Comstock Resources Inc (CRK) 2014 Q4 法說會逐字稿

Good day, ladies and gentlemen, and welcome to the fourth-quarter 2014 Comstock Resources earnings conference call.

(Operator Instructions)

I'd now 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 website at www.ComstockResources.com, and downloading the quarterly results presentations. There you'll find a presentation entitled fourth-quarter 2014 results. I am Jay Allison, Chief Executive Officer of Comstock. With me this morning are Roland Burns, our President and CFO; and Mark Williams, our COO.

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 and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations of such statements to be reasonable, there can be no assurance that such expectations will prove to be correct.

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, and put 91 on production. In our East Texas Eagle Ford Shale play we drilled 11 wells, with 10 being successful. We placed 6 of those wells on production and have 8 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 well, but otherwise we're very, very pleased with the results, which Mark will go over with you in a moment. We have delayed further development at 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 shut down 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 offset 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 assess 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 had 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, oil 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 cost in 2014 were up 15%, and DD&A was up 12% for the year. Our G&A costs were down 7% in 2014. The impairments, the rig termination fees, and dry hole 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 exploration activities, and $98 million on acreage and acquisition cost. We also spent an additional $6.7 million to release the 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 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 they 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 of 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 $28.50 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 fall-off 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 4 wells on our East Texas Eagle Ford shale acreage that were in process at year end. And then we plan to spend $50 million for completion cost of 8 Eagle Ford Shale wells that were drilled in 2014 that will be completed in 2015, and then we have an additional $42 million budgeted for facilities, re-completions, 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 $1.07 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 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 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 4 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 3, 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 8, 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 Henry well. (technical difficulty).

On slide 17, we outline our current lease 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 #1 H 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, 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 could add additional production and reserves from our 189 producing 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 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 4600-foot 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 change is the significantly larger stimulation treatment. On a per-cluster basis, we plan to increase proppant 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 to 6 Bcf range that we previously obtained, to the 14 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 costs and gas price. The program should generate a 21% rate of return at an initial well cost of $13 million and a $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. And, as you can see, there's significant upside in this program with the rebound in 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 in 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 reserve potential 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 notice, in Mark's model, at $11 million to complete the wells at a $2.50 gas price, should give us a 16% ROR, or at a $3 gas price should give us a 54% ROR. So we're very confident in that and 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, and we plan to protect our lease-hold 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 some, maybe, some down spacing in our South Texas also, that'll give us 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. Again, 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)

The first question will come from the line of Kim Pacanovsky from Imperial Capital.

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 you know gas prices have weakened since we put out the budget and we continue to look at that, so we feel like there will be good returns and we want to see the 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.

Roland, would you wait to see results on your first well before you would make that decision? 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 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.

Okay, yes. I think that overall, that we are pretty confident in the results because we've seen it in other select wells that have the same design, especially the early results. I think 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 the triggers 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 is in play I think over the next month.

So I think over the next month, you 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 is a lot of stuff in play, so I think within a month or so as we finish up these first wells and get through the first quarter, I think that's when we make that decision.

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 increased to about a million and a half, say up to five or six million cubic feet a day. It real variable and everybody is experimenting with design so much that you're not seeing the consistent results, yet so we've got to the point where we just have to try a couple and look at our own results.

Okay.

The other thing we have two rigs now in the Haynesville. I think one terminates in June?

August.

Is in August. 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 just set casing on and it drilled four or five days quicker than we thought. So that's a good thing. And again we drilled, 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 is 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.

Probably have three TD'd in the next six weeks. The first one, again we set casing on already. The second one we're how far?

We're 10,300 feet, we're setting our intermediate case right now.

So you give it another 30, 40 days it'll be TD'd and so 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.

What we do have is partners that would like to come in with those type returns, as you mentioned, and maybe own a piece of the wells and the acreage and have a program there. 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 know you've got to look at some kind of production growth for the year.

That's where we came up and said, well maybe after the third well or fourth well, we'll see where gas prices are, we'll see where oil prices are. We could 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, where we have to do something that's really dilutive when we don't have to.

Okay, great thanks a lot.

So we definitely apologize to all of the analysts. We know that it's difficult to have precise models, because we are keeping a very fluid program. But as we 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 the space because of the 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 Exco talked about in their press release in their Shelby area in East Texas?

