Comstock Resources, Inc.
Q4 2016 Earnings Call Transcript

Published: 25 Feb 2017

[Operator:]

Welcome to the Comstock Resources Fourth Quarter 2016 Earnings and Operational Update. At this time, all participant lines are in a listen-only mode to reduce background noise but, later, we'll be holding a question-and-answer session after the prepared remarks, and instructions will follow at that time. As a reminder, today's conference call is being recorded. I would now like to introduce your first speaker for today, Jay Allison, Chief Executive Officer. You have the floor.

[M. Jay Allison:]

All right, Andrew. Thank you. A few comments before we start the formal presentation. First of all, thank you for listening to the Comstock report. I'd like to tell you that 2015 and 2016 were tough years in the energy sector; as you all know that are listening. I mean, action had to be taken to survive and then prosper for almost all energy companies. And as a company in the past two years, Comstock has executed, in my opinion, well on all fronts giving our starting point. In 2015, we focused on capital restructuring and protecting our liquidity and, at the same time, reducing our total debt. In those two years, we reduced our total debt by $240 million. We monetized our East Texas Eaglebine and our South Texas conventional gas properties. And then, on November 8, which is not that many months ago in 2016, we fully recapitalized Comstock. And today, Roland will report that we have $190 million of liquidity and a capital structure that works. And with a two- to three-rig Haynesville drilling program this year, which will be a predictable program, we should see a 40% production growth. And the key is that, that's funded primarily with operating cash flow in 2017. The other thing we've done the last two years is we focused on our core business activities, which was, switching from oil to natural gas, but the natural gas is in the Haynesville. And then we focused on great geology, because I think that drives everything. With our 700 operating locations in the Haynesville, we see our rate of returns from anywhere from 50% to 70% with $2.50 gas, and 70% to 100% with $3 gas, depending upon the lateral length of the wells. They're repeatable, they're predictable. And if you look at February of 2015 when we started, we had zero inventory of operated drill locations because we haven't drilled at that time an extended lateral location. Today, we have 700 operated locations in the Haynesville. We've come a long way in two years. It's been a rough two years. We're glad that today is the finale of 2016 and we could go forward with 2017. And we look forward to predictable growth in 2017. With that, I welcome everyone to the Comstock Resources fourth quarter 2016 financial and operating results conference call. You can view a slide presentation during or after this call by going to our website at www.comstockresources.com and downloading the quarterly results presentation. There, you'll find the presentation entitled Fourth Quarter 2016 Results. I'm Jay Allison, Chief Executive Officer of Comstock. With me is Roland Burns, our President and Chief Financial Officer; and Mack Good, our Chief Operating Officer. During this call, we will discuss our 2016 operating and financial results, but most importantly, we'll review our outlook for 2017. Please refer to slide 2 in our presentation and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. Now, our 2016 highlights. The highlights of 2016 are summarized on slide 3. 2016 was a difficult year for where both (04

[Roland O. Burns:]

