Comstock Resources, Inc. (CRK) Q4 2014 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and welcome to the Fourth Quarter 2014 Comstock Resources Earnings Conference Call. At this time, all participants are in a listen-only mode. Later, we’ll facilitate a question-and-answer session. [Operator Instructions]. As a reminder, this conference is being recorded for replay purposes. Now, I’d like to turn the presentation over to your host for today, to Mr. Jay Allison, Chief Executive Officer. You may begin.

Frances, thank you, and welcome to the Comstock Resources’ fourth quarter and year-end 2014 financial and operating results conference call. You can view a slide presentation during or after this call by going to our Web site at www.comstockresources.com and downloading the quarterly results presentations. There you’ll find a presentation entitled Fourth Quarter 2014 Results. I’m Jay Allison, Chief Executive Officer of Comstock. With me this morning are Roland Burns, our President and CFO; and Mark Williams, our CCO. During this call, we will discuss our 2014 fourth quarter and year-end operating and financial results. Forward-looking statements, please refer to Slide 2 in our presentation. Note in our discussions today, we’ll include forward-looking statements within the meaning of Securities Laws where we believe the expectations of such statements to be reasonable, there could be no assurance that such expectations will prove to be correct. Slide 3, the 2014 highlights. Slide 3 lists some of the highlights of 2014, which was all focused on oil growth. Unfortunately, the bottom fell out of oil prices in the fourth quarter but the progress made by the company to build up its oil operations will serve it well when oil prices improve. The 86% increase in our oil production in 2014 drove significant increases in our revenues, EBITDAX and cash flow. Our oil and gas sales including hedging gains of $564 million were up 34% over 2013. EBITDAX in 2014 of 446 million is 41% higher than 2013 and our cash flow from operations grew 57% in 2014 to $392 million or $8.41 per share. We drilled 68 successful South Texas Eagle Ford wells, placed 91 on production. In our East Texas Eagle Ford shale play, we drilled 11 wells with 10 being successful. We placed six of those wells on production, have eight more to be completed in 2015. We drilled our first wells in TMS where we have currently 82,000 net acres. We were only able to complete two-thirds of the lateral due to mechanical problems in our first TMS, but otherwise we’re very, very pleased with the results which Mark will go with you in a moment. We have delayed further development in TMS until the oil prices improve. I will let Roland review the financial results with you in more detail. Roland?