Ron, this is based on totally an analysis in northern Louisiana. We don't really, 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 Bossier Parish, over there in that area.

But in terms of the economics, I'm assuming this is 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're utilizing all of the variations that we had done in the past, kind of a combination of looking at our data and some of their public data, as well.

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. What was the mechanical issue? Is it related to the above variable zone, below variable 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, 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 and get it to TD, but when we ran our production casing it hit that spot in the side track 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 recondition the well and try again. So we set pipe and just abandoned that open hole section past the side track.

So no, 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, 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 on the Kovar since that was your Southern most test so far?

Yes, Ron. This is Mark again. The Williams definitely 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 heterogeneity in the rock and some variation across the field and that's just a well that's just an anomalous well that doesn't seem to fit any of the wells around it.

It doesn't fit the Bravenec or the Stiffelmeyer, the Halcon well or our Henry well or the Williams, so it's just an anomalous well, one of those things hard to put a finger on but we figure it's a local phenomenon right there in that area. The Kovar well is a high GOR well, and that's why it has 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 2000 standard cubic feet per barrel. So it's definitely getting gassier as you move to the South, and that's why it has acted differently than those other wells. On a flow rate basis it flows at a pretty high rate, but it was just a lot more gas.

All right, great thanks.

Ron, on some clean up comments, we did look at the Goodrich Crosby well and 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. 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 that's, I think that well is 2 to 2 1/2 miles away from our Foster Creek well.

I agree with that statement. It's in line with the wells on a lateral foot basis.

Yes, and 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 in the TMS, which we think is a good play as oil prices are low.

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.

And we've got the option to do that.

Your next question will come from the line of David Amoss from Iberia Capital.

Good morning.

Good morning.

Mark, you mentioned that thinking about spacing in the Haynesville as you go back there for the first time in a couple 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 widen 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, it's Mark again. On the first point 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 in and develop 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, 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. We may utilize refracking as part of our new drill program if we're fracking a new well and have an existing offset well, we may choose 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 standalone wells and make sure that it works.

Okay, got it, thanks and then one other question. So you 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 2016 might look like with the Haynesville program.

Well, if we decide to drop a rig we'll have to revise our gas guidance. The oil wouldn't be affected at all because the Haynesville is 100% gas, and 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.

Thanks.

Mark, a question on the new well design in the Haynesville. Can you talk about the reasoning behind going to unrestricted flowback 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 2009 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 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 at it again and you say, well it didn't really work out that way. So we saw very little benefit from the restricted rate 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, 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 chokeback 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 cost, and what are your AFEs on these first couple wells you are all drilling this year?

Our AFE on the first couple 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 that from everybody and we've already seen about a 15% decline in frac costs, just in the first two months of this year, without really any 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, if 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 million to $13 million is the completion part? Is it 50% or 60%, is that about right?

About 65%, I believe 65% completion. $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 Jeffrey Campbell from Tuohy Brothers Investment Research.

Good morning.

Good morning. Is it snowing in New York?

Oh, 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 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 really whatever the market price is that's going to generate the rate of return plus the well cost, which is, I think, moving toward -- probably has a high 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.

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

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 compared to the amount of costs that come with drilling the wells with it, it's a small percentage of that.

Okay, going back to oil, what stable oil price do you look for to be able to return to oil development, and how long would 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 operated rigs and move them back to where they were, because they've moved over to the Haynesville. It's relatively not that far apart, so 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's going to be dependent on where we think service costs are settling down at. So at reduced service cost, we could look at lower prices and lower kind of lower prices achieved and the kind of returns you get on the lower prices. So my guess would be, as we approach the $70 a barrel, we're probably getting to where we could find oil projects that meet our return levels, if service costs don't go back up, but that oil prices go up.

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 and it's all relative. Of course if everybody is returned with the same level of activity, I don't know if you could expect service costs to be down that far, but there's going to be some meeting in the middle there when oil settles out at 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? Was this a mechanical issue like there's been in the past, are you just testing some fringe acreage, or what was the story?

No, this is Mark. We've reported on this well before, this is not a new well that came on in this quarter. It was our Mach well and in the very last frac stage, the casing parted and we were never able to return or reenter the well and drill the plugs out. The well just wouldn't produce.

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

That's correct. It was in that set. And then talking about our acreage a little bit, one thing if you 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 that's more down in the wet gas window. But just, 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 Capitol One.

