Comstock Resources, Inc. (CRK) Q1 2014 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Q1 2014 Comstock Resources, Inc. Earnings Conference Call. My name is Mark, and I'll 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 Jay Allison, CEO. Please proceed, sir.

Thank you, Mark, and welcome. I know there are some competing conference calls today, there may be 2 or 3, so again, I thank you for attending this one. I was visiting with Roland and Mark earlier, and I decided that my opening comments and my closing comments are really about the same. And the proof is in the middle, which is the report that we'll give you, and that's operations update from Mark and financial update from Roland. But what I'd like to do, I'd like to start out and tell you what's happened in the last year because that's a very important sticking point with us. It's a good starting point. On May 14, 2013, we received a wire for $824 million upon selling our Permian assets, and we reported a gain on the sale of $230 million or $3.21 per share for all of you which are the shareholders. That's a year ago. At that time, our oil production was approximately 5,300 barrels of oil per day. And this first quarter of 2014, we averaged at 10,400 barrels of oil per day, almost a double from 1 year ago today. In 2014, we think we can double our oil production. Although our natural gas production has declined as we expected, since we are spending no money on developing our gas fields, our gas price realizations offset the production declines. One of our great catalyst at Comstock is our ability to inventory approximately 6 trillion cubic feet of Haynesville gas reserves and 1,000 drill sites in the future when natural gas rebounds to the $5 range. But we're at $0.30 from that happening in the current market. And then last year, our debt has been materially reduced as you've seen, and our borrowing base materially increased as you've seen. We're $340 million currently undrawn on our facility. The stellar performance of our South Texas Eagle Ford region, which Mark will go into in a moment, our Bell-Cal [ph] asset today, provides predictable oil growth as reflected in our numbers and our credit facility. At Comstock, we believe in our people and we invest in our people, all of them. As a result, we've had exemplary success in our Haynesville region in the past, then the investment in and selling of our Permian assets, and now, the South Texas Eagle Ford region. The Comstock future is clearly visible. As our $100 million investment in the 30,400 net acres East Texas Eagle Ford play in Burleson County should continue to be materially derisked in 2014 and 2015 as we join in with other active operators to aggressively develop this extension of the Eagle Ford shale play. And our 52,200 net acres of the TMS, which we think is in the core of the play, should provide us great growth in 2015. Our current plan is to spud a well at Wilkinson County in July to drill our first TMS wells. We will join other operators who have committed $700 million in 2014 to drill approximately 60 TMS wells. We think that the $57 million we invested in the TMS to-date should provide us year-after-year of material growth in the future. Needless to say, but we have never been more excited about where we are and where we're going at Comstock. And the key really is balance, which we have between oil and gas and our financial flexibility, which we created by the profits we received 1 year ago today with our Permian sale and our investment and our people and their belief in the South Texas Eagle Ford region, and now in the East Texas Eagle Ford and the TMS. So with that, I'll formally start our conference call of the first quarter of 2014 results. Welcome to the Comstock Resources First 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 clicking Presentations. There, you will find a presentation entitled First 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 first quarter operating and financial results. Flip 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 securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. Now our 2014 first quarter highlights to Slide 3. Slide 3 lists some of the highlights in our first quarter. The 119% increase in our oil production this quarter drove large increases in our revenues, EBITDAX and cash flow. Our oil and gas sales this quarter of $142 million are up 49% over 2013's first quarter. EBITDAX this quarter of $110 million is 52% higher than 2013's first quarter. And our cash flow from operations grew 72% this quarter to $98 million, $2.05 per share. We reported net income, excluding nonrecurring items, of $3.5 million or $0.08 per share for the quarter. Our outlook calls for more oil production growth for the rest of the year. Oil now makes up 34% of our total production in the first quarter and is expected to average over 40% this year. We expect that oil production will grow 88% to 103% over 2013, driven by our successful drilling program, our investment in our people. In the first quarter, we drilled 22 successful Eagle Ford wells and put 38 new Eagle Ford shale wells on production. Our well costs continue to come down in our South Texas Eagle Ford program, as Mark will go over in a moment. In the first quarter, our average completed well cost fell to $6.8 million before the KKR promote, which is 11% lower than last year. We're very excited about recent developments in our 2 new ventures. I think they're box office hits this summer: the East Texas Eagle Ford and the TMS. We added 9,000 acres in our Burleson County play in the first quarter by buying out our partner. We also added 1,000 net acres in the TMS. Most importantly, offset operator activity in both plays, which Mark will discuss in a few minutes, has been very, very encouraging. I'll now let Roland Burns review the financial results for you in more detail. Roland?