Thanks, Jay. Slide 4 in the presentation shows our natural gas production since 2013. And despite having a limited drilling budget in 2016, we're still able to grow our natural gas production by 13% from 2015. We put a rig to work in March of last year and we drilled three 7,500-foot horizontal lateral wells in our Haynesville program, but then we released that rig in July to conserve our liquidity. With the completion of the debt exchange that happened in September, we started drilling again at the end of September and then we added a second rig at the very end of October. Our gas production averaged to 133 million cubic feet per day in the fourth quarter. And the decline in our gas production from the third quarter rate was partially due to the sale of 10 million a day relating to our South Texas natural gas properties, but most significantly, it was due to the lack of drilling in the third quarter and the shut-in of many of our largest producing Haynesville wells in November for 21 days, and they were shut-in while we were conducting offset completion operations and doing other field work. But we're off to a good start this year as our January production averaged 150 million per day, and we're bringing a lot of high-volume wells in this first quarter. So, based on the drilling program and these new wells coming on, we do expect our gas production in 2017 will average between 200 million to 230 million cubic feet per day and probably get close to those rates as we get to the middle of this year. Slide 5 shows the hedge position that we put in place to try to lock-in some of the high returns from the Haynesville Shale wells that we plan to drill in 2017. So, right now, we have 72 million of our projected 2017 gas hedged at $3.38 on a NYMEX basis. Slide 6 shows the expected differentials from NYMEX that we expect to realize from our Haynesville Shale program. With firm transportation obligations, some of which expire in 2017 and 2018 and the renegotiation of various gathering and treating contracts, we're expecting our differential to NYMEX to average $0.37 in 2017. This number includes both the gathering and treating costs, which is shown on red on this slide, which we include an operating cost. And then the average differential that you'd see from a Henry Hub gas price to our realized gas price. On slide 7, we summarize our oil production. Oil production averaged 3,200 barrels per day in the fourth quarter, showing continuing declines due to the lack of drilling since 2014 and the sale of our Burleson, Eaglebine properties in 2015. With no drilling activity really budgeted for this year, we do expect that oil production to decline further. We expect our oil production this year will average between 2,200 and 2,800 barrels per day. On slide 8, we summarize the fourth quarter financial results. The 22% production decline resulted from the limited drilling in 2016, offset much of the benefit of improved oil and gas natural prices, as compared to the fourth quarter of 2015. The oil prices were up by 27% and natural gas prices were up by 41%. The net result was our oil and gas sales for the quarter were only up slightly to 1% to $48.5 million, and EBITDAX was up a similar percentage to $27.2 million. But most importantly, our operating cash flow of $9.2 million was substantially improved from the cash flow deficit we had of $3.3 million in the fourth quarter of 2015. We have continued to experience significant improvements on the cost side, our lifting costs this quarter were down 33%, with lower production taxes and lower gathering cost, and our DD&A was down 51% due to improvement in our DD&A rate. Our G&A costs were up this quarter in comparison to the very, very low number we had in the fourth quarter of 2015 as the company returned to normal with its compensation practices and, unlike 2015, is paying performance bonuses again. As Jay mentioned in his opening comments, the bonuses were earned but given back to the company which created the very low number in the fourth quarter of 2015. For the quarter, we reported a net loss of $54.9 million or $4.48 per share, but there were still a lot of unusual items in the quarter including some impairments or loss on divestitures of $3 million and unrealized mark-to-market on the hedge position we have in place for 2017 of $6 million, and some losses related to the debt exchange we completed in September of $11 million. If you exclude these items and other nonrecurring items, the net loss would have been about $32 million or $2.58 per share for the fourth quarter. Slide 9 summarizes the 2016 financial results. There you see our overall gas production was up by 13% but oil production was decreased by 55%. Overall production was about 6% lower in 2016 and 2015 due to the very limited drilling activity we had in 2016. Oil prices were also lower in 2016. They had fallen by 17%, while the gas prices were fairly consistent between the two years. But overall, because of the lower oil production, oil and gas sales were down 30% to $178 million and our EBITDAX was down to $91 million. Again, you saw the costs were much lower in 2016. Lifting costs were down 23%, and our DD&A, depreciation, depletion and amortization, was down 56%. In 2016, lots of noise in the loss we reported. $126 million of impairments or losses on the sales, and that same unrealized mark-to-market loss on hedges, which totaled about $8 million for the year, and then we had the large gain that was recorded on the debt exchange and the other retirement of debt of $177 million. So, excluding these items, we would have a net loss of about $14.61 per share or $171 million. Slide 10 in our presentation shows the very positive direction our producing costs have trended, since we've shifted toward drilling in our low cost Haynesville Shale natural gas-oriented properties versus the higher cost oil projects that really made up most of our activity in 2014. So, operating cost for 2016 averaged $1.10 per Mcfe produced as compared to $1.48 back in 2014. A lot of that reduction is due to lower production tax and some of that relates to the much lower oil and gas prices that were realized. But there is also with the mix of more production from the Haynesville wells, a lot of the wells are exempt from production taxes their first two years. So, yeah, that was a huge part of the savings, and we expect to kind of see that continue into 2017. But field level costs, which were also down, they averaged $0.76 in 2016 as compared to $0.92 in 2014. Part of that is due to the volumes in the Haynesville have very little hard field level costs associated with them. And then, we've made efforts to reduce our operating cost in our oil properties in 2017. We've seen a dramatic reduction in DD&A per Mcfe produced, which has come down to average $2.26 per Mcfe as compared to $5.74 in 2014. This improvement, a lot of it's due to the very, very low finding cost of the Haynesville Shale wells that were drilled in 2015 and 2016 which are now making up a big part of our production. But also, it's in part due to the significant asset write-downs we took on our oil properties back in 2015 to help lower their cost also. So, looking ahead to 2017, we expect to show further improvements to our producing cost and expect our total lifting cost to actually be under $1 for 2017 and that our DD&A expense per Mcfe to be under $2. And again, this is more just a shift of the high volumes coming from the Haynesville which come with the lowest cost. Slide 11 summarizes the proved reserves at the end of 2016. We're able to grow our proved reserves from 625 Bcfe to 916 Bcfe at the end of 2016, and that was done through a combination of drilling and the strong performance from the new Haynesville wells that we drilled in 2015 and 2016. And it's also due in part to the improvements to our liquidity which allows us to have expanded drilling plans in the future. The SEC prices that were used to determine proved reserves were no help at all. They were actually lower than they were in 2015 given the backward-looking nature of that calculation. And the oil prices used for the reserves net to the company's realization were $37.62 per barrel as compared to $46.88 per barrel in 2015. And gas was $2.29 per Mcfe, just a little bit less than the $2.34 used in the 2015 reserve estimates. So, these lower prices called (18

