Comstock Resources, Inc. (CRK) Q1 2018 Earnings Report, Transcript and Summary

Good day, ladies and gentlemen, and thank you for standing by. Welcome to the Q1 2018 Comstock Resources, Inc. earnings conference call. [Operator Instructions] As a reminder, this conference call is being recorded for replay purposes. It is now my pleasure to hand the conference over to Mr. Jay Allison. Sir, you may begin.

All right. Brian, thank you, and I want to thank everyone for participating this morning in our first quarter conference call. And again, we try to put out major news before the call, so you probably all are aware of that and we will go over that as we go through the call. Welcome to the Comstock Resources first quarter 2018 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 will find a presentation titled First Quarter 2018 Results. I am Jay Allison, Chief Executive Officer of Comstock, and with me is Roland Burns, our President and Chief Financial Officer, and Dan Harrison, our VP of Operations. During this call, we will discuss our first quarter operating and financial results. If you’ll go to Slide 2, please refer to Slide 2 in our presentation and note that our discussions today will include forward-looking statements within the meaning of securities laws. While we believe the expectations in such statements to be reasonable, there can be no assurance that such expectations will prove to be correct. Now we get to the 2018 first quarter summary. That is Slide 3. Our first quarter financial results showed substantial growth as compared to the first quarter of 2017. Natural gas production grew by 55% and was the driver of higher revenues, EBITDAX and cash flow. Oil prices were 41% higher, but natural gas prices were down by 5% as compared to the first quarter of 2017. Our sales grew by 36% to $74 million and our EBITDAX increased by 54% to $54 million and cash flow increased 125% to $36 million. We are very excited about the strong results from our Northern Haynesville area, where we have the JV with USG that Dan will cover in a moment. The first six wells we have to put on to sales each had initial production rates of 27 million to 28 million per day. As discussed on our last conference call, we are very focused on improving our balance sheet and our capital structure, which Roland will go over. We completed the sale of our Eagle Ford properties on April 27, which we plan to use as a catalyst to refinance our expensive first and second lien notes. On April 2, we announced a comprehensive refinancing plan and made an offer to convert the second lien notes into equity. Market conditions in April made this transaction unworkable, so we put together an alternative transaction to get the job done. We announced this morning that we have entered into an agreement with Jerry Jones, who will contribute $620 million in Bakken Shale properties to Comstock for an 84% stake in the company. The properties will almost double our EBITDAX and cash flows, which will allow us to complete the refinancing of our balance sheet. Now, if you will turn to Slide 4, we will summarize the asset contribution transaction. Jerry Jones will contribute North Dakota producing oil and gas properties that he holds at two wholly-owned partnerships valued at $620 million to Comstock in exchange for newly issued common stock in the company. The effective date of the acquisition of the properties is April 1, 2018. He will receive approximately 88.6 million newly issued shares of Comstock common stock based upon an agreed upon share price of $7 per share and will own approximately 84% of the pro forma outstanding shares. The acquisition is subject to the approval of the issuance of the common stock by our stockholders and other closing conditions, including the refinancing of our existing debt. The contributions provided us with substantial cash flow to invest in our high return Haynesville Shale drilling program and the capital to further grow our drilling prospect inventory through acquisitions of new leases and producing properties. The proved reserve value and related cash flows from the North Dakota properties when combined with our properties will support the refinancing of our debt at attractive terms. Page 5, if you would turn there, is an overview of the properties that we will be acquiring. The acquisition includes 332 producing oil wells, 52.5 net in North Dakota producing from the Bakken Shale. The wells have all been drilled over the last three years. There are also 128 drilled uncompleted wells, or 13 net, that are expected to be completed later this year and 10 are three net undrilled wells. The wells are currently producing approximately 10,500 barrels of oil per day and 20 million cubic feet of natural gas per day net to the interest being acquired. Our independent reservoir engineers have estimated that proved reserves at 22.5 million barrels of oil and 48.5 billion cubic feet of natural gas. Based on current oil and gas prices, we expect the acquired properties to generate approximately $200 million of operating cash flow in 2018. Slide 6 recaps the new strategic drilling venture we entered into with Arkoma Drilling. Arkoma and Comstock entered into a two-year joint venture agreement in which Arkoma may participate in drilling wells proposed by us in the Haynesville/Bossier and Eagle Ford shale area. We receive a 20% carried interest for projects that Arkoma participates in. The promote will increase the capital efficiency of our drilling program by 20%. Arkoma only earns an interest in a wellbore for projects they participate in and does not have the right to any related acreage. Comstock will offer a minimum of $75 million in opportunities in the first 12 months and $100 million in the second 12 months. Arkoma has committed to participate in six Haynesville Shale wells representing a $34 million investment. Projects under the venture could be on acreage we now own or new acreage we acquire in the future. This joint venture allows us to grow our production faster, will help us hold acreage that has drilling requirements that will allow us to pursue acquisitions that we could not otherwise make. This venture will be accretive to our existing drilling inventory as we will use it to add more leasehold inventory. After the property contribution is closed, we will decide whether the venture continues or if the projects remain in Comstock. Slide 7, if you’d turn there, recaps the previously reported sale of our Eagle Ford shale asset. We sold the 191 producing wells to an affiliate of our existing Haynesville partner, USG, for $125 million. The sale was effective November 1, 2017. We did not sell 8,700 net undeveloped acres, which have 218 identified drilling locations. Our plans are to jointly develop those with USG. Under a new joint development agreement that we’re working on with USG, we intend to exchange a 45% interest in the 218 drilling locations for 50% of 108 infill drilling locations and 50% of the economics of re-frac operations on the 191 producing wells. Comstock and USG will start a one rig drilling program in the third quarter to begin developing the properties. I will now have Roland and Dan cover our first quarter results. Roland?

