Miles Jay Allison - Chairman and Chief Executive Officer Roland O. Burns - President, Chief Financial Officer, Principal Accounting Officer, Secretary and Director Mark A. Williams - Chief Operating Officer and Vice President of Operations.

Brian M. Corales - Howard Weil Incorporated, Research Division Ronald E. Mills - Johnson Rice & Company, L.L.C., Research Division Michael C. Schmitz - Ladenburg Thalmann & Co. Inc., Research Division Kim M.

Pacanovsky - Imperial Capital, LLC, Research Division Brad Heffern - RBC Capital Markets, LLC, Research Division Jeffrey Campbell - Tuohy Brothers Investment Research, Inc..

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..

3 in the South Texas Eagle Ford region, 1 in our East Texas Eagle Ford region and 1 in the TMS. Things are on track and very positive for Comstock, as shown on Slide 3. Slide 3 lists some of the highlights of our second quarter. The 102% increase, in our oil production, this quarter drove large increases in our revenue, EBITDAX and cash flow.

Our oil and gas sales this quarter of $155.7 million are up 44%, over 2013 second quarter. EBITDAX this quarter of $121.3 million is 45% higher than 2013's 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 for the rest of the year. Oil made up 40% of our total production, in the second quarter. It 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 a successful drilling program. Since our last update, we drilled 21 successful Eagle Ford wells and put 19 Eagle Ford shale wells on production. Our well costs keep coming down in our South Texas Eagle Ford program.

2014 well costs have averaged $6.9 million before the KKR promote, which is 9% lower than last year. We are very excited about recent development in our 2 new ventures, the East Texas Eagle Ford play and the TMS play. Our first well the Henry A#1, was very successful at an 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 financial results with you in more detail.

Roland?.

Thanks, Jay. On Slide 4, we recapped our oil production growth, which is driving the growth we've had in 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 2 quarters of 2014, we're expecting -- I mean, for the last 2 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 our own natural gas direct to 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 6 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 2014, but were not as strong as they were in the second quarter of 2013. We realized $99.90 per barrel, down from the $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. 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 6 months of 2014.

We realized $98.39 per barrel, in the first 6 months of 2014, down from the $102.60 per barrel, we realized in the first half of 2013. Our realized price 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 price decreased to $95.78 per barrel, 11% less than the after hedging oil price we averaged in the first 6 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'll 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 is 94% of the average NYMEX Henry Hub gas price for the quarter. Our average gas price improved by 34%, in the first 6 months of this year, to $4.57 per Mcf as compared to $3.42 in the first 6 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 price has offset our lower natural gas production this quarter and drove our sales up 37%, over the second quarter of 2013.

Our sales increased to $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 6 months of this year compared to $208 million in the -- in last year's first 6 months.

Our earnings before interest, taxes, depreciation, amortization and exploration expense and other noncash expenses, or EBITDAX, increased by 45% to $121 million from $84 million in 2013's second quarter, as shown on Slide 11. Our EBITDAX, for the first 6 months of this year, increased by 48% to $232 million from $156 million in 2013's first 6 months.

Cash flow increased significantly this quarter driven by the increase, in oil and gas sales, and lower interest costs. 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 of 2013 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 6 months of 2014, came in at $205 million, increasing 68% from cash flow of $122 million in 2013's first 6 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 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 [indiscernible] gas properties.

Excluding these items, we 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 6 months of 2014, net income was $3.1 million or $0.06 per share, as compared to net loss of $46 million or $0.95 per share in 2013's first 6 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 6 months.

On Slide 14, we share our lifting cost, per Mcfe produced by quarter, related to our continuing operations. Total lifting costs 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 decreased from the $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 costs. And also the higher cost of oil production including higher production taxes that 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 costs 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 costs increased to $0.41 per Mcfe in this quarter as compared to $0.33 in the second quarter 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 6 months of this year, as compared to $133 million, that we spent in 2013's first 6 months, related to our continuing operations.

The $308 million, in 2014, includes $50 million of leased acquisition costs 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 outline 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 costs.