Thanks, Jay. We recap our oil production growth, which is driving the improvements to revenues, cash flow and earnings this quarter on Slide 4. Our oil production increased to 10,400 barrels per day this quarter, and was up 2,800 barrels per day or 37% over last quarter. It's also up 119% over the first quarter of 2013. Our Eagle Ford properties of South Texas accounted for most of our oil production. After falling behind on schedule completion activity late last year, we caught up in January, and we are now on track to meeting our goal of doubling our oil production this year. For the first 3 quarters of 2014 -- I mean, for the last 3 quarters of 2014, we are expecting the oil production to average between 12,400 to 13,700 barrels per day based on our current drilling and completion schedule. This would represent an 88% to 103% growth over 2013. Slide 5 shows our natural gas production, which continues to decline. It was down 30% from the first quarter of last year at 122 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 102 million to 112 million per day for the remaining 9 months of the year or 23% to 30% less than 2013. Slide 6 shows our realized oil prices this quarter. Oil price realizations in South Texas improved some in the first quarter of 2014, but were not as strong as they were in the first quarter of 2013. We realized $96.59 per barrel, down from $105.82 per barrel we realized in the first quarter of 2013. Our realized price averaged 98% of the average benchmark NYMEX-WTI price as the LLS premium to WTI was less than our transportation costs to get our oil to that market. 58% of our oil production was hedged this quarter at a NYMEX-WTI price of $96.42. After our hedging program, our realized price decreased to $95.20 per barrel, 14% less than our after-hedging oil price we averaged in the fourth quarter of -- in the first quarter of 2013 of $111.19. Slide 7 shows our current oil hedges for the remainder of 2014. We have 7,000 barrels per day hedged at $96.60 per barrel. This represents a little more than 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 8 shows our average gas price, which improved by 49% in the first quarter to $4.70 per Mcf as compared to $3.15 in the first quarter of 2013. Our realized price was 95% of the average NYMEX Henry Hub gas price for the quarter. The higher realized gas prices offset the impact of the production declines that we had this quarter. On Slide 9, we cover our oil and gas sales, including realized hedging gains or losses. The 119% increase in oil production and improved natural gas prices offset the lower natural gas production this quarter and drove sales up 44% over the first quarter of 2013. Our sales increased to $141 million this quarter compared to $97 million in last year's first quarter. Oil accounted for 63% of our total sales as compared to 49% in the first quarter of last year. Our earnings before interest, taxes, depreciation, amortization, and exploration expense and other noncash expenses, or EBITDAX, increased by 52% to $110 million this quarter from $72 million in 2013's first quarter, as shown on Slide 10. Cash flow increased significantly this quarter, driven by the increase in oil sales and lower interest costs. On Slide 11, you can see that our operating cash flow for the quarter came in at $98 million, increasing 74% from cash flow of $56 million in 2013's first quarter. Cash flow per share this quarter of $2.05 per share was up 77% from cash flow per share of $1.16 in the first quarter of 2013, reflecting the lower share count we now have after repurchasing some of the shares last year. On Slide 12, we outline our earnings. We reported net income of $1.2 million or $0.02 per share this quarter as compared to a net loss of $27 million or $0.58 in 2013's first quarter. We only had one unusual item in the first quarter results, which was a $3.6 million unrealized loss relating to our oil hedge position. Excluding this item, we would have reported net income of $0.08 per share as compared to our recurring loss from continuing operations of $0.48 per share in 2013's first quarter. On Slide 11, we show our lifting cost per Mcfe produced by quarter relating to our continuing operations. Our total lifting cost increased to $1.47 per Mcfe in the first quarter of 2014 as compared to $1.07 in the first quarter of 2013 and the $1.36 