Thanks, Jay. On Slide 8, we recap our natural gas production by quarter. And in the first quarter of this year, our natural gas production averaged 241 million a day, which was up 55% from 2017’s first quarter, but it was roughly flat to the fourth quarter of 2017. With the drilling program that we’re running now, we still expect our overall growth in gas production to be about 30% year-over-year in 2018 versus 2017. Slide 9 recaps what production we had shut in for the quarter. So, in the first quarter, we had shut-in gas production, which averaged 5 million a day over the entire quarter. And this was mostly necessary due to shut-ins for offset frac activity for either our operations or for activity by offset operators. On Slide 10, we outline our hedge position. We had 42 million a day of our natural gas hedged in the first quarter at $3.26 per Mcf, but for the remainder of 2018 and going into the first quarter of 2019, we have 60 million a day hedged at $3. We still want to add more hedges but are waiting for a little more strength in the forward curve in natural gas. On Slide 11, we summarize the first-quarter financial results. The higher natural gas production and lower operating costs really drove the increases to our sales and cash flow in the quarter. Our natural gas production was up 55%, while oil production from the Eagle Ford continued to decline. Oil prices improved by 41% in the quarter, but natural gas prices were down by 5%. So overall, our oil and gas sales this quarter, including our hedging gains, increased by 36% to $74 million as compared to the first quarter of 2017. Our EBITDAX was up 57% to $53.7 million and we have $35.7 million of operating cash flow, which was 125% higher than the first quarter of 2017. The quarter showed continued improvement of many of our operating cost items. Lifting costs in the quarter were up only 5%, despite the 46% higher production level we had and our depreciation, depletion and amortization was down 9%, despite the increase in production. And that was due to continued improvement in our rate from our lower finding cost Haynesville Shale wells. Our G&A costs were also down this quarter by 6%. We did report a loss this quarter of $41.9 million or $2.78 per share, but most of that loss was due to unusual items, including an unrealized mark-to-market gain on our hedge contracts of $1.2 million, the non-cash amortization of the discount recognized on the bond exchange we completed in September of 2016 of $11 million, and the $28.6 million additional loss taken on the Eagle Ford sale. Without these items, our loss this quarter would have only been $3.5 million or $0.23 per share. On Slide 12, we show our producing costs continue to improve quarter-over-quarter as we see continued growth in the low-cost Haynesville Shale properties. Our operating costs this quarter fell to $0.70 per Mcfe, as compared to $0.97 in the first quarter of 2017. The components of operating costs, including gathering costs, fell to $0.19 as compared to $0.26 in the first quarter of 2017. Production taxes were up slightly to $0.08 as compared to $0.07 in 2017. That’s just due to the higher oil prices. And then our overall field level costs were down to $0.43 per Mcfe compared to $0.64 in 2017. And then our DD&A rate per Mcfe produced fell by 38% to $1.18, as compared to $1.90 in 2017. If you include the Eagle Ford operations, our operating costs this quarter would have been $0.54 and our DD&A would be $1.25. So, April will be the last month we include any results from our Eagle Ford properties as they were sold right at the end of April. So, our future cost structure without the high-cost Eagle Ford operations and after we refinance our expensive debt will be one of the best in the industry. On Slide 13, we present the balance sheet at the end of the quarter and we also show it pro forma for the Eagle Ford sale transaction that we completed at the very end of April. We ended the quarter with $51 million in cash. We did have $15 million outstanding under our bank credit facility which we repaid in April. Overall, we had in $1.2 billion in total debt, but pro forma for the recently completed Eagle Ford sale, our net debt is now at $1.1 billion and our liquidity is at $270 million. We do plan to use the proceeds for the sale as part of our comprehensive refinancing plan that we’ll complete once the Jerry Jones property contribution is completed. On Slide 14, we outlined a revised 2018 drilling program, which is based on the expectation that we complete the Arkoma transaction early in the third quarter. So, we plan to add an additional operated rig at the very beginning of the third quarter to go along with the three rigs that we are currently operating. And then we plan to add a fifth operated rig in our Haynesville operations by the end of this year to really support our 2019 program where we’re going to run five rigs in the Haynesville. We will also have 1 to 2 rigs this year and then going into 2019 developing our Eagle Ford properties under our new joint venture with USG. So, in total, this year, that we plan to drill 36 Haynesville Shale wells or 15.6 net to our interest for an overall capital outlay of $127 million. And you can see that the well count, it’s just one of the things to look at, but the average well that we’re drilling in our Haynesville program this year has an average lateral length of 8,500 feet as compared to last year’s program where the average well averaged 7,085 feet. We’re also budgeting an additional $22 million this year to complete the wells that were drilled in 2017 that carried over into this year. And then we have seven re-fracs budgeted for $32 million. So, as we start the Eagle Ford program back again, we have about $5 million we’re spending on that program. And then post the property contribution of the North Dakota properties, we are estimating we will spend $52 million in the second half of this year, which represents primarily completion activity on 7.2 net wells. So, these are probably drilled and uncompleted wells, but there are also several new wells that will be in that number. So, in total, we expect capital expenditures will be $237 million as we ramp up our activity now to keep up with the Company’s higher operating cash flow post the Arkoma transaction. I’ll now turn it over to Dan to provide an update on our drilling results in the first quarter.