[Mack D. Good:]

Thanks, Roland, and good morning to everybody out there. I'll start off, as I usually do in the other conference calls, with the first slide that's familiar to most of you, and that's slide 15 that shows our 67,000 net acres in the Haynesville/Bossier. But what it doesn't show is where we're looking for additional acreage to add to our holdings. As an example of what we've been doing and are doing, in January of this year, we announced our JV partnership with USG, and that will give us exposure to an additional 3,300 net acres in the Haynesville. We plan to start drilling out there on this acreage block sometime in the second quarter this year, and we'll be drilling 10,000-foot laterals in the Haynesville. We'll operate these JV wells, as Roland mentioned earlier, with a 25% working interest. The net revenue interests are attractive, net lease position out there, so we'll have well over 20% NRI in all of those wells. And we're working on various other arrangements, and some of them are quite close to being finalized, that'll increase our acreage count and improve our drilling and inventory by several 10,000-foot lateral locations. And also increase, obviously, our tremendous reserve potential in the Haynesville. And we'll talk about all of these arrangements, of course, once we get them finalized. Also, given the improvements we've made in our completion strategy, our Haynesville reserve expectations per well on our acreage have grown. And so, that 6 Tcf reserve potential that we refer to in the right-hand corner of slide 15 continues to be supported by the strong results that we've seen from our extended reach Haynesville drilling program. And these wells that we've drilled suggest that we should be able to gain recoverable reserves approaching 2.5 Bcf per 1,000 feet of completed lateral using an improved completion design that I call Gen 2. Gen 1 is the completion design that we applied in 2015 and 2016. Given our history of improvement, I know we can improve above the 2.5 Bcf per 1,000 feet going forward as we continue to optimize our completion designs. Anyway, moving on to the next slide, I'll give you a little more information about all of this. Slide 16 is showing the location of numerous wells that we've drilled. We've summarized some of the Haynesville Shale drilling program results for you in our last conference call. And this slide 16 continues the discussion. In the past, we've talked a lot about how longer laterals with better completions gave us significantly better economics under a variety of market conditions. And although this continues to be true, our expectation is that we should be able to do better. We think that everything else being equal, we can increase our previous rates of return by at least 20% across the board by changing our well completion design to include, simply put, more proppant per foot and going to smaller frac stages and cluster spacing. In fact, we've completed three wells using this new design and we're in the process of completing three additional wells that within two to three weeks will be flowing to sales. These six wells will give us pretty decent starter kit for evaluating the benefits of our new design. All six of these wells that I mentioned have varying lateral lengths. Two of the first three wells we've already brought to sales. The Claybrook and the Halsey have lateral lengths that are slightly less than 4,500 feet, but both gave IP rates above 20 million a day. Tremendous results. The third well, the Pace 5-8 had a lateral approaching 7,500 feet long and its IP rate was approximately 25 million a day. So, to be brief, we're seeing IPs and initial performance profiles that meet our expectations. And as we move forward, we'll be able to evaluate the future benefits of our new design on each wells longer-term production. We'll be looking at just how each well's production profile compares to our existing type curve along with how each well's performance might compare to the other legacy producers in immediate area. There's no question that comparing the well's performance against the type curve is useful. So, let's take a quick look about how things are going so far by looking at slide 17. Slide 17 is a little different than you've seen in the past but it's still that same type curve metric that we used for the 7,500-foot lateral well for standard comparison purposes. And what we've done is we've averaged nine of our wells into a single representative curve so we can clear it up a little bit. That gives you a better picture of how the other wells are performing against our 7,500-foot lateral type curve measuring stick. Obviously, the nine-well average curve is well above the type curve and that speaks for itself. You can also see that our one Bossier well, as Roland mentioned earlier, the Jordan, continues to impress. It's well above the type curve. In order to better define and measure well performance, we're in the process of building a 4,500-foot lateral type curve that will be based on the future performance from our two (32