Thanks, Jay. On Slide 4, we recap our oil production growth in 2014, which drove the growth we had in revenues, cash flow and earnings for the year. Our oil production increased to 12,400 barrels per day in the fourth quarter and for the year, we’re able to grow our oil production by 86% over 2013. With the rapid fall in oil prices, we have shutdown our oil drilling program in late December, but we do have eight additional wells in our South Texas Eagle Ford and nine additional wells in our East Texas Eagle Ford area that we expect to put on production in the first quarter of 2015. So we do expect a little more oil growth in the first quarter, but then we expect oil to decline later in the year with no additional drilling budgeted. For all of 2015, we’re expecting oil production to average between 9,500 and 10,500 barrels per day. Slide 5 shows our natural gas production, which continued to decline in 2014 with really no gas drilling and it was down 29% from the previous year. Gas production in the fourth quarter averaged 98 million cubic feet per day. We did announce in December that we’re moving two rigs to the Haynesville shale to drill long lateral wells and by restarting our program in the Haynesville, this will allow us to grow gas production in 2015 where we estimate our gas production will increase to 145 million to 160 million cubic feet per day. On Slide 6, we summarize our fourth quarter financial results. The 63% increase in oil production in the quarter offsets the 26% decline in our gas production to provide strong growth in revenues, cash flow and EBITDAX. Oil production made up 43% of our total production as compared to 26% in the fourth quarter of 2013. Our realized oil price after hedging decreased 11% to $83.55 per barrel, our gas prices improved by 6% to $3.55 per Mcf. Revenues this quarter were up 20% to 127 million, EBITDAX was up 27% to 100 million and cash flow was up 34% to 86 million or $1.85 per share. Lifting costs in the quarter were up 6% and our DD&A was up 17% compared to the fourth quarter of 2013. Both reflect the higher cost associated with oil production as compared to gas production. Our G&A costs were down 26% in the quarter to $6.5 million. We did have two significant charges in the quarter. We recorded a $60 million impairment on our producing properties due to the decline in oil and gas futures prices. As we’re a successful efforts company, we use the forward-looking prices to access impairment on a property by property basis. We also incurred a charge of $6.7 million, which is included in exploration expense for payments made to release two of our operated rigs before their contracts expired. These charges account for most of the $55 million or $1.19 per share loss we had in the quarter. Excluding these items, we would have a net loss of about $0.19 per share. Slide 7 covers our annual 2014 financial results. We grew our oil production by 86% while our gas production declined by 29%. Overall, we’ll have made up 39% of our total production as compared to only 20% in 2013. Our realized oil price after hedging decreased 9% to $92.50 per barrel, gas prices improved in 2014 by 23% to $4.16 per MCF. For the year, revenues were up 34% to 564 million, EBITDAX was up 41% to 446 million and cash flow was up 57% to 392 million or $8.41 per share. Lifting costs in 2014 were up 15% and DD&A was up 12% for the year. Our G&A costs were down 7% in 2014. In impairments, the rig termination fees and drop in oil cost accounted for most of the $54 million or $1.17 per share loss that we reported. Excluding these items, we would have had a net loss of $0.05 per share for 2014. On Slide 8, we detail our capital expenditures for 2014. During 2014, we spent $483 million on development and exploration activities and $98 million on acreage and acquisition costs. We also spent an additional $6.7 million to release two rigs early, which had contracts that would expire in 2015. We had originally budgeted to spend $505 million on our drilling activity in 2014 but we pulled back that activity mainly in the TMS late in the year. In 2014, we drilled 80 horizontal oil wells or 54.7 net to our interest and we drilled one natural gas well. We also put 98 new oil wells on production in 2014. We have a slide on our proved reserves and finding costs on Page 9 of the presentation. Our proved reserves at the end of 2014 were estimated at 620 Bcfe as compared to 585 Bcfe at the end of 2013. We operate 96% of our proved reserves and there were 68% developed at the end of 2014. Our drilling program in the Eagle Ford shale added 5.1 million barrels of oil and about 5 Bcf natural gas or about 5.9 million barrels of oil equivalent to proved reserves in 2014. Reserves in the Haynesville shale and other regions added 73 Bcf of proved natural gas reserves in 2014. Our 2014 finding costs came in at approximately $28.56 per barrel of oil equivalent. On Slide 10, we outline the components of our current 2015 capital budget, which we announced in December. We put out our press release on the budget. We announced our plans to suspend our oil drilling with the rapid falloff in oil prices and reallocate two of our operated rigs to the Haynesville shale. We estimate we’ll spend $307 million in 2015 under this budget. This budget basically includes drilling 18 new horizontal wells in 2015. 168 million of that will be spent to drill 14 long lateral wells in the Haynesville shale and then another 17 million to refrac 10 of our existing producing Haynesville wells. We’ve also budgeted 30 million to finish drilling four wells on our East Texas Eagle Ford shale acreage that we’re in process at year-end, and then we intend to spend $50 million for completion costs of eight Eagle Ford shale wells that were drilled in 2014 and will be completed at 2015 and then we have an additional $42 million budgeted for facilities, recompletions and other capital projects. As natural gas prices have weakened some since we approved our December budget, we’re currently considering dropping back to one rig in our Haynesville program. This would save us about $80 million from this budget. In the fourth quarter, we had some activity in our share repurchase plan, which we detail on Slide 11. We repurchased 2.1% of our outstanding shares or 1 million shares at an average price of $8.09 per share. We have $83 million authorized for share buybacks but have not made any additional purchases in 2015 as we’re protecting our liquidity. Slide 12 recaps the balance sheet at the end of 2014. We had $2 million of cash on hand and $1.70 billion of total debt outstanding. Debt is about 55% of our total book capitalization. The borrowing base under our $1 billion bank credit facility is 675 million giving us unused availability of $300 million. With the rapid fall in oil prices this year, we are guarding our liquidity. We currently have adequate liquidity for 2015 to weather this downturn. We’ve made substantial reductions to our drilling budget and we’re considering additional reductions. We’re also looking at asset joint ventures as a possible way to increase liquidity and other potential financings to add to our liquidity. We’ll also be looking at reducing the dividend. I’ll now hand it over to Mark Williams to go over the operating results.

