2015. Right now it is a four rig program. We'll move those four rigs around in those two places.

A lot of it will depend upon Mark and operations and our frac commitments and our drilling commitments. All the rigs that we have today can either drill South Texas, East Texas or they can drill in the TMS. So we're trying to make the rigs flexible. We try to make the completions flexible. And a lot of it will be just locations.

And Mark had mentioned earlier, we want to make sure land is far enough ahead of the drilling program so we don't start a big program in East Texas, we catch up with land. But think of problems, they're never really good problems. And particularly since the results that we've had in our East Texas Eagle Ford program have been good. And we're encouraged with all the offset operators being very active and having good results.

Two follow ups, the 100 locations South Texas Eagle Ford, that was the start of the year or that's after you drilled the 45 net wells this year?

That's after this year. We said initially we thought we had about 300 locations in South Texas. By the end of this year with the drilling program we have this year, we'll have drilled about 200 locations. Like Mark said, we drilled about 158 well so far. We'll end up with about 200 wells being drilled from inception in our South Texas program by year end. We think we got about 100 locations left. And we'll high grade those locations, that's what we think right now.

Okay and one last. What are your current thoughts on adding oil hedges for next year?

It's our goal to add some oil hedges for next year. We'll probably try to have those in place by the time we put our budget in place. So think the way the oil market has been working so backwardated, it's been better not to jump in too early.

We had 50% to 60% of our oil hedge, and then as Roland said, the last two quarters of this year we'll have about 50% of our production hedged.

Yes, that's our goal for next year.

And that is our goal for 2015.

Nothing more than that. Yes.

Great, thanks so much.

And you didn't ask but we still don't have any hedges for natural gas because we are not drilling any gas wells.

Your next question comes from the line of Kim Pacanovsky with Imperial Capital.

First a question on East Texas. Your 30-day rate on your well was 774, that's about 61% of IP. I'm curious if that fits your type curve?

Yes, Kim, this is Mark. The 774 probably fits our type curve better than the IP did. That well for whatever reason when we opened it up, it responded more positively than we expected on the IP. And then it fell down and lined out more as you would expect it to act. So the 774 that's above our type curve, but the well has been behaving since the first couple of weeks it's been behaving much more normally is what I'd say.

Okay. And you had mentioned that on the third well, the 18.5 days were substantially better than the first two wells. What was the average for the first two wells?

Kim the first well I believe was 40 because we drilled a pilot hole �and cores.

Right, okay. I guess that one doesn't count, let's say the second well.

The second well was 34, 35 days. We had a lot of trouble in the intermediate hole with lost returns. Very unusual, Austin chalk is going to be that way in that area. But the second, the third well and the fourth well have been much more normal in the chalk. That well, I don't know we were just next to a big fracture or something, it just gave us a little trouble.

Okay and then moving on to the TMS. Goodrich with their Beech Grove well got a lower than I guess anticipated IP rate there. And they have at least preliminarily attributed that to a lack of natural fracturing. But they had seen surrounding it, their vertical data showed that there was sufficient natural fracturing. So I'm wondering on your -- the next well that you'll be drilling down in Louisiana what do you see as far as fracturing is concerned from nearby vertical wells? And could you also tell us what depth contour that well will sit on?

I'll answer the easy question first, Kim. I think the contour is about 12,000 feet. I believe that's right, I don't have a contour map with me but from what I recall that's about right.

I think these fractures are going to come and go and you don't -- a vertical well doesn't see many natural fractures first off. You get a little indication on the logs but if they're older vintage logs, they're very difficult to tell. And then if there is a core within the area then your coring a six or eight-inch diameter vertical hole, you're not to see many of the fractures. We're planning to, right now anyway, we're planning to core that well so we should get some better data. Plus all the new vintage logs that will help us. But I really think the natural fracturing issues going to be a location to location issue, not more of a regional type issue.

Okay, that's helpful. And it would be great if you guys could show your future locations on your map on your slide deck.

Well they're not ready yet.

Okay. All right, thanks a lot guys.

Your next question comes from the line of Brad Heffern with RBC Capital Markets.

Sticking with the TMS, I wonder if you could provide any color around maybe what the AFE on that first well is going to be and any color you can give on the completion design and how you're planning to land it relative to the rubble zone?