[M. Jay Allison:]

All right, Mack, excellent. Roland, excellent. I'd like to conclude kind of the formal presentation with and you can look at slide 26 and read that on your own. But nobody knows where oil and gas prices will settle in 2017, nobody. But here are the things that we do know about Comstock and there are 10 or 11 of them. One, we do have a world-class natural gas asset in the Haynesville. We kind of start proving that up because there are several private E&P companies backed by private equity that have made multi-billion dollar bets recently. And you've got several public E&P companies that have reported stellar well results. Well, I think we kicked this off in February 2015. It is a world-class natural asset. Two, two years ago, even a year ago, we had no hedges for gas. Today, we have hedged 50% of our current production and probably 30-plus percent of our 2017 projected production at $3.38. Three, like Mack just said, our EURs are up 20% on our Gen 2 frac program in the Haynesville and our Gen 1 EURs were stellar and they're getting better. Four, we have 700 operated (48

[Operator:]

Sure. We'll be taking our first question from the line of Ron Mills from Johnson Rice. Your line is open.

[Ronald E. Mills:]

Good afternoon, or morning. A question on the Eagle Ford maybe for Mack. Obviously, really good results on those staggered/stack wells and an increased inventory. Given the liquidity position and the outlook of becoming free cash flow positive in the early part of next year, at least on our model, what would make you want to revisit and maybe start drilling again to add a little bit of oil exposure and reverse that decline?

[Mack D. Good:]

Ron, all we need is to get certain things to happen that we plan to make happen in the Haynesville to build our production wedge, get our production targets in sight. Roland mentioned earlier about the last two wells in our program are the Bossier wells, then also I didn't give a whole lot of attention to that in my talk. But the Bossier is a completely wide open opportunity for Comstock. We just need to make sure that we're in a great capital position. If we are at the end of the year, I guarantee you if oil is in the $55 to $60 range, the opportunity to add to our oil production is just right in front of us. We would certainly be eager to take that next step and get out there and drill a few wells. We've already got an action plan built for that. We know exactly where we want to go, we know exactly what we want to do once we get there. It's finding the right time in terms of the financial situation to do that. And so I'm hopeful that at the end of the year, Ron, at the first part of next year, we'll have that opportunity to get out there. Roland may have something that he wants to add to that picture, but that's the kind of the way I see it.

[Roland O. Burns:]

No, I think Mack summarized it pretty well. I mean, it's a great opportunity. I think as we go through this year, we'll continue to see our gas and well perform in relation to each other and continue to evaluate that. I mean, we think even with the gas falling off some, the returns in the Haynesville are probably still trumping everything and that's where we want to meet our production goals, build up our cash flow with the Haynesville production. And then over time, that'll (54

[Ronald E. Mills:]

And then just – go ahead.

[Roland O. Burns:]

So I'd say the timing is really up to us, it's held by production leases. So we just need to see when does it fit into the company's capital program the best. And most likely would not be – yeah, before 2018, that we really start...