Thank you, Roland. Slide 13 shows our South Texas Eagle Ford acreage. We currently have 24,000 net acres in the South Texas Eagle Ford where we have drilled 196 wells. We have 62 mapped operated locations left to drill in this area without down spacing. Slide 14 shows our 2013 and 2014 drilling activity on these properties. We’ve completed 192 wells so far on our South Texas Eagle Ford acreage. Our wells have had an average per well and initial production rate of 741 barrels of oil equivalent per day. Since our last operational update in October, we have completed 11 additional wells. These wells had an average per well initial production rate of 816 BOE per day. This is a little higher than the 792 BOE per day average that we had last quarter. We have four additional wells, 2.2 net wells that are scheduled to be completed in the first quarter of 2015. Slide 15 shows the acreage we’ve accumulated in Burleson County targeting the Eagle Ford shale. We have 31,000 net acres in this play. Slide 16 shows the recent activity in the vicinity of our East Texas Eagle Ford acreage. We are continuing to delineate our acreage in this play. Since our last update, we have completed three or 2.3 net wells with an average initial production rate of 741 BOE per day. The Williams A #1H, the Kovar A #1H and the Ozell A #1H wells had initial production rates of 919 BOE per day, 683 BOE per day and 620 BOE per day, respectively. We have eight or 7.8 net wells in Burleson County that we also expect to complete in the first quarter of 2015. One of these is located on the far south end of the acreage and the remaining seven are offsetting our very successful results [ph]. On Slide 17, we outline our current leased position in the TMS. Our ownership is up to 82,000 net acres. With the drop in oil prices, we have suspended our leasing program in this play but we intend to retain most of our acreage position for development when oil prices improve. During the fourth quarter, we completed our first well in the TMS. The CMR Foster Creek 28-40 #1H was drilled to a total depth of 19,312 feet with a 6,764 foot lateral. Due to mechanical issues, we were able to complete only the first 4,537 feet of the lateral. The well was completed with an initial production rate of 874 BOE per day. The initial production rate of 194 BOE per day per 1,000 foot of lateral compares favorably with other successful wells in the play. In East Texas and North Louisiana, we have 69,000 net acres prospective for natural gas in the Haynesville and Bossier shale as outlined on Slide 18. This acreage has 6 Tcfe in total resource potential. We think that by applying improved completion techniques such as longer laterals and larger frac jobs, this area can generate acceptable returns at current gas prices. We are implementing a refrac program that can add additional production and reserves from our 189 Haynesville and Bossier wells. We have budgeted to refrac 10 of our wells in 2015. Slide 19 shows the evolution of our development plan in the Haynesville. We expect to enhance recovery and improve the economics in the Haynesville in two ways; by increasing the lateral length and by significantly increasing stimulation size. The well graphic on the left illustrates our previous development approach where we drilled sectional wells with [indiscernible] laterals at 660 foot well spacing. The graphic on the right shows our 2015 plan to drill wells covering 1.5 sections, which provides lateral length of 7,500 feet. The extended laterals should increase recovery per well by about 64%. The other major changes is the significantly larger stimulation treatment. On a per cluster basis, we plan to increase profit amount by 200% and fluid amount by 40%. With this, we anticipate a 60% increase in recovery due to those larger treatments. Along with the larger treatments, we will expand well spacing to minimize well to well interference and maximize the economics of the wells. Slide 20 provides more detail of our new Haynesville development plan. We have budgeted $13 million initially for well costs with cost expected to decline to $11 million during 2015 as we fine-tune our approach and take advantage of declining service costs. We expect that ultimate recovery will increase from the 5.5 Bcf to 6 Bcf range that we previously obtained to the 14 Bcf to 16 Bcf range. We expect an initial production rate of around 23 million a day with this new development approach. Slide 21 shows the expected economics of the new Haynesville approach and sensitivity to capital cost and gas price. The program should generate 21% rate of return at an initial well cost of $13 million and $3 NYMEX gas price. As well cost is reduced, the program economics will improve significantly delivering a 33% rate of return at the same $3 NYMEX price. As you can see, there’s significant upside in this program with the rebounding gas prices. I’ll now turn it back over to Jay.

Mark, thank you and Roland, thank you. If you look at the outlook slide, which is Page 22, I’ll summarize our outlook for 2015. As Mark I think really discussed, we are restarting our natural gas program at the Haynesville and we’ve drilled over 180-some odd wells there. We’re very confident in that and we think that it will materially improve based upon the completion technology, which he showed in a slide. We do have over 6 Tcf serve potentials in the Haynesville/Bossier shale with over 550 drilling locations. It’s a pretty balanced program with our oil program. Our natural gas properties are located near the growing Gulf Coast market with premium price realizations, which is a gift for us. Our current drilling budget will deliver strong natural gas growth with gas production in 2015 expected to increase by 35% to 50% over 2014. And if you noticed in Mark’s model at $11 million to complete the wells that are $2.50 gas priced should give us a 16% ROR or the $3 gas price should give us a 54% ROR, so we’re very confident in that and that that will give us some great returns on the money we’re spending. Our oil program is on hold in the current low oil price environment. We plan to protect our leasehold positions with lease extensions as budgeted in Roland’s charts. When oil prices do improve, we do have some great upside. We’ve got 235 future operated Eagle Ford shale locations. We have 327 future operated TMS locations and we also have maybe some down spacing in our South Texas also that will give us some great rate of returns. We continue to have one of the lowest overall cost structures in the industry, which will serve us well in the current environment. We will safeguard our balance sheet in 2015 with the current oil and gas price uncertainty. We haven’t issued equity in over 10 years. We protected our share count. We do have 300 million in liquidity right now, which equals our drilling budget this year. We have reduced drilling activity and we continue to evaluate our activity level based upon oil and gas prices, which you’ve seen us do as recently as December to go to a gas program. For the rest of the call, we’ll take questions only from research analysts who follow the stock. So, Frances, turn it back over to you.

Thank you. [Operator Instructions]. Our first question will come from the line of Kim Pacanovsky from Imperial Capital. You may begin.