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 in the second quarter. We have $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 $420 million. And now, I'll 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 6 months of 2014, along with our 2013 drilled wells. We drilled 43 horizontal oil wells, 29.6 net, in the first 6 months and had 2 wells or 1.6 net wells drilling at June 30.

We had 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 averaged 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 tracked the cost of our Eagle Ford wells, which have decreased considerably since we started drilling in August of 2010. In 2010, our first 2 wells averaged 11.4 million dollars. Cost 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 those lower costs. In the first half of 2014, we reduced our average well costs to $6.9 million.

Our joint venture further enhances our return as the effective average well cost in 2014 to Comstock on an 8H basis improves to $5.9 million when the KKR spud fee is considered. On Slide 23, we have that 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 its first 30 days of production.

We are completing our second well, the Mach A #1, which is taking longer than anticipated, as we are making repairs to the casing, which was damaged during the frac treatment. We've 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 2 wells.

We have spud the fourth well, the Currington 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 the 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 in Mississippi. I will now hand it back over to Jay..

Perfect. Again, Roland, thank you. And Mark, thank you. Everybody, 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.

Strong growth in our oil production has more than offset the natural gas production declines, that we're 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 in 2 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. 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 opportunity natural gas prices are improved.

We have over 1,000 undrilled locations on that acreage. We will continue to have a strong balance sheet, and 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..

2 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 kind of big packages now? And then 2, Mark, can you maybe repeat what happened with the second well? I kind of missed that..

I'll comment on the acreage. We picked up 200- to 300-acres, Brian. And we -- again we look for acreage all the time, as some of the companies, I mean Apache, I think recently said they're going to have 10 rigs busy there. That's a good thing for everybody. Alcon has 3 or 4 rigs. Clayton has 2 or 3 rigs. So it is busy.

There's 15 or 20-plus rigs, active in the area. Some of the results had been as good as others. So I think that, to answer your question, to get what we call Tier 1 acreage, we ended up paying around 4,000 acres. You're going to probably going to double, triple, or quadruple that, to pick up acreage now.

I mean from what we understand, that's why we haven't picked up acreage. But it's going to be -- it's going to be a lot more expensive than what we picked up 3 or 4 months ago. So that's a good thing for the industry. And if we think we can drill all 100-acre spacing, we have 300-plus locations, and 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. We've not been able to pick up really any Tier 1 acres there.

In the TMS, we did pick up a little over 8,000 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 in the public [ph] is, hopefully, we'll add 4,000 or 5,000 net acres per quarter, but we're on a good glide path to get that acreage.

So now I go back to Mark on that -- is it Mark Williams or Mark Williams? We'll go back to Mark Williams on the Mach well..

Yes, Brian it's Mark. What we did on that well is we frac-ed it. All fracs went well, 17 stages, about 9 million pounds. And when we went in to drill out the frac plugs with coil 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 you wring that out, get it big enough to get our equipment through it so we can get the frac plugs out, and put the well on production. So that's what we have scheduled right now..

Okay, that's very helpful. And then one final one, and maybe for you, Roland. I guess I would have thought we would have seen the gas production declines, flatten a little bit. But it still seems to be pretty steep.

Can you maybe comment on that?.

I think the gas -- we said the gas is going to decline, and I think it's within our expectations. I mean, there is absolutely no workovers or drilling or any operational support. So I think you're seeing just kind of a pure decline right now..

We're in a high 35%, 38% decline last year. Brian, this year, looks like 25% to 30%. I mean, that, what you really see here is purity in 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 the mirror image of that as Roland said..

[indiscernible] with our drilling programs coming from South Texas so....

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

And so if I look at '15 versus '14, I mean, would you expect another 20% to 25% decline without -- I know you haven't announced the 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 at 25% or so?.

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

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

Jay, I think you mentioned a 80,000-acre TMS target in April to add for the $5,000 an acre, also the $500 cost. Where have you been able to add those 8,000 or 9,000 acres, since the end of 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 have that type acreage anywhere near Wilkinson..

We are going to add a lot in Wilkinson and fill it in.

Most of acreage has been -- fill in acreage?.

Yes..