[M. Jay Allison:]

Well, Ron, you've seen the reports the last two weeks. I mean, the peer operators that offset our acreage, I mean, they have materially derisk a lot of the Eagle Ford that we own, I mean, by the stack/staggered success. So, we continue to look at that. And then, again, our cost structure is so much less in the Haynesville. We have to consider that when we go back to the oil play in South Texas Eagle Ford. And then, again, we committed to our equity owners and our bondholders which are incredible people. I mean, to have a 98% vote for the secured and unsecured bondholders and the 90%-plus vote from the equity owners that we could round up to vote to support the plan. We committed to keep our balance sheet as pristine as we can. So, a lot of the decision would be based upon that.

[Ronald E. Mills:]

And then along the same lines, Mack, any update or in terms of maybe even just an update on timing? I know you participated in three staggered/stack wells also in the Haynesville testing tighter spacing which I think can increase your inventory by about 20%, where does that staggered/stack test stand in terms of potential timing of new slope (56

[Mack D. Good:]

Well, the initial results are very encouraging, Ron. They're still flowing the wells back. And so, we haven't completed our evaluation of those yet, so it's going to have to wait two or three weeks for that to happen. But right now, I can tell you that it is exactly fitting our model. There's been no surprise. We've very encouraged by the results that we've seen so far. But I want to wait until the wells get tested to final IP and then we build the curve on those things. But the stack/staggered opportunities in the Haynesville, you're exactly right. That's an opportunity for Comstock to add additional locations and the operator that drilled those wells had two that were high in the Haynesville section and one that was low in the Haynesville section. And so, all three of those wells are performing exactly what we anticipated so far. But give it another two or three weeks and we'll have some harder data for you, Ron.

[Ronald E. Mills:]

And then just to go back to Eagle Ford, I failed to ask this. The results that you're having there, I know you're using more intense completion designs now than when you last drilled. Can you just refresh our memory of kind of what you were expecting in that area, how these wells are versus what you would have expected with the new completion designs? Because I just can't recall your Eagle Ford-type curve.

[Mack D. Good:]

Well, we sure haven't talked about it in a long time. But basically, what Comstock did and most other operators did back in 2012 – starting in 2011 through 2014, was to use the 30/50 and even 40/70 proppants, lots of gel in the fluids that were pumped. And so, the EURs, on average, in our area was around 40,000 barrels per 1,000-feet of completed lateral length. And that's kind of an average. I can give you more specific ranges later. But on an average, that's kind of what we – EUR at our wells using, this completion approach, again, Eagle Ford Gen 1. Eagle Ford Gen 2 is going to be totally different. A lot of things have changed. The 11 operators that I referred to earlier, certain considerable number of things have changed in the completion strategies. Obviously, higher proppant loadings by some operators. Other operators have gone a different route with different staging and different fluid systems. We've looked at all of that stuff. We have a favorite that we think yields the best results. And by that, I mean 70,000 barrels or so per 1,000-feet of lateral is kind of an estimated target for us to go back out into the tighter spacing and stack/staggered opportunities in the Eagle Ford. We think that's certainly achievable given all the data that we've seen. So, we have a particular approach that we want to take and that's – but I don't want to give you any more detail than that right now.

[Ronald E. Mills:]

Great. Thank you for all the comments.

[Mack D. Good:]

Sure, Ron.

[M. Jay Allison:]

Thanks, Ron.

[Operator:]

Thank you. Our next question comes from the line of Ray Deacon from Coker & Palmer. Your line is open.

[Ray Deacon:]

Hey. Good morning. Thanks for taking the question. Mack, I was going to ask you about the Claybrook well and the Pace James well, just what you're seeing with the higher sand loadings in terms of pressure drawdowns and expected declines and whether potentially that 18.5 Bcf type curve might turn out to be conservative with using more sand?