Thank you, Roland. On Slide 15, you’ll see a – this is a slide you’ve seen before. It shows our 69,000 net acres in the Haynesville and the mid-Bossier Shale play across North Louisiana and East Texas. We operate most of our net acreage position and have an average working interest of 79% across the 88,000 gross acres, which we have an interest in. The average net revenue interest across our acreage is 81%. As Roland stated, we are currently planning to drill 36 gross wells this year or 15.6 net wells to Comstock. Over on Slide 16 is a summary of our completions to date. This shows 37 of the 43 total wells we have completed to date since reentering the play back in early 2015. The other six wells we have completed are located further north in the USG joint venture and can be seen on the next slide. That red callouts represent the 13 Gen 1 wells we drilled in 2015 and 2016 that were completed with 3,000 pounds per foot. The gold callouts represent 24 of the 30 Gen 2 wells we have completed since late 2016, and these were completed with 3,800 pounds per foot. Since our last conference call, we have completed eight additional wells, six Haynesville wells plus two Bossier wells. The average initial production rate of all eight wells was 25 million cubic feet per day. Four of the eight new wells are highlighted on this slide. The Roberts 26-35 #1 and #2 wells were drilled to the Haynesville at an average vertical depth of 11,147 feet with the #1 well having an 8,599-foot lateral and the #2 having a 9,018-foot lateral. The initial production rates were 27 million cubic feet per day and 28 million cubic feet per day, respectively. The BSMC LA 12-1 #1 well was drilled to the Bossier at an average vertical depth of 11,066 feet with an 8,801-foot completed lateral. The initial production rate on this well was 17 million cubic feet per day. The BSMC LA 13-24 #3 well was drilled to the Bossier at a vertical depth of 11,214 feet with a 9,808-foot completed lateral and tested with an initial production rate of 20 million cubic feet per day. As of today, we are fracking four wells and have four additional wells in various stages of completion. We also have one well that is awaiting starting completion. Over on the next slide, this provides an update of our joint development program with USG. The initial activities of the joint development program have been focused primarily in Caddo Parish, Louisiana, where to date USG has acquired 6,300 net acres targeting the Haynesville, allowing Comstock and USG to drill 34 extended lateral wells. To date, we have drilled a total of 10 – 10,000-foot lateral wells on the acreage and we are currently drilling the next four wells in the program. Since our last update, we have completed four additional successful Haynesville wells and also have four additional wells in various stages of completion. The Flournoy 28-21 #1 and #2 wells were drilled at the Haynesville at an average vertical depth of 10,995 feet and averaged 9,378-foot complete laterals. The wells were tested with an initial production rate of 27 million and 28 million cubic feet per day, respectively. The Florsheim 9-16 #1 and #2 wells were drilled to the Haynesville at an average vertical depth of 10,982 feet and averaged 9,443 foot completed laterals. These wells also tested with an initial production rate of 27 million and 28 million cubic feet per day, respectively. We are currently participating with a 25% working interest in these wells and will increase our participation to a 40% working interest starting with the 13th well in the program. USG is also participating in four recently drilled wells targeting the Bossier Shale in DeSoto and Sabine Parishes, Louisiana. USG is also participating in our drilling program on approximately 5,800 net acres over in Harrison County, Texas, that will target the Haynesville. We are currently completing our first two wells in this area and expect to have results on these wells by mid-year. Look over on Slide 18. We are showing the same well performance today as presented on the earlier slides for the Gen 1 and Gen 2 completions. The well performance to date on this slide has been normalized. It shows the initial production rates per 1,000 feet of completed lateral. Still shows the superior results of the Gen 2 wells versus the Gen 1 wells. Over on the next slide, Slide 19, this will show the latest update to how our Haynesville and Bossier wells that have sufficient production history are performing against our base 7,500 foot type curve. The red curve represents the average of our 12 Gen 1 Haynesville wells completed in 2015 and early 2016. These wells have a significant amount of production history now and continue to outperform our 7,500-foot type curve. The purple curve represents the average of our 16 now Gen 2 Haynesville wells completed since late 2016 and continue to outperform the Gen 1 wells. The light blue curve represents the average of our eight Gen 2 Haynesville short lateral wells, which are also outperforming the 7,500-foot type curve. Lastly, the green curve represents our two Bossier wells, which continue to outperform our average Gen 1 Haynesville wells. On the next slide, we have adjusted the data presented to reflect the production per 1,000 feet of completed lateral. You can see the red curve represents the average of the 12 Gen 1 Haynesville wells in 2015 and early 2016. The average length for these wells was 7,194 feet. The dark blue curve represents the average of our 24 Gen 2 Haynesville wells that have been drilled since late 2016. The average lateral for these 24 wells is 7,130 feet. The green curve, which represents the two Bossier wells, have an average lateral length of 7,460 feet. As you can see, the Gen 2 wells are continuing to outperform the Gen 1 wells over the longer term. And with that, I will turn it back over to Jay.