Hi. Good morning, everybody.

Hi, Kim.

So you mentioned that obviously gas pricing has decreased since you announced your transition to the Haynesville and possibly dropping one of the two rigs. And I’m not asking you to give me an exact price that you would do that at, but how do you think about what would make you pull the trigger on dropping that second rig?

Kim, this is Roland. I think the gas prices have weakened since we put out the budget and we continue to look at that. So I think that we feel like there will be good returns. We want to see some results from these initial wells, but overall spending we would like to see lower with the lower prices. So I think it’s something we’re looking at pretty hard in the face of current gas prices. Any improvement in gas prices would support us keeping the program as it stands today [ph].

Roland, would you wait to see results on your first well before you would make that decision, just because obviously from your Slide 21, you still can get very strong returns at some of these lower price decks. So I’m wondering if you would just wait and see what the results are? And then maybe if you could also just talk about what your confidence level is on some of the projections that you’re giving us in your slide deck?

I think overall that we’re pretty confident in the results because we’ve seen it in other select wells that have the same design. Especially, the early results we think they’ll be – we’re pretty confident in those. I think it’s really more of the overall level of spending and where liquidity, just trying to safeguard liquidity and that’s one of tricks we can pull. So, I think it’s really looking at all these factors along with other potential financings we may look at. So a lot will play I think over the next month. So I think over the next month, I think you kind of get some of those results from the early wells, from the refrac which will be interesting. Depending on maybe the results of the refrac, it may be less expensive to try to generate gas with that program. So there’s a modest effort in play, so I think within a month or so as we finish up the first wells and get through the first quarter, I think that’s when we make that decision.

Okay. And what’s kind of the expected rate on a refrac? Can you just maybe summarize what others are finding?

Kim, this is Mark. What we’ve been told and are seeing is anywhere from an increase to about 1.5 million up to 5 million or 6 million cubic feet a day.

Okay.

It’s real variable and everybody is experimenting with designs so much that you’re not seeing the consistent results yet. So we just have to go try a couple and look at our own results.

Okay.

The other thing on our – we have two rigs now in the Haynesville. I think one terminates in June – we have one in August and then the other one is in November, so you’ve got the rig expiration dates, those two dates and I think the first well we’re just casing on and it drilled four, five days quicker than we thought, so that’s a good thing. And again, we’ve drilled a bunch [ph] of these. We’ve never had a lack of a high IP rate in Logansport where we’re drilling, so I think our confidence level there is really high and I think the longer laterals and the more frac fluid that we use, you’re going to have some pretty big wells and they’re going to be we think the 14, 15, 16 Bcf type reserve potential wells. We’ll have three of them TD’d by probably the next six weeks.

That sounds about right.

We’d probably have three of them TD’d in the next six weeks. The first one again we said casing on already. The second one we’re how far?

We’re 10,300 feet. We’re setting our intermediate casing right now.

So you give it another 30, 40 days, it will be TD’d. And I think these are three strategically located wells. They’ll be pretty good markers on what the program should look like. And going back to Roland’s comments on JV partners, we do have partners that would like to come in with those type of returns as you mentioned and maybe own a piece of the wells and the acreage and have a program there. Now what you hate to do is give up a really good program for a JV when in fact we don’t have to do that. We could hold it, but you got to look that it’s some kind of production growth for the year. And that’s where we came up and said, well, maybe after the third well or fourth well, we’ll see where gas prices are, see where oil prices are. If we could go move a rig back into East Texas Eagle Ford or the South Texas Eagle Ford if we needed to, because oil prices were a lot higher, but we’re trying to keep all that flexibility with our primary goal, as Roland said, to protect our liquidity. We don’t want to be put in a box. We have to do something that’s really dilutive when we don’t have to.

Okay, great. Thanks a lot, guys.

So we definitely apologize to all the analysts. We know that it’s difficult to have precise models because we are keeping a very fluid program, but as we see changes we’ll communicate those but the company has a lot of options and we’ll navigate this year, which it’s hard on everybody in this space because of these low prices for both oil and gas.

Your next question will come from the line of Ron Mills from Johnson Rice. You may begin.

Good morning. Maybe Mark for you on the well economics you provided there, you just boil it down to one comment, you talk about the plus or minus 2 Bcf per thousand lateral foot of EURs. Is that based off of recent Encana results in that particular Logansport or DeSoto Parish area versus what ESCO talked about in their press release yesterday in their Shelby area in East Texas?

Ron, this is based on total analysis in North Louisiana. It’s not really an apples-to-apples comparison when you look at Shelby County, so we don’t really look at that data and try to analyze it and use it as an analog for us. So this would all be Encana and other well data in our area in DeSoto and I guess Bossier Parish over there in that area.

But in terms of the economics, I’m assuming this was reservoir modeling, but is there also any inclusion of recent well results that it sounds like Encana is both on the refrac and the new drilling side? Are you sharing data with them? Is that something you will do?