And so it is on the map. So I mean, 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 just additional fill-in acreage. That's really been our goal is to -- So there's not any new areas at all. It is just 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 activity is, you're going to pay up for that. We're not paying up for big blocks. I mean 33,000 net acres at Wilkinson. I mean, you don't find that type of acreage, we don't, available right now..

From eyeballing the maps, last night it looked like more of it was down on the Louisiana side than the Mississippi side and....

That's correct in the -- for the first 6 months and then maybe next, you'll see more in Wilkinson in the third quarter because I don't want to disclose on 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 could look to as we look forward even past your first TMS well?.

This is Mark. I guess it will be about halfway between the Goodrich Blades well and that recent [indiscernible] well. Not neither one of them are real close it's just south -- it's just a little bit south of the Encana Anderson wells.

So, I think there'll be more activity and more results over the next quarter or 2, in that area, than there have been so far. But those are the -- near spuds right now..

And is the plan still to drill 2 or 3 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?.

Well as to keep that rig very busy. I mean with the first 2 of wells in Wilkinson in lieu to Louisiana. And then, really our goal is to continue to keep it busy in 2015..

I think we'll have 2 TD-ed, by the end of the year. So our count would be down to 2 and the third one would be drilling at the end of the year. That's kind of 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 Currington is, and the Flencher, it looks like a lot of your activities is really more focused on your oil window.

Any color, in terms of where the fifth and sixth locations are being built? I guess I'm just 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.

Is this year really focused more on the oil side?.

We were really just testing our acreage all the way across. So if you look on the map, the fifth dot a little further to east, just east of the Henry, is the Cobar [ph]. That would be our fifth well. And then we've got 2 or 3 other locations working, at least one of which will be south of that. And I'm not sure which.

Just depends which one we'll have titled on, and units formed and locations built in time. So we're a little bit flexible after that fifth one right now. But we plan to test all of our acreage, pretty methodically, and see -- make sure we know what to expect over the whole acreage position..

The 2 rigs you'll be going to, is that a thought of taking another one out of the South Texas Eagle Ford, and moving it to East Texas Eagle Ford, so you stay at 5 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?.

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 5. We're moving a rig from South Texas do 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 5-rig program for East Texas or South Texas Eagle Ford rigs. So 5-rig Eagle Ford program..

5? I -- Okay. I thought it was 4 there and 1 in the TMS..

4 right..

Yes. But we'll end up -- it'll -- what we're looking for now we've got 3 rigs right now in South Texas and 1 of course in East Texas. We'll move 1 rig from South Texas to East Texas. But then, I think as 2015 progresses, we will probably add another rig. That wouldn't happen till '15 though. One will be busy in the TMS..

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

Jay, I think you mentioned, with success, you're going to 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 just following up on that last question, how do you see the South Texas Eagle Ford program in '15 and '16, relative to this year, from a magnitude standpoint?.

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, 100-acre spacing, it's about 300 locations. What our goal really is, we're kind of issued the second withdrawn on that earlier.

Our goal is to have this, maybe, 4- to 5-rig program in our Eagle Ford play. I mean right now, we have 3 rigs in South Texas and again we have a rig in East Texas. We have a 4-rig program. We might end up with a 5-rig program sometime in 2015. Right now, it is a 4-rig program. We'll move those 4 rigs kind of around in those 2 plays.

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

And as Mark had mentioned earlier, we want to make sure our land is far enough ahead of the drilling program, so we don't start a big program in East Texas and then we'll catch up with land.

I think the problems were, if we are going to have 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, so....

2 follow-ups.

The 100 locations at South Texas Eagle Ford, that was the start of the year, or is that after you drilled the 45 net wells this year?.

After this year. We said initially, we thought we have 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've got about 100 locations left. And we'll high grade [ph] those locations. That's what we think right now..

And one last.

What are your current thoughts on adding oil hedges for next year?.

As 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 I think the way the oil market has been working so backwardated, it's been better not to jump into early..

We had 50% to 60% of our oil hedged. And then, as Roland said, the last 2 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..

And you didn't ask will but we still don't have any hedges for natural gas, because we're 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 wells was 774. That's about 61% of IP.

I'm just curious if that's 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 kind of settled 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 2 wells.

What was the average, for the first 2 wells?.