All right. Roland, thank you and Dan, thank you. If you go to Slide 21, we’ll go over the 2018 outlook, which is really, really good. We are focused, of course, on completing the Jerry Jones contribution, which will have to be approved by our shareholders. The completion of the transaction will allow us to transform our balance sheet and simplify our capital structure, as Roland mentioned. The added operating cash flow improved reserves from the North Dakota properties will allow us to refinance all of our existing debt, addressing near-term maturities, enhancing our liquidity and substantially reducing our interest costs. The additional cash flow will be reinvested in our high return Haynesville shale program, which will create 30% production growth in 2018, as Roland mentioned, and over 50% production growth in 2019. Comstock’s already low-cost structure is expected to continue to improve as the low-cost Haynesville shale production continues to grow. Our operating costs per Mcfe in the first quarter of 2018 decreased by 28% and our DD&A per Mcfe was down 38% and will continue to improve as we grow our Haynesville production. After our refinancing is complete, we could see our interest expense cut in half. For the rest of the call, we will take questions from the analysts who follow the company. So, Brian, turn it back over to you.

Thank you, sir. [Operator Instructions] And our first question will come from the line of Ron Mills with Johnson Rice. Your line is now open.

Good morning, Jay. Quick question. As the relationship with Jerry Jones expands with the Williston acquisition, you had talked about him really being interested in the Haynesville and the growth opportunity there. Can you talk about potential consolidation plans? How the relationship with Jerry could make you all a potential consolidator in that area and how that relationship would work to execute on that?

Again, I think going back to the Joneses, I mean to give you an overview, they do think big. And they are attracted to the economics of the Haynesville/Bossier play, particularly since we have minimum firm transportation burdens. They look at a tremendous number of potential Haynesville/Bossier drill sites locations. They look at the location of the Haynesville itself and they see where the demand center is. LNG exports, Mexico exports, industrial demand. So, you look at that and you say, well, what do we do with the cash flow that they are injecting? And we go from 3 rigs to 4, 4 to 5, by year-end 2018. And what does that do? Well, that should – and this is what the Jones want, it significantly increases our pace of production. But at the same time, it pushes our leverage lower. So, what does that allow us to do within cash flow? Well, that does allow us have additional acquisitions. In fact, we were, as Ron and you were here at the same time – I mean, in 2007 when we started deepening some of these Cotton Valley wells, there was a Bossier there. We’re one of the first entrants to help discover this whole play. So, the Joneses come back and say you drilled 120 of these Haynesville wells horizontally between 2008 and 2012. And they look at what’s happened since 2015, and we are the first really to redefine the Haynesville. They said, okay, can we grow in the area? And we said, well, we think we really can. And so, I do think that they would like to see some consolidation in the area. And I think we have to continue to say what is our goal. I mean, our goal is to exercise discipline. It is to refinance our existing debt, is to lower our leverage, is to drill quality Haynesville/Bossier wells, it’s reduce costs. But it is also to incrementally grow our locations. We’ve had a couple of private companies call us once we have put out the letter of intent and they have reached out and they said are you interested in maybe us looking at you buying some of our properties and stuff? And we said, well, I think that is the plan. Now, we’ve got to be disciplined, though. And we’re not going to increase leverage, we’re going to decrease it, but I do see some consolidation in the basin. And I think we could be the leader in that if we’re smart. There’s a lot of investment there. There’s a lot of drilling that needs to take place. I think there’s some economies of scale that can happen if we can add more rigs. So, yes, I think you think big, that’s one of our goals. So, good question.