We’re not sharing data with them but we have data. There’s a lot of public data available on some of this work and so we’re utilizing that. We utilizing all the variations that we had done in the past. It’s kind of a combination of looking at our data and some of their public data as well.

Okay. And then in the TMS, you talked about a mechanical issue in terms of that last couple thousand feet you weren’t able to get out. Is that – what was the mechanical issue? Is it related to the above zone – below zone commentary other companies have talked about?

Ron, it was a drilling issue. We had gotten a little bit too low in our window and we’re concerned about being able to finish drilling the well, so we backed up and made a side track at about – I’m trying to remember now – at about 15,800 feet I believe is what it was, but that may not be the right depth. I’m going off the top of my head here. But we sidetracked the well while we were drilling. We were able to finish the well. We did it at TD. But when we ran our production casing, it hit that spot in the sidetrack and reentered the old hole instead of the new hole and we could not get it to turn and go into the new one. We decided it was less risky to go ahead and set pipe and complete the well there than it was to try to pull that casing and risk and recondition the well and try again. So we set pipe and just abandoned that open hole section passed the sidetrack. So we had no trouble completing the well. The frac jobs all went very well. The plugs drilled out just like they do in our other areas, so the completion part of it went just fine. It was just a steering issue and not getting production casing to bottom.

And then lastly, if you look at the Williams versus the Kovar versus the Ozell, I think the Ozell was one of the first wells to start testing more proppant. I think you were going to put even more proppant in the Williams. When I look at those well rates, the Williams look like it’s probably in line with a type curve. Was there anything from a drilling or completion or mechanical problem that occurred with the Kovar and Ozell or can you comment on those results and also on the gas oil split, particularly or the Kovar since that was your Southern most test so far?

Yes, Ron. This is Mark again. The Williams definitely kind of fits our type curve and what our expectation was. The Ozell has underperformed it somewhat. No mechanical issue or completion issue there. I think it’s just a factor of you see some [indiscernible] in the rock and some variation across the field and that’s just a well. It’s kind of an anomalous well that doesn’t seem to fit any of the wells around it. It doesn’t fit the broad neck [ph] or the Stifflemire, the Halcon well or Henry well or the Williams. So it’s kind of just an anomalous well. One of those things, it’s hard to put a finger on but we figured it’s just a local phenomena right there in that area. The Kovar well is a high GOR well and that’s why it’s performed differently than the other ones. It’s about 7,000 standard cubic feet per barrel, 6,000 to 7,000 I believe, I don’t have the number in front of me but compared to the Henry, which is about 2,000 standard cubic feet per barrel. So it’s definitely getting gas here as you move to the South and that’s why it’s acted differently than those other wells that on a flow rate basis, it flows were a pretty high rate but it was just a lot more gas.

All right, great. Thanks, guys.

Ron, some cleanup comments. We did look at the Goodrich Crosby well. We looked at per thousand feet what your BOE per day was and I think the Crosby well is about 193 BOE and I think our Foster Creek was like 194 or so. So even though we weren’t able to complete the extra couple thousand lateral feet, we thought the per thousand foot was pretty comparable to the Crosby well and I think that well is 2, 2.5 miles away from our Foster Creek well.

I agree with that statement. I mean it’s in line with the wells on a lateral foot basis.

Yes. Again, it’s the first one we drilled and so to have that in line shows you that I think the reservoir quality is there. And the other reason we haven’t continued to end the TMS, which we think is a good play is oil prices are low. So we shouldn’t see --

Is the plan to drill your second commitment well or just maybe pay lease extensions then?

Right now in our budget, we just pay lease extensions. I think that’s the safest thing to do to see where oil prices end up and to see where gas prices end up.

Okay. Thank you.

We’ve got the option to do that.

Your next question will come from the line of David Amoss from Iberia Capital Partners. You may begin.

Good morning, guys.

Good morning.

Mark, you mentioned the thinking about spacing in the Haynesville as you go back there for the first time in a couple of years, and I’m curious how you’re going to monitor the potential interference between wells? And then what are the options if you do see something between your first couple of wells where you can wind the spacing? And then one last question is, when you think about the refrac program with the new well, is that something we should view as a complementary program or are they two separate and unique concepts?

Yes. On the first point – this Mark. As far as interference, we’re probably not going to be doing many spacing tests out here, because of the rig count. With one or two rigs, it’s hard to really get any developed full units. So, our picture on interference is based on the other data that we had analyzed and the idea that with the bigger frac jobs, you need to put the wells a little bit wider and those tests were done in some other areas by Encana. And so that public data has helped us to determine that the six wells per spacing is the correct spacing right now. In terms of the others, they’re really independent programs. The refrac program and the new well program, they’re really totally independent. Now we may utilize refracing as part of our new drill program if we’re fracing a new well and have an existing offset well, we may chose to refrac the offset well at the same time to gain some benefit there. But initially we’re going to test the concept on some stand-alone wells and make sure that it works.