Hello. Thanks, just a couple questions for Roland on the revolver. What drove the reduction in the borrowing base to $675 million from $700 million, and what do you expect looking out into the Spring and the Fall redeterminations?

Well, the $675 million was the last redetermination that was done in November. So that was the new number that came out. And you know, we'll have another redetermination in May, and so we're looking at that because we are looking at their prices, their prices will be down potentially, probably 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 our 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?

The $25 million? I think it was just based on their pricing at the time.

Oh, 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 have alluded to that. I think you developed most of your acreage on 80s if I'm not mistaken, so are you talking about possibly going down to 40s there at some point?

Yes, this is Mark.

A lot of the companies have tested down spacing and have talked about it being advantageous. So, everything can be infilled when prices are right and service costs are right, 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 infilled locations and see how they work.

Okay, thank you.

And your next question will come from the line of Dan McSpirit from BMO Capital Markets.

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?

Well 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 given -- looking at the low returns that are available in oil drilling, and kind of a tenuous return in gas, it doesn't make a lot of sense for us to want to go out and ensure a lot of financing for those programs. But there are options.

The asset joint venture is something, that maybe something we want to look at to 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 oil plays and maybe even potentially in the Haynesville, which offers those returns that were 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.

Great, got it, and as a follow-up to that, it was mentioned earlier in the call $70 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. We typically have liked to hedge to match the drilling program, so a lot of it, the $70 is relative on where we feel like cost are at that time. I think that's a pretty fair number and maybe it can go a little lower than that in the South Texas Eagle Ford.

Well 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. I think that it's fairly not a real active play at the time, but there's no market for acreage at any particular time that you have to see what players are adding acreage.

And what is your cost basis, put differently?

Our cost is probably overall about $1000 an acre.

It's about $1000 an acre.

Okay, great.

And the Wilkinson acreage, remember we paid as low as $200 or so for the acreage, and you blend it in, it's probably $1000 an acre.

Maybe slightly less.

Okay, great and then just 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 flowed at a very restricted rate, they are going to have a much flatter early time decline than these wells will. These well 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 unchoked wells 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 Nicolaus.

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

It's probably hard to say. It obviously has to go to East Texas first, if it keeps going to South Texas it will just stay on the 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 expected future results and wells to ones that are already on production?

Yes, Dean this is Mark. Primarily our undeveloped acreage is in Atascosa and Frio County, so those are lower IP wells, probably 400 to 500 barrel a day IP, maybe in that range. That's where most of our undeveloped acreage is.

We go back down to South Texas with prices increasing and if the data supports it, we may initiate an infill program and test that concept first. Which would be in our McMullen County acreage or maybe in LaSalle County, so it really depends on the analysis at the time and what our goals are with the capital at that time.

Okay, and you have talked about ten refracks this year. How deep do you see that inventory being? How many opportunities do you have in the Haynesville?

We have a little over 100 operated wells, and every well out there is a refrac candidate. So we will just line them up in terms of what we feel like the highest potential benefit to the lowest, and work down that list. And we've 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 more consistent results with our program and then we can apply it across all of our acreage.

Okay great and then last one for me. Have you been in discussions with your bank group 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 look 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 the reset of the borrowing base.

Okay, good to hear. Thanks.

It looks like we have time for one more question. That will come from the line of Mr. Mike Breard from Hodges Capital.

Yes, you mentioned you had a redetermination in your bankline 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 the prices since then are probably lower, potentially by another 10% to 15%. I don't recall how they compared to the Spring before.

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

You remember, 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, well good. Shouldn't have that much of an impact on your borrowing base, even at 15%.

Right, no, we're not expecting a material decrease 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 online that will really help offset some of that.

And your first Haynesville results by then too?

Right, and then I think the potential to really have a increase, significant increase in undeveloped reserves based on proven up that 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 are based on our old historic performance which is three, four, five years ago type design.

Okay, well thank you very much.

All right, thank you. Good question.

And at this time I'd like to turn the call back over to Mr. Jay Allison for your final remarks.

All right, again Francis, thank you.

Our goal is to use our capital wisely, protect our liquidity, test the Haynesville play. I know it's a Tier I 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 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 and 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 2000 feet shorter there on a lateral per thousand feet, 194 BOE was a good number. And then we'll just again, we'll protect our liquidity and report if we make any changes in our business plan. Appreciate the time and we'll be good stewards of the money. Thank you.

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