[Mack D. Good:]

That's a great question, Ray. It's pretty early in the game for me to give you a definitive comment on it. I could tell you that the initial performance of the wells, it's awfully early. I mean, the James Pace has only been on for about 2.5 months, the Claybrook is about 45, 50 days. And, of course, the Claybrook being a 4,500 footer that the James Pace being a 7,500 footer. They were both drilled in a different environment, meaning offset wells around them. So, there was the depletion shadow, if you will, affect influence. So, right now, the pressure drawdown is kind of in our expectation window. We haven't seen any excessive pressure drawdown as a result. We're pretty pleased right now that we're on target with the kind of production profile that we anticipated. But it's – really, we need six months in order to get firm data given the fact that one well is a 4,500 footer and the other well is a 7,500 footer and those were our first two 3,800 pounds per foot jobs, and given the different settings that those wells were drilled in. So, I can tell you right now, we're very pleased with the results. And it's meeting our expectations, but we need about another six months of hard data, production data to firm up things.

[Ray Deacon:]

That's great. Thanks, Mack. I guess, where are you targeting with the JV acreage to – will you stick in Caddo Parish with that and how big could it get? And I guess I was also wondering if Roland could kind of quantify the potential interest savings with the debt exchange and refinancing your other debt. Thanks.

[Mack D. Good:]

Well, real quick on the – on our JV acreage, the 3,700 acres, the 10,000-foot laterals that we plan to drill, it'll accommodate at least 20 10,000-foot laterals up there. And, again, it does have the opportunity for expansion. And that work is going on right now. And it's in a variety of locations. So, I don't want to really comment any more than that, Ray, about it, but it does have room to grow.

[Ray Deacon:]

Got it. Thanks. And I guess, for Roland, just how much potentially, once you get the conversion done between the PIK and cost savings and refinancing the secured debt? Could you improve interest expense?

[Roland O. Burns:]

Sure, Ray. On the budget, the interest that's paid on the second-lien notes is paid in-kind, just the actual interest is around $9.5 million a quarter. And then there's this additional almost $10 million a quarter of really phantom interest that results from those bonds being recorded at $0.80 on the $1 when they first were issued just under the accounting rules, and then $100 million gain being created, and then the amortization of discount back. So, those are just accounting numbers that just show up as non-cash. So, that's another $10 million. So, a lot of interest will leave the income statement just for the conversion and none of it is paid in cash. But then the cash interest the company really has is related to its secured debt which is closer to $70 million on an annual basis and we could pay in-kind but don't budget to this year. The opportunities are there post-conversion to look to refinance that at lower effective rates. So, we'd have to see where the markets are at the time, but that's a 10% type rate. And for secured debt and for unsecured debt in the markets today when the balance sheet is stronger, should be substantial savings there in the future. And that would be the step two that we'd hope to achieve to get the balance sheet back to completely healthy and getting the leverage ratio at our targets. So we think we're on the path to do that. We have all the tools to work with and it'll take us time for Mack to get all those production online, and that's what 2017 is all about. (65

[Ray Deacon:]

Great. Thanks.

[M. Jay Allison:]

Well, another comment to kind of follow up on Mack, he stated this earlier, but if you give us another three weeks, and maybe four at the most, we will have three additional wells flowing to sales and that's Gen 2 completed wells. I think a couple are 7,500-feet and another one is 5,000-feet. So we've drilled them and completed them, we're flowing them back. So, again, we'll know that in another four to six weeks. And then we'll have consistency in 2017 that we didn't have in 2016. As Roland said, this time last year we had no rigs drilling. We start in March with a rig, we drilled three wells, laid it down until we could recap the company, which is September. Put a rig in September drilling and then one in November. So, it was choppy last year. I mean, that's why the year-end results were choppy. That's why we're looking forward to 2017 and the performance that we'll deliver.

[Ray Deacon:]

You've done an amazing job in the past year. It looks a lot better. Thanks.

[Operator:]

Thank you. Our next question comes from the line of Chris Stevens from KeyBanc. Your line is open.

[Chris S. Stevens:]

Hey, guys. I appreciate the comprehensive update here. If I could just follow up on the Eagle Ford a little bit. You mentioned you have an action plan ready for when you want to go back out there and start drilling. Can you just maybe give a little bit more color on exactly what it is that you'll be testing out there? Are you going to go into an area where the lower – part of the lower Eagle Ford has already been fully developed and are you going to drill just a bunch of wells directly or I guess staggered/stacked above that? Is it going to be a single well, a few wells? Are they going to be, I guess, 660-feet apart or so? Just any color you can provide there?