we averaged in the fourth quarter of 2013. The increase is mainly due to the lower natural gas volumes in the fixed nature of much of our lifting costs, combined with the higher cost oil production, including higher production taxes on oil. Production taxes were $0.34 per Mcfe this quarter, and our transportation cost averaged $0.23 in the first quarter. Field operating costs increased to $0.90 per Mcfe this quarter as compared to $0.84 in the fourth quarter of last year. On Slide 14, we show our cash, G&A per Mcfe produced by quarter, excluding stock-based compensation. Our general and administrative costs increased to $0.37 per Mcfe in the quarter as compared to $0.31 in the first quarter of 2013, mainly due to the lower gas production volumes we had this quarter. Our depreciation, depletion and amortization per Mcfe produced is shown on Slide 15. Our DD&A rate in the first quarter averaged $5.36 per Mcfe, as compared to our $4.66 rate in the first quarter of 2013 and the $4.94 that we averaged in the fourth quarter of 2013. The higher rate is due to the oil production representing a higher percentage of the company's total equivalent production this quarter. On Slide 16, we detail our capital expenditures relating to our continuing operations. We spent $188 million in the first quarter as compared to $58 million that we spent in 2013's first quarter just on continuing operations. We did spend an additional $56 million on our West Texas properties in that quarter. The $188 million includes $40 million of leased acquisition costs, primarily related to our acquisition of an additional 30% interest in the East Texas Eagle Ford shale acreage and Burleson County, Texas. We also spent much of the $76 million that was budgeted for a completion of carryover wells of our 2013 drilling program in this quarter. We do expect the capital spending for the remaining 3 quarters to be much more in line with the cash flow that we generate from operations. On Slide 17, we outline the components of our revised 2014 capital budget. In connection with the acquisition of additional interest in the Burleson County acreage, we increased our capital budget for this year to account for those acquisition costs, plus the higher interest in the wells in the East Texas Eagle Ford and a revised rig utilization schedule. We expect to spend $510 million this year on development exploration projects and another $55 million for lease acquisition activity, which includes the first quarter acquisitions. The budget for drilling activity includes: $284 million to drill 65 wells, 46 net wells in the Eagleville field in South Texas; $79 million to drill 10 Eagle Ford shale wells or 9.2 net wells on the new Burleson County, Texas acreage; and then $33 million to drill 3 wells, 2.7 net wells on our Tuscaloosa Marine shale acreage. The budget also includes $76 million to complete 18 wells or 13.3 net wells that we carried over from last year and $38 million in facilities and other development activity. The increase in planned activity has allowed us to increase our outlook for oil production this year, but will have a much larger impact on our expectations for 2015 oil production. Slide 18 recaps our balance sheet at the end of the first quarter. We have $2 million of cash on hand and $949 million of total debt at March 31. Our debt increased $150 million this quarter, partly due to a large deferred lease bonus payment of $44 million for the TMS acreage we acquired in 2013. That expenditure was reflected in 2013, but the cash payment is shown as a change in working capital this quarter. We also had the acquisition of the additional interest in the East Texas Eagle Ford acreage this quarter, combined with a high completion activity in the South Texas Eagle Ford. At our spring bank [ph] meeting, our borrowing base under our $1 billion bank credit facility was increased to $700 million, giving us unused availability of $340 million. We continue to pay a quarterly dividend of $0.125 per share to our stockholders, as we show on Slide 19. This dividend costs the company around $6 million a quarter. If you notice on Slide 19, only 1/3 of the 62 E&P companies that we track pay a dividend. And of those companies, we have the third highest dividend yield of 2.2% at March 31. I'll now turn it over to Mark to review our drilling results for the first quarter.