And as it relates to the Haynesville and Bossier, looking at the map, looks like the Bossier wells now really, really cover that whole block down on the Sabine Parish line from north to south and east to west. So how does that – the de-risking of the Bossier down there – fit in with the planed Haynesville development in terms of activity? Or is the Haynesville still ahead of the Bossier in terms of potential timing?

I think Ronnie – and of course, if you go back in between 2008 through 2012, we drilled probably 20 Bossier wells. Now, they weren’t – we didn’t have enhanced completions and we didn’t have extended laterals and stuff. But you drill – fortunately you drill through the Bossier and then you hit the Haynesville. So, and then when Mack Good was the COO, Mack stepped out in December of 2015 and we drilled a Jordan well and he was confident enough back then and we couldn’t make any mistakes back then. We can’t make any now, but we certainly couldn’t make any back then. And the Jordan well came in. And if you looked at the type curves, the Jordan well is probably one of the best if not the best well we have. So, then you see some peer companies drilling some Bossier wells to the east and they look like really good wells. And we thought, well, we know the big mineral owner in part of that area, so we were confident that our Bossier extended to the north and to the west. But you’ve got to be slow in it. And then all of a sudden, we hit a 21 million a day well, 17 million a day well, another 20 million a day well. And I think this fourth well that we are testing right now, I think it’s going to look like a really good well, too. So yes, we’ve come a long way from December 2015 through today to de-risk the Bossier. And I don’t think we get a lot of value for the Bossier. Of course, your Tier 1 play, that’s the least risky play, is the Haynesville. You can see all on those charts on 16. We have lots of locations. But I do think we’ve got some really, really valuable Bossier locations. And as we de-risk that, which we’ll materially de-risk it as of today, we will start getting some value for that too. And we will be drilling some of those wells.

And then one last one for Dan, maybe. The Caddo Parish, the results up there have been really comparable with the wells down in DeSoto Parish. Has that been a pleasant surprise? In other words, has it been better than what you may have expected, Dan? Or internally did you think it was like that, and especially as it relates to what’s going on in – since your active in East Texas, is the perception about that area a different reality?

We had looked at some wells that some other companies had drilled in Caddo, and they look pretty good, but unless they are your own, you don’t know. I mean, you want your own. So, USG has been an incredible – they’re like a blue-ribbon partner. We couldn’t have a better partner. So, they came in and with their dollars they leased that acreage in Caddo. And of course, we own 20% of the wells and after the 13th well or starting the 13th well, we will own 40%. But these wells, they have been – they are great wells. We thought they would be good and they’re great. And Dan can go over a little more detail with them, so Dan, you want to comment on that?

Yes, I’d say that we’re – I mean, we are – we’re very happy with the results. I think if you look at the data that we had in the area on the old vintage completions and you just – you go by the numbers, we were expecting to make some good wells here. Now until you reach out there and actually deliver the results, there’s maybe some skepticism on some people’s parts, but it’s basically in line with the multiples that we’ve seen down in DeSoto Parish as far as the old vintage completions to the new wells. So really not a huge surprise in that regard. But very consistent results. Of course, we’re pumping the same type of completions and just, yes, we ought to have – basically everything we drill up here ought to be fantastic from here forward.

Well, and you had mentioned – Ron, you had mentioned do we want to acquire initial acreage or consolidation. I think that’s a good example that Dan’s talking about and you brought up. Beginning of February of 2015, January of 2015, we didn’t know any of the Caddo acreage. So, you fast-forward to today, there’s 34 locations. We drilled a bunch of wells. You can see how good they are. Same thing with Harrison County and Panola County. We’re drilling those wells. They should be really good wells and we’ve added acreage there. Same way with some of the Bossier wells that we just talked about. Some of that is new acreage. And we did that with a stretched balance sheet, so the Joneses see that and they say, wow, if you had some money and we get our leverage. Our goal is to get our leverage less than two times. That is our goal. You’ve got to have a goal out there and that is our goal and we can play over levered for a long, long, long time. So, our goal is to get it down. And what does that allow us to do? It allows us to be a consolidator and add Tier 1 locations.