Kim, the first one, I believe, was 40. Because we drilled the pilot hole and [indiscernible].

Okay. That one doesn't count.

Let's say, the second well?.

The second well was like 34, 35 days. We had a lot of trouble in the intermediate hole with loss returns. Really unusual off the chalk [ph] 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 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, of the vertical data showed that there was sufficient natural fracturing.

So I'm just wondering -- on the next well, that you'll be drilling down, on Louisiana, what do you see, as far as fracturing is concerned, from nearby vertical wells? And could you also tell us what depth and contour that well will sit on?.

I will answer these question for us, Kim. I think the contour's about 12,000 feet. I believe. I don't have a contour map with me, but what I recall that's about right. I think these fractures are going to come and go. And you just don't -- a vertical well doesn't seam any 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 if there is a core within the area, then your coring a 6- or 8-inch diameter vertical hole, you're just not going to see many of the fractures. We're planning to -- right now, anyway, we're planning to core that well, so we should get better data.

And plus all the vintage logs that will help us. But I really think the natural fracturing issue is going to be kind of a location to location issue, not more of a regional type issue..

And it will be great if you guys could show your future locations on your map, on your slide deck..

Well, they're not ready yet..

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

Just sticking with the TMS, I'm wondering if you could provide any color around maybe what the AFE on that first well is going to be.

An any color you can give on the completion design and how you're planning to land it relative to the rubble zone?.

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 it was cored. So it's kind of getting redundant on information if we do that.

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

And then just 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, I mean if you look more at the second quarter stand alone, I mean the first quarter had a lot of extra costs in it as went over at that call. So, I think if you look at this quarter, this is more -- it's more closer to what we'll spend in the third and fourth quarter. Maybe a little under.

Those will be a little bit higher, but the 6 months is really skewed by the first quarter, where we had an acquisition in there, 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, kind of 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, potential opportunities we could see more opportunities, spend a little bit more on acreage or we could see less..

[Operator Instructions] Your next question comes from the line of Jeffrey Campbell with Tuohy Brothers Investment Research..

Just a quick South Eagle Ford one. You featured 3 outperforming Eagle Ford wells.

I was just wondering was that outperformance due to lateral length or geology or both?.

Let me thumb back there a little bit, Jeffrey.

which one is it?.

Like 850s, or maybe it was around an 850 average or something like that..

Those wells are fairly long lateral, but that's just in a good performing area kind of in the middle of our acreage. And so those are probably -- of the group of wells we drilled this quarter, that's probably the best acreage in the area. Cortez wells and [indiscernible].

That's just kind of in the core of our acreage and it's been a good producing area..

Okay, that's good. Going to the East Texas Eagle Ford, doesn't seem like anybody's drilling kind of say 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 not in the condensate window, but we won't know for sure until we drill it and test it..

I mean, is it -- is that kind of a Southern acreage test in mind for maybe sometime in 2015?.

We should drill the wells -- Jeffrey, I think we -- 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 will be right at end of the year or if it will roll over into early '15. Just depends when we can get the acreage and the units put together..

Yes. We'll probably drill one year-end or first of next year..

Quickly, when we -- you -- based on the data you've got, when you compare the East Texas Eagle Ford and the TMS, and you compare the decline curves in each play, do you see a lot of similarity? Or are there any discernible differences between the 2?.

Jeffrey, this is Mark again. We see a lot of similarity between all 3 of the plays, between the South Texas Eagle Ford, the East Texas Eagle Ford and the TMS. 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's 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 would say a fairly, standard decline curve..

And the last question I'd like to ask. The second quarter '14 Encana talked about the Haynesville re-completions that costs $1 million per. And they were IP-ing at an average of 400 -- 4 million cubic feet a day. They say they're the highest return wells in their portfolio, including condensate oil wells, and their effort is ramping up.

I'm just wondering, have you heard about this? 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. It's so new that there's not much public information, other than just what's 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 look at it hard for 2015's budget, if the results hold up..

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

All right. It was always -- Glenn, thank you and -- for hosting the call. And we want to thank all the shareholders that followed the stock for a long time. And we thank you for your time that you spent today. Hopefully we [indiscernible] you 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..