Thank you, Roland. Slide 20 shows the location of the wells we have drilled in our Eagleville field in South Texas in the first quarter of 2014, along with our 2013 drilled wells. We drilled 22 horizontal oil wells, 16.5 net in the first quarter, and had 7 wells, 5.6 net, drilling at March 31, 2014. Completion activity was very high in this quarter. Since the beginning of the year, we have put 38 new oil wells or 28.6 net wells on production in the Eagleville field. The wells with the highest initial production rates since our last update on February 10 were the Swenson A #2H, A #3H and A #4H wells in McMullen County, which had IPs in excess of 1,000 BOE per day. Slide 21 compares our 2014 completions to our prior year completions. Our average 24-hour IP rates were lower this quarter at 663 BOE per day as compared to 785 BOE per day in 2013. Much of this was due to 9 wells we drilled on our RTH lease, which had short laterals due to the acreage configuration. Excluding these short lateral wells, our average 24-hour IP rate was much closer to the 2013 average at 746 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 2 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 the savings. The wells drilled in recent years have much longer laterals and larger stimulation treatments despite these lower costs. In the first quarter, we reduced our average well cost to $6.8 million. Our joint venture further enhances our return as the effective average well cost in 2014 to Comstock on an 8H basis improves to $5.8 million when the KKR spud fee is considered. Further savings are possible as our new frac contract will save us between $350,000 and $400,000 per well, starting in the second quarter of this year. On Slide 23, we show a detailed map of the East Texas Eagle Ford acreage in Burleson County. We acquired 21,000 net acres for $67 million in 2013, and purchased the remaining 30% interest in these properties this quarter for $34 million. We now have 30,400 net acres prospective for Eagle Ford shale development in this area. Slide 24 shows recent activity in the vicinity of our East Texas Eagle Ford acreage. Several wells have had initial production rates in excess of 1,000 BOE per day. The most recent is the Stifflemire well drilled by Halcón adjacent to our acreage. We have staked the first 5 wells of the 10 wells we plan to drill this year to test our acreage. They are shown as red stars on this map. We are currently drilling the Henry A #1H located in the center of our acreage. We drilled a pilot hole to 9,990 feet and cut a 227-foot core and logged the Eagle Ford interval. We have started horizontal operations and are currently drilling the lateral at 12,000 feet. Projected TD for this well is 17,500 feet measured depth. On Slide 25, we show a detailed map of the Tuscaloosa Marine shale play. We now have 52,200 net acres in what we believe is the most prospective parts of this emerging play. Our acreage is located in Wilkinson and Amite Counties in Mississippi and East Feliciana and St. Helena parishes in Louisiana. Our map on Slide 26 shows recent TMS wells with initial production rates over 1,000 barrels of oil per day, including the very successful Goodrich Crosby well in Wilkinson County. We expect to start drilling the first of 3 planned wells in July. We have primarily been involved with leasing activities and forming units on our acreage. Our timing is still very tentative and may change based on how units are formed and the time required to obtain the necessary permits. We have entered into data trades with active operators to allow us to access proprietary well information to improve our well designs. We are excited about the ongoing activity in the TMS. On Slide 27, we show the permits by other operators near our acreage. We will continue to monitor new wells to learn how operators are overcoming their initial drilling and completion problems encountered in this play. I'll now turn it over back to Jay.