Thank you.

Thank you. And our next question will come from the line of Mike Kelly with Seaport Global. Your line is now open.

Hi guys good morning.

Hi, Mike.

Jay, Roland, congrats on the really nice Jerry Jones pivot [indiscernible]. Had to read it about five times to make sure I was actually reading it correctly, but it’s great to see you guys with a healthy balance sheet again. Following on to Ron’s line of questions, just on Jerry Jones, having him in the mix and 84% of the company, how should we think about that at a high level? What’s that really going to do in terms of just changing the dynamics of the company? Anything else you’d really add on that front?

Yes, sure. I think the earlier press release kind of said it exactly right. I mean, Comstock has to play on offense instead of being on defense like we’ve been – we’ve tried to – protecting the stakeholders for the last three years with everything we could, trying to add value, but having to do it through – with a lot of help from partners in managing the balance sheet in the downturn. So, I think post the refinancing, then that can be all behind us and really go to capturing more Haynesville opportunities. In addition, just the drilling up our inventory, which is pretty substantial. But we really think there’s the opportunity, especially in this current environment, where there’s not another well-capitalized public company out there that’s significantly focused on the Haynesville. It’s a great opportunity to consolidate private interest out there, smaller operators that really – they see the value, but you have to – you need a lot of size and scale to run the drilling programs out here. And you need to have multiple rigs, multiple frac crews to bring economies of scale to this program. And I think we can help provide that vehicle for those other companies to consolidate some of that interest in the Haynesville. So, we’re really looking forward to that, just really putting all our efforts away from protecting the company to growing the opportunities. Have a very strong partner obviously and I think his attraction to the company is to see it be the premier Haynesville company and can support the company in whatever endeavors. If we find good opportunities, I think he’ll support the company in any way that we need it.

And Mike, the other thing, he – they made – the Jones family made their money in oil and gas, so this is not a one-off backer. This is a family that made their money in oil and gas. He loves oil and gas. So, he said I made my money in gas, really in gas. So, it gets even a little better the deeper you dig. And like Roland said, you’ve got to be best-in-class, you’ve got to do things right. If we hadn’t done that, he wouldn’t touch us. And so, we’re just kind of now – again, he said we’re going to play offense. We’ve been pretty good at that, we just hadn’t been able to play on that side of the line for about three or four years.

It’s a really unique combination, which I hope the market appreciates, of the high cash flow, Bakken assets that he has invested in and now is harvesting. As we are seeing differentials come down and you kind of combine that with our opportunity-rich, but capital – lack of capital resources kind of Haynesville operations and you put those two together and they really – they provide – I think we think a real attractive company as we’re able to – that cash flow, one, it supports the – it supports all the refinance of the debt at much more attractive rates in terms that we have now. Then it also provides us a big growth opportunity fully within cash flow. I think we were looking at our new capital budgets recently. We are used to having to cut back and figuring out how do we cut projects back to keep CapEx within cash flow. And then the challenge is almost reversed. All of a sudden, we’re saying we need to really add a lot of projects. It does take a while to get things back into operation and get all that set up. It’s actually – we have to increase our activity a lot just to stay within cash flow and actually invest the cash flow. So, it’s going to be an exciting new chapter for Comstock once we close this transaction.

And Mike, again, I think even when we sold the PDP part of the Eagle Ford, I mean we kept upside for that 218 identified drilling locations on that 8,700 net acres. And then we should have upside on 50% on the 108 infill drilling locations and the re-frac of the 191 producing wells. That’s the type partner we have even there. So, we’ll have a rig there, so we’ve been there, I mean that’s oil. If oil prices go up, we’ll have the 10,500 barrels and we’ll just have more cash flow to reinvest in the Haynesville and to grow even more. It is absolutely a win-win-win everywhere.

Yes. That’s good stuff, guys, exciting. Just, real quick, the Bakken, let me know if I’m thinking about this correctly. But I really just see that as a cash flow stream for you guys and don’t expect you to be doing bolt-on acquisitions or anything up in North Dakota anytime soon. Is that correct?

That’s correct.

We look at that, though.

Yes, I think it’s that opportunity set will be something that now, especially with more expertise from our Arkoma partners, we won’t rule that out, but I think the – as they are seeing that the opportunities up there are expensive now because it’s such a high cash flow area and they see the investment opportunities are better on natural gas. They invested in the Bakken when oil prices were lower and created this asset in that time. And did really well because they invested at the right time. Now they see it’s expensive to get acreage or drilling opportunities up there. But we would look at – there are projects that will come to us that still need to be drilled. That’s in some of that CapEx. And there’s also a fair amount of drilled uncompleted wells that need to be completed. But most of that capital activity will probably get finished in the next 12 months or so, and then unless we add new opportunities, we’re just harvesting that cash flow and reinvesting it in other parts of the company.