[Mack D. Good:]

Sure, I can give you a little bit. One is, of course, we'll be on tighter spacing. We'll be 300-feet or so away from adjacent wells. The other is that, yes, it will be a stack/staggered location, and we'll also test just like the operator that I mentioned in my discussion earlier, did with the two wells they drilled. It will be just an infill drilling opportunity, not a stack opportunity. So, we would like to test both options, and we have a variety of areas that we can do that and that we think hold tremendous potential. So, the first thing we're going to do is to look at where we have the best data set to guide us. When I say data set, I mean that operators in the area where have they drilled these kinds of wells, what were the results that they got, how does their geology compare to our geology, and then we'll go forward. But what I would like to do – and of course there's a lot of moving parts to this, so what I'd like to do is to test in three different areas, the infill drilling opportunity versus the stack/staggered opportunity. We think we have both. And so, we'd like to confirm that by drilling wells. We would like to take advantage of drilling two well pads for obvious reasons, cost, efficiencies, and economy of scale. But as Roland mentioned earlier, that depends upon us making our Haynesville targets. We got great economics in the Haynesville. But we know where we're going to go, we know what we're going to do when we get there. And so, giving you any additional detail would be like laying our total plan in front of you right now. And we're not quite at that point, but we're getting pretty close.

[Roland O. Burns:]

I want to add another comment. I think the Eagle Ford, the unique opportunity there, too, is that we've made big investments in infrastructure, electricity. We have excellent facilities there. And so, this is a huge – and production is much lower than it was back in its prime. It's a great opportunity to add a lot of new production and not have to make any of those investments for infrastructure that were already made back in 2013 and 2014. So I think it's going to be some compelling economics based on where oil prices are.

[Mack D. Good:]

That's a great point, Roland.

[Chris S. Stevens:]

Right. So, that's definitely helpful information there. And I guess based on our newer sort of EUR expectations in a $55 to $60 environment, how do you expect those returns to compare to the Haynesville at this point?

[Mack D. Good:]

Well, quite well.

[Roland O. Burns:]

No, the Eagle Ford versus the Haynesville?

[Mack D. Good:]

Oh, the Eagle Ford versus the Haynesville?

[Roland O. Burns:]

Yeah, that's what he's saying.

[Mack D. Good:]

Oh, well, the Haynesville is just knocking it out of the park. I mean, 70% rate of returns, give me a $3 gas price and we're over 100% rate of return with a 10,000-foot lateral. I mean, it's just hard to compare the Haynesville to anything in my known universe. So, the Haynesville is – that's it's just hard to beat.

[Chris S. Stevens:]

Okay. Yeah. That's what I sort of assume. So, just given the size of the opportunity set in the Haynesville, it would probably be difficult to put much capital to work out in the Eagle Ford. Is that an accurate statement? And I guess would the thought be that maybe you monetize it to accelerate some of the value of the Haynesville?

[Roland O. Burns:]

Well, I think on the Eagle Ford, it's – whether or not you deploy all your capital there to bring it all forward is a question to look at for the future. And again, it's, what's the relationship between oil and gas? They're both very volatile. But I think, for us, we want to prove up at value. We think it's very much underappreciated asset that the company owns now and to play in general, and we think it's going to get better. And in the long run for the company, like the idea of having a diversified opportunity set, not just oil, not just gas. So it gives us that very unique low-cost oil opportunity versus having to start a brand-new oil play that would come with a lot of other exploratory risk, infrastructure issues, et cetera, that we would do to have to add that in the future. Yeah, so, I think right now, our idea is to get the property value more appreciated and (72

[M. Jay Allison:]

Yeah. And that acreage is held by production. I mean, 90% of it, you don't have to drill the hole. So, we're not going to lose it. It continues to be de-risked by other operators. And at the same time, we really think we know what type rate of return we're going to have in our Haynesville. And it's predictable, repeatable. We're focused there, and we got a big partner there. So, I think that's where we came up with this tremendous balance both on oil and gas and tremendous future.