Okay, got it. Thanks. And then one other question. So you guys were talking a little bit about the potential to drop a rig and it sounds like you’ve got contracts coming up in August and November. So when we look at our model and if you do drop that rig, how should we think about any risk to guidance in the back half of the year? And then what '16 might look like with that Haynesville program?

Well, if we decide to drop a rig, we’ll have to revise our gas guidance though oil wouldn’t be affected at all because the Haynesville’s all 100% gas. So we’ll come back and do that at that time.

Okay, got it. Thank you.

Your next question will come from the line of Jeff Robertson from Barclays Capital. You may begin.

Thanks. Mark, a question on the new well design in the Haynesville, can you talk about their reasoning behind going to unrestricted flow-back versus the restricted choke program you all ran on the old wells?

Yes, Jeff. We have had much more time now to gather the data since we did the program in '09 and 2010 and we looked at the data in our Logansport wells and really haven’t seen the benefit from the restricted choke program that we saw early. You take a really early time data and project it out and you think you see something and then you get three years of data and go back and look it again and you say, well, it really didn’t work out that way. So, we saw very little benefit from the restricted break program and you see a significant benefit to rate of return by going unrestricted, so that’s why we’re going that way now.

So they settled out on the same terminal decline then no matter – or at least of what you think you would get on an unrestricted well? Is that the point you’re making?

Yes. In our better areas especially we’ve seen no change in EUR, no benefit in EUR on the choke back wells.

Okay. And then on your well costs, is there anything other than just falling service costs in terms of what you all are trying to do to achieve the $11 million well costs and what are your AFEs on these first couple of wells you all are drilling this year?

Our AFE on the first couple of wells is about 12.7 million. And so primarily it’s going to be service cost reduction. The frac costs are coming down quickly. I’m sure you guys are hearing it from everybody and we’ve already seen about a 15% decline in frac costs just in the first few months of this year without really impact of the drop in the rig count. So everything we’ve talked to the vendors, we expect to see a significant reduction in frac costs and in other ancillary costs as well. So we trim a couple of days of drilling off from what we’re doing right now and we add that to the frac savings, that’s where we’re getting our $11 million.

Okay. And last question, how much of the 11 to 13 is the completion part? Is it 50% or 60%? Is that about right?

About 65%, I believe it’s about 65% completion.

Yes, 4 million or so to drill and then about 8 million to complete.

Okay. Thank you very much.

Your next question will come from the line of Mr. Jeffrey Campbell from Tuohy Brothers Investment Research. You may begin.

Good morning.

Good morning. Is it snowing in New York?

It’s freezing but we’re used to it now, we’re all numb. Referring to Slide 21, I’d like to approach this a little bit different way. What’s the minimal acceptable rate of return that you guys are shooting for to support the 2015 Haynesville drilling? And how much of your production is hedged currently at a price that supports this rate of return?

None of it is hedged, so it’s whatever the market price is it’s going to generate the rate of return plus the well costs, which is I think moving toward the – probably has a higher probability of moving to the best returns on the slide.

Okay.

I mean it’s a very dynamic year obviously with commodity prices and that’s why we have a very dynamic budget.

Understood.

Roland can correct me if I’m not quite right here but my guidance from them typically is a 20% rate of return is kind of our threshold and that’s where we try to look at on all of our projects. And sometimes there’s extenuating circumstances but generally that’s what we look for.

Yes, that’s our goal.

Okay, great. If you do decide to drop another rig, can you do so without penalty? And if you do have to pay a charge, do you have any idea what it might be?

It depends on when we drop it, but I think it would be somewhere probably less than 3 million most likely to drop one. So, that compared to the amount of cost that come with drilling the wells, it’s a small percent of that.

Okay. Just going back to oil, what stable oil price do you look for to be able to return to oil development and how long will it take you to get back up and running drilling oil wells?

As far as to return back, I think it would be something we could do fairly quickly if we were to take our existing operating rigs and move them back to where they were because they’ve moved over to the Haynesville that’s relatively not that far apart. But it’s something that we could do fairly swiftly and we do probably have enough locations maybe where we’ve done work that we could move back into – especially in Burleson. The oil price, a lot of that is going to be dependent on where we think service costs are settling down at. So as we reduce service costs, we can look at lower prices, kind of lower prices to achieve and [indiscernible] with our prices. So my guess would be in as we approach the $70 a barrel, we’re probably getting to where we could find oil projects that made our return levels if service costs don’t go back up but oil prices go up.

Okay. Some of your peers have talked about how if we got service cost reductions where the old $90 return became the new $70 return that that would really work. It kind of sounds like maybe that’s what we’re talking about here?