Yes, I don’t think that Jones invest in owning 84% of Comstock to drill a lot of Bakken wells. What we’ve done is we’ve said if there are opportunities there and you think that we should look at those and do that. I mean, we would absolutely look at them and do that if they competed against the economics of the Haynesville, Bossier or Eagle Ford. So that would be another leg of the stool we would have. I don’t think, Mike, you can say we’re going to be that active there, but it’s just another leg.

Yes, we’re not an operator on any of those properties.

Yes, they are all non-op.

And traditionally Comstock has liked to operate and spend most of our drilling budget – it’s always been our philosophy to spend most of our drilling budget on operated properties.

Got it, okay. And then for me, last one. 2019, it was good to see, Jay, slide 21 that you laid out 50% growth expectations in the Haynesville in 2019. Curious, some of the assumptions behind that; where you’ll be with the rig count, what kind of ballpark CapEx could look like. And then also if you can maybe fill in the blanks for what oil could potentially look like in 2019 given you’re going to be starting back up the Eagle Ford program. Thank you.

Sure. So yes, that really is based on running the five operated rigs in the Haynesville, which we hope to have in place by the end of 2018. So that kind of represents a five-rig program. Now, those would still probably be dedicated to finishing the development of joint venture properties, but then you’d have three on higher interest projects that are in our portfolio. We would see on the oil side, probably not seeing a lot of growth in oil overall, other than we’d have a full year of the acquisition versus a half a year. But we would see not a real large decline, depending on how strong the Eagle Ford program is going, but oil kind of probably quarter-to-quarter slightly declining and kind of our expectations without a bigger oil investment program going on. And I think the overall – if you look at the overall CapEx, it’s probably in the neighborhood of $400 million for next year. Kind of targeting what we think will be the cash flow generated by the combined enterprise based on the current strip pricing out there for oil and gas. So, we size the program looking at the cash flow we thought we’d generate and that five rigs seems to match up right now. If we get better gas prices then that could be a little different answer.

Mike, that’s a pretty expendable number because we don’t have the takeaway issues that you have in some of the basins, sand, and we don’t have the differential issues [indiscernible] some of them. Those are big, big things, the reasons the Joneses looked at the Haynesville/Bossier too.

We’re pretty much doing the projects that we’ve always been doing, so there’s not a lot of – and there’s a little bit of Bossier in 2019. We still haven’t really dedicated a big program to the Bossier, but I think that will be coming at some point when we decide to have a larger program down in the Bossier properties. We still will continue to do some projects, delineate it and study the long-term performance, which has been good. Those wells seem to – we don’t really IP them as they don’t start out as high, but they have a lower decline. I think that’s been the consistent thing we’ve been seeing from the Bossier.

Great. Thanks, guys, and congrats again.

Thank you.

Thank you. And our next question will come from the line of David Beard with Coker Palmer. Your line is now open.

Good morning, gentlemen.

Good morning.

Two questions, a micro and a macro. On the micro front, when you look up in the Bakken, first, do you have a lot of visibility being a non-op that you will spend around $50 million? Or could that be sort of high/low?

Well, you’ve got – we know we have 13 net wells that are not completed, so that budget is to complete those wells and there’s three net undrilled wells.

I think it’s just a matter of we’ll spend that, but the timing will not be under our control. So, the timing could be in the next six months or the next nine months, the next 12 months. But it’s probably in that kind of timeframe. That’s why we do usually like to operate because we like to control the timing of projects.

Yes, I was worried a little less about timing, just that you could get hit with a bunch of AFEs given the activity up in the basin. I know it’s a little hard to look at that, but could there be some variability from that?

No, there’s really not because the property – what we own are individual – what we own are individual drilling opportunities that they have, so we don’t have acreage. Other than the opportunities we have already committed to, we’d have to commit to new ones, so there is no – unless we add new opportunities, there’s not going to be any other activity other than that. So, yes, it’s unique. It’s how that asset was created. It’s kind of a unique asset. It’s kind of like the program we’re doing with Arkoma now. It’s participation in wells only.

Yes, no, that is unique and that gives you a little more control for a non-op than typically people think. And do you think that spending is enough to hold production roughly flat or down a little?