[Chris S. Stevens:]

Great. Thanks so much.

[M. Jay Allison:]

Thank you.

[Operator:]

Thank you. Our next question comes from the line of Mike Breard from Hodges Capital. Your line is open.

[Michael Douglas Breard:]

Okay. Chesapeake has reported some excellent wells in Caddo County. How close was that to your joint venture acreage with Caddo?

[Mack D. Good:]

It's about eight miles to the southeast, Mike.

[Michael Douglas Breard:]

Okay. And then also the (73

[Mack D. Good:]

Mike, we do have the rig under contract, and we plan to move it into the area in late April into the Caddo JV area. That's our current plan.

[Michael Douglas Breard:]

Okay. Is there any chance you might drill a well on your own acreage in March (74

[Mack D. Good:]

Yes, sir. Actually, our plan is exactly that, to bring in the new rig, drill a well on our acreage. It'll be probably around 5,000-foot lateral test. And then after we finished with our well, we'll move it north to the Caddo area and start drilling our JV wells, 10,000-foot lateral wells.

[Michael Douglas Breard:]

Okay. And then also there's been some good Cotton Valley wells in the Texas (75

[Mack D. Good:]

We have a lot of Cotton Valley experience as you know, Mike, and we certainly haven't let that fall off the radar either. But the rates of return that we calculate on Cotton Valley horizontal are far less than the opportunities in Haynesville. So, that would be down the road for us.

[Michael Douglas Breard:]

Okay. Is there any chance you might sell that acreage to some of the active Cotton Valley drillers?

[Mack D. Good:]

Heck no. We like. We want to keep it. It's HBP, Mike. So, it's an inventory and it's an opportunity for later.

[M. Jay Allison:]

I think the key point though is, Mike, you did bring up some important. We do have that acreage. And years and years and years and years ago, we had Hosston, Travis Peak, Cotton Valley. And the question is, would we sell it and spend most of our money in the shallow waters in the Gulf of Mexico? And we said no. And what happens below the Cotton Valley is the Haynesville. So, I think that's why, Mack is an old East Texas guy, he won't sell anything, and I agree with him. So, you never know where that next golden egg will come from and maybe it is Cotton Valley. So, that's a very good point.

[Michael Douglas Breard:]

Okay. All right, thanks very much.

[Mack D. Good:]

Thanks, Mike.

[Operator:]

Thank you. That's all the questioners that we have in the queue at this time. So, I'd like to turn the call back over to management for closing comments.

[M. Jay Allison:]

Sure. Thank you, Andrew. Again, I just want to stress that we are very appreciative of the 98% vote from the secured and the second-lien holders and the 90-plus percent vote from the equity owners that we could round up to vote it. It's an extreme vote of confidence in management when no one was forced to vote in favor of the recap proposal. No one. And it was clearly represented, and it was based upon the results of the Haynesville. I think we had to prove it up, and I think we had to have good behavior, our entire corporate life as a management group in order to have the support that we have out there. Again, we are appreciative of it. We will never abuse it, and we will tell you the truth good or bad. When you ask Mack a question, Roland a question, or me a question, we'll tell you what the answer is. And we do take big actions. When things are looking bad after Thanksgiving of 2014, we told everybody we made changes, big changes. And as a result of that, I think we have the call we have today. And the big changes have brought, I think, a really bright future to the company. If you look at natural gas, it was April a year ago. If you look at the five-year average gas storage, we were 60% above that. And today, we're only 7% above that. That's pretty good, even though we hadn't had a really bad winter. We're still – the numbers look good. Even though gas has pulled back $1 or so in the last several days, we're still very profitable. As Mack said, a $2.50 gas price, a $3 gas price, we get a 50% to 70% to 100% rate of return. And unlike last year, we're going into this summer with a hedged portfolio, too. So, world-class gas asset with a world-class bondholders and equity owners, we're thankful. Thank you for listening to the conference call.

[Operator:]

Ladies and gentlemen, thank you again for your participation in today's conference call. This now concludes the program and you may now disconnect at this time. Everyone have a great day.