Well Brad, this is Mark. As far as the AFE I think it was just over $14 million which includes a pilot hole and a full suite of new vintage logs to capture as much data as we can on that well. We do not plan to core that well because the Crosby well just across the way was cored. So getting redundant on information if we do that.

Completion, our plan is to copy the Crosby well. It's the best well in the field and is right adjacent to us, so we will do everything completion wise to be very, very similar to that well and just to prove that we can reproduce those results.

Okay, got you, that makes sense. And then looking at CapEx for the year, obviously if you take the first half run rate that would end up being well above the budget. Is there cost savings that you're expecting in the second half of the year or less acreage spending?

Well if you look at the CapEx, if you look more at the second quarter standalone, the first quarter has been a lot of extra cost in it as we went over that call. So I think if you look at this quarter is more closer to what we'll spend in the third and fourth quarter, probably a little under. Those will be a little bit higher but the six months is really skewed by the first quarter where we had an acquisition in there of the Burleson acreage and we also had a lot of carryover completion costs. There we spent $188 million in the first quarter, $120 million in the second quarter.

So yes, we're tracking right on our budget for drilling and completion. For acreage it's very opportunistic driven, so it's impossible to budget. And so that area, depends on opportunities we could see more opportunities to spend a little bit more on acreage or we could see less.

Okay. Thank you.

(Operator Instructions)

And your next question comes from the line of Jeffrey Campbell with Touhy Brothers Investment Research.

A quick South Eagle Ford one. You featured three outperforming Eagle Ford wells. I was wondering was that outperformance due to lateral length or geology or both?

Let me thumb back there a little bit, Jeffrey, and make sure I know which one--

Like three guys -- like 860s or maybe around 850 average, something like that.

Yes, those wells a fairly long lateral but that's in a good performing area, in the middle of our acreage. And so those are probably the -- of the group of wells we drilled this quarter, that's probably the best acreage in that area.

Cortez wells and Hubberd wells.

That's in the core of our acreage that has been a good producing area.

Okay, that's good color. Going to the East Texas Eagle Ford, doesn't seem like anybody's drilled any condensate window wells yet. Do you guys have any plans to do that, any appetite to test the condensate?

Jeffrey, this is Mark. We plan to test all of our acreage. The southernmost acreage we believe is in the volatile oil window and not in the condensate window, but we won't know for sure until we drill it and test it.

Is it - is that kind of a southern acreage test in mind for maybe sometime in 2015?

We should drill a well -- Jeffrey I think we're planning to drill a well near the end of this year as we work our way south, but I don't know if it'll be right at the end of the year or if it will roll over into early 2015. Just depends we can get the acreage and the units put together.

Yes, but we'll probably drill one year end or first of next year.

Okay. Quickly when we -- when you -- based on the data you've got, when you compare these East Texas Eagle Ford and the TMS and you compare the decline curves in each play, do you see a lot of similarity? Are there any discernible differences between the two?

Jeffrey, this is Mark. Again we see a lot of similarity between all three of the plays, between the South Texas Eagle Ford, the East Texas Eagle Ford and the TMS. And I think if you look at some of the properties the thickness, the pressure, the age of the rock, they're all very similar. There are some differences in gas/oil ratio that may affect it a little bit, but all these horizontal plays have been following a fairly normal, I wouldn't say normal, I'd say a fairly standard decline curve.

And last question I'd like to ask. In second quarter of 2014, Encana talked about Haynesville recompletion as it costs $1 million per and they were IPing at an average of 400 -- 4 million cubic feet a day. They said they were the highest return wells in their portfolio, including condensate and oil wells and their effort is ramping up. I'm wondering have you heard about this or are you keeping an eye on it? Do you have any potential interest in trying anything similar?

Jeffrey, this is Mark. We have heard about it. We're monitoring the results of both Encana and EXCO as it's so new that there's not much public information out other than what they're saying. But yes we'll monitor it. We don't have any money in our budget for this year to do that and we'll look at it hard for 2015's budget if the results hold up.

Okay, great. Thank you.

At this time we have no further questions. I will now turn the call over to Mr. Jay Allison for closing remarks.

All right. Well as always, Glenn, thank you for hosting the call. And then we want to thank all the shareholders that bought the stock for a long time and we thank you for your time. We spent today hopefully we've covered in detail and we're working daily to create value for the shareholders. So thank you.

Ladies and gentlemen, that concludes today's conference. Thank you for your participation. You may now disconnect and have a great day.