I think that’s right. It’s all relative. Of course if everybody’s returned to the same level of activity, I don’t know if you could expect service cost to be down that far but there’s going to be some meeting in the middle there when oil settles out in a level and the service companies figure out where they can make things work. And I think that will take some time to settle out.

If I can ask one last question. Could you add a little color on the unsuccessful Burleson County well? I mean was this a mechanical issue like there’s been in the past or were you just testing some fringe acreage or what was the story?

This is Mark. When we reported over this well before, this is not a new well that came on in this quarter. It was our mock well and in the very last frac stage, the casing parted and we were never able to return – reenter the well and drill the plugs out. The well wouldn’t produce.

Okay. Yes, I’m familiar with that one. So the point is it wasn’t a new well. You’re including that old well in the set?

That’s correct. It was in that set. And talking about our acreage a little bit, one thing if we look at the map, you can draw it different ways. I think that’s Slide 16. We feel really comfortable about 60% of our net acreage is in the oil window. We’ve probably got another 10% maybe that’s kind of on the oil/gas transition and then based on the Kovar well, we’ve got maybe 30% of our acreage. It’s more down in the wet gas window. Sometimes you look at these maps and you draw a line and you just add it up in your head and it doesn’t look quite like that, but the way the net to gross works out, it’s really about 60%. And then we’ve got all those Henry wells. We’ve got seven Henry wells left to complete that we’re starting on this week. They are all in that oil window and should provide significant oil uplift.

Okay, great. That’s very helpful. Thank you.

Your next question will come from the line of Phillips Johnston from Capital One. You may begin.

Hi, guys. Thanks. Just a couple of questions for Roland on the revolver. What drove the reduction in the borrowing base to 675 million from 700 million? And what are you guys expecting looking out into the spring and the fall redeterminations?

The 675 was the last redetermination that was done in November, so that was the new number that came out. And we’ll have another redetermination in May, so we’re looking at that because we’re looking at their prices. Their prices will be down potentially. It will be in the magnitude of 10% to 15% kind of lower prices, especially on the oil side more so than the gas side. So we’ll be monitoring that and that’s why we want to safeguard on liquidity so we don’t have to worry about not having enough borrowing base compared to what we have outstanding.

Okay. And was the reduction driven by an asset sale or something?

For the 25 million, I think it was just based on where pricing at the time.

Okay, got it. And then Jay, I think you mentioned in your opening comments potential for down spacing in South Texas Eagle Ford, which I think is the first time you guys have alluded to that. I think you’ve developed most of your acreage on 80s if I’m not mistaking, so are you talking about possibly going down to 40s there at some point?

This is Mark. A lot of the companies have tested down spacing and have talked about it being advantageous, so everything can be infield when prices are right and the service cost are right and so we’ll always keep looking at that as an option. And at some point, we’ll probably need to go in and test some infield locations and see how they work.

Okay. Thank you.

Your next question will come from the line of Dan McSpirit from BMO Capital Markets. You may begin.

Thank you, folks. Good morning.

Hi, Dan.

Turning to the balance sheet, what options would be considered as sources of capital to enhance liquidity, meaning what do you view as your cheapest cost of capital today?

I think there are different things. We can look at different financings to the extent that we have activity we want to finance. I think that looking at the low returns that are available in oil drilling and kind of a tenuous return on gas, it doesn’t make a lot of sense for us to want to go out and mature a lot of financing for those programs, but there are options; the asset joint venture is up that that maybe something we want to look at to kind of help enhance the returns on the projects like we did in our Eagle Ford play. And so that’s something that we’ll continue to look at for both our old plays and it maybe even potentially in the Haynesville, which offers those returns for a joint venture today. So those are the main ones. I think there are other type of debt financings we can look at also.

Okay, great. Got it. And as a follow up to that, it was mentioned earlier in the call $17 per barrel being somewhat the economic breakeven price or the price at which you may commit more capital to drilling the Eagle Ford or maybe even the TMS. The question is, would you hedge at that price?

Potentially. I mean we typically have liked the hedge to match the drilling program. So a lot of it – the $70 is relative on where we feel like costs are at that time. I think that’s a pretty fair number and maybe it could go a little lower than that in the South Texas Eagle Ford.

On the same question, Dan, with gas, at 3, 3.25, 3.50 whatever, if we had a Haynesville program that was aggressive, we would hedge.

Okay, great. And then on the subject of the TMS, what is acreage going for today in the play, just trying to get a marker on valuation?

We really wouldn’t know. You’d have to – I think it’s fairly not a real active play at the time, but there’s no real – there’s no market for acreage any particular time that you can – you have to kind of see what players are adding acreage.

Okay. And what is your cost basis I guess put differently?

Our cost is probably about $1,000 an acre.

Yes, it’s about 1,000 on acre.

Okay, great.

For the acreage, remember that we paid as low as 200 or so for the acreage to the South East. If you blend it, again it’s probably 1,000 --

Yes, maybe slightly less.