No, we think it’d be – it is going to increase some as you get those projects finished, but then after that, once they are all finished, then you would see a decline. So, it’s the timing of those projects to kind of say when they will all come online will determine when that happens. But we overall though, potentially can ramp up the Eagle Ford program after we get some first results in and that would be our growth oil asset in the future right now. And we think we’re going to see some pretty good results, especially in the current oil prices as we kick off that program with USG down there.

Right, right.

We think there’s a lot of – there was a lot left behind that we just didn’t – given what other operators are doing all around us in the Eagle Ford.

No, that’s helpful. And then a little bigger picture back in the Haynesville, but it relates with your joint venture partner. Now that you guys are on offense and they’ve been on offense as well, how would you manage? Would there be any conflicts in terms of acquisitions given that you are both going to be a lot more active in the basin? How should we think about that?

Well, I think that as far as – I don’t think we ever competed against each other. And I think we are – in the Haynesville, anyway, I think we’re kind of their main partner. And we look jointly to do acquisitions. We’ve bid on acquisitions, several of them jointly, just haven’t gotten them. I think we’ll be a more – we can carry more of the load I guess and be – a lot of those early acquisitions, they were having to carry a lot of the upfront load because we couldn’t really invest in acreage and stuff. We needed to put all our money in drilling. So, I think it just gets stronger because we will be stronger.

Well, even if you look at Caddo, had we had – if we had the liquidity, we would have gone 50-50 with them in the Caddo wells. And we didn’t have this. So, I think that’s a difference you’ll see, that’d be good for them and good for us.

And we like having the partners and being at that 50-50 level. That’s why we’re kind of looking at both our potential JV partners and looking at kind of keeping – trying to have 50-50 ownership. It gives us good – better diversification in our drilling program, but then both have a very meaningful interest. And that’s how we’d see doing things with either of the two partners in the future, targeting a 50-50 ownership.

Right. No, that makes sense to have two shoulders to the wheel versus just one. Appreciate the color and congratulations, guys.

Thank you.

Thank you. And our next question will come from the line of Joshua Gale with Nomura Securities. Your line is now open.

Hi, good morning. Thanks for taking the question.

Good morning.

A ton of strategic stuff to ask about, so I apologize in advance for asking about the minutia, but just had a couple questions about the contribution agreement and refinancing of the debt. First, is the effective date of the transaction still April 1? And although you are paying in shares, would the purchase price adjustment be made in cash back to you at closing? And I know there’s some completion activity in process, but it’s obviously cash flowing positive, so would you expect that adjustment to be somewhat helpful in the refinancing process?

Yes, that’s a great question, and I think that’s exactly how we set it up, is that the shares are fairly fixed and the net cash flow after the April 1 effective date would come back to the company in cash. And so, we do see that as a good source of cash to go along with the cash that we had put in our pocket from the Eagle Ford sale to be part of what we used in the overall refinancing that we’ll undertake as we close that Arkoma transaction.

Right, thank you for that. And then as far as – I know in the 2016 process, it was 50 calendar days from the filing of the proxy materials to the shareholder vote date. And I’m not an expert in this field as to what the regulatory requirements are for notice period, but would you expect it to be a similar period of time? And can you run the call notice and the refinancing process on the debt concurrently with that?

We do plan to be working on both of those two items over the next – the rest of this month and through June. And we’re targeting to, of course, to having the shareholder vote in very early July. But that’s all dependent on – given that this is not a routine proxy that we will be filing, it can be reviewed by the SEC, so we don’t control the timing. But pending not having a review, we could see getting to the vote in early July. So, in that period of time as we are going through the process to put the matter in front of our shareholders to vote on, we will be working on putting together a bank group and really just completing the already refinancing plan we were working on before. And it’d just be on a bigger scale and what we’ve been told much better terms with a stronger balance sheet. So, we will be putting together the refinancing plan and having that pretty much in place so they can be fairly simultaneous when we get the shareholder vote.

All right. Thanks so much. Congrats on all you’ve accomplished and best of luck.

All right, thank you.

Thank you.

Thank you. Ladies and gentlemen, we are out of time to take questions for today. So now, it is my pleasure to hand the conference back over to Mr. Jay Allison for some closing comments or remarks.

Well, as the Board and as management and as everyone that works here, we want to thank every one of you that are debtholders, equity owners, analysts, whatever, for trusting us, for going through the ups and downs we’ve had since Thanksgiving of 2014. We’d never quit on you. We had a lot of dead ends, but we were transparent with that and we’re just thankful that you have again trusted us with the problems. And we’ve tried to tell you what the problems were and I think we have an incredible solution and everybody is a big winner. But without you allowing us to do that, we wouldn’t be here. So, anyhow, thanks for participating in the call and we will finish what we started.

Ladies and gentlemen, thank you for your participation on today’s conference. This does conclude our program and we may all disconnect. Everybody, have a wonderful day.