Well, as Roland and Mark has said, we are a balanced oil and gas company. We do have a major gas field at Haynesville in inventory. And at $5, we can start proving up our 6 Tcf reserves in our 1,000 locations. We do expect our oil growth to double in 2014 by drilling wells, not by buying oil. We've added 2 emerging oil plays, which we think will be stellar plays: the East Texas Eagle Ford, spent $100 million on 30,400 acres; in the TMS, we spent $57 million on 52,200 acres. I think that's going to be our oil growth in the future. And again, we have a very strong balance sheet, $340 million of liquidity. The future has never looked better at Comstock ever. So for the rest of the call, we'll take questions only from the research analysts who follow the stock. Mark, I'll turn it back to you.

[Operator Instructions] Your first question comes from the line of Don Crist from Johnson Rice. Donald P. Crist - Johnson Rice & Company, L.L.C., Research Division: Can we start in the Southern Eagle Ford? The RTH wells were lower than your traditional IP rates in the area, but can you talk -- give us a little bit more color around those wells and maybe lateral lengths and costs to those wells? And how they competed on an IRR basis?

Yes, Don. This is Mark. Those -- the lateral length averaged about 4,600 feet in that area, and we were really restricted just because that's -- we drilled our entire lease, and that's basically -- the shape of the lease allowed us to set up 2 units, North and South, at 4,600-foot length. IP rates, slightly less than your average on a foot -- per foot basis, but only maybe 10% less, not significantly less on a per foot basis. So it really performed pretty close to our average. Rate of returns, these wells were very low cost because of the short laterals. I think our average cost in these wells is probably around $6 million. So on an IRR basis, they're very competitive with the rest of our program. Donald P. Crist - Johnson Rice & Company, L.L.C., Research Division: Right. That's exactly what I was thinking as well, just given the lateral lengths. And moving over to Burleson County, a lot of activities going on there right now. Can you give us an idea of how you're looking at the rest of the year? Obviously, you're drilling your first well now, but do you plan on keeping that rig active for the rest of the year? And maybe adding another rig given, obviously, the success or failure?

Yes, Don, this is Mark again. Yes, our plan is to -- we have a rig running right now on the first well and we will run that rig through the year. And in our new revised budget, we have a second rig starting in October. Now that rig is contingent on results, so we'll have results before we move that second rig over there, but that is our plan at this time. And with all the encouragement we're getting from the offset results, we are highly confident we'll have the second rig running in the play in the fall.

And Don, this is Jay. I think the goal in Burleson was could we really add another 9,000-plus acres because we thought acreage would be a lot harder to add there than the TMS. Because there are fewer acres available in the East Texas Eagle Ford because a lot of that, as you know, was held by production from the oil fields back in the '80s. So when we were able to get the other 9,000 acres and get a 30,000 net acre footprint, we internally think that, that acreage position is probably twice as valuable as our South Texas Eagle Ford acreage position. If we are correct, when we drill these wells and it continues to be derisked, then a lot of these wells will look like our Gloria Wheeler wells did in McMullen, which are our better wells. So we're excited to get the 9,000 acres. We continue to see stellar results from other operators around us that are very vocal about their success which we -- where we applaud. And we look at that and you haven't had hardly any, if any, drilling or completion issues in this area. I mean, we drilled 140 South Texas Eagle Ford wells, we think this is an extension of this same Eagle Ford play and these wells are pretty similar. So hopefully, they'll be better and we'll test that theory. We did say, based upon the 16 rigs that are active in that area today, that we need to be prepared to have a second rig, if we want to put a second rig in use, fourth quarter or whatever. So we're preparing that. You've got to prepare -- as you know, Don, through the land. It's a land issue, really. You've got to make sure that the drill sites are ready. So on the Slide 24, we show you the 5 initial locations. We tell you we'll drill 10 wells. We own more interest in every well, which we like because if they're good wells, you want to own more of them. So we think that in the last 90 days, the -- this Burleson acreage has really materialized to be a lot more derisked than we thought it would be at this point in time. Donald P. Crist - Johnson Rice & Company, L.L.C., Research Division: Okay. And one last question for me about Burleson. A lot of debates have been swirling around on where that gas, oil, wet gas, lines are. Can you just give us a sense, because your slide is a little bit cartoonish, as to how much of your acreage is in the southeast portion, which maybe in the condensate-rich portion of the play versus the black oil?

Yes, Don, this is Mark. If you look at our map, we didn't label the colors. But the gray is our estimate of the black oil area, and the green would be volatile oil. And then that -- kind of each color, I guess, would be condensate. So that's how we have it broken out based on the gas oil ratios that we see in the other producers. And that green to peach boundary may move north and south a little bit, but it's getting pretty well defined. So we believe that all our acreage is either in black oil or in the volatile oil window based on gas oil ratios.

Remember, if you look at Gloria Wheeler, it's in a volatile oil/black oil window that you have your better wells.

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

Just sticking with that last question on the East Texas Eagle Ford, how much of the leasehold sits in the volatile oil window by your estimate today?

Dan, this is Mark. I believe about 25% -- 20%, 25% of it it's in the volatile oil window, and 75% of it would be in the black oil window.

Yes, we saw the low was 15% and a high of 25%. It's kind of in that range.

Okay, great. Next question then, how might the capital expenditure budget change again as the year progresses? That is, any chance capital has shifted out of South Texas and into East Texas or the TMS upon greater success?

Yes, Dan, this is Roland. I think that given that we're getting -- approaching the halfway point of the year, it may be difficult to see a big change between regions. I think what the real question would be, how do we kind of set it up next year, and I think those movements are definitely -- you can see you have more activity in the new plays than the old traditional play next year. I think the real question is on the -- as we approach the mid-year point and we've already kind of factored in adding the second rig to the East Texas area, will be the timing of when we start the work in the TMS. I mean, that's the most tentative, I think, part of our schedule right now, whether that gets started up and we actually get the 3 wells in this year. That assumes we start sometime in July. But I think as we progress further than in plan, we'll really be looking for a 2015 budget that, based on results, can really show more ramp-up in the new plays.

And I think the other thing, we do have the ability -- which we didn't a year ago. We have ability to balance our budget. I mean, you go back to 2012, we spent $102 million on gas. Well, it's 0 now. We can go to 0 because we've done that. If we choose to add the Haynesville it's because gas prices are $5 or greater, but we can choose to do that. Same way with the East Texas Eagle Ford, would they rig, we're in great shape. We would choose to put a second one there to increase that budget. But we don't have to do that because leases are expiring. The same way with TMS. As we discussed [ph] with you earlier, we said, well, maybe 2 wells. And then a month or so ago, maybe 0 wells because we only have to drill 3 wells by the end of 2015. And then as we've seen the success in the TMS and that footprint that we have, we thought, you know what, it'd be a really good year in 2014 if we could exit with 1 and maybe a second TMS well, but those are optional. Those are very flexible. That $20 million, $25 million extra there, we don't have to spend. So we don't want to become reckless with our balance sheet. That's why, when the banks looked at us a couple of weeks ago, we -- our borrowing base increased to $700 million. And our goal is always to keep it at least undrawn what our CapEx budget might be for a given year. Now we never end up accomplishing that goal, but it is a goal we try to accomplish. And we don't have to outspend our cash flow if we don't want to because, again, we have added our biggest part of our footprints in both of these plays.

Well, I think we'll see the next 3 quarters that -- dependent on commodity prices, that we're going to be much closer to the CapEx to operating costs. And then hopefully, we'll achieve that goal of balancing those the next 3 quarters with all of the no-unusual items kind of expected in those quarters.

Well, and you won't have the $80 million carryover for completing all those wells, which got our production up to that 10-plus-thousand barrels a day, and that was a line item for our CapEx budget. And a lot of companies backward date everything, but we didn't. We got our production up. We want to keep it up and grow it.

Got it, great. Appreciate that. And then just, if I may, quickly 2 follow-ups. Just turning to South Texas then, what is the game plan for the RTH leasehold going forward, considering the limitation on lateral length, yet competitive returns with what's drilled elsewhere in South Texas?

Dan, this is Mark. The RTH lease is mostly developed, so there's just a few locations left there. And if they're competitive on an IRR basis, then we'll drill them like everything else.

Okay, great. And then on the TMS, forgive me if you've identified this in your presentation, but where will the first 3 wells be located?

We are working on permits. This is Mark again. But our plan right now would be to drill 2 wells on our northern acreage and 1 on our south to really test both areas, and that there again is somewhat dependent on permit timing and on well results between now and then.

So 2 in Wilkinson, and then we will have 1 elsewhere.

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

You guys had said that you were looking at some data trade agreements with others in the East Texas Eagle Ford, and I'm wondering if anything has been inked on that? And if you've had any insight into how Halcón's Stifflemire well?

Kim, this is Mark. Yes, we have inked a couple of agreements, and we do have some of the information on the Stifflemire well. But by definition, data trade means you have to have something to trade which we're helping that with our first well. So as we provide information, we get information back, which would be very helpful. But yes, we have a good bit of information on the Stifflemire.

Great. Is there anything notable that you can share with us?

No, it's -- that's Halcón's information, it's not ours. It's a good well and it's right next to us, and that's all I could say about it.

This is Jay. You know our relationship with Petro Oil, Halcón, Floyd, it goes back probably 2 decades. Same way with Goodrich, it goes back almost 2 decades, so this -- you deal with people and we deal with people. They are good people so.

And when will you get the core data back on the East Texas, the vertical you drilled before you kicked it out?

Yes, Kim, this is Mark. That data would kind of trickle in over time. We've gotten a little preliminary data in now and we'll continue to get it probably over about a 3- or 4-month period.

Okay. So you'll have all that data before you commit to a second rig, along with a first well result or maybe first few well results?

Yes, that's our expectation, to have that data. And then, there again, it's trade data to be able to get data on another well too, so which kind of doubles the value of it.

Right. Okay, great. And then just another question on the TMS and timing. I just want to kind of narrow this down because you -- initially, you said mid-summer you'd drilled a well and then you said that it would be later in the year. Now you're back to July again. What would cause this well to not be drilled in July now? I mean, if -- we have a couple of well results coming out from Halcón, from Goodrich in the near future. If either of these were maybe iffy, would you put this well back off to the end of the year? Or are you committed to drilling this well in July, the first well?

Kim, I've always told Mark, we should probably wait, and Mark, being a stellar Aggie, says you have to spend money to make money. And if there's a party going on, we want to join it. So I do leave that up to Mark, with a little asterisk. So Mark, you want to answer that question?

Yes, Kim. Our plan right now is to go forward. Now we don't have the permits finalized and the units finalized. So there could be some delay if we just run into regulatory issues getting permits finalized, so that would drag it. Or a rig availability, we do not have a rig for that just yet. We're starting to look for one, but we don't know exactly what the rig availability is. So that timing -- that's where Jay had said earlier, that timing is going to be pretty flexible because it's dependent on a lot of items that are not really in our control. We do not expect well results to really deter our idea. We have too many good well results for 1 data point to change our opinion.

Right. So Kim, our goal is to drill that well.

Yes, the other really encouraging thing is we have seen several wells just in the last 2 months that have been drilled in 30 to 35 or 36 days, which was a vast improvement over what it was maybe a year ago. So we're seeing what we expected, which is the learning curve building and the operator quality is really having an impact on results out here.

[Operator Instructions] Your next question comes from the line of Marshall Carver from Heikkinen Energy Advisors.

You gave the well count completed in the Eagle Ford through April. Could you give us the breakdown of expected completions for 1Q, 2Q, 3Q and 4Q? Ideally, on a net basis, but if it's a gross basis, that's fine, too.

I think Gary can get back to you with that later. I don't think we have that kind of -- in front of us here.

I don't have it.

Okay. Next question would be on the gas drilling. The idea of if gas prices get above $5, you could potentially renew that. Do -- would you look at the strip needing to go above $5? Or how much time would you need gas to stay over $5 for you to decide to do that?

I think if we evaluate -- this is Roland, if we evaluate the gas prices, I mean, it obviously needs to be a longer-term price, so we're not just waiting for the spot price to hit a particular number. So yes, I think that's a big part that gets our attention, that the 12-month strip is added area. We continue to look at the gas economics especially in the core Haynesville, which we believe is our top return gas projects, and compare those and look at, obviously, applying new technology, longer laterals, better completions to those wells and look at those compared to what we're drilling. And that debate continues and the more gas can gain a little ground, the more of those can start to compete at a return basis with opportunities we have on the oil side. But nothing's -- we haven't really seen the price yet to have us start shifting our budget.

And then, Marshall, [ph] we put all of them on a sheet of paper and decide which ones have the greatest rate of return. They all compete against each other, all these plays.

Right. And in terms of the first well in Burleson County that's drilling now, when would it frac? And when would it -- do you expect it to be producing? And so when should we get results on that?

We'll report that at the end of second quarter. We never report well-by-well results. Mark may want to answer that more micro. But unless you dig the Railroad Commission reports, whatever, you won't hear it from us till into second quarter.

Yes, Marshall, this is Mark. That's right. We'll have it completed and online before the second quarter results come out. I can almost guarantee that, not -- never guarantee anything in our business, but I'll almost guarantee that.

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

Just one more follow-up, if I may. Recognizing it's early innings, between the East Texas Eagle Ford and the TMS, where do you see the better field level returns today? And maybe from a different point of view, where do you see the greatest resource potential?

Dan, this is Mark. I'll answer at least the first part. I'll say that right now the better individual well return is in the East Texas Eagle Ford and mainly because the cost structure is less. The results, if you look at IPs and decline curves, they're almost identical in the 2 plays. And so really you're just talking about cheaper wells in East Texas. And as far as resource potential, yes, we have more acreage in the TMS. And I think the ability to grow acreage is better in the TMS, so resource potential is going to be -- going to lean that way.

Yes, see, I would agree with that, Dan. And in fact, that's why we went to both plays. We looked at the East Texas Eagle Ford, and we said, well, 21,000 net acres, can we get anymore? We didn't know that we could get more and we thought it would be -- derisk quicker than the TMS. And then TMS, of course, we got in it, which was probably the fourth quarter of 2013. It hadn't had the results, the Blades well with the Goodrich. You hadn't had Halcón reenter the play. You hadn't had a -- kind of a reentry or resurgence of Encana and Sanchez, et cetera, et cetera. And like Mark had mentioned earlier, I mean, we heard a well was drilled in less than 30 days in the TMS for one of the operators. And one of the great strengths we have, which hopefully we bring to the TMS, is the operation success we had in the Gulf of Mexico, the 100 wells we've drilled in the Haynesville, the 140 wells we drilled in the South Texas Eagle Ford. We've been very, very good at operations. So when we expanded to the East Texas Eagle Ford, we didn't think that there's a great operational risk. It was just you had to drill enough wells to derisk it as a play. But if you go over to the TMS, we think the 2 big things you have to have, to have a successful oil and gas well is, one, you have to have oil or gas in place. And quite frankly, in the TMS where we are, we internally don't have an issue that the oil is there. We think it's there. So now it's a pure cost issue. The question is, can you drill and complete these wells for $10 million or $11 million in the TMS. And we think that we'd be able to. I was looking at the chart this morning on the South Texas Eagle Ford. To think that you could go -- we show $11.4 million. A lot of the wells in South Texas Eagle Ford were a lot more expensive than that. And now, we are less than $6 million. I mean, it's like 2 for 1, and it's longer laterals and more profit. It's amazing the costs, how they've come down. And we think that same thing will happen, particularly in the TMS. So they're pretty balanced plays. We have -- if you're 100 acres, 120 acres in the Eagle Ford, you got 200, 250 locations in East Texas. If you go 700 feet apart from well-to-well in the TMS, you've got 500 or 600 locations. So there are several ways to answer that question. The key is we think we're in really good plays, and obviously, other operators do also.

I appreciate that. And Jay, just maybe 2 follow-ups to your statements then, with -- specific to the TMS. Recognize you wouldn't have leased in the TMS or acreage -- prospective for the TMS if you didn't believe that there is, obviously, first, original oil in place, and that it could be extracted by economic means, but is there anything about the rock and the rock quality itself that still causes any concern? And then second to that and specific your statement about getting bigger in parts of Louisiana and Mississippi, what is the market for leasehold today that is prospective for the TMS?

Yes, Dan, this is Mark. In discussing the rock quality, we see very consistent rock quality across that play. And so I guess the concern would be you have maybe a dozen data points or 15 data points over 1 million-acre, 750,000-acre area, which looks pretty sparse when you look at it that way, but the results have been so consistent and the rock quality on logs looks so consistent that we really aren't overly concerned about quality in that play. Now the rock quality has lent itself to some drilling problems and I do believe that Goodrich, Encana have kind of figured that out and have figured how to overcome the drilling problems associated with the rubble zone or the fracture zone that they're talking about. And that's really the -- I guess, the biggest concern about rock quality is more from a mechanical point of view than from a reservoir point of view. In terms of acreage, there's still a lot of blocks available out there, but they're smaller pieces. The big blocks and the big timber companies have been leased up and there's still, what we feel like, a pretty substantial amount of acreage available but it's in much smaller pieces and just takes more time to put together.

I would now like to turn the call back over to Jay Allison, for closing remarks.

Again, I want to -- I know we had some competing calls and they're all important. And we want to, again, thank you for listening to this and we continue to try to create real wealth for every single share of stock that you own as a stockholder. Thank you.

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