Okay, great. And then just a last one, if I may, on the subject of the Haynesville. I know some questions were asked about the old versus new completion designs. But if you could clarify and apologies if I missed this, what are the first year decline rates on the old and new completion designs, just trying to get a sense of how the shape of the curve changes with the larger treatments under the new completion design?

Dan, this is Mark. I don’t think the shape is going to change much if you compare unrestricted to unrestricted. So, you have to be careful what wells you’re looking at. If you’re looking at original wells that were completed using a small choke size and a float at a very restricted rate, they’re going to have a much flatter early time to climb than these wells will. These wells are probably in the 75% to 80% range. I don’t remember the number we used on our type curve, but I think that’s about right, 75% to 80%. And that’s pretty similar to the un-choked wells that we completed in the very beginning of the play before we initiated the restricted rate program.

Very good. Thanks, again.

Thank you.

Your next question will come from the line of Dan Guffey from Stifel. You may begin.

Good morning, guys. If we returned to $70, where does your first rig go, East Texas or South Texas?

That is probably hard to say. I mean it obviously has to go to East Texas first as it keeps going to South Texas of the same track.

Makes sense. And I guess can you discuss, give some color on the size and quality of your remaining South Texas Eagle Ford inventory comparing the expected future results in wells to ones that are already on production?

Dan, it’s Mark. Primarily, our undeveloped acreage is in Anascossa and Freole County, so those are going to be lower IP wells probably 400 to 500 barrel a day IP, maybe in that range. That’s where most of our undeveloped acreage is. If we go back down to South Texas with pricing increasing and if the data supports it, we may initiate an infield program and test that concept first, which would be in our McMullen acreage or maybe in LaSalle County. So it really depends on the analysis at the time and kind of what our goals are with the capital at that time.

Okay. And you guys have talked about 10 refracs this year. How deep do you see that inventory being? How many opportunities you have in the Haynesville?

We still have over 100 operated wells and every well out there is a refrac candidate. So we will just line them up in terms of where we feel like the highest potential benefit to the lowest and work down that list. We got to do a few and see how they work, because there just isn’t much data out there and what little bit of data we’ve seen is pretty sporadic. So we need to get some more consistent results with our program and then we can apply it really across all of our acreage.

Okay, great. And then last one from me. Have you guys been in discussions with your banker about the possibility of loosening your debt to EBITDA covenant? And if so, can you give an idea how that may affect the borrowing base and/or borrowing cost?

No, we haven’t really started those discussions yet. As we looked at the new borrowing base, I think that’s something that’s definitely very doable. We used to have a much higher leverage ratio before and so that was really set for a higher price environment. So I don’t suspect that will be a big issue at all. So that will be something that we will address in May with – and kind of reset the borrowing base.

Okay, good to hear. Thanks, guys.

It looks like we have time for one more question and that will come from the line of Mr. Mike Beard from Hodges Capital. You may begin.

Yes. You mentioned you had a redetermination in your bank line in November. What prices did the bank use at that time compared to what they were using earlier?

I don’t know the exact answer to that. I think that the prices since then are probably lower potentially by another 10% to 15%. But I don’t recall how they compared it to the spring before.

Okay, but it must have been a pretty small drop I guess?

Yes, it wasn’t – I mean if you remember in November, things were just starting to come down a little bit. We kind of had our redetermination at the end of the season and prices had started to weaken up.

Okay. All right, well, good. It shouldn’t have much of an impact on your borrowing base no matter even at 15%?

Right. We’re not expecting a material increase and we also will have new reserves, so it’s not a static number. We have a lot of new producing oil reserves that are coming on line that will really help offset some of that.

In your first Haynesville results by then too?

Right. And I think the potential to really have a significant increase in undeveloped reserves kind of based on proven up our new kind of design there and we haven’t reflected that in our reserves at all at this time. We really have – any Haynesville reserves in our reserves are based on our old historic performance which is three to four years ago type design.

Okay, all right. Thanks very much.

All right, thank you. Good question.

At this time, I’d like to turn the call back over to Mr. Jay Allison for your final remarks.

All right, again, Frances, thank you. Our goal is to use our capital wisely, protect our liquidity, test the Haynesville play; I know it’s a Tier 1 gas play, test it and continue to look at maybe down spacing in South Texas Eagle Ford, if we put rigs back in that play and we do have 62 locations right now that we can down space. Look at East Texas. Again, I think Mark said 60% of our acreage we’re very comfortable with an that’s to the Western part. We’ve got seven or eight wells that we’ll report in the next quarter, which are near the Henry wells. I think that will be good. The TMS well although we were 2,000 feet shorter than we wanted on our lateral per thousand feet, 194 BOE was a good number. And then again, we’ll protect our liquidity and report if we make any changes in our business plan. I appreciate the time and we’ll be good stewards for the money. Thank you.

Ladies and gentlemen, this concludes your presentation. You may now disconnect and